Energy Focus Autumn 2016

ISSN: 1749-3811

Issue 27 n Autumn 2016

THE MIDDLE EAST:

Issue 27 n Autumn 2016

Gulf NOCs adapting to a new era

FROM THE ENERGY INDUSTRIES COUNCIL

OIL & GAS:

Collaborative contracting to get projects off the drawing board

VIEW FROM THE TOP:

Jeff Reilly Group President, Strategy & Business Development, Amec Foster Wheeler

www.the-eic.com

PLUS: Vietnam: the new market for your business? n PDO EOR breathes new life into old wells n UK leads global race for mini-nuclear reactors n Behind the scenes with OGA’s Technology Leadership Board n Australia making waves in renewable energy n The future of CCS

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From the EIC

From the

Chief Executive...

Energy Focus is the EIC’s flagship publication. Produced twice a year, it delivers regional market insights, expert commentary and in-depth features on the global energy industry It’s a real pleasure to be writing my first foreword for Energy Focus since joining the EIC in May. Having been a long time reader of what I consider to be a key industry magazine, I’m delighted to be contributing to its content.

As the autumn season kicks off with ADIPEC 2016, there is a good deal to be positive about. Much like the event itself, the EIC’s involvement has grown year on year.

In 2015 ADIPEC broke all records attracting over 94,000 visitors and this year will surpass the 100,000 mark. Likewise, the EIC’s UK pavilion is not only the largest of all the pavilions we host at energy events around the world, it also has the most UK companies exhibiting, each showcasing skills and solutions to be proud of.

The fact that ADIEPC has built on its success in the midst of a global economic down cycle demonstrates the resilience of the Middle East.

This buoyant market – which currently has 675 active and future projects, 146 of which are in the power, nuclear and renewables sectors (information taken from EICDataStream) – is proving its strength as well as depth.

At the same time, the Middle East is experiencing significant change, one of the most notable aspects being the restructuring of national oil companies in several Gulf countries. Edmund O’Sullivan’s article on page 28 looks at how this will affect member companies who want to work in the region.

Hydrocarbon superpowers Saudi Arabia and Iran also feature in an article on page 33 by the EIC’s Terry Willis. As head of our Dubai office with responsibility for the Middle East, Africa and CIS, Terry draws on his 30 years of experience in the region to follow how these two countries are tackling low oil prices and financial issues at home.

Developing joined up ways to meet the current economic challenges is the subject of this

edition’s View from the Top interview (page 11). Amec Foster Wheeler’s Group President for Strategy and Business Development, Jeff Reilly, explains how his company’s focus has shifted to efficiency, collaboration and driving new ways of thinking.

It’s also good to see so many oil and gas conferences around the world now integrating the theme of responses to market conditions in their programmes. Petroleum Development Oman’s David Brown explores this theme further in an article on page 36. His company’s ground-breaking work in enhanced oil recovery highlights the importance of innovation at all times – whether thriving or surviving.

There was a time when collaboration among energy heavy weights was generally frowned upon. However, reality has now kicked in and the concept of working together has been gaining ground. Allen Leatt (page 88) argues for the industry to collectively reassess its cost bases to get CAPEX projects off the drawing board and up and running. This, he feels, can only be achieved if there is real collaboration between the supply chain and operators.

In terms of the UKCS, we go behind the scenes of the Oil and Gas Authority’s (OGA) Technology Leadership Board to see how it is centring technological efforts on the UKCS to maximise available resources and revenues (page 74).

One of the OGA’s main goals also involves promoting the opportunities that North Sea decommissioning has to offer. In his article (page 71) Roger Esson, CEO of Decom North Sea, traverses this very area, in a sector estimated to be worth £17bn in the next decade alone.

Nuclear decommissioning holds much promise for the UK supply chain too. On page 114 the EIC’s Oliver Barnes analyses Germany’s nuclear phase-out and the rich rewards UK companies could reap. To complement this, our recent Insight Report on nuclear decommissioning delves further into the topic (members can download a copy from EICDataStream).

Another rapidly developing sector is renewables.

The EIC’s William Sharkey examines the phenomenal growth of the global solar PV market (page 125), to which many oil and gas companies can transfer their skills.

As the fastest-growing energy consumer in the world, accounting for 40% of global oil demand, Asia Pacific tells an encouraging story. We put the spotlight on two of the region’s rising stars: Vietnam (page 56) and Indonesia (page 58). With massive natural resources and rapidly rising energy consumption, both countries are attractive markets for UK companies.

We all recognise the changes in the market and the need to change with it. This is precisely why the EIC is re-doubling its efforts for our members.

We’ve enhanced our project tracking capability to look at regions that companies may not have previously considered. We’re offering more tailored advice and support based on needs.

We’re also working harder to develop the right contacts that can generate new business.

In fact, the International Energy Agency estimates that South East Asia’s demand for energy will increase by 80% in the next few decades. For companies looking to capitalise from huge future investment, attending OSEA (Offshore South East Asia, held in Singapore later in 2016) could help with your business development planning (read more on page 61).

If you’re interested in learning more about the benefits of EIC membership, we’d love to hear from you. Please email us at membership@the-eic.com n Stuart Broadley Chief Executive Energy Industries Council

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Issue 27 n Autumn 2016

Contents From the EIC Foreword 5

Q&A with Stuart Broadley 14

From the Chief Executive

Meet the EIC’s new CEO

View from the top 11

About the EIC 18

Jeff Reilly, Group President of Strategy and Business Development, Amec Foster Wheeler

What we do and our newest members

11 EIC Global Middle East and North Africa Regional report

23

Asia Pacific, Australasia and China

ADIPEC 2016

24

Regional report

55

Vietnam: rising star in Asia Pacific The South East Asian country looks to expand its offshore exploration and refinery capacity

56

Gulf national oil companies 28 set to define future of world energy How the region’s NOCs are adapting in the new era Low oil: a challenging period 33 for the Middle East super powers Saudi Arabia and Iran tackle falling oil prices

Powering up Indonesia 58 Indonesia’s 10-year power plan pushes coal and renewables OSEA 2016

Breaking new ground in 36 enhanced oil recovery technologies Oman leads the way in enhanced oil recovery

North and Central America

EIC Connect Middle East 2016

41

South America

EIC trade delegation to Iran

42

Regional report

Regional report

Egypt Petroleum Show (EGYPS) 2017 44

Russia and Caspian

United Kingdom

Regional report

Regional report

46

EIC Connect Oil & Gas 2016

49

Regional report

50

Offshore Mediterranean Conference 2017 54

28

62

63

65

Indian subcontinent, Pakistan and Afghanistan Regional report

Europe

61

66

Sub-Saharan Africa Regional report

67

Oil and Gas The UK prepares for 71 decommissioning While North Sea decommissioning is set to take off in a big way in the future, UK companies need to be ready for action now

Driving technological 74 innovation in the North Sea

What is the OGA’s role in stimulating innovation to maximise economic recovery?

Glocalisation: 81 thinking globally acting locally

Beyond pre-salt: 85 offshore frontier exploration in South America South America’s hottest oil and gas offshore frontier exploration areas

Contracting in the new era 88

The potential risks of unlimited liability is causing great concern within the marine contracting world

85

To succeed in global markets, utilising the local supply chain is a necessity

7

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Run by engineers and industry specialists Developed for energy professionals Discounts for EIC members Early bird and group offers

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Issue 27 n Autumn 2016

Contents Power Electricity storage is ready now

92

99

The Capacity Market and the role of peaking power plants

The UK electricity storage industry is ready and willing to deploy but regulation needs to catch up

CCS is vital to meeting Europe’s climate targets

Powering ahead

95

Closing Sub-Saharan Africa’s energy gap

100

Can renewables and gas help bridge the region’s power gap?

CCS technology is a reality but insufficient policy support is a barrier to progress

92

Nuclear A small revolution

104

Seeking innovative solutions to technical challenges

108

Small nuclear reactors could be powering the UK by 2024

Delivering progress in nuclear decommissioning

Nuclear power in South Africa ready to leap forward

111

Germany’s nuclear phase-out

114

South Africa's nuclear new build plans offer great potential for the UK supply chain As Germany unplugs itself from nuclear and embraces renewables, what lies ahead?

114

Renewables The fifth carbon budget: an important step towards a low carbon economy

119

A global solution from an island-nation

122

125

Leading the way in wave energy

128

Solar power on the rise in India and South Africa

UK sets fifth carbon budget, but what next?

Tidal energy under review

Global opportunities in solar PV

CETO technology goes deep to harness wave power

122

ENERGY INDUSTRIES COUNCIL (EIC) 89 Albert Embankment, London SE1 7TP

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Cover photograph: The GASCO gas processing plant at Habshan in Abu Dhabi, UAE, is one of the largest complexes in the world. Photo: ADNOC

SALES ENQUIRIES Tim Cariss, Media Executive T: +44 (0)161 661 4174 tim.cariss@excelpublishing.co.uk

Designed and produced by Excel Publishing Co Ltd 6th Floor, Manchester One, 53 Portland Street, Manchester M1 3LD T: +44 (0)161 236 2782 www.excelpublishing.co.uk Editors: Sairah Fawcitt and Edward White

Printed by Buxton Press Limited, Palace Road, Buxton, Derbyshire SK11 6AE Every care has been taken in compiling this publication and the statements it contains. All information is correct at the time of going to press.

The opinions herein are those of the authors and not of Excel Publishing Co Ltd or the EIC, who cannot take responsibility for any error or misinterpretation based on this information, nor do they endorse any of the products advertised. © Energy Focus EIC Autumn 2016.

Published by Excel Publishing Co Ltd. Visit eic.excelpublishing.co.uk to view the ebook All rights reserved. No part of Energy Focus may be reproduced by any means, or translated into a machine language without the written permission of the copyright holder.

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From the EIC

View from the top In the midst of the oil price crash, which has seen energy companies shelve nearly US$400bn of spending on new projects, Jeff Reilly, Group President of Strategy and Business Development at Amec Foster Wheeler talks to Energy Focus about how the company is dealing with the downturn The new structure is based on operating geographies in the Americas, northern Europe and the Commonwealth of Independent States, Asia, the Middle East, Africa and southern Europe, and is leaner, more nimble and opens further opportunities for growth.

hen ADIPEC opens its doors to the international oil and gas market in November, it will be nearly two years to the day since Londonbased Amec completed the acquisition of US-listed Foster Wheeler. The company will have a significant presence at ADIPEC and fittingly, this year’s theme is ‘Transitional Strategies for an Efficient and Resilient Energy Industry’.

‘We could have organised the integration by market, for example, but we wanted a complete and rapid integration,’ says Reilly. ‘By using a regional approach, it gave us the opportunity to instantly have Amec people working for Foster Wheeler people and Foster Wheeler people working for Amec people, utilising integrated systems and tools. Moving forward, the organisation structure will continue to evolve as we look to get closer to our customers.’

While market conditions remain challenging in many places and the low commodity price looks set to continue, Jeff Reilly – the man brought in to help with the planning of the integration and implementation process, and to take on the role of corporate strategy and global business development – is confident about the future.

Following the merger, Amec Foster Wheeler employs 36,000 people, has operations in more than 55 countries and provides a range of services – including consultancy, engineering, project management and construction – not only to the oil and gas industry, but also to clean energy, mining and environment and infrastructure (E&I) businesses. Its client base includes BP, ConocoPhillips, Dow, EDF, ExxonMobil, Rio Tinto, Sempra, Shell, the US Department of Defence and ZADCO. The merger has provided a number of strategic opportunities, explains Reilly, ‘By adding Foster Wheeler’s mid and downstream capabilities to Amec’s upstream focus, the company has expanded its operations across the entire oil and gas value chain. Many of our customers like ExxonMobil for example, operate both in upstream and downstream. Combined, we can now service all parts of their portfolio.’

Reilly continues, ‘We have also been able to extend our geographic footprint in regions such as the Middle East, Asia and Latin America.’

Good progress ‘The integration is going well,’ says Reilly. In any major merger the first thing you gain are cost synergies, he explains, highlighting that while overhead costs have been cut due to the consolidation of operations, priorities

Flexible business model

“The depth and breadth of our experience enables us to create a flexible and commercial model for meeting our customers’ challenges whatever market they are in and wherever they are” for this year include driving cost reduction and efficiency programmes. About £130m annual cost savings are expected by 2017.

The company has also been steadily developing significant revenue synergies.

‘We count revenue synergies as those which neither individual company would have achieved itself,’ says Reilly pointing to their work on Anagold Madencilik’s Çöpler gold mine in the Erzincan province, Turkey.

‘Foster Wheeler didn't have the gold mining expertise and Amec didn't have a presence in Turkey. But together, as one company, we were able to win that work,’ he says.

As international and national oil companies continue to limit expenditure and decrease capital spend as they adjust to market conditions Reilly acknowledges that there are tough times ahead but points to the benefits of Amec Foster Wheeler’s multi-market business model and its diversity, adaptability and scalability.

‘We have developed a business with a range of full life-cycle services to many different customers in many different countries around the world,’ says Reilly. ‘Because we have an expanded global footprint, we can adapt to changing market conditions and move resources to where the work is. Today, Amec Foster Wheeler is a much stronger business than either Amec or Foster Wheeler would have been on a standalone basis.’

Operating efficiently Amec Foster Wheeler’s approach to seizing opportunities is based on technical innovation, strong collaboration and the ‘More4Less’ methodology of delivering more work for less cost without compromising on safety.

Launched last year, to lower the cost of delivering small projects in the UK North Sea market, ‘More4Less’ is the company’s new approach to delivering genuine efficiency savings to customers. This is achieved by standardising designs to reduce duplicated

11

From the EIC costs with the project owner, making the supply chain even more efficient and using technology to ensure that things are routinely done right first time, every time.

According to Reilly, efficiencies from 'More4less' have been proven to deliver 30–60% savings – in time and cost – compared to traditional approaches. It is now moving quickly into a new phase, with customers asking whether it can work on larger scopes on an international basis, including for new-build projects.

‘So right now, across all our markets, it's all about increasing and implementing capital efficiency. And "More4Less" is a key part of that,’ says Reilly. With thousands of specialists, engineers and project managers around the world, ‘the depth and breadth of our experience enables us to create a flexible and commercial model for meeting our customers’ challenges whatever market they are in and wherever they are’.

Fishing where the fish are Amec Foster Wheeler has had notable successes in helping customers achieve greater efficiencies and ‘we have continued to win projects and contracts across all of our sectors,’ says Reilly. Although in some regions, projects have been cancelled and project decisions have been slower than anticipated.

By ‘fishing where the fish are’, the company plans to focus on parts of the business that are stable or growing. The 'end markets' of growth are identified as downstream services in the Americas, renewables and government services, while nuclear and brownfield oil and gas are considered stable.

Amec Foster Wheeler An international energy services company providing consultancy, engineering, project management, operations and construction services, project delivery and specialised power equipment services to customers worldwide.

Core markets: oil and gas, clean energy, environment and infrastructure and mining markets Revenue: US$5.5bn

Awarded in 2012, Amec Foster Wheeler’s five-year contract provides brownfield EPC and commissioning services in support of Repsol Sinopec’s Montrose Area Redevelopment project in the Central North Sea, extending the life of the existing Montrose Area fields. The photo shows the new bridge-linked platform connected to the Montrose Alpha platform – one of the oldest in the North Sea

In upstream oil and gas, while Reilly reports a shift from new build CAPEX towards the OPEX operations and maintenance market as greenfield activity takes a dip, he says the company has benefitted from its strong position in brownfield and hook-up activity in the UK. ‘We are seeing good demand in downstream work in the US as refiners make light sweet crude oil investments. In addition, as companies seek to monetise low cost natural gas from the shale revolution this has sparked a surge in the construction of new gas processing, LNG export, petrochemical and refining capacity.’

Globally, there has been greater attention focused on renewable energy, mainly on account of the COP21 Paris Agreement says Reilly. ‘We have seen robust growth especially in North America as US tax incentives for wind and solar are being extended out to 2022.’ The company also plans to increase

operations in the Middle East as more nations are increasingly using their oil wealth to harness power from clean sustainable sources.

‘Our wind and solar business in power is an important focus for us right now,’ he adds.

The strong growth in E&I has been underpinned by increasing government work in the US, says Reilly. ‘The US government is a very large customer and with our geographic presence we work with various US government entities including USAID and the US Department of Defence around the world.’

North America North America currently accounts for nearly half of Amec Foster Wheeler’s revenues with Canada and the US generating 48% of group revenue in 2015, approximately £2.6bn.

This demonstration of strength comes as no surprise to Reilly and he believes that, in part, it is down to offering services across all four markets and building leading positions in a number of sectors. For example, Amec

Employees: approximately 36,000 Geographical coverage: major hubs in the UK, North and Central America, the Middle East and Australia and a global footprint in 55 countries worldwide

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“We need to communicate the real benefits of collaboration throughout the entire supply chain and commit to supporting all parties in the adoption of innovation and new behaviours” www.the-eic.com

From the EIC “We’re in a new pricing environment moving forward… and whether it’s ‘lower-for-longer’ or ‘lower-forever’, the industry will need to adjust to the new reality” Foster Wheeler has a market leading position in Canadian mineable oil sands with in situ expertise, a strong US position onshore and in the Gulf of Mexico, as well as a growing presence in Mexico. ‘We provide a fullservice solution in the mining market from our leading position in consulting, project delivery and remediation. In clean energy, we have a strong renewables business supporting the development of solar and wind projects, a robust nuclear position and a growing development of gas power.’

However, Reilly sees plenty of scope for further growth, whether it is extending the services provided to existing clients, delivering more integrated services, or winning new customers in new locations.

US shale gas has shifted the energy mix globally says Reilly. ‘And the boom looks set to make the US a net gas exporter, giving it security of supply and changing the dynamics of its gas market.

'It has had a positive impact on our clean energy activities as the low natural gas price has driven the transition to gas-fired power generation which is highly-efficient, cost-effective and has a lower carbon footprint than coal.’

Nevertheless, Reilly notes that US shale has made it more challenging for solar and wind energy to compete on economic grounds. He adds, ‘We’ve seen the lifting of the 40-year-old US crude export ban at the end of last year, a historic action which reflects the political and economic shifts driven by the rapid rise in shale hydrocarbon production.’

excited about recent developments in the country he grew up in. ‘The Saudi market poses attractive opportunities, especially as it embarks on its ambitious Vision 2030 strategy designed to end the kingdom’s dependency on oil and transform the country into a global investment power.’

He cautions, however, that developing countries across the region, and indeed Asia, are adopting higher local content requirements. So to improve the prospects of winning work, he advises the supply chain to deliver locally – perhaps by building in-country joint ventures and partnerships.

Project delivery Reilly explains one of Amec Foster Wheeler’s major pillars of strategy is to combine local regional offices and capabilities with collaborative efforts on project execution, in Thailand, India and Vietnam and centres of excellence in Europe, Asia, America and Australia.

‘When there's a large opportunity in front of us,’ says Reilly, ‘By looking through the lens of our customers – and having previously worked at ConocoPhillips procuring services, that’s one of the roles I play – we can determine what is the best combination of our capabilities for this opportunity for the client.’

Middle East is key

‘We're currently working on a methane-tomethanol plant project in Louisiana in the US for Yuhuang Chemical Inc – a company which is making its first investment into the US. Our lead office is in Houston and it made the most sense to use our supply chain expertise in China with suppliers that they were comfortable with.’

As Amec Foster Wheeler readies itself for ADIPEC 2016, Reilly says ‘The Middle East region is a key strategic area for us and despite the challenges, we still see potential growth.’

Reilly feels that this approach is particularly crucial in the current market environment where competitiveness is king.

Local operators are still investing in the region and the company has expanded operations in the UAE to make Abu Dhabi its hub of expertise in the region. ‘We are actively working on mega-projects in Kuwait, Saudi Arabia, Iraq, Qatar and Oman,’ says Reilly noting that ‘like many others we are looking at Iran, staying in line with the sanction guidelines’.

As well as providing oil and gas services, the company is also looking to expand its nonhydrocarbon business across the Middle East.

Having identified the UAE, Kuwait and Saudi Arabia as core markets, Reilly is

Championing collaborative innovation With the industry’s focus firmly on reducing costs and improving efficiency, projects are becoming more technically challenging. For projects to succeed, ‘we need to communicate the real benefits of collaboration throughout the entire supply chain and commit to supporting all parties in the adoption of innovation and new behaviours,’ says Reilly. And he acknowledges the important role industry forums like ADIPEC and organisations such as the EIC play in inviting and furthering dialogue.

Technological innovation is crucial in the current environment says Reilly. ‘We know that innovation gives us competitive advantage and during recent years we have implemented a number of technologies, including diagnostic software used in the car industry for preventative maintenance and 3D laser scanning technology to create accurate as-built assets digitally for work on retrofit and upgrade projects.’

Most recently, Amec Foster Wheeler championed an Oil and Gas UK study with TOTAL Exploration and Production to identify new technologies to improve asset integrity on the North Sea.

UK commitment So what does the future hold for Amec Foster Wheeler in the UK? While Reilly appreciates ‘it is too early to predict the impact of Britain's decision to leave the European Union on its energy industry,’ it seems safe to assume that investor confidence has been knocked by Brexit.

‘Out of our 36,000 employees, we have around 10,000 people in the UK and about 4,500 in other EU countries,’ says Reilly. ‘Given the range of our activities and the international nature of the markets in which we operate, I don’t see a huge impact, either in the short-term or longterm, on Amec Foster Wheeler’s operations or those of our supply chain as a result of the UK’s vote to leave the European Union.’

Looking ahead One certainty is that global energy demand will continue to grow as countries develop and living standards improve says Reilly. While the fuel mix will shift, ‘oil, gas and coal will remain the dominant form of energy for a long time – but burnt cleaner’. He notes that although renewables is expected to quadruple by 2035, it is from a very low base, while hydroelectric and nuclear will increase steadily.

‘We’re in a new pricing environment moving forward,’ says Reilly. ‘And whether it’s "lowerfor-longer" or "lower-forever", the industry will need to adjust to the new reality based on the current energy supply-demand balance, for the foreseeable future.’ n

About Jeff Reilly Jeff is currently Group President of Strategy and Business Development.

He includes within his scope, strategy and global business development across all sectors, as well as corporate affairs. Previously, he held executive roles at ConocoPhillips, as well as senior roles at other major international EPC contractors.

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From the EIC

Q&A with Stuart Broadley, EIC CEO Stuart joined the EIC as its new CEO in May 2016, bringing to the company over 20 years of global energy services experience.

Before taking over the leadership of the EIC Stuart was based in Vienna, working as Hoerbiger’s Global Head of Service for its Compression Technology Division. Prior to that he spent four years in Hamburg with wind turbine manufacturer Repower Systems AG (now Senvion), having previously worked for 13 years with Wood Group.

Energy Focus talks to Stuart about his vision for the EIC, the work it is doing to support members to expand into new markets and what he thinks the future holds for the energy industry Q. Leaving Hoerbiger and your life in Vienna must have been a big decision, what was it about the EIC that attracted you to this role?

A. When the opportunity came along to lead the EIC, which is widely regarded as the leading UK energy trade association, it was clearly a unique chance for me to work closely with a wide array of talented and influential stakeholders, covering member companies, energy experts, the DIT (formerly UKTI) and FCO, and other associations to name a few.

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Stuart brings over 20 years of global energy services experience to the EIC

I’ve been in the energy industry for 20 years now, and have gathered a broad spectrum of experiences across different products, sectors and regions, and have a very interesting network as well. This role offers me the opportunity to give something back to the UK energy industry.

I am really eager to work with the dynamic and experienced EIC team to help the UK supply chain prosper in what are challenging but still exciting UK and international markets.

“Don’t be too afraid of becoming an exporter – not just to emerging markets but also mature markets like Europe where there are huge opportunities” www.the-eic.com

From the EIC Now that you’ve started to settle into your new role, what are your first impressions of the EIC? I was lucky enough to attend one of our flagship events, EIC Connect Middle East in Abu Dhabi, in my first week with the EIC. What I was struck by was the highly professional and yet friendly nature of the event. I was also hugely impressed by the content of the presentations from the major operators such as ADNOC, ENEC, BP and Shell, and key contractors and industry experts which the event attracted.

The extremely positive feedback which we got from all the attendees, not just the delegates and exhibitors but also from the operators and contractors was fantastic.

What became really clear over the course of the event was the relevance of what the EIC is doing to bring members of the UK supply chain closer to the action. By this I mean opportunities that are deliverable outside the UK and making those opportunities real through unparalleled access to influential decision makers in major energy companies.

I’ve come into an organisation which has a highly effective and motivated team of energy experts in place and have quickly concluded that my job is to focus our time and resources fully to meet the needs of members in what is still a fast growing, but competitive, global energy market.

Now I am working with the team to get closer to members to really understand what their short and medium-term needs are, so we can further enhance our effectiveness in meeting those needs.

Your previous positions have focused on service excellence and bespoke business solutions. What have these roles taught you?

My career in the global service business has covered the oil and gas, power, renewables and technology sectors. During the last two decades I’ve identified common dominators for success which I know can be applied to the EIC and its members.

The primary one is to focus on solving the problem of your customer, in this case our members. Listen clearly to what is needed rather than assume you know what is needed.

Early on in my career while at Wood Group I received a bit of advice that I’ve never forgotten and that is, the key to success is to listen to what the customer wants. It’s not about me telling them what I think they need but actually listening actively, and then adapting my offering to solve their problems.

Consistency and professionalism of service are critical. Service providers spend years building up trust with their customers, which really

Stuart joined the EIC from Hoerbiger where he was Global Head of Service for its Compression Technology Division

“A natural evolution of EICDataStream is to extend it into the energy industry’s aftermarket sector, covering the OPEX cycle as well as the CAPEX cycle”

becomes a partnership, but that can be lost in days if the service level is not acceptable, so you’ve got to keep standards high all the time.

With a particular focus on trade associations, I really believe that the time has come for us to start collaborating more. There are a lot of us on the market, and I want to see the EIC take a lead in consolidating this sector in a way that will help supply chain companies as they seek to export more actively or consider transitioning their business from one sector to another.

You’ve worked in both the oil and gas and renewables sector. What insights does this allow you to bring to the EIC? I have been fortunate to work across nearly all energy sectors and it has taught me a few things. A key consideration for those companies thinking of diversifying across sectors is that there are differences in customer expectations in different industries such as their mind-set on project life time, contract models, safety and risk. However, I have found, as I have moved from sector to sector, that there is still huge potential for

oil and gas related skills and experience, for instance, to be brought quickly into other sectors, especially nuclear and renewables.

I worked in the wind turbine business at a time when the industry was still relatively young and was looking to oil and gas to learn, which is why I moved to renewables – to try to transfer my oil and gas expertise.

Indeed, I discovered that a huge amount of this knowledge could be transferred such as reliability management, inventory and working capital management, sales and commercial structures and technical skillsets.

At the EIC, we are really focused on helping members with a background in oil and gas get into the renewables and nuclear sectors.

We really do offer a great deal to help with that transition, both in the UK and globally.

We have a number of Insight Reports which give very detailed information on how the renewables and nuclear sectors work, who the players are, what the key projects are, and how to navigate the processes in place to enter these markets. We provide a huge amount of training from industry experts on getting to know different markets and how to enter certain territories. We are also extremely active participants in major renewables and nuclear events around the world, often managing UK pavilions.

We do a lot of great work already but we always want to do more for our members. With that in mind I am in the process of setting up further EIC Connect events in the key renewables hubs around the world, which will bring together the buyers, operators, contractors and industry experts with our members in an environment where relationships can be built, deals can be struck and knowledge can be enhanced.

15

From the EIC

During his first week as EIC CEO Stuart (pictured with members of EIC’s senior management team) took part in EIC Connect Middle East 2016 in Abu Dhabi

Your career to date has had a strong emphasis on OPEX. Will this have any impacts on the EIC and the services it offers?

One of the EIC’s key offerings is its hugely successful project database, EICDataStream, which is recognised by our members as the go-to database for large capital investment projects across the energy sector on a global basis. What seems to me as a natural evolution of that great capability is to extend it into the energy industry’s aftermarket sector, covering the OPEX cycle as well as the CAPEX cycle.

I will bring my global service experience to the EIC and quickly help us to further serve members across the aftermarket and OPEX cycle. Extending EICDataStream accordingly is just one of the ways we’ll being doing so.

You’ve lived and worked all over the world.

What advice can you give our members thinking about expanding into new markets?

Yes, it’s true, I have travelled extensively all over the world and lived not just in the UK, but also in Canada, Germany and Austria. I’ve learnt first-hand that culture, not only national culture but also business culture, is absolutely critical to success. You have to know where culture will have an impact on your business and have a clear plan on how you are going to address it. The EIC can help with this. We see one of our roles as providing insight into understanding and adapting to different cultures. The EIC has a global network of offices in strategic locations around the world, so we’ve got experts on the ground who know the local markets inside out, can introduce you to the key players, explain regional

16

legislation and help you find local partners.

In my experience the careful use of humour also helps greatly when doing business abroad. This cuts through cultural barriers very quickly, builds friendships fast and allows you to get onto the other topics you really want to talk about.

It can be very expensive and time consuming to target a new country or area. Again, this is something which we can help with.

We can accelerate the time it takes to establish a presence in a new country by providing a hot desk or serviced rental office facilities at one of our global offices – this really does reduce the risks and expenses associated with entering a new market.

One thing I would like to say is don’t be too afraid of becoming an exporter. And not just to emerging markets but also mature markets like Europe where, in my experience, there are huge opportunities such as nuclear decommissioning in Germany or in the renewables sector across the whole of the region.

What do you think the next few years have in store for the energy industry?

I think that the trend towards more money being spent globally every year on renewables projects compared to other traditional fuels will continue into the future and that renewables will continue to grow in importance and influence on a global basis – as a technology, as an employer and as a fuel source.

Without a doubt, energy diversity will become ever more important as countries

“The EIC has a global network of offices so we’ve got experts on the ground who know the local markets inside out, can introduce you to the key players, explain regional legislation and help you find local partners” and operators seek to diversify to reduce the impact of any future down cycles.

In the future I believe we’ll see more and more focus on big data where companies will increasingly offer solutions to improve efficiency, reliability and cost effectiveness through analysis and management of operating data to help squeeze every last dollar out of existing assets.

Although lower-for-longer oil seems probable, my view is that both through a slow but steady increase in oil price and increasing activity in decommissioning there will be a recovery in the UK oil and gas supply chain sector albeit different from how it looked in the past. New more innovative players will emerge, and there will be more industry consolidation and partnerships – ultimately though creating higher activity levels again. n

www.the-eic.com

High-profile international events connecting suppliers with buyers

Join our trade delegations to learn about regional energy markets, build business relationships and generate new opportunities

2016/17 delegations include: Mozambique and Africa Oil Week (Nov) Myanmar (Jan) Uganda (Feb)

Book a stand in our UK pavilions at major energy exhibitions to showcase your products and services to global contractors and operators

2016/17 exhibitions include:

Oil & Gas Asia (Kuala Lumpur) Offshore SE Asia (Singapore) ADIPEC (Abu Dhabi) OTC (Houston)

Find out more and book at www.the-eic.com/Events

From the EIC

About the EIC

E

stablished in 1943, the EIC is the leading trade association for UKregistered companies working in the global energy industries. Our member companies, who supply goods and services across the oil and gas, power, nuclear and renewable sectors, have the experience and expertise that operators and contractors require.

As a not-for-profit organisation with offices in key international locations, the EIC’s role is to help members maximise commercial opportunities worldwide.

We do this in a variety of ways from providing detailed project information and regional market insight; to showcasing specialist skills and connecting suppliers with buyers; through to running tailored training courses and events that inform and engage the industry.

The services we offer play an important part in supporting over 600 member companies to do business in a competitive marketplace.

Market insight EICDataStream: helping members

to track global energy projects Our projects database, EICDataStream, provides extensive information on almost 8,000 active and future projects in all energy sectors. By tracking the full project life-cycle from feasibility to construction and then completion, it helps members to identify opportunities and plan their business development strategies.

Business intelligence Keeping members informed and raising their profile We help our members to stay connected with

A warm welcome to the EIC’s new members...

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www.the-eic.com

From the EIC

the world of energy through informative online news, e-bulletins, market reports and industry publications. Our comprehensive directory of member supplier services is also a useful resource for operators and contractors.

projects, sector developments and markets.

Our overseas trade delegations and EIC-run pavilions at international exhibitions are also a good way of introducing members to regional energy markets and their major players.

High-profile international events

Worldwide business support

Connecting members with buyers and enhancing knowledge The EIC hosts flagship industry events that bring together UK supply chain companies with global energy contractors and operators, and bespoke events that keep members informed about

Helping members to enter or expand into markets across the globe Member companies who want to do business outside the UK can rely on our global network to provide regional market knowledge, one-toone advice and practical support. We also run

events and training courses, provide virtual and rental offices, and offer facilities for hot-desking, meetings, conferences and corporate events.

Industry courses Trusted training from energy experts Our quality courses, which can be delivered off-site or in-house, are led by highly experienced trainers with industry backgrounds. We tailor our training to suit a variety of levels and also work with member companies to run programmes, some of which include tours to manufacturing companies.

A warm welcome to the EIC’s new members...

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19

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Middle East and North Africa Regional report

23

ADIPEC 2016

24

Gulf national oil companies set to define future of world energy

28

Low oil: a challenging period for the Middle East super powers

33

Breaking new ground in enhanced oil recovery technologies

36

EIC Connect Middle East 2016

41

EIC trade delegation to Iran

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Egypt Petroleum Show (EGYPS) 2017

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United Kingdom Regional report

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EIC Connect Oil & Gas 2016

49

Europe

EIC Global

Regional report

50

Offshore Mediterranean Conference 2017

54

Asia Pacific, Australasia and China Regional report

55

Vietnam: rising star in Asia Pacific

56

Powering up Indonesia

58

OSEA 2016

61

North and Central America Regional report

62

South America Regional report

63

Russia and Caspian Regional report

65

Indian subcontinent, Pakistan and Afghanistan Regional report

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Sub-Saharan Africa Regional report

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21

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EIC Global

Middle East and North Africa Despite the many changes taking place across the region, the Middle East and North Africa continue to provide a vast amount of opportunities for the UK supply chain

There is significant activity in Algeria where gas discoveries continue to be made (image: Anadarko Petroleum Corporation)

T

his year has seen some interesting developments to say the least. A number of regional national oil companies (NOCs) have used the current depressed state of the market to take a closer look at themselves and reassess how they are delivering their services.

Setting this trend for self-assessment was Qatar Petroleum. A streamlining process plus a reintegration of operations took over eight months from which emerged a much leaner company totally focused on its core business.

Later in February, Abu Dhabi’s National Oil Company (ADNOC) found itself with a new CEO. Sultan Al-Jaber, the UAE minister of state who is widely credited with the success of the Masdar development was given the role of examining all activities of the mother company plus its numerous operating companies.

After only three months in the job, he had replaced six operating company CEOs and announced two new senior appointments, with further changes anticipated.

Developments in Saudi Arabia have made global headlines with long-serving oil minister Ali Al-Naimi being replaced by ex-Aramco chief, Khalid Al-Falih, while the government has announced plans to sell a 5% stake in Saudi Aramco as part of the Saudi Vision 2030 to diversify what has until now been an oil-dependent economy. Meanwhile, across the causeway in Bahrain, Tatweer is now on the lookout for new partners following the withdrawal of Mubadala and Occidental from the consortium.

