Industrial CCS on Teesside – Summary...

Industrial CCS on Teesside – Summary Report

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Industrial CCS on Teesside – Summary Report Contents

© 2015 Pale Blue Dot Energy Ltd

Contents Document Summary

Client Tees Valley Unlimited (TVU)

Project Title Industrial CCS on Teesside

Title: Summary Report

Distribution: M Lewis Classification: Client Confidential

Date of Issue: 12th October 2015

Name Role Signature

Prepared by: T P Dumenil Energy Consultant

Approved by: S J Murphy Project Manager

Disclaimer: While the authors consider that the data and opinions contained in this report are sound, all parties must rely upon their own skill and judgement when using it. The

authors do not make any representation or warranty, expressed or implied, as to the accuracy or completeness of the report. There is considerable uncertainty around the

development of CO2 stores and the available data are extremely limited. The authors assume no liability for any loss or damage arising from decisions made on the basis of this

report. The views and judgements expressed here are the opinions of the authors and do not reflect those of TVU or any of the stakeholders consulted during the course of this

project.

Amendment Record

Rev Date Description Issued By Checked By Approved By Client Approval

V03 16/06/15 Issued for Client Review T P Dumenil S D Gomersall S J Murphy

V04 03/07/15 Final Report T P Dumenil A T James S J Murphy

V05 12/10/15 Final Report V2 T P Dumenil S J Murphy A T James



Contents 1. Executive Summary _________________________________________________________ 6

2. Recommendations __________________________________________________________ 9

3. Introduction _______________________________________________________________ 11

4. Project Overview ___________________________________________________________ 13

4.1 Battery Limits ................................................................................................................ 14

4.2 Outline Technical Solution ............................................................................................. 15

5. Commercial Overview _______________________________________________________ 26

5.1 CO2 Emission Profiles ................................................................................................... 26

5.2 Project Structure ........................................................................................................... 27

5.3 Outline Commercial Solution ......................................................................................... 29

5.4 New Entrants ................................................................................................................ 31

6. Business Case ____________________________________________________________ 33

6.1 Introduction, Reference Case & Business Model ........................................................... 33

6.2 Business Case Insights & Conclusions .......................................................................... 35

6.3 Other Key Points from the Business Case ..................................................................... 39

7. Execution_________________________________________________________________ 45

7.1 Project Execution Plan .................................................................................................. 45

7.2 Key Milestones .............................................................................................................. 45

7.3 Project Schedule ........................................................................................................... 46

8. Getting to FEED ___________________________________________________________ 50

9. Conclusions _______________________________________________________________ 51

Annexes ___________________________________________________________________ 55

Annex A - Transport Services Term Sheet ........................................................................... 55

Annex B - Infrastructure Sizing Report................................................................................. 57

Annex C - Potential Ownership Options for Onshore Transport of CO2 ................................ 65

Annex D - References ......................................................................................................... 84

Annex E - Glossary ............................................................................................................. 85



Figures

Figure 1 - Teesside Collective ICCS Feasibility Project Summary .................................................................................................................................................... 5

Figure 2 - High Level Project Schedule ............................................................................................................................................................................................ 9

Figure 3 - Overview of TVU Objectives .......................................................................................................................................................................................... 11

Figure 4 - Major Industrial Sites across the Tees Valley Region ..................................................................................................................................................... 14

Figure 5 - Store Locations .............................................................................................................................................................................................................. 15

Figure 6 - Steel Process (Source Amec Foster Wheeler) ............................................................................................................................................................... 15

Figure 7 - Overview of SSI Option 1 (Source Amec Foster Wheeler) .............................................................................................................................................. 16

Figure 8 - Overview of SSI Option 2 (Source Amec Foster Wheeler) .............................................................................................................................................. 16

Figure 9 - Overview of Onshore Gathering Network Route Options (Source Amec Foster Wheeler) ............................................................................................... 18

Figure 10 - Preferred Blue and "Big Blue" Onshore Gathering Network Routes (Source Amec Foster Wheeler) ............................................................................. 19

Figure 11 - Offshore Network route to the NGC 5/42 Store (Source Amec Foster Wheeler) ............................................................................................................ 20

Figure 12 - Offshore Network route to the Goldeneye Store (Source Amec Foster Wheeler) .......................................................................................................... 20

Figure 13 - Dynamic Storage Capability of an Aquifer .................................................................................................................................................................... 21

Figure 14 - Captain 1, 2 & 3 Stores ................................................................................................................................................................................................ 22

Figure 15 - Bunter 1, 2 & 3 Stores .................................................................................................................................................................................................. 22

Figure 16 - Capex and 40 year Opex for a 15 mTpa system connected to Bunter ........................................................................................................................... 25

Figure 17 - Current Teesside emissions depending on source size ................................................................................................................................................ 26

Figure 18 - Cumulative Emissions Profile ....................................................................................................................................................................................... 26

Figure 19 - Low Medium and High emissions forecasts for Teesside .............................................................................................................................................. 26

Figure 20 - Project Structure for CCS ............................................................................................................................................................................................. 27

Figure 21 - Commercial Structure for Teesside ICCS ..................................................................................................................................................................... 28

Figure 22 - Funding Mechanisms for Teesside ICCS (Source: adapted Societe Generale image)................................................................................................... 29

Figure 23 - Comparison of Levelised Costs between Scenarios ..................................................................................................................................................... 38

Figure 24 - Comparison of the Financial Support Required for each Scenario ................................................................................................................................ 38

Figure 25 - Distribution of Cost along ICCS Chain (2015 terms) ..................................................................................................................................................... 39

Figure 26 - £/T Cost of Capture by Industrial Processes (PV terms, 7% discount rate) ................................................................................................................... 39

Figure 27 - Transportation Economies of Scale .............................................................................................................................................................................. 41

Figure 28 - Breakdown of Transportation and Storage Costs for each Store ................................................................................................................................... 42

Figure 30 - Headline Process......................................................................................................................................................................................................... 45



Figure 31 - High Level Timeline for the Teesside Collective ........................................................................................................................................................... 46

Figure 32 - High Level Project Schedule ........................................................................................................................................................................................ 46

Figure 33 - Execution Schedule from Progressive Energy's TVU CCS Pre-FEED Study for the Outline Execution Strategy for delivery of the SSI Anchor Project .. 49

Figure 34 - Key cost considerations for getting to FEED and beyond.............................................................................................................................................. 50


© 2015 Pale Blue Dot Energy Ltd Page 5 of 86

The Reference Scenario allows for expansion with the scope to feed in a further

2.2million tonnes of CO2 a year. A more ambitious scheme could treble the pipeline

capacity to 15 million tonnes of CO2 a year, with only 8% additional support required

and has the potential to reduce the cost per tonne of CO2 stored to below £80.

This would provide a platform for new low carbon investment supporting in excess

of 2,600 permanent jobs in new plant, £2billion in additional annual economic

activity and £1.2billion in additional exports annually by the 2030s.

Teesside Collective has a technically viable, end-to-end plan that encompasses the

capture of CO2 from four energy intensive anchor companies and its transportation

and permanent storage under the North Sea. With the right level of support

Teesside Collective could be up and running in time to deliver on the Committee on

Climate Change’s recommendation of industrial CCS being deployed in the UK from

the mid-2020s. It could be an expanding network, with new clean industrial

production attracted to the area to plug in to the infrastructure.

Teesside Collective is a cluster of leading industries with a shared vision: to

establish Teesside, in Tees Valley, as the go-to location for future clean industrial

development by creating Europe’s first Carbon Capture and Storage (CCS)

equipped industrial zone.

This Summary Report presents the case for the Teesside Collective ICCS project.

A conservative Reference Scenario could see the capture of 2.8 million tonnes of

CO2 each year from four industrial plants (SSI, GrowHow, BOC and Lotte) and

inject the CO2 into a saline aquifer store in the Southern North Sea. The project

could be operational from 2024 and over 20 years permanently store 57 million

tonnes of CO2 at a cost of £95/tonne of CO2 or £1.5 billion of financial support.

Figure 1 - Teesside Collective ICCS Feasibility Project Summary

Industrial CCS on Teesside – Summary Report 1. Executive Summary


1. Executive Summary

Background

The Teesside Collective is a cluster of leading industries based in North East

England who are collaborating to create Europe’s first Industrial Carbon

Capture and Storage (ICCS) equipped industrial zone. Teesside Collective is

not a traditional CCS project. Its focus is on capturing and storing emissions

from chemical, steel and process industries rather than the power sector.

In 2013 the UK Department of Energy and Climate Change provided £1m

under the “City Deal” to Tees Valley Unlimited (TVU), the local Regional

Development Agency, to undertake an Industrial CCS Feasibility Project to

produce a coherent and compelling business case for three specific scenarios

for deploying ICCS in the Teesside area.

Decarbonising Teesside will be vital in mitigating the effects of climate change.

The region is home to 5 of the UK’s top 25 CO2 emitting plants and emissions

per person are 3 times UK average. In total, Teesside process industries are

responsible for 5.6% of UK’s industrial emissions. Teesside presents a good

location for ICCS with large amounts of CO2 in a compact area adjacent to the

shoreline and relatively close to potential CO2 stores offshore, i.e. Bunter 5/42.

The region has business engaged in the ICCS concept, sites that already

capture and transport CO2 and a culture of developing regional infrastructure

for shared use. Teesside has the potential and the collective desire to develop

a national industrial asset that puts the UK at the forefront of the global drive to

decouple growth from emissions. The project is crucial in keeping the UK on

target to meet its 2050 80% CO2 reduction target and will help prevent

industries (and jobs) moving to countries where they may end up emitting

more CO2 than they would have in the UK.

Strategic Highlights

ICCS from Teesside is technically and commercially viable, with financial

support from Government, and provides a cost abatement option for the UK.

ICCS can reduce industrial CO2 emissions by 90% and with the right financial

support mechanism it can represent good value for money for Government.

The project leverages Government investment in CCS projects by planning to

use knowledge gained on the stores currently being evaluated in the CCS

Commercialisation Programme.

The project could be operational within 7 years of the funding mechanism

being negotiated between government and the developers. This lead time

could be reduced if a separate arrangement was to be put in place to cover the

detailed engineering, design and planning work required before the final

investment decision point.

To gain insight into likely CO2 transportation infrastructure requirements and

change to one or more anchor sites, three scenarios were developed to

estimate future levels of CO2 that could be captured on Teesside. These

scenarios allow for variation in the start date of capturing, system longevity and

also the number of capture projects and their respective captured emissions

rates. The base and high scenarios indicates that CO2 transportation



infrastructure should be sized to carry 10mT CO2/year, both include a new-

build IGCC plant in the region.

The ICCS project is commercially complex with a number of different

outcomes possible. Whilst several parties have indicated a degree of interest

in owning and operating the onshore elements of the project, no potential CO2

storage company has been identified (it seems unlikely that either of the two

participants in the CCS Commercialisation Programme would be interested in

undertaking an additional CO2 storage venture). Several outcomes are

presented in the report and one that attracted a lot of attentions was the

concept of nationally owned infrastructure for the transportation and storage of

CO2 was considered briefly and is likely to be the subject of further study – it

would be a potential route through the current impasse.

Financial Highlights

The infrastructure will have an operational life of at least 40 years and, with a

significant number of existing and future CO2 supplies, the network can quite

reasonably be expected to operate beyond the 20-year evaluation period.

The cost of capture ranges between £37 – 215/T for the different process

industries and the different scales at which they operate.

The reference scenario captures and exports 2.8 mTpa of CO2 from four

industrial sites on Teesside to the Bunter saline aquifer store 155km away

under the Southern North Sea resulting in the export and storage of 56 mT of

CO2 over the 20-year project life and costs £95/T of CO2, amounting to some

£5.3bn of cost over the project evaluation period (£1.5bn in present value

terms using a 7% discount rate). This assumes a 13% rate of return after-tax

to each of the project participants.

A range of different possible networks were explored which confirmed

considerable economies of scale exist. The cost of ICCS can fall to below

£77/T if, for example an additional 5 mT/year of CO2 is available to capture (as

might be the case from a large power plant, etc.)

An additional 8% investment could treble the transportation capacity and

provide ullage for future CO2 supplied from Teesside. Fully utilizing the

transportation infrastructure over its life can dramatically reduce the unit costs

for transportation by up to 80%, equivalent to £10/T to a Bunter store.

Two commercial mechanisms were evaluated; a store payment arrangement

and a CO2 Contract for Difference (CfD) arrangement. From an economic

perspective there was no discernible difference in the two approaches.

An outline term sheet for the transportation of CO2 is provided in Annex A. The

key terms are considered to be the charging mechanism (a combination of

capital investment, capacity rights and use of system) and allocation of

liabilities between the suppliers (emitters) and the transporter and in particular

who has the commercial liability of suppling the CO2 to the storer. The

implications of admitting New Entrants to the system were also considered

The major areas of CCS specific risk are considered to be associated with the

geological storage of CO2. A qualitative assessment of risk allocation between

Government and the developers of the store shows that the level of support is

dependent upon the share of risk borne by developers, and vice versa.



Looking Ahead

Pale Blue Dot Energy completed the business case work during the first half of

2015, following a stage of engineering design and costing commissioned by

TVU. The project was guided by a steering board chaired by TVU with input

from teams at the Department of Business Innovation and Skills (BIS) and

Department of Energy and Climate Change (DECC).

Future work should build upon the Amec Foster Wheeler Engineering Study,

Pale Blue Dot Energy Business Case and the associated commercial

mechanism work by Societe Generale, to further develop an appropriate

financial support mechanism. The next phase of work should be a significantly

more detailed analysis, (commercial, technical, financial and policy), based on

the CO2 CfD Model and Storer Model. The aim should be to develop a model

that is acceptable to both Industry and Government such that investors are

prepared to invest in the next phase of engineering in 2017. If this can be

attained then construction could start three years later and the project could be

operational by 2024.

Annex E contains a Glossary to assist the reader if required.

Industrial CCS on Teesside – Summary Report 2. Recommendations


2. Recommendations With respect to techno-economic aspects, the Feasibility Study shows that

Industrial CCS at scale is technically feasible and that it is essential to

establish an attractive commercial support mechanism with the UK

Government as soon as possible. This will ensure the scheme delivers the

economic benefit directly from CCS and indirectly through developing

sustainable heavy industrial manufacturing centres coupled with Decarbonised

Power Generation at key locations across the UK.

The study has established the technical and infrastructure solutions required to

capture and store 2.8 mTpa of CO2 from four industrial sites by the early

2020’s and offers the potential for other emitters to connect to the network to

enable the sequestration of significantly higher volumes through a 15 mTpa

infrastructure. A portfolio approach should be taken to ensure a broad mix of

emitters to mitigate risk of one or more emitters leaving the network.

Building on the Feasibility Project, Teesside Collective now need to steer the

project through to completion. As shown in Figure 2, an initial “Bridge” stage is

required to link the existing Feasibility Study work to Pre-FEED (Front End

Engineering Design), then progress into FEED and ultimately to a Financial

Investment Decision (FID) envisaged for 2020. A successful FID enables

construction to be complete leading to carbon being sequestered before the

mid-2020s.

The Bridge Stage is expected to take 12 months, Pre-FEED is expected to

take 6 months whilst FEED is expected to take 18 months. A Store Appraisal

will need to be completed in parallel with FEED. Execution and Financing

through to FID is expected to take 2 years. Engineering Procurement

Installation & Commissioning is expected to take 4 years and is expected to

cost £0.77-2.12bn depending on the technology and capacities chosen for the

installed scheme. Operational Expenditure (Opex) is expected to cost £7.4-

14.7bn again dependent on system design and sizing and with a life time of 20

years for capture plant and 40 years for transportation and storage

infrastructure.

Agreeing an appropriate commercial support mechanism with the UK

Government is the critical path item for the overall project whilst ongoing

communications and engagement via the Teesside Collective is fundamental

to promoting ICCS and delivering a successful project.

Figure 2 - High Level Project Schedule

Industrial CCS on Teesside – Summary Report 2. Recommendations


The Teesside Collective will need to continue to provide leadership and

establish the route by which Industrial CCS can be delivered in the UK. The

three immediate next steps recommended are:

a. Establish The Teesside Collective as the implementation company

b. Maintain focus on ICCS and build on the progress made to date

c. Commence project development activity through delivery of the initial

“Bridge Stage” that secures funding for and initiates the Pre-FEED work.

Other key recommendations are:

1. The Commercial Structure could mirror the three battery limits, i.e.

Capture, Gathering and Transportation & Storage Ventures.

2. For Capture the recommended solution delivers 2.8 mTpa of CO2 for a

capex of £311m. Sahaviriya Steel Industries (SSI) would be the initial

anchor project for the regional CCS infrastructure with smaller

contributions from GrowHow, BOC and Lotte. If SSI went ahead alone it

would deliver 2.1 mTpa of CO2 for a capex of £192m.

3. Capture plant could be owned by the process company or a third party

operator at each emission site. Potentially the same entity could own and

operate the capture plant for all four emission sites.

4. A trebling of onshore and offshore pipeline capacity from 5 to 15mT is

achievable at a relatively modest incremental capex spend of £92-104m,

leading to the recommendation of a 15 mTpa transportation infrastructure.

5. The Onshore Gathering Network delivers 15 mTpa of capacity through

>34km of 100barg pipeline for a capex of £77m. The Gathering Venture

will either be a Sole Operator or a Special Purpose Vehicle (SPV) involving

emitters alongside a proven network operator, i.e. The Teesside Collective.

6. For Transportation & Storage it is viable to transport dense phase CO2 to

either the Bunter or Captain sandstone saline aquifers. The lower costs

offered by the Bunter make it the preferred Store. For the Bunter an

Offshore solution would have a one off capex cost of £254m and an

annual opex cost of £294m for a 5 mTpa system, representing £47.4/T for

Transport and Storage. Alternatively, for a 10 mTpa system it would have a

one off capex cost of £579m and an annual opex cost of £294m,

representing £30.3/T for Transport and Storage. Further appraisal of the

Bunter area is needed to ensure sufficient capacity for a 10 mTpa.

7. With National Grid Carbon (NGC) the prospective operator of a storage

project in the Bunter it is possible that transport and storage could be

provided by NGC.

8. Key for progressing commercial arrangements will be securing necessary

up-front commitments or guarantees around the future usage of a scaled-

up network through Transportation Agreements, a vital component of the

network financing. Title will be a significant area to resolve, i.e. simple

Throughput Service or Title of Transfer at each Boundary.

9. Two commercial support mechanisms were evaluated: a store payment

mechanism and a CfD style arrangement with the emitter. The same level

of support is required from the UK Government whichever of the two

commercials mechanisms is applied.

A charging mechanism would need to be developed with the aggregate

charge likely to comprise of three separate charges; an EPC Charge

(Engineering, Procurement & Construction), a Capacity Rights Charge and

a Use of Network Charge. Who is charging whom and how will depend on

which of the two commercial support mechanisms are chosen as money

will flow from the store to the capture site for the store payment

mechanism whilst flow in the opposite direction for the CfD arrangement.

Industrial CCS on Teesside – Summary Report 3. Introduction


3. Introduction Tees Valley Unlimited (TVU) is a Local Enterprise Partnership between the five

local authorities of Darlington, Hartlepool, Middlesbrough, Redcar & Cleveland

and Stockton and private sector industrial partners. TVU secured £1m of

central government funding under the “City Deal” for a Concept Study to

examine the case for a pioneering Industrial CCS (ICCS) initiative centred on

Teesside and to develop insights into an appropriate subsidy mechanism.

Teesside is home to the largest concentration of chemical facilities in the UK

and the second largest in Western Europe (based on manufacturing capacity).

The project is different as it holistically looks at capture technology,

transportation & storage, business case, finance, Her Majesty’s Government

(HMG) funding and external communications.

Decarbonising Teesside will be vital in mitigating the effects of climate change.

The region is home to 5 of the UK’s top 25 CO2 emitting plants and emissions

per person are 3 times UK average. In total, Teesside process industries are

responsible for 5.6% of UK’s industrial emissions. Teesside presents a good

location for ICCS with large amounts of CO2 in a compact area adjacent to the

shoreline and relatively close to potential CO2 stores offshore, i.e. Bunter 5/42.

The region has business engaged in the ICCS concept, sites that already

capture and transport CO2 and a culture of developing regional infrastructure

for shared use. Teesside has the potential and the collective desire to develop

a national industrial asset that puts the UK at the forefront of the global drive to

decouple growth from emissions. The project is crucial in keeping the UK on

target to meet its 2050 80% CO2 reduction target and will help prevent

industries (and jobs) moving to countries where they may end up emitting

more CO2 than they would have in the UK.

TVU contracted Pale Blue Dot Energy to lead a large multi-company, multi-

disciplinary project to develop the business case for Industrial CCS on

Teesside. TVU also engaged Amec Foster Wheeler to deliver the Engineering

Package, Societe Generale the Commercial Package and Madano the

Communications Package.

The Teesside project aimed to establish the technical design, costs,

commercial arrangements and potential investment mechanism for an

Industrial CCS network on Teesside fed by captured emissions from a variety

of industrial manufacturing sites. The objectives for the project are outlined in

Figure 3 below.

Figure 3 - Overview of TVU Objectives

Industrial CCS on Teesside – Summary Report 3. Introduction


The 12 month project commenced in July 2014. Pale Blue Dot’s scope was

three fold:

1. Ensure full and timely delivery from all contractor teams, specifically the

Engineering and Commercial contractors

2. Produce a coherent and compelling business case for three specific

scenarios:

a. An anchor project based around export of CO2 from the SSI steelworks

b. A business case for 3 additional industrial emitters (Growhow, BOC and

Lotte) to connect to the network based on an anchor project

c. A business case for the 3 additional industrial emitters to develop a

network if the anchor project does not go ahead

3. Provide advice and guidance to the Steering Board

Industrial CCS on Teesside – Summary Report 4. Project Overview


4. Project Overview The Teesside Collective is a cluster of leading industries with a shared vision:

to establish Teesside, in Tees Valley, as the go to location for future clean

industrial development by creating Europe’s first Carbon Capture & Storage

(CSS) equipped industrial zone.

The Teesside Collective consist of:

• Tees Valley Unlimited (TVU) - the Local Enterprise Partnership covering

an area which includes the Teesside industrial base. TVU manages the

Teesside Collective project in close collaboration with its industrial

partners.

• Sahaviriya Steel Industries (SSI) UK - iron and steelmaking facilities with

a capacity of 3.6 million tonnes of slab production per annum.

• BOC - an industrial gas supplier and operates the UK’s largest hydrogen

plant in Teesside. It supplies compressed, bulk and pipeline gases,

chemicals, engineering solutions and innovations in clean energy

technologies, including carbon capture and storage.

• GrowHow - the UK’s leading manufacturer of ammonium nitrate and

compound fertilisers and a major supplier for process chemicals and

utilities.

• Lotte Chemical UK - produces in excess of 150,000 tonnes of

Polyethylene Terephthalate (PET) resin chips every year.

• National Grid - runs the gas and electricity systems, distributing energy to

the nation’s homes and businesses. National Grid bring their expertise on

gas transport and storage to the project.

• North East Process Industry Cluster (NEPIC) - a body representing over

500 chemical, pharmaceutical, biotechnology, Energy and Renewables

businesses and their support companies across the North East of

England.

• Department of Energy & Climate Change (DECC) - a UK Government

Department working to make sure the UK has secure, clean, affordable

energy supplies and promoting international action to mitigate climate

change.

The Teesside Collective is a pioneering infrastructure project offering a

compelling opportunity to progress the UK’s industrial and environmental

interest’s hand-in-hand. Tees Valley Unlimited, has been awarded £1m

funding by DECC to develop a business case for deploying industrial CCS in

the Teesside cluster and to make recommendations for a funding mechanism.

To complete and promote the Concept Study, the Teesside Collective are

being supported by:

• Pale Blue Dot Energy (PBDE) - Management Consultants for The Energy

Transition delivering advice in three key area: Carbon Capture & Storage,

Oil & Gas Transition and Emerging Energy Systems.

• Amec Foster Wheeler - Consultancy, engineering, project management,

operations and construction services, project delivery and specialised

power equipment services for the oil & gas, clean energy, environment &

infrastructure and mining markets.

• Societe Generale - One of the largest financial services groups in Europe

offering a range of businesses: corporate and investment banking to

private banking, asset management, and securities services, as well as

specialised financial services including vehicle and equipment finance.



• Madano - One of the UK’s leading strategic communication consultancies

with a wealth of specialist knowledge to deliver powerful communications

that enable and inspire.

• Process Industries CCS Initiative (PICCSI) - a Teesside based industry

led group supporting CCS development across the region.

4.1 Battery Limits

The proposed Teesside ICCS infrastructure comprises of four main

components:

1. Capture plants at emission sites

2. Onshore Gathering Network for CO2

3. Booster Station and Offshore Network for CO2

4. Offshore Injection and Storage

Figure 4 depicts many of the large industrial sites across the Tees Valley

Region. Previous work has evaluated the carbon emissions from these sites

prioritising their carbon capture potential, engaged the businesses into the

concept of a regional ICCS project and ultimately led to the formation of the

Teesside Collective. The locations of the four industrial entities in the

Collective are shown as A-D on Figure 4. These are the four Emitter Sites &

Capture Points considered within the project.

• SSI - a steel manufacturer with the second largest blast furnace in Europe

which produces circa 6-7m tonnes of steel annually. The site has seven

CO2 emission points within operation totalling 7.1mTpa. The project has

evaluated a number of Pre- and Post-Combustion Capture technology

options. The project assumes precombustion capture of 2.1mTpa.

• GrowHow - the manufacturer of ammonia for fertilisers in the UK. The

ammonia manufacturing process also produces a pure CO2 coproduct

stream of 375kTpa which only requires to be dried and compressed for

Capture.

• BOC - a manufacturer and supplier of industrial gases. BOC supplies

hydrogen through a local network. A coproduct of the hydrogen

manufacturing process is 305kTpa of CO2 which can be captured using

Post Combustion Capture technology.

• Lotte - a manufacturer of PET resin for plastic bottles. The aim is to use

Post Combustion Capture technology to capture 50kTpa.

B

A

C

A

D

A

E

Figure 4 - Major Industrial Sites across the Tees Valley Region



Once the CO2 has been captured at each site it would be transported via

pipeline through an Onshore Gathering Network. The project study required

consideration of various routes for the Onshore Gathering Network utilising the

existing pipework corridors where

possible, (see Figure 4). The Onshore

Gathering Network would culminate at a

Booster Station adjacent to SSI, point E

on Figure 4, at which point the CO2

pressure would be boosted to meet

offshore storage requirements. The scope

required evaluation of various routes for a

pipeline from the Booster Station to

offshore and the subsequent route and

sizing off an Offshore Pipeline to either of

two predetermined storage locations

under the North Sea, Figure 5. The

captured CO2 would be injected into and

stored in a sandstone saline aquifer in either the Captain Aquifer (Goldeneye

area) or Bunter Aquifer (5/42 area). The scope required size and costing

evaluation for both 5mTpa and 15mTpa captured volume scenarios.

For the Business Case, three Battery Limits have been established, one at

each of the three principal interfaces: Capture, Gathering and Transportation &

Storage.

Capture: The design, installation & operation of capture plant at four capture

sites that exports 100barg CO2 within specification into the Onshore Gathering

Network.

Gathering: An Onshore Gathering Network for gathering and co-mingling

multiple sources of metered CO2 at the required specification to the onshore

Booster Station.

Transportation & Storage: An Offshore System from the Booster Station inlet

that increases the CO2 pressure to 160barg for pipeline transportation to the

offshore facilities for injection into the subsurface store.

4.2 Outline Technical Solution

4.2.1 Capture Solutions

4.2.1.1 SSI Main Site

The SSI Main Site is expected to emit 7.1mTpa of CO2 with the majority arising

due to the chemistry of steelmaking.

For SSI a total of 32 capture

options were coarse screened

leading to further optioneering

of 13 options that were fine

screened down to two

Concept Development options

utilising by-product gas

streams to fuel a new turbine

unit. Blast Furnace Gas (BFG) is a by-product of reducing iron ore with coke to

metallic iron and Basic Oxygen Steelmaking (BOS) gas is a by-product of

blowing oxygen over the molten metal. Both BFG and BOS are forms of low

calorific syngas. The two Concept Development options reviewed were:

Figure 5 - Store Locations

Figure 6 - Steel Process (Source Amec Foster Wheeler)



1. Post combustion capture via a chemical or physical solvent on the flue gas

of a BFG fired turbine resulting in circa 1.7mTpa. A new power station

would be built incorporating a gas turbine fuelled by BFG and natural gas.

The turbine flue gas would be rich in CO2 (30%). The flue gas would pass

through an amine unit which would strip out the CO2. The amine is

regenerated using steam from a new auxiliary boiler to produce a stream

of pure CO2. The CO2 is compressed, conditioned, metered & exported.

2. Chemically shifting a mix of BFG and BOS gases and then capturing

2.1mTpa of CO2 via pre-combustion capture using a physical solvent

absorption process to separate out the CO2 before the fully decarbonized

fuel gas enters the turbine. Shifting adds water to the CO in the fuel

stream to create CO2 and H2. The solvent is regenerated to a pure CO2

stream which is compressed, conditioned, metered & exported.

The work to date has confirmed that SSI has the potential to be the anchor

project underpinning the regional CCS infrastructure. The final selection

between the two specific options will depend on costs of capture and on wider

site plans for fuel gas utilisation. At this stage, the second pre-combustion

capture option appears to offer the most attractive economic and technical

solution. These options represent the ‘lowest hanging fruit’. The site has

further CO2 which could be captured in the future once the infrastructure is

established, subject to the commercial case.

4.2.1.2 GrowHow

GrowHow’s integrated manufacturing facility produces fertilizer, ammonia and

nitric acid. The ammonia plant uses natural gas as base feedstock and

removes CO2 using Benfield DEA capture technology producing around

950kTpa CO2. A further CO2 stream of circa 500kTpa from reformer flue gas

was outside the study scope.

A major proportion of the CO2 from the Benfield process is purified,

compressed and sold to the food industry in liquefied form. An average

375kTpa excess captured CO2 is emitted from the Benfield vent. The

composition of this CO2 is close to the network requirements and only requires

dehydration and compression prior to metering and export. The conceptual

design utilizes proven technology from established suppliers and involves a

new facility based around two 50T/hr 100barg compressors.

Figure 7 - Overview of SSI Option 1 (Source Amec Foster Wheeler)

Figure 8 - Overview of SSI Option 2 (Source Amec Foster Wheeler)



4.2.1.3 BOC

At BOC, CO2 emissions result from the steam methane reforming (SMR)

process used to produce hydrogen and from the combustion of fuel and

process gases. Three initial options for CO2 capture were reviewed with

Concept Development on one option for post combustion capture on the SMR

flue gas. The flue gas from the Reformer will be diverted to a new

Conventional Amine Process (MEA) to capture circa 305kTpa. The amine

would be regenerated using co-produced steam with the released CO2 stream

then compressed, conditioned, metered & exported. The MEA technology is

well proven with several providers.

4.2.1.4 Lotte

CO2 emissions result from combustion of methane to create heat for the PET

production process. A total of 14 capture options were coarse screened

leading to further optioneering of five technology types in fine screening

leading to two Concept Development options. Only post capture technology is

feasible with circa 50kTpa of CO2 removal from flue gas through either

membranes or chemical/physical solvents. The chosen solution is an off the

shelf packaged amine capture solution.

4.2.1.5 Sizing Scenarios

The table below provides a summary of the Concept Development options for

CO2 capture across the four sites. With Option 2 preferred for SSI the following

total potential capture volumes can be considered for each of the three specific

scenarios outlined in Section 3.

a. 2.1 mTpa for the Anchor Emitter (SSI) only

b. 2.8 mTpa for the Anchor Emitter plus 3 Smaller Emitters (GrowHow, BOC,

Lotte)

c. 0.7 mTpa for the 3 Smaller Emitters only

4.2.2 Onshore Gathering Network Solutions

4.2.2.1 Onshore Gathering Network Route

Two Concept Development options have been evaluated:

• Option 1: a 5 mTpa pipeline sized to just take the proposed volumes from

the 4 sites.

• Option 2: a 15 mTpa pipeline deliberately oversized to collect CO2 from

across the Teesside area.

The study considered whether the Onshore Gathering Network should be

contain CO2 in Gas or Liquid phase, reviewed the CO2 quality specification

required for entry and also reviewed the emitter potential for the 15 mTpa

scenario. The review considered use of existing river crossings versus the



creation of a new crossing. Further considerations included were: safety, major

crossings (i.e. rail, road, National Grid NTS Feeder route etc.), urban

populations, environmental constraints, historical sites, the re-use of way-

leaves and access to a suitable shore landing.

Figure 9 below shows the multiple route options available on Teesside for the

Onshore Gathering Network. Three main routes were tested, Blue, Red and

Orange. The Green route presents an alternative option for crossing to the

proposed Booster Station location. The Purple route presents a mix of the

orange and blue routes. The Yellow route presents a Wilton Collection

Network.

Post screening the Blue route was confirmed as the preferred option. The Blue

route is technically the most feasible, optimizing the use of existing wayleaves

or routes with fewer issues associated with navigating obstacles. Also Blue’s

route across the river through the existing Tunnel 2 is likely to have space for a

15 mTpa pipeline with a river crossing possible if not. Whilst the Orange route

was cheapest by less than 1%, point access to/from Tunnel 1 on both the

north and south shore is complicated. The red route has issues with proximity

to Port Clarence, environmental constraints, complex routing from the spine to

BOC and also complex routing south of the river.


Onshore Gathering Network routes have been confirmed for both the 5 mTpa

and 15 mTpa sizing scenarios requiring a central pipeline diameter of 300-

400mm and 700–800mm respectively. In Figure 10 the Blue route maps out

the 5 mTpa network which can be expanded to a “Big Blue” 15 mTpa network

through the larger central pipeline and the Pink route extensions. Importation

of CO2 from out with the immediate Teesside Region may be necessary to fill

the “Big Blue” network. The Blue route has 17kms of pipeline whilst the “Big

Blue” network is more than double that length.

Operating conditions within the Onshore Gathering Network will be 100barg

and 35oC entry conditions as assumed for the design work at the four capture

sites. The CO2 composition will be defined by the offshore storage

requirements but have been assumed at >95% CO2, <50ppm water and

<10ppm O2.

Figure 9 - Overview of Onshore Gathering Network Route Options (Source Amec Foster Wheeler)



4.2.3 Offshore Network Solutions

A total of 7 Offshore Transportation were reviewed which led to further

optioneering of 2 options that were fine screened with both options going onto

Concept Development. In short these were 5 mTpa and 15 mTpa options for

both the 5/42 and Goldeneye stores. All have a common start point at the

Booster Station and all finish at the top of the riser of the host platform.

The Offshore Infrastructure is made up of Five Key Subcomponents:

• The Booster Station

• The Onshore Horizontal Directional Drill (HDD) Line to the Beach

• The Shore Approach

• The Main Pipeline

• The Delivery Termination

4.2.3.1 Booster Station

The Booster Station consists of PIG receivers from the Onshore Gathering

Network, metering, booster pumps to assure delivery pressure and a PIG

launcher for the Offshore Network. There will be three 50% duty Flowserve

booster pumps to ensure 99% uptime. These proven centrifugal pumps are

widely used on US CO2 networks and will boost the CO2 pressure from circa

100barg to that required by each of the stores which is 120barg for Goldeneye

and 100-182barg for 5/42.

4.2.3.2 Offshore Network Route

The Offshore Network route starts with a 1km long onshore HDD pipeline to

the beach navigating two natural gas lines on route. The first section of

offshore pipeline, known as the Shore Approach, requires a pre-trench area to

float the fabricated pipeline to a beach connection. The other end connects to

the Main Pipeline which conveys the CO2 to the Store location. The Transport

Line is trenched and buried in water under 50 metres deep and then laid on

the seabed. The pipeline is concrete coated to maintain depth and stability of

the line as it is installed and to protect it from interactions from ship anchors or

fishing gear. The offshore end of the pipeline consists of a subsea isolation

B

A

D

C

A E

Figure 10 - Preferred Blue and "Big Blue" Onshore Gathering Network Routes (Source Amec Foster Wheeler)



valve, platform riser and connection to the injection facilities. The proposed

Offshore Transport Infrastructure is designed for a high level of uptime at 99%.

A key consideration for the Offshore Network are the crossings over other

services such as pipelines, electrical transmission cables and communication

cables. Bridges are constructed out of concrete mattresses and dumped rock

again to protect the pipeline and the service that it crosses from interactions

with fishing gear and ship anchors.

Concept 1, Figure 11, is routed from the Booster Station to the NGC 5/42

Storage Complex. Pipeline Diameters have been established at 18 inch / 450

mm and 24 inch / 600 mm for 5 and 15 mTpa respectively. The 154km

involves:

• 3 Pipeline Crossings,

• 3 Communication Cable Crossings

• 3 Potential Electrical Transmission Cable Crossings

• A Submarine Exercise Area

Concept 2, Figure 12, is routed from the Booster Station to the Shell

Goldeneye Storage Complex. Pipeline Diameters have been established at 20

inch / 500 mm and 30 inch / 760 mm for 5 and 15 mTpa respectively. The

433km route involves four Pipeline Crossings.

It is viable to transport dense phase CO2 to either destination using proven

equipment, technologies, materials and techniques and account for such

transport through measuring and monitoring systems. Preliminary hydraulic

Figure 11 - Offshore Network route to the NGC 5/42 Store (Source Amec Foster Wheeler)

Figure 12 - Offshore Network route to the Goldeneye Store (Source Amec Foster Wheeler)



assurance has been completed which will be refined during FEED. The major

technical risk associated with the installation and operation of the offshore

infrastructure is maintaining the CO2 in the dense phase. This will be

accomplished through simple pressure management thus avoiding two phase

flow and its potential consequences of liquid hammer, drop out of dissolved

water and pump cavitation.

4.2.3.3 Injection & Storage

In the project scope it was predetermined that captured CO2 would be injected

into and stored in a sandstone saline aquifer in either the Captain Aquifer

(Goldeneye area) or Bunter Aquifer (5/42 area).

The Captain sandstone aquifer is 1500m below the seabed off the coast of

Aberdeenshire. The aquifer is well characterized with many well penetrations

enabling the long term projection of dynamic information. Further knowledge

exists through 7 years of gas production from Goldeneye and interaction with

adjacent fields. Carbon storage capacity is estimated at 34 mT in the depleted

gas field with a further estimated storage capacity of 300 mT across the

Captain aquifer as identified in the Captain Storage Development Plan

completed by Pale Blue Dot.

The Bunter sandstone aquifer is 1100m below the seabed in the 5/42 area of

the North Sea off the Yorkshire coast. The aquifer is poorly characterized with

just 3 wells and no dynamic information. Carbon storage capacity is estimated

at 200-300 mT as identified in the Bunter Storage Development Plan

completed by Pale Blue Dot.

Dense phase CO2 would arrive at an offshore facility and be injected. This

would require either a minimal facilities platform or a subsea manifold with a

number of injection wells. Metering, control and power will be connected to the

nearest hub or shore point.

The geology and local conditions, i.e. porosity, pressure, temperature etc. will

influence both the rate of injection at any one point in time and the total volume

that can be injected at a single point as simplistically represented in Figure 13

above. In other words identical wells will have differing injection capacity

dependent on the specific local geology of the store. Thus the total storage

capacity of identical wells at different parts of the store may vary between 5

and 20 mT as per the fictitious example above. Assuming each well can inject

up to 1 mTpa CO2 and store a total of 20 mT, the 5 mTpa scenario would

require 5 active wells at any one time and between 6 and 20 wells in total

across the lifetime of the operation. Wells are likely to be drilled in two to three

stages, 10-15 years apart.

Figure 13 - Dynamic Storage Capability of an Aquifer




Current operators of the potential Bunter and Captain stores are National Grid

and Shell respectively. Initial discussions were completed with both operators

indicating that neither store was likely to have injection capacity to handle an

additional 5-15 mTpa nor handle an extra 200-600 mT over 40 years. This

could be resolved by drilling additional wells and/or development of additional

stores.

For Captain, the 5 mTpa scenario would involve a development at Captain 1, a

subsea development, approximately 10km west of the Goldeneye platform.

Power and utilities are provided from St. Fergus. The Teesside Collective

pipeline goes directly to the Captain 1 subsea centre which would involve five

deviated wells, each with an injectivity of 1 mTpa and capable of storing circa

100 mT in total.

For Captain, the 15 mTpa scenario would involve two extensions to Captain 1

involving a Captain 2 subsea centre 20km west of Captain 1 and a Captain 3

subsea centre 50km west of Captain 1. A pipeline extension would run from

Captain 1 to Captain 2 and onto Captain 3. Power etc. for Captain 2 & 3 would

come from Captain 1. Captain 2 and 3 would be replicas of Captain 1 involving

five deviated wells with the same injection and storage capacity as Captain 1,

(Reference: Captain Storage Development Plan).

The Bunter Stores would be satellites of the proposed NGC development of

the 5/42 aquifer. For Bunter, the 5 mTpa scenario would involve a Bunter 1

subsea development, circa 10km east of the planned 5/42 platform. Power and

utilities are provided from 5/42. The Teesside Collective pipeline goes directly

to the subsea centre which would involve five deviated wells, each with an

injectivity of 1 mTpa and capable of storing circa 100 mT in total.

Figure 14 - Captain 1, 2 & 3 Stores

Figure 15 - Bunter 1, 2 & 3 Stores



For Bunter, the 15 mTpa scenario would involve two extensions in the 5/43

aquifer, 60km east of 5/42. Bunter 2 would require a new facilities platform

whilst Bunter 3 would be a subsea development. A pipeline extension would

run from Bunter 1 to Bunter 2 and onto Bunter 3. Power etc. for Bunter 2 & 3

would come the 5/42 host platform. Bunter 2 and 3 would be replicas of Bunter

1 involving five deviated wells with the same injection and storage capacity as

Bunter 1. Aquifer 5/43 is estimated to have a storage capacity of circa 334 mT

(BGS), (Reference: Bunter Storage Development Plan).

4.2.4 Key Operational Considerations

4.2.4.1 Term Sheet

Annex A - Transport Services Term Sheet, outlines the likely material

commercial terms that could be expected to form the basis of a CO2

Transportation Agreement for users of the proposed Teesside Collective CO2

network. The table in Section 2.3 of the Term Sheet, replicated below, outlines

the main operational parameters for captured CO2:

Attribute Condition

CO2 > 95.5%

Water < 50ppm

O2 < 10ppm

Pressure 100 barg

Temperature 35oC

4.3 Development Cost Estimate

A Cost Estimating Process was agreed to establish the Capital Expenditure

(Capex) estimate based off the Material & Equipment Lists (MEL) concluded

for each solution during the Engineering Work Package. A Cost Basis was

established to agree which items would be estimated via a Measured Cost

basis and which items would be estimated via a Factored Cost basis.

Assumptions, Battery Limits and Exclusions were also determined. The AACE

(Association for the Advancement of Cost Engineering) Class 5 definition (-

20% to +50% accuracy) was used for a Low, Medium and High projection

whereby the Medium scenario is the Capex estimate with Low being Medium-

20% and High being Medium+50%.

For the Operational Expenditure (Opex) full cost estimates were developed for

additional direct labour and associated payroll, administration and overhead

burden. Annual Maintenance and Insurance were factored at percentages of

the Capex cost. Power and water volume requirements were identified but not

costed.

4.3.1 Capture Solutions

The table below details the Capex cost estimates for the Capture Solutions

and summarises the total Capex costs for the three scenarios outlined in

Section 3. The optimum solution delivering 2.8 mTpa is estimated at £311m.



The table below details the Opex cost estimate for the Capture sites and

summarises the total Opex costs for the three scenarios. The 2.8 mTpa

solution Opex is estimated at £125m per year.

Site Opex £m pa

SSI – 1 73.2

SSI – 2 92.6

GrowHow 15.2

BOC 12.8

Lotte 4.4

Total Scenario a) (SSI 2) 92.6

Total Scenario b) (SSI 2) 125.0

Total Scenario c) 32.4

4.3.2 Onshore Solution

The table below details the Capex cost estimates for the Onshore

Transportation for the 5 mTpa and 15 mTpa scenarios.

For simplicity the Opex for both Onshore and Offshore Transportation have

been combined together and is estimated at £10.7m pa. The Opex is the same

for the two scenarios.

4.3.3 Offshore Solution

The first table below details the Capex cost estimates for the Offshore

Transportation Pipeline for the 5 mTpa and 15 mTpa scenarios. Note that a

trebling of onshore and offshore pipeline capacity from 5 to 15mT is achievable

through a relatively modest incremental capex spend of £92-104m.