“In Saudi Arabia longserving oil minister, Ali Al-Naimi, has been replaced by ex-Aramco chief, Khalid Al-Falih while the government has announced plans to sell a 5% stake in Saudi Aramco�

Despite all the changes taking place, the region remains one of the most active as far as opportunities for UK supply chain companies are concerned. Major contracts are being awarded across the Gulf from Kuwait all the way down to Oman with Petrofac leading the EPC-contractor chase for new business. It recorded a backlog of US$20.7bn when they posted their 2015 results earlier this year.

Besides the Gulf countries, there are also pockets of significant activity in Egypt and Algeria. In Egypt, Italian giant ENI is fast tracking the development of the huge gas finds in the Nooros area they announced at the end of last year, while BP has also taken the plunge to develop the huge West Delta Deep field along with two smaller gas fields located nearby. Onshore, expansion of the downstream facilities to accommodate this new source of feedstock will be announced

on a piece by piece basis. In Algeria, further gas discoveries continue to be assessed with PetroCeltic and BP prominent where new development projects continue to feature.

With all these awards, there comes an expectation that the ratio of in-country value (ICV) will be increased within the contract awards. Of all the countries mentioned awarding these contracts, Oman is setting an example in this area through its stringent adherence to a policy to provide more employment opportunities for the local population. Iraq has done its best during some fiscally challenging times while Saudi Arabia continues to remain committed although it does recognise that it has to make huge cultural changes if it is to be successful.

On the subject of ICV, the regional past masters of this convention, Iran, cannot be overlooked. Having endured a prolonged period of economic and trade sanctions, its economy has not only survived but actually blossomed through this difficult time purely because of the close engagement of its population, the second largest in the region after Egypt.

Looking at any occupation from road sweeper to management accountant, the jobs are all delivered by Iranians, something that most of the Gulf countries have yet to fully embrace. n

Contact: Terry Willis, Director, Middle East Africa & CIS Tel: + 9 714 602 6001 Email: terry.willis@the-eic.com

23

EIC Global

ADIPEC 2016: transitional strategies for an efficient and resilient energy industry The EIC will once again host the UK pavilion where 55 companies will showcase the very best in technical innovation and expertise that the UK oil and gas industry has to offer

“Shaping the future of the oil and gas industry and being part of the dialogue to resolve the issues facing the industry is one of the reasons why ADIPEC has gone from strength to strength”

F

ollowing on from the record breaking 2015 edition which received 94,661 visitors, ADIPEC 2016 is set to surpass last year’s attendance with approximately 100,000 people expected to take part in the oil and gas industry’s premiere conference and exhibition.

Taking place in the global hydrocarbon hub of Abu Dhabi from 7–10 November, this year’s theme Transitional Strategies for an Efficient and Resilient Energy Industry is particularly pertinent as the industry searches for ways to maintain productivity and boost profitability during this time of low crude prices.

Over 100,000 people are expected to take part in ADIPEC 2016

The new energy landscape ADIPEC 2016 will offer a huge range of plenary speeches and conference sessions that address the challenges facing the oil and gas sector.

The various panel sessions taking place during the four days include topics such as operational excellence and efficiency, using research and technology as a transitional strategy to enable companies to thrive during this down market, as well as the global business leaders’ sessions which will include CEOs and executive level speakers from Total, Statoil and Schlumberger discussing effective leadership strategies for the new energy landscape.

The 2016 technical conference has received a record number of submissions. ADIPEC now hosts one of the world’s largest oil and gas technical conference programme. With a remarkable 2,700 technical submissions, ADIPEC 2016 is the ideal platform for engineers to learn about the latest technical exploration and production (E&P) solutions.

Facilitating global business Shaping the future of the oil and gas industry and being part of the dialogue to resolve the issues facing the industry is only one of the reasons why ADIPEC has gone from strength to strength.

Attracting as it does key industry players from around the world in unprecedented numbers, ADIPEC generates new business on a scale almost unseen in the rest of the world.

The 2015 edition facilitated an estimated US$9.76bn of business on-site alone.

With ADIPEC attracting delegates from over 120 countries and all sectors of the oil and gas industry it offers an unparalleled opportunity for attendees to build their networks, develop new business partnerships and explore the opportunities offered by the various business lines and sectors represented at the event.

24

www.the-eic.com

EIC Global

The EIC-managed UK pavilion includes 55 exhibiting companies

The UK: leading the way in innovation

EIC UK pavilion exhibitors, Hall 8

With over 80 years’ experience of supplying goods and services to the global oil and gas sector and more than 40 years’ experience in the North Sea, one of the world’s most demanding offshore environments, the UK oil and gas industry is a world leader in innovation and technological development, putting it in a great position to meet the challenges of the current market.

• ABTECH, a supplier of hazardous area enclosures and equipment to the oil, gas and petrochemical industries • Advanced Sensors, produce industrial instrumentation and sensors, oil in water monitors, leak detection systems, etc • Amec Foster Wheeler, one of the world’s leading EPCs providing services to the global oil and gas industry as well as mining and metals, clean energy, and environment and infrastructure.

• Andrews Kurth, an international law firm which is a specialist in oil and gas industry issues • Angus Fire, specialists in the design, supply and manufacture of all types of fire-fighting equipment and protection systems for the oil, gas and petrochemical industries, both onshore and offshore • Begg Cousland Envirotec, designs and supplies equipment and package solutions for gas/ liquid filtration, liquid/liquid separation, 3-phase separation, CPI systems and nut shell filters

From the need to produce from more remote and geologically complex fields through to the necessity to make smaller, brown field sites economically viable and increase returns from larger fields, the North Sea is a microcosm of many of the issues facing the offshore industry today.

Such challenges require the latest in offshore technologies and an increased focus on innovation. The UK industry is now a recognised world leader in the areas of subsea engineering, reservoir monitoring and pipeline technologies to name just a few.

To find out more about the expertise and highly innovative solutions and services that UK companies offer the global oil and gas industry visit the UK pavilion in Hall 8. n

• Bermad UK Ltd, provides comprehensive customised solutions for fire protection systems in petrochemical plants, offshore and onshore sites, refineries, power stations, tunnels and public buildings • Bibby Transmissions, is a leading innovator of high performance flexible couplings and engineering solutions for rotating equipment with over 80 years’ experience • BS & B Safety Systems (UK), manufacturer of rupture discs and pressure relief equipment for the hydrocarbons industry • Cargostore International, suppliers of cargo carrying units for rental and purchase on a worldwide basis • CCG Cable Terminations, specialised manufacturer of cable glands and junction for industrial and hazardous areas • Churchill Drilling Tools Ltd, a specialist oilfield service company which delivers innovative solutions to the industry • CMP Products, designer and manufacturer of cable glands and cable connectors for the oil, gas, petrochemical and power industries

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EIC Global • Completion Products Limited, a world leader in the design and manufacture of downhole cable and control line protection systems • Corrotherm International Limited, a leading supplier of nickel alloys in the form of pipes, fitting, flanges, plates, bars and welding consumables • Crowcon Detection Instruments, manufacturer of gas detection instruments for oxygen, flammable and toxic gas hazards • Cutting & Wear Resistant Developments, supplier of downhole tool technology to drilling equipment manufacturers • Derrick Services (UK), a partner for offshore construction, inspection and engineering • Drilling Systems (UK) Ltd, delivers training simulators in over 40 countries for oilfield training technology • Dunlop Oil & Marine Ltd, a leading supplier of a comprehensive range of fluid transfer solutions for the global oil and gas industry • Edif Group, provides a range of inspection, testing and consultancy services to industrial markets worldwide • Elfab Ltd, manufactures and supplies a wide range of safety critical pressure relief products including: rupture discs, explosion vents and buckling pin relief valves • Enhydra, provider of specialist engineering services for produced water treatment and water injection systems • European Safety Systems (E2S), manufacturer of warning signals, alarm sounders, intelligent voice annunciators and beacons for industrial, marine and hazardous areas • EXHEAT, provider of electric process heating and control systems for hazardous area locations • FFE Ltd, offers a wide range of industry leading beam and flame detectors • Garlock Pipeline Technologies, a pipeline supply company that provides an overall package to the oil, gas and water industries • Globus (Shetland), provider of hand protection solutions from the Showa, Best and Skytec safety glove ranges • Goodwin International, a leading manufacturer of valves • High Voltage Partial Discharge (HVPD), experts in the on-line partial discharge condition monitoring of in-service, medium voltage and high voltage networks • Hughes Safety Showers, provider of emergency safety showers, decontamination equipment and emergency response shelters • Imtex Controls Limited, an independent producer of high integrity pneumatic and hydraulic valve/damper actuation equipment and ancillary control systems • Innospec, a global specialty chemicals company focused on bringing innovative new technologies to market • James Fisher Offshore limited, a leading service provider in all sectors of the marine

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The 2015 edition of ADIPEC facilitated an estimated US$9.76bn of business on-site alone

“With more than 40 years’ experience in the North Sea, one of the world’s most demanding offshore environments, the UK oil and gas industry is a world leader in innovation and technological development”

•

• •

•

•

•

•

•

industry, and a specialist supplier of engineering services to the UK and overseas KBC Process Technology, a leading, independent oil and gas consulting and technology company Knowsley SK, designs and manufactures fire-fighting systems and equipment Land and Marine Engineering, constructs marine pipelines, landfalls and crossings, intakes and outfalls, and also provides horizontal directional drilling and engineering services Lumenox, a specialist manufacturer of portable and fixed luminaires for the oil and gas, petrochemical, marine and heavy industrial markets Mech-Tool Engineering Ltd (MTE), a global supplier of solutions protecting people and equipment from fire, blast and radiant heat hazards Mitutoyo, a leading manufacturer of precision measuring equipment offering a huge range of products Mott MacDonald, provider of engineering consultancy services for oil, gas and power projects internationally NDSL Ltd, a provider of technology and service solutions for mission critical standby power systems

• Norbar Torque Tools, supplier of torque tightening tools and measuring equipment • Orga, a provider of navigation aids and helideck equipment • Penspen, an independent group of companies delivering engineering and management services to the onshore and offshore oil and gas industry • Pharos Marine, developer of high quality engineered marine navigational aids, complete with support services, for the oil and gas and marine industries • Portwest, supplier of workwear and safety equipment for specialist industries • Raytec, manufacturers of LED lighting for CCTV and safety critical applications • Safehouse Habitats (Scotland) Ltd, supplies a range of products and services to protect people working in hazardous environments • Severn Glocon, provides high-integrity products and services for onshore, offshore, subsea and LNG operators around the world • The Monobuoy Company, designs, builds and installs CALM Buoys, FSOs and FPSOs • Total Waste Management Alliance (TWMA), a leading provider of integrated drilling and environmental solutions • Walter Frank, a manufacturer of non-ferrous water transfer and fire protection fittings • Welsh Government, representing Welsh companies providing goods and services to the oil and gas sector • Wolf Safety Lamp Company Limited, a world leading manufacturer of hazardous area portable and temporary lighting

Contact: Mark Gamble Senior Overseas Events Manager Tel: +44 (0) 207 091 8600 Email: mark.gamble@the-eic.com

www.the-eic.com

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EIC Global

Gulf national oil companies set to define future of world energy

by Edmund O’Sullivan, Chairman, EIC Connect Middle East 2016

The slump in oil prices is the key challenge facing the Gulf Cooperation Council (GCC), but how the region’s national oil companies are changing is what matters most orld oil prices have risen by 80% since January 2016 and were about US$50 a barrel at the start of July. The price recovery is a landmark for the market and represents the biggest oil price rise in history.

That is, after falling by more than US$70 a barrel in the previous 18 months (Figure 1).

Figure 1. Oil price: July 2014 – July 2016 Crude Oil Brent (ICE)

US$ / bbl 120.00 110.00 100.00

While these are extraordinary times for world energy, the demand for global oil continues to grow (Figure 2). It rose by 1.5% annually in the 25 years ending December 2016 and it is forecast to grow by that much this year and by at least 1% thereafter.

90.00 80.00 70.00 60.00

Global energy outlook The Energy Information Administration’s (EIA’s) revised long-term forecast (International Energy Outlook 2016) released in May shows that oil will still be America’s largest single energy source in 2040, accounting for 33% of total demand in that year. Coal, gas and renewables are growing, but oil and petroleum liquids will still dominate American energy in 25 years. BP forecasts it will remain number one globally in 2035, though its share will fall to 28% from 32% now.

And the Gulf region will continue to be the world’s single largest source of petroleum.

According to BP, the six Gulf states that are members of OPEC have almost half the world’s oil reserves and 40% of its gas.

This is supporting steadily expanding Gulf output. The six states produced more than 24m barrels per day (MMbbl/d) of crude oil in May 2016 (Figure 3). That is 1MMbbl/d more than in the same period last year and 25% of the world total.

Iran’s oil exports are set to increase to 2.2MMbbl/d by the end of summer 2016, roughly double last year’s figure, as the country capitalises on the relaxation of nuclear-related sanctions in January. This will push capacity back up to 4MMbbl/d.

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52.52 40.00 30.00 20.00 2015

0

2016

Source: NASDAQ, 4 July 2016

Figure 2. World oil demand 2008 – 2016 MMbbl/d 96.00 94.00 92.00 90.00 88.00 86.00 84.00 82.00 80.00

2008

2009

2010

2011

2012

2013

2014

2015

2016F

Source: OPEC, May 2016

www.the-eic.com

EIC Global

ADNOC is streamlining its procurement process between its three main operating arms: Adco, Adma-Opco and Zadco (photo: ADNOC)

Meanwhile supplies from non-OPEC countries, in contrast, are forecast to contract by 750,000 barrels per day (bbl/d). This is due in a large part to a decline in US output, which fell this year for the first time since 2005. The industry has responded to the sharp decline in oil prices over the last two years by cutting investment severely and shedding rigs. In May this year, analysts at Morgan Stanley said that oil discoveries in 2015 were at their lowest level globally since 1952, amid reports that the number of operational oil rigs in the US had fallen to its lowest-ever level.

On a more positive note, the oil price is forecast to hold the gains from January during the rest of 2016 despite record global oil stocks. Recently, the EIA revised up its 2016 Brent blend crude price forecast by US$3 to just over US$40 a barrel and to US$50 for 2017. While this is still below the level needed by producers in the North Sea and other high-cost oil regions, the trend provides for cautious optimism and is helping underpin confidence that US$70 a barrel is possible before the end of the decade.

Figure 3. Gulf OPEC six: crude oil production May 2015 – May 2016 MMbbl/d

“Saudi Aramco is entering a period of unprecedented corporate change”

Saudi Arabia’s significant influence Saudi Arabia sees rising prices as vindicating the decision to stick to its market-share defence strategy and reject calls for an OPEC production freeze. The kingdom was lambasted by some OPEC members when oil fell below US$30 a barrel at the start of the year, and there were forecasts it faced unsustainable financial pressures.

24.8

The storm about Saudi Arabia’s oil policy climaxed at a meeting between OPEC and nonOPEC nations in Doha on 24 April 2016, which closed without agreement. The kingdom said it would not freeze output unless other OPEC countries including Iran did as well. Tehran had already said that this was out of the question.

24.4 24.0 23.6 23.2 22.8

Source: OPEC, May 2016

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Saudi Arabia, meanwhile, says it is prepared to increase output to meet growing world demand. The kingdom’s maximum sustainable production capacity is 12MMbbl/d and it can temporarily lift output to 12.5MMbbl/d, Saudi Aramco’s CEO, Amin Nasser, told the Wall Street Journal in May 2016.

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EIC Global Developments since January mean Saudi Arabia will produce more oil this year than last and enjoy export earnings higher than forecasts suggested. Claims that Saudi Arabia was heading towards bankruptcy have been shrugged off by the international banking community, which offered the Saudi government more than US$10bn in loans in April despite forecasts its budget deficit would soar to 10% of GDP this year.

Rating agencies have cut the kingdom’s credit rating, but it remains at a healthily investment grade. Riyadh has at least US$600bn in reserves and almost no debt.

Confidence that Saudi Arabia has the resources to deal with lower oil prices has been underpinned by its new economic strategy defined in the government’s Vision 2030 programme unveiled in April. It calls for the Saudi economy to reduce its dependence upon oil production, which accounts for more than one-third of GDP, the bulk of its export earnings and almost all government income.

How this is to be done is, as yet, unclear, although the kingdom has already slashed fuel, water and electricity subsidies to reduce the budget deficit and cut consumption and waste. Privatisation and publicprivate partnerships are on the agenda.

But nothing is as ambitious as the plans announced in January to sell a stake in Saudi Aramco, the kingdom’s national oil company originally created by US oil firms in the 1930s.

It may now be the world’s most valuable corporation. The kingdom is the largest oil exporter in world, second only to Iran among the Middle East’s gas producers and owner of a multibillion dollar network of refineries, storage and distribution assets and tankers.

The kingdom needs money to cover its domestic and external deficits. The Saudi Aramco share sale has other objectives including the desire to give Saudi citizens a direct stake in the corporation and exposing its managers to the improving influence of the market. But, perhaps, most important is countering charges made that Saudi Aramco is no more than an extension of the Saudi government. Listing will support the kingdom’s claim that it is just like any other big oil corporation.

This might involve separate listings of Saudi Aramco subsidiaries or a floatation of a small minority stake in the mother corporation. Studies into how it is to be done should be complete this summer and the offering is planned for 2017.

What is definite is that Saudi Aramco is entering a period of unprecedented corporate change. Nasser, a career Aramco executive, was made CEO last September.

30

His predecessor Khalid al-Falih had been appointed Aramco chairman and joined the cabinet as Health Minister in April. In May this year, he replaced Ali al-Naimi, 81, as minister of the expanded Ministry of Energy, Industry and Mineral Resources.

All the kingdom’s power is produced using oil and gas supplied by Saudi Aramco. By expanding the remit of the ministry that AlFalih now leads, Saudi Arabia is signallling its intention to achieve closer integration across the kingdom’s energy supply chain from spigot to final consumer. This will facilitate energy saving and efficiency measures.

Al-Falih’s industrial portfolio includes the government’s majority stake in Saudi Arabian Basic Industries Corporation (SABIC), the world’s largest producer of bulk petrochemicals.

While the minerals sector has been designated as the third pillar of the future Saudi economy after hydrocarbons and petrochemicals.

Having recently agreed to conduct a joint feasibility study on a proposed oil-tochemicals project with SABIC, Saudi Aramco’s commitment to promoting the non-oil sectors that Vision 2030 requires is unequivocal.

Changing dynamics The new Saudi Aramco model is inspiring change at the Abu Dhabi National Oil Company (ADNOC), where a new CEO was appointed in February 2016. Producing around 3MMbbl/d at present and aiming to lift sustainable capacity to 3.5MMbbl/d, ADNOC is the sleeping giant of Gulf national companies. Its new chief Sultan al-Jaber has announced sweeping senior management changes and is expected to reduce the number of ADNOC subsidiaries to six from 18 through mergers and rationalisation. It is cutting its payroll by 10%, with most of the jobs being cut held by foreigners.

The third Gulf national oil company (NOC) experiencing great change is Qatar Petroleum, which owns and operates oil, gas, petrochemical and industrial assets in Qatar. These include stakes in Qatar’s liquefied national gas (LNG) industry which produces around 80m tonnes a year. Saad al-Kaabi was appointed chief executive at the end of 2014 and a rationalisation programme is being implemented. Qatar is the only Gulf OPEC country forecast to produce less oil in 2020 than it does now.

Further development of its offshore North Field non-associated gas field is on hold.

The Kuwait Petroleum Corporation announced that it may invest US$115bn on oil projects during the next five years. More than US$100bn will be spent on local projects and the rest overseas. Two-thirds will be on exploration and production. Kuwait plans to

“Iran’s return to global oil markets since January is possibly the most important development of 2016”

lift crude production capacity to 4MMbbl/d by 2020 from just over 3MMbbl/d now. This will include building four new gathering centres to increase heavy oil production and raise gas output capacity to 2bn cubic feet per day from 150m cubic feet per day.

In Iraq, oil output is now above 4.5MMbbl/d, a record level. But plans to increase capacity to 10MMbbl/d by the end of the decade have been replaced by a more realistic investment target that also involves increasing gas production. Iraqi production has risen despite political violence across the country and the seizure by the Islamic State of Mosul, Iraq’s second largest city, and some of its oil production facilities in June 2014. Iraqi Kurdistan produced almost 600,000bbl/d of oil on average in 2015.

Capitalising on Iraq’s enormous oil reserves, estimated to be the world’s fourth largest, has been complicated by the oil price slump. The Iraqi government’s finances are parlous and the IMF stepped in with financial support this year.

Iran’s return to global oil markets since January is possibly the most important development of all in 2016. The National Iranian Oil Company has lifted exports by almost 1MMbbl/d since then. Iran has almost 20% of the world’s proven gas reserves, a population of 80 million people and the Middle East’s second largest economy. Restoring oil output to levels before nuclear-related sanctions were imposed will clear the way for Iran to be the world’s fastest-growing economy and a potent force in global energy.

Class of their own Other Middle East nations are significant oil industry players, but the Gulf six are in a class of their own. Their market share is growing and this will increase their influence over the direction of global energy as a whole.

As delegates attending EIC Connect Middle East 2016 were told, anyone serious about the industry should be doing business with the Gulf OPEC six. But it is the Gulf NOCs that matter most. They will emerge stronger from the radical changes sweeping world oil and are set to replace international oil companies as the dominant force in the global industry to 2050 and beyond. n

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EIC Global

Low oil: a challenging period for the Middle East super powers

by Terry Willis, EIC Director – Middle East, Africa and CIS

As the austerity period of low oil continues there is an interesting contrast between how the two largest economic ‘super powers’ in the region, Iran and Saudi Arabia, are tackling the economic challenges that they each face domestically during this period of oil price instability Iran Let us first take a look at Iran. After enduring an eight-year long war with Iraq this was then followed by a difficult period of sanctions imposed due to its known nuclear ambitions. Sitting on a considerable proportion of the world’s oil and gas reserves and not having the tools to develop those assets must have been truly frustrating.

Since the lifting of economic sanctions Iran has been working hard to attract foreign investment in the country (photo: Flickr/Chris Blackhead)

Nevertheless, the economy survived and now, given the partial lifting of sanctions back in January, the time has come for Iran to take advantage of an international investment appetite that has been supressed during the current global depression, especially across the energy sector.

In preparation for Implementation Day, 16 January – the day the majority of the sanctions were lifted – the Iranian government diligently produced proposals to entice overseas investment from the international oil community and by using a number of ‘taster sessions’ they received what was considered by most observers as a favourable response.

However, not all parties within the Iranian government agreed to some of the terms being offered within the contracts, titled Iran petroleum contracts (IPCs). Presanctions, agreements with international oil companies (IOCs) followed a buy-back model where the contractor is paid back by being allocated a portion of the hydrocarbons produced as a result of its services.

The payback period was relatively short after which time the developed field would be handed back to the Iranians. However, the IPC model allows for a joint venture to be established between the government and the IOC where risks are more equally shared than with the buy-back model, where all the risks were firmly planted at the door of the IOC.

“The Iran petroleum contract model allows for a joint venture to be established between the government and IOCs where risks are more equally shared”

This new model is very attractive to foreign investors not least because risks are shared and the return on investment is transparent and quantifiable. IPCs are being offered across a range of both oil and gas assets and will no doubt become a bedrock of economic growth in the future.

Self-sufficiency, well taught through the sanctions years, will also prove to be an important element in Iran’s economic growth. With traditional markets across the region being somewhat depressed, Iran can provide a beacon of light for the UK supply chain, although investing in a revitalised Iran still poses some significant challenges.

The necessary banking and financial infrastructure has still to be fully established.

Having been stung by regulators during the sanctions era, the majority of the international banking community remains nervous of dealing with Iranian financial instruments and while most trading sanctions have been lifted, there are still some US related sanctions that remain in place which mean banks are still cautious about engaging with this market. This issue needs to be rectified without delay if Iran is to meet the economic expansion targets it has set itself.

33

EIC Global

Both Saudi Arabia and Iran are increasing their downstream activity (photo: Wikimedia/Secl)

“In Saudi Arabia there is a relatively high proportion of foreign labour engaged across many parts of the economy” Another element of risk is ‘snap back’. In the unlikely event that Iran reverts to its previous nuclear ambitions, the sanctions can be immediately re-applied. This also leaves investors with a degree of nervousness but overall, Iran will continue to be the main new frontier for members of the UK supply chain, who, looking to expand their businesses, will in turn fuel the economic growth that Iran desires.

Saudi Arabia Across the Gulf, Saudi Arabia also faces its own set of internal challenges. The kingdom’s population is less than half that of Iran’s, and its demographics are altogether very different. In Iran, the local population remains fully employed across all sectors, whereas in Saudi Arabia, there is still a relatively high proportion of foreign labour engaged across many parts of the economy.

Saudis aged below 30 make up a high proportion of the population. Almost all of them are well educated and seeking meaningful employment, however, there is a real gap between what this talented generation aspires to in their professional lives and what is currently available in the country.

34

This is a conundrum that the government has wrestled with for quite some time with perhaps only a modicum of success so far.

The current low oil price is not helping matters and economists can see that a considerable amount of wealth is being eroded in order to maintain the country’s economic equilibrium.

It is these factors that have perhaps prompted the headline grabbing announcement made recently by Deputy Crown Prince Mohammed bin Salman that the kingdom’s economy would be self-sufficient without the need for oil revenues by 2030.

The plan, entitled Vision 2030, aims to cut government salaries from the current 45% of the total budget down to 40%. This is in itself highly ambitious given that two-thirds of total Saudi employment is within the government sector. Another notably part of the vision is its plan to sell a 5% stake of state-owned oil giant Saudi Aramco.

For the Saudis to come up with such radical plans would suggest that despite maintaining their production levels at almost 10m barrels of oil per day, the drastically reduced revenues as a result of the oil price drop has had a serious effect on their economic plans set out in their last five-year plan, originally announced back in 2014.

This has now been superseded by the National Transformation Plan, which forms a key part of Vision 2030’s plan to prepare the kingdom for a post-oil era, and has been

ratified by the Saudi Council of Economic and Development Affairs or CEDA which is a new super committee of top ministers charged with implementing all the various reforms that have been announced.

The wider reforms of the plan are expected to include subsidy cuts, tax rises, the sale of state assets, a government efficiency drive and efforts to spur private sector investment.

While the International Monetary Fund said that these plans were ‘appropriately bold and far reaching with an aim to reduce the country’s economic deficit to zero by 2020’, a number of financial experts around the world have expressed doubts that these measures will come to pass, noting similar plans have been announced before.

Investing in energy Despite the wide and diverse nature of the two nations’ economic drivers, and an unprecedented amount of change taking place in both countries there can be no doubt that the two main regional power houses will continue to inject a significant amount of investment into their respective energy infrastructures for many years to come.

While oil and gas will continue to be the bedrock of their economies for the near future as they both continue to increase their downstream investments to maximise their hydrocarbon value chains, they are also aiming to diversify into other energy sectors and markets, all of which is welcome news indeed for the UK supply chain. n

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EIC Global

The Miraah plant’s concentrated solar power technology will harness the sun’s energy to produce steam, which will then be used in thermal EOR for extracting heavy oil at PDO’s Amal field, South Oman

Breaking new ground in enhanced oil recovery technologies

by David Brown, Senior Editor, Petroleum Development Oman (PDO)

A pioneer in enhanced oil recovery, PDO continues to push the boundaries of EOR technology innovation with more groundbreaking projects in the pipeline

P

etroleum Development Oman (PDO) is a world leader in the application of enhanced oil recovery (EOR) processes and technologies and, despite the current challenging low oil price environment, EOR remains a central pillar of the company’s production portfolio.

The different mechanisms – thermal, chemical, miscible gas – enable the extraction of crude across Oman’s spread of mature assets and complex oil and gas reservoirs, which are located in some of the world’s oldest, hardest rocks.

Delivering long-term value While the Sultanate benefits from substantial hydrocarbon deposits, Oman’s challenging subsurface geology and oil properties limit the effectiveness of conventional production techniques.

36

As a result, PDO has had to push the boundaries of innovation and efficiency as it strives to deliver on its core business of oil production in an environmentally sustainable and cost-effective way – especially during the prevailing austerity in the sector.

‘Because of the resource-intensive nature and higher cost of tertiary recovery mechanisms, much emphasis has been placed on accelerating conventional oil and gas opportunities instead of additional short-term expansion of EOR projects,’ says PDO’s Managing Director, Raoul Restucci. ‘However, EOR is an indispensable tool if we are to secure improved ultimate recovery and deliver long-term value for Oman and all our stakeholders.’

EOR is expected to account for about 25% of PDO’s oil production by 2025, and while

“EOR is expected to account for about 25% of PDO’s oil production by 2025”

this is down on last year’s projection of 33% by 2023, the company is currently operating 10 EOR projects and trials, with many more under construction or design stage.

Restucci says, ‘For PDO’s fields, the recoverable fraction of oil using improved oil recovery technologies, such as primary and secondary depletion (with conventional water and gas injection), adds up to about 25%.

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EIC Global ‘This is simply too low and we have been making a big effort to increase this fraction substantially through the application of EOR technologies. Indeed, our EOR team has the aspiration of doubling PDO’s overall recoverable oil volume fraction to above 50%.’

Staircase methodology reduces risk Every one of the company’s 200-plus fields has been screened for its EOR potential, and several groundbreaking EOR projects are under way.

PDO has developed a process of climbing what it calls the ‘EOR staircases’, a methodology specially developed to take some of the operational risk out of EOR implementations.

The staircase approach ensures that the company has specific roadmaps for maturing its tertiary techniques which have been devised for each of the main EOR mechanisms currently being deployed.

The company’s EOR journey started in the 1980s with a polymer flooding project in Marmul field in southern Oman and a steam injection trial aimed at extracting heavy and viscous oil.

While results were encouraging, due to the lower oil price environment at the time, PDO decided not to proceed to the full field development phase. However, the processes and lessons were captured and, with a more conducive environment in place and a greater focus on arresting declining production, the company reverted to EOR in 2005–06.

Advancing chemical injection Following further sector tests, the first full fieldscale EOR development within PDO – Marmul polymer – was launched in early 2010. Phase 1, where polymer was injected into 27 wells, increased oil production by 50%. The project paid back within 18 months, delivering more than 10.3m barrels (MMbbl) of oil. The second phase started last year with the addition of 19 injectors and phase 3 is currently at the front end engineering design stage. With water injection the recovery factor was 28% but the implementation of polymer injection is expected to increase it to above 35%.

With this first staircase rung successfully scaled, PDO now intends to expand the Marmul flooding operation in a move that will see daily polymer injection increased from approximately 100,000 barrels (bbl) to approximately 500,000bbl, thus creating one of the largest projects of its kind anywhere in the world.

Marmul is also the field where PDO is trialling the alkaline-surfactant-polymer (ASP) recovery process. This works in tandem with the established polymer injection process: the alkaline-surfactant mixture helps to release residual oil left within the rock, which is then swept from the reservoir using a polymer flood.

PDO is targeting a further 250MMbbl of oil to be delivered by the US$1bn-plus Rabab-Harweel miscible gas project in southern Oman, now under development

And as a further step on the staircase, PDO has also successfully launched a highly viscous polymer flood trial at its Nimr field.

Nimr’s oil is of an order of magnitude heavier than Marmul’s so trialling there first would have been extremely challenging. But, with the lessons from Marmul to call upon, PDO is confident of success, demonstrating the power of the staircase approach.

The success at Marmul has been followed by other field developments, including steam injection in Qarn Alam and Amal fields, and miscible gas injection at Harweel.

Innovative thermal recovery As every field has its own characteristics, ‘we rigorously assess which method is most appropriate taking into account factors such as the porosity of rocks, oil viscosity and the depth, temperature and pressure of a reservoir,’ says PDO’s Field Development Manager, Junaid Mohiuddin Ghulam.

‘Thermal dominates our EOR portfolio at present and this is reliant on the burning of natural gas to produce steam which is then injected into the reservoir to heat heavy oil and reduce its viscosity.’

The mirrors used are a small fraction of the weight of exposed solar thermal systems, resulting in significant material and cost savings.

Importantly, the glasshouse is efficiently cleaned as and when required, ensuring minimal spacing between mirrors and high operating uptimes.

Moreover, the 1,021MW installation will save 5.6 tonnes of British thermal units of natural gas each year, enough to provide residential electricity for more than 209,000 Omanis, and cut CO2 emissions by over 300,000 tonnes annually, the equivalent of taking 63,000 cars off the road. The project won the ADIPEC 2015 Award for Best Oil and Gas Innovation or Technology (Surface).

Another example where PDO has led the way is at Qarn Alam, a reservoir featuring both heavy oil and fractured rock – in the past a nightmare scenario for producers armed only with conventional techniques.

PDO’s solution has been to inject steam into the reservoir, heating up the oil so it becomes less viscous. The oil and water mixture then drains downwards into producing wells located at the base of the reservoir. It is the first time this thermally assisted gas-oil gravity drainage (TAGOGD) process has been used in fractured carbonate rock anywhere in the world.

However, he says, ‘This proposition is unsustainable, bearing in mind the value of the gas consumed, especially at a time of rising domestic demand and the regional shortfall. This means we will not only have to discover a new alternative to gas but also build on other EOR mechanisms.’

The technique requires 18,000 tonnes of steam every day, the production of which consumes around 60,000 cubic metres of clean water as well as a huge amount of heat. However, PDO has addressed the challenge by extracting water from deep-lying salt water aquifers while the heat is a recycled waste product from the electricity generation process at Qarn Alam’s power station – created from resource-efficient cogeneration.

One innovation that could provide a longterm solution is PDO’s Miraah facility, one of the largest solar energy plants in the world, which it is developing with partner GlassPoint Solar, at Amal West. The plan is to build 36 greenhouse modules housing pioneering enclosed trough technology which will produce steam using the sun’s rays.

There is no requirement for Qarn Alam steam – either in its vaporous form or when it is condensed back into water – to actually drive the oil into producing wells as it does in the conventional steam flood process.

Instead, says Field Development Centre EOR Studies Portfolio Leader, Nasser Al Azri, ‘The gravity drainage element makes a virtue

37

EIC Global of the fractures in the rock, through which the now freer-flowing oil drains down into horizontally drilled producer wells that are situated towards the bottom of the reservoir.

‘We are currently producing just under 20,000bbl of oil per day with a further rampup expected. The field was discovered in the 1970s and we hardly managed 5% using conventional methods. However, we expect thermal EOR to boost recovery to 30% of the estimated oil in place in the coming years.’

PDO is now using the knowledge gained from Qarn Alam to fast track the development of a similar project at its Habur field.

More conventional steam flooding is also becoming an increasingly important weapon in PDO’s EOR armoury. The company’s first phase project in Amal has been running for more than two years, with good results. The knowledge gained in Amal will feature very heavily in PDO’s maturation plan for steam flooding; not least the second and third phases of its implementation within the Amal field itself.

Pioneering miscible gas techniques For the third EOR staircase – miscible gas – the focus of attention has been on the Harweel cluster of fields in the south of Oman. Here, PDO has initiated what is probably its most ambitious EOR project to date, injecting miscible gas at ultra-high pressures into the Zalzala field, which is designated ‘sour’ because of its significant volumes of deadly hydrogen sulphide gas.