The second table below details the Capex and Opex cost estimates for the

Offshore Injection and Storage for the 5 mTpa and 15 mTpa scenarios.



The Injection and Storage estimates are on the basis of the Storage

Development Plans completed by Pale Blue Dot and ongoing discussions with

both NGC and Shell. The Opex shown is a total life of project estimate based

on a 40 year operation of the Offshore System and subsequent 30 year post

closure monitoring. The Financial Security figures are from EU Guidance

Document 4 and have been benchmarked with the ROAD project in The

Netherlands.

4.3.4 Overall Cost Summary

There are a number of overall cost summaries depending on whether Scenario

a), b) or c), outlined in Section 3, is chosen and what assumptions are taken

regarding further carbon volumes from future entrants determining whether a 5

mTpa or 15 mTpa infrastructure is built onshore and offshore and at either

Bunter or Captain. Thus, included below is a very preliminary whole system

overall cost summary estimate over 40 years on a likely system design.

The system design involves Scenario b), i.e. all four emitter sites with the

precombustion option (SSI 2) at SSI capturing a total of 2.8 mTpa. The

transportation and storage infrastructure are sized for the 15 mTpa case and

CO2 is injected into the Bunter Aquifer Store. The costs are based on 2015

money with no escalation and no risk included. The opex is based on 20 year

life for the Capture plant and 40 year life for the transportation and storage

infrastructure. The preliminary whole system capex and opex cost for transport

and storage over 40 years totals £9.1bn.

The capex and opex data outlined in Section 4.3 formed data used in a

comprehensive financial model developed by Pale Blue Dot to evaluate the

Business Case for ICCS on Teesside. Section 6 summarises the key

conclusions from Pale Blue Dot’s Business Case Report.

Figure 16 - Capex and 40 year Opex for a 15 mTpa system connected to Bunter

Industrial CCS on Teesside – Summary Report 5. Commercial Overview


5. Commercial Overview

5.1 CO2 Emission Profiles

As a part of the Teesside Collective Business Case preparation, Pale Blue Dot

conducted an Infrastructure Sizing Study, see Annex B – Infrastructure Sizing

Report, on the potential demand for

CO2 transportation infrastructure

between 2020 and 2069. The aim of

the study was to determine the

potential size of CO2 transportation

infrastructure required and to verify

the assumption that the

infrastructure capacity would be

between 5 and 15 mTpa of CO2.

Using European

Union Transaction

Log Data, it was

estimated that

12mT of CO2 is

currently emitted on

Teesside from the

industrial sites

every year. In 2013

this figure was

10.8mT. Figure 17 presents the distribution of the current 12mT of emissions

depending on the emitter size, where Tier 0 represents sites with emissions

level above 1000kTpa, Tier 1 above 50kTpa and Tier 2 above 5kTpa. In Figure

18 all existing sites were arranged decreasingly according to their emissions

size. It has been found that over 80% of the cumulative emissions were

produced by only four sites, the four in this study and that SSI represents 60%

of the total emissions at just under 7.5mTpa of which only 2.1mTpa is being

considered for capture at this stage.

By predicting future emissions levels the Infrastructure Sizing Study identified

the potential demand for the CO2 transportation infrastructure on Teesside

between 2020 and 2069. The profile depends on: the start date of CCS

projects, the number of new sites opened and the operational life of the

emitting sites. Although the transportation infrastructure may have a design life

Figure 18 - Cumulative Emissions Profile

Figure 17 - Current Teesside emissions depending on source size

Figure 19 - Low Medium and High emissions forecasts for Teesside



of 40 years there is less certainty that all the industrial businesses will maintain

their current operation for such a period. CO2 emissions are proportional to

industrial output and this is in turn is related to market demand for products

and so is very different to the situation of a base-load power plant which would

have a more predictable output. Thus a future forecast was made using

probabilistic modelling of emission sources of known and possible new

additional emitters as well as reduced emissions due to business closure.

Within the model Low, Medium and High captured volume scenarios were

forecasted for the transportation and storage infrastructure, i.e. the High

volume scenario would involve every industrial site capturing at high rate and

one or more CCS Power Stations connected to the network.

In conclusion, the demand for the CO2 transportation infrastructure on

Teesside will be driven by emitters of significant size. For the four current main

emitters a capture volume of 2.8mTpa was identified. The CO2 infrastructure

would only see volume in excess of 10 mTpa in the event of a number of new

large emitters who are attracted to Teesside due to the region’s CO2

infrastructure, i.e. power stations as depicted in Figure 19 above. The

infrastructure could be also used for transportation of CO2 exported from other

parts of the UK. In such cases, investing in infrastructure of capacity 15 mTpa

could be justified.

5.2 Project Structure

As shown in Figure 20, although there is only one physical route for the CO2

the project is commercially very complex with multiple options for commercial

interfaces.

Each emission site will require a capture facility, which may be operated by the

process company, or by a third party. The operation of an Onshore Gathering

Network for gases is commonplace with many interested players for a Sole or

Special Purpose Vehicle (SPV) ownership model for the Onshore Gathering

Network potentially involving one or more emitters. The operation of an

Offshore Network for gases is also commonplace but with fewer interested

players. There are very few operators in the CO2 storage domain.

Contractually, an emitter could decide to build, own and operate (BOO) their

own capture plant and also enter into separate contracts with each of an

Onshore Transportation Operator, an Offshore Transportation Operator and a

Storage Operator. Alternatively, a disaggregated model would see commercial

contracts following the flow of CO2, i.e. an emitter has a contract with a

Capture Operator who in turn has a contract with an Onshore Transportation

Operator who in turn has a contract with an Offshore Transportation who in

turn has a contract with the Storage Operator. Or there could be a new

business opportunity for an aggregator who takes on the whole infrastructure

from Capture through to Storage. It is important to highlight the commercial

complexity associated with the Capture Sites which are likely to be a mix of

Figure 20 - Project Structure for CCS



current and future Industrial and Power solutions with a number of existing

emitters choosing to join as New Entrants at a later stage.

The CO2 network, particularly the offshore aspects, could also be created as a

piece of National Infrastructure, potentially even pan-European, to help kick

start the ICCS market. This could potentially deliver lower commercial risk and

speed up the reduction of transportation and storage costs to marginal prices.

For at least the last three decades the trend has been towards divestment of

assets by HMG alongside a strong preference for major new infrastructure

projects to be privately financed. Whilst it isn’t clear what future role HMG will

play in financing transport and storage, it is assumed for Teesside that the:

• Current HMG approach would be to provide financial support to

Competition (Phase 1) projects that enables private sector delivery of

oversized infrastructure.

• Phase 2 projects could then come forward as a lower subsidy transition to

Phase 3 projects that are stand-alone and cost competitive.

Thus, HMG will not seek to deliver Transport and Storage infrastructure via

other routes, despite potential risk, cost and programme benefits but may be

requested/expected to provide support during the operational phase.

In Section 4.1, three Battery Limits were outlined, one at each of the three

principal interfaces: Capture, Gathering and Transportation & Storage. The

study has concluded that the most likely commercial structure could mirror

these interfaces resulting in the creation of three separate Ventures as

depicted in Figure 21.

Although possible that each emitter may undertake a BOO arrangement for

their capture plant an alternative is that a Sole Operator will step forward to

become the Capture Venture. The same company could possibly complete a

BOO arrangement at all four sites, either independently or potentially through a

joint venture arrangement with the emitter(s) and/or other Venture partners.

Again a Sole Operator could become the Gathering Venture much in the same

way that a Network Operator functions for the UK’s Gas or Electricity Grid.

Nearly every Gathering Network for CO2 in the USA has been built by and is

then owned and operated by a Sole Operator. However, there is also a strong

case for the Gathering Venture to be an SPV which fits well with the Teesside

Collective philosophy. As part of the study a report was prepared, which is

contained in Annex C – Potential Ownership Options for Onshore Transport of

CO2. The report looked at a broad range of ownership aspects, which are

applicable to other parts of the ICCS infrastructure, including the risks and

opportunities associated with the pipeline sizing, construction, operation, and

maintenance and charging options and how the risks and liabilities will be

shared between each element of the chain. The creditworthiness and ability to

raise finance of different ownership models were also evaluated. The report

concluded with the recommended ownership option being a Special Purpose

Vehicle (SPV) involving emitters alongside a proven network operator, and

Figure 21 - Commercial Structure for Teesside ICCS



with either direct Government involvement or as a minimum clear Government

sponsorship, guarantees and financial support mechanisms.

5.3 Outline Commercial Solution

The working assumption for the Teesside Collective project it that Government

support will be both necessary and made available for the project to be both

built and operated. The Outline Commercial Solution is considered in two

parts, firstly the Commercial Support Mechanism governing how centrally

funded subsidy for ICCS could be applied to the Project and secondly the

nature of Commercial Agreements that Ventures would need to have in place.

5.3.1 Commercial Support Mechanism

Figure 22 shows a model for two different options for a Funding Mechanism:

1. a Storage Mechanism Payment, and

2. a CO2 CfD Emitter Mechanism

In the Storage Mechanism Payment option the CCS Authority pays a carbon

subsidy to the Transportation and Storage Venture who purchases CO2 from

the Capture Venture(s) at a contracted price customized for each emitter, pays

fixed fees to the Gathering Venture and recovered fixed fees from within the

subsidy for their own costs for the transportation and storage of CO2.

The CfD Emitter Mechanism option assumes reversed flow of the central funds

where emitting sites, via the Capture Venture(s), receive subsidy from the CCS

Authority and pay a fee for usage for each part of the transportation and

storage infrastructure.

The analysis within Pale Blue Dot’s Business Case Report evaluates which

mechanism constitutes the more cost-efficient solution with regard to

governmental support of the project. This is summarised in Section 6.

5.3.2 Commercial Agreements

The principal aspect to resolve for the network ventures will be the securing of

necessary up-front commitments or guarantees around the future usage of a

scaled-up network through Transportation Agreements, e.g. long-term supply

and off-take agreements. The need to address non-supply and non-demand

Figure 22 - Funding Mechanisms for Teesside ICCS (Source: adapted Societe Generale image)



risk is at the core of the contractual framework for a CCS network. This issue

is not uncommon in other projects based on investments requiring successful

multi- or bi-lateral commercial relationships. Long-term CO2 supply and off-

take contracts between the Emitters, Capture Venture, Gathering Venture and

Transportation & Storage Venture which are mutually agreeable is therefore a

key priority. As with natural gas pipelines, the commercial arrangements are

likely to be based on the need to secure known capacity levels. Such contracts

generally also contain penalty provisions and clauses addressing specific

concerns such as project failure or non-performance. Ultimately, the

negotiation process to develop commercial contracts may determine the

network capacity to be built.

A network approach entails many challenges, in particular from commercial,

financial, and legal perspectives, including:

• The design of a multi-user charging framework linked to the allocation of

capacity in the system that reflects the initial investment cost alongside

ongoing operation and maintenance costs;

• The development of innovative commercial structures that accommodate

first and new users/partners/owners and their different priorities for access

to the network;

• The ability to finance the construction of a network that may initially be

‘oversized’ in anticipation of future volumes of CO2 being added; and

• The metering or monitoring of the different sources of CO2 which feed into

the common network. Each source could fluctuate, so sources need to be

individually tracked and different entities need to receive specific

benefits/charges for each tonne of CO2 supplied.

Once established, the Commercial Solution should offer a reasonable amount

of flexibility with scope for future exit and entry of first users and new entrants

to provide the greatest means to insulate risk and leverage debt into the

project through the presence of well-capitalised, creditworthy entities. In

practice, a structured and negotiated process will need to emerge that serves

to bring the Venture partners along, requiring first the development of initial

memoranda of understanding, collaboration agreements, moving then towards

letters of intent and finally structured contracts.

A Transportation Agreement is a vital component of the network financing and

is likely to represent the main source of revenue for the project to service its

debt. For trust to ensue, both emitters and financial backers will seek long term

stability, flexibility, transparency and efficient local administration from the

network operator. Key areas to be covered by the transportation agreement

are:

• Volume

• Price

• Title/Liability Issues

The Transportation Agreement is typically an availability-based contract, where

the emitter's obligation to pay is independent of whether or not it ships CO2

through the pipeline, i.e. a ship-or-pay basis. The ship-or-pay obligation of the

emitter must be sufficiently tight to ensure certainty of payment. This would

need to be backed up with a robust take or pay supply agreement with the

offshore operator to ensure onward transportation.

A charging mechanism would need to be developed for emitters. This could be

based on a Capacity Only Model, Throughput Only Model or a combined "Cost

Plus" Capacity & Throughput Model. The network operators would want the

reward mechanism to focus on capacity versus utilisation to establish high



fixed costs and low variable costs. Thus an annual capacity fee to recover

capital cost over the contract length, associated Opex as recoverable rolling

fixed fees and a variable charge for gas transferred. Entry requirements and

service costs would need careful clarity and negotiation and ensure that first

movers do not become disadvantaged as the network grows. However, once

the network is established the most efficient use of capacity is promoted by

unbundling ownership from capacity and moving towards setting tariff

structures in line with variable costs. There is already extensive experience of

agreements and tariff mechanisms for private, self-regulated cooperation on

utility infrastructure on Teesside meaning that both the Onshore Gathering

Network operator and emitters should be able to develop arrangements

without too much difficulty. The design of the charging mechanism may be

affected by legal or regulatory factors.

The aggregate charge would likely comprise of three separate charges:

• EPC Charge: This covers the costs associated with the Engineering,

Procurement and Construction (EPC) of network capacity. The EPC

Charge may also include those pre-project kick-off concept and

development costs which are to be recovered as part of the project as

well as any other asset associated costs and costs of risks (e.g.

decommissioning costs, post-closure risks, etc.).

• Capacity Rights Charge: This is the charge associated with the acquisition

of the right to use a proportion of the capacity in the infrastructure

network. This charge is likely to be primarily fixed operational and

maintenance costs, i.e. those costs which are incurred due to the

operation of the assets but which are not related to the level of network

throughput, e.g. pipeline surveys.

• Use of Network Charge: The charge reflects those costs which are wholly

and directly attributable to the act of transporting and/or storing CO2 in the

infrastructure network. This charge would cover the variable cost of asset

use (incremental fuel cost, incremental financial security and insurance

costs, etc.). The fee will mostly likely be in the form of a charge per

quantity (e.g. £/Tonne) of CO2 transported.

Title will be a significant area to resolve, i.e. simple Throughput Service or Title

Transfer at each Boundary? The general view is the latter with emitters not

wanting to be involved beyond their boundary fence. However, this places a

major obligation on the Capture Venture, Gathering Network Venture and

Transport & Storage Venture to take on all of the long term risk/liability for all

the capture, transportation and storage. Who benefits from Grandfathered

Emission Trading rights if the captured carbon a) goes down the pipeline, or b)

doesn’t go down for whatever reason? Two possible scenarios are that a) the

Store Owner gets EU ETS benefits or b) the Emitters gets EU ETS benefits.

As the emitters currently get the benefit we can assume that the Network

Operator(s) have no connection to EU ETS rights and so provide a simple

conduit only.

Annex A - Transport Services Term Sheet and Annex C – Potential Ownership

Options for Onshore Transport of CO2 offer further commercial insights.

5.4 New Entrants

The potential to establish a competitive market for the Onshore Gathering

Network capacity should be pursued through continually seeking to attract

New Entrants. The efficiency of the Onshore Gathering Network design is

improved through ensuring the provision of blanked T's to enable easy low

cost access for New Entrants. System dynamics and operating regimes will

need to be reconsidered with each New Entrant.



The framework for the commercial terms for future entry should be developed

upfront and then determined in detail to match the specific needs of each New

Entrants, i.e. onshore network extension, and their impact on the existing

network, i.e. profile of incremental volume. A possible principal is that whilst

New Users should be subjected to the same Capacity Rights Charge and Use

of Network Charge as First Users, New Users should only incur an EPC

charge associated with any bespoke connection to the network and

subsequent network extensions. This would mean that recovery of the EPC

costs associated with setting up the initial Gathering, Transport and Storage

infrastructure would be borne by the First Users.

Industrial CCS on Teesside – Summary Report 6. Business Case


6. Business Case

6.1 Introduction, Reference Case & Business Model

6.1.1 Introduction

The “Industrial CCS on Teesside - The Business Case” report issued by Pale

Blue Dot Energy provides a full summary of the business case work with a

condensed summary presented within Section 6 of this report. The Business

Case work was completed during the first half of 2015, following the phase of

engineering design and costing commissioned by TVU. The project was

guided by a steering board chaired by TVU with input from teams at BIS,

DECC (Heat and Industry and OCCS).

Key issues to be addressed by the business case were identified at the start of

the project and extended during the course of the modelling work. The eight

key goals addressed are summarized below.

1. Quantify the level of financial support that might be required from

Government for various network options and demonstrate the benefit of

having an anchor project.

2. Assess the impact of two commercial support mechanisms suggested by

Societe Generale.

3. Generate insights into two potential store locations.

4. Estimate the potential benefits from installing infrastructure that is oversized

for the current demand but that could reasonably be expected to be utilised

in the future.

5. Quantify the impact of new entrants joining the network in the future.

6. Identify the likely investment returns that participant companies and future

investors might expect for the level of risk assumed.

7. Explore the impact of varying the balance of risk and reward between

private and public sector participants on the level of financial support

required.

8. Estimate the impact of a greater level of public sector participation in the

provision of offshore transportation and storage services.

6.1.2 Reference Case

A Reference Scenario was agreed that represents a credible project development scenario built around an agreed set of assumptions as summarized below.

• Emissions captured from all 4 process sites and a total of 2.8mTpa of CO2

exported into the onshore gathering system, boosted at a coastal

pumping station and piped to an as yet un-appraised and undeveloped

southern part of 5/42 aquifer.

• System transportation capacity of 5mTpa of CO2.

• Nominal storage capacity of 100mT (i.e. assume White Rose uses the

other 100mT in the structure) provided by a new platform with 5 injection

wells all controlled by the NGC platform in the northern part of 5/42.

• Transportation infrastructure life of 40 years.

• CO2 emissions from the initial anchor group of 4 sites, run for 20 years.

• The financial support mechanism has a 20 year tenor (duration).

• Commercial operations start 1/1/2024. All sites commence operations at

the same time (in practice this would likely be phased, GrowHow starting

first and their CO2 used to help commission the system).



• A common 4 year construction period, preceded by a 2 year period (2017

– 2018) of planning, development, permitting, project structuring and

design work. Effectively this assumes that there is sufficient visibility of an

investment mechanism by mid-2016.

The technical solution includes eight elements:

SSI Pre-combustion capture of 2.1mTpa CO2 using a physical absorption process on chemically shifted excess gas from the blast furnace and steel making process.

GrowHow

CO2 is captured during the Benfield process used to create ammonia. The excess CO2 (that is not used elsewhere or sold) is approximately 375kTpa and is dehydrated and compressed before export into the gathering system.

BOC Post-combustion of 305kTpa CO2 using monoethanolamine (MEA) absorption process on flue gas from the steam methane reformer unit.

Lotte Post combustion capture of 50kTpa CO2 using a MEA process on flue gas from the oil-fired heaters.

Onshore Gathering

A 17km, 14” diameter pipeline transporting CO2 in dense phase at 100bar and 35oC connecting the 4 industrial sites to the pumping station at Redcar.

Pumping Station

Three 50% duty pumps boosting pressure from 100bar to 160bar export. The station includes metering facilities.

Offshore Transport

A 154km, 18” diameter carbon steel pipeline operating in dense phase from the pumping station to the injection platform.

Injection and Storage

Platform development of the southern part of the Bunter anticline aquifer known as 5/42. 5 deviated wells each with an injectivity of 1mTpa and collectively able to store approximately 100mT. The platform receives power and utilities from the 5/42 platform 10km to the west.

The Reference Scenario exports and stores 56.5mT of CO2 over the 20 year

evaluation period, whereas transportation infrastructure has an asset life of 40

years. A 13% IRR, rate of return after-tax, to each of the project participant was

identified by the Project Steering Board as a level of return on investment that

their organisations would normally seek to cover project risks and specific CCS

technology and commercial risks. The analysis looks at the cost components of

all the project stages as well as costs for individual sites. Reference Scenario

results have been use as an orientation point for further analysis.

6.1.3 Business Model

The primary purpose of the business case modelling work was to fill a

knowledge gap in the understanding of how an industrial CCS project could work

commercially. A number of techno-economic studies have been carried out in

the past and these have tended to provide an estimate of the construction and

operating costs of projects and/or clusters. The Pale Blue Dot Energy work goes

further and examines the economic returns that are likely to be sought by project

participants. The basis is a full cost assessment including all activities from pre-

FEED through to decommissioning for all elements of the ICCS chain.

The decision–focused model was built in Excel 2013 and comprises of four main

modules; 1. Control Panel, 2. Assumptions, 3. Discounted Cash Flow (DCF)

Calculations, and 4. Results. In addition, four aspects of the Reference Scenario

were examined: the ICCS chain as a whole; industrial process; elements of the

industrial product and cost sensitivity. Results show the Developer return unless

specified otherwise. Results excluding Developer return are also provided.

Nine scenarios were designed and built to provide further the information

required by the eight key goals. The detailed composition of each scenario is



described in the Business Case Report. The following summary described how

each scenario differs from the Reference Scenario.

A Reference Scenario

B Large pipeline to the Bunter aquifer store (15MT/y rather than 5MT)

C Storage in the Captain aquifer

D Large pipeline to the Captain aquifer store

E Anchor project only (SSI)

F Ancillary emitters only

A* Low IRR for offshore transport & storage service

A** High IRR for offshore transport & storage service

G New emitter joins network, no additional infrastructure

G* New emitter joins network, additional store required

H Alternative Pricing Mechanism

A number of sensitivities were also run. All the above culminated in a wide range

of outputs being calculated and reported:

• Economic metrics include capex, opex, NPV, IRR, PIR, LCoCTS, and

unit costs.

• Operational performance in terms of production levels, CO2 created, CO2

exported, transported and injected.

• Store capacity in terms of the total volume used and appraised.

• Asset utilization in terms of proportion of pipeline capacity used.