From an engineering perspective, PDO has had to break new ground in terms of materials and technologies used, including in the manufacture of a giant compressor which generates the 500 bar (about 500 times our atmosphere) pressure required to induce miscibility.

The company is also pioneering the use of flowline pipes with outer walls that are 40cm thick so they can cope with the extreme pressures and highly corrosive fluids involved.

Such ingenuity led to another PDO award at last year’s ADIPEC, with the Harweel 2AB scooping the Best Oil and Gas Mega Project scheme.

‘Generating sufficient pressure is one of the biggest and most costly challenges faced when deploying the technique,’ says Al Azri. ‘There are significant levels of hydrodgen sulphide.

As a result, the surface facilities must be built to the highest possible levels of integrity, as well as feature multiple safety mechanisms, to minimise the risk of leaks that would harm the workforce and neighbouring environment.

The implementation of such measures necessitates a complex balance between achieving HSE goals and meeting cost targets.’

The next step on this particular staircase is the US$1bn-plus Rabab-Harweel miscible gas project, now under development. This is

38

PDO’s polymer flooding project in its Marmul field has delivered in excess of 10.3MMbbl of oil since it was launched in 2010. The phase 3 development will make it the largest project of its kind in the world

one-and-a-half times bigger than the existing Harweel scheme, and will see miscible gas injected into each of the seven Harweel oil reservoirs. It will also involve recycling sour gas in the neighbouring Rabab field to develop condensate. Production from the Rabab Harweel EOR project is expected to begin in 2019, with a target of 250MMbbl of additional production.

Driving EOR excellence Sometimes it is necessary to move beyond the boundaries of conventional EOR wisdom, such as the ultra-heavy oil field at Habab where PDO has been trialling a chemical solvent never used before in the industry as a potential method of increasing yields from complex heavy oil and tight reservoirs. Later this year, PDO will also be testing super-heated steam applications.

Such ambitious and complex ventures mean PDO faces both staff and supply chain challenges, given their technical, capital and labour intensity – and the opportunity of developing Oman into a global hub for EOR excellence.

‘We must also ensure that the benefits of our EOR strategy are spread across Oman through the supply chain,’ says Restucci. ‘That means ensuring that key technologies, services, materials and components required for EOR are ‘Omanised’ as much as possible, while ensuring quality and cost competitiveness.

‘At the same time, it is about getting the basics right – safety is our overarching priority – developing new ways of working centred around risk sharing and partnerships, innovation/ technology as a ‘sine qua non’ [essential], and step-changing the use of data, while concurrently minimising energy intensity.’

He says, ‘We are also driving Lean continuous improvement practices across all our operations and key processes to eradicate duplication and avoid waste and ensure that our production, including EOR, is done as efficiently as possible.’

“Every one of the company’s 200plus fields has been screened for its EOR potential, and several groundbreaking EOR projects are under way”

Collaboration is key, says Ghulam, ‘PDO talks constantly to potential partners who can help it to execute its EOR strategy safely, reliably, efficiently and sustainably. Research and development for each of our EOR technologies are steered and pursued through its partnership with Shell, universities, joint industry ventures and strategic alliances with relevant parties.

‘The technical know-how offered by external companies is valuable in helping us to progress, so that we can identify those technologies, techniques, materials and asset integrity processes which are best suited to our operations.’

Looking ahead, Restucci says, ‘We place a premium on EOR solutions which underpin the robustness of our long-term surface and subsurface development and infrastructure plans.

However, extracting residual oil is a complex, expensive and sometimes hazardous process.

‘So striking a balance between the commerciality of our projects and the potential risks is imperative. The focus remains on sustainable value creation.

‘It is only by adopting a Goal Zero approach to safety, and methodical data gathering, analysis and testing that we can decide on the best technology to be deployed in each case and reduce those risks.’ n

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EIC Global

EIC Connect Middle East 2016: supporting UK companies to do business in the Middle East This year’s EIC Connect Middle East event in May benefitted from the participation of major energy companies including Abu Dhabi National Oil Company (ADNOC), Emirates Nuclear Energy Corporation (ENEC), Shell and BP

W

hile usually a biannual event, in response to the overwhelmingly positive feedback which EIC Connect Middle East 2015 received we decided to return to Abu Dhabi a year earlier than usual.

Reflecting the increasingly diverse energy mix in the region, ENEC gave an update on the Barakah project, the Emirates’ first nuclear power station, and provided information on how UK companies can support this project to provide clean, safe and reliable energy to the country.

The decision to do so proved to be the right one as the event received over 400 delegates, an impressive figure at any time, but especially considering the current economic climate.

EIC Connect Middle East is designed to help UK companies expand into the Middle East energy sector and enhance bilateral trade between the region and the UK through a day of conferences, vendor briefings, energy project updates, exhibitions and one–to-one meetings between major regional operators and UK energy companies.

One of the key features of the event was its one-to-one sessions which brought together representatives from the major energy companies in the region, such as ADNOC and many of its subsidiaries, ENEC, Amec Foster Wheeler, Petrofac, McDermott and Fluor with potential new UK partners, providing these with advice on registration processes and their specific project requirements. These sessions also allowed UK companies to present their services and products directly to the companies’ key decision makers.

Despite global market conditions, the Middle East remains resilient and has a positive investor climate. Throughout the Gulf region developers enjoy the world’s lowest production costs, meaning projects in much of the Middle East remain highly profitable.

A strong market combined with an unprecedented level of leadership changes across the national oil companies and Saudi Aramco’s plans to float on the stock exchange means the Middle East remains of great interest to the whole of the energy industry, so the large turnout at our event was perhaps unsurprising.

The delegates who made the trip to Abu Dhabi were richly rewarded by the high calibre of the companies and presenters supporting this event.

We were delighted to have the new CEO of GASCO, Dr Saif Al Nasseri, as the event’s keynote speaker. Dr Al Nasseri had only been in his new post for two days prior to the event, following a complete restructuring of ADNOC.

GASCO CEO Dr Saif Al Nasseri was the keynote speaker at EIC Connect Middle East 2016

“EIC Connect Middle East is designed to help UK companies expand into the Middle East energy sector and enhance bilateral trade between the region and the UK”

Two conference sessions took place during the day, with speakers coming from ENEC, Shell, BP, Kentz, Atkins, Endress+Hauser, IRENA and EU GCC Clean Energy Network II. These sessions focused on current and future energy projects in the UAE and the Middle East, and the opportunities for UK companies to support these developments, which will help to meet the growing energy demand in the region and add value to the local supply chain.

EIC Connect Middle East has a dedicated Middle East Landing Zone, where UK companies receive practical advice on setting up and running a business in the region as well as how to find and work with local partners. The year’s zone benefitted from the support of the UKTI and the British Centre for Business.

Our exhibitor stands were once again sold out with all 40 places being booked quickly.

UK companies were keen to exhibit their products and services to UAE-based operators and contractors, who were aware that the innovative products and expertise provided

by UK companies could enable them to enhance efficiencies and maximise production, giving them an advantage in the buoyant but competitive Middle East market.

The 2016 event has received fantastic feedback with 86% of delegates saying their expectations were fully met. The EIC Connect Advisory Board has taken on board all the comments and suggestions offered by the delegates and is already planning the next edition of this event which will take place in May 2017. n

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EIC Global

EIC trade delegation to Iran With economic sanctions having been lifted in January, Iran is now ready to re-establish itself in the global energy market. The EIC delegation explored the opportunities on offer in the Gulf country

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he EIC’s overseas trade delegation to Iran in May took 11 delegates from 11 UK companies to Tehran to find out more about the current oil and gas opportunities available in this recently re-opened market.

Since news of the economic sanctions being lifted was announced back in January, a considerable amount of business opportunities have been identified in the country. However, there is also a general consensus that many challenges still exist that need to be recognised, identified and overcome in order to succeed. Despite this, it is clear that Iran is now definitely open for business.

With proven reserves of 158bn barrels of crude oil and 1,201tn cubic feet of natural gas, Iran holds the world’s fourth largest and second largest reserves of crude oil and natural gas respectively.

Among the country’s most valuable assets is the South Pars offshore gas field, part of the world’s largest natural gas field which is shared between Iran and Qatar. The field, discovered in 1990, accounts for almost 40% of Iran’s natural gas reserves. Currently, only 50% of the field’s planned 24 development phases have been completed.

This huge development plus numerous greenfield and brownfield projects all require support from the international supply chain.

One barrier to doing business in the country has been difficulties in obtaining an entry visa. However, the Iranian embassy in London has recently reinstated its consular service, offering a limited number of business and tourist visas and although there are still some challenges for British passport holders seeking a visa, ongoing diplomatic discussions continue to improve the situation.

The delegation’s four-day programme included an in-country briefing hosted by the British Embassy as well as meetings with a number of high profile players active within the country’s oil and gas sector. Visits to engineering, procurement and construction (EPC) contractors including Tasdid, Iran Offshore Oil Company, Mapna, Namvaran, Nargan and Tehran Janoob took place.

We also arranged meetings with National Iranian Oil Company operating companies SPEC, Pars Oil and Gas Company, Petrochemical

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“Having identified Iranian financial instruments as being a barrier to entering the market we organised a meeting with Saman Bank – a Tier 2 Iranian bank” Commercial Company and the National Iranian Gas Company. The delegation also met with senior officials from the Ministry of Petroleum. The programme also included various networking opportunities, the most notable of which was the Queen’s birthday celebration held at the British Embassy.

Perhaps the most pressing consideration for companies aiming to renew their business relationships with Iranian companies is that of finance. UK high street banks are still reluctant to work with Iranian financial instruments which leads to a need for UK companies to explore alternative sources of finance. Having

The four-day EIC delegation to Iran included meetings with National Iranian Oil Company operating companies, financial institutions and EPC contractors including Petrochemical Commercial Company

identified this as a barrier to entering the Iranian market we organised a meeting with Saman Bank, a Tier 2 Iranian bank. The meeting was solution-focused and considered very beneficial by all delegates. During the meeting Saman Bank stated that they have upwards of US$1bn of trade finance available to UK companies provided the transactions can be routed through one of Saman’s nominated banks located in Oman, Turkey or Belgium.

The much publicised Iran petroleum contracts were also discussed, which have been created specifically to attract foreign investment from international oil companies. While some details about these contracts are known, the full terms and conditions are still to be released. What we do know is that there are up to 50 onshore and offshore contracts on offer, which represent over US$185bn worth of project investment over the next five years – adding a considerable pipeline of work to the already vast business opportunities available in this re-vitalised market. n

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EIC Global Egypt has proven reserves of 4.4bn barrels of oil and 77tn cubic feet of gas

Egypt Petroleum Show (EGYPS) 2017 Taking place from 14–16 February in Cairo, EGYPS is a direct route into the largest non-OPEC oil producing country in Africa, offering a platform to interact with Egypt’s key operators, forge local partnerships and learn about doing business in the country ith proven reserves of 4.4bn barrels of oil and 77tn cubic feet (Tcf) of gas, Egypt is the largest non-OPEC oil producer and the second-largest dry natural gas producer in Africa. As production has stagnated over the last years and its domestic energy demand has increased rapidly, the country is committed to developing its oil and gas industry.

Upstream developments like the West Mediterranean Deepwater and North Alexandria concessions, which hold estimated reserves of 5Tcf of gas and 55m barrels of natural-gas condensates, have recently seen major engineering, procurement and construction contract awards.

Another major project already underway is the Zohr gas field, being developed by ENI and IEOC joint venture Petrobel. The project is currently in the first phase of development which will see the field producing 1bn cubic feet of gas per day by quarter four 2017. Its

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second phase will require the development of 14 wells and subsea trees and a new onshore processing plant. The overall CAPEX for the field is approximately US$13bn.

BP is investing heavily in the country. The North Damietta Offshore Concession, which holds the Atoll gas discovery, is to be developed in two phases the first of which will consist of three wells to be tied-back into existing infrastructure with production set to start in 2018. The most notable BP project in Egypt, however, is the West Nile Delta development valued at US$12bn with first gas expected in 2017.

The downstream sector is also seeing major investment. Carbon Holdings is currently developing the Tahrir petrochemical complex at a cost of US$7.2bn. While major contracts have already been awarded on the project a number of supply chain opportunities are still available for work on the complex, which is due to start production in quarter four 2019.

WorleyParsons was awarded a project

management consultant contract in March by the Egyptian General Petroleum Corporation for the modernisation of the Assiut refinery. The project has been split into two phases which are to be carried out over the next four years and will receive investment of over US$2bn.

The three-day Egypt Petroleum Show is expected to receive over 10,000 visitors and 400 exhibitors and benefits from 25 conference sessions and 150 speakers from regional operators and contractors.

If you would like to exploit the tremendous opportunities in Egypt’s energy industry now is the time to engage with the market and establish relationships with regional operators and local partners. n

Contact: Mark Gamble Senior Overseas Events Manager Tel: +44 (0) 207 091 8600 Email: mark.gamble@the-eic.com

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EIC Global

United Kingdom The recently established OGA is committed to maximising the potential of the UKCS, where decommissioning projects will provide significant opportunities for the UK supply chain. While uncertainty surrounds Hinkley Point C, progress has been made on the Wylfa Newydd project

Shell’s Penguins field redevelopment will see the construction of a new FPSO for which the EPC contract will be awarded in Q4 2016 (photo: Shell)

Oil and gas While challenges exist on the UK Continental Shelf (UKCS), work has progressed to make the region an attractive investment destination now and in the future. Following government intervention, the UK now has more attractive fiscal terms than Norway, Australia and the US Gulf of Mexico.

The establishment of the Oil & Gas Authority (OGA) in 2015 was a vitally important move to breathe life into the UKCS. The OGA, now fully staffed, is committed to ensuring that the maximum value of economically recoverable petroleum is developed from beneath UK waters. While times are undoubtedly tough, the establishment of the OGA will hopefully lead to new opportunities for the oil and gas industry in the UK.

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“The increase in decommissioning projects being proposed represents potentially significant opportunities for the UK supply chain”

While new build projects are thin on the ground, the increase in decommissioning projects being proposed represents potentially significant opportunities for the UK supply chain. With the supply chain still developing the opportunity exists for the UK to become

a world leader and hub for the sector, with expertise gained off UK shores. Costs of decommissioning could be as high as £47bn between 2015 and 2041. The challenge is to ensure that decommissioning can be done in a cost effective, efficient and safe way. The OGA is at the forefront of these developments and has established a Decommissioning Board to lead on this. One of its targets is to reduce costs by 35% vs 2015 base case, which is achievable with industry support.

Work offshore, while slow, does continue.

Significant progress has been made on the Culzean project. Installation of a wellhead jacket has been completed and work on the fabrication of topsides and jackets for the central processing platform and living quarters is underway. With total

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EIC Global Penguins field Greater Lancaster Area

Key Oil & Gas Power Nuclear Culzean field

Renewables

Neart na Gaoithe wind farm

Belfast Harbour Estate Kirby Misperton shale drilling Wylfa Newydd Charity Farm, Burlton

Hinkley Point C

Map showing key energy projects in the UK

CAPEX expected to be in the region of US$4.7bn, development of the field is a real positive for the UK oil and gas industry.

Progress is also being made on the Shelloperated Penguins field redevelopment.

Successful completion of the redevelopment work would lead to production from the field being extended and continuing for up to 20 years. The project, which dovetails fittingly with the OGA’s plan to maximise recovery from the UKCS, will see the construction of a new floating production storage and offloading (FPSO) vessel, the drilling of up to 11 wells and new subsea infrastructure.

A final investment decision is to be made in Q4 of 2016, which is when the engineering, procurement and construction (EPC) contract for the FPSO is expected to be awarded.

Despite the lower rig prices, very little exploration and appraisal work has taken place since the turn of the year. With the risk of numerous rigs being cold stacked, it is important that agreements are reached between operators and rig suppliers to ensure these rigs are not out of action for an extended period of time. One company that is supporting the local rig market is Hurricane Energy. The company has secured financing to drill two wells in the second half of 2016

in the Greater Lancaster Area in the west of Shetland region. The appraisal well is designed to determine the contingent resource ranges ahead of any field development decisions.

Shale gas has been in the news a great deal recently. In a landmark ruling, approval was granted by the local council for Third Energy to undertake shale gas drilling, including the fracturing of the rock, near Kirby Misperton in Yorkshire. Third Energy has a great deal of responsibility on its shoulders to ensure that when drilling commences that operations are undertaken safely and without impacting the environment. Drilling is not expected for some time though as the company still has to meet conditions set by the planning authority and Environment Agency. When these have been met and final consent received from the secretary of state Third Energy can go out to market and order the long-lead items needed for the drilling. Only once drilling has been completed will we know the potential to flow gas from shale in the UK and what the future holds for the industry.

Power Investors in the UK, who continue to feel the effects of challenging economic conditions, have pointed out that there are few incentives in place to encourage the

“The early introduction of the Capacity Market scheme is aimed to offset the impact of historical oil prices on existing generating capacity”

construction of new power plants. Under the government’s capacity market scheme, the owners of power plants are paid to provide electricity at short notice. Power generators which are successful in auctions get capacity payments which encourage them to invest in new plants or keep existing ones running.

They have to be able to deliver energy when it is needed or face penalties. The government recently undertook a review of the capacity mechanism and as a result of the consultation confirmed its intention to bring the scheme forward to guarantee back up energy generating capacity to 2017, one year earlier than intended. The government has already secured back up generating capacity for the winters of 2018–19 and 2019–20, and the auction for winter 2020–21

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EIC Global

Development of the proposed Hinkley Point C nuclear power station has been hit by numerous delays (image: EDF)

is expected to take place later this year. The early introduction of the Capacity Market is aimed to offset the impact of historical oil prices on existing generating capacity.

In the first half of 2016, Evermore Energy announced plans to develop the 400MW facility at a site on the Belfast Harbour Estate. The company previously developed a smaller biomass-fuelled power plant at Londonderry Port. A planning application is due to be lodged later this year and funding for the scheme is understood to be well advanced. The new plant will use the latest Siemens’ gas-fired technology.

Nuclear While the uncertainty surrounding Hinkley Point C casts a shadow over its development timescales, progress has been made on the Wylfa Newydd project being developed

by Horizon Nuclear Power. The company appointed a joint venture responsible for construction of the plant. The newly created company, Menter Newydd, is comprised of Hitachi Nuclear Energy Europe, Bechtel Management Company and JGC Corporation (UK). Hitachi-GE, which has been operating under a front end engineering design contract

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with Horizon for more than three years, will continue to provide the UK advanced boiling water reactor (ABWR) technology, under sub-contract to Menter Newydd. Horizon has recently completed a further stage of public consultation in north Wales, launched its apprenticeship scheme, and appointed Duncan Hawthorne, formerly president and CEO of Canada’s Bruce Power, as its CEO. Site development work is also continuing to advance, and the UK ABWR remains on track to complete its regulatory generic design assessment by the end of 2017.

The government has been criticised for the lack of details regarding future CfD rounds.

According to the 2016 Budget, presented in March, an auction that will support offshore wind and other less-established renewables will be held this year.

In the wind sector, it was recently reported that the CfD for the 448MW Neart na Gaoithe wind farm off Scotland has been terminated and that the developer, Irish company Mainstream Renewable Power, is fighting that decision. n

Renewables On the renewables front, developments in the solar sector were limited as only one of the five solar projects that won support in the UK’s first contract for difference (CfD) auction last year was delivered on schedule: developer Lightsource Renewable Energy’s 11.94MW Charity Farm development located in Burlton, near Wem was commissioned at the end of June 2016. Shortly after the auction results, it was confirmed that solar projects totalling 33MW – the two that made the lowest bids – would not be built. Two other projects have now hit hurdles, one has had its CfD terminated and the other is negotiating an extension.

Contact: Neil Golding Head of Oil and Gas and Business Development Tel: +44 (0) 20 7091 8613 Email: neil.golding@the-eic.com

Contact: Amisha Patel Head of Power, Nuclear and Renewables Tel: +44 (0) 20 70918612 Email: amisha.patel@the-eic.com

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EIC Global

EIC Connect Oil & Gas 2016: global opportunities for the UK supply chain Siemens, Centrica, WorleyParsons, Bechtel, and SNC Lavalin will be joined by a host of other major energy companies at the eighth edition of EIC Connect Oil & Gas

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IC Connect Oil & Gas returns to Manchester on 22 and 23 November 2016 to again support UK export and supply chain companies through a series of informative presentations by major oil and gas operating companies and their contractors.

When the advisory group responsible for planning this event met in April, the oil price was hovering at US$42 per barrel, an improvement on the January level of US$34 per barrel, but still a long way short of the US$60 per barrel level believed to signal the turning point for the market.

The industry consensus is that prices of both oil and gas will never reach the heights of the pre-crash period and costs will remain under pressure as the year progresses – which will be reflected in the supply chain environment where ‘capital efficiency’ and ‘added value’ are becoming key to success in this competitive sector.

The challenge for EIC Connect Oil & Gas this year is to highlight the opportunities that do exist to the UK supply chain while also enabling them to present their ideas, innovations and questions to operators and contractors.

EIC Connect Oil & Gas supports UK supply chain companies to work with major oil and gas operating companies

“EIC Connect Oil & Gas’ conference programme deals with the challenges facing the industry, the benefits of collaborating and clean energy as an alternative income stream for the future” The conference programme will tackle the challenges facing the industry, as well as introducing delegates to the benefits of collaborating, the options for those looking to clean energy as an alternative income stream for the future and the opportunities decommissioning presents for all.

Matthias Bichsel, then Executive Director at Shell, was one of the keynote speakers at EIC Connect Oil & Gas 2014

Siemens, Centrica, WorleyParsons, Bechtel, and SNC Lavalin are among the companies already confirmed to take part in this event,

and will provide delegates with an update on their global oil and gas projects as well as their supply chain and buying strategies.

Many other major companies and contractors have also committed to speak at the event and support the all-important one-toone sessions where members of the UK supply chain will have the opportunity to learn about these companies’ procurement requirements and registration processes as well as present their services and products directly to key decision makers.

Sponsoring this year’s event are Siemens, Addleshaw Goddard, and Hare. n

Contact: Sarah Lansdell Head of UK and National Events Tel: +44 (0) 7595 082 162 Email: sarah.lansdell@the-eic.com

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EIC Global

Europe The region continues to reduce its reliance on Russian gas through a series of pipeline projects while concerted efforts to decarbonise the electricity sector have big implications for Europe’s power producers. Recent licensing rounds should lead to an increase in exploration activity

Large contracts continue to be awarded for Statoil’s Johan Sverdrup development

Oil and gas When looking at future opportunities in Europe, the supply chain should be encouraged by the recent announcements from a number of licensing rounds which point to a bright future for exploration activity in the region.

The 2015 Atlantic Margin Licensing Round saw the largest number of applications received in any licensing round off Ireland.

Both major and mid-size companies have taken acreage in this frontier region.

Off Norway, a number of licences were awarded in an area of the Barents Sea that has never seen exploration activity.

Operator commitments to exploring this frontier acreage is important for the future of the industry and is particularly significant given current market conditions.

These challenging times have seen contracting activity slow considerably in Norway, however, projects do progress.

Statoil continues to award multi-million dollar contracts on its Johan Sverdrup

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“Recent announcements from a number of licensing rounds point to a bright future for exploration activity in the region”

development with companies offering innovative technology being particularly successful, which is encouraging. One such example will see GE Oil & Gas supplying a Christmas tree system that incorporates a special valve which will increase the longevity of maintenance intervals, resulting in reduced downtime for the operator.

This in turn will drive higher productivity and lower operational expenditure.

Reliance on Russian gas continues to be a key theme in Europe, as the continent

continues to look to diversify the source of its supplies. Having completed its first liquefied natural gas terminal, Poland has announced plans to move forward with the Denmark Poland Baltic pipeline, which would see gas supplied from Norway transported to Poland.

The project, which has EU backing and financial support, will see a feasibility study undertaken through the remainder of 2016.

Elsewhere in the region, a number of major contracts have been awarded on the TANAP and TAP pipeline projects which will form the Southern Gas Corridor. These pipelines will see gas transported from the Shah Deniz field in Azerbaijan to a number of locations in Europe. Completion of the pipelines in 2018 and 2020, will help meet the increasing demand for gas seen in countries such as Greece, Albania and Italy.

Power, nuclear and renewables As Europe continues its march towards a decarbonised electricity sector, the region’s power producers are having to undertake radical reforms.

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EIC Global One such market is Italy where the price of solar power now competes with conventional sources of power. The prospects for Italian wind energy are, however, very uncertain as a feed-in-tariff announced in early 2016 for a further 800MW of onshore wind capacity has yet to enter legislation and government officials have indicated that this incentive tariff will be the last for onshore wind farms. Longerterm prospects for Italy’s wind energy sector largely hinge therefore on repowering, as the best onshore sites have already been taken.

For repowering to become a major new trend, market players argue that specific legislation is needed to streamline the approval process.

“Statoil continues to award multi-million dollar contracts on its Johan Sverdrup development” Momentum continues to build in Germany’s offshore wind industry where Siemens’ has recently completed the installation of all 97 turbines at the Gode Wind 1 and 2 offshore wind project in the German North Sea. Located 45km from shore, the 582MW project is now operational. Having sold a 50% share in the project to a consortium of Danish pension funds for €600m in 2014, DONG Energy remains the majority shareholder and will operate and maintain the offshore wind farm. DONG Energy has a target of installing 6.5GW of offshore wind capacity by 2020 and reached the 3GW milestone in 2015 by bringing its Borkum Riffgrund 1 project in the German North Sea into operation.

Major pipeline projects are taking place across Europe including the TANAP and TAP projects which will form the Southern Gas Corridor The nuclear sector in Europe continues to see incremental developments on various new build projects. However, with many markets looking to dismantle existing plants due to government policy and others citing unfavourable market conditions, decommissioning activity is also set to increase in the coming years. Most recently, nuclear operator Vattenfall has warned that all of Sweden’s nine operational reactors could be shut in a little over five years if the government does not remove a capacity tax levied on nuclear generation. Vattenfall operates seven reactors and OKG, two. The majority of OKG’s shareholders voted in October 2015 to close the 492MW Oskarshamn-1 due to financial reasons and the company announced that the unit would be shut permanently in the middle

The Gode 1 and 2 offshore wind farm, in the German North Sea, is now operational (photo: Siemens)

“Momentum continues to build in Germany’s offshore wind industry where Siemens’ has recently completed the installation of all 97 turbines at the Gode Wind 1 and 2 offshore wind project” of 2017. Shareholders also voted to shut the 661MW Oskarshamn-2 ahead of schedule, also due to financial reasons. It is planned to be closed before 2020. Vattenfall’s closure plans for the 916MW Ringhals-1 and the 910MW Ringhals-2 are not likely to change even if the capacity tax were to be removed. The company has said that all investment in Ringhals-1 and Ringhals -2 will stop in 2017, as it does not plan to make the new safety improvements to the two units that are required under Swedish law for all nuclear power plants operating in the country after 2020.

In other news, the European Commission (EC) has received 16 project proposals for its first (of two) Connecting Europe Facility Energy Call for Proposal. Funding will be available only to projects that are part of the Projects of Common Interest (PCIs) list adopted by the EC in October 2013 aimed at upgrading and developing new energy transmission infrastructure to cater for future energy demand, ensure security, as well as support large-scale deployment of energy from renewable energy sources in the European region. Total funding of €800m will be made available over the two calls for proposals planned for 2016. n

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IMI Critical Engineering takes LNG forward through innovation Severe service valves have been a critical component in the production of oil and gas for decades, but to add real value, valve design must evolve to meet the changing needs of clients and the industry they serve.

In the past five years, some of the most rapid change has been in the LNG sector, thanks to the everincreasing pressure for companies to generate return on their investment.

In fact, LNG liquefaction plants began to grow in scale from the early 2000s, with a growing requirement for very large valves which could no longer be produced by conventional forging.

Many plants were using 12” to 24” valves to generate 1 to 3 MTPA (million ton per annum) of LNG. In response, IMI Critical began to produce larger LNG valves from castings, which were derived from the earlier forged shapes.

However, by 2010, as the first ‘mega’ LNG projects came on stream, the required valve size had increased still

further and IMI Critical identified a clear need for a new engineered valve with an inlet diameter of 20 inches or more for LNG and other plant applications.

The design process began with a thorough survey of IMI Critical’s global production history over the past decade, to define the sizing and pressure classes that would be required.

The experience of scaling up earlier valves had also revealed a number of issues to solve.

Scaling up limited the scope to optimise and rationalise the valve range.

The size of the valve and its growing weight – some castings weighed around 15,000 lbs (6.8 tonnes) – meant additional lifting and handing supports were required. And providing castings on a case-by-case basis limited the ability to apply best practise. Finally, the cylindrical shape of the castings had become inefficient and was now carrying too much weight.

IMI’s research team concluded that a spherical design would be more appropriate for modern LNG applilcations, and set out ot create a new range of lightweight, spherical castings.

It took three months to create the geometry. The aim was to replace the existing cylindrical shape with a spherical profile, to save weight and optimise the design without compromising on strength. The IMI CCI team created a new architecture, and a parametric model that allowed them to establish the relationships between side port, gallery diameter and radii of curvature. This meant designs within the new range could be quickly scaled from small to large sizes.

The development team applied finite element analysis (FEA) and computational fluid dynamics (CFD) to the product development process.

More than 20 valve designs were analysed through FEA which helped the team identify and correct a potential weakness in the area surrounding the outlet port. Although the design

complied with the ASME code, the FEA study revealed an area of high stress at the intersection of the valve body gallery and the side flange. The team found a method to reinforce this intersection and validated their approach with additional FEA studies.

The results The success of IMI Critical’s innovation can be seen in the number of valves from the new range that have already been installed and successfully used in major LNG projects. Over the past two years the team has supported these valves being designed and installed into plants ranging from combined cycle power units in India, to refineries in Trinidad & Tobago and LNG liquefaction units in Russia and the United States.

The valves have met industry needs by providing better flow, fast response and durable design, and clients are happy with the better cost, delivery and safety profiles of the new valves compared to their legacy predecessors.

IMI CCI has now established the new improved design as standard, and is proud of having once more taken the severe service valve industry forward through innovation.

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EIC Global

Offshore Mediterranean Conference 2017: transition to a sustainable energy mix Italy’s premier oil and gas conference and exhibition, which will feature an EIC hosted UK pavilion, returns to Ravenna and will focus on the contribution the oil and gas industry can make to a lower carbon Europe

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he next edition of Offshore Mediterranean Conference (OMC) will once again take place in Ravenna, northern Italy, from 29–31 March 2017. Over the three days industry professionals and decision makers from oil and gas companies around the world will come together to share new technologies and

discuss the latest exploration and production developments in the Mediterranean Basin.

Since its launch in 1993 OMC has been working to disseminate offshore technical knowledge, promote and support education for offshore engineers and technicians and advance the development of the tools and

The EIC will manage the UK pavilion at OMC 2017 which expects to receive approximately 18,000 visitors

procedures required to explore, study and further the responsible and sustainable use of the energy resources in the Mediterranean.

In 2015, OMC welcomed a total of 18,923 visitors which – a substantial 20% increase on 2013 numbers – with a total of 25,142 square metres of exhibition space being fully occupied by 688 exhibiting companies.

The 2017 edition, which will include an EIChosted UK pavilion, explores the contribution that the oil and gas industry can make to a lower carbon Europe. As gas remains the most sustainable fossil fuel consumption of this resource will increase, especially in Europe and Asia. The Mediterranean Basin is a natural distribution hub for this vital fuel.

The Eastern Mediterranean has seen a number of very significant gas discoveries made during the last decade, most notably in Cyprus, Israel and Egypt. Still relatively unexplored, the region – buoyed by these discoveries – offers potentially significant opportunities now and in the future. The region is attractive to major operators, with companies including Eni and BP holding significant assets.

The Italian supply chain, led by Saipem and Rosetti Marino, is well placed to play a key role in developing these fields and this event will provide a great opportunity to meet with representatives from these companies. As well as the much-publicised new developments the recent passing of a law to extend production at the existing fields offshore Italy, means supply chain opportunities abound in the Mediterranean. woes, as the country – an OPEC member – is highly dependent on oil revenues. n

Contact: Raelene Rifkind Head of Overseas Events Tel: +44 (0) 207 091 8600 Email: raelene.rifkind@the-eic.com

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www.the-eic.com

EIC Global

Asia Pacific, Australasia and China China continues to dominate developments in Asia Pacific with state-owned oil and gas company CNPC planning to increase its natural gas sales by 40% over the next five years. The country is also leading global investment in renewable energy

China National Petroleum Corporation plans to construct 12 new gas storage facilities

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he 169th OPEC meeting which took place in Vienna in June observed that since the previous meeting in December 2015 crude oil prices have risen by more than 80%, that supply and demand is converging and oil and product stock levels have shown relative moderation. All of which offer fresh hope for the oil and gas industry that the market is moving through a balancing process.

BP’s Statistical Review of World Energy 2016 reported that the Asia Pacific region holds approximately 349m tonnes oil equivalent (MMtoe) of proven oil reserves and 722MMtoe of natural gas reserves.

Moreover, the region accounted for 40% of global oil demand, with China once again contributing the largest national increment to global oil consumption growth at approximately 770,000 barrels per day.

With Australia’s US$180bn of new liquefied natural gas (LNG) plants likely to fall short on the hoped for returns, it is apparent that there is a need for LNG producers to collaborate more to capitalise on growth opportunities, and enhance efficiencies through debottlenecking and backfilling programmes. Producers will be able to boost LNG volumes at lower cost in by committing to these programmes, which could realise up to US$10bn worth of value, according to energy consultant, Wood Mackenzie. The consultant forecast approximately 13m tonnes

per year of new LNG volume will become available from debottlenecking and backfilling.

In China, state-owned oil and gas company, China National Petroleum Corporation (CNPC) plans to increase its natural gas sales by 40% over the next five years to a total of 314MMtoe.

By 2020, the company aims for its gas pipeline network to stretch more than 108,000km to an annual gas transportation capacity of 162MMtoe. On the supply side, CNPC plans to add 12 gas storage facilities in China and to expand the receiving capacity of its three LNG terminals from its current 12m tonnes to 19m tonnes. To deal with its growing energy demand, the company will look towards gas-fired power plants as well as the use of gas-fired vehicles.

Earlier this year Vietnam announced that it was abandoning its ambitious coal power plant plans in favour of an accelerated investment in renewable energy. This was followed by the news that India’s coal imports dropped by 35% last year due to massive oversupply and a faster than expected expansion in renewables.

Indonesia – with its extensive geothermal, solar, micro hydro and biomass resources – could potentially make the renewables shift even faster than India, however, this seems unlikely as despite its abundance of renewable resources, coal remains resolutely king of the country. Nevertheless, the energy landscape in Asia Pacific continues to shift with the dominance of fossil fuels being challenged.

According to Bloomberg New Energy Finance 2016, besides China and India, Thailand was the only country other than Japan to achieve US$1bn in asset finance for renewables excluding hydro – with an increase of 162% in 2014. The Philippines, which has become an active market for both wind and solar in recent years, saw a 41% drop in asset finance to US$798m last year, however, this was most likely due to the timing of particular funding issues rather than a downward shift in its investment trend.

China was by far the largest market for renewable energy investment in 2015.

The country accounted for the largest proportion of global investment for the fourth year in a row, with total investment of US$96bn – nearly three times Europe’s utility-scale funding of US$34bn and almost four times that of the US, at US$24bn.

The surge in renewable energy reflects China’s strategy of expanding its electricity generation in a less coal intensive way, while reducing carbon intensity and pollution. Wind and solar investment dominated the market in almost equal measure – with US$48bn and US$44bn of capital committed respectively. n

Contact: EIC Kuala Lumpur office Tel: +6 03 2725 3600 Email: kualalumpur@the-eic.com

55

EIC Global

Vietnam: rising star in Asia Pacific

by Ian Gibbons, Her Majesty’s Consul General to Ho Chi Minh City and Director, Department for International Trade (DIT), Vietnam

Rich natural mineral resources, strong oil and gas demand and fast-growing refining capacity have helped Vietnam stand out as an attractive upstream and downstream market for UK companies with relevant expertise Since 2013 Gazprom and PetroVietnam have been engaged in commercial gas production at the Moc Tinh and Hai Thach fields, with recoverable gas and condensate reserves amounting to 118bn cubic feet and 15.2m tonnes respectively (photo: Gazprom)

W

hile the oil and gas market remains subdued globally, Vietnam has not been as affected as other oil producing countries.

And although questions remain over access to this high-growth market, where relations are key and territorial disputes dominate, large opportunities exist for companies as Vietnam looks to explore its oceans further and expand its refinery capacity.

Upstream and midstream With current oil reserves of about 4.4bn barrels, accounting for 0.3% of the world’s reserve, Vietnam ranks second in East Asia, third in Asia and 31st in the world in terms of oil output.

Production has grown from only 175,000 barrels per day (bbl/d) in 1996 to 362,000bbl/d in 2015.

Vietnam is one of the top five oil producers in the Asia Pacific region. There are large amounts of natural and associated gas in the Vietnamese waters. According to the BP’s Statistical Review of World Energy 2016, Vietnam’s natural gas reserves reached 21.8tn cubic feet (Tcf) in 2015. As the demand for energy in Vietnam continues to grow, these gas reserves will become increasingly important. Natural gas production reached 378bn cubic feet in 2015, accounting for 0.3% of total world production.

The country has five operational oil and gas basins (Song Hong, Phu Khanh, Cuu Long, Nam Con Son and Malay-Tho Chu).

There are two more basins in the East Sea (Truong Sa and Hoang Sa), however, these basins have not, as yet, been explored.

56

Vietnam has approximately 80 oil and gas prospects, of which around 30 have made discoveries. Most oil exploration and production (E&P) activities occur offshore in the largest oil reserve basins (Cuu Long (80%) and Nam Con Son). Most of the natural gas reserves are generally believed to be located in the Nam Con Son Basin. A former BP-led consortium has exploited the primary field and formed a joint venture with Vietnam’s national oil and gas group, PetroVietnam (PVN), to develop natural gas resources there and in the Lan Tay and Lan Do fields. These fields contain an estimated 2Tcf of natural gas. The offshore pipeline, Nam Con Son 1, and the recently launched Nam Con Son 2 delivers wet gas to the gas plant to feed gas to the power plants and fertiliser plants in the province.

Downstream Vietnam’s refinery investment plans are particularly ambitious. PVN plans to develop three refinery-petrochemical centres in north, south and central Vietnam.

So far the country’s oil refining capacity consists of only the Binh Son Refinery Company in Dung Quat, Quang Ngai province (central Vietnam), which is 100% owned by the Vietnam government. The refinery opened in 2010 with capacity of 6.5m tonnes per year, meeting around 34% of local daily consumption of 378,000bbl/d. The project has been expanded to increase capacity of up to 8.5m tonnes per year, equivalent to 190,000bbl/d by 2021.

The engineering design, for both initial and expansion projects, has been carried out by

Amec Foster Wheeler. The second oil refinery, Nghi Son, with production capacity of 10m tonnes per year began construction in October 2013 in Thanh Hoa province and is scheduled for completion in 2017. The US$9bn plant – with investment from Vietnam, Japan and Kuwait – will meet 40% of Vietnam’s forecast domestic demand for petroleum products.

Others are entering the refinery market. Work on the Vung Ro Refinery (Phu Yen province, annual capacity 8m tonnes) began in September 2014 and an engineering, procurement, and construction (EPC) contract was awarded to Japan’s JGC. There is an ambitious US$22bn Victory Nhon Hoi Refinery project (Binh Dinh province, capacity 400,000bbl/d) planned

by Thailand’s largest energy company, PTT. However, with Saudi Aramco’s recent withdrawal from further development, internal Thai politics and uncertainty in the global oil market, the project has been delayed. Also, Long Son Refinery, Can Tho Refinery and Nam Van Phong refinery are all on the list of potential projects in which Vietnam will call for investment.

Key players in the market The oil and gas sector is highly regulated in Vietnam by the state-owned company, PVN – the key body that acts both as regulator (on behalf of the Ministry of Industry and Trade) and industry participant. This could be construed as a potential conflict of interest. As PVN issues the licence for the production sharing contract (PSC)/joint operating company contract (JOC), it needs to protect the state’s assets (oil and gas resources) on behalf of the government.

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EIC Global Hanoi

Key

Laos Hainan So

Operational oil and gas basins

with Malaysia and Indonesia. As Vietnam is facing challenges in deepwater exploration, equipment and services for deepwater are needed. However, opportunities also exist in shallow water in marginal fields, as well as onshore E&P.

ng Ho ng Ba sin

Hong Sa Basin Thailand

Da Nang

VIETNAM Phu K

Cambodia

hanh B

Cuu Long Trough

u Cu

Lo

ng

asin

Ho Chi Minh City Ba

sin

Truong Sa Basin Group

M al

Nam Con Son Basin

ay Ba si n

However, as a partner in the PSC/JOC, it needs to ensure that the PSC/JOC generates profit.

PVN is responsible for all oil and gas resources in Vietnam and contributes approximately 20% to Vietnam’s GDP every year. In addition to local E&P activities, PVN is also involved in several E&P projects in Malaysia, Algeria and Peru. Through its various companies and wholly owned subsidiaries, PVN covers all operations from oil and gas E&P to storage, processing, transportation, distribution and services.

Offshore Vietnam oil and gas E&P Source: PetroVietnam Ho, have reached maturity and production has decreased sharply. Also, high-pressure hightemperature drilling in the main Nam Con Son basin, and unrecovered petroleum resources mainly in deep zones far from logistic bases, make it difficult to drill the oil. Exploration of these areas will be a big challenge for Vietnam as the country lacks experience, adequate equipment and facilities for deepwater exploration; territorial disputes in these waters also make exploration difficult and uncertain. This has been compounded by the low prices for oil. One IOC has told UKTI that they have been waiting for months to get approval from PVN for them to carry out activities in the conflict area.

The company operates alone or in partnership with international oil companies (IOCs) under a JOC/PSC. Exploration permits are awarded on a bilateral basis, with no regular upstream bidding rounds. IOCs are allowed to independently explore for oil and gas. While the presence of PVN is required in all production projects, IOCs are allowed to hold the majority stake and receive a share of the output. Some of world’s largest oil and gas operators have a presence in Vietnam through forming partnerships with PVN such as ExxonMobil, Repsol, Rosneft, ConocoPhillips, KNOC and PETRONAS.

Opportunities

The Ministry of Industry and Trade has overall responsibility for managing the energy sector, including overseeing the state-owned energy companies, such as PVN. It is also responsible for formulating sector reform initiatives and approval of all major investment projects.

Key opportunities lie in both trade and investment. For investment, PVN looks to partners to form PSCs/JOCs to explore a number of undiscovered blocks in Song Hong Basin, Phu Khanh Basin, onshore Mekong Delta, Nam Con Son Basin, Phu Quoc Basin, Malay-Tho Chu-Phu Quoc Basin.

Challenges The local oil and gas sector faces a number of challenges. Major oil fields, including Bach

The oil price drop has affected Vietnam, resulting in low export revenue for the country. However, production remains at the same 2015 levels. PVN and its PSCs are finding ways to cut cost by restructuring management and exploration activities.

According to a report conducted by Frost and Sullivan in 2015, Vietnam ranks in the top three in the region in terms of opportunity, together

Specifically, there is demand for equipment and services includes engineering services such as concept study, feasibilities studies, front end engineering and design (FEED), detailed engineering and project management, seismic studies, field production facilities, engineering design and fabrication of deepwater structures, supply and installation of deepwater, subsea equipment and services.

For midstream and downstream capacity expansion, products and services that will be required are for storage tank terminals, pipelines and liquefied natural gas re-gasification, and engineering services such as FEED, engineering and project management, specialist services for new build refineries and expansion.

It is worth noting that procurement of the PSC should follow PVN’s procurement regulations.

It is required that procurement packages with a specific value (depending on the negotiation when forming the PSC/JOC), should be approved

by PVN. And PVN requires high local content in the tender packages as they have many member companies that cover all fields of the oil and gas industry, such as exploration, exploitation, fabrication, storage, transportation, processing and delivery of oil and gas products, as well as commercial, financial and oil insurance.

Some IOCs have disclosed that local content of recent packages range from 83 to 98%, with most work being carried out

by PVN’s subsidiaries. To become involved with the packages companies should ideally work through PVN subsidiaries, or work through local trading companies, due to their good connections with PVN. Another potential area is training and education across the industry. Some IOCs have concerns about local technical capabilities but the overall mood is positive in terms of local talent, once training has been completed by local or overseas companies.

Doing business in Vietnam Vietnam boasts one of the most vibrant economies in Asia. It has both a large market for capital goods and a growing domestic market for consumer goods. This is an exciting market of increasing affluence and is one of the fastest growing economies in the world. Accession to the WTO in 2007 created a surge in external trade (Vietnam’s trade/GDP was 160% in 2011).

Vietnam has signed two bilateral free trade agreements (FTAs), in addition to six ASEAN FTAs. Most recently, Vietnam signed an FTA with the Eurasian Economic Union on 29 May 2015. It is expected that the FTA with the EU will enter into force in early 2018 and Vietnam is part of the Trans Pacific Partnership. n

57

EIC Global

Coal will continue to play a vital role in the development of power generation in Indonesia for the next 10 years due to the relatively lower costs of construction and operation

Powering up Indonesia

by Tony Frampton, President Director, PT Power Consultants Indonesia

To ensure energy security and meet growing demand for electricity, Indonesia is looking to coal and renewables to expand its generation capacity

I

ndonesia is a resource-rich county with a young and large population, and a growing economy. However, for a middle-income country, it lags behind its South East Asian neighbours in terms of access to energy for its population. The country proposes to address its comparatively low overall rate of electrification with ambitious infrastructure project plans to boost its electricity production and distribution, and to facilitate economic growth.

One of the priorities in the government of Indonesia’s National Medium-Term Development Plan (Rencana Pembangunan Jangka Menengah Nasional or RPJMN), 2015–19 is to enhance domestic energy security.

Within the sector, the Electricity Power Supply Business Plan (Rencana Usaha Penyediaan Tenaga Listrik or RUPTL) provides a 10-year plan (2016–25), which also includes changes to the five-year Electricity Development Plan – the third fast track programme (FTP3) launched in 2015 to add 35GW of power by 2019.

Ten-year power plan The release of the 2016–2025 RUPTL electricity supply plan, in June 2016, provides significant insight into the future growth plan of the Indonesian power network. It reveals how the state-owned electricity company Perusahaan Listrik Negara (PLN) is planning to expand the generation capacity and distribution network of

58

electricity, across the Indonesian archipelago.

The RUPTL also indicates the projects that are planned to be developed by PLN, and those that are available for independent power producer (IPP) investors (Table 1).

to be constructed by 2025, representing a 156% increase over the forecast period.

The RUPTL specifies that 18.2GW of plants planned will be constructed by PLN and 45.7GW by IPPs. The remaining 16.6GW has not yet been allocated. With such projects due to come online, Indonesia’s current energy consumption of 224TWh is forecast to grow to 457TWh by the year 2025 (Figure 1).

The growth of electricity sales in the past five years has averaged 8.1%. PLN plans for a growth forecast of 8.6% during the next 10 years, within an overall economic growth target of 6.7%.

Indonesia’s current generation capacity is listed at 51.35GW and to achieve the nominated level of electrification, the RUPTL indicates at least 80.5GW of power plants will need

The projected energy mix, for new generation capacity to be added in the next 10 years, is 43% coal, 29% gas, 13% hydro, 8% geothermal, 5% pumped storage and 2% other energy sources (Figure 2).

Figure 1. Forecast of electrical energy growth across Indonesia 2016-25 318 TWh 83 33 TWh TWh

Kalimantan: 10% 168 TWh

Sumatra: 11%

457 TWh

56 24 TWh TWh

Indonesia Timor: 10.6% Maluka: 11.1%

224 TWh

Papua: 9.6%

Java-Bali: 7.8%

Nusa Tenggara: 9.1% 2016 2025 Indonesia: 8.6%

Source: 2016–25 RUPTL, PLN

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EIC Global Energy mix

will be used for peaking power plants rather than for base-load power plants.

Figure 2. Indonesia’s energy mix 2016-25

5%

The RUPTL also plans for the 500kV High Voltage Direct Current (HVDC) transmission lines connecting Sumatera and Java to deliver electricity from coal mine-mouth power plants in Sumatera, to the more populous Java Island.

2%

13%

Key n Coal

A new focus on renewables

43%

Indonesia has significant renewable resource potential (Table 2) but suffers from underdevelopment.

n Geothermal n Gas n Hydro n Pumped storage n Other

Hydro generation is currently the largest single renewable contributor to the Indonesian electricity grid with around 8GW installed.

Indonesia has been estimated to having the third largest geothermal resources in the world.

However, only 1.34GW of generating capacity has been installed. Wind energy is in its infancy with only 1.4MW installed, while biomass energy accounts for about 1.7GW of installed capacity.

29%

8%

Coal dominates With proven reserves of 28bn tonnes and potential resources of 120bn tonnes, and the relatively lower costs of construction and operation, coal will continue to play a vital role in the development of new installed capacity in Indonesia for the next decade.

Coal mine-mouth power plants are fundamental to PLN’s plans, given Indonesia’s large lowrank coal deposits are often located in remote areas without adequate infrastructure – for the secure and efficient transfer of coal from mine to power plant – making transportation of the coal uneconomic.

Table 1. 2016–25 RUPTL plans for IPPs Fuel source

Allocated GW

Unallocated GW

Coal

25.12

1.71

Gas/Combined Cycle

6.78

9.31

Hydro (including mini-hydro)

6.79

2.03

Geothermal

5.06

0.69

Solar

-

2.90

Other

1.92

-

45.67

16.64

Source: 2016–25 RUPTL, PLN

Although conventional coal-fired plants will be the focus, the government and PLN are also moving ahead with new cleaner coal technologies including supercritical and ultrasupercritical, which use high pressures and high steam temperatures to generate electricity more efficiently and produce fewer emissions.

The RUPTL sets out plans to meet the government’s revised renewable energy target of 23% by 2025. There is 22.2GW of renewable generating forecast to be developed from renewable sources during the 10-year period including 13.1GW of large hydropower and 1.37GW of small hydropower planned, 6.15GW of geothermal, 444MW of solar PV, 640MW of wind, and 488MW of biomass/biogas. PLN also plans to use over 3,000 kilolitres in biofuel in diesel generators over the next 10 years (Table 3).

PLN has expressed interest in other clean coal technologies including coal-drying, coalblending, slurry (liquid coal) and SynGas. And while Indonesia’s gas and coal-fired power plants will offer opportunities to develop commercial-scale carbon capture and storage (CCS) in the future, CCS has not yet been planned for in this RUPTL.

Changes to fast track power plan In May 2015, the Indonesian government released the third installment of RPJMN for 2015–19 with the third fast track programme (FTP3), to complete 35GW of power generation projects by the end of 2019.

Indonesia has 104.7tn cubic feet (Tcf) proven and 48Tcf potential gas reserves.

Even though Indonesia has large reserves, in reality there is insufficient gas available for power generation. The supply of gas to the existing power plants has been and will be declining such that a deficit in gas supply is expected if there is no new gas supply.

The 35GW plan seeks to improve energy efficiency and increase the use of renewable energy, while expanding electricity access to all Indonesians and increasing per capita consumption from the current 840kWh to 1,200kWh per year. The intention is to increase the overall electrification ratio from the current 82% to a target electrification ratio of 97% by 2019. The delivery of the 35GW would be split between PLN (10GW) and IPP investors.

PLN plans for the use of liquefied natural gas (LNG) for gas-fired power plants.

However, because of the high cost of LNG given the need for regasification, the LNG

Table 3. Renewable energy development plan 2016-25 Table 2. Renewable resources in Indonesia Energy source

Estimated resources

Plant type

Capacity 2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

Total

Hydro

MW

45

57

175

1,405

147

330

639

2,322

2,031

5,950

13,100

Geothermal MW

85

350

320

590

580

450

340

935

1,250

1,250

6,150

Mini hydro

MW

32

78

115

292

81

86

196

26

257

201

1,365

Solar

MWp

26

122

70

50

118

11

10

17

10

10

444

Hydro

75GW

Wind

MW

-

70

190

165

195

10

-

5

-

5

640

Biomass

50GW

Wind

9GW

Biomass / Waste

MW

125

142

135

11

21

11

-

21

15

6

488

29GW

Bio-fuel

10^3 Kl

812

594

365

261

230

170

173

179

189

191

3,165

312

819

1,005

2,513

1,142

898

1,185

3,326

3,563

7,422

22,186

Geothermal Solar

4.8kWh/m2day

Source: 2016–2025 RUPTL, PLN

Total MW

Source: 2016–25 RUPTL, PLN

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EIC Global Table 4. 35GW programme changes

achieved. Based on the forecast growth, PLN must deliver in excess of 8GW to the grid each year for the next 10 years with 42GW between now and 2019.

35GW programme 2015 Developer / fuel source PLN

Coal

Gas

Hydro

Geothermal

Other

Total (GW)

2.2

7.0

1.2

0.1

0.1

10.6

IPP

18.1

6.6

1.1

–

0.1

25.9

Total (GW)

20.3

13.6

2.3

0.1

0.2

36.5

Hydro

Geothermal

Other

Total (GW)

35GW programme 2016–25 RUPTL Developer / fuel source

Coal

Gas

PLN

2.2

6.8

1.4

0.2

-

10.6

IPP

17.6

6.1

0.6

0.5

0.2

25.0

Total (GW)

19.8

12.9

2.0

0.7

0.2

35.6

Source: PwC The 2016–25 RUPTL includes changes to the 35GW programme – which actually targeted 36.5GW of power generation – and reduces planned new capacity to 35.6GW. Coal and gasfired generation has been cut by approximately 400MW and 700MW, respectively, while hydro has been reduced by 300MW and geothermal increased by 600MW (Table 4).

In May 2016, Indonesian President, Joko Widodo, called for a review of the 35GW programme to look at aspects ranging from the tender process to financing and management by PLN. Previous fast track expansion programmes namely FTP1 and FTP2, which had targets of 10GW each, had a variety of issues including land acquisition, financing and procurement. There is a total of 6.8GW that still remains incomplete.

Reform The 35GW announcement by the government included a range of changes to government regulations to address the issues identified in previous programmes. These included accelerating the availability of land as per Law 2/2012 on land acquisition and providing a price negotiation process by setting a benchmark price for private and excess power purchase by PLN. The long development process time due to procurement procedures, could, in some cases add 6 to 18 months to the total execution period, which, when executing a coal-fired steam power plant project over a typical period of 36 months could extend the overall project period in excess of four-and-a-half years.

Steps have been taken by PLN to reduce this time period in terms of internal procedures and working with selected tenderers to reduce the financial close period. There have also been changes to speed up the procurement process with reference to Law 3/2012 with alternatives for direct appointment or direct selections for new renewable energy generation, mine-

60

“The projected energy mix, for new generation capacity to be added in the next 10 years, is 43% coal, 29% gas, 13% hydro, 8% geothermal, 5% pumped storage and 2% other energy sources” mouth coal projects, marginal gas projects and expansion options to existing generators.

Ensuring the performance of developers and contractors through a reliable and comprehensive due diligence process has seen the procedures tighten accordingly.

Changes to the control of projects have been made by setting up a project management office to monitor and report on the status of the projects and to report consistently on the overall completion status of the projects.

PLN’s financing issue of not being able to secure the necessary funding in the requisite timeframe was resolved by moving the execution methodology from an engineer, procurement and construction (EPC) platform to one of IPP. Under the IPP model, the investor is required to provide the funding for the project. This move has meant that around 29GW of the 35GW programme will be executed on an IPP or mine-mouth basis with private investment. The remaining 6GW is to be executed by PLN with funding mixed between PLN’s own internally funding and credit facilitated by successful tenderers.

Future outlook The task ahead for Indonesia is considerable, if the electrical energy goals are to be

The country is open to adopting nuclear energy to fulfil baseload electricity needs and has included it in the 2016–25 RUPTL to add 3.6GW of new nuclear capacity. Costs have been estimated at US$6,000/kW of installed capacity, however, given the long lead times of nuclear, the final cost may be significantly higher.

While massive new investment in power generating capacity is being developed, the move to more renewable energy sources is being skewed by the enormous reserves of coal Indonesia has at its disposal. To achieve capacity growth, Indonesia must consider other viable forms of electricity generation including large-scale solar farms, like its other South East Asian neighbours.

Opportunities PwC reports that construction of this level of power generation will require investment of at least US$31.9bn by PLN, and US$78.2bn from IPPs. As such, over the next 10 years, the private sector will play a greater role than ever in development of the Indonesian power sector. In addition, PLN will also need to invest around US$43.7bn for expansion of the transmission and distribution networks.

The government allows foreign investors to have 95% ownership of power plant projects, built under public-private partnership, during the project concession period.

Despite potential challenges the country’s programme represents lucrative prospects for players throughout the value chain.

Opportunities include: • Engineering, construction, operation and maintenance of new power plants (mostly coal-fired plants) • Development of transmission and distribution network • Substation equipment • Refurbishment and upgrade of state-owned generating plants • Asset management The article acknowledges data sourced from PwC, RUPTL, PLN and the Ministry of Energy and Mineral Resources of the Republic of Indonesia.

Power Consultants Indonesia (PTPCI) is an established power and mining consultancy with a specific focus on commercial, technical and regulatory aspects in the power and mining industry. www.ptpci.com

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EIC Global

OSEA 2016: the gateway to one of the world’s fastest growing regions The EIC’s UK pavilion at OSEA will be one of the first stops for over 18,000 delegates looking for the cutting-edge products and technical expertise the UK oil and gas industry is famous for worldwide

S

howcasing the most innovative products the oil and gas industry has to offer, OSEA attracts operators and contractors from around the world making it the ideal venue to meet new buyers and potential local partners. This year’s OSEA, the 21st edition of Asia Pacific’s premiere oil and gas event, takes place in Singapore, 29 November to 2 December.

As well as its exhibition, this year’s OSEA conference deals with the ever increasingly important area of asset management.

Extending the life of assets and enhancing existing infrastructure is seen as critical in the current down cycle market.

The International Energy Agency estimates that over the next 20 years South East Asia’s energy demand will surge by 80%. Furthermore, over the next five years, the region is expected to receive record levels of offshore investment, fuelling the expansion of its upstream industry.

For those companies which want to make the most of the lucrative opportunities this market offers there is no better event than OSEA 2016.

Rapidly developing infrastructure to allow the efficient commissioning of the region’s vast resources combined with a lack of local capacity means this is an ideal time for supply chain companies and contractors to consider expanding into this market.

The South East Asia region is the seventh largest in the world and is forecast to become the fourth largest single market after the EU, US and China by 2030.

OSEA 2016 is expected to attract over 18,000 visitors and 1,300 exhibitors

“The International Energy Agency estimates that over the next 20 years South East Asia’s energy demand will surge by 80%” In 2016, the top five countries leading offshore projects in this region are Indonesia, Malaysia, Thailand, Vietnam and Philippines with total investment for projects under development or planning amounting to approximately US$183bn.

The government of Indonesia aims to develop five floating storage and regasification units (FSRUs) in 2017 in a bid to improve domestic gas infrastructure and increase the use of natural gas in its domestic market. According to its Energy and Mineral Resources Ministry the FSRUs are expected to be operational in 2018. There are plans in place to increase the number of FSRUs to nine by 2020.

There are significant offshore projects taking place in Malaysia such as the Bokor Phase III field development. The project will include a 16,000 tonne central processing platform with a contract award expected by the end of 2016 or early 2017. Elsewhere in the country,

a new gas discovery was made offshore Sarawak in Block SK408 by SapuraKencana Energy which contains an estimated multi-trillion cubic feet of gas reserves.

Decommissioning activity in South East Asia is set to soar over the next decade. Indonesia, Brunei, Malaysia and Thailand are home to about 833 offshore installations that are 20 years old or more – the average life expectancy of offshore assets. Major operators, namely PETRONAS and Thailand’s PTT Exploration and Production Public Company Limited have already listed platforms to be decommissioned and feasibility studies are under way.

The South East Asia region is full of opportunities, however, each country comes with its own set of challenges, none the least is the need to find and work with local partners as well as learning how to successfully work with the region’s major operators. OSEA is the perfect forum to meet with potential local partners as well as understand the regional operators’ procurement and project requirements. n

Contact: Mark Gamble Senior Overseas Events Manager Tel: +44 (0) 207 091 8600 Email: mark.gamble@the-eic.com

61

EIC Global

North and Central America In the US the downstream sector continues to flourish, propelled by low LNG costs. Mexico’s upcoming Round 1.4 deepwater auction is attracting considerable attention while Canada pursues an ambitious carbon emission reduction plan

M

exico’s highly anticipated deepwater Round 1.4 auction will be held on 5 December 2016, and is drawing a considerable amount of attention. The field expanded to 31 global majors and independents and the final list of bidders was published on 24 August.

Companies that requested prequalification included Chevron, ExxonMobil, Shell, BP, Anadarko, Hess, Total, Statoil, and BHP Billiton. The blocks available represent 10bn barrels of oil equivalent, which the Mexican government hopes will bring investments of US$4.4bn. Almost US$1bn of pipeline contracts in Mexico have been awarded in 2016, which is the beginning of a larger, US$12bn plan to build 12 natural gas pipelines totalling 5,000km over the next five years.

Mexico held its first electric power auction on 30 March, in which it received 227 offers from 69 local and foreign prequalified bidders of which it granted 18 offers to 11 firms.

All awarded projects comprised of wind and solar, with the majority scheduled to enter operation in 2018. The country is also researching the feasibility of incorporating more biomass into its electrical generation. In an attempt to address the country’s significant infrastructure deficiencies, Mexico is aiming to construct 25,000km of transmission lines and achieve an investment of over US$13bn within the next 15 years. Opportunities have been present in Central America as well.

Panama and Colombia have announced a public tender to be launched in mid-2017 for a 600km transmission line to link the two countries’ grids. The interconnection will have an initial transmission capacity of 400MW and use bipolar, direct current technology.

In August US regulators launched the Gulf of Mexico Lease Sale 428, which included all unleased areas off Texas, totalling 4,343 blocks. The available areas ranged from 9km to over 400km offshore, and in water depths from 5m to 3,345m. Operators requested that contractors revisit their initial bids and lower their costs in order to improve the capital efficiency of the major projects.

The US has begun exporting LNG, however, the exportation business is not expected to make a significant impact in the near future. The downstream industry continues to flourish, as new projects continue to

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The US solar market is expected to grow by 119% in 2016, with installations set to total 16GW (photo: National Renewable Energy Laboratory)

“Almost US$1bn of pipeline contracts in Mexico have been awarded in 2016 as part of a plan to build 12 natural gas pipelines totalling 5,000km over the next five years” be uncovered and previously abandoned projects are resurrected. Low LNG costs will continue to propel the downstream industry.

The extension of the Production Tax Credit and Investment Tax Credit have proved to be highly beneficial to the US renewable industry, as new-build construction continues to rise, primarily in wind and solar. The US solar market is expected to grow by 119% in 2016, with installations set to total 16GW. The US Bureau of Ocean Energy Management issued a call for interest in developing offshore wind projects in Hawaii this summer. Nearly 18GW of electrical generation was retired in 2015, and more than 80% of that was coal fired. Natural gas-fired generation is expected to surpass coal in 2016.

Market conditions combined with wildfires in the spring have limited oil sands production in Canada. However, the governments of Nova Scotia and Canada opened competitive bidding for exploration licences for six blocks off the province. The deadline for bids for these blocks was October. Regulators in the province of Newfoundland and Labrador have issued two calls for bids for new acreage off the country’s Atlantic coast.

These bids are due in November 2016.

Canada has become a global leader in renewable energy construction. The province of Alberta plans to issue its first competition for renewable projects in late 2016 in an attempt to curb carbon emissions. The province of Ontario has also launched a request for qualifications as it aims to double the amount of renewable energy it plans to procure this year. Nuclear power is being utilised as an economically efficient way to meet Canada’s global climate change obligations and reduce carbon emissions. All current nuclear construction in the country consists of unit refurbishments to existing plants. n

Contact: EIC Houston office Tel: +1 713 783 1200 Email: houston@the-eic.com

www.the-eic.com

EIC Global

South America South America’s energy market is undergoing a period of transition following economic and political reforms. Brazil and Argentina are the countries with most oil and gas potential while Chile remains a regional leader in the PNR segment

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t the time of writing, Petrobras’ business plan for 2016–20 is expected to be released in early October. The company’s new management, appointed by interim Brazilian president Michel Temer, has committed to a US$15bn divestment plan for 2016 while also focusing on the development of pre-salt fields.

Legislation removing the requirement that Petrobras must operate all pre-salt assets is expected to be approved by the lower house of Congress by the end of the year. Shell’s acquisition of BG has greatly increased its participation in pre-salt assets and the company has pledged to focus its E&P efforts in Brazil and the Gulf of Mexico in the coming years. Statoil and Karoon, meanwhile, are expected to issue tenders for the construction of production units for their respective projects in the country.

The power, nuclear and renewables (PNR) sector remains strong in Brazil, particularly the wind and hydro segments.

Solar is also expected to pick up as panel manufacturers set up plants in the country.

Delays in the construction of transmission infrastructure, however, pose challenges to many developers. Earlier this year, the transmission and distribution market was shocked by Abengoa’s local unit filing for bankruptcy, which has put concessions for key transmission projects in the country on hold. Government authorities are likely to put the projects up for auction for a second time in order to guarantee their development.

In Argentina, Ricardo Darré, a former Total executive, has been appointed as CEO of YPF. Darré’s appointment comes at a time when the company is prioritising the development of Argentina’s massive shale gas resources, estimated at 801tn cubic feet. In the PNR

YPF is focusing on developing Argentina’s massive shale gas resources, estimated at 801tn cubic feet

“Petrobras has committed to a US$15bn divestment plan for 2016 while also focusing on the development of pre-salt fields” segment, in June the government received a total of 49 bids from 22 companies in a tender for the supply of 1GW of installed capacity. Both the oil and gas and power generation sectors are set to benefit with the end of Argentina’s long-standing dispute with international hedge funds over defaulted bonds, after a settlement was reached in April.

The move will allow the country to re-gain access to international capital markets and obtain crucial financing for energy projects.

PNR remains a buoyant market in Chile, where President Michelle Bachelet has signed a decree approving the government’s Energía 2050 energy programme which sets a goal to produce 70% of electricity from renewable sources by 2050. Currently, Chile produces approximately 47% of its power from renewables, including hydro (40.7%), wind (3.6%) and solar (2.43%).

Peru held general elections in June and Pedro Pablo Kuczynski was elected as the country’s new president, narrowly beating rival Keiko Fujimori. A former energy and

mines minister, Kuczynski is keen on attracting private investment to Peru’s gas sector, focusing on the development of new gas fields and related infrastructure as well as the construction of gas-related downstream projects such as fertiliser plants and ethylene/polyethylene plants.

Down in Uruguay, Gas Sayago has resumed the development of a liquefied natural gas import terminal following the departure of Engie and Marubeni from the project in 2015.

The company has invited tenders for the construction of the terminal, which will feature a floating storage and regasification unit with a capacity of 353m cubic feet per day. The terminal will allow Uruguay to export gas to Argentina via the existing Cruz del Sur pipeline.

Venezuela’s troubles have yet to show signs of receding as the country’s economic crisis continues to escalate. Inflation rates are expected to increase to 480% in 2016 and the International Monetary Fund says it could skyrocket to 1,642% in 2017. According to the World Bank its economy is expected to contract by 10.1% in 2016. The downturn of oil prices is one of the key causes of Venezuela’s woes, as the country – an OPEC member – is highly dependent on oil revenues. n

Contact: EIC Rio office Tel: +55 21 3265 7400 Email: rio@the-eic.com

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EIC Global

Russia and Caspian Gas supply and pipeline projects continue to dominate the region while the Caspian Sea canal project shows signs of actually developing from myth to reality

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s a result of the current economic austerity which Russia is experiencing, it has made a number of conciliatory approaches to some of its neighbours, seeking out new avenues of investments, most of which have been focused on gas and security of supply. To this end, discussions have been taking place with Azerbaijan, Turkmenistan, Uzbekistan and of course, no surprise, Iran.

The prime beneficiary from these proposals has been Uzbekistan. Following high level talks between the leaders of the two countries, it was announced that Russia intends to invest up to US$12bn in various projects during the next five years. This came soon after a huge gas refinery built by Lukoil began production and Gazprom started to take more gas than specified in its original three-year agreement.

Both companies are the main recipients of this investment with Lukoil signing a production sharing agreement to develop six gas condensate fields plus a further area in the south-west of the country. Meanwhile, Gazprom signed a deal to take volumes of gas that were four times more than those agreed in 2015. This is all good news for Uzbekistan at a time when South Africa’s SASOL announced that it was reviewing its plan to partner with the local national oil company, Uzbekneftegaz, to establish a gasto-liquids plant with a similar design to the plant they established in Qatar back in 2007.

In Turkmenistan, the first 214km section of a pipeline planned to cover Afghanistan and Pakistan leading eventually across to India, is under construction. The 1,800km line is expected to deliver 33bn cubic feet of gas per year by 2020. However, it is still not clear how the project will be financed given that the estimated cost of US$10bn represents about a third of the country’s total budget.

“Russia intends to invest up to US$12bn in various projects in Uzbekistan over the next five years” Azerbaijan has said that its main goal is to increase its current gas production sevenfold by 2050. The prime source will be the huge Shah Deniz field. There are also plans to exploit a further six known fields over the next 20 years.

There was also some good news concerning the Trans Anatolian Pipeline project that is designed to bring gas into Central Europe.

Due to the current industry depression, the original expected cost of US$11.7bn has been cut to US$9.2bn. However, the project is progressing with 893km of pipework already positioned. Meanwhile work continues on the new receiving terminal and it has been announced that a further US$28bn of investment will be required to complete the planned 3,500km South Caucasus Pipeline Expansion pipeline to Turkey.