• Numerical and graphical format

6.2 Business Case Insights & Conclusions

6.2.1 Insights

1. ICCS on Teesside is technically and commercially viable with financial

support from government. It presents a significant opportunity to export

considerable volumes of CO2 to offshore storage and in doing so make a

significant contribution to meeting climate change targets. In particular, the

initial phase described by the Reference Scenario would meet 60% of the

CCC 2030 targets for ICCS.

2. The two storage sites under consideration for the UK Government CCS

Commercialisation Programme do not have sufficient capacity or injectivity

to accept the quantities of CO2 likely to be exported from Teesside in

addition to their currently publicised commitments. Consequently

alternatives will be required for sequestering emissions from Teesside.

3. Significant economies of scale are possible if the pipeline capacity can be

more fully utilised over its lifetime. If the 15mTpa capacity pipeline were

fully utilised throughout its life then unit transportation costs would be

reduced by 80%.

4. In the smaller, 5mTpa capacity pipeline, an increase in throughput from 3

to 5mTpa reduces the transport cost by 50% on a per tonne basis.

5. Current total emissions from Teesside are approximately 12mT, 60% of

which are from the SSI steel plant. New industrial and power plant

developments could join the network to make the case for a capacity of

15mTpa over the longer term. Imports of CO2 would be also feasible.

6. Trebling the pipeline capacity to 15mTpa can be achieved with a modest

additional capital investment of approximately £104m which would require

a 7-8% increase in the level of financial support.


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7. This initial phase of the Teesside Collective project includes a third of the

emissions from SSI and capturing additional CO2 from the SSI complex is

considered to be feasible but would require additional investment.

8. A transportation and storage service provider with some substantive

storage risks underwritten by Government may provide greater value for

money, i.e. require less financial support, than one where the majority of

risk is borne by the private sector. In the example provided, financial

support is reduced by 14% to £1334m.

9. Two commercial support mechanisms were evaluated: a storer payment

model and a CO2 CfD style model. The same level of support is required

whichever of the two commercial mechanisms is applied. The policy

implications of the two options did not form part of this work.

10. Storage in the Captain Aquifer provides ready access to many of the oil

fields that are being considered for CO2 EOR – there is no such

opportunity for the Bunter Aquifer store.

11. The pricing methodology used assumes a post-tax rate of return for each

participant: this is normal from an investor perspective and may not

represent best value for money from a government perspective. An

alternative methodology such as return on capital & cost-plus might

represent a reasonable compromise.

12. The two potential storage locations have very different risk profiles; the

Captain Aquifer is quite well characterised due to 20 years of hydrocarbon

production from contiguous hydrocarbon fields such as Britannia. There is

not yet any similar understanding of how the Bunter Aquifer behaves under

dynamic conditions.

13. As in all areas of business investors will seek a larger IRR in return for

investing their capital into a risky project.

6.2.2 Conclusions

1. A Reference Scenario was designed and used as a basis against which to

test numerous sensitivities. The Reference Scenario includes CO2

captured from the 4 industrial anchor group sites, an onshore gathering

network and export via a 145km pipeline to an aquifer store in the Bunter

Formation in the Southern North Sea.

2. In the Reference Scenario 2.8mTpa of CO2 is exported. The modelling

was restricted to an evaluation period of twenty years. The infrastructure is

likely to have an operational life of at least forty years and with a significant

number of existing and future CO2 supplies the Teesside Collective project

can quite reasonably be expected to exist beyond the evaluation period.

3. The Reference Scenario exports and stores 56mT of CO2 over the 20 year

project life and requires £95/T of support amounting to £5.3b over the

project evaluation period (£1.5b in present value terms using a 7%

discount rate). This provides a 13% rate of return after-tax to each of the

project participants.

4. The pipeline has a capacity of 5mT and a lifetime of forty years, and thus

has a lifetime utilisation factor of 28%.

5. If only the SSI plant is considered then the CO2 export is reduced by 25%

to 46mT and the level of support required is 16% lower at £1.2b (PV7).

6. Removing the SSI plant from the project reduces the CO2 export by 75%

but only reduces the level of support by 33% to £1.0b (PV7).

7. Cost of capture ranges between £37-215/T for the different process

industries and the different scales at which they operate.

8. Neither of the two specific sites in the CCS Commercialisation Programme

(the depleted Goldeneye gas field overlying the Captain Formation and the

northern portion of 5/42 structure in the Bunter Formation) have sufficient



storage capacity or injectivity to accommodate the quantities of CO2 to be

exported from Teesside.

9. The two potential stores outlined in this report are locations in the Captain

and Bunter Formations in close proximity to the Goldeneye and 5/42

stores but distinct from them.

10. The 5mTpa capacity pipeline to the Bunter store is estimated to cost

£125m; some £286m less than providing the same capacity pipeline to

Captain.

11. The Captain store is approximately 433km from the planned pumping

station at the coast on Teesside. This is almost three times the distance to

the Bunter store. This greater distance causes a bigger pressure drop for a

given pipeline diameter. Thus, for a given throughput, the pipeline to

Captain will also need to have a greater diameter.

12. The Captain aquifer store in the Central North Sea (CNS) is substantially

better appraised than the Bunter aquifer store in the Southern North Sea

(SNS) for two major reasons:

13. Greater amounts of data exist for Captain.

14. The availability of dynamic performance information resulting from

decades of water injection and hydrocarbon production in the CNS region.

This provides significant confidence in the connectivity of the formation

across a large area and therefore confidence in the storage capacity

levels.

15. Appraising the Bunter is expected to cost more than at Captain due to the

differing risk profile mentioned in Insight 11. If the appraisal maturity of the

Bunter were to be raised to that of Captain with respect to its dynamic

performance then the appraisal cost would be very significant, potentially

£50m - £150m.21

16. Developing an already appraised store in the Bunter for a capacity of

100mT is estimated to cost £97m (27%) less than developing the same

capacity at the Captain Store. Again, there are two main reasons:

17. The Captain formation is situated approximately 1500m below sea level,

500m deeper than the Bunter. Consequently the wells are longer and thus

the cost of accessing the Captain store is greater.

18. The water depth at the proposed location for the Captain facility is

approximately 130m, compared to less than 50m at the Bunter location.

The deeper water requires a different and more costly style of

development.

19. A discount rate of 7% was chosen to be representative of how the

organisations represented on the Project Steering Board would evaluate

investment decisions.

20. For new supplies of CO2 that do not require additional infrastructure to the

Reference Scenario the only additional costs are associated with the new

capture plant and the incremental power used to pump the additional CO2.

Costs per tonne are reduced by 19%.

21. If the new supplies of CO2 exceed the Reference Scenario infrastructure

capacity of 5mTpa then a bigger pipeline and potentially an incremental

store are required, as well as the new capture plant. This incurs additional

capital investment. Even so, the benefits of the additional CO2 can be

significant, reducing the unit costs by 15% compared to the Reference

Scenario, depending on the magnitude of the additional CO2 supply.



Figure 23 shows the levelised cost of capture, transport and storage (LCoCTS)

for the various scenarios and highlights the three cases that examine the

impact of changing the composition of the anchor group emitter sites. The

lowest LCoCTS results from Scenario G* with a new entrant with 5mTpa of

CO2. This is driven by maximising the utilisation of the transportation

infrastructure and the store capacity. The highest LCoCTS (£391/tonne) occurs

where the amount of CO2 captured and stored is the smallest (Scenario F,

without the steel plant) and is only 27% of the CO2 captured in the Reference

Scenario. The LCoCTS fluctuates accordingly to the level of capital investment

required.

Figure 24 - Comparison of the Financial Support Required for each Scenario

The financial support required for each scenario depends on the amount of

CO2 captured and stored as well as the level of IRR required by each element

of the chain. Figure 24 shows the variation between the scenarios.

The highlighted bars represent the Reference Scenario with differing levels of

return for the transport and storage services. In the Low IRR case, the Present

Value (PV) support required is reduced by 10% (Scenario A*) whereas in the

High IRR case the required support is increased by 56% (Scenario A**).

Scenario F requires the lowest level of PV support due to smallest amount of

CO2 captured.

Figure 23 - Comparison of Levelised Costs between Scenarios



6.3 Other Key Points from the Business Case

6.3.1 Reference Scenario LCoCTS - Capture

For the entire ICCS Chain, a total of £5.4b (£1.5b PV7) of financial support is

required to meet the target return over the evaluation horizon of 20 years,

equating to £95/T. Figure 25 illustrates the distribution of that support along the

ICCS chain. However, the PET plant has a much higher cost of capture per

tonne than the other sources (see Figure 26). Excluding that plant the cost per

tonne falls to £93/T.

Figure 25 - Distribution of Cost along ICCS Chain (2015 terms)

The cost of capture is £44.8/T, as illustrated in Figure 25, over the 20 year

evaluation period this equates to £2,508m (PV7 £732m). Note that £44.8/T is

the volume-weighted average of the undiscounted financial support for all four

industrial processes. The elements of cost for each of the four processes are

illustrated in Figure 26.

Figure 26 - £/T Cost of Capture by Industrial Processes (PV terms, 7% discount rate)

Scenarios E and F show the impact of changing the composition of the anchor

group and the results compared to the Reference Scenario are summarised in

the bullets below.

• With only the steel plant included (Scenario E), financial support is

reduce to £1291m and 42MT of CO2 is captured, increasing the cost

per tonne to £107.

• Without the steel plant (Scenario F), financial support is reduced to

£1001m (PV7) and 15MT of CO2 is captured, increasing the cost per

tonne to £238 (undiscounted).



The SSI steel plant generates an order of magnitude more CO2 than any of the

other industrial plants. In this analysis the steel plant accounts for almost 75%

of the 56.5mT CO2 exported over the 20 year evaluation period.

The cost of capture ranges between £37 - £215/T CO2 according to a

combination of the CO2 intensity of the industrial process and the complexity of

the capture process. The lowest cost capture is at the GrowHow ammonia

plant which produces high quality CO2 as part of the production process.

Consequently only minimal gas conditioning and compression is required to

export CO2 at the required specification. The SSI steel works uses a more

complex process but benefits from enormous economies of scale. By contrast

the Lotte PET plant may well be able to use an “of the shelf” amine capture

plant but produces limited volumes of CO2 such that the unit costs of capture

are higher than for the other sites.

In terms of cost uncertainty, the analysis clearly shows that the greatest impact

on the amount of financial support required is the capital cost of the store and

the steel plant, closely followed by the electricity price. The uncertainty of the

capex estimates for the other three plants is not significant. This is because of

the capex required for capture at the steel plant is an order of magnitude

greater than at the other three plants.

6.3.2 Reference Scenario LCoCTS - Gathering

The terms of reference for the project stipulated that transport infrastructure of

capacities of 5 and 15 mTpa should be evaluated. The Reference Scenario

assumes capture of 2.8mTpa of CO2 and so infrastructure of 5mT capacity is

sufficient for the purposes of the current project. However a number of new

industrial and power projects are considering locating to Teesside and may wish

to use the CO2 infrastructure to minimize their emissions, in which case

oversizing to 15mT capacity would be beneficial. The characteristics of the four

permutations of pipeline are summarised in the table below.

Bunter Captain

Capacity (mTpa) 5 15 5 15

Length (km) 125 125 434 434

Diameter (in) 18 24 20 30

Capex (£m) 125 184 411 456

Cost (£m/km) 1.00 1.47 0.95 1.05

The unit cost of the large pipeline to the Bunter store is significantly higher than

any of the others. This is due to the relatively short length and non-standard

combination of diameter and wall thickness specification resulting from the flow

assurance work. In practice it is likely that a more cost effective compromise

would be available.

The analysis was conducted in two parts. First, using Reference Scenario

assumptions the transportation capex, financial support requirements and unit

cost were calculated for both 5 and 15mT capacity infrastructure. Secondly, the

impact of increased throughput was investigated using the larger infrastructure

capacity. Each part of the analysis was conducted for both the Bunter and

Captain stores.



Capacity

(MT/yr) Throughput (MT)

Gathering and Transport Cost

(£/T, excluding Return)

MT/y MT Bunter Captain

5 (Reference

Scenario) 2.8 56.5 13.6 20.2

15 3 60 15.9 22.0

15 5 100 8.6 11.9

15 10 200 4.6 6.3

15 15 300 3.2 4.3

Figure 27 - Transportation Economies of Scale

Figure 27 shows how the unit costs of transportation fall as the pipeline

throughput increases. The Reference Scenario outcomes are shown by the two

bars, one for each store location. The lines illustrate the unit costs for the larger,

15mTpa pipeline. Trebling the infrastructure capacity only requires an additional

8% of support (£64m PV7) to the project. The incremental cost and amount of

financial support required to install the larger infrastructure is almost identical for

both store locations despite their significant difference in distance from

Teesside. This is due to the higher unit cost of the large Bunter pipeline.

Larger infrastructure enables a higher level of throughput which, if utilized, would

significantly decrease the cost per tonne. An increase in throughput from 3 to

5mTpa reduces the transport cost by 50% on a per tonne basis. Additional

increases in throughput continue to reduce costs per tonne but have significantly

diminishing marginal benefit. If a 15mT capacity pipeline were fully utilized over

its 40 year life then transportation costs would be reduced by 80%.

6.3.3 Reference Scenario LCoCTS - Transport & Storage

Analyses for both storage sites were conducted using Reference Scenario

assumptions. The cost of the offshore transport infrastructure for each storage

location was calculated. Cost-effectiveness was compared between the

Captain and Bunter locations using the following indicators: capital cost

(capex), operational cost (opex) and total cost per tonne of CO2 (assuming

56.5 mT over the over the first 20 years of the life of these assets, and

therefore assuming that capital invested is repaid over that time. Inherent in

this analysis is that the two storage locations are appraised to a similar degree,

and in the case of Bunter that the White Rose project has progressed and

further appraised 5/42. Estimates of appraisal costs for each store are

included. The estimate included for the Bunter store assumes that the White

Rose project proceeds and includes further appraisal of the 5/42. If this turns



out to not be the case than an additional £50-£150m could be required to fully

appraise the formation for the quantities of CO2 contemplated here.

Cost (£m) (Undiscounted) Bunter Captain

Storage Capex 254 351

Storage Opex 504 504

Purchase of CO2 3880 5011

Offshore Transport Capex 167 469

Offshore Transport Opex 488 488

Total 5326 7061

The table above illustrates the costs associated with transporting, injecting and

storing 56.5 mT of CO2 at the two different sites. The purchase of CO2 is a

feature of the Storer Mechanism and is used to fund the capture, gathering and

transportation activity.

Figure 28 compares the components of the transportation and storage cost for

each of the stores. The major difference is the capex required for the offshore

pipeline due to Captain being approximately treble the distance from Teesside

compared to Bunter. When more than 100mT storage capacity is required an

extension or step-out store is also required. These are storage developments in

their own right and can be expected to cost a similar amount of money to develop

as the first store. Assuming that the two stores are appraised to a similar level

of maturity then the cost of offshore transport and storage for Captain is almost

25% greater than for Bunter, reaching £125 and £94/T respectively.

In addition to the transportation capex difference stated above, the Captain

Formation is 1500m below sea level. This is 500m more than the Bunter

Formation near 5/42 and since well costs are very significantly proportional to

depth the wells cost more to drill at Captain. In addition the water depth at the

proposed location for the Captain facility is approximately 130m, compared to

less than 50m at the Bunter location. The deeper water requires a different and

more costly style of development at Captain compared to Bunter. It is possible

that if the White Rose project does proceed and the Teesside ICCS project is

sufficiently mature that the development of the store at 5/42 could be altered to

provide a solution that is optimal for both sources of CO2. In this situation some

synergy would likely be possible, perhaps removing the need for a bespoke

platform and reducing capital requirements by approximately £65m. However

this outcome is considered too speculative at this stage.

Figure 28 - Breakdown of Transportation and Storage Costs for each Store



Operating costs for each store are currently estimated to be the same and to be

largely driven by the frequency of remedial work on injection wells. Offshore

transportation opex is dependent on CO2 throughput rather than length of

pipeline and therefore is the same for both storage sites.

Extending the store at Captain is considered easier and lower cost than at

Bunter. This is because the step-out Bunter store at 5/43 is approximately 60km

from 5/42 and requires an additional platform, additional wells, an in-field

pipeline and control umbilical. The subsea development at Captain would

requires additional wells and extension of the existing subsea infrastructure.

6.3.4 Funding Mechanism

A number of potential commercial support mechanisms were identified during

the study and following analysis and discussion with various stakeholders two

were considered to have the greatest potential. These two options, as

introduced in Section 5.3.1, are outlined below and followed by an assessment

of their economic impact on the project.

Storer Payment Model

Financial support flows directly to the Storer who buys CO2 from each of the emitters. The emission sites pay for gathering and transportation service

Emitter CO2 CfD Model Financial support flows directly to the Emitters who each pay for gathering, transportation and storage services

Both models are described in detail in a separate report by Societe Generale,

including implementation and policy issues. The conclusions from that report

related to each option are replicated below.

“If structured well, the Storage Driven Model helps to resolve a number of the

challenges implicit in the Emitter CfD Model, including counterparty risk, volume

risk and motivation for investment in the transport and storage assets. In

addition, the concept of availability-based commercial agreements has been

widely used for many years and is accepted by the finance market. However,

there are still significant challenges to be overcome in adapting this precedent

to the ICCS arena, including the substantial reliance government for

underpinning of the capacity payment obligations.

The Emitter CfD Model is a relatively elegant solution to the funding of an ICCS

project or cluster in that it provides for a volume based mechanism, which can

be linked to the market price of the commodity (CO2) to which it relates, and

which would adjust the subsidy level automatically with the evolution of this

price. It is also likely to benefit directly from the work already being done on the

power CfD, including commercial structuring and financing for the White Rose

CCS project if this proceeds to a successful conclusion. However, there are a

number of challenges specific to ICCS that may not be adequately addressed

directly by the mechanism, particularly around credit risk and incentive to invest.

With further work it is anticipated that some or all of the challenges could be

resolved but the result may be either a scheme where government is effectively

backstopping a range of risks or alternatively, the level of complexity is such that

neither Emitters nor potential T&S providers can be attracted to invest in the

industry.” - Societe Generale

Based on the work done to date, there does not appear to be any significant

economic difference between the two commercial mechanisms; each requires

£1.54b (PV7) of support in order to sustain the project. The amount of money

paid in storage fees is 20% less when using the CO2 CfD mechanism compared

to the Storer mechanism. This is due to the compound nature of the IRR used

in the pricing calculation. Understanding the detail of how the mechanisms might

differ in their application is a topic for substantial further study.



Mechanism

Storer CO2 CfD

Financial Support (£m PV7) 1,542 1,541

Capture Cost (£/T) 44.2 44.2

Gathering Cost (£/T) 3.2 3.2

Transporting Cost (£/T) 17.1 17.1

Storage Cost (£/T) 30.3 26.6

Total Cost (£/T) 94.7 91.1

One significant practical difference between the two models is that with an

emitter payment the storer will not be able to plan and size the project until all

emitters have reached their Financial Investment Decision (FID) - without adding

a risk premium to account for emitters "failing to get there". Quantification of the

risk premium was outside the scope of this study and consequently the impact

of it is not included with in the analysis presented here. understanding what this

premium may be is viewed as a key outcome of the CCS Commercialisation

programme.

Industrial CCS on Teesside – Summary Report 7. Execution


7. Execution

7.1 Project Execution Plan

In simple terms the Project Execution Plan can be described through the three

stages of Initiate, Influence and Implement as shown in Figure 29 below.

Figure 29 - Headline Process

The Initiate Stage involved the completion of the Feasibility Study between

July 2014 and June 2015 whereby the commercial viability of ICCS on

Teesside was assessed, quantified and qualified through the completion of the

Business Case, Commercial and Engineering work packages by experienced

advisors. This required continued engagement with the 4 process industry

companies and collaboration with DECC and BIS to sense check outputs as

they arose. The Concept Study output has been collated into a series of

reports, including this Summary Report.

At the start of 2015 the Influence stage commenced. Initially this involved the

rebranding of the project as Teesside Collective with a number of key

engagements completed, i.e. Westminster Launch Event, Knowledge Share

Event at Wynyard Hall etc. Going forward the Influence stage will see

Teesside Collective continuing to lead the engagement of DECC and others on

the Business Case and Commercial Mechanism until the Final Investment

Decision (FID) stage and potentially beyond.

Finally, the Implement stage, commenced in Q2 2015 with the aim of evolving

the key outputs from the Concept Study in to a coherent project

implementation plan that will deliver the UK’s first Regional ICCS Project.

Pale Blue Dot facilitated a risk workshop and produced a summary report,

Teesside ICCS Risk Workshop Report, outlining the key risks to be considered

in the Execution Plan for the Teesside Collective project.

7.2 Key Milestones

Figure 30 provides a highlevel overview of the project’s key milestones. The

overview shows the major milestones for the Teesside Collective project

alongside key external factors that present considerable political and market

risk and opportunity. The project faces two General Elections with new

Governments /Ministers in place to change plans for the better or worse. The

project is running in parallel with the UK CCS Commercialisation Programme,

both Phase 1 (Peterhead & Whiterose) and the proposed Phase 2 follow on

projects.



Building on the Feasibility Project, Teesside Collective will need to now steer

the project through Pre-FEED (Front End Engineering Design) into FEED and

ultimately a Financial Investment Decision (FID) envisaged for 2020. A

successful FID enables construction to be complete leading to carbon being

sequestered before the mid-2020s. The aspiration is to be able to bring these

key milestones forward. Agreeing an appropriate commercial support

mechanism with the UK Government is the critical path item for the project.

7.3 Project Schedule

To be successful the Teesside Collective will need to continue to provide

leadership and establish the route by which Industrial CCS can be delivered in

the UK. No other region yet has a project at the same level of maturity and with

sufficient ambition to lead the way. Industrial CCS is critical to enable the UK

to meet its carbon reduction targets, and unlike power generation, more

difficult to substitute with alternative energy sources. Teesside Collective

should therefore continue to provide leadership by progressing though the next

stage of development.

The proposed Project Schedule, Figure 31, expands the high level timeline in

Section 7.2. The Project Schedule outlines the six major Milestones, the four

Delivery Stages and the Key Deliverables that are required for successful

project implementation. An initial ‘Bridge’ stage links the existing Feasibility

Study work with Pre-FEED. This is followed by FEED and then Execution and

Financing, which lead to FID. The overall period for these activities to FID, is

shown as 5 years. Each of the Stages is discussed in further detail in the

subsequent sections.