Finally, given the current geopolitical climate that exists across the Gulf region, it is interesting that a project originally conceived as being overly ambitious to say the least, should suddenly become a hot topic of

Work is progressing on the Trans Anatolian Pipeline project with 893km of pipework already laid

discussion. Building a canal from the Caspian Sea through Iran to either the Persian Gulf or Gulf of Oman is not a new idea. Two routes, one following a western path, another following a path through the west of Iran, have been put up for discussion and consideration. Each route has its own merits for both Russia and Iran. No matter which route is chosen, of primary importance to Russia is raising the profile of its southern city of Astrakhan. St Petersburg is cited as the ‘Russian window to the West’ and Vladivostok carries a similar title of the ‘Russian window to the East’. The plan is that Astrakhan be established as the final ‘window to the south’. For Iran, it would cement stronger ties with Russia along with its Caspian neighbours while at the same time providing more access to India. From an economic perspective, the eastern route is a non-starter due to geographical and cost considerations. Currently, this is still ‘blue sky thinking’ but knowing how Russia is moving both economically as well as politically, it could well become reality within the next decade. n

Contact: Terry Willis, Director, Middle East Africa and CIS Tel: + 9 714 602 6001 Email: terry.willis@the-eic.com

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EIC Global

Indian subcontinent, Pakistan and Afghanistan With India’s energy demand continuing to rise at a dramatic pace and its oil consumption reaching 4.2m barrels per day this year, the government is focusing on reducing its dependence on crude imports. Elsewhere in the region, Pakistan has identified LNG as the means of plugging its energy gap

Pakistan is developing its LNG capacity

I

ndia is set to contribute more than any other country to the rise in global energy demand over the next 25 years, underlining its ever-increasing influence on the world stage. Its oil consumption hit 4.2m barrels per day (MMbbl/d) this year, surpassing Japan’s 4.1MMbbl/d, and is forecast to rise to 6MMbbl/d by 2040, compared to the 4.8MMbbl/d predicted for China, according to the International Energy Agency.

India’s state-owned oil and gas company, Oil and Natural Gas Corporation (ONGC) plans to spend approximately US$662bn by 2030 to raise output – this is key to Prime Minister Narendra Modi’s target to cut crude import by 10% within the next six years. Despite the country’s large hydrocarbon reserves, it is still heavily dependent on oil imports, as its own resources remain highly undeveloped.

The government’s new liberal approach is encouraging investors to exploit these reserves. With its new policies the government aims to boost gas output by 1.24bn cubic feet per day (Bcf/d) and make US$27bn of project investments throughout the next five years. About 90% of the new investments will be on test drilling and putting the necessary infrastructure in place to develop projects efficiently.

ONGC expects first gas from the KrishnaGodavari Basin block by mid-2019 with a peak production of 529m cubic feet per day (MMcf/d), while crude oil output will begin a year later and may increase to 77,000 barrels per day.

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“India is moving toward renewables quicker than anyone expected, driven by proactive renewables investment” India’s shift towards cleaner energy sources has been particularly surprising. The country faces similar challenges to Indonesia – having coal as its prime source of power generation as well as a densely populated country with a growing economy and vast energy demands – yet it is moving toward renewables quicker than anyone expected, driven by proactive renewables investment by the government.

Solar power is the fastest growing new source in India, which accounted for 17.4% of all renewable energy in 2016, a rise from 10.5% in 2015. India’s solar project pipeline has now surpassed 22GW with 13GW under construction and 9GW in the request for proposal stage.

Global clean energy research company, Mercom Capital Group, estimates solar installation in India to total 5GW as at 2016.

State-owned Bangladesh Oil, Gas & Mineral Corporation (Petrobangla) and Excelerate Energy L.P. have signed an agreement to build Bangladesh’s first floating storage and regasification unit (FSRU) to boost natural gas supply by 500MMcf/d. At a projected cost of US$1.6bn, the FSRU will be located at the island of Moheshkhali in the Bay of Bengal, offshore Bangladesh.

In Pakistan, the government has made it clear that liquefied natural gas (LNG) will be the primary source of fuel for the energy-starved economy in the medium to long-term. A framework agreement has been signed between the country’s National Energy Administration, the Ministry of Petroleum and Natural Resources, and China Petroleum Pipeline Bureau for the development of the Gwadar-Nawabshah LNG terminal with a capacity of 600MMcf/d.

A 700km gas pipeline project is under way as part of the development. The terminal and pipeline project is expected to be completed by 2018. The pipeline project forms part of the China-Pakistan Economic Corridor framework agreement. Another LNG development is being undertaken by Pakistan LNG Company Limited, which is carrying out feasibility studies for what would be the country’s second LNG terminal.

An initial investment agreement of US$200m has been signed for the TurkmenistanAfghanistan-Pakistan-India (TAPI) gas pipeline project by all four countries and will go towards engineering studies for the pipeline.

Turkmenistan is expected to achieve financial close by December 2016 for the project to develop the gas field and construct the pipeline with completion expected by December 2019. Despite these positive developments there are security concerns about some of the areas over which the pipeline will run. n

Contact: Terry Willis, Director, Middle East Africa and CIS Tel: + 9 714 602 6001 Email: terry.willis@the-eic.com

www.the-eic.com

EIC Global

Sub-Saharan Africa

In East Africa, recent gas discoveries would suggest that if efficient recovery and distribution channels could be established then this situation could be easily addressed. Overall, it is estimated that there is more than 15bn cubic feet of gas reserves across this area alone, which would be more than enough to overcome the shortage, but as with all hydrocarbon developments, the issue is essentially available finance and developing resources in an efficient way.

Mozambique and Tanzania lead the way in terms of sizable discoveries, however, these will rely on international oil companies (IOCs) providing foreign investment to develop these rich reservoirs. In Mozambique, Anadarko and Eni are the major players but both companies are being ultra-cautious before reaching any final investment decisions. There are considerable bureaucratic hurdles to overcome and of course they have to determine if there will be an acceptable return on investment.

Nevertheless, the signs are positive that these developments will eventually get the green light.

A similar situation exists in Tanzania although from a development programme perspective, they

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hen it comes to energy, the Sub-Saharan Africa region is still finding it very difficult to achieve some form of balance between available resources and domestic demand. While the region accounts for 13% of the global population, it can only account for 4% of its own energy demand despite having sizeable known hydrocarbon reserves. In effect, this means that two-thirds of the population still remain without access to electricity. To put this into context, across the Organisation for Economic Cooperation and Development member countries gas accounts for 24% of power generation while globally the figure is around 22% but in Africa it is less than 14%.

So, how can this shortfall be addressed?

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Sub-Saharan countries are still struggling to meet their domestic energy needs and while some sizeable hydrocarbon discoveries have been made, notably in Mozambique and Tanzania, these will require significant investment from IOCs to be developed efficiently

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are slightly behind Mozambique. The situation has become more clouded following the takeover of BG by Shell which has yet to announce its intentions with regard to the offshore discovery BG made in partnership with Statoil.

Moving on to West Africa, in the region’s leading hydrocarbon producing country, Nigeria, President Muhammadu Buhari has overseen a complete reorganisation of the national oil company, Nigeria National Petroleum Corporation and has announced high profile arrests of past directors suspected of corrupt business practices as well as considerable recoveries of unaccounted financial assets. This is certainly a step in the right direction but a high degree of social unrest continues to plague any positive developments to improve the country’s balance of wealth.

Ghana’s GDP has hit some hurdles with the most serious being the unexpected delay in bringing the offshore Jubilee field on-stream to full production. Tullow Oil, the prime operator announced that there was some damage to the turret on the FPSO Kwame Nkrumah which resulted in the company having to announce a force majeure on two cargoes and then revise downwards production and offtake numbers significantly until an effective repair could be completed. However, Ghana also announced

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some good news by stating that that the Sankofa development operated by Eni is being accelerated and first oil is expected to be delivered in mid-2017 with first gas available in 2018.

Petrofac secured its first contract in Angola where Eni awarded its Engineering Production Services Division a three-year deal to deliver a condition monitoring programme for its Bumi Armada Olombendo FPSO which will be located offshore towards the end of this year. Meanwhile, Cairn Energy endorsed their completion of a multi-well evaluation in Senegal which has the potential to be a world class asset.

Finally, the President of Angola, José Eduardo dos Santos has appointed his 43-year-old daughter Isabel dos Santos as CEO of the state-run energy giant, Sonangol, who then immediately announced a radical reorganisation by setting up three new units, one to oversee its oil operations, another to focus on logistics and the last to manage all the concessions held by IOCs. n

Contact: Terry Willis, Director, Middle East Africa and CIS Tel: + 9 714 602 6001 Email: terry.willis@the-eic.com

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Oil and Gas

The UK prepares for decommissioning

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Driving technological innovation in the North Sea

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Glocalisation: thinking globally acting locally

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Beyond pre-salt: offshore frontier exploration in South America

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Contracting in the new era

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The UK prepares for decommissioning

Oil and Gas

by Roger Esson, CEO, Decom North Sea

With an estimated £17bn to be spent during the next decade on cleaning up and removing ageing oil and gas infrastructure, the North Sea decommissioning market is set to take off in a big way, offering a significant opportunity to the supply chain

O

il and Gas UK’s 2016 Activity Survey reveals that the pace of decommissioning on the UK continental shelf is accelerating.

Over the last year, the number of fields expected to cease production between 2015 and 2020 has risen by a fifth to over 100 and reserves reported by companies for potential future development have fallen from 10 to 8.8bn barrels of oil equivalent (boe).

Once a job that was considered ‘something for the future’, and overshadowed by the big money in exploration projects, decommissioning is now being viewed as an opportunity for the supply chain. If this sector is not part of your company’s growth plans, it should be.

Decommissioning set to ramp up In total, there are over 600 offshore oil and gas installations in the North Sea, 470 of which are in UK waters. These include subsea equipment fixed to the ocean floor as well as platforms ranging from the smaller structures in the Southern North Sea (similar in size to Big Ben) to the enormous concrete or steel structures as big as the Eiffel Tower and much heavier in the Northern North Sea. Offshore there are also more than 10,000km of pipelines and approximately 5,000 wells to be taken into consideration.

With decommissioning expenditure in the North Sea set to increase from the current £1bn per year, there is an important balancing act to be undertaken; it is crucial that the supply chain

“If this sector is not part of your company’s growth plans, it should be”

opportunities are maximised but this must be within the context of optimum cost-efficiencies.

As the decommissioning industry’s only independent members’ organisation, we focus on this as a fundamental to a successful future.

Focusing on all aspects of the decommissioning value chain, from solution development and cross sector learning to helping to build supply-chain capability, we work with a number of strategic partners including the Oil and Gas Authority to achieve these objectives.

So how does decommissioning fit into the current, challenging economic climate? Over the past 18 months, the drop in oil price has

The last day of production on Miller took place in July 2007. Since then, BP has undertaken well abandonment and topsides clean up on the asset and anticipates that the topsides will be removed during 2017 or 2018 (photo: BP) led to a number of difficult decisions for those with the unenviable task of cutting costs where CAPEX has been significantly reduced, resulting in deferred or cancelled projects. The supply chain has been squeezed and headcount has reduced considerably, but does this translate into a push towards decommissioning?

Ready for action Across the industry, it is clear that the desire is there to maximise economic recovery, maintaining existing infrastructure for as long as it remains efficient and cost-effective.

Equally however, it is recognised that now is the time to really understand – and become an integral part of – a robust decommissioning supply chain, making sure that we are all ready for action, when the time comes.

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Oil and Gas So premature decommissioning is not on the agenda – far from it. Rather, Decom North Sea’s aim is to shift the decommissioning focus from purely post-cessation of production, and for good reason. We are paying close attention to the late life phase, ensuring it is managed as effectively as possible; in other words, we are looking at what can industry can do now, which will benefit future decommissioning projects.

A complex process Across the globe, decommissioning is now recognised as a critical – and inevitable – stage in the life of an installation; it is not an isolated project. Offshore decommissioning is a complex, years-long, series of activities, each calling for its own level of skill and expertise.

From operations to communications, engineering to legislation, each strand is vital. Understanding how a platform was installed, how it was operated, and the expectations for when it reaches the end of its life is a collaborative process which requires transparent knowledge sharing over a considerable period of time.

Collaboration is key To achieve this, we work to bring the regulators, operators and supply chain together. Ultimately, Decom North Sea exists to help raise the profile of SMEs across the industry, facilitating their relationships with operators and Tier 1 contractors, providing an in-depth understanding of the late life and decommissioning scope and legislation. That is the key to ensuring decommissioning work will be undertaken in a timely – and cost-effective – manner.

“Across the globe, decommissioning is now recognised as a critical – and inevitable – stage in the life of an installation”

The overarching aim of any fledgling industry should be to bring people from across a range of sectors together, in an open environment to discuss challenges and opportunities and, above all, to learn from one another.

To make decommissioning opportunities as efficient and effective as possible, Decom North Sea consistently encourages its members and others to share their experiences, to learn from one another, and ultimately benefit the industry as a whole.

Fundamental to that approach will be industry adoption of Decom North Sea’s Late Life Planning Portal, L2P2. Created in conjunction with representatives from the Regulator, operators and contractors, it provides the ultimate decommissioning toolkit: a repository for lessons learnt, a forum for discussion and a gateway to contacts, analytics and market intelligence.

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Once online, L2P2 will help oil and gas professionals to plan and execute projects. Its development marks a change in the mind-set of companies

When an industry is in its infancy, a toolkit such as this provides fundamental support in achieving the overarching objectives of efficiency, simplification, standardisation and cooperation.

As decommissioning activity increases, the importance of focused, standardised planning procedures increases and L2P2 will provide the toolkit to which industry can refer on all aspects during the entire decommissioning project, from early planning (i.e. pre-late life) through to application from regulatory compliance through to technology assessment and selection. This is powerful information. However, it will only be accessible if industry is willing to share its knowledge and experiences. From best practice and company guidelines, to case studies and lessons learnt, sharing experiences will build an invaluable knowledge bank for the entire decommissioning community.

Driving innovation The oil and gas industry has a responsibility to ensure that these fruitful relationships are built and maintained over the coming decades. Events such the annual Decom Offshore conference and the OGA’s recent Hackathons recognise that the supply chain is the source of the innovative technological solutions required to establish a highly competitive and capable new decommissioning sector for the whole UKCS. Hackathons – a concept originally developed by the computer programming industry (a great example of cross-sector learning in itself) – act as a platform for the supply chain to present directly to influential operators, facilitating cooperation on the challenges being faced.

Leading the way As an industry, we have an opportunity right now to effect a fundamental step change in our ways of working, our behaviour and culture – to effect transformational change, which will truly enable effective and efficient decommissioning.

Genuine cooperation occurs where there is trust, when operations are joint and when structures, teams and processes are aligned.

In this way, the UK can become a world leader in this critical phase in an oil field’s life cycle, with the opportunity to export this expertise on a global scale. However, this golden opportunity will only come to pass if companies put individual gains aside, to share and develop a collective approach.

The time for enabling effective and efficient decommissioning is now. Take advantage of the mechanisms in place to ensure you are a part of it. n

Decom North Sea is the UK-based industry forum set up to maximise the business opportunities presented

by North Sea decommissioning.

It focuses on all aspects of the decommissioning value chain. www.decomnorthsea.com www.l2p2.net

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Oil and Gas

Driving technological innovation in the North Sea

by Dr Angela Seeney, Director, Technology, Supply Chain and Data, UK Oil and Gas Authority (OGA)

Established to ensure key technologies are successfully developed and deployed to help maximise economic recovery of the UK’s oil and gas, the OGA’s MER UK Technology Leadership Board has a key role to play in the industry's future

T

he UK Continental Shelf (UKCS) is one of the world’s most mature, diverse and technologically advanced basins with a successful track record of developing and deploying new solutions throughout its 40-year production history.

In recent years, however, the industry operating on the UKCS has become increasingly fragmented, complex and slower to embrace innovation and ensure widespread deployment of new technologies in the field.

Meanwhile significant technological advances have been made and now present material opportunities to sustainably improve cost efficiency, risk mitigation and value creation across the oil and gas lifecycle.

Standardisation and collaboration can deliver the benefits of scale and timelier implementation but this requires a concerted effort to stimulate and attract the necessary investment in the UKCS during the downturn to effectively prepare for the upturn and enhance the approach towards developing new technologies.

The founding of the OGA From 2014 when the OGA was founded, as a direct recommendation of Sir Ian Wood’s review of the UKCS, industry bystanders have witnessed a steady fall in oil prices to hit a 13-year low of below US$28 a barrel at the start of 2016.

Although prices have increased to about US$50 more recently, this still represents a significant downturn for the global oil and gas market and the UKCS. What does this mean for future investment in technology and the UKCS’ supply chain, renowned for its innovative mind-set?

The overarching objective of the OGA is to implement the maximising economic recovery (MER) UK Strategy. Alongside its role as the authority, balancing regulation with a mandate to influence and promote MER solutions,

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Technology will play a bigger part in the future for the North Sea as recovering remaining resources becomes more difficult

“We now have a tangible opportunity and need to drive change forward and take advantage of the pioneering technology capability this industry has at its disposal to become more competitive”

licensing onshore and offshore oil and gas and carbon storage in a flexible and pragmatic way, the MER UK Strategy also explicitly cites the role technology has to play in achieving a sustainable future for the basin. It states: Relevant persons must ensure that technologies, including new and emerging technologies, are deployed to their optimum effect… in maximising the value of economically recoverable petroleum that can be recovered from relevant UK waters, including in relation to decommissioning.

www.the-eic.com

Oil and Gas Figure 1. MER UK Forum core work area boards Purpose

Objectives

Deliver tangible benefits in support of MER UK and maximising UK value from the oil and gas industry as a whole 1. Develop a clear strategy and five year plan 2. Create leadership alignment and leverage tripartite action 3. Deliver tangible and quantifiable results

Leadership

Industry-led with tripartite support

1

Exploration

2

Asset stewardship

3

Regional development and infrastructure

4

Cost & efficiency

Phil Kirk, Chrysaor

Ray Riddoch, Nexen

Paul Goodfellow, Shell

Walter Thain, Petrofac

Gunther Newcombe

Gunther Newcombe

Gunther Newcombe

Stephen Marcos-Jones

Core work areas

5

Technology

6

Decommissioning

Paul White, GE

TBC

Angela Seeney

Gunther Newcombe

Frequency: Quarterly

7

Supply chain, exports and skills

Neil Sims, Expro Group Angela Seeney

Support: OGA/Oil & Gas UK

Industry lead

Support lead

Focused priorities and action

“With the greatest range and concentration of upstream oil and gas expertise outside Houston, the UK has established itself as a global leader in oil and gas technologies�

Much has been said over the years about the importance of technology but never before has this been supported by legislation. We now have a tangible opportunity and need to drive change forward and take advantage of the pioneering technology capability this industry has at its disposal to become more competitive.

Given the challenging backdrop we are currently facing, now more than ever, is the time.

Technology opportunities and challenges With the greatest range and concentration of upstream oil and gas expertise outside Houston, the UK has established itself as a global leader in oil and gas technologies.

Considerable investment in field developments and rejuvenation by the industry has helped offset UKCS production decline, growing production year-on-year in 2015 for the first time in over a decade, which is a great achievement. However, more can be done to further improve economic performance and attract investment to more effectively unlock projects, maintain ageing assets and develop more marginal resources.

The UKCS faces unique and prevailing challenges of reduced investment budgets and higher costs, coupled with competing opportunities in other international basins and energy sectors. Therefore the ability of operating companies to invest in the basin has dropped significantly, resulting in a hiatus in the introduction of novel technologies.

This has also impacted the traditionally innovative supply chain companies who are finding it difficult to introduce transformative, efficient technologies, which the UKCS needs.

Unlike other capital intensive industries, the UKCS oil and gas sector does not have a centre of excellence for developing and delivering oil and case solutions.

Technology Leadership Board OGA is committed to engaging with industry to prioritise activities and identify areas where

we can facilitate further collaboration and conversation with other areas of government.

One of our early priorities was to simplify the industry landscape and integrate the many working groups that existed.

This resulted in the creation of the MER UK Forum which is designed to support the delivery of the MER UK Strategy.

It is focused on seven core boards (Figure 1), namely; exploration, asset stewardship, regional development and infrastructure, cost and efficiency, decommissioning and supply chain exports and skills and finally, the technology leadership board (TLB) which I co-chair alongside Paul White, Director Subsea Technology at GE Oil and Gas, who is the industry lead.

The TLB is comprised of senior representatives from industry, government and research institutions and has the remit to identify and align key technology priorities so that concerted efforts can be framed, planned and adequately funded, ensuring key technologies are successfully developed and deployed.

Technology innovation carries benefits right across the oil and gas lifecycle, from exploration and development to the late life and decommissioning stage so we work closely with our colleagues in other MER UK Boards.

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Oil and Gas

Nexen’s Buzzard oil field in the North Sea provides ‘new oil’ in a mature basin We are focusing our technology efforts on what the UKCS needs now to tackle immediate challenges, while also looking ahead to how we can further improve performance and grow our supply chain exports. Collaboration has an important role to play in aligning priorities and plans across the technology sphere to maximise UK-wide impact.

The TLB’s four themes were selected due to industry demand and the potential value they represent: • Small pools – The UKCS has approximately 300 unsanctioned hydrocarbon discoveries which are not pursued because of their marginal economic nature. Technology has a significant role to play from reducing the cost of development wells, to developing subsea infrastructure and tie-backs to existing host facilities or fit-for-purpose, efficient standalone concepts • Well cost reduction – aims to reduce total well cost by 50% to enable further UKCS development and incentivise drilling. Improving collaboration, drilling efficiency and processes as well as developing standardised well designs and scale economies in deploying efficient equipment for drilling and construction can impact this

Asset integrity – enhanced asset integrity inspections can improve late life and reduce operating costs. The adoption of existing technology from other sectors, such as aerospace and nuclear, could help achieve cost efficiencies and 15–20% higher production uptime. Positive results in the UKCS would attract significant interest from other international offshore basins • Decommissioning – utilise technologies to support cost saving targets of +35%. This focuses on two areas primarily: facilities and well plugging and abandonment and can deliver significant cost savings for the industry and treasury Encouraging progress has been made already. Recent work completed for the TLB Well Construction Cost Reduction workgroup reduced the cost of a typical well in one of the UKCS sub-regions by over 30% using existing, but underutilised technologies, which are able to simplify and significantly shorten the drilling process.

Cost effective well construction is of increasing importance, particularly for marginal field developments, including small pools and subsea developments, where well construction costs form a significant proportion of the overall field development costs. Although more work remains to be

“We are focusing our technology efforts on what the UKCS needs now to tackle immediate challenges, while also looking ahead to how we can further improve performance and grow our supply chain exports” 76

done to meet the 50% cost reduction target, developments so far highlight the benefits of a focused and collaborative approach.

In addition, the OGA is working closely with other parties in the development of the £180m Oil and Gas Technology Centre (OGTC), which was announced by the Prime Minister earlier this year as part of the 2016 Aberdeen City and Shire City Deal.

The vision for the OGTC is to become the ‘goto’ centre globally for solving offshore mature basin, subsea and decommissioning technology challenges. This includes taking forward the four TLB themes but also expanding to include subsea, digital and data, and other areas. It will be vital in ensuring that the UK builds on being a centre of operational excellence, cementing its position as a global technology development centre and helping anchor the supply chain and talent in the region.

The future A well-resourced and implemented technology strategy cannot be overstated. Exports of technology based services, and decommissioning activities have a £50bn per annum total value add potential. This supports thousands of companies, jobs and families across the UK. The OGA is committed to working with industry, government and the research community to enhance innovation in the UK’s oil and gas industry, promote and influence technological improvements which maximise economic recovery, reduce development and operational costs and capture broader economic value through retaining skills and growing exports.

With an estimated 20bn barrels of oil equivalent of recoverable hydrocarbon reserves remaining in the UKCS, the future of our revered industry depends on it. n

www.the-eic.com

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Orga Offshore T +31 (0)10 208 5566 E offshore@orga.nl www.orga.nl

Shining light on safety Offshore oil and gas workers around the world face some of the most dangerous conditions of any profession. The harsh open sea environment can be extremely demanding, particularly during aviation and marine manoeuvres, and to achieve safe operations in all conditions can be highly challenging.

It is with these issues in mind that Orga continues to push the boundaries in innovative signalling technology to improve safety of life at sea and enhance operational efficiency.

Circle-H technology for helidecks For safer offshore helicopter operations, Orga has developed the new touchdown/positioning marking and heliport identification marking (TD/ PM) Circle-H LED lighting system – in collaboration with the UK Civil Aviation Authority (UKCAA).

After almost a decade of development and trialling to determine the correct modular configuration, colour, intensity, robustness and reliability of the LED lights, Circle-H is now in production and has been installed on oil and gas platforms around the world – from the Gulf of Mexico through to the North Sea, Asia Pacific and the Middle East.

Replacing the use of floodlights, which caused glare and the so-called ‘black hole’ effect leading to loss of the pilot’s vision, the new Circle-H LED technology has proved to radically improve visual cueing for pilots during landing approaches in all weather conditions.

“Orga continues to push the boundaries in innovative signalling technology to improve safety of life at sea and enhance operational efficiency” Now incorporated in the UKCAA’s internationally-acknowledged guidance for offshore helicopter landing areas – CAP 437, 7th Edition, Amendment 01/2013 – duty holders have until 31 March 2018 to retrofit the new lighting system on UK North Sea offshore platforms. Helidecks not fitted with the new Circle-H lighting system after this date will be considered unsuitable for night and low visibility operations.

In addition to Circle-H, Orga has added the newly launched technologically advanced illuminated windsock with integrated aviation obstruction light (AOL) option and the new touchscreen digital navaids central control panel (DNCCP) to its helideck LED lighting system.

Creating a digital advantage Digital intelligence is transforming the energy world and Orga is evolving its digital offerings to help customers move to the next level of operational excellence.

At the heart of Orga’s helideck lighting, marine navaids and aviation obstruction lighting systems sits the latest digital central control panel. Its smart modular design offers more versatility than an analogue controller and allows for easy set-up and very low maintenance.

The DNCCP can be supplied in an industrial safe area cabinet or in an ATEX/IEC Ex-certified panel, bringing

“With advanced LED optical technologies and precision engineering, Orga’s signalling solutions meet all national and international regulations, securing increased safety for routine offshore operations” enhanced functionality to any hazardous and isolated location by providing full alarm, history and remote status monitoring capabilities for all Orga signalling solutions. Critical information can be rapidly viewed, accurately analysed and then immediately actioned from one central location for the safe and efficient control of operations.

R&D vital On bringing the new technology to market, Daniel Powell – Product Group Manager for Helideck Lighting at Orga – is the first to acknowledge the integral role that Orga’s investment in research and development (R&D) has played in shaping the success of Circle-H, the new windsock, the DNCCP, and, indeed, all Orga products.

“Having our own R&D capability to complement our manufacturing skills commands a real strategic advantage,” says Powell. “By having our own R&D team, we are able to keep ahead of the competition by driving continual technological innovation to develop new products and to keep improving existing ones.”

By offering standardised and modular safety signalling products for global use, Orga not only meets its customers’ global needs says Powell but also “by stripping back complexity we can, in turn, help lower operating costs.”

In this low oil price environment, pursuing and implementing efficiency is now more important than ever. Powell believes that “optimising performance and lowering maintenance costs, by adopting the latest supply chain innovation, could be a key to survival for many oil and gas companies amid the ‘lower-for-longer’ oil price environment”.

Safety cannot be compromised All Orga products are designed with safety foremost in mind and Marko Nieuwenhuize – Manager Sales at Orga – is keen to point out that, “safety cannot be compromised when optimising costs”.

“We use high-grade materials and cutting-edge components to protect sensitive electronics and minimise maintenance requirements while excellent thermal management gives the longest possible operating life,” reveals Nieuwenhuize.

With advanced LED optical technologies and precision engineering, Orga’s signalling solutions meet all national and international regulations, securing increased safety for routine offshore operations.

A smarter way to safety Orga has been at the forefront of developing innovative helideck lighting, marine aids to navigation and aviation obstruction lighting products for more than 40 years. To find out how Orga is driving cost and operational efficiency through standardised, safe and smart solutions, please contact Orga at www.orga.nl

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Glocalisation: thinking globally acting locally

Oil and Gas

by Frederic Farhad Farschi, Global Manager Local Content, Shell

To succeed globally, it is vital that companies tailor their offerings to suit the interests of local markets across the world. One company getting it right is Shell, as it continues to integrate the global and local aspects of business operations to expand the influence of its business Bonga is the first deepwater project for the Shell Nigeria Exploration and Production Company (SNEPCO) and for Nigeria

R

ecently, more and more governments and communities have been more focused on local content requirements (LCRs) to generate a short-term boost to domestic economic activity by creating jobs and stimulating contracts for local suppliers.

Getting it right LCRs are also used to promote an environment for the longer-term development of targeted industrial sectors. Well defined, planned and executed local content (LC) enables oil and gas operators to benefit from more reliable and lower cost national and regional capacities with the ability to access a sustainable local workforce and supply chain.

However, poorly designed national LC policies can impose significant costs and delays on projects and the operation of assets to the detriment of both companies and countries, and undermine the investment attractiveness of a market.

A highly technical and safety sensitive oil and gas sector, with global supply chain standards coupled with overly ambitious local content targets has the potential to set up a natural ‘global’ vs ‘local’ conflict. This could create distortions and inefficiencies in the affected categories of the supply chain and industry segments. It can also cause monopolistic positions in a smaller market where there is not enough space for several local players.

“Well defined, planned and executed local content enables oil and gas operators to benefit from more reliable and lower cost national and regional capacities with the ability to access a sustainable local workforce and supply chain”

LCR has become a significant non-technical risk area with more than two-thirds of future production of oil and gas coming from countries with explicit or implicit LCR as governments award projects based at least partly on LC offerings.

Investing in local content Shell companies aim to be good neighbours and contribute to societies where we work. Our

operations are a major source of revenue each year for governments around the world. These funds can help support a country’s economy and contribute to local development and social services. We work closely with governments on matters of taxes and royalties. We are a founder and board member of the Extractive Industries Transparency Initiative (EITI).

Employing a local workforce and our ability to develop competitively local capability and capacity, is very much part of our license to operate or to acquire. We look at longterm sustainability. We consider how we leave a legacy in the countries where we operate. We are actively contributing to the industry collaboration with governments and international institutions on local content guidelines and policy development, e.g. OECD, World Bank and IPIECA .

In our upstream and liquefied natural gas operations, the demand varies greatly in volumes, categories and technological complexity of inputs along the lifecycle of projects and assets. Each phase poses specific commercial and technical risks for resource developers and the supply chain.

The development phase often presents shortterm and limited business opportunities for

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Oil and Gas the local industry and workforce due to the complexity of today’s industry projects which require input from experts all around the world. The longer-term opportunities for local businesses and workforce normally arise during the operations phase and through collaboration with the government and the suppliers.

Therefore governments and markets should collaborate with each other in competitive local content development.

The key message is that governments need to support a collaborative environment that supports industrial activities with the potential to become economically viable.

Oman Shell's participation in the design of Oman’s InCountry Value (ICV) Blueprint Strategy for the oil and gas sector serves as a good example of the different steps in the design of a governmentled collaborative strategy. And how, if done well, it can be readily replicated in other national industrial sectors. Shell is a shareholder in Petroleum Development Oman (PDO), a leading operator for upstream in Oman that contributed to the ICV. Since the 1970s, PDO and other Shell joint ventures operating in Oman have been hiring, training, and investing in the country but the ICV framework became firmly embedded in the company’s business mandate in 2011.

Oman now has an ICV Committee, chaired by the under secretary of the Ministry of Oil and Gas with the participation of all key ministries and industry as well as operators, which is co-developing a sustainable approach to local content for the oil and gas sector.

Oman’s ICV strategy set the objective of increasing ICV in the Omani oil and gas sector by 2020 through more than 50 local business development initiatives, technical training standards to create new jobs and 40 enabling initiatives across six sectors (human resources, technology and innovation, business development, capital and finance, contracting and tendering, legislation and process improvement).

Nigeria An innovative example to share involves Shell companies operating in Nigeria. In 2012, they facilitated the collaboration between four Nigerian banks to lower collateral requirements with faster loan processing times to support local contractors executing projects for Shell in Nigeria. This reduced pressure on Shell for advance payments thus shifting the focus to improvements in quality, safety and on-time service delivery.

The scheme offered contractors more attractive terms compared to the open market.

From inception to the end of 2015, a total of US$940m has been approved for disbursement to about 220 vendors. This funding is from a combined US$4bn commitment by the banks.

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“Shell’s participation in the design of Oman’s In-Country Value (ICV) Blueprint Strategy for the oil and gas sector serves as a good example of the different steps in the design of a government-led collaborative strategy” Kazakhstan Another successful example is Shell’s collaboration with the government of the Republic of Kazakhstan and the National Agency for Development of Local Content to build capacity in country. The UK Trade and Investment (UKTI)/Shell Partnership Facilitation Programme was launched by UKTI in 2011 and targets small medium-size enterprise development to facilitate relationships, technology transfer and shared value creation between local and international suppliers.

Some of the most significant opportunities identified by Oman’s ICV Blueprint Strategy include localising the development of drilling rigs

A similar collaboration with UKTI in Nigeria helped to introduce local players to UK companies to enhance glocalisation of the supply chain.

Flexibility is key Successful ‘glocalisation’ requires proactive collaboration, led by government agencies.

It is only through dynamic engagement with operators and industry suppliers that economically viable solutions can be mapped out – linking the country’s economic development priorities (exploring synergies with education, industrial development, infrastructure and industrialisation, environmental themes, smaller supplier and community development) with the oil and gas industry needs (in terms of safety, quality, security, environmental consideration and cost competitiveness) in a globally challenging market for access to capital.

A successful collaboration will recognise that external factors can change rapidly over time underscoring the necessity for mechanisms that are adjustable and flexible between the government, operators and industry suppliers. n

www.the-eic.com

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Oil and Gas

Beyond pre-salt: offshore frontier exploration in South America

by Pietro Ferreira, EIC Regional Analyst, South America

Offshore frontier exploration areas across the whole of South America are attracting considerable attention from global oil and gas operators and offer longterm benefits for the energy security and economies of countries across the region

O

ffshore oil and gas activity in South America is usually associated with deepwater fields located in south-western Brazil. And rightly so, as much of the region’s offshore proven reserves are located in the country’s pre-salt play. In recent years, however, a number of oil companies have turned their attention to unexplored offshore basins across the region, targeting high impact resources from Colombia’s Caribbean coast to the Falkland Islands.

Colombia Guyana Brazil's equatorial margin

Brazil’s equatorial margin Far away from the pre-salt play in the Santos basin, Brazil’s equatorial margin is a little explored stretch of coastline in the north and north-east regions, between the states of Amapá and Rio Grande do Norte. Spanning a length of more than 2,000km, it encompasses five sedimentary basins and occupies an area of 1m km2. The area’s appeal lies in the fact that its geology is analogous to locations in West Africa where significant discoveries have been made (e.g. the Jubilee field in Ghana). Brazil’s National Petroleum Agency (ANP) sees the equatorial margin as one of the country’s most promising frontier exploration areas and believes it could hold up to 30bn barrels (Bbbl) of oil.

In a bid to boost the development of these resources, ANP’s 11th bidding round for exploration blocks, which took place in May 2013, awarded 45 concessions in shallow and deep waters in the equatorial margin.

Successful bidders included international oil companies such as BP, Chevron, ExxonMobil, BG (now Shell) and Total, in addition to a number of independent operators including UK newcomers Premier Oil and Chariot Oil & Gas. Activity in the equatorial margin started to pick up in 2015 with several companies commissioning seismic surveys ahead of their drilling campaigns. PGS conducted a 7,300km2 multi-client 3D survey in the Ceará Basin for Chevron, ExxonMobil, Premier Oil and Total,

Uruguay

The Falklands

A number of oil companies have turned their attention to unexplored offshore basins across the South America region including Brazil’s equatorial margin, Colombia, Guyana, Uruguay and the Falkland Islands

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Oil and Gas

The Maersk Venturer drilled the Raya-1 well off the coast of Uruguay. The world’s deepest well, it is estimated to hold approximately 1.5Bbbl of oil equivalent (photo: Maersk Drilling)

“Brazil’s equatorial margin is one of the country’s most promising frontier exploration areas and could hold up to 30bn barrels of oil” while earlier this year Polarcus finished a 785km2 3D seismic survey for Chariot Oil & Gas, which is targeting prospective resources of 300–500m barrels (MMbbl) across its four blocks in the Barreirinhas Basin. Spectrum, meanwhile, is shooting a 10,400km2 multiclient 2D seismic survey in the Foz do Amazonas and Pará-Maranhão Basins in a partnership with BGP. Exploration plans have been impacted by low oil prices but drilling campaigns are expected to begin by 2018.

Colombia An established exploration and production (E&P) player in South America, Colombia has traditionally focused on onshore fields, where it produces most of its oil. However, a recent push by the Colombian government towards offshore exploration has created a number of opportunities for oil majors. A bidding round organised in 2014 by the National Hydrocarbons Agency (ANH) awarded offshore exploration blocks on the Caribbean coast to Anadarko, ONGC Videsh, Petrobras, Repsol and Shell, in addition to the national oil company Ecopetrol.

Although Colombia already produces gas from the shallow water Chuchupa field (operated by Chevron), the country’s first breakthrough in deepwater exploration took place in December 2014 when Petrobras

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announced a gas discovery on the Tayrona block, located approximately 40km off the Guajira peninsula. The find was made at the Orca-1 exploration well, drilled by Diamond Offshore’s Ocean Clipper rig, in a water depth of 650m. Proven reserves at the Orca discovery are estimated at 264MMbbl of oil equivalent, according to Wood Mackenzie. The consultants also hailed Orca as Latin America’s most important hydrocarbon discoveries in 2014.

Orca was followed by another significant offshore discovery by the US independent Anadarko Petroleum. The company announced in July 2015 the drilling of the Kronos-1 well, located in 1,584m of water in the Fuerte Sur block, identified between 39.6 and 70m of natural gas pay. Despite unsuccessful results at a second wildcat in the nearby Fuerte Norte block, the operator plans to drill additional wells in the two blocks when the Bolette Dolphin drillship returns to Colombia in quarter four of 2016.

A strategic shift at Ecopetrol also looks set to benefit the country’s fledgling offshore oil industry. The company plans to balance its E&P activities amid low oil prices by intensifying gas exploration offshore Colombia and the Gulf of Mexico. An Ecopetrol subsidiary dedicated to offshore E&P, with an initial capital of US$594m, was created in January 2016.

Guyana Not far from Colombian shores, another promising project can be found in the Stabroek licence, a 26,800km2 block located some 160km off the coast of Guyana. In May 2015 ExxonMobil made the Liza discovery, which received much publicity as one of the oil industry’s biggest finds in 2015. Located in a water depth of 1,743m, the Liza-1 wildcat was drilled by Transocean’s Deepwater Champion

rig and led to the discovery of a 90m net pay in high-quality sandstone reservoirs. Following a 17,000km2 3D seismic survey carried out on the licence by CGG, ExxonMobil drilled the Liza-2 appraisal well, which encountered another 58m of oil-bearing reservoirs. Another three wells are planned to be drilled as part of an appraisal drilling programme, to be carried out by the Stena Carron drillship. ExxonMobil believes the Liza discovery holds between 800m and 1.4bn barrels of oil equivalent in recoverable reserves.

ExxonMobil is keen on fast-tracking the project and the company is understood to have shortlisted Modec and SBM Offshore to take part in the tender to supply a floating production storage and offloading (FPSO) unit for an early production phase. At the time of writing, a six-month front end engineering and design (FEED) stage is set to begin in late summer, to be followed by an engineering, procurement and construction contract award. The subsea scope is likely to feature 16 trees, with manufacturers such as FMC, OneSubsea, GE and Aker Solutions expected to chase supply contracts.

According to local sources, later development stages could feature a larger FPSO, possibly with a capacity of 150,000-180,000 barrels per day.

Should estimates prove correct, Liza’s reserves are equivalent to 24 times the gross domestic product of Guyana. In addition to putting a frontier exploration area on the radar of oil and gas operators worldwide, the field has the potential to be a turning point for the infrastructure and economy of Guyana, one of South America’s least developed countries.

Uruguay Another country where offshore E&P could make a significant contribution to the economy is Uruguay. French major Total started drilling the Raya-1 wildcat in March – the first offshore

www.the-eic.com

Oil and Gas

The Sea Lion field off the Falkland Islands, operated by Premier Oil, is estimated to contain 520MMbbl of oil reserves (photo: Premier Oil)

well in the country in 40 years and Uruguay’s first experience with deepwater exploration.

Drilled by the Maersk Venturer drillship, Raya-1 lies approximately 250km off the coast on Block 14 and is also the world’s deepest well, situated in a water depth of 3,411m. Total believes the prospect holds resource potential of more than 1.5Bbbl of oil equivalent. At the time of writing, drilling results have yet to be announced. Should they prove to be successful, government authorities think the appraisal stage could take three to four years, with production starting as early as 2023.

“Offshore Colombia, the Orca field has been hailed as one of Latin America’s most important hydrocarbon discoveries”

Block 14 was acquired by Total in 2012 in the second bidding round for exploration blocks organised by ANCAP, Uruguay’s stateowned oil company. Offering licences in three offshore basins, the round also awarded three blocks to BG (now Shell), three blocks to BP (relinquished in 2015) and one to Tullow Oil. The country’s offshore potential also attracted ExxonMobil and Statoil, which both became partners with Total in Block 14 with stakes of 35% and 15%, respectively. Statoil also teamed up with Tullow Oil and INPEX in nearby Block 15, acquiring a 35% interest.

This level of interest from key oil and gas players is noteworthy considering that Uruguay does not produce oil and has never made

a hydrocarbons discovery. Interestingly, the Fraser Institute’s Global Petroleum Survey 2015 put Uruguay in first place among South American E&P markets in terms of market attractiveness. A successful exploration campaign by Total will add strength to a bidding round for exploration blocks planned to be launched by the Uruguayan government this year, with results expected in 2017.

The Falklands While exploration work is only beginning in nearby Uruguay, the remote Falkland Islands in the South Atlantic are already witnessing the development of their first oil and gas field.

Sea Lion, discovered in 2010 and operated

by Premier Oil (with Rockhopper Exploration as a minority partner), lies 220km offshore in the PL032 licence, located in a water depth of 450m. The field is estimated to contain 520MMbbl of oil reserves, which are planned to be developed in two phases.

The first phase, estimated to require an investment of US$1.8bn, is expected to recover 220MMbbl of oil using a small-scale FPSO connected to 18 subsea wells. FEED studies for the FPSO were awarded to SBM Offshore in January 2016 and are expected to take 18 months. FEED contracts for the subsea scope of Sea Lion were awarded in the following month to National Oilwell Varco and Subsea 7, covering flexible lines and transport and installation of SURF equipment, respectively.

The second development phase will aim to recover the 300MMbbl of remaining reserves in the PL032 and nearby PL004 licences.

There are additional sections of the islands where exploration activity is also taking place, such as the PL004 licence, where Premier Oil announced the Isobel Deep discovery, and other licences in the South and East Falkland Basins,

where independent operators such as Borders & Southern and Noble Energy are operating.

Challenges and opportunities Other notable offshore frontier exploration areas can be found in South America. French Guiana made headlines in 2012 following the Zaedyus discovery in the Shell-operated Guyane Maritime licence, while in neighbouring Suriname, Kosmos Energy and its partners Chevron and Hess have commissioned seismic surveys before starting drilling on Block 42.

Argentina, where Total is already producing gas and condensate from the offshore Vega Pleyade field in Tierra del Fuego, has the potential to unlock resources in little-explored offshore basins along its coastline with the country’s energy minister having announced that offshore activity is expected to grow in 2018.

In many of these frontier exploration areas the infrastructure in place does not meet the requirements of exploration activities. This can lead oil companies to source key goods and services from other areas (e.g. Trinidad and Tobago for operations in Guyana, southeast Brazil for exploration in the equatorial margin), which drives up costs. Logistics play a crucial role in the short-term, which creates opportunities for the construction of terminals, supply bases and storage infrastructure. Key ancillary services in demand include transport, waste management, environmental consultancy, recruitment and training, among several others.

Although many of South America’s frontier exploration projects are still a long way from the development stage, they provide opportunities for the improvement to the local infrastructure and supply chain. Additionally, frontier exploration offers long-term benefits for the energy security of countries across the region as well as their respective economies. n

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Oil and Gas

Contracting in the new era

by Allen Leatt, Chief Executive, International Marine Contractors Association (IMCA)

This new era is reflective of the challenges in the ‘CRINE’ era 25 years ago. However, the pressures on the traditional allocation of liabilities may create another milestone in the evolution of contracting terms. In uncharted territory, what is the way forward?

Marine contractors are asking ‘will signing this contract lose me my company?’ (photo: Heerema Marine Contractors)

I

MCA member companies globally are grappling with the deterioration in contracting terms in the post-Macondo and the post-US$100 barrel oil business environment, a task on which members of the IMCA Contracts and Insurance Workgroup are working hard, both within their own companies, and on behalf of members.

Turn to CRINE

“The prevailing doctrine of oil companies pushing ever-higher liabilities onto contractors is dividing us, and is exactly opposite to what happened 25 years ago”

Let us turn the clock back to a comparable period. After the oil price crash of 1986 the industry took as long as five years to grapple with what had happened and start to restructure and reshape itself. Then in 1991, in the face of prolonged low oil prices, a new mantra emerged from Dr Rex Gaisford of Amerada Hess – CRINE, Cost Reduction Initiative for the New Era. The CRINE leadership at the time was motivated, like today, to recalibrate the industry’s cost base in order to get the then backlog of CAPEX projects off the drawing board.

‘future-proofing’ for which our industry is well known. Initially this was no easy task, as engineers always like to improve on the last design iteration in terms of efficiency, elegance and flexibility. The downside is that these positive engineering arguments can tend to aggregate into ever more sophisticated specifications.

With the result that we are sometimes guilty of creating overpriced monsters!

They homed-in on robust, safe designs that were fit for purpose, rather than incorporating those ‘nice-to-haves’, ‘gold-plating’ and

As well as addressing the technical challenge of rationalisation, they also bravely focused on the commercial model

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and contracting philosophy to incentivise everyone – the direction of travel was ‘let’s have a different way of working, let’s work together in collaboration’ (referred to then as alliancing and partnering).

Many people were initially sceptical to the idea because it required clients, contractors and their competitors to work together where trusting relationships are essential, but in that era it worked, and many projects were successfully taken off the drawing board and brought to fruition. It is a system that has also worked well in the mainstream civil engineering industry, and indeed in recent years all major infrastructure projects in London – the Olympic Park, Terminal 5 and Crossrail – have relied heavily on the collaboration model.

Company killers Unfortunately, in our current ‘new era’ we see the hangover of the Macondo disaster badly distorting the contracting philosophy. The prevailing doctrine of oil companies pushing ever-higher liabilities onto contractors is dividing us, and is exactly opposite to what happened 25 years ago. In particular, the

www.the-eic.com

Oil and Gas introduction of the potential risks of unlimited liability – for pollution, damage to work and consequential losses – are company killers, and far too crude a way to engage with the supply chain for getting projects off the drawing board. Their impact on the marine contracting world is causing great concern within our global membership and is totally unnecessary.

“Should a new CRINE emerge, as surely it must, we need to ensure that it continues rather than disappears once the price of oil recovers” Clarity needed

IMCA FAIR contracting principles • Fair (not equal) and realistic distribution of risk in relation to relative rewards • Allocation of risk – to the party best placed to assume • Insure – sufficient scope of cover • Reasonable – avoid 'duplicate' assumptions of risk and minimise potential for dispute

IMCA’S new recommended guiding principles

Oil companies have the ultimate responsibility towards the country in which they operate if things go badly wrong. Contractors understand their requirement for the supply chain to have ‘more skin in the game’ as it is often called, but the current course is simply not sustainable and a better formula needs to be found. The need to address the Macondo syndrome is totally understandable, but a more pragmatic system is needed.

Pollution

The contractual situation is confusing, and whenever there is a lack of clarity there will be litigation. The insurance sector is also caught up in this confusion, since the ‘knock-for-knock’ principle, which has worked extraordinarily well for the last 40 years, is now being distorted. Our members, quite justifiably, and regardless of size and ownership, feel hard done by, since marine contractors rarely, if ever, touch the oil and feel that the logic of this treatment being meted out is unsound.

• Company to indemnify for consequential losses • No acceptable compromise

As David Blackmon, General Counsel at Heerema Marine Contractors explained at a recent IMCA Contracts and Insurance Seminar, Heerema is privately owned with a single shareholder who does indeed ask ‘will signing this contract lose me my company?’ That is a very telling question from the owner of three of the four largest crane vessels in the world and for whom the world’s largest crane vessel is currently being constructed in Singapore.

Today, with US$50 oil at best, it is a time for our industry to dissolve the new legal barriers to allow the free moving collaboration of the past. We need to make business seamless in terms of facilitating sensible technical and commercial discussions and thereby bringing projects back to the market.

At that seminar, held in May 2016, we launched our new recommended guiding principles and reminded delegates of our FAIR contracting principles.

• Contractor shall be protected from any pollution liability, other than pollution emanating from contractor’s spread • Acceptable compromise: capped liability for any carve out on pollution whether for gross negligence or wilful misconduct

Consequential losses

Damage to work • Company to indemnify for damage to the work or provide insurance coverage by way of a contractors all risk (CAR) policy • No acceptable compromise

The way forward So, will we find a solution? One thing is certain: our industry will adjust its cost base – we will have to. Overall lifting costs have to be reduced and efficiency improved in order to rebuild a sustainable and profitable industry.

Oil companies, of course, have a big role to play in this regard, as it is their often ‘gold-plated’ specifications and requirements that inflate costs and overheat the market. Oil companies have outsourced so much during the past 25 years that it will be impossible for them to retrace their steps. There is a symbiotic relationship that needs to be managed and regenerated. Either we will see a dearth of new projects for many years to come, or we will find some other way of working to make today’s backlog of projects economic.

It is perhaps a little early to see CRINE-style leadership standing up and challenging the status quo. We certainly have the talent and

resolve to move the barrel hurdle rate for investments from say US$70 to US$30. Some of that can be achieved by crude cost and price cutting, but smarter ways of working will also be needed to reset the economic model.

It is a time for bold decisions again, and for leadership to recognise there will be a limit to how much the supply chain can be beaten up, and to figure out how to make best use of the symbiotic relationship in place.

If oil companies do not provide the leadership, as they did in 1991, then the market may well do it on their behalf. There may be a move to a variety of new contracting tiers and models in the future. Some contractors will become smaller niche players; the bigger ones will, and some already have, develop far greater integration in their service offering.

There is a lot of activity taking place within IMCA’s global contractor community. In particular, the TechnipFMC proposed merger (following their pilot with Forsys Subsea) which sees a very strong global contractor merging with a very strong global subsea production systems company – two leaders wanting to redefine how capital developments can be brought to the market at a fraction of the traditional cost.

Also, Subsea 7 is teaming up with OneSubsea (a Cameron and Schlumberger company) on subsea production systems and subsea umbilicals, risers and flowlines solutions; and McDermott and GE establishing io oil & gas consulting aimed at transforming the development of front-end solutions.

The big contractors are coalescing parts of the supply chain for good reason – to reduce the interface risks and associated costs. For the oil companies which are early adopters of innovation this could well be a compelling answer; for others there will be alternative strategies – but for sure, new thinking will be needed.

Should a new CRINE emerge, as surely it must, we need to ensure that it continues rather than disappears once the price of oil recovers. Such successes would be further developed and built upon in other large industries – automobiles, aircraft or locomotive industries – so why not in ours? n

The International Marine Contractors Association (IMCA) represents organisations engaged in delivering offshore, marine and underwater solutions. Its core purpose is improving performance in the marine contracting industry by championing better regulation and enhancing operational integrity. www.imca-int.com

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Power

Electricity storage is ready now

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CCS is vital to meeting Europe’s climate targets

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Powering ahead

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Closing Sub-Saharan Africa’s energy gap

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Power

Electricity storage is ready now

by Dr Jill Cainey, Director, Electricity Storage Network

As new energy storage technologies have come to prominence, regulatory barriers must be tackled if the technology is to be scaled up and commercialised successfully

H

ow often have we heard that the arrival of electricity storage would be the solution to the UK’s struggling electricity system? If only we had electricity storage to soak up ‘excess’ renewable generation for use at times when there was less power. If only we had fast acting batteries to help keep the system stable and if only we could store heat to reduce gas demand. Well, the wait is over as storage is not only ready, but also actively being deployed in the UK. There is a perception that the UK is still waiting for electricity storage to develop sufficiently to meet system requirements, but the reality is that electricity storage has been here, with well-demonstrated reliability, for many years. We have our legacy pumped hydro schemes that have been vital to maintaining system stability since the early 1980s, but they were built by the nation for the nation and the commercial and regulatory realities make new projects of that scale challenging.

Fact not fantasy There are a number of developers keen to expand existing pumped hydro facilities and to convert hydroelectric generation facilities into pumped hydro storage facilities – a company in north west Wales, Quarry Battery, is about to deliver a brand new 99.9MW pumped hydro facility in disused quarries – but the planning and investment requirements make it difficult to commission these new projects quickly.

A number of developers, including Advancion Energy Storage (AES) UK and Ireland and RES Group have been deploying batteries commercially overseas for many years, in North and South America and Europe. The UK is only now, after some delay, realising that electricity storage is fact and not fantasy.

New technologies While the attention is very much on batteries – with a particular focus on lithium-ion batteries – there are many other exciting UK-developed electricity storage projects deploying now.

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The 5MW pre-commercial demonstration project on Viridor’s site at Pilsworth, Greater Manchester, will operate for at least one year – providing energy storage as well as converting low-grade waste heat from the landfill gas engines to power (photo: Highview Power Limited)

REDT are deploying a vanadium flow battery alongside a wind turbine on the Isle of Gigha, to manage constraints on an island network.

Highview Power Limited will shortly commission a 5MW device on partner Viridor’s site at Pilsworth. The Highview large-scale liquid air energy storage (LAES) process uses electricity to compress air to liquid nitrogen, which is stored in large pressurised tanks, before re-expanding the liquid nitrogen through a gas turbine to generate electricity.

The LAES technology is scalable from around 5MW to significantly greater than 50MW. This is a UK-developed technology that has a well-established engineering supply chain based largely in the gas industry.

Both of these projects are supported by Business, Energy and Industrial Strategy (BEIS) innovation funding – BEIS having subsumed the work of the Department of Energy and Climate Change (DECC).

“The UK is only now, after some delay, realising that electricity storage is fact and not fantasy” Managing heat is crucial The UK has progressed well towards its carbon targets for electricity generation, but reaching the targets in heat and transport falls well behind what is required. Indeed, National Grid in its Future Energy Scenarios (2016) has shown that even on their ‘greenest’ pathway to 2030 the UK will not hit its targets in 2020. In winter, the ‘heat’ peak is 300GW and is currently supplied by gas, but the UK needs to decarbonise and so managing heat is of urgent importance.

It will not be possible to deliver 300GW of heat via our electricity system and thermal energy

www.the-eic.com

Power storage will become increasingly important using water, storage heaters and phasechange materials, such as those developed

by Sunamp, to manage in-day heat supply.

Seasonal storage remains a challenge, but decoupling heat from electricity demand using solar thermal could be increasingly important (given we have sufficient solar resource to create electricity, we certainly have enough to generate heat). It should be remembered that decarbonisation does not mean electrifying everything and partnering heat generation, be it solar thermal, heat pumps or hybrid solutions, and storage will be necessary to keep us all warm in winter, while reducing carbon emissions and maintaining security.

We tend to forget that we have been storing heat happily in homes for years, although the change in boiler technologies means that hot water tanks are an endangered species. The hidden storage in homes and airing cupboards is an untapped source of flexibility that is ripe for exploiting.

All-electricity system boilers in the UK could offer an estimated 30GWh of flexibility. If hot water tanks are retained they could provide a valuable demand ‘turn up’ service to help manage the challenging summer midday system minimum demand caused by peak solar generation. Currently, National Grid curtails wind generation to balance the system and this is not a sustainable approach.

“A critical regulatory problem is the way the UK funds its renewable generation incentives using end user supply levies”

This summer demand minimum challenge illustrates how the UK’s increasingly complex electricity system is becoming harder to manage. With large centralised high carbon generation coming off the system, the ability of the system to cope with stress events is becoming limited and the time to respond to a problem has reduced considerably, so National Grid is looking for more rapidly responding technologies that can deliver support in under five seconds.

storage was never defined as not being an end user, the charging of electricity storage attracts this levy even though the electricity passes through the device and on to another end user, who again pays the levy. This is a double charge that has a significant material impact on the income of any electricity storage development of the order £15-20/ MWh. This needs to be resolved rapidly to ensure projects are not delayed and to minimise the cost to the end consumer.

Regulatory uncertainty

Batteries charge forward

Many storage developers are deploying storage in spite of regulatory uncertainty and this regulatory uncertainty costs money. The issues are many and varied but largely because the electricity system was developed before electricity storage was considered, storage is treated as generation or not treated at all. Take connecting a storage asset to a distribution network.

Since storage charges and discharges, it looks like demand and generation/supply.

This means that currently the connection of a single asset requires duplication in two connection applications and teams, doubling the workload for developer and network alike.

But back to batteries because that is where all the interest lies at the moment. Behind-themeter batteries have received much attention since the Tesla Powerwall launched in early 2015.

A critical regulatory problem is the way the UK funds its renewable generation incentives using end user supply levies. Because electricity

However, the payback times for domestic behind-the-meter storage are long at 16–24 years, even coupled with rooftop solar PV. This is because current tariff structures do not facilitate price arbitrage (charging the battery when it is cheap and discharging when it is more expensive) or the selling of electricity back to the network from the storage device.

Innovative companies such as Moixa Technology are exploring how domestic behind-the-meter storage can be paid for providing system support services, reducing the payback period, however accessing all

UKPN’s energy storage project in Leighton Buzzard, Bedfordshire, is helping shape UK policy on technology issues (photo: UK Power Networks)

the value that storage can provide is difficult whether it is behind-the-meter or in front, because of commercial and regulatory barriers.

National Grid, the Transmission System Operator, purchases services that support the system, but does so on a service-by-service basis. With one or two exceptions (combining a capacity obligation with balancing services is possible) providers contract to deliver a single service, rather than multiple services.

This contractual approach does not support novel business models that rely on stacking income streams. National Grid is working hard to understand how to support a stacking approach, as it needs new services and providers urgently, but like regulation the process is slow and slower than innovation or delivery of electricity storage projects.

One clear example of a new service, built on the technical requirements of the system rather than the technical capabilities of the generation fleet connected to it, is the new Enhanced Frequency Response (EFR) service, which requires a sub-second response and is something that electricity storage is well placed to deliver, indeed the initial call for 200MW attracted 7.5GW of prequalified interest and it will be interesting to see the price when the results of the tender are revealed in late-summer 2016.

Many of the developers exploring the EFR service will use lithium-ion batteries. The cost of these batteries has decreased rapidly and continues to fall; with the EFR tender driving prices rapidly lower in the last six months. Lithium-ion is a well-established technology and extended warranties are

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Power

The UK’s ‘biggest battery’ has been installed at AES’s power station in Kilroot. The battery is the start in plans for a 100MW storage facility (photo: AES UK and Ireland)

being provided by some manufacturers.

UK Power Networks (UKPN) Smarter Network Storage project at Leighton Buzzard has been using a 6MW battery, since 2014, to provide security of supply to the local area, avoiding the need for a costly third overhead line and ancillary equipment.

Since the support of supply is needed only in winter, the battery has been used to explore providing other services to the National Grid, one of the partners on the project, which has used the knowledge from this project to help develop the EFR service and contracts for utility-scale electricity storage.

This first-of-a-kind battery project was supported by innovation funding from Ofgem, but the recent 10MW battery project delivered by AES UK and Ireland at its Kilroot plant in Northern Ireland, is the first fully commercial battery project to be operational in the UK. The AES battery builds on the experience of delivering large-scale electricity storage projects internationally and provides system services to the Northern Ireland and Ireland Single Energy Market. It is providing valuable insights into just how effectively such a rapidly responding asset can be to delivering stability to the system operator. Indeed, the battery is so flexible that the way it responds can be adjusted at the request of the system operator to better meet requirements.

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“While the industry would like the numerous problems to be resolved as soon as possible, the solutions do need to deliver a strong foundation and clear signal that the UK is open for business for electricity storage”

Both the UK Power Networks battery and the AES battery are able to provide a broad range of services from rapid frequency response to reactive power, to capacity and can deliver services simultaneously, making efficient use of the asset and minimising overall system costs.

Clear market signal needed Regulation and commercial arrangements need to catch up with the technology and appetite for deployment. DECC (now BEIS) and Ofgem both released papers in late 2015 that covered these barriers to electricity storage.

Although the government is working actively to understand and resolve many of the issues,

the joint call for evidence has been delayed several times due to political uncertainties.

These delays will hurt the industry.

These papers were reinforced by the National Infrastructure Commissions Smart Energy report (2016) indicating that by incorporating electricity storage into the system would save £8bn on running that system, while delivering security and sustainability. While the industry would like the numerous problems to be resolved as soon as possible, the solutions do need to deliver a strong foundation and clear signal that the UK is open for business for electricity storage.

So the UK electricity storage industry is ready and willing to deploy and given the speed of deployment – the AES Kilroot battery took less than 12 months to deploy – it is not impossible that GWs of electricity storage will be operational on UK networks by 2020. n

The Electricity Storage Network represents national and international companies with an interest in electrical energy storage, and actively promotes the value of storage within the UK power system. www.electricitystorage.co.uk

www.the-eic.com

Power

CCS is vital to meeting Europe’s climate targets

by Andrew Purvis, General Manager – Europe, Middle East and Africa, Global Carbon Capture and Storage Institute

CCS has the potential to help mitigate climate change both in Europe and around the world. Its technology is already proven but lack of policy and regulatory support is limiting its true potential

I

n December 2015, 195 countries signed the historic Paris Agreement establishing an unprecedented level of global support for urgent action to address greenhouse gas emissions. The agreement represents a significant shift in thinking.

International and EU climate targets No longer are we aiming to limit global warming to 2°C. After Paris, we are aiming for well below that – as little as 1.5°C. While the successful conclusion of the COP21 negotiations was a significant and welcome outcome in itself, giving effect to its ambition is a far greater challenge.

We must say ‘yes’ to all low carbon technologies.

But the world needs especially to say ‘yes’ to carbon capture and storage (CCS), and we need our political leaders to pave the way forward with strong policy support, just as they have for renewable energy and will need to continue doing so.

CCS has a vital role to play in a portfolio of low-carbon technologies to tackle climate change at least-cost to the world economy.

It is a proven technology that is already reducing carbon emissions by millions of tonnes per year, with 15 large scale CCS plants operating globally, and another seven under construction. These 15 operational projects have the capacity to capture 28m tonnes (Mt) of carbon dioxide (CO2) each year.

The UN’s Intergovernmental Panel on Climate Change (IPCC) has concluded that CCS is essential to tackling climate change in the most cost-effective way. In a report released in November 2014, the IPCC highlights that without CCS the cost to limit global temperature rise to 2°C would increase by 138%.1 The International Energy Agency (IEA) recognises CCS will make a major contribution to total CO2 emission reductions required by 2050. The IEA in its 2016 Energy Technology

For 20 years, Statoil has captured about 16Mt of CO2 from the natural gas from the Statoil-operated Sleipner field, and stored it in a formation more than 800 metres below the seabed (image: Statoil)

“CCS is a proven technology that is already reducing carbon emissions by millions of tonnes per year, with 15 large scale CCS plants operating globally, and another seven under construction” Perspectives report estimates that CCS has the potential to deliver 12% of the cumulative CO2 emissions reductions the 2°C scenario requires through to 2050. However, while the world needs CCS to achieve a low carbon future, CCS needs much more policy and regulatory support to achieve its full potential.

While all mitigation technologies will be needed to achieve this ambitious goal, in a 1.5°C scenario, CCS will need to make a significantly larger contribution.

Current projections indicate more than 2,400 new coal-fired power stations are already planned for construction by the year 2030, while hundreds of existing facilities will still be in operation for the coming decades. Even if unabated coal power was to be replaced with unabated gas, CCS will be required to limit greenhouse gas emissions sufficiently to meet climate targets.

Outside of the power sector, 25% of the world’s CO2 emissions result from the industrial sector, in industries such as iron and steel, cement, chemicals and petrochemicals and fertiliser manufacture. CCS is the only technology available capable of delivering significant reductions in greenhouse gas emission from these industrial processes.

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Power CCS development in Europe Currently, there are six CCS projects across Europe in different stages of development.

This includes two Norwegian projects that are actually operating, one of which will achieve 20 years of operation in 2016: • The Sleipner CO2 Storage project was the world’s first demonstration CCS project for a deep saline reservoir and started operating in 1996. The project installations process gas and condensate from the Sleipner East and Sleipner West fields (and tie-ins from a number of satellite fields). The Sleipner project has since 1996 captured, injected and stored more than 16Mt of CO2 in the Utsira storage formation, located in the Central North Sea.2 • The Snøhvit CO2 Storage project is a liquefied natural gas processing development in the Barents Sea offshore Norway. The project is designed to capture 0.7Mt of CO2 per year when at full capacity and it has stored as much as 3Mt of CO2 since injection started in 2008.3 • The Rotterdam CCS Demonstration project (ROAD) involves the retrofit of a 250MW post-combustion capture and compression unit to a newly constructed 1,070MW power plant located within the Rotterdam port and industrial Zuid-Holland area. The ROAD project plans to capture 1.1Mt of CO2 per year and to store it in a depleted

“While the world needs CCS to achieve a low carbon future, CCS needs much more policy and regulatory support to achieve its full potential”

gas reservoir under the North Sea. The Dutch project is in the define stage of development planning and its next step is to make a final investment decision.4 Development of the Sleipner and Snøhvit projects was encouraged through a CO2 tax the Norwegian government has implemented on a number of sectors (including offshore petroleum production) since 1991. In 1996, the first year of Sleipner operation, the CO2 tax on offshore petroleum production on the Norwegian Continental Shelf was around US$35 per tonne of CO2. This tax was raised to around US$70 per tonne in 2013, and in July 2015 the exchange rate between NOK (Norwegian currency) and US dollars modified the tax value to around US$50 per tonne of CO2.

Supporting CCS The European Union Emissions Trading Scheme (EU ETS) puts a cap on the CO2 emitted by business and creates a market and price for carbon allowances. The EU ETS is currently under the EU Institutions review

– that is, the European Commission issued a legislative proposal for phase four of the EU ETS directive in July 2015. The proposal includes an Innovation Fund, known as the NER400, which extends the existing support (NER300) for the demonstration of innovative low-carbon technologies, such as CCS, and includes measures to decarbonise industrial production. The Innovation Fund will be filled by selling 400 million carbon allowances of the free allocation portion of the fourth ETS phase (2021–2030). The financial mechanism will also include 50 million unallocated allowances to supplement existing resources before 2021.

The EU Institutions have the opportunity to support CCS through the EU ETS revision, which could also be broadened as suggested in the draft report proposal of the MEP Ian Duncan. Rapporteur for the EU ETS review file in the European Parliament Environment (ENVI) Committee, Duncan has issued a draft proposal that foresees an additional 150 million allowances on top of the 400 million included in the Innovation Fund.

Storage overview: site options

Key 1

Saline formations

2

Injection into deep unmineable coal seams

3

Use of CO2 in enhanced oil recovery

4

Depleted oil and gas reservoirs

2

4 3

1

Source: Global CCS Institute

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www.the-eic.com

Power As CCS development entails large upfront investments and long development times, Duncan’s proposal represents a very positive step for the CCS sector.

Nevertheless, a funding gap exists between the current financial mechanism and the NER400.

While the 50 million allowances would help to support CCS until the Innovation Fund becomes available, larger financial support is needed before 2020 to create the necessary transport and storage infrastructure for CCS to fully contribute in reaching the EU climate targets.

The global carbon cycle Deforestation Animal, plant and microbial respiration

Ocean carbon cycle

Combustion of fossil fuels Photosynthesis

UK CCS sector prospects The UK is among the most promising European countries in developing and deploying CCS. The country currently hosts three projects in development planning – the Caledonia Clean Energy project, the Don Valley Power project and the Teesside Collective project: • Summit Power, developer of the Caledonia Clean Energy project, intends to build a new 570MW integrated gasification combined cycle (IGCC) power plant in Grangemouth, Scotland. The proposed IGCC plant, equipped with carbon capture technology, is meant to capture 3.8Mt of CO2 per year. The captured CO2 would be transported to and stored in the Central North Sea in an offshore injection site.5 In March 2015, the Caledonia project was awarded £4.2m in joint funding from the UK and Scottish governments for industrial research and feasibility work.6 • The Don Valley Power project would consist of two Sargas Stargate 250 IPCT units generating approximately 520MW of electricity. As much as 1.5Mt of CO2 per year would be captured from the pressurised system.7 • The Teesside Collective is an infrastructure project developed by a cluster of industries in the North East of England that aim to establish a CCS equipped industrial zone. The Teesside area is home to five of the UK’s major CO2 emitting plants, and its industries are responsible for 5.6% of total industrial emissions in the UK.8 The project would remove up to 5Mt of CO2 per year in the 2020s.

The three projects are all in the evaluate stage of development planning. At this stage, a project examines a range of options to determine the business viability of a broad project concept. Development of these projects and the transport and storage infrastructure to support them, would bring major benefits to both the UK economy and to the countries’ efforts to meet ambitious emissions reduction targets. A recent economic benefit analysis on the Teesside process industries alone has been shown that it could contribute as much as £26bn to the national economy.9 A study published by the Energy Technologies Institute

Source: Global CCS Institute

“A study published by the Energy Technologies Institute in 2015 estimates that a failure to deploy CCS in the UK would mean almost doubling the cost of carbon abatement to the UK economy from around 1 to 2% of GDP by 2050”

in 2015 estimates that a failure to deploy CCS in the UK would mean almost doubling the cost of carbon abatement to the UK economy from around 1 to 2% of GDP by 2050.10

As we have seen from the success of the COP21 negotiations, the only way the world will achieve effective action on climate change is through a determined long-term commitment to international collaboration.

This must be achieved through effective policy settings that enable the deployment of all low emission technologies. CCS has a vital role to play in reducing emissions in the global energy sector, and is the only practical option available for the vast majority of industrial processes which collectively account for approximately 25% of global CO2 emissions.