Given the pace of power generation CCS in the UK over the last 8 years, the 5

year timing to FID could be regarded as overly ambitious. However, the timing

is important for two reasons; firstly, pressing forwards with the Teesside

Collective project will demonstrate the need to progress funding mechanisms

Figure 30 - High Level Timeline for the Teesside Collective

Figure 31 - High Level Project Schedule



for ICCS and; secondly, the need for action on climate change mitigation is

becoming ever more urgent.

Each Delivery Stage would comprises of eight major Workstreams:

• Engineering & Design

• Consenting & Permitting

• Commercial Development

• Finance & Economics

• Communications

• Knowledge Transfer

• Storage Development

• Project Management

Of particular note, the ongoing Communications Workstream is fundamental to

the success of the project. Teesside Collective provides a project brand and

professional image with which to promote ICCS and the project. Providing a

distinct communication portal enables promotion of the project and improved

communication to external stakeholders to maintain and build momentum and

enables the launch of reports and engagement material locally, nationally and

internationally. A lobbying plan has been developed for the project including

key messages, key people, key outputs and key dates that drives the

development of meetings with key people including UK government, EU

Commission, Trade Associations, NGO’s, and others. The overall aim is to

promote the project in a way that captures attention and embeds the outcomes

required for successful delivery of the project within government work

programmes and the other seven major Workstreams.

The Feasibility Study has moved a project concept into a clearly articulated

project development opportunity. The work completed lays the foundations for

the next steps. However, for a number of reasons the project is not yet ready

to commence Pre-FEED. Most important of these, is the need to develop a

funding plan and funding sources to enable Pre-FEED activity to take place.

There is a need for a Bridge stage to link the existing work with the Pre-FEED

activity. This stage is expected to take 12 months with activities including:

• Securing public funding for the pre-FEED stage

• Preparing for pre-FEED

• Developing options and routes for a) FEED funding and b) project delivery

• Putting in place a Project Development vehicle

• Building depth in the Teesside Collective brand

• Transitioning into Project delivery mode

• Continuing to progress the funding model for ICCS

• Retaining a position at the centre of UK CCS thinking

• Maintaining engagement with industrial partners

• Allowing time for the DECC Commercialisation projects to move forwards

The key aim of the Pre-FEED Delivery Stage is to secure the funding

necessary to complete FEED. This involves taking and refining the Basis of

Design for capture, transportation and storage developed at the Concept

Stage and using this to develop a detailed Cost Time Resource Plan for

delivering FEED. In parallel the Business Case and Commercial Mechanism

thinking will be evolved and be used alongside the FEED Plan to establish

both the funding levels required and funding routes for FEED whilst also

concluding the optimum Project Developer solution. Activity may include

application for FEED funding through NER400 or DECC Phase 2 projects,

depending on timing of these initiatives. Pre-FEED success involves a clear



view of the longer term project funding mechanism or the process and

timetable by which it is expected to be developed, along with investment and

risk material. Pre-FEED is expected to take 6 months.

The FEED stage is expected to be similar in nature to the FEED activities

undertaken on the previous and current UK CCS projects. It will address a

wide range of technical design aspects for the full CCS chain, commercial and

contractual arrangements, project finance, permitting and environmental

matters and stakeholder engagement. The output will provide sufficient

confidence that the project can be delivered with a reasonable cost certainty

and the risks are manageable. If funded with public support it is likely there will

be a strong Knowledge Transfer element. FEED is expected to take 18

months. Separately a Store Appraisal will be required.

The final Stage prior to FID is the Execution and Financing. During this stage

the material developed during FEED is translated into the technical and

commercial documents and arrangements required to deliver the project. The

Project Contract would be finalised with the Authority, EPC contracts would be

finalised for the detailed design and construction of the project, permits and

consents would be in place or available shortly thereafter, agreements

between project partners would be in place and project finance arranged. Two

key challenges of this period are that FID may be determined, to some extent,

by external factors; and the project team assembled for FEED are likely to

disperse, during what is essentially a commercial/finance stage, before being

needed back for project execution. Execution and financing is expected to take

up to 2 years.

The project will then move into the fourth and final Delivery Stage of

Construction / Implementation of the full supply chain solution. The Operations

& Maintenance plan will be finalised in parallel. The ICCS network will be

commissioned and commence operation via a phased ramp up plan.

Figure 32 provides an early stage indication of Construction Stage scheduling.

The schedule focuses on SSI, the anchor site for the project given SSI delivers

the material amount of CO2 that justifies the offshore infrastructure investment.

Equivalent schedules would be developed for the capture installations at

GrowHow, BOC and Lotte. Note that the schedule for SSI involves CO2 from

GrowHow. It is anticipated that the far simpler solution for post process capture

of further material volume of CO2 at GrowHow will ensure that there is a

suitable supply of CO2 for fully commissioning and proving the full

transportation and storage infrastructure ahead of commissioning the more

complex capture technology at SSI. A further schedule would be developed for

the storage infrastructure installation.

The aim would be to place all EPIC (Engineering Procurement Installation &

Commissioning) contracts within 3 to 6 months of Financial Close. The

contract for pipe supply and pipeline fabrication is a critical path item with the

need to schedule fabrication time within the factory for the line pipe and ensure

slots for lay barges are reserved well in advance of the detailed engineering

being completed.

Detailed engineering will take 12-15 months from Financial Close. Fabrication

of the line pipe will be undertaken in parallel and take approximately 12



months with a further 3 months required to complete the concrete coating. The

pipeline installation commences with a pre-lay survey and route clearance, in

parallel with the onshore construction of the horizontal directional drill (HDD)

line from the booster station to the beach, the beach preparation works and

shore approach pre-dredging activities. Line pipe will be assembled offshore

on the lay barge and floated through the pre-dredged area to be connected to

the HDD line and the remainder of the pipeline will be installed off the rear of

the lay barge. Pipeline and cable crossings will be erected ahead of the lay

barge so that they can support the laid pipeline. Final connections will be

completed at the selected storage complex.

The commissioning activities include pressure testing of the installation and

drying out the entire pipeline length through the use of pigs, air drying and

slugs of methanol between two pigs. An integrity survey will be completed prior

to the pipeline being filled with nitrogen and then filled gradually using CO2

from GrowHow.

The entire EPIC duration should be within 42 months of Financial Close, with

SSI coming on stream 3-6 months later. Thus an overall schedule of around 48

months from Financial Close to full commercial operation of the SSI anchor

project including injection of CO2 into the offshore store.

Figure 32 - Execution Schedule from Progressive Energy's TVU CCS Pre-FEED Study for the Outline Execution Strategy for delivery of the SSI Anchor Project

Industrial CCS on Teesside – Summary Report 8. Getting to FEED


8. Getting to FEED In order to successfully deliver the UK’s first Regional Industrial CCS scheme

on Teesside, three immediate next steps are recommended:

Establish The Teesside Collective as the implementation company.

Teesside Collective contains representation from four main industrial emitters

in the region. Transforming Teesside Collective into an SPV results in an

Industry led business delivering the implementation of the project. The SPV

would be jointly owned by TVU, the emitters and developers involved. The

commercial structure should allow new parties to join the Collective and also

provide exit options at various points of project development. A Teesside

Collective SPV is likely to be equivalent in size to a FTSE 250 business which

would require to be adequately funded, resourced and governed.

Maintain focus on ICCS and build on the progress made to date. The

DECC funded Industrial CCS Feasibility Study has proved that ICCS on

Teesside is viable. The outline design has been validated with capture and

transport and storage options narrowed down and evaluated and fully costed

scenarios presented. Business and Commercial Cases have been developed

and a lauded Teesside Collective profile established. In short, “the what” has

been established. Teesside Collective now need an interim plan that

commences work on “the how”, specifically covering the transition from the

end of the Feasibility Study through to start of the Pre-FEED activity as

outlined as the Bridge stage in Section 7.3.

Commence project development activity. Teesside Collective should seek

to create a project structure that is operationally and financially credible and

engage with a number of experienced developer organisations on each of the

elements of the project. A number of developers have already indicated

interest. As stated in Section 7.2, agreeing an appropriate commercial

mechanism with the UK Government that leads to a DECC Contract is the

critical path item for the project. This would need resolution before any

significant investment will be found that would enable progress beyond Pre-

FEED.

Figure 34 provides an overview of some of the key cost considerations for

delivering each of the key stages.

Figure 33 - Key cost considerations for getting to FEED and beyond

Industrial CCS on Teesside – Summary Report 9. Conclusions


9. Conclusions 1. ICCS on Teesside is technically and commercially viable and presents a

significant opportunity to capture, gather, transport and store considerable

volumes of CO2.

2. The study has established the technical and infrastructure solutions

required for a Reference Scenario to capture and store 2.8 mTpa of CO2

from four industrial sites by the early 2020’s and offers the potential for

other emitters to connect to the network to enable the sequestration of

significantly higher volumes.

3. At 7.1 mTpa SSI accounts for approximately 65% of the 10.8 mT emitted

from Teesside in 2013. Only a third of the SSI volume is recommended for

capture at this stage alongside much smaller volumes from GrowHow,

BOC and Lotte. The region would need significant advancement in capture

technology and cost reduction together with major new built plants in the

region or CO2 imported from other regions in order to fill 15mT capacity

infrastructure. A portfolio approach should be taken to ensure a broad mix

of emitters to mitigate risk of one or more emitters leaving the network.

4. Three Battery Limits have been established, one at each of the three

principal interfaces: Capture, Gathering and Transportation & Storage.

5. For Capture the optimum solution delivers 2.8 mTpa of CO2 for a capex of

£311m and opex of £125m per annum. Key technical and cost insights for

Capture are:

a) SSI can be the anchor project that underpins a regional CCS

infrastructure.

b) At SSI, precombustion capture on furnaces gases delivers 2.1 mTpa of

CO2 for a capex of £192m and opex of £ 93m pa.

c) At GrowHow, straight forward dehydration and compression delivers

375 kTpa of CO2 for a capex of £28m and opex of £15m pa.

d) At BOC, post combustion capture via a bespoke conventional amine

process delivers 305 kTpa for a capex of £56m and opex of £13m pa.

e) At Lotte, post combustion capture via an off the shelf packaged amine

solution delivers 50 kTpa for a capex of £35m and opex of £4m pa.

f) For the three specific scenarios outline in Section 3:

i) Anchor Emitter (SSI) only: As per b) above.

ii) All four sites: 2.8 mTpa for a capex of £311m and an annual opex

of £125m.

iii) Three smaller sites: 0.7 mTpa for a capex of £118m and an annual

opex of £32m.

6. For Gathering the optimum solution delivers 15 mTpa of capacity through

>34km of 100barg Onshore Gathering Network infrastructure for a capex

of £77m and a combined onshore and offshore transportation annual opex

of £11m.

7. For Transportation & Storage it is viable to transport dense phase CO2 to

either the Bunter or Captain sandstone saline aquifers. Key technical and

cost insights for Transportation & Storage are:

a) With a design life of 40 years and a High Volume emissions scenario,

a 15mTpa gathering and transportation infrastructure would gradually

be brought up to full capacity and would require a three stage storage

development at either Bunter or Captain, with each stage totalling

100mT. Each stage would require five active 1 mTpa injection wells at

any one time and between 6 and 20 wells in total across the lifetime of

each stage.

b) For Bunter an Offshore solution would have a one off capex cost of

£254m and an annual opex cost of £294m for a 5 mTpa system or



alternatively have a one off capex cost of £579m and an annual opex

cost of £294m for 10 mTpa scenario involving two stages of storage

development.

c) For Captain an Offshore solution would have a one off capex cost of

£351m and an annual opex cost of £294m for a 5 mTpa system or

alternatively have a one off capex cost of £640m and an opex cost of

£294m per pa for 10 mTpa.

d) The Captain store is 433km from the planned booster station at the

coast on Teesside. This is almost three times the distance to the

Bunter store. This greater distance causes a bigger pressure drop for

a given pipeline diameter, thus necessitating a greater diameter

pipeline to Captain.

e) The Captain aquifer store is substantially better appraised than the

Bunter aquifer store for two major reasons:

i) Greater amounts of data exist for Captain; and

ii) The availability of dynamic performance information resulting from

decades of water injection and hydrocarbon production in the

Central North Sea region. This provides significant confidence in

the connectivity of the formation across a large area and therefore

confidence in the storage capacity levels.

f) Capex for developing the Bunter store is significantly lower than the

Captain Store for two main reasons:

i) The Captain formation is situated approximately 1500m below sea

level, 500m deeper than the Bunter. Consequently the wells are

longer and thus the cost of accessing the Captain store is greater.

ii) The water depth at the proposed location for the Captain facility is

approximately 130m, compared to less than 50m at the Bunter

location. The deeper water requires a different and more costly

style of development.

8. A trebling of onshore and offshore pipeline capacity from 5 to 15mT is

achievable through a relatively modest incremental capex spend of £92-

104m. Hence the conclusion that the transportation infrastructure should

be set at 15 mTpa.

9. The most likely Project / Commercial Structure going forward may seek to

mirror the three battery limits, i.e. a Capture Venture, Gathering Venture

and a Transportation & Storage Venture.

10. Although feasible that an emitter may wish to build, own and operate

(BOO) their capture plant it is more likely that a third party sole operator

will become the Capture Venture at each emitter and potentially the same

entity for all four emitter sites.

11. Pale Blue Dot complete a report on “Potential Ownership Options for

Onshore Transport of CO2” which concluded that the Gathering Venture

could be a Sole Operator or ideally a Special Purpose Vehicle (SPV)

involving emitters alongside a proven network operator, i.e. The Teesside

Collective.

12. The Commercial Solution should offer a reasonable amount of flexibility

with scope for future exit and entry of first users and new entrants to

provide the greatest means to insulate risk and leverage debt into the

project through the presence of well-capitalised, creditworthy entities. In

practice, a structured and negotiated process will need to emerge that

serves to bring the Venture partners along, requiring first the development

of initial memoranda of understanding, collaboration agreements, moving

then towards letters of intent and finally structured contracts.

13. Key for the three Ventures will be securing the necessary up-front

commitments or guarantees around the future usage of a scaled-up

network through Transportation Agreements, a vital component of the

network financing. Title will be a significant area to resolve, i.e. simple

Throughput Service or Title of Transfer at each Boundary.



14. A charging mechanism would need to be developed with the aggregate

charge likely to comprise of three separate charges; an EPC Charge

(Engineering, Procurement & Construction), a Capacity Rights Charge and

a Use of Network Charge.

15. Pale Blue Dot complete a Business Case for ICCS on Teesside. The

Insights and Conclusions from the Business Case are listed in Section 6.2.

with the Executive Summary from the separate report included below:

Strategic Highlights

The economics of industrial CCS (ICCS) are different to those in power

CCS. The cost of CCS in the power industry, where international trade is

minimal, can be passed onto consumers via a Contract for Difference,

(CfD). However, the competitive nature of globally traded commodity

products means industrial emitters are unable long term to do this. The

current absence of a funding mechanism means that no private company

will develop an industrial CCS scheme on its own.

ICCS from Teesside is technically and commercially viable, with financial

support from government, and provides a cost abatement option for the

UK. ICCS can reduce industrial CO2 emissions by 90% and with the right

financial support mechanism it can represent good value for money for

government.

The Teesside ICCS project would leverage Government investment in

CCS by planning to use knowledge gained on the stores currently being

evaluated in the CCS Commercialisation Programme.

The project could be operational within 7 years of the funding mechanism

being negotiated between government and the developers. This lead time

could be reduced if a separate arrangement was to be put in place to

cover the detailed engineering, design and planning work required before

the final investment decision point.

In GVA terms, the economic impact on the region is estimated to be in

excess of £500m annually.

Financial Highlights

The Reference Scenario requires £1.5 billion of financial support (in

present value terms using a 7% discount rate), which equates to

£95/tonne (undiscounted) for the 56.5mT of CO2 stored over the 20 year

evaluation period. Transportation and storage costs are spread between

all uses on a cost per tonne basis.

In present value terms the capital investment required to construct (and

later decommission) the network is £0.5 billion; the operational

expenditure to run the network is £0.6 billion and the investment return

likely to be sought by developers is £0.4 billion. The bulk of the capital

spend is on capture at the steel plant (25%) and development of the

offshore CO2 store (35%). The offshore pipeline accounts for a further 20%

of capital investment.

The four industrial processes considered have differing levels of CO2

intensity and consequently the cost impact of CO2 capture on the creation

of industrial products varies widely and is between £16 and £302 per

tonne.

During the course of this study a number of organisations have indicated a

degree of interest in investing in specific elements of the chain, subject to

an appropriate funding mechanism being in place.

Two commercial mechanisms were evaluated; a storer payment

arrangement and a CO2 CfD arrangement. From an economic perspective

there was little difference in the two approaches.

Significant economies of scale are possible, particularly in the offshore

pipeline element of the chain, where costs per tonne of CO2 transported

could be reduced by up to 80%. An additional 8% investment in financial



support could treble the transportation capacity and provide space for

future CO2 supplied from Teesside.

The major areas of CCS specific risk are considered to be associated with

the geological storage of CO2. A qualitative assessment of risk allocation

between Government and the developers of the store shows that the level

of support is dependent upon the share of risk borne by developers, and

vice versa.

Looking Ahead

Future work should build upon the Business Case Study, and the

associated work by Societe Generale, to further develop an appropriate

financial support mechanism. The next phase of work should be a

significantly more detailed commercial, technical, financial and policy

analysis based on the CO2 CfD Model and Storer Model. The aim should

be to develop a model that is acceptable to both Industry and Government

such that investors are prepared to invest in the next phase of engineering

in 2017. If this can be attained then construction could start three years

later and the project could be operational by 2024.

16. Building on the Feasibility Project, Teesside Collective will need to now

steer the project through to completion. An initial “Bridge” stage is required

to link the existing Feasibility Study work to Pre-FEED (Front End

Engineering Design), then progress into FEED and ultimately to a

Financial Investment Decision (FID) envisaged for 2020. A successful FID

enables construction to be complete leading to carbon being sequestered

before the mid-2020s.

17. The Bridge Stage is expected to take 12 months. Pre-FEED is expected to

take 6 months. FEED is expected to take 18 months. Execution and

Financing through to FID is expected to take 2 years. Engineering

Procurement Installation & Commissioning is expected to take 4 years and

cost circa £0.77-2.12bn depending on the technology and capacities

chosen for the installed scheme. Operational Expenditure (Opex) is

expected to cost £7.4-14.7bn again dependent on system design and

sizing and with a life time of 20 years for capture plant and 40 years for

transportation and storage infrastructure.

18. Agreeing an appropriate commercial support mechanism with the UK

Government is the critical path item for the overall project whilst ongoing

communications and engagement via The Teesside Collective is

fundamental to promoting ICCS and delivering a successful project.

19. The Teesside Collective will need to continue to provide leadership and

establish the route by which Industrial CCS can be delivered in the UK.

The three immediate next steps recommended are:

a) Make Teesside Collective the implementation company

b) Build on the progress made to date

c) Commence project development activity through delivery of the initial

“Bridge Stage” that secures funding for and initiates the Pre-FEED

work.

With respect to techno-economic aspects, the Feasibility Study is showing that

Industrial CCS at scale is technically feasible and that it is essential to

establish an attractive commercial support mechanism with the UK

Government as soon as possible. This will ensure the scheme delivers the

economic benefit directly from CCS and indirectly through developing

sustainable heavy industrial manufacturing centres coupled with Decarbonised

Power Generation at key locations across the UK.

Industrial CCS on Teesside – Summary Report Annexes


Annexes

Annex A - Transport Services Term Sheet

Industrial CCS on Teesside

Transport Services Term Sheet for First Users and

New Users

Author: Pale Blue Dot Energy

1. INTRODUCTION

There is considerable local and global experience of the operational and

commercial issues involved in gas transportation, including carbon dioxide.

This document is drafted as a pro-forma Term Sheet and outlines the likely

material commercial terms that could be expected to form the basis of a CO2

Transportation Agreement for users of the proposed Teesside CO2 network.

2. MATERIAL TERMS

2.1 Primary Service

For the Network Operator the primary service will be the transportation by

pipeline of CO2 that meets the network specification, from a defined system

entry point to the system exit point at the pressure boosting pumping station at

Redcar. Metering is also part of the primary service.

The primary service of a Network User is to supply CO2 at a certain rate for a

specific period of time and within the required compositional specification.

2.2 Legal Boilerplate

Primarily; definitions, term, termination, parties, legal jurisdiction,

confidentiality. In the first instance the Parties are expected to be the Network

Users: SSI, GrowHow, BOC, Lotte Chemicals and the Network Operator.

2.3 CO2 Specification

This is described in detail in the CO2 specification document produced as part

of this overall project, reference 2000 0005-DC00-SPC-0001. The primary

attributes are listed below. This section will also likely contain the throughput

ramp rates.

2.4 Charging Mechanisms

The design of the charging mechanism may be affected by legal or regulatory

factors, of particular relevance are regulations regarding third party access to

CO2 transport and storage infrastructure. The aggregate charge seems likely

to comprise three separate charges:

Attribute Condition

CO2 > 95.5%

Water < 50ppm

O2 < 10ppm

Pressure 100 barg

Temperature 35oC



2.4.1 EPC Charge

This covers the costs associated with the engineering, procurement and

construction of network capacity. The EPC Charge may also include those pre-

project kick-off concept and development costs which are to be recovered as

part of the project as well as any other asset associated costs and costs of

risks (e.g. decommissioning costs, post-closure risks, etc.).

2.4.2 Capacity Rights Charge

This is the charge associated with the acquisition of the right to use a

proportion of the capacity in the infrastructure network. This charge is likely to

be primarily fixed operational and maintenance costs, i.e. those costs which

are incurred due to the operation of the assets but which are not related to the

level of network throughput, e.g. pipeline surveys.

2.4.3 Use of Network Charge

The charge reflects those costs which are wholly and directly attributable to the

act of transporting and/or storing CO2 in the infrastructure network. This

charge would cover the variable cost of asset use (incremental fuel cost,

incremental financial security and insurance costs, etc.). The fee will mostly

likely be in the form of a charge per quantity (e.g. £/Tonne) of CO2 transported.

2.5 Liabilities

Specific liabilities attaching to the Parties will depend wholly on the commercial

structure of the project and how it is funded. The following table summarises

those liabilities considered at this stage to likely be the most material.