The 15 large scale CCS projects currently operating around the world have proven that the technology is a safe, reliable and effective way to reduce emissions. Now is the time to get serious about implementing policies that will deliver deep cuts in emissions at least cost, and that means supporting CCS. n

1. https://www.ipcc.ch/pdf/assessment-report/ar5/syr/AR5_SYR_FINAL_SPM.pdf 2. http://www.globalccsinstitute.com/projects/sleipner%C2%A0co2-storage-project 3. https://www.globalccsinstitute.com/projects/sn%C3%B8hvit-co2-storage-project 4. http://www.globalccsinstitute.com/projects/rotterdamopslag-en-afvang-demonstratieproject-road 5. http://www.summitpower.com/projects/carbon-capture/ 6. https://www.gov.uk/government/news/42m-for-ccs-research-at-grangemouth 7. https://www.globalccsinstitute.com/projects/don-valley-power-project 8. http://www.teessidecollective.co.uk/project/teesside-decarbonisation/ 9. http://www.teessidecollective.co.uk/project/teesside-economic-benefits/ 10. http://www.eti.co.uk/wp-content/uploads/2015/05/2015-04-30ETI-CCS-sector-development-scenarios-Final-Report.pdf

The Global CCS Institute is a not-for-profit company working to accelerate the development, demonstration and deployment of CCS. www.globalccsinstitute.com

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Power

Powering ahead

by Alex Marshall, Group Marketing & Compliance Manager, Clarke Energy

Electricity peaking stations are power plants designed to help balance the fluctuating power requirements of the electricity grid

T

he Capacity Market is a key component of the UK electricity market reform. The UK’s electricity grid has historically relied on large centralised power plants supplying domestic and business consumers alike.

The most advanced gas engine-based power peaking stations that were developed in 2001 and 2002 are still operating and providing power. Gas engines are characterised as having lower emissions than diesel engine technology, with more attractive fuel prices.

The old coal power plants are in the process of ramping down capacity and closing as they no longer meet the required environmental and performance standards. Nuclear power plants are reaching the end of their design lives and new nuclear plants are slow to be realised.

High efficiency gas engines and the Capacity Market

In parallel there is the requirement to deliver a greater amount of renewable energy. Technologies such as wind power generation and solar power generation are notoriously intermittent, only generating when the wind blows or sun shines. These different factors mean that demand and supply are more challenging to match.

The Capacity Market aims to balance the mismatch between demand and supply and to bring forward investment in new generation projects and innovative technologies, in parallel with maximising the utilisation of the existing generation capacity.

Generators that opt to work in the Capacity Market receive a steady revenue stream in the form of capacity payments that enables them to invest in new power generation assets.

There is also a capacity obligation that requires generators to be able to deliver electricity when needed or face a penalty charge.

Capacity Market technologies Historically, there has been a range of technologies deployed for peaking plant operation. A peaking plant is a power station that is turned on for typically a short number of hours per day, depending upon when there is a mismatch between existing supply of power and demand.

The different technologies installed as peaking stations include low cost diesel-fuelled generators. However, in recent years the cost of diesel fuel has increased, and there is recognition of the role these engines have in contributing to nitrous oxide and carbon dioxide emissions.

The suitability of gas engine technology for the Capacity Market is also now being recognised in the industry with a number of projects in development across the UK. There is also significant benefit to deploying high efficiency gas engines.

In the UK natural gas as a source of fuel for the peaking stations is significantly cheaper than diesel. The greater numbers of hours these facilities are operational for, the higher the long-term cost to the Capacity Market operator.

Higher electrical efficiency translates to a lower switch-on electricity price. That is, the extra points of electrical efficiency means increased generation revenue and operating profit.

The generators can operate at a lower grid electricity price, meaning greater revenue for the operator of the plant.

Size of plant The modularity of containerised gas engine technology is also beneficial. A 20MW containerised peaking plant can be deployed on a plot of land 53m x 63m meaning a modest footprint that can be deployed in a range of different settings, ideally closest to the point of electricity consumption. The facility can also be supplied, installed and commissioned in less than 10 months.

Maintenance The operation of peaking plants is different to that of base load generation stations. It is important that the technology provided can withstand the stresses imposed by repeatedly starting and stopping the generators.

A normal gas engine maintenance programme would include a flat-rate cost per operating hour for maintenance that includes oil, parts and labour. Maintenance programmes for Capacity Market installations would

“The suitability of gas engine technology for the Capacity Market is also now being recognised in the industry with a number of projects in development across the UK”

follow a similar format, however, they would need to account for the operating characteristics of the station, which would likely be significantly less than a base load combined heat and power plant.

The operating parameters of peaking stations currently installed in the UK and the greenhouse sector, demonstrate the success of gas engine technology in meeting variable operating parameters.

A proven solution In summary, gas engine technology represents an appropriate, proven, high-efficiency solution for project developers and operators for the UK’s Capacity Market auctions.

Higher efficiency translates to a lower switch on price and hence higher operational hours and greater revenue for the operator.

The plants can be deployed readily across the UK in a range of different settings, close to the site of use, maximising the fuel efficiency of the project.

Due to the higher electrical efficiency of a gas engine, the plant can run for up to 30% more hours than the other comparable plants. This gives the developers additional power generation revenues thereby significantly reducing the payback period of the investment. n

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Closing Sub-Saharan Africa’s energy gap A chasm exists between Sub-Saharan Africa’s installed capacity and its potential. Here, two members of the Business Council for Africa’s Renewable and Sustainable Energy Working Group – Nick Holme, Chair, and Chris Johnson, General Manager of Developing Gas Markets for Africa, Shell – discuss ways to bridge the power gap

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nergy is a transformative prerequisite for the development of any economy, and yet in Sub-Saharan Africa (SSA) almost 600 million people lack access to electricity (McKinsey, 2015); the region accounts for 40 of the 51 countries in the world where less than 50% of the population has electricity access (World Bank, 2015).

failures. Due to their dependency on diesel generators, these households spend around US$10/kWh, about 20 times that spent by households with grid connection.

Power supply inadequacies also undercut the productivity of manufacturing and commerce, with estimated revenue losses of 20% (Africa Progress Panel, 2015).

SSA’s entire grid has a power generation capacity of just 90GW, half of which is located in South Africa; this is equivalent to the amount of power consumed in Spain. It is estimated that by 2040, SSA will demand 1,600TWh of power, representing a fourfold increase in power consumption today (McKinsey, 2015).

The World Bank estimates that the cost to African economies of load shedding is equivalent to 2.1% of GDP, on average.

Some of Africa’s poorest households are victim to one of the world’s starkest market

Nick Holme on renewables and off-grid solutions According to the International Renewable Energy Agency, an additional 250GW of new capacity (on top of the current approximate

“SSA governments across the continent are increasingly embracing renewable energy as a portion of their energy mix”

150GW installed capacity throughout the whole continent) will be needed by 2030 to meet increased demand. This will require capacity increases to double to approximately 7GW a year in the immediate future and to quadruple by 2030.

Microgrids hold great promise for electrifying remote areas in SSA and will help countries reach their energy access goals (photo: Daleen Loest)

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Power The picture is not as bleak as it first appears – a challenge, certainly, but not impossible. SSA governments across the continent are increasingly embracing renewable energy as a portion of their energy mix and technological advances mean that renewable energy is becoming more efficient and less expensive to install.

There is also rapidly increasing interest in African renewable energy projects among commercial capital providers and institutions, such as the World Bank and African Development Bank, which are prioritising energy installation in Africa.

Blessing in disguise One of the major hurdles to be overcome in SSA is the lack of infrastructure required to cope with the increased power production, but that in itself could be a blessing in disguise, as it will enable Africa to leapfrog technologies (as it did with the mobile phone) and install smart electricity systems that are not reliant on being connected to the national grid.

The national grid will obviously still play a vital role in SSA and the cooperation of individual countries in the three regional power pools (west, east and southern) with a view to sharing electricity throughout the regions, is of paramount importance. This will require large projects with carefully thought through power purchase agreements and major funding from the likes of the World Bank.

The future is bright So, the future outlook for SSA is not as bleak as it first seems. The challenge is large and there is a strong need for the political will among SSA governments to encourage investment into the energy sector by creating an enabling environment – sooner, rather than later. Where commercial opportunities are created, the financial, technical and human expertise will quickly follow and it is not beyond the realms of possibility for SSA to satisfy its energy needs by 2030.

Chris Johnson on SSA’s gas-to-power potential In contrast to the region’s gloomy power backdrop, the energy potential of SSA is incredibly rich. 30% of global oil and gas discoveries made over the last five years have been in SSA, from conventional discoveries in Mauritania, Mozambique, and Tanzania, to shale deposits in South Africa.

Gas production in SSA grew at an annual average of 10% over the last 10 years and is expected to continue growing by 5% (annual average) to 2040 (US DOE/EIA, 2014).

Central role in meeting demand From an electricity generation perspective, gas could drive Africa’s industrialisation. Analysis suggests that gas could become the dominant generating technology, climbing from under 10% of capacity today to approximately 40% from 2020 onwards (McKinsey, 2015).

Off-grid potential Where SSA has the advantage over other continents, however, is that its off-grid potential is massive and provided the relevant legislation is enacted in each country in a timely manner, with suitable investment incentives for foreign investors, there could be a great increase in the number of independent power producers (IPPs) across the continent. These IPPs would essentially be aimed at two markets: • The large, industrial off-grid customers, such as mines, industrial complexes, factories and even whole towns • The microgrid market for rural villages, individuals and micro businesses (which would account for a large percentage of the over 600 million people currently without access to electricity) Both of these options would have the immediate knock-on effect of creating extra jobs and stimulating entrepreneurship in the rural economies, as well as increasing the ability of students to continue studying long after darkness falls. The benefits to health would also be enormous, with the need to rely on kerosene (and therefore exposure to its fumes) for light and cooking diminishing significantly.

“In combination with indigenous gas, LNG could play a central role in securely meeting demand, diversifying sources of energy, powering economic growth and creating jobs in the region” Utilising gas resources on a least-cost basis could position SSA with levelised cost of energy figures that are competitive with most other regions. Domestic gas could have a profound impact on manufacturing, especially in industries such as cement, chemicals, and fertilisers; coupled with low labour and energy costs, some countries could gain a competitive advantage in such gas-intensive sectors.

From the 2020s, African LNG exports could be a ‘game changer’ and could contribute to the diversification of gas supply into Europe, but only if they can compete with established supplies

Almost 600 million people lack access to electricity in SSA (photo: Michael Wick) on cost and schedule. LNG imports and intraAfrican trade also have an important part to play.

In combination with indigenous gas, LNG could play a central role in securely meeting demand, diversifying sources of energy, powering economic growth and creating jobs in the region. Emerging small-scale LNG technologies have the potential to bring natural gas to energy users not currently connected to pipeline networks.

This potential also extends to renewables, to which natural gas can provide a strong grid balancing partnership. McKinsey analysis led to an astonishing finding that by 2040, 26% of total electricity capacity in the region could come from renewable sources (geothermal, hydro, solar and wind), entirely driven by market forces (McKinsey, 2015).

Unlocking the potential Royal Dutch Shell has been active in SSA for decades and remains committed to helping the region to unlock its energyrelated growth potential. Going forward, there are five main priorities at hand: • Provision of affordable power for domestic consumption – electricity tariffs should reflect the true cost of electricity; costs should be transparent; countries should make the most of what they already have in the sector; and governments should pursue least-cost options

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Power

LNG could play a central role in meeting the region’s energy demand (photo: Phonix_a Pk.sarote)

• Creating an attractive investment climate – the Africa Progress Panel estimates that investments of US$55bn per year are needed until 2030 to achieve universal access to electricity. Current investment is just US$8bn per year. An environment that will attract a broad range of funding mechanisms is critical. There is a need for clear and consistent regulations, competitive terms, appropriate allocation of risks and availability of credible buyers • Creating the right policy/regulatory framework that supports the development of both renewables and gas – the Africa Progress Panel, among others, has recognised the partnership of gas and renewables, and states, ‘The idea that countries in Africa have to choose between low-carbon development and economic growth is coming increasingly anachronistic…the smart money for the future is on natural gas and green-energy sources’ • Regional integration – not every country has gas resources, but every region does. Regional integration is a crucial step in power sector reform that would substantially reduce costs due to economies of scale and increased share of power in total power generation, e.g. regional power pools. Utilising

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the continent’s rich gas resources on a least-cost basis could position SSA with a levelised cost of energy that is competitive with most other regions • Political will – governments in the region will need to develop capacity in their countries, allow for export, reinvest in local markets and balance security of supply and affordability

Collaboration is key Unlocking Africa’s energy potential will require partnerships between national governments and companies with the ability to innovate, capacity to deliver major projects and willingness to take on long-term commitments. Integrating the capabilities of a range of local and international companies, contractors and stakeholders will be one of the most important challenges for the African oil and gas industry in the years ahead. n

References McKinsey (2015) Brighter Africa, The Growth Potential of the SubSaharan Electricity Sector.

Africa Progress Panel (2015) Power, People Planet: Seizing Africa’s Energy and Climate Opportunities.

World Bank Group (2015) Support to Electricity Access Evaluation Report.

US DOE/EIA (2014) Annual Energy Outlook.

The Business Council for Africa (BCA) supports and promotes the private sector in Sub-Saharan Africa. The BCA’s Renewable and Sustainable Energy Group was founded in 2016 and comprises a multidisciplinary group of members with a range of specialities in the sector, from specialist services to manufacturing. www.bcafrica.co.uk

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Nuclear

A small revolution

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Seeking innovative solutions to technical challenges

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Nuclear power in South Africa ready to leap forward

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Germany’s nuclear phase-out

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Nuclear

A small revolution

by Mike Tynan, CEO, Nuclear Advanced Manufacturing Research Centre, and visiting professor of Nuclear Manufacturing, University of Sheffield

Small modular reactors (SMRs) offer a faster, cheaper way of building new nuclear plants. Backed by government the UK could lead the way, with SMRs powering the country by 2024

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mall modular reactors (SMRs) are defined by the International Atomic Energy Agency as ‘a reactor plant whose net electrical output is less than 300MW and is of advanced, modularised construction intended to either reduce cost, or enhance some parameter(s) of safety or performance, or both’.

There are a number of technology vendors and potential nuclear site developers that are interested in the opportunity to provide SMR technology for the UK. SMR technology is dominated by light water reactor (LWR) derivatives, specifically pressurised water reactors (PWR). There are technology developers interested in molten salt reactors (MSRs) and variations include static, or stable, salt reactors (SSRs); nuclear fission reactors in which the primary reactor coolant, or even the fuel itself, is a molten salt mixture. This article will focus on the PWR-type SMR. SMR technology is not new; small nuclear reactors for marine application have been in service for many years and these are a PWR derivative reactor. The civil nuclear industry has not, however, adopted small reactors for commercial electricity generation, principally because of large capital costs for nuclear power stations and the received wisdom of economies of scale – ‘big is better’.

Why then the current interest in SMR for the UK, and specifically the interest from the government? The obvious opportunity is to develop SMR technology for the UK with potential sales of licensed technology into the national and international civil nuclear power market.

“Real opportunity exists for UK manufacturing to engage fully in UK SMR development, manufacture and build” 104

Design concept for a power station based on Westinghouse SMR technology

UK SMR opportunities The UK is ideally placed to take a global lead in the SMR market, which is valued at £400bn, creating opportunities for SMR technology vendors, utility companies and the UK supply chain.

SMR technology vendor With the exception of Rolls-Royce, all of the publicly declared potential technology vendors are overseas technology companies. Vendors currently include Westinghouse, NuScale, MPower, GF Power, China National Nuclear Corporation, Terrestrial Energy (MSR) and Urenco (‘U Battery’ micro-reactor). There are other vendors, however, some have not made public statements about their intent for SMR. Vendors see the UK as a powerful partner and a potentially lucrative market for SMRs as the opportunity would satisfy a number of key objectives: • Access to a market where the government is ‘open for business for civil nuclear power’, providing a stepping stone to the global market • Secure UK government funding to complete the development of design for build and commence a localised development programme. This eases the self-financing burden, reduces exposure to risk and creates investor confidence • Entry into reputable UK licensing process goes a long way to provide confidence in safety case and assurance for world markets

• Access to a potential development site opens up the consenting process, including planning permission and public consultation

UK operating utility company With the possible exception of EDF, it is uncertain whether existing UK utilities would participate in a UK SMR programme at this time. A participating utility would have to be one that is not already committed to a 1GW+ nuclear new build programme (this rules out NNB Genco, Horizon, NuGen) and not German due to domestic policy on nuclear power (this rules out RWE and EON). SSE and Iberdrola both exited NuGen, and Centrica withdrew from NNB Genco. Currently an SMR programme does not appear to be a compelling opportunity for most of the utility operators, due to: • Attraction of affordable alternative technologies • Protection of shareholder value • Requires significant on-balance sheet investment

UK supply chain There could be a potential opportunity to compete in a programme of wider scope than is open to them for UK 1GW+ reactors and there is more capability and capacity to supply to SMR than to big reactors.

UK suppliers would have to compete against existing overseas supply chains on cost, quality and delivery, and would flagship suppliers step-up and invest in a UK SMR? That could

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Nuclear very well be a risk that suppliers would take, particularly if they see real investment from developers to create UK intellectual property.

“In its 2016 Budget, the government confirmed support for SMRs, including a competition to identify the best value SMR design for the UK market”

This opportunity would be severely restricted by exposure to risk of first-of-a-kind production and potential competition in the overseas sales market. The potential for volume production is highly sensitive to export sales since the size of the UK market alone would not be sufficient to justify investment. Other factors which would influence supplier investment decisions include: • Extent of modularity of the mechanical and civil infrastructure • Required certainty of contract before investment in delivery capacity • Designs not fixed, no technology declared, no design in licensing • Significant technical development required to deliver product qualification to specification

“The UK is ideally placed to take a global lead in the SMR market, which is valued at £400bn”

The economic case for SMRs Assuming that an investment model can be developed that provides robust confidence in route to market for SMR technology and the electricity from them, the following criteria could be used to build an economic case for UK SMR technology:

Two other considerations must be applied to an economic case for UK SMRs: ■■ Marketability – principally in the export market. Which technology brings the greatest and most robust access to export markets and to what extent is the technology vendor able to underpin this market with its existing global business?

Cutaway of the Westinghouse SMR containment vessel design, with the reactor pressure vessel

will be a need for a technology road-map that clearly identifies and utilises the capability and capacity of the UK supply chain to deliver a UK SMR. Supply chain issues such as productivity improvements and delivery confidence must be addressed quickly

■■ Commerciality of design – the use of derivatives of a global commercially available product tends to lead to an obvious choice of a PWR-type reactor, particularly if deployment is expected before 2030. PWR technology is standard to the global civil nuclear market with fuel regarded as a commodity, and experience and competition in outage management and servicing is extensive

■■ Technology fit to an available UK site – an SMR station will have a smaller footprint than a 1GW+ station and the design of a potential UK SMR to fit readily accessible and licensable sites could be a differentiator. Transportability of factory built reactor units will also be an issue: most SMRs cannot be fully factory built and modularised units will need transportation to an on-site assembly facility, while others claim to be factory built as integrated units

■■ Ease of licensing – choosing a technology in which the UK nuclear regulators have knowledge and experience will ease the licensing burden on both the regulator and the potential licensee. This will increase efficiency in the licensing process, foster innovation, and provide increased confidence in the site license application

■■ Technology developer investment in a sustainable programme – to what extent will a developer or technology vendor provide funding for a UK SMR development?

How will they finance that interest? And how will they attract other investors? If the government has invested, at what point, and how, is that investment returned?

■■ Ability of UK supply chain to participate – real opportunity exists for UK manufacturing to engage fully in UK SMR development, manufacture and build. There

■■ Lasting economic value for the UK – what plans do SMR developers or technology vendors have that clearly demonstrates lasting economic value for the UK?

■■ Deliverability – how has the technology vendor underpinned its claims for deliverability to schedule, cost, and quality?

To what extent does volume manufacture improve deliverability metrics and how does this give unambiguous confidence in the price of electricity from the technology?

Attracting investment The involvement of any investor in a UK SMR project will be subject to the attractiveness of SMR technology through a business case that demonstrates: • A clear, present, and forward opportunity • A route to market for the technology and its electricity at an attractive price • Confidence in volume export market • Choice of a commercial technology with a track record on large scale • Efficiency of the UK regulatory process leading to easing of licensing risk • Capability and capacity of UK supply chain to deliver, otherwise supply chain will be de-risked through global competition • Absolute confidence in deliverability of the technology to time, cost and quality A commercial delivery model for a UK SMR must be established; as any investment by the government in a UK SMR development would require the creation of some form of special purpose vehicle that would either create, or procure from, a consortium that would have to include as a minimum: SMR technology vendor, commercial manufacturer, technology developer, civil constructor, and design/regulatory support.

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Nuclear

One of the Nuclear AMRC’s largest machining centres, with the capability to develop manufacturing processes for full-scale SMR components

Government support In its 2016 Budget, the government confirmed support for SMRs, including a competition to identify the best value SMR design for the UK market. The Budget also confirmed a £250m programme to enable the UK to become a global leader in innovative nuclear technologies, including at least £30m for an SMR-enabling advanced manufacturing research and development programme. Part of the rationale for government support is the potential for UK manufacturers to take the lead in a global market for SMRs.

UK capability The Nuclear Advanced Manufacturing Research Centre (Nuclear AMRC), managed by the University of Sheffield and part of the national High Value Manufacturing Catapult, is working closely with a number of SMR developers that wish to deploy their technology in the UK. The centre was recently commissioned by Westinghouse to provide an independent assessment of the reactor pressure vessel (RPV) of the US group’s proposed 225MW SMR. The RPV is one of the largest and most demanding parts of any reactor, with Westinghouse’s design measuring around 10 metres in height.

The study for Westinghouse showed that the UK has the manufacturing capabilities to effectively make the RPV, and detailed

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how advanced manufacturing techniques could cut delivery lead times for the RPV by half, offering substantial cost savings for SMR manufacturing. The report also identified specific companies with the capabilities to take on the work, including many based in the Sheffield city region.

Advanced manufacturing is vital to SMR development. Because SMRs are designed to be largely made in factories, manufacturers will be able to use lessons learnt from other sectors such as aerospace, automotive, and marine to drive down costs, and exploit innovative manufacturing techniques.

Certainty needed ahead Given that 1GW+ new nuclear reactors in the UK will not reach commercial operation until at least the mid-2020s, there is a real opportunity to develop a UK SMR on a similar timeline; it is expected that SMRs could be online in the late 2020s (2028+).

Urenco contend that their U Battery micro reactor could be online as early as 2024.

For an SMR programme to progress in the UK we will need certainty: of technology, safety (licensing), siting, investment, and most of all, of indigenous value to the UK.

“There will be a need for a technology road-map that clearly identifies and utilises the capability and capacity of the UK supply chain to deliver a UK SMR”

competition for SMR technology. Could this result in an indigenous UK nuclear reactor technology commercially deployed worldwide?

That genuinely would be first-of-a-kind. n

The Nuclear Advanced Manufacturing Research Centre aims to enhance the capabilities and competitiveness of the UK civil nuclear manufacturing industry, and help British manufacturing companies compete for nuclear contracts worldwide. www.namrc.co.uk

The UK government has taken a first step towards this through an initiative to explore a

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FROM THE ENERGY INDUSTRIES COUNCIL

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Nuclear

Seeking innovative solutions to technical challenges

by Melanie Brownridge, Head of Technology, and Deborah Ward, Corporate Communications Manager, Nuclear Decommissioning Authority (NDA)

In decommissioning the UK’s nuclear legacy, the NDA faces many complex challenges. To complete the mission safely and securely, and to accelerate progress and reduce costs, the industry must embrace new technology and adopt new ways of working

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ack in the 1940s, the UK was at the forefront of developing nuclear power, initially as part of the Cold War arms race but subsequently to provide electricity for the nation. Driven and funded by the government of the day, the first nuclear power station was built at Calder Hall, Cumbria, in 1956.

Today, the 11 early Magnox-designed power stations are all closed and some of the first test reactors have been dismantled. Other historic facilities include research centres, fuel-related plants and Sellafield, which houses more than 200 nuclear facilities and 1,000 buildings. All require decommissioning, with appropriate management and disposal of wastes. Some facilities pose distinctive challenges, especially where novel engineering processes were pioneered or unusual fuels tested as part of the experimental programmes.

Taking on the challenge It is the task of the NDA, set up by the government in 2005, to address the legacy of these 17 sites.

Given the diverse, experimental nature of this inheritance, especially at Sellafield, the task is quite probably one of the world’s most complex environmental challenges.

The UK’s groundbreaking involvement with the early nuclear industry means its decommissioning programme is also one of the most well established internationally, leading the way in many areas.

Sellafield is the NDA’s most complex and urgent challenge

The NDA’s budget is allocated by the government and currently stands at around £3bn a year.

Estimates are that the whole decommissioning mission will take another 120 years, concluding only when the buildings have been cleared away, the land appropriately remediated and the waste safely stored or disposed of. For material at the upper end of the radioactivity spectrum, current government policy is to develop a highly engineered underground facility at a location yet to be agreed; more conventional routes are already available for lower-activity wastes.

Sellafield is the NDA’s most complex and urgent challenge. The site contains a diverse, hazardous mixture of weapons-related waste and other accumulated material placed into ponds and silos built hastily many decades ago. More modern buildings, meanwhile, include the world’s first large-scale advanced gas-cooled reactor (now successfully decommissioned), fuel reprocessing plants, fuel fabrication plans and waste stores.

These will also eventually be dismantled.

“Estimates are that the whole decommissioning mission will take another 120 years” 108

Research and development critical Understandably, research and development (R&D) is critical to solving some of the unique, often hazardous challenges that arise as facilities are taken apart and the waste is retrieved.

An important part of the NDA’s responsibility is to ensure that the right level of R&D is carried out, enabling real progress including on issues that have often never been addressed before, either in the UK or overseas.

As a small organisation of nearly 200 staff, tasked with strategic national oversight and direction rather than hands-on clean-up, the NDA provides a significant amount of R&D funding to the Site Licence Companies (SLCs) which manage sites on a day-to-day basis and are responsible for detailed decommissioning programmes spanning many decades. Planning their future technological requirements is a key part of site activities, along with a requirement to demonstrate that the selected technology will deploy successfully.

The NDA’s strategy acknowledges that R&D is an integral part of plans for delivering decommissioning. Pragmatic and costeffective application of new technology or innovative processes, whether tailor-made for

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Nuclear nuclear or adapted from other sectors, can improve safety, shorten timescales, lessen environmental impacts and reduce costs.

Up to £85m of investment is provided annually at site level, while the NDA invests approximately £5m (much of it in collaboration), targeted at R&D projects that offer potential for innovation across multiple sites and also to support the development of the vital, specialist technical skills that will be needed in the future.

Collaboration and technology transfer are key areas of focus. The NDA works increasingly with partner research organisations to harness additional funding, and encourages suppliers to work together, to link up with academia and with Site Licence Companies. Crossover of innovation from other industries is also proving valuable in all directions: modifying promising technology for deployment in nuclear and vice versa.

Unsurprisingly, Sellafield accounts for more than half the NDA’s annual budget.

R&D funding is targeted at addressing its numerous complexities and uncertainties.

Making sure innovation works An essential feature of technical innovation associated with radioactive or hazardous environments is the need to ensure it will work when deployed. This sounds obvious and simple, but tweaking equipment or adjusting systems once inside a contaminated cell, for example, is difficult. Therefore extensive trials and tests form an integral part of comprehensive project development prior to deployment.

The NDA and its SLCs have adopted good practice developed by NASA that was designed to establish the maturity of technology and its potential readiness for deployment as part of the US space exploration programme. This system uses technology readiness levels on a nine-point scale and helps address the maturity of the chosen technology, any risks to deployment and provides a common language to consider technologies across projects and even industries.

“Pragmatic and cost-effective application of new technology or innovative processes, whether tailormade for nuclear or adapted from other sectors, can improve safety, shorten timescales, lessen environmental impacts and reduce costs”

Physical Research Council and UK Trade and Investment (UKTI), which supports UK businesses in the international market. Pooling funds can also attract private-sector contributions, potentially doubling the amount of investment available and providing a more sustainable source of funding

This level of partnership between all the key nuclear organisations ensures that innovation is not only well coordinated and cost-effective but targeted where it is most needed. The sharing of information across the sector also improves collaboration and minimises duplication.

Since 2012, this joint approach has seen an investment of around £50m from funding bodies and from participating organisations.

The research projects supported cover all civil nuclear operations: many technologies relate directly to decommissioning, while those developed for existing or future generation also have potential in the decommissioning sector.

Internationally, the NDA is among the many organisations providing support for the clean-up of Japan’s Fukushima Daiichi plant, severely damaged by the tsunami that followed the devastating 2011 earthquake. More than 160 countries and 40 organisations responded while David Cameron offered high-level political support which was followed by information exchange agreements between Japanese organisation, Sellafield Ltd and the NDA. With the support of NDA subsidiary International Nuclear Services, a number of UK companies have provided skills and services to assist the ongoing work.

Separately, and as part of its direct investment, the NDA has recently awarded contracts worth up to £12m in total over four years to a series of organisations that will be working on specific themes as part of NDA’s strategic R&D portfolio. Many are collaborative in nature, with partnerships between large corporations, SMEs and research institutions tasked with specific projects. More than 70 organisations have secured work, based on submissions related to key NDA themes: university interactions; spent nuclear fuels and nuclear materials; integrated waste management and site decommissioning and remediation.

A partnership approach As well as collaborating on funding, the NDA’s R&D team also works with partners both in the UK and overseas to pool experiences, improve information sharing and avoid duplication.

Skills investment for the future Skills are another critical area of focus for the NDA, whose century-long mission means an ongoing requirement for high-level technical expertise over many decades. Faced with the obvious implication that ‘decommissioning’ means (quite correctly) closing plants down, the industry acknowledges that it will need to encourage bright young recruits and invest significantly in university research to develop this capability in academia so it will be available when required.

Much of the development work and creative thinking is sparked by suppliers who provide products and services to our sites. Many are small specialist organisations that can benefit from support to take ideas forward, or to link up with academic institutions for additional input. There is further potential to harness technologies from outside the nuclear industry, often a more efficient and cheaper option to re-inventing the wheel.

To provide strategic direction, advice and coordination, the NDA established its Research Board, which is independently chaired.

Membership comprises senior representatives from all sectors of the nuclear industry including the government, regulators, SLCs, the Ministry of Defence, industry, research councils, overseas experts and Radioactive Waste Management Ltd, the NDA subsidiary responsible for developing a geological disposal facility.

The NDA currently supports almost 60 PhD projects, sponsors students at 22 universities and has seen more 50 peerreviewed publications from NDA-sponsored R&D in the last two years. Working with the EPSRC, Sellafield Ltd and the National Nuclear Laboratory, the NDA is also jointly sponsoring a four-year programme of research being undertaken by 30 doctoral students at 10 UK universities, named DISTINCTIVE (Decommissioning, Immobilisation and Storage Solutions for Nuclear Waste Inventories).

A range of initiatives are in place to seek out and build up their expertise, including allocation of funding through a collaborative drive by public bodies. These include the NDA, universities, the Department of Energy and Climate Change, Innovate UK (the government innovation agency), Research Councils UK, the Engineering and

Supporting the board, representatives from the UK’s nuclear site operators meet quarterly as part of a technical network, the Nuclear Waste and Decommissioning Research Forum. The Ministry of Defence and EDF, owner of the current AGR reactor fleet, are both represented on this group which has a series of working sub-groups.

The intent is two-fold: to promote research in relevant subjects and encourage interest in decommissioning as a career. The benefits are far wider than the NDA mission: globally, the decommissioning industry is expected to be worth £250bn by 2030, while new build investment is likely to reach a total of £930bn.

Harnessing technologies

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Nuclear These case studies represent two out of many involving different funding routes as well as collaboration between partner organisations, and the opportunity to conduct extensive trials on a site, in these cases at Sellafield.

Case study: RISER

Case study: LaserSnake An illustration of the NDA approach is the development of the LaserSnake robotic equipment, which has recently been successfully trialled at Sellafield.

RISER uses its own internal navigation system to manoeuvre inside industrial spaces RISER (Remote Intelligence Survey Equipment for Radiation) combines separate pieces of technology to produce a sophisticated radiationmapping system mounted on a drone that collects information on contamination distribution to enable decommissioning plans to be developed.

Remote operation is vital, enabling the lightweight drone to manoeuvre accurately inside high-dose environments, including complex spaces. RISER builds its own 3D map as it goes and simultaneously uses it to navigate and map radiation.

The N-VisageTM radiation mapping software, developed by Createc, received direct investment from the NDA as part of an innovation competition in 2009, enabling continued development during the critical early stages.

As well as being used in the UK, N-VisageTM has been deployed at the damaged Fukushima Daiichi power station, where the laser scanning combined with gamma imaging shows the distribution of radioactivity.

The RISER project is a collaboration between Cumbria-based Createc and Blue Bear Systems Research in Bedford; the collaboration was formed after the companies met at an Innovate UK Nuclear team-building event and was partially funded through the collaborative initiative by NDA, Department of Energy and Climate Change, the Engineering and Physical Research Council and Innovate UK. RISER has been trialled in Sellafield’s Windscale Pile chimney where it provided valuable information about internal contamination that will enable decommissioning plans to be drawn up. n

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In 2008 the NDA allocated £1m in a project with TWI Ltd to demonstrate the effectiveness of lasers, widely used by non-nuclear industries, in cutting up metal and removing contaminated concrete surfaces. The process was shown to be highly accurate leaving little waste – ideal for situations too hazardous or inaccessible people-led teams.

Collaboration with Bristol-based OC Robotics then led to the first LaserSnake project, where the cutting head was attached to a snake-like robot arm and its potential as a decommissioning tool was demonstrated in a non-active environment. Subsequent funding of approximately £6m was allocated from the 2012 joint initiative to a consortium led by OC Robotics and including TWI, ULO Optics, Laser Optical Engineering and the National Nuclear Laboratory.

This led to Lasersnake2, a new, larger, more accurate snake robot, with purpose-designed lightweight cutting heads and special optics to enhance the tolerance for cutting sections above 40mm thick. LaserSnake2 was recently demonstrated cutting a double-walled stainless steel dissolver vessel, with a 32mm thick inner shell, in a radioactive environment at Sellafield.

LaserSnake2 is one of a number of nuclear R&D projects designed to make the decommissioning process safer and more sustainable

“LaserSnake2 can be customised to suit a range of conditions and is now ready for commercial deployment” Laser cutting is faster and far more efficient than requiring workers in protective air-fed suits to manually cut up the vessel with heavy-duty sawing equipment, restricted to working for a few hours at a time. It is also safer, cheaper and produces less secondary waste.

This has shown Lasersnake2’s capability to cut some of the thickest materials on the Sellafield site remotely, and its potential to access active areas where other robotic technologies would have difficulties.

Sellafield has thousands of items that must be cut up for removal before the buildings can be decommissioned. Other sites could also benefit from the LaserSnake approach, while aerospace and defence industries have already realised its potential.