Network Operator CO2 leakage from the onshore network

Supply of CO2 to the System Exit point, i.e. Pumping Station

Inability for Offshore Network to receive CO2

CO2 Suppliers Consequences of supplying “off-spec” CO2

Consequences of not meeting any “send or pay” obligations

2.6 Information Sharing

There will be obligations on the Parties to share certain information such as

planned shutdowns, unplanned interruptions to CO2 flow, changes to CO2

composition, safety, operational or environmental critical items.

2.7 Asset Ownership

The pipeline network and associated equipment are likely to be owned by the

transportation company. Use of the network is unlikely to confer any ownership

rights.

2.8 CO2 Title

Certain liabilities and obligations attach to the entity that has title to the CO2.

This is a highly uncertain area and there are no precedents within the EU. It

seems most likely that in most cases title will remain with the emitter, with the

possible exception of once the CO2 has been injected.



Annex B - Infrastructure Sizing Report


TVU Infrastructure Sizing Report


1. EXECUTIVE SUMMARY

As a part of the Teesside Collective Business Case preparation, the Pale Blue

Dot Energy (PBDE) team conducted a study on the potential demand for CO2

transportation infrastructure between 2020 and 2069. To forecast potential

demand, three possible Cases have been considered: Lower, Base and

Upper. Based on the analysis completed it has been concluded that

infrastructure with a capacity of 10 mTpa will be required for the project.

2. RECOMMENDATION

Based on the analysis completed The Teesside Collective should seek to size

the CO2 transportation infrastructure on Teesside to meet a future demand for

the CO2 sequestration in the order of 10 mTpa. Although potential demand in

excess of 10 mTpa is highly unrealistic, if Teesside Collective were to choose

between their two Business Case capacity options of 5 mTpa or 15 mTpa then,

from an emissions profile perspective, the recommendation would be 15

mTpa, given both the Base and Upper Cases far exceed 5 mTpa.

3. INTRODUCTION

The Process and Steel Industries on Teesside are seeking a regional industrial

Carbon Capture & Storage (CCS) solution. The aim of the PBDE infrastructure

sizing study was to provide a recommendation on the potential size of required

CO2 transportation infrastructure and to verify the previously stated

assumption that the project will require between 5 and 15 mTpa in CO2

infrastructure capacity.

Using European Union Transaction Log Data, PBDE estimated that 12 mT of

CO2 is currently emitted in Tees Valley every year. By predicting future

emissions levels PBDE study identified potential demand for the CO2

transportation infrastructure on Teesside between 2020 and 2069.



4. DEMAND FOR CO2 TRANSPORTATION INFRASTRUCTURE

4.1 Current emissions

12 mT of CO2 is currently emitted on Teesside from the industrial sites every

year. Figure 1 presents distribution of those emissions depending on the size,

where Tier 0 represents sites with emissions level above 1000kTpa, Tier 1

above 50kTpa and Tier 2 above 5kTpa.

In Figure 2 all existing

sites were arranged

according to their

emissions size, largest

to smallest. It has

been found that over

80% of the cumulative

emissions were

produced by only 4

sites.

It can be observed that

the marginal impact of

capturing emissions decrease with each subsequent site. Therefore, whether

or not CO2 is captured from each of the biggest 4 emitters will have a

significant impact on the required infrastructure size.

4.2 Future emissions and capture

To predict future levels of CO2 captured on Teesside PBDE modelled three

potential Cases: Lower, Base and Upper while allowing for variation in the start

date of capturing, system longevity and also the number of capture projects

and their respective captured emissions rates. Appendix 1 includes detail

assumptions for each of the Cases. The summery of the levels of captured

emissions between 2020 and 2069 is showed in Figure 3. Each of the Cases is

discussed in more detail in sections 4.2.1-4.2.3 respectively.

9.7

2.30.3

12Mt CO2 currently emitted

Tier 0, > 1000ktpa

Tier 1, > 50ktpa

Tier 2, > 5ktpa

Figure 1 Current emissions depending on source size

Figure 2 Cumulative percentage of emission according to number of

industrial site in Tees Valley



4.2.1 Lower Case

Distribution of the total captured emissions depends on the start date of the

capture infrastructure, the duration of operation and capture volume of capture

plants at existing emitter sites on Teesside and also the number of new emitter

sites opened on Teesside and their respective capture volume and duration of

operation. The Lower Case model assumed low emissions (based on 2008

emissions data), short longevity of capture (8 years), comparatively low

capture rate (75%), and limited number of sites capturing CO2 (see

Appendix 1). First capture is to take place in 2025 due to slow progress of the

project. The maximum utilisation of the infrastructure is 5.2 mTpa over a period

of 6 years, excluding a 6.3 mT one year peak in 2032. The summary of the

results for the first 15 years from the analysis model is presented in Table 1

(detailed data may be found in Appendix 2). The comparison of emitted and

captured CO2 is presented in Figure 4.

Table 1 – Lower Case 2020-2035 Results: Total CO2 emitted (mTpa), Total CO2

Captured (mTpa) and captured percentage.

Figure 3 CO2 captured rate prediction for Lower, Base and Upper Case

Figure 4 CO2 emissions vs capture rate prediction for Lower Case



4.2.2 Base Case

The Base Case model assumes business as usual emissions (based on 2013

emissions data), medium longevity of the capture infrastructure (15 years)

and an average capture rate (80%). The model assumes that all the existing,

planned and possible new sites, including a new IGCC power plant, will start

capturing at different points in time, (see Appendix 1). The first capture is to

take place in 2020. The summary of the results for the first 15 years is

presented in Table 2 (detailed data may be found in Appendix 2). The

comparison of emitted and captured CO2 is presented in Figure 5. The

maximum utility of the infrastructure is equal to 15 mTpa and only lasts two

years, which is not long enough to consider it as a required maximum. With the

peak excluded an appropriate infrastructure capacity is 10 mTpa.

Table 2 – Base Case 2020-2035 Results: Total CO2 emitted (mTpa), Total CO2 Captured (mTpa) and captured percentage.

4.2.3 Upper Case

The Upper Case model assumes a high level of emissions (110% of 2013

emissions data), long longevity of the projects (25 years) and a high capture

rate (90%). All the existing, planned and possible new capture sites, including

a new IGCC power plant, will start capturing very early with over 50% of

emissions already being captured by 2020. The maximum utility of the

infrastructure is equal to 19 mTpa with maximum utilisation lasting 19 years.

The summary of the results for the first 15 years is presented in Table 3

Figure 5 CO2 emissions vs capture rate prediction for Base Case



(detailed data may be found in Appendix 2). The comparison of emitted and

captured CO2 is presented in Figure 6. This scenario is very unlikely.

Table 3 – Upper Case 2020-2035 Results: Total CO2 emitted (mTpa), Total CO2 Captured (mTpa) and captured percentage.

CONCLUSIONS

The demand for the CO2 transportation infrastructure in Tees Valley will be

driven by emitters of significant size. Only in the event that a number of new

sites start operating with large emissions will future demand on the CO2

transport infrastructure exceed 10 mTpa. The transportation infrastructure

could be also used for CO2 exported from other parts of the UK. If the latter

were to occur at scale then investing in 15 mTpa of infrastructure capacity

could be justified.

Governmental policy supporting or requiring industrial carbon capture and

storage will play a significant role in the decision making of businesses on

whether or not to invest in carbon capture technologies. This will be especially

important with the potential for changing ownership of operational sites where

the emission duration will outlive the companies that own such sites.

The presented results are predictions developed to provide input for the

economic assumptions developed for the purpose of the Teesside Collective

Business Case. It has to be stressed that these predictions may be subject to

significant change depending on the future economic circumstances of the

Teesside Region.

APPENDIX 1 - MODELLING ASSUMPTIONS

The following two pages contain a copy of the assumptions used in the model

for each emitting site.

Figure 6 CO2 emissions vs capture rate prediction for Upper Case



APPENDIX 2 – DETAILED RESULTS

The following 2 pages show Lower, Base and Upper Case detailed results.



LOW CASE 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044

Total CO2

Emitted (ktpa) 7516 7516 7516 7516 7516 7516 7516 7516 7516 7516 7656 7656 8382 3536 3579 1745 1745 1745 1745 1745 1032 1032 1032 1032 1032

Total CO2

Capture (ktpa) 0 0 0 0 0 2944 2944 5102 5102 5102 5207 5207 6287 2652 2685 1309 1309 1309 1309 1309 774 774 774 774 774

Captured

Percentage 0% 0% 0% 0% 0% 39% 39% 68% 68% 68% 68% 68% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75%

2045 2046 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 2058 2059 2060 2061 2062 2063 2064 2065 2066 2067 2068 2069

Total CO2

Emitted (ktpa) 892 892 166 166 123 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Total CO2

Capture (ktpa) 669 669 125 125 92 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Captured

Percentage 75% 75% 75% 75% 75%

BASE CASE 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044

Total CO2

Emitted (ktpa) 10850 10850 10850 10850 10850 10901 10901

1090

1

1090

1

1090

1

1209

6

1209

6

1209

6

1210

1

1210

1

2071

2

2071

2 13679 13679 13679 11435 11435 11435 11435 11435

Total CO2

Capture (ktpa) 131 131 4838 4838 4838 7462 7462 7462 7462 7462 9339 9339 9339 9778 9778

1666

7

1666

7 11040 11040 11040 9245 9245 9245 9245 9245

Captured

Percentage 1% 1% 45% 45% 45% 68% 68% 68% 68% 68% 77% 77% 77% 81% 81% 80% 80% 81% 81% 81% 81% 81% 81% 81% 81%

2045 2046 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 2058 2059 2060 2061 2062 2063 2064 2065 2066 2067 2068 2069

Total CO2

Emitted (ktpa) 10233 10233 10233 9806 9806 8611 8611 8611 8611 8611 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Total CO2

Capture (ktpa) 8284 8284 8284 7845 7845 6889 6889 6889 6889 6889 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Captured

Percentage 81% 81% 81% 80% 80% 80% 80% 80% 80% 80%



UPPER CASE 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044

Total CO2

Emitted (ktpa) 12117 12117 12117 12117 12117 13210 13210

1321

0

1321

0

1321

0

2163

6

2163

6

2163

6

2163

6

2163

6

2163

6

2163

6 21636 21636 21636 21636 21636 21636 21636 21636

Total CO2

Capture (ktpa) 6566 6566 6566 9764 9764 11471 11471

1147

1

1147

1

1147

1

1959

2

1959

2

1959

2

1959

2

1959

2

1959

2

1959

2 19592 19592 19592 19592 19592 19592 19592 19592

Captured

Percentage 54% 54% 54% 81% 81% 87% 87% 87% 87% 87% 91% 91% 91% 91% 91% 91% 91% 91% 91% 91% 91% 91% 91% 91% 91%

2045 2046 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 2058 2059 2060 2061 2062 2063 2064 2065 2066 2067 2068 2069

Total CO2

Emitted (ktpa) 13437 13437 13437 11150 11150 10204 9995 9995 9983 9983 9513 9513 9513 9513 9513 8419 8419 8419 8419 8419 0 0 0 0 0

Total CO2

Capture (ktpa) 12214 12214 12214 10155 10155 9304 9115 9115 9105 9105 8561 8561 8561 8561 8561 7578 7578 7578 7578 7578 0 0 0 0 0

Captured

Percentage 91% 91% 91% 91% 91% 91% 91% 91% 91% 91% 90% 90% 90% 90% 90% 90% 90% 90% 90% 90%



Annex C - Potential Ownership Options for Onshore

Transport of CO2


Potential Ownership Options for Onshore Transport

of CO2


1. INTRODUCTION

The preferred method for large scale gas transportation is via pipelines with

millions of kilometres of pipelines around the world that transport various

gases, including CO2. There are over 50 CO2 pipelines currently operating in

the US alone, transporting roughly 68 mTpa of CO2 (Global CCS Institute -

Global Status of CCS 2014). These onshore pipelines, around 6500 km in

length, deliver mainly naturally sourced CO2 for EOR purposes. Thus CO2

pipelines are an established technology, both on land and under the sea. CO2

pipelines pose no higher risk than that which is already safely managed for

transporting hydrocarbons.

The Teesside Collective ICCS Feasibility Project considers three

scenarios/business cases (BC). BC1 involves just the Anchor Site, SSI. BC2

involves all four businesses identified, SSI, GrowHow, BOC and Lotte. BC3 is

as per BC2 but without the Anchor Site, SSI. The anticipated CO2 volumes for

the sites are:

• Circa 2.20 mTpa from SSI if 90% of the power generation emissions are

captured. This could increase by up to a further 1 million tonnes if other

sources on the SSI site were to be captured.

• Circa 0.38 mTpa from GrowHow with 80% capture assumed as some

CO2 is already captured and sold for food.

• Circa 0.30 mTpa from BOC assuming a 90% capture rate, and

• Circa 0.05 mTpa from Lotte assuming a 90% capture rate.

Thus the total CO2 emissions to be captured from the four sites are uncertain

but are likely in the region of 3 mTpa. Further opportunity to capture CO2

volumes exist across Teesside now and also through potential future

schemes, i.e. power generation which has led to views of an onshore network

capable of taking 15 mTpa. Over the past few years, a number of power

station with carbon capture capability projects have been evaluated within the

Tees Valley area, i.e. Lynemouth Power Station and it's 2.25mte CO2 per year.

None appear to have progressed beyond the concept feasibility stage. BC2

would require a pipeline of 300-400mm whilst a 15 mTpa pipeline would be

circa 700-800mm. The route would be the same. A trebling of capacity can be

provided at a fraction of additional cost. The Amec One North East Study

confirmed that for large emitters the network solution represents a factor of 3

to 4 saving over single source and can be up to a factor of 60 more economic

for smaller emitters. So networks are effective at enabling small and medium

emitters achieve low transport costs. Thus with respect to ownership options

for the onshore network we have considered a range of 3-15 mTpa. However,

although there may be considerable benefit to plan for an oversized transport



infrastructure this requires commercial justification. The clear rationale and

cost/benefit analysis for whether an oversized pipeline is considered or not is

covered within the Business Case evaluation.

With respect to ownership options it is assumed that the Onshore Network

design will be a shared pipeline from the four emitting sites. The onshore

network will carry CO2 in at 100barg thus dense phase and feed a

compression station adjacent to the SSI location which will then transfer CO2

for its offshore sequestration. The Engineering Workstream has evaluated

routes and confirmed a preferred route as marked in blue below. For the

purpose of network ownership we have assumed the blue route. The CO2

pipeline would start from GrowHow travelling along the north side of the river

to pick up BOC, crossing the river through Pipeline Tunnel 2 and continuing

along the south side of the river to the compression station. There would be

separate spurs to Lotte and SSI. Given the pivotal role of SSI as the anchor

project and being located adjacent to the compression station consideration is

given to a standalone point to point pipeline connecting SSI directly to the

station.

An onshore CO2 network presents an economy of scale benefit for first users

and lowers the barrier of entry for subsequent CCS projects wishing to join the

network. The ownership structure for the onshore network needs to consider

the risks and opportunities associated with the pipeline sizing, construction,

operation, and maintenance and charging options and how the risks and

liabilities will be shared between each element of the chain.

2. RECOMMENDATION

A network approach entails many challenges, in particular from commercial,

financial, and legal perspectives, including:



• The design of a multi-user charging framework linked to the allocation of

capacity in the system that reflects the initial investment cost alongside

ongoing operation and maintenance costs;

• The development of innovative commercial structures that accommodate

first and new users/partners/owners and their different priorities for

access to the network;

• The ability to finance the construction of a network that may initially be

‘oversized’ in anticipation of future volumes of CO2 being added; and

• The metering or monitoring of the different sources of CO2 which feed into

the common network. Each source could fluctuate, so sources need to be

individually tracked and emitters need to receive specific benefits for each

tonne of CO2 supplied.

Ultimately the network requires an Owner/Operator. Whilst there is only one

physical route for the CO2, there are multiple options for commercial interfaces

and ownership. An emitter could have separate contracts with an onshore

network operator, an offshore network operator and a store operator.

Alternatively contracts could follow the CO2 flow so an emitter has a contract

with an onshore network operator who in turn has a contract with the offshore

network operator and so on. Finally you could see a vertical or aggregated

model where either a private entity of the UK Government take on the whole

infrastructure.

For at least the last three decades the trend has been towards divestment of

assets by the Government alongside a strong preference for major new

infrastructure projects to be privately financed. So whilst the UK Government

are considered as a potential Network Owner it is unlikely that they will want to

play more than a key supporting role. The Element Energy report

commissioned by One North East and NEPIC late 2010 for CCS in the

Teesside area concluded two modes for project development and structuring;

1) Single Entity Promoter, and 2) Joint Venture Development. Element Energy

repeated this view in a report completed for the Energy Technologies Institute

in 2012 where five potential options for CO2 transport and storage

infrastructure development within the UK were considered. From their

stakeholder engagement on these options they recommended two options

worthy of more detailed analysis; 1) Regulated regional private monopolies,

and 2) Regulated regional public-private JV monopolies. Thus the options

considered below focus on private solutions, i.e. Sole Operator and Joint

Venture arrangements. Upstream, downstream and mid-stream led pipeline

investor models exist for gas pipeline infrastructure and the same is being

considered for the Teesside Collective Project. Thus, the same (aggregated



model) or different entities (disaggregated model) could own the Onshore

Network, the Offshore Network and/or the Store.

The table on the following page evaluates ownership options that have been

considered for the onshore network. Key attributes are summarised for each

option and are covered in detail in the following sections of the report.

The recommend ownership option is a Special Purpose Vehicle (SPV)

involving emitters alongside a proven network operator, i.e. National Grid

Carbon and with either direct Government involvement or as a minimum clear

Government sponsorship, guarantees and financial support mechanisms.

As stated in the Amec One North East report on Teesside CCS, the small

physical size of the cluster lends itself to private ownership of the onshore

network via established CO2 pipeline, industrial gas, gas transmission or utility

companies. The Element Energy report for One North East and NEPIC also

considered the JV model using a project finance approach to be the most

promising method for the Teesside onshore network. The network could be

promoted and developed by a "coalition of the willing‟ made up of Teesside

operators, via a JV consortium and using a project finance model (SPV). There

is significant potential to build an appropriate vehicle through which to promote

and develop the project, building on existing relationships and structures in the

Tees Valley (e.g. the North East Process Industry Cluster; NEPIC) – to this

end, ten NEPIC members have already signed up to a Collaboration

Agreement – the Process Industry Carbon Capture and Storage Initiative

(PICCSI) to further explore potential of a CCS network. This is the first small

step in the process of moving towards a JV, as described previously. Element

Energy state that the results from a survey of Teesside operators showed the

majority considered that a consortium approach would be the most effective

means of developing a CCS network in the area.

As surmised by Element Energy, once established, the SPV could offer a

reasonable amount of flexibility with scope for future exit and entry of direct

participants and new market entrants and offers the greatest means to insulate

risk and leverage debt into the project through the presence of well-capitalised,

creditworthy counterparties. Furthermore, once built and proven, the equity

holders could potentially exit and/or refinance, leveraging new sources of

lower cost commercial debt (including mezzanine arrangements, structured

finance), which could serve to lower financing costs. In practice, a structured

and negotiated process will need to emerge that serves to bring the JV

partners along, requiring first the development of initial memoranda of

understanding, collaboration agreements, moving then towards letters of intent

and finally structured contracts and a SPV entity with its associated articles of

incorporation and shareholder agreements.



Evaluation of Onshore Network Ownership Options Risk Categorisation: High Medium Low

Consortium SPV

(UJV) (IJV)

Description An existing incorporated company, limited by guarantee A joint venture where the parties do not form a corporation. Thus a

group of parties that form a legally structured partnership.

A Special Purpose Vehicle or Incorporated JV. A joint venture in

which the companies involved create a separate corporation and

divide its shares between themselves as an equitable way to

distribute JV income and risk.

Government owned and operated company.

Example BOC, NGC or Denbury (USA)

GDF SUEZ E&P on ROAD Project

Central Area Transmission System (CATS) (BG 62.42%, BP 36.01%,

ConocoPhillips 0.66%, Eni 0.34%, and Total 0.57%. The operator is

BP.

Interconnector (UK). Formed when nine energy companies made

long-term shipping commitments and also became shareholders.

Motorways, Nuclear Decommissioning Authority

Raising Finance Challenging and likely based on project sponsor's credit worthiness

and access to capital (corporate finance). Few corporate sponsors

likely to have sufficient profile

Likely to be promising, subject to developing a strong corporate

coalition of the willing with good track records and credit ratings.

Over time equity shares can be changed. Enables multiple sources

and levels of equity funding via the parties. Potential issues around

asset ownership and rights. Lenders likely to conduct extensive due

diligence.

Likely to be promising, subject to developing a strong corporate

coalition of the willing with good track records and credit ratings.

Over time equity shares can be changed. Enables private

capital/debt funding alongside equity funding from parties. Well

capitalised and creditworthy entities improve the chances of

attracting private capital.

High risk, due to Government involvement and commitment

(subject to incentives and project terms). Highly disruptive

intervention, contrary to current policy so challenging to obtain

funding. Public investment may distort energy, oil, carbon and CCS

markets. As a national requirement and directed investment the

project can be removed from funding issues associated with risk on

future EU ETS prices.

Creditworthiness Significantly exposed to all non supply and demand risk due to

limited involvement of underlying users of network.

Effectively addressed as equity involvement ensures commitment

of partners with interest in underlying assets, i.e. investment by

emitters reduced stranded asset risk. Ability to take small equity

share limits downside risk for individual investors and to better

match the different risk-reward profiles for different industries.

Effectively addressed as equity involvement ensures commitment

of partners with interest in underlying assets, i.e. investment by

emitters reduced stranded asset risk. Ability to take small equity

share limits downside risk for individual investors and to better

match the different risk-reward profiles for different industries.

Effectively addressed as Government has capacity to create new

regulation and economic framework to support objectives and

enforce payments in cash flow model. Potential for efficiency

capacity over long-term particularly when expected future

capacities are high.

Decision Making Coordination without excessive standardisation or bureaucracy.

Could limit innovation / new projects.

More complex given multiple parties and dependent on the

strength of the lead party.

More complex given multiple parties and dependent on the

strength of the lead party.

Central planning may reduce innovation and flexibility, raising

costs.

Transportation

Agreement

Operator would have little or no recourse to the underlying asset

creating entities. It would rely on the development of a watertight

supply and off-take agreements, or a very robust demand case for

CO2, i.e. EOR.

Emitters integrated alongside network operators could enable

increased levels of assurance and trust. Again dependent on the

role played by a lead party.

Emitters integrated alongside network operators could enable

increased levels of assurance and trust. Again dependent on the


More complicated business models but could deliver an

aggregated/vertical solution.

Supply Risk Most exposed if supply volumes fail to match expectations and/or

are late. Again can be mitigated via watertight agreements.

If emitters involved in ownership then provides greater onus to

ensure volumes are supplied on time, in specification and at

volume specified. Again dependent on robust agreements and the


If emitters involved in ownership then provides greater onus to

ensure volumes are supplied on time, in specification and at

volume specified. Again dependent on robust agreements and the


If established as National Infrastructure this would better enable

the installation of a future proofed infrastructure that can

accommodate short-medium term exposure on supply risks.

Construction Simplest structure enabling direct interface between EPC

Contractor and Owner to deliver the project.

Experience of local players in previous infrastructure projects can

help expedite the onshore build providing clear decision making is

in place, ideally through a designated lead player.

Experience of local players in previous infrastructure projects can

help expedite the onshore build providing clear decision making is

in place, ideally through a designated lead player.

Significant pace of development. Government ownership could

enable a long term plan to ensure right sizing of pipeline to future

capacity.

Operations "First of Kind" technical risk remains overriding barrier to attracting

commercial debt. Non-supply and demand risks can be addressed

through design of suitable contractual arrangements

"First of Kind" technical risk remains overriding barrier to attracting



"First of Kind" technical risk remains overriding barrier to attracting



Technical risks remain but can be underwritten by Government, key

operating risks can also be managed through use of Government

supply and demand guarantees. Government can lease or outsource

the operational requirements and if necessary change operator.

HSE & Regulation Can Self Regulate. Clear accountable entity for HSE, OFGEM. Likely

to be a known trusted entity on Teesside for gaining rights of way

licenses etc. Will benefit from Government support and

intervention already in place.

Can Self Regulate. Potentially unclear accountable entity for HSE,

OFGEM. As a Group may find gaining access rights, approvals etc.

more difficult. Will benefit from Government support and

intervention already in place. Public Sector involvement in the JV

reduces policy and regulatory risk.

Can Self Regulate. Potentially unclear accountable entity for HSE,

OFGEM. As a Group may find gaining access rights, approvals etc.

more difficult. Will benefit from Government support and

intervention already in place. Public Sector involvement in the JV

reduces policy and regulatory risk.

Would required HSE and OFGEM to Regulate. Easier route for

licences, permits etc. with Government as sponsor and primary

policy maker / regulator.

Likelihood of success Unclear and dependent on profile and track record of project

sponsor in addition to level of Government support

Dependent on level of equity involvement, suitability of lead party

and the ability to de-risk counterparty commercial linkages. Proven

track record on Teesside in building investment consortia and

facilities sharing

Dependent on level of equity involvement, suitability of lead party

and the ability to de-risk counterparty commercial linkages. Proven

track record on Teesside in building investment consortia and

facilities sharing

Contingent on the development of new government policy and

regulation. Approach at odds with current UK policy approach.

Overall, an SPV model involving Government support presents

a compelling option for the Onshore Network Operator

Clarity of decision making is easiest via a Sole Owner but could

be replicated within an SPV/UPV via a clear lead party with a

clear remit.

Minimal difference between owner options. More suited to a

Sole Operator or UJV/SPV with a clear lead entity with proven

track record and long term outlook.

Minimal difference between owner options. More suited to a

UJV/SPV involving emitters or National Infrastructure where

Government guarantees may be needed to underwrite supply

volume risks and asset cost recovery mechanisms.

The risks associated with the network construction and

integration require underwriting with the Government best

placed to provide this.

Operations is unlikely to influence the ownership route

although a JV or Public arrangement provides greater

flexibility in the event of Operator failure.

HSE & Regulation is likely to have minimal influence on

ownership route.

Attributes Sole Public

Key Takeaway

An SPV model is likely to be the most successful in securing

finance

Although an unlikely route, a Public solution presents the

strongest credit position. An SPV/UPV solution is most likely

with creditworthiness dependent on the mix of parties

involved.



3. RATIONALE

Pipelines are usually developed by multiple parties whom have an interest in

either selling or buying the item being moved. These parties may own the

project by either an incorporated joint venture (“IJV”) or an unincorporated joint

venture (“UJV”). The IJV or SPV structure is the more traditional form of

corporate vehicle selected. The Teesside region has both the capabilities to

deliver the shared infrastructure that would be needed and also several parties

that could either act as a Sole operator or come together and form an SPV as

demonstrated by the shared pipeline infrastructures for steam, hydrogen,

oxygen and wastes already existing on Teesside.

3.1 Raising Finance

Whether Sole Operator or SPV the ability to raise sufficient finance to

construct and operate the onshore network will be the biggest hurdle faced.

The complexity of building a shared large-scale infrastructure is not the main

challenge. Key is the demonstration of a UK first commercial scale industrial

CCS network and whether the policy framework and economic fundamentals

are sufficient to attract finance. Whether Sole or SPV, the Network Owner

would fully expect the project to pay back debts and provide profit/dividends.

A Sole Operator would be a large company with appropriate expertise, e.g.

BOC, Linde, National Grid Carbon, who has financial resource to make the

necessary investment based on a speculative view of the presented business

case. Whilst not risk averse, such companies could perceive significant

opportunity costs.

The SPV model presents an attractive option. Equity involvement by a number

of emitter site operators would significantly de-risk the project from the point of

view of non-supply risk, probably the most important factor affecting the

commercial viability of the network. It is also more likely to ensure fair and

equitable self-regulation of the network operation and commercial model. The

involvement of these entities would improve the sourcing of private capital.

The presence of the well-capitalised "anchors" with equity in the JV, alongside

other equity investors, presents a more stable long term proposition. Lenders

will take security over the proceeds of the CO2 transportation agreements,

along with any other security which local law will permit, such as a pledge of

other assets. Lenders may seek to take security over the pipeline itself.

Where a UJV is used, it gives rise to questions of how the pipeline and other

assets are owned by the developing sponsors (e.g., tenants in common), how

are those ownership interests evidenced and what are the rights and

obligations which attach to those ownership interests (e.g. what are the

funding obligations). Where one of the sponsors is seeking to project finance

its share of the costs, then that raises additional questions that require its

lenders to conduct extensive due diligence on the underlying UJV structure.

Sponsors of a pipeline may fund the construction of a pipeline purely through

equity contributions or other shareholder funds to the project company, but

may also wish to obtain debt funding from commercial banks, export credit

agencies and/or multilateral financial institutions. Where the project company

is borrowing from third party lenders in order to fund construction costs, the

lenders will need to be comfortable that the transportation agreement related

to the pipeline is bankable, not least because the lenders will typically only



have recourse to the revenue stream generated by the pipeline owner from

transporting the CO2, and will typically have no recourse to any assets not

related to the project. Transportation agreements will also typically be

structured on an availability/send-or-pay basis, such that the project company

is being paid a capacity fee if the pipeline is operational. The capacity fee

would be sufficient to cover interest and principal on the project finance loan

and other fixed costs. It would also be paid a separate variable fee to cover

variable costs.

Where different parts of the overall supply chain (for example, the upstream

facilities, the pipeline, and the downstream facilities) are owned by different

sponsors and being project-financed by different syndicates, the construction

of a pipeline in that chain may be further complicated by the different

syndicates’ competing interests.

The main issue for the Onshore Network is that it is a "Mid-Stream" project

built to link supply and demand. Such projects are rare and are most at risk

from changes in business plans at either end. Risks for mid-stream projects

are reduced when supply contracts and tariffs are arranged in advance.

However, in the case of Teesside Collective the supply and demand are also

both "greenfield" and themselves requiring project financing so the risks for the

Onshore Network Owner are high.

Thus, one possible route is for vertical integration from emitter sites through to

sink. This could be via a National Infrastructure model, a Sole Operator such

as National Grid Carbon or a collaborative SPV approach by emitters and sink-

holders. The latter presents the lowest end to end risk from a finance

perspective and enables the parties to share the value of the emission

allowances between them. In practice a vertical SPV should provide the basis

for the signing of long terms contracts for pipeline capacity enhancing the

ability to secure finance for the construction investment. Whilst such an

arrangement may present concerns around localised monopoly power this

could be mitigated by imposing a requirement on the pipeline to allow the

future connection of new emitters. For an effective market in CO2

transportation to exist a degree of liquidity will be required. Thus, the network

needs to be able to accommodate capacity reductions and disconnections due

to loss of first users with the possibility of new users joining. Therefore, having

a pool of potential new users would benefit overall network functioning and

efficiency.

In summary, wherever possible the potential to establish a competitive market

for the onshore network capacity should initially be pursued. The second route

would be through a JV among market participants ahead of vertical integration.

Where the latter emerges as the preferred option the ability to integrate a

competitive provision in network investment and use should be considered.

3.2 Creditworthiness

In terms of creditworthiness the order of preferred onshore network owner

would be from the UK Government, SPV, UJV through to Sole Operator. As

already stated, for the purpose of this report, Public ownership has been ruled

out. Although an unlikely outcome, the UK Government may play a role within

a JV to provide support, i.e. creditworthiness, capital investment, regulatory

support, etc. As a minimum, given the Teesside project is viewed as a

pioneering major infrastructure project of national interest the UK Government



may position themselves as a backer of last resort to enable others to secure

the necessary finance to construct and operate the network.

Whilst an SPV / UJV presents a vehicle to share first mover risk, their

perceived creditworthiness is dependent on the mix of parties involved. With

the creditworthiness of SSI, the anchor emitter, in question, it will be essential

that parties with deep pockets and an appetite for major infrastructure are

brought into the mix to cover both the initial investment and continuity in the

event the anchor volume is lost.

In terms of a credible Sole Operator, one can realistically envisage an

established pipeline operator such as BOC or National Grid Carbon.

3.3 Decision Making

In terms of decision making the order of preferred onshore network owner

would be in reverse from Sole Operator, UJV/SPV to UK Government.

Examples of some of the decisions faced are listed below, i.e. should the

onshore network be oversized or not, route of network, commercial terms for

use, how handle leavers/joiners etc. The ability for a single entity to make a

decision is clearer than that involving multiple parties within a UJV/SPV.

However, it is common for a UJV/SPV to have a lead party to whom decision

rights are assigned. With a Public option, the UK Government would need to

fully assign responsibility to a single entity to construct/operate the onshore

network on their behalf to avoid protracted consultation and decision making.

Some thoughts on a few of the issues and decisions likely to be faced:

• Onshore Network route sizing. Should the network be sized to the

maximum possible or just match First User volumes? If to be "future

proofed" then where and how are the future connection points to be

established? What route is to be taken? How are way leaves to be

handled?

• Volume commitments. What volumes do emitters commit to? What

happens if these commitments are not realised? How are metering

discrepancies handled?

• User exit. What happens when an emitter's business fails and they leave

the network?

• Future Entrants / New Users. What would the commercial terms for future

entry be? Are these established at the onset on when each new user

arises?

• Commercial model. Capacity Payment versus Throughput Payment or

combination of both? Transfer of Title/Ownership of CO2?

• Liabilities associated with the onshore network. How is ongoing operation

and liability handled in the event of a) leaks from the network, b)

equipment failure that prevents transport, c) CO2 quality issues, etc.?

How is a COMAH event handled?

• How will the onshore network be regulated? Self or external?

3.4 Transportation Agreement

With respect to the transportation agreement the difference between the

potential options for choice of network owner would be minimal. A robust

transportation agreement can be developed just as easily by a Sole Operator,

UJV/SPV or the UK Government. The transportation agreement is a vital

component of the network financing and is likely to represent the main source

of revenue for the project to service its debt. Where project financing is part of



the sources of funding, then lenders will wish to review the connection

agreements entered into by the operator as part of their due diligence. For

trust to ensue, both emitters and financial backers will seek long term stability,

flexibility, transparency and efficient local administration from the network

operator. Thus, more suited to a Sole Operator or UJV/SPV with a clear lead

entity with proven track record and long term outlook. OFGEM or an equivalent

may be required to ensure checks and balances on the operator.

Key areas to be covered by the transportation agreement are:

• Volume

• Price

• Title/Liability Issues

The transportation agreement is typically an availability-based contract, where

the emitter's obligation to pay is independent of whether or not it ships CO2

through the pipeline, i.e. a ship-or-pay basis. The ship-or-pay obligation of the

emitter must be sufficiently tight to ensure certainty of payment. This would

need to be backed up with a robust take or pay supply agreement with the

offshore operator to ensure onward transportation. Where project financing is

part of the sources of funding, then lenders will wish to review the connection

agreements entered into by the onshore operator as part of their due diligence.

The transport agreement may need to reflect different configurations for

infrastructure, i.e. SSI may want a simple point to point agreement with a

connection at the compressor whilst other emitters are likely to utilise a shared

pipeline. The efficiency of onshore network is improved through providing

blanked T's. This enables new entrants and promotes competition on price.

The mechanisms for how New Entrants and network extensions are charged

for should be developed upfront with the prevailing view that New Entrants

should be charged the same or more that First Users with capacity costs re-

phased across all players. Similarly the mechanism for treating a First User

that buys an option on oversizing, i.e. use it or lose it, transfer of rights etc.

A tariff mechanism would need to be developed for emitters. This could be

based on a Capacity Only Model, Throughput Only Model or a combined "Cost

Plus" Capacity & Throughput Model. The network operator would want the

reward mechanism to focus on capacity versus utilisation to establish high

fixed costs and low variable costs. Thus an annual capacity fee to recover

capital cost over the contract length, associated O&M as recoverable rolling

fixed fees and a variable charge for gas transferred. Entry requirements and

service costs would need careful clarity and negotiation and ensure that first

movers do not become disadvantaged as the network grows. However, once

the network is established the most efficient use of capacity is promoted by

unbundling ownership from capacity and moving towards setting tariff

structures in line with variable costs. There is already extensive experience of

agreements and tariff mechanisms for private, self-regulated cooperation on

utility infrastructure on Teesside meaning that both the onshore network

operator and emitters should be able to develop arrangements without too

much difficulty.

With volume based variable charges, a notable part of service and hence

Transport Agreement will be metering. Duplex fiscal meters to enable

calibration and continuity would be required and accessible at emitter

boundaries with the recommendation of one or more duplex metering points



on the network spine. Within the agreement details can be captured to cover

meter calibration, tolerances, meter failures, discrepancies etc.

A useful reference document is the Capacity Charging Mechanism for Shared

CO2 Transportation and Storage Infrastructure report prepared by National

Grid Carbon Limited for the Global CCS Institute for the purposes of sharing

National Grid Carbon Limited’s work in developing a conceptual model for a

charging mechanism for application to shared CCS infrastructure systems.

One tariff mechanism suggested is for three separate charges an EPC

Charge, a Capacity Rights Charge and a Use of System Charge.

Finally with respect to the Transportation Agreement some thoughts on title

and liability issues. Sembcorp currently own the way leaves rights to the

majority of pipeline routes. Way leaves and their associate title rights and

costs (upfront and ongoing) will need to be covered within the Transport

Agreement.

Title will be a significant area to resolve. Will we see a simple Throughput

Service or Title Transfer at each Boundary? General view is the latter with

emitters not wanting to be involved beyond their boundary fence. However,

this places a major obligation on the Network Operator(s) to take on all of the

long term risk/liability for all transportation and storage. Who benefits from

Grandfathered Emission Trading rights if the captured carbon a) goes down

pipeline, or b) doesn’t go down for whatever reason? Two possible scenarios

are that a) the Store Owner gets EU ETS benefits or b) the Emitters gets UE

ETS benefits. As the emitters currently get the benefit we can assume that the

Network Operator(s) have no connection to EU ETS rights and so provide a

simple conduit only. Note that the European Union CCS Directive states that

the Store Owner has ultimate liability if a store leaks, unless a fully vertical

arrangement is established.

All parties will want to avoid contractual liability for leakage. This is discussed

in more detail in the Supply Risk section below. Within the Transport

Agreement what happens in the event of a) leaks, b) capture equipment

failure, c) transfer equipment failure etc. will need to be spelt out. The initial

view is that for events <12 hours no liability costs are due, for >12hours to < 1

month is covered by emitter/operator insurance and anything >1 month is

considered Force Majeure.

3.5 Supply Risk

Although there are a number of significant supply risks associated with the

onshore network as per 3.4 above they should be manageable through robust

agreements/contracts and/or term sheets together with robust ongoing risk

management. From a supply risk perspective, the onshore network ownership

is more suited to a UJV/SPV involving emitters and with a clear lead party with

an appetite for risk and a proven track record for long term stability. However,

Government guarantees may be necessary to underwrite the volume risks and

associated infrastructure costs involved. Key risks are viewed as:

• CO2 Supply Volumes

• CO2 Quality

• Leakage

• Technical risk associated with the integration of the chain



The main risk for the pipeline operator is that there is insufficient supplied

volumes to take up the pipeline’s capacity. To a certain extent, ship-or-pay

obligations in the agreements may mitigate these risks, but the operator's

ability to make full use of the pipeline will nonetheless be reduced. For

example, will the pipeline outlast all the First User emitters?

As stated in the section above leaks and meter inaccuracies present volume

risk which need to be covered contractually but also addressed on an ongoing

basis through operational procedures that regularly complete check and

balances to capture leaks and meter errors timeously. Such controls may

require internal or third party regulation to ensure they remain robust.

The following section, and associated part table from the Element Energy One

North East report provides a useful view on associated supply risks. The

principal aspect to resolve for the network operator will be the securing of

necessary up-front commitments or guarantees around the future usage of a

scaled-up network (e.g. long-term supply and off-take agreements). The need

to address non-supply and non-demand risk is therefore at the core of the

contractual framework for a CCS network. This issue is not uncommon in other

projects based on investments requiring successful multi- or bi-lateral

commercial relationships. The use of long-term CO2 supply and off-take

contracts between supply parties (i.e. by CO2 capture entities and/or a

midstream network operator), midstream operators (where these are separate

to supply parties) and demand parties (i.e. CO2 storage and/or EOR

operator(s)) which are mutually agreeable is therefore a key priority. As with

natural gas pipelines, the commercial arrangements are likely to be based on

the need to secure known capacity levels (i.e. capacity rights, capacity

payments, with ability to re-sell capacity rights in a secondary market). Such

contracts generally also contain penalty provisions and clauses addressing

specific concerns such as project failure or non-performance. Ultimately, it is

this type of negotiated process, perhaps even involving bidding rounds or

open-seasons for capacity rights, which will serve to determine the network

capacity to be built at least in the first phase. Element Energy’s discussions

with Teesside stakeholders suggest that nearly three-quarters of those spoken

with would potentially be interested in considering entering into an initial long-

term supply contract for a Teesside network, either before 2020, or soon

thereafter.

The need to address “first of a kind” technology risk is also central to the

success of the contractual framework and commercial basis of the network.

Performance guarantees for equipment must be provided before lenders can

consider investing. Again, because of the "project-on-project" risk, these will be

required across the entire system including each plant, all the capture

equipment and any new build plants (known as a “wrap”). General

performance guarantees do not typically provide for the full range of technical

risks associated with operating the entire CCS network. For example, there will

be concerns around whether emitting plants can operate satisfactorily with the

capture equipment across all operating modes, fuel input variations and

exhaust gas streams, over their expected lifetime. As it is extremely unlikely

that insurance for technology failure will be available, commercial lenders will

therefore require equipment vendors to stake their reputation on providing

performance guarantees for equipment. This will ensure that it is in the

vendor's interest to overcome any operational problems. A further element to

consider for shared infrastructure is the risk of change of ownership. This



could affect incumbent contracts, and potentially prevent access to the system.

Use of non-disturbance agreements will typically be required to manage this

risk.

An extract of a table from the Element Energy report below summarises some

of the key supply risks associated with developing the CCS network and the

range of potential approaches to managing them.

The table shows that while many of the risk management options can be dealt

with primarily by the private sector (through various commercial and legal

arrangements typical of large multi-party investment projects), other areas of

risk will likely require government policy and regulatory support. In this context,

it is important to note that some CCS risks are viewed by investors as potential

“deal-breakers” unless addressed by the policy framework (e.g. EU Allowance

price, long-term liability) whereas others can be managed through well

understood existing approaches (CO2 supply and demand risk, tariff

arrangements).

Another key supply risk for the network operator is the quality of the carbon

dioxide received. With multiple sources of CO2, clear entry specifications are

required. The onshore network operator will have to specify composition of

gas, aiming for >95% purity of CO2. Key is the minimisation of water or oxygen

as both present a corrosion risk to a mild steel pipeline. Each emitter site will

need to install molecular sieves at their boundary interfaces to remove water.

Gas contaminants specific to individual sites will need to be risk assessed, i.e.

ammonia from GrowHow. Potential disputes, i.e. "Your rubbish CO2 caused

my leak", need to be covered off upfront via clarified specifications in the form

of a Term Sheet. Liability should lie with the Network Owner with the

development of robust Term Sheets minimising risk. National Grid Carbon

have provided a standard specification which provides a good starting point.

With regards to leakage from the onshore network COMAH Safety

arrangements will be required including a Safety File, risk assessments and

associated risk mitigation plans together with routinely tested procedures to

deal with leaks. To determine when a leak occurs, leak detectors and/or

differential pressure gauges may be required to supplement a real time

automated meter reading analysis. The onshore network would need

Emergency Shutdown Valves every 1-2kms. This can then enable

quantification of loss in the event of line ruptured.

The final area to touch on briefly are the technical risk associated with the

integration of the chain. Multiple capture technologies are proposed. Thus a



network connecting multiple sources needs to be designed to account for

differing specifications being amalgamated into an appropriate CO2 stream

composition, temperature, pressures and velocities. The onshore network then

integrates with the offshore network at which point the CO2 will be further

compressed providing another layer of complexity and risk, i.e. what happens

to the CO2 within the onshore network in the event of a compressor failure.

3.6 Construction

There are two common approaches to the contractual framework for the

engineering, procurement and construction of a pipeline. The onshore network

operator can contract all the required services through the EPC contractor

alone. The EPC contractor will then be obliged, under the terms of the contract

with the operator to procure all necessary services, by itself contracting with,

for example, the pipe supplier. Alternatively, the operator can contract

separately with each contractor. In this scenario, the operator would have

separate contracts with a pipe supplier to supply the pipes and a contractor to

build the pipeline. This gives rise to enhanced interface risk, although this

would not necessarily make it impossible to obtain project financing as it is

possible to mitigate interface risk. That said, where the sponsors are seeking

to obtain project financing, then this contractual structure becomes subject to

additional scrutiny as lenders will wish to ensure that the contract(s) required

to build the pipeline are as time and cost certain as possible.

Sembcorp own 90% of the pipe corridors in the area. Rather than one off

payments Sembcorp normally rent out way leaves for pipeline land. Terms

would need to be agreed prior to construction commencing. National Grid have

statutory rights to land access via a compensatory mechanism.

Adjacent to SSI, the coastline still has environmental constraints but the

coastline hosts the landfall of the CATS natural gas pipeline. Thus precedence

exists and environmental considerations are expected to be manageable. The

shoreline is a RAMSAR marine reserve in additional to being designated a

Special Protected Area and recognised as an Important Bird Area.

A host of technical and engineering challenges may result in the delayed or

sub-optimal phasing of the network's evolution at emitter sites, within the

onshore arrangements and also within the offshore arrangements. The

integration of the chain through the successful sequencing of each required

component presents the biggest construction challenge. The risks associated

with the onshore network construction and integration will require underwriting

as any supporting tariff mechanism may not necessarily cover these risks.

3.7 Operations

System dynamics and operating regimes will need to be considered. In terms

of system dynamics, a CO2 pipeline has different operating modes to consider

at both ends. The CO2 injection facility may require the CO2 to be delivered in

a constant flow, whereas the CO2 capture unit at the emitter sites may operate

on an intermittent basis. The requirements of the storage formation, such as

flow, pressure and temperature, set the downstream conditions. The emitter,

on the other hand, provides another set of upstream conditions in terms of flow

rates, ramp-rates, temperature, pressure and composition. These conditions

from both the storage and capture facilities need to be taken into account (and

optimised) in both the design and operation of the onshore network.



Beyond the initial design and associated risk aspects, the network operator will

need to consider the operational aspects of gas impurities and managing their

impact. As mentioned above the majority of the network’s CO2 will come from

production and capture systems that will intrinsically add small quantities of by-

products or impurities to the CO2. There are a number of consequences to

such additions. These impurities can influence the thermodynamic properties

and behaviour of the CO2 stream, creating variations to the equations of state

of the CO2, resulting to changes in flow rate (both in terms of mass and

volume) of the CO2 stream and its phase. Two-phase flow in a pipeline may

present problems for compressors and transport equipment, due to slugging

and fatigue, and this form of transportation is also inefficient. The interaction of

certain impurities (particularly free water) in the CO2 stream may result in

equipment and pipeline corrosion, increased failure rates and fracture

propagation, damage and clogging (due to hydrate formation). Thus for system

integrity and injection/storage efficiency further cleaning steps may be

necessary, i.e. compression, heating, more injection wells, chemical additives,

filters etc.

The ultimate aim of the Operations and Maintenance (O&M) program is to

assure safety at all times. Additionally an O&M program should provide

environmental protection and economic efficiency. A routine, ideally real time

automated, mass balance utilising network meters will be useful in detecting

large leaks but not sensitive enough to detect small leaks. Thus an inspection

and maintenance program is required to assure safe operations. A robust

asset care programme including full FMECA will be required to a) minimise the

risk of leakage, and b) maximise the reliability of the pipeline and associated

plant. The network operator will need to have prepared and systematically

follow each standard operating procedure for both routine operation and

maintenance of the system and the handling of abnormal operations and

emergencies.

The network operator will need to administer meter readings and the

associated billing process. In the event of meter failure, procedures will need

to cover retro charging on allocation via mass balance and historical data.

With respect to operational liabilities associated with leaks and plant failure,

the associated costs of loss/repair can be easily recovered through the

recommended Cost Plus Model, i.e. repair costs going into next year's budget

and spread across the network users.

3.8 HSE & Regulation

The construction of the onshore network will require the consent of a number

of statutorily empowered bodies. These consents come in the form of various

approvals, licences and permissions and ensure a large range of statutory

rules with respect to rights of way, protection of others’ interests,

environmental protection, health and safety, etc. are complied with. Gaining

consent is likely to require lengthy application procedures and/or studies to be

carried out. However, these are unlikely to a) create a major barrier to the

onshore network and b) have minimal influence on ownership route.

Regulatory and competition law issues will need to be considered in relation to

the construction and operation of the network. The most important policy from

the EU is the Storage Directive (Directive 2009/31/EC), the so-called “CCS

Directive” which is globally one of the most comprehensive examples of CCS

specific legislation. The Directive creates a framework regime, allowing the



capture and transport of CO2 to be regulated under existing legislation, and

establishing a regulatory permitting regime for the storage of CO2. The

Directive establishes liability (although civil liability is explicitly excluded),

responsibility and sets a range of obligations and for storage; including site

selection, operating, closure and monitoring activities.

Rules may require the operator to operate the pipeline in a way which is less

than optimal with regards to its interests, and by extension, those of the

lenders. For example, in the European Union, refusing third parties access to

spare capacity in the pipeline could fall foul of the EU regulatory regime and/or

infringe the competition law prohibition on the abuse of a dominant position

within the market, since as a general rule EU law requires third parties to be

granted access to a pipeline where capacity is available (subject to limited

exceptions) on the basis of non-discriminatory and cost-reflective tariffs. As

per existing utility networks on Teesside, network capacity access and charges

are likely to be set by the network owner and not by the Government. The

regulatory regime in the EU also requires the ownership and operation of a

pipeline to be separated (“unbundled”) from any gas production, electricity

generation and gas or electricity supply operations, which means that in many

of the EU Member States the ownership of the pipeline and its operation must

be fully separated from any production or supply operations. This would need

to be assessed, in the event that say BOC were to operate the network. There

is precedent on Teesside for bundled energy/gas networks.

CO2 pipelines have operated for multiple decades with an excellent safety

record applying internationally adopted standards and codes of practice.

However, these codes have been mainly applied for pipeline systems

transporting naturally occurring CO2 through sparsely populated areas for use

in EOR operations and do not specifically address CO2 transport as part of

CCS systems. Standards organisations in Europe are reviewing existing

standards in light of planned large-scale CCS projects. The establishment of

an international standard has the potential to harmonise and guide both

regulators and operators alike, and improve design, construction, and

operation of CO2 pipelines. It will take a minimum of two years to get the

current Working Draft of the International Standard for CO2 pipeline transport

to a Final Draft. Once finalised, this new international standard might become

mandatory if adopted by a government and/or becomes part of business

contracts.

Section 12.3 of the Amec One North East report addresses the question of

whether a Teesside CO2 network should be regulated or non-regulated. The

current view is for possibly a bit of both. Whilst recognising that national

network equivalents such as National Grid and Interconnector UK are

regulated by OFGEM, for what is in effect a small private network a robust

governance process should lead to the majority if not all areas being

adequately self-regulated by the network operator. One or two exceptions may

require control via OFGEM or HSE, i.e. CCS Third Party Access Regulations,

COMAH, etc. The authority would act such that a private organisation could

operate networks and infrastructure but under regulations that enforce fair

access, structured pricing and costs, underlying development work and long

term contracts. A role by OFGEM would likely be required where a non-vertical

structure between emitters and store exits, i.e. potentially three different

operators for the Onshore Network, Offshore Network and Store. With respect

to regulation, the National Grid Carbon report for GCCSI on Capacity Charging



Mechanism for Shared CO2 Transportation and Storage Infrastructure would

be a useful guide when drawing up the business contracts and governance

process.

4. FURTHER RELEVANT CONTEXT

Denbury are a network operator with access to over 940 miles of CO2 network

in the US Gulf Coast region, majority privately owned by them. Denbury's

primary focus is on enhanced oil recovery utilising CO2. One of the principles

of their corporate strategy is to create, a competitive advantage as a result of

their ownership or use of CO2 reserves, oil fields and CO2 infrastructure.

Denbury transport and supply their own CO2 but also third party CO2.

National Grid Carbon, on behalf of the Global CCS Institute, have compiled an

86 page report providing insight on how to run the commercial side of a CO2

network. Titled "Capacity Charging Mechanism for Shared CO2 Transportation

and Storage the report focuses on:

• Shared Networks

• Optimal sizing

• Capacity Charging Mechanisms

• Case Studies

National Grid Carbon are the Network Operator for the proposed Yorkshire

and Humber CCS Project. Thus, an aggregated/vertical Sole Operator model.

The network has the White Rose CCS project at Drax as its anchor project

from where a 67km high pressure onshore Cross Country Pipeline will transfer

captured carbon dioxide to the coast for sequestration in the North Sea. The

long term aspiration is for the Cross Country Pipeline to be the foundation for a

regional CCS network. National Grid Carbon will own and operate both the

onshore and offshore network. The potential exists for an integrated offshore

solution for the White Rose and Teesside Collective projects.

The Maasvlakte CCS or ROAD Project involves the retrofit of a 250 MWe

equivalent post-combustion capture and compression unit to a newly

constructed 1,070 MWe ultra-supercritical power plant located within the

Maasvlakte section of the Rotterdam port and industrial area in Zuid, Holland.

The retrofitted post-combustion capture and compression unit will have the

capacity to capture 1.1 million tonnes of CO2 per annum at 99% purity.

Captured CO2 will be compressed, cooled, dehydrated and metered onsite. It



will then be transported 5 km / 3 miles over land via a 41 cm / 16 inch pipeline

that commences at the discharge of the CO2 compressor and crosses

Rotterdam’s Yangtze Harbour. From the coast, the proposed pipeline will run 1

metre / 3.3 feet below the seabed of the North Sea; transporting the captured

CO2 to depleted gas reservoirs located approximately 20 km / 12 miles off the

coast of Rotterdam. A joint venture formed by E.ON Benelux N.V. and

Electrabel Nederland N.V. (a subsidiary of GDF SUEZ Group), is responsible

for managing all aspects of the ROAD Project. The Project’s intended partners

include GDF SUEZ E&P Nederland B.V. for the transport of CO2 and TAQA

Energy B.V. (a subsidiary of Abu Dhabi National Energy Company PJSC) for

injection and permanent storage of CO2. Thus, ROAD have taken a

disaggregated SPV route.

Ecofys and SNC-Lavalin completed a detailed review of "CO2 Pipeline

Infrastructure" on behalf of IEA GHG, published 18th December 2013. The

report, summarising 29 projects from across the globe, provides a reference

document for project developers, decision makers, regulators and

governmental bodies. Key points from this report are captured below.

In the US, EOR has been the primary driver for CO2 pipeline infrastructure

development. Most EU projects focus on CO2 storage within emissions

reduction schemes. Except for the US, most countries have little or no

experience with CO2 pipelines or CO2-EOR operations. The pipelines can

usually handle the flexible operational needs of both supplier and user. A

number of pipeline network examples exist in the US. These hubs have no

specific set of rules, as each system has its own standards for CO2 purity and

operating conditions.

When completing the IEA GHG report, the contractors created a reference

manual, database and interactive web tool detailing information on 29 CO2

pipeline projects worldwide. Figure 2 from the report indicates the Sources of

CO2 across the projects and the Sinks that the pipelines supply.

A version of Table 2 from the IEA GHG Report, see following page, includes

details of the Pipeline Owner, Pipeline Operator and Ownership Model

reviewed within the study. Over 80% of the pipelines are owned and operated

by Sole businesses, with the remainder being JV operated. There are some

interesting examples of hubs in the US where CO2 from individual sources is

gathered and from which various CO2 customers are supplied. The US has

seen private companies or consortia join forces to develop a project as a

commercial venture with the EOR revenues providing project justification. In

some cases projects have been abandoned due to changing market

conditions, i.e. low oil price. Carbon offsets may provide a supplemental

source of revenue. In a number of projects existing oil or gas pipelines or

infrastructure were reused for CO2 transportation and / or injection. Where this

is possible substantial savings in investment costs may be realised.



A version of Table 2 from the IEA GHG Report including details of the Pipeline Owner, Pipeline Operator and Ownership Model reviewed within the study.

Project Name Country Status Pipeline Owner Pipeline Operator Model Length

(km)

Capacity

(Mton/y)

On/Offsho

re

Sink

1 CO2 Slurry CA P Enbridge Enbridge Sole Unknown Unknown Onshore EOR

2 Quest CA P Athabasca Oil Sands Project Shell Canada (60%) Chevron Canada (20%) and

Marathon Oil Sands L.P. (20%)

JV 84 1.2 Onshore Saline Aquifer

3 Alberta Trunk Line CA P Enhance Energy Inc. Enhance Energy Inc. Sole 240 15 Onshore Unknown

4 Weyburn CA O Dakota Gasification Company Dakota Gasification Company Sole 330 2 Onshore EOR

5 Saskpower Boundary Dam CA O Cenovus Energy Cenovus Energy Sole 66 1.2 Onshore EOR

6 Beaver Creek US O Devon Energy Devon Energy Sole 76 Unknown Onshore EOR

7 Monell US O Anadarko E&P Company Ltd Anadarko E&P Company Ltd Sole 52.6 1.6 Onshore EOR

8 Bairoil US O ExxonMobil Petro Source Corporation Sole 258 23 Onshore Unknown

9 Salt Creek US O Anadarko E&P Company Ltd Anadarko E&P Company Ltd Sole 201 4.3 Onshore EOR

10 Sheep Mountain US O Kinder Morgan (Occidental Permian and ExxonMobil own northern

portion, while Occidental Permian, ExxonMobil and Amerada Hess own the

line south of Bravo Dome.)

Occidental Permian operates both sections Sole 656 11 Onshore CO2 Hub

11 Slaughter US O Kinder Morgan Occidental Permian Sole 56 2.6 Onshore EOR

12 Cortez US O Kinder Morgan CO2 Pipeline Company L.P. Kinder Morgan Sole 808 24 Onshore CO2 Hub

13 Central Basin US O Kinder Morgan CO2 Pipeline Company L.P. Kinder Morgan Sole 232 27 Onshore CO2 Hub

14 Canyon Reef Carriers US O Kinder Morgan CO2 Pipeline Company L.P. Kinder Morgan Sole 354 Unknown Onshore Unknown

15 Choctaw (NEJD) US O Denbury Onshore, LLC Denbury Onshore, LLC Sole 294 7 Onshore EOR

16 Decatur US O University of Il l inois and DOE NETL Archer Daniels Midland Company Sole 1.9 1.1 Onshore Saline Aquifer

17 Snohvit NO O StatoilHydro StatoilHydro Sole 153 0.7 Both Porous Sandstone

formation

18 Peterhead UK P Shell UK, SSE Shell UK Sole 116 10 Offshore Depleted oil/gas field

19 Longannet UK C National Grid National Grid Sole 380 2 Both Depleted oil/gas field

20 White Rose UK P National Grid National Grid Sole 165 20 Both Saline Aquifer

21 Kingsnorth UK C E.On E.On Sole 270 10 Both Depleted oil/gas field

22 ROAD NL P Maasvlakte CCS Project C.V. (Joint venture between E.On Benelux and GdF

Suez Energie Nederland)

GDF SUEZ E&P Nederland B.V. JV 25 5 Both Depleted oil/gas field

23 OCAP NL O Nederlandse Pijpleidingmaatschappij (NPM) OCAP (joint venture between GasBenelux and

VolkerWessels) and Pipeline Control

JV 97 0.4 Onshore Greenhouses

24 Barendrecht NL C Shell OCAP JV 20 0.9 Onshore Depleted oil/gas field

25 Janschwalde DE C Vattenfall GdF Suez (assumed) Sole 52 2 Onshore Sandstone Formation

26 Lacq FR O Total Total Sole 27 0.06 Onshore Depleted oil/gas field

27 Rhourde Nouss-Quartzites DZ P Sonatrach Sonatrach Sole 30 0.5 Onshore Depleted oil/gas field

28 Qinshui CN P China United Coal Bed Methane Company Ltd. (CUCBM) - Client tbc tbc 116 0.5 Onshore ECBMR

29 Gorgon AU P Chevron Texaco Australia Chevron Texaco Australia Sole 8.4 4 Onshore Sandstone Formation

O = Operational C = Cancelled

Country Codes: AU = Australia, CA = Canada, CN = China, DE = Germany, DZ = Algeria, FR = France, NL = Netherlands, NO = Norway, UK = United Kingdom, US = United States. EOR = Enhanced Oil Recovery, ECBMR = Enhanced Coal Bed Methane Recovery

Status Codes: P = Planned



A key finding in the IEA GHG study is that CO2 pipelines are both similarities

and differences when compared to other gas pipelines, natural gas in

particular. As relatively similar gases the regulations and standards used for

CO2 originate from natural gas pipeline codes. However, the different physical

properties of CO2 do result in different design parameters and a higher risk

perception, which the public usually associates with the security of geological

storage of CO2. The key distinguishing features fall into three specific areas:

• Regulatory agencies and members of the public are usually not familiar

with CO2 pipelines

• CO2 pipelines are not separated in the public mind from the perceived

risks associated with geological storage of CO2 and arguably there are

parallels

• Properties of CO2 gas result in different design parameters, risk contours

and assessment than for natural gas.

In 1989 specific regulations were published for CO2 pipelines in the US, not

because of the CO2 industry’s safety record, which was good, but rather the

possibility of a high consequence incident if a break in a CO2 pipeline

occurred. The permitting and approval processes play a large role in

realisation of the project timeline. This can take much longer than expected

and exceed the construction time by far. The CO2 pipelines in the UK have a

>40year history of operation with no civilian injuries or fatalities. Public

opposition can lead to cancellation of the whole project as in the case of

Barendrecht.

Typically the pipeline will be the most operationally reliable component of a

CCS infrastructure. The pipeline can usually handle the operational flexibility of

both the supplier and user. In most countries construction activities are

prohibited within a specified distance of a pipeline corridor, typically 5m, to

avoid the risk of impact. Weekly visual checks are completed to ensure no

construction activity has occurred within the corridor.

For project developers it is important to understand what the key drivers of

public concern are so that focused action can be taken. Interviews with several

pipeline operators suggested that in many cases a CO2 pipeline itself is less of

a focal point of increased public concern and is not regarded much differently

from other pipeline projects. Instead, typically, public concern is related to the

power plant or CO2 storage project that the pipeline is tied to.



Annex D – References

1. Teesside ICCS Risk Workshop Report, Pale Blue Dot Energy

2. Captain Aquifer Outline Storage Development Plan, Pale Blue Dot Energy

3. Bunter Aquifer Outline Storage Development Plan, Pale Blue Dot Energy

4. Teesside CO2 Emissions Report, Pale Blue Dot Energy

5. Teesside ICCS Project Technical Summary Report, Pale Blue Dot Energy

6. Teesside ICCS business case model V16.xls, Pale Blue Dot Energy

7. SSI Steel Plant CO2 Capture Concept Report, Amec Foster Wheeler

8. GrowHow Ammonia Pant CO2 Capture Concept Report, Amec Foster

Wheeler

9. BOC Hydrogen Plant CO2 Capture Concept Report, Amec Foster Wheeler

10. Lotte Plant CO2 Capture Concept Report, Amec Foster Wheeler

11. Onshore CO2 Network Concept Report, Amec Foster Wheeler

12. Offshore CO2 Transportation Concept Report, Amec Foster Wheeler

13. Capture and Transportation Cost Estimate Report, Amec Foster Wheeler

14. ICCs Incentive Mechanism Report, Société Générale

15. 17R-97 Cost Estimating Classification System, American Association of

Cost Engineers International

16. The Economic Impact of Developing a CCS Network in the Tees Valley,

Cambridge Econometrics 2015

17. Green Book and Optimism Bias Supplement, H M Treasury,2013

18. Directive 2009/31/EC on the Geological Storage of Carbon Dioxide.

European Parliament, 2009

19. The Road Project - CCS Permitting Process, Maasvlakte CCS Project C.V.,

2013

20. Captain Clean Energy Project, CO2DeepStore, 2011

21. UK Storage Appraisal Project, Energy Technologies Institute, 2011

22. Delivering CO2 storage at the lowest cost in time to support the UK

decarbonisation goals. UK Transport and Storage Development Group,

2013.

23. Capacity Charing Mechanisms for Shared CO2 Transportation and Storage

Infrastructure. Global CCS Institute and National Grid, 2013.

24. Delivering a CCS Network in the Tees Valley Region. Element Energy and

Carbon Counts, 2010.



Annex E - Glossary

Name Definition

B Billion

BIS Department of Business, Innovation and Skills

BOC BOC

BRAM Baseline Risk Allocation Matrix published by DECC as part of the CCS Commercialisation Programme

Bunter Bunter Formation aquifer 5/42 and 5/43

Capex Capital Expenditure

Captain Formation aquifer underlying the Goldeneye depleted gas field and extending NW from there

CCS Carbon Capture and Storage

CCS Authority Carbon Capture and Storage Authority

CCS Commercialisation

The UK Carbon Capture and Storage Commercialisation Competition

CfD Contract for Difference

CNS Central North Sea

CO2 Carbon Dioxide

DCF Discounted Cash Flow

DECC Department of Energy and Climate Change

DPI Discounted Profitability Index (1+PIR)

Emitter Industrial site emitting CO2

EOR Enhanced Oil Recovery

EU European Union

FEED Front End Engineering Design

Gathering System Onshore transport system required to collect CO2 and transport it to the compressor

GDP Gross Domestic Product

Government Her Majesty's Government

HMG Her Majesty's Government

ICCS Industrial Carbon Capture and Storage

IRR Internal Rate of Return

LCoC Levelised Cost of Capture

LCoCTS Levelised cost of Capture, Transport and Storage

LCoS Levelised Cost of Storage

MT Million Tonnes

NEPIC North East Process Industry Cluster

NPC Net Present Cost

NPV Net Present Value

OCCS Office for CCS (part of DECC)

O&M Operation and Maintenance

OPEX Operational Expenditure

PBDE Pale Blue Dot Energy Ltd

PET Polyethylene Terephthalate

PIR Profit Investment Ratio (NPV/Discounted Capex)

Pre-FEED Pre- Front End Engineering and Design

Project Teesside Collective Carbon Capture and Storage Project

PV Present Value

PV7 Present Value at a 7% discount rate

SNS Southern North Sea



SSI Sahaviriya Steel Industries

Store Location of the CO2 storage site

Storer Developer organisation responsible for the storage

TC Teesside Collective

Transportation System

Offshore transport system required to transport CO2 from the compressor to the store

TVU Tees Valley Unlimited Local Enterprise Partnership

UK United Kingdom

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