LaserSnake2 can be customised to suit a range of conditions and is now ready for commercial deployment. Its journey has taken four years and involved many steps, including collaboration on the investment, collaboration between developers, collaboration with Sellafield and ongoing support from joint sponsors NDA, Innovate UK and DECC. Separately, laser cutting has been successfully trialled at the Hinkley Point A site, where spent fuel skips have been size-reduced, then cleaned by a separate milling process to remove surface contamination. The technology enabled the skips to be recycled as clean metal and has potential for other sites. n

The Nuclear Decommissioning Authority is an executive non-departmental public body responsible for the safe and efficient clean-up of the UK’s nuclear legacy. www.gov.uk/government/organisations/nuclear-decommissioning-authority

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Nuclear

South Africa is considering new nuclear power stations to supplement Eskom’s Koeberg plant near Cape Town (photo: Eskom)

Nuclear power in South Africa ready to leap forward

by Ian Hore-Lacy, Senior Research Analyst, World Nuclear Association

South Africa has given nuclear the green light. With firm plans to build between six and eight new nuclear reactors – giving 9.6GW of total new capacity – by 2030, opportunities abound for the UK nuclear supply chain

S

outh Africa is getting ready to issue its request for proposal for 9.6GW of nuclear power capacity.

An international cast of five reactor vendors will soon be invited to make proposals: Rosatom, SNPTC, KEPCO, EDF/ Areva and Westinghouse – from Russia, China, South Korea, France and the US respectively.

China is not far behind, and South Korea has established a fine reputation with its construction of four reactors in the UAE.

Of course, the quality and price of the nuclear power plants (NPPs) offered will be of vital interest, but since South Africa is anything but flush with funds, much will depend on the finance packages attached as well as plans for technology transfer and localisation of manufacture and construction. Russia has the best reputation in providing finance for 85 to 90% of the costs, and is a front-runner, having high-level agreements in place, but

Electricity consumption in South Africa has been growing rapidly since 1980 and the country is part of the Southern African Power Pool (SAPP), with extensive interconnections. Total installed generating capacity in the SAPP countries is about 55GW, of which around 80% is South African, mostly coal-fired, and largely under the control of the state utility Eskom.

Eskom supplies about 95% of South Africa’s

It is quite possible that two vendors and deals will be selected with around half of the target capacity at each site.

Installed generating capacity

electricity and approximately 45% of Africa’s.

Of its total installed net capacity of 40.5GW (44.2GW gross), coal-fired stations account for 34.3GW and nuclear, 1.8GW. In recent years, demand in South Africa has been uncomfortably close to this. Last year the Koeberg nuclear plant generated 11TWh – about 4.7% of total South African total.

The Koeberg plant was built by Framatome (now Areva) from France and commissioned in 1984–85. It is owned and operated by Eskom and has twin 900MW class (970 and 940MW gross) pressurised water reactors (PWR) the same as those providing most of France’s electricity. ‘Stress tests’ similar to those in the EU post-Fukushima were carried out in 2011 with International Atomic Energy Agency (IAEA) help.

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Nuclear Operating South African power reactors Reactor

Type

Net capacity

First power

Planned closure

Koeberg 1

PWR

930MW

April 1984

2024

Koeberg 2

PWR

900MW

July 1985

2025

Total (2)

1,830MW

Forward plans In the 2011 Draft Integrated Electricity Resource Plan for South Africa – 2010–30 Integrated Resource Plan (IRP), nuclear prospects were outlined for 9.6GW, supplying 23% of the electricity. In November 2011 the National Nuclear Energy Executive Coordination Committee was established as the authority for decision-making, monitoring and general oversight of the nuclear energy expansion programme. An IAEA Integrated Nuclear Infrastructure Review was carried out in 2013.

Although the draft IRP included six new 1.6GW reactors coming online in 18-month intervals from 2023, Eskom said that it would be looking for lower-cost options than the earlier AP1000 or EPR proposals from Westinghouse and Areva, and would consider older designs from China (perhaps CPR–1000) or South Korea (perhaps OPR). The capital cost per installed MW of CPR–1000 was said to be about half that of an AP1000 or EPR. Before approval, a safety report for the selected specific design must be submitted to the National Nuclear Regulator for evaluation and approval, and a Nuclear Installation Licence obtained. However, following the Fukushima accident it is likely that a state-of-the-art design will be favoured.

Early in 2011 Areva stepped up its involvement with the Nuclear Energy Corporation of South Africa (Necsa), and in 2013 Rosatom declared its interest in bidding. Bids were expected to be called early in 2014 so that the contractor/vendor could be on site in 2016, with a view to operation of the first unit in 2023. Initially about 30% local content was expected in the project, rising to 40% later.

South Africa announced in December 2011 that some US$50bn would be spent on nuclear capacity to 2030. A national development plan then cast doubt on nuclear power’s financial viability, but in November 2012 the cabinet endorsed a ‘phased decisionmaking approach for implementation of the nuclear programme’, along with the ‘designation of Eskom as the owner-operator as per the Nuclear Energy Policy of 2008’.

President Jacob Zuma’s annual state-of-thenation address in February 2015 reaffirmed the 9.6GW target with the first unit online in 2023 and said that bids would be sought from

112

the US, China, France, Russia and South Korea.

In May, South Africa’s Energy Minister, Tina Joemat-Pettersson, said that the procurement process for the new NPP would begin by September, and she expected that a strategic partner would be selected by March 2016. Early in June 2015 Eskom ceded control of the new build programme to the Department of Energy.

“The quality and price of the nuclear power plants offered will be of vital interest, but since South Africa is anything but flush with funds, much will depend on the finance packages attached as well as plans for technology transfer and localisation of manufacture and construction”

Russian interest In November 2013 Necsa signed a broad agreement with Russia’s NIAEPAtomstroyexport and its subsidiary Nukem Technologies, to develop a strategic partnership including nuclear power plants and waste management, with financial assistance from Russia.

Commenting at that time, Rosatom offered to ‘build the entire process chain of NPP construction and operation’. In addition to constructing up to eight Russian VVER reactors, Rosatom’s integrated approach to the construction of research reactors and establishment of research centres would lay ‘the basis for joint business in the area of isotope production and sales in the international market’.

According to Rosatom, the NPP construction project will allow 40–60% of equipment orders

to be placed with South African companies, help create 10,000 jobs, generate a profit of US$48.3bn for local businesses and bring US$52.5bn in tax revenue to the national budget. Finance was not mentioned then.

In September 2014, Rosatom signed an agreement with South Africa’s energy minister to advance the prospect of building up to 9.6GW of nuclear capacity by 2030. The energy minister said that ‘this agreement opens up the door for South Africa to access Russian technologies, funding, infrastructure and provides proper and solid platform for future extensive collaboration’.

Necsa later said that the new agreement ‘initiates a preparatory phase for the procurement process for the new nuclear build in South Africa'. Similar agreements will be signed with other vendor countries that have expressed an interest in assisting South Africa with the build programme.

‘No vendor country has been chosen yet and no technology has been decided.

The agreement refers only to what Russia could provide if chosen’. Rusatom Overseas confirmed the likelihood of a Russian government loan, and said that the build-ownoperate model was preferable. OKB Gidropress and NIAEP–ASE subsequently presented the VVER–TOI design as appropriate – an advanced version of Russia’s VVER–1200.

China not left out A similar inter-governmental cooperation agreement was signed with China in November 2014. Joemat-Pettersson said that the agreement ‘initiates the preparatory phase for a possible utilisation of Chinese nuclear technology in South Africa’. Three further agreements in December were: between Necsa and China National Nuclear Corporation to establish a cooperative partnership supporting the country’s nuclear industry, between China’s State Nuclear Power Technology Corp (SNPTC), the Industrial and Commercial Bank of China and South Africa’s Standard Bank Group with a view to financing new nuclear plants, and between Necsa and SNPTC for training South African nuclear professional staff.

In February 2015 Necsa signed a further skills development and training agreement with SNPTC and China General Nuclear Power Corp (CGN), funded up to 95% by China. CGN has had an office in Johannesburg since 2010.

It was reported in March 2014 that China’s main nuclear power companies were lining up to bid for the contract to build six reactors by 2030.

China’s Ministry of Commerce reported that negotiations towards a nuclear cooperation agreement were proceeding. Joemat-Pettersson said that this could involve the joint marketing and supply of nuclear energy products along with infrastructure funding to promote nuclear

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Nuclear

Rosatom’s VVER reactor technology makes Russia one of the frontrunners in South Africa’s nuclear expansion plans (photo: Rosatom)

“In March 2016, Eskom submitted site licence applications to South Africa’s National Nuclear Regulator for both Thyspunt and Duynefontein to construct and operate multiple nuclear power reactors and associated auxiliary nuclear installations”

power developments across the region (China’s CGN is ahead of Russia in nuclear power agreements with Kenya). SNPTC is focused on the possible supply of CAP1400 reactors.

Chinese industry officials in December 2015 expressed confidence in securing the US$80bn order for CAP1400 units, though the first of these was not yet under construction (and is still delayed at the time of writing).

France and others A nuclear cooperation agreement with France was signed in October 2014. JoematPettersson said that ‘this paves the way for establishing a nuclear procurement process’. Areva welcomed the agreement, and said that it was ready to support the development of new South African nuclear projects, ‘notably through its Generation III+ EPR reactor technology’. Recently senior French spokesmen have said that Areva/ EDF ‘should win the bid’ on the basis of

its ongoing involvement with Eskom.

Agreements with the US and South Korea are in place, and a further agreement is pending with Japan.

Westinghouse has been active in South Africa’s nuclear industry, mainly through support to Koeberg, since the 1990s. In October 2013, Westinghouse signed an agreement with the Sebata Group of engineering companies to prepare for ‘potential construction’ of new nuclear plants in South Africa.

Site selection, environmental preparation The environmental impact assessment process initiated in 2006 confirmed the selection of three possible sites for the new nuclear power units: Thyspunt, Bantamsklip and Duynefontein, the last of which is very close to the Koeberg nuclear plant. All are in the Cape region

and were subject to further assessment.

A draft environmental impact report (EIR) was published in March 2010 recommending the Thyspunt site in Eastern Cape province, near Oyster Bay, Jeffrey’s Bay and a few kilometres west of Cape St Francis. Bantamsklip is east of Cape Town near Gansbai. A final EIR was submitted to the Department of Environmental Affairs early in 2011.

In March 2016 Eskom submitted site licence applications to South Africa’s National Nuclear Regulator for both Thyspunt and Duynefontein to construct and operate multiple nuclear power reactors and associated auxiliary nuclear installations.

Bid process Request for proposals are expected to be issued to the bidding countries in the coming months.

The five bids are broadly predictable, but the outcome will depend very much on finance and the package of supply chain arrangements. n

The World Nuclear Association represents the global nuclear industry.

Its mission is to promote a wider understanding of nuclear energy among key international influencers by producing authoritative information, developing common industry positions, and contributing to the energy debate. www.world-nuclear.org

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Nuclear

Germany’s nuclear phase-out

by Oliver Barnes, EIC Sector Analyst – Power and Nuclear

In 2011, after the Fukushima incident, Germany decided to completely phaseout nuclear power by 2022. Seventeen nuclear power reactors will now be decommissioned, and the German nuclear industry is looking to UK companies to assist in the volume of work that is set to last into the second half of the century

E

urope is at a crossroads with nuclear power. While some nations have ambitious plans to construct a new generation of plants – the UK is currently proposing the largest – others are moving away from nuclear power citing safety concerns, decreased profitability and shifts towards renewables and decentralised energy generation.

This trend, combined with a substantial number of ageing reactors in the region, has led the European Commission to predict that 50 of the 129 reactors currently in operation in the European Union (EU) will be shut down by 2025. This represents a huge challenge for the region, not only to replace this generation capacity, but also due to the careful planning and enhanced cooperation necessary among countries to facilitate the simultaneous decommissioning of a large proportion of nuclear power plants in the EU.

“In 2011, after the Fukushima disaster, Germany decided on a complete phase-out of nuclear power” 2011, the German government decided, just three days after the event, to declare a three-month moratorium on nuclear power plants during which checks would be made and nuclear policy reconsidered.

During the suspension, the Ethics Commission on Safe Energy Supply, comprised of 17

representatives from industry, research and politics reviewed Germany’s future nuclear plan and recommended a dramatic policy change: immediate closure of the country’s eight oldest reactors and a complete nuclear phase-out by 2022. Despite safety assurances in a report produced by the German Reactor Safety Commission in May 2011 that all reactors in Germany were safe and robust, the government decided to adopt the Ethics Commission’s recommendations and enact the phase-out plan.

Subsequently, all nuclear power plants that began operation in 1980 or earlier were immediately shut down, leading to a total of over 8GW in capacity offline under government direction – about 6% of the country’s generation.

The European Commission predicts that 50 of the 129 reactors currently in operation in the EU will be shut down by 2025

The Fukushima disaster One country that has taken decisive action to move away from nuclear power is Germany.

In 2011, after the Fukushima disaster in Japan, the country decided on a complete phase-out of nuclear power, marking the beginning of the end of five decades of nuclear power generation in the country.

This was not the first time the German government had passed legislation to end nuclear power in the country. Following the Chernobyl disaster in 1986, the government at the time decided to abandon nuclear power within 10 years, though an agreement in June 2000 secured government commitment to continue to operate existing plants – with a lifetime limit placed on all reactors equivalent to an average of 32 years each.

However, following the world’s first triple reactor meltdown at Fukushima in March

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Nuclear

E.ON’s Grohnde is one of eight remaining reactors in Germany, all of which will be shut down by 2022

The reactors affected were Biblis A and B, Neckarwestheim 1, Isar 1, Unterweser and Phillipsburg 1, along with Brunsbüttel and Krümmel, already in long-term shut down.

Energy gap implications Significant questions have been raised about the German government’s decision to phase-out nuclear power, with many saying it was a knee-jerk political decision rather than one based on specific nuclear power safety evidence, highlighting the fact that Germany is a not in a seismic danger zone like Japan, and that Germany’s reactors were among the safest in the world.

The phase-out led to further questions about where the lost power supply will be made up, given that nuclear power accounted for over 20% of electricity generation in Germany.

Recouping almost a quarter of the country’s capacity, which was provided by secure, baseload generation, is certain to require a huge investment, not only on the supply side, but also in transmission and distribution, if, as per the German Energiewende policy, the replacements will take the form of intermittent renewables.

Financial implications As of 2016, only eight reactors are operating with a combined capacity of 10.7GW: RWE operated Emsland and Gundremmingen B and C, E.ON’s Grohnde, Brokdorf and Isar 2, and Philipsburg 2 and Neckarwestheim 2 owned by EnBW. These plants, which will all be shut down gradually by the end of 2022, along with the eight closed in 2011 and another unit which

“A total of 17 nuclear power plants will be decommissioned at a predicted cost of around €38bn”

construction, operation and decommissioning of a radioactive waste repository. It was also suggested that a risk premium of around 35% should also be added to close the gap between provisions and costs.

Decommissioning options

was closed in June 2015, means a total of 17 nuclear power plants will be decommissioned at a predicted cost of around €38bn.

Germany is the only country in Europe to have completely decommissioned nuclear power plants and released the sites from regulatory control. However, the reactors so far dismantled and decommissioned have been small, experimental reactors that were relatively simple to decommission.

Questions have been raised over whether the four operators of the German nuclear power plants have enough money set aside to decommission their reactors, given that their operational lives have been cut short and hence contributions to their respective decommissioning funds have been truncated, rather than being allowed to accumulate for a full 40 years or more.

The country has yet to tackle the larger, more complex commercial power plants situated around the country. So far, most operators have decided to undertake immediate dismantling of their plants, rather than opting for Safstor, where the facility would be maintained in a safe enclosure for a period of time and then dismantled.

In April 2016, the commission reviewing the financing of the phase-out recommended to the German government that the reactor owners pay €23.2bn into a state-owned fund for decommissioning of the plants and managing radioactive waste. The independent commission suggested the utilities pay €4.7bn to the state to secure the financing of interim storage, the production of repository containers for waste from reprocessing and the transportation from the interim storage facility to the final repository.

The operators point out that it is advantageous to undertake decommissioning with their current staff as they know and understand the workings of the plant, rather than dismantling after a Safstor period of 40–50 years when this knowledge may be lost. Common to both methods, however, is a post-operation phase which will last for approximately five years, during which fuel assemblies and operational media and waste will be removed.

The commission also recommended the utilities pay €12.4bn to finance the selection,

With a number of plants already shut down prior to 2011 and those still to be closed, by 2022, more than 20 nuclear

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Nuclear “Germany is the only country in Europe to have completely decommissioned nuclear power plants and released the sites from regulatory control” power plants will be in various stages of decommissioning in the country. The volume of work will mean that decommissioning will last into the second half of this century.

Key to the successful decommissioning of the fleet of nuclear power plants will be the planning of each project, starting from the back end and in particular the disposal of the radioactive waste. Critical path analysis is required to avoid any bottlenecks in the project (related to easy-to-use decommissioning technology, interference between parallel dismantling work packages, licensing or staffing aspects) and ensure that all phases run smoothly. The purchase and delivery of containers and casks licensed for the storage and transport of waste also has to be planned and controlled carefully.

In addition to planning, challenges exist in managing financial and human resources: as funds are based on current decommissioning cost estimates, project management is crucial to ensure that the work is performed within the expected budget and with the suitable number of experienced staff.

Supply chain opportunities It is important to note that the German nuclear sector is inexperienced at carrying out multi-site parallel programmes, and has never undertaken such scale of work in its nuclear decommissioning industry simultaneously. Furthermore, given the deadline set for the phase-out, there are a number of other challenges that the country will need overcome in order to complete its decommissioning plans including reducing and controlling costs and schedule, building industry capacity, improving conventional safety and radioactive safety enhancements.

Companies in the UK are well placed to take advantage of nuclear decommissioning opportunities in Germany, given the UK’s

Experience gained through decommissioning work at facilities such as the Wylfa Nuclear Power Station means UK companies are well placed to take advantage of opportunities in Germany

experience and technological know-how in the nuclear industry. This is especially true in the decommissioning sector through work carried out at existing UK nuclear facilities such as Sellafield and the Magnox sites. Opportunities are to be found across the supply chain from the larger Tier 1 and 2 contractors, down to small and medium-sized enterprises for whom there are significant opportunities for supplying goods and services to the numerous projects.

In Germany, 14 large component removal projects are planned and need to be implemented alongside the same number of reactor pressure vessel segmentation and packaging projects. This is of particular importance to companies supplying remote technologies that are designed to work where human access would not be viable due to high radiation levels. In addition, much of this work is often undertaken underwater providing an effective shield against the radiation emitted by the materials to be disassembled. Innovative cutting tools and techniques, are also sought after: either thermal or mechanical techniques depending on the area and conditions within the plant.

Site clearance and storage Nineteen site clearance projects will also need to be undertaken, which will need to be designed, approved and implemented.

This includes supplying appropriate sampling methods to check surfaces for contamination to demonstrate compliance with clearance values required for approval

“Companies in the UK are well placed to take advantage of nuclear decommissioning opportunities in Germany, given the UK’s experience and technological know-how in the nuclear industry” 116

by the competent authority. In addition to this, more than 10 waste handling centres will need to be designed, built, commissioned and operated at the various nuclear sites.

Similarly to the UK, Germany has no repository, however, there are plans to construct one. Until one is available, conditioning of the waste (e.g. in a drum) or interim storage is required. Up until 2005, spent fuel assemblies from reactors could be delivered to reprocessing plants.

Since then, they have had to be stored in local interim storage facilities. Consequently, UK companies can take advantage of substantial opportunities in the waste management sector, not only in the construction of storage facilities, but also in the manufacture and supply of drums, casks and packaging to contain waste.

What lies ahead?

Two important anniversaries in the history of the nuclear power industry take place in 2016. It marks 30 years since the fatal nuclear meltdown in Chernobyl and five years since the catastrophe at Fukushima. These two events were crucial to the motivation for and timing of Germany’s decision to exit nuclear power once and for all.

The logistics of pulling the plug on what was until recently one of the country’s primary sources of power are proving an immense challenge. Legal hurdles, decommissioning technicalities and, above all, the questions of where to store the radioactive waste and who will pay for it all, are the main issues at hand.

UK companies are well placed to take advantage of the opportunities to come from the phase-out. The experience, technologies and knowledge already gained through work at nuclear facilities in the UK put both large and small companies in a prime position to win business in the decades of work to come in Germany. n

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Renewables

The fifth carbon budget: an important step towards a low carbon economy

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Renewables

The fifth carbon budget: an important step towards a low carbon economy

by Angus MacNeil MP, Chair, Energy and Climate Change Select Committee

The UK government has accepted the fifth carbon budget recommendations of the Committee on Climate Change to reduce carbon emissions by 57% by 2033, from 1990 levels. But what is the budget and what are the UK’s next steps?

The 2008 Climate Change Act commits the UK to reducing carbon emissions by at least 80% by 2050 from a 1990 baseline. To meet this target, the government sets carbon budgets, or emissions caps, for successive five-year periods. These budgets are important stepping stones on the path to 2050: providing the certainty needed for forward looking policy decisions and investment to take place.

“The Climate Change Committee had called for a 57% emissions reduction by 2030 to keep the UK on its cost-effective path to the 2050 target” Before it decides on a carbon budget, the government consults its statutory advisor, the Committee on Climate Change (CCC) – not to be confused with the cross-party Energy and Climate Change Select Committee, which I chair. The CCC analyses current climate science and possible future energy scenarios and determines the level at which budgets should be set. It produces an advisory report that the government takes

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2014: ,36% 2020: ,43%

4 CB: ,52%

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1500 1000

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500

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Budget emissions (i.e. Over five years; MtCO2e)

Setting the UK’s carbon budgets

The recommended fifth carbon budget would continue emissions reduction on the path to the UK's 2050 target

Annual emission (MtCO2e)

A

fter the political turmoil and uncertainty of recent months there has been at least some good news for energy and climate change policy. It was thoroughly buried in the avalanche of news following the Brexit vote, but on 30 June the government said that it would set a fifth carbon budget for 2028–32 that was commensurate with the scientific advice about the scale of emissions cuts needed.

Historical emissions Projected (net) emissions to 2020 Legislated carbon budgets Cost-effective path to 2050 Proposed fifth carbon budget Statutory 2050 target allowing for IAS emissions Allowance for IAS

90 95 00 05 10 15 20 25 030 035 040 045 050 2 2 19 19 20 20 20 20 20 20 2 2 2

Source: Committee on Climate Change into account before setting each budget. Four budgets have so far been passed into law, covering the period to 2027. They commit the UK to halving emissions by 2025.

Each new budget has to be set 12 years in advance, and the deadline for setting the fifth was the end of June. The CCC had called for a 57% emissions reduction by 2030 to keep the UK on its cost-effective path to the 2050 target. When my Select Committee decided to investigate whether the proposed budget was appropriate, we called, in our Setting the Fifth Carbon Budget report, for the government to accept the CCC’s recommendation.

election, not to mention the decision to decouple ourselves from the European Union.

It sends a welcome signal that the government is still committed to decarbonising, and that it will continue to drive energy policies designed to achieve that aim. Nevertheless, some argue it is not ambitious enough.

Is the budget ambitious enough?

In December 2015, the world reached a historic deal at the 21st Conference of Parties (COP21) in Paris. Governments collectively pledged to keep global average temperature rise to well below two degrees – the temperature increase widely believed to lead to dangerous levels of climate change. They even went further and agreed to attempt to keep temperature rises to below 1.5 degrees.

Setting the carbon budget at this level is welcome news. It provides some much needed certainty for an industry reeling from a series of sudden policy changes after the general

To do this, the UK may need to cut emissions deeper and faster than before. The fifth carbon budget should be considered a minimum.

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Renewables The CCC has committed to analysing what further level of emissions reduction may be required and will report on the implications of COP21 in the autumn.

The government has not completely accepted the CCC’s advice. On top of the 57% reduction, the CCC recommended that emissions from the international shipping sector should be capped in the budget for the first time, at no more than 40m metric tonnes of carbon dioxide equivalent from 2028 to 2032. When it accepted the fifth carbon budget, the government ignored this recommendation.

The CCC said that they would examine the government’s reasoning for not doing so in detail. We as a committee will keep a watching brief on this matter to ensure that the UK is as ambitious as we need it to be.

Decarbonising the power sector Most emissions reductions so far have been in the power sector, mainly due to growth in renewables and as the UK has moved away from coal. But the next steps will be

“Tangible policies and a long-term plan are now needed to provide essential certainty for investors”

“It sends a welcome signal that the government is still committed to decarbonising, and that it will continue to drive energy policies designed to achieve that aim” harder: we will need an ever-increasing share of low-carbon sources of electricity generation, especially as we electrify heating, the rail network and road vehicles.

But investors need certainty. To provide this, the CCC, backed by our report, recommended setting a decarbonisation target for the power sector of 100g/kWh for 2030. Unfortunately, the government has rejected this recommendation, to ‘retain the flexibility to pursue decarbonisation where it is cheapest’. Keeping bills down is of course a priority. But the cost of cleaner forms of electricity generation will only come down if the right signals are in place, and it is disappointing that the government will not commit to such a target. The more we delay, the more expensive this transition will get.

Where next?

The UK is on track to meet the first three budgets but progress is less certain thereafter.

Worryingly, National Grid’s future energy scenarios, launched on 5 July, further warned that the UK was almost certain to miss its 2020 EU targets for renewable energy. Of course, it is a moot point now

Greater transparency and clarity is needed on the government's existing low-carbon energy policies

whether that matters for a government committed to leaving the EU. But it is an indicator of our progress on decarbonisation.

Meeting our immediate and long-term targets will require action across the board: we need to make our power sector cleaner, but also reduce emissions in heating, transport, buildings and agriculture. The CCC’s latest report to parliament shows that progress in these sectors has stalled. So we need a tangible, feasible plan that is adhered to.

The government recognises this and has committed to producing a plan by the end of the year. The CCC sets out some important areas that the plan should address.

Firstly, new policies are needed to improve energy efficiency. My committee has consistently called for this and we hope that the government will set out a long-term approach soon.

Secondly, policies are urgently needed to decarbonise heating and improve the efficiency of new vehicles. Our ongoing inquiry into the 2020 renewable heat and transport targets has examined these issues and identified the decarbonisation of transport as one of the biggest challenges for the next decade.

Thirdly, a new approach to carbon capture and storage (CCS) is urgently needed, especially after the government put the hammer to its CCS competition last autumn. Gas-fired power stations emit less carbon dioxide than coal ones, but still too much. Without investment in CCS infrastructure now, meeting climate change targets could become vastly more expensive.

Finally, the cheapest forms of low-carbon electricity generation should be given a route to market. Since the election, the government has cut support for onshore wind and solar and there is increased nervousness among some investors looking at energy projects in the UK. Our recent report on investor confidence concluded that greater transparency and clarity from the government on lowcarbon energy policies is urgently needed.

In the aftermath of the EU referendum result, the fifth carbon budget provides welcome reassurance that the government remains committed to its targets. But tangible policies and a long-term plan are now needed to provide essential certainty for investors as we have been calling for and make the most of all the opportunities that a transition to a low carbon economy offers. n

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Renewables

A global solution from an island-nation

by Mark Shorrock, CEO, Tidal Lagoon Power Limited

The government’s independent review of tidal lagoon power will recommend to the secretary of state whether or not to authorise tidal lagoons as part of the UK’s electricity portfolio. So, what is the case for tidal lagoons?

D

uring the last five years the team at Tidal Lagoon Power has focused on a vision of a national fleet of tidal lagoon power plants that could provide up to 8% of UK electricity for the next 120 years.

The first lagoon, ‘pathfinder’, is at Swansea Bay, with an installed capacity of 320MW. The second lagoon in Cardiff – the first project at full-scale – will have an installed capacity of around 3GW. Both lagoons could be commissioned within a decade.

Four more large lagoons are envisioned.

Cardiff will generate around 5,500GWh of reliable power each year, enough to meet the needs of every home in Wales. For comparison, the world’s largest offshore wind farm, to be built off the Yorkshire coast, will generate around 4,000GWh per year.

The pathfinder at Swansea Bay has been successful in passing important environmental and planning stage gates, including award of a Development Consent Order last year.

Swansea Bay Tidal Lagoon is the first tidal range project to secure planning consent in the UK, an achievement of which we are very proud.

Unique lifespan As a form of energy infrastructure with an ultra-long life – 120 years, compared to 25 years for wind turbines or 60 years for nuclear – it has been a challenge to compare tidal lagoons with other forms of energy on an ‘apples-to-apples’ basis.

This has been especially so when considering the cost of power and the question of affordability. All new power stations in the UK require support via energy bills, no matter what technology is employed. Framed into the same support contract as shorter-lived projects, a 120-year asset is always going to look expensive: the analysis is confined to the first quarter of its working life.

Our discussions with the government have progressed to a more realistic analysis, reflecting the unique lifespan of lagoons.

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Tidal Lagoon Swansea Bay's Visitor Centre will accommodate up to 100,000 visitors annually

“The analysis shows that the UK’s first largescale tidal lagoon being developed for Cardiff can generate the cheapest electricity of all new build power stations” Government review In February 2016 the government announced a review of the whole tidal lagoon industry, led by Charles Hendry, former Minister of State for Energy. The review commenced in May and will run through to November 2016.

It is assessing the strategic case for tidal lagoons and whether they could play a cost effective role as part of the UK energy mix.

To be clear, although an unexpected development for our team and investors alike, we are completely on board with the process and its full and transparent analysis of the opportunity at hand.

Its assessment of the practicality and feasibility of tidal lagoon energy in the UK will cover questions of cost, finance, scale, competition,

supply chain and global deployment. In short, the process is about thoroughly ‘kicking the tyres’ – inspecting, verifying and sense-checking the case for tidal lagoons against government policy, as well as stakeholder expectations.

One big focus will be on the level of support required. Many of the engineering and project questions having been reviewed and validated by experts in the nationally significant infrastructure project process.

The Hendry review will ultimately make a recommendation to the government ahead of final decision-making at the turn of the year.

We are confident about the robust quality of the case we are making. The tidal lagoon programme has been under scrutiny in a number of planning and environmental processes and has passed with flying colours.

And, as discussed later in this article, we have a compelling offer on the question of affordability.

UK power and role of subsidy By 2030, the UK will have closed 82% of its existing fossil fuel based power station capacity. At the same time electrification policy calls for electric trains, electric heat pumps and more electric cars – all new demand.

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Renewables ■■ Reliable – employing proven technology to harness entirely predictable tides over a 120-year life, lagoons are the very definition of energy security

Even when all currently consented projects are accounted for, including planned interconnectors to Europe, the UK faces a large gap between its power appetite and expected capacity. We should expect our ‘power deficit’ to be front of mind for the next 20 years.

■■ Low cost – the bill payer support required to incentivise investment in large lagoons is not just low – it can be the lowest of all low carbon sources. Lower than combined cycle gas turbines running at high loads, and lower than nuclear

Building new power stations to address this deficit means power will be more expensive than that from old power stations long paid-off – no matter what technology is employed.

However, the cost of constructing a new fleet of UK power stations does not need to translate to equally higher bills. Energy efficiency will play a significant role. Denmark, for example, has the highest energy rates in Europe, but their household bills are equivalent to ours thanks to their efficiency measures.

The UK government needs to incentivise new build through a variety of enabling contracts that pay the generator a premium over the wholesale cost of power. This premium is ultimately borne by the UK bill payer. We recently published data about the relative cost of these subsidies. But to better understand the data, it is helpful to review the context.

Decarbonisation is causing a transformation in every country’s power networks – from power networks that were historically largely centralised and predictable, to networks that are much more decentralised, with a much greater component of variable power that is less predictable in the intra-day cycle. In this new world, not all electrons are equal.

UK Power deficit in numbers 85GW Installed capacity

20GW Future electrification demand (Transport, heat, etc) + 38GW Going offline (Coal, etc) = 58GW Total new capacity needed 18GW Consented capacity (Nuclear, tidal, wind, etc) 8GW Interconnectors (Not yet consented) = 32GW The power deficit

Tidal Lagoon Power engineers accessing the underwater housing of a variable speed rotor.

A GE/Andritz Hydro consortium will build these turbines So, a low support cost is important, but the qualities of power provided and its network integration are also important.

Tidal lagoon power Tidal lagoon power takes advantage of the moon’s gravitational pull that sweeps Atlantic tides into the UK’s western estuaries. The resulting tidal range is the second highest in the world; lifting huge volumes of water by as much as 14 metres. On a spring tide, twice a day, over 4bn cubic metres of water flow in and out of the Severn Estuary.

Tidal lagoons are impoundments connected to the shoreline that hold back and then channel rising and falling tides though bidirectional turbines located in the lagoon wall. When the difference in water level, or ‘head’, inside and outside of the lagoon is at its greatest, the lagoon releases huge volumes of water to drive its turbines.

Imagine a hydropower dam that runs reliably both ways, and you have the idea of tidal lagoon power.

Marine hydro turbine technology is new to the UK, but not the world. The longestrunning project is France’s La Rance power station in Brittany. Its turbines have generated reliable power for 97% of its 49-year operation to date. The technology is proven. And the power generated is said to be the cheapest in Europe today.

Of course power electronics have improved, and today’s turbines offer greater efficiencies and greater flexibility in terms of maximising head and being able to generate power at times of greatest need. In this respect, a lagoon is effectively a very big, natural battery.

Tidal lagoon power also has the following characteristics: ■■ Big, and scalable – the UK needs a lot of new power generation capacity, and large tidal lagoons are comparable to nuclear in their peak capacity

■■ Years to build, not decades – a big lagoon takes around seven years to build, a much lower risk construction than nuclear Power output from tidal lagoons can be modulated in order to provide grid balancing services. A portfolio of lagoons in multiple locations around the UK coast, with different tidal cycles, has the potential to provide roundthe-clock grid balancing services. With the right policy regime in place, tidal lagoons can provide power to the National Grid at times when that power is most needed; their inherent flexibility is a huge asset to the system.

Thus lagoons can help to facilitate the integration of further intermittent wind and solar capacity with nuclear, whose power output is largely inflexible. Tidal lagoons are clearly part of the UK’s long-term energy solution.

Cost-effectiveness So, what about value-for-money? We recently conducted a study – validated by Pöyry – to stack up support costs for all new UK power stations, and to put tidal lagoons in that context.

We looked at how much actual cost each contract, awarded and forecast, commits the bill payer to and how much power they are likely to get in return over the life of the plant. These are the two key ingredients for anyone seeking to understand value-formoney in the power sector, and they are all too often missing from the analysis.

Published as the New Power Cost League Table (Table 1), we hope that this ‘applesto-apples’ comparison has contributed to the debate around energy costs.

“With the right policy regime in place, tidal lagoons can provide power to the National Grid at times when that power is most needed; their inherent flexibility is a huge asset to the system” 123

Renewables The table shows the consumer cost of each megawatt hour of power delivered by the UK’s new generation of power stations. Notice how the ‘premium’ for new build, low carbon generation is reducing as old enabling contracts are replaced by new, more competitive contracts.

Wind and solar have seen significant reductions in their consumer cost since the first contracts were issued. This is very good for UK bill payers.

It means that the renewables support process is responsive to both lower cost and increased competition. Where new technologies are introduced, they are coming in on trend.

The analysis also shows that the UK’s first large-scale tidal lagoon being developed for Cardiff can generate the cheapest electricity of all new build power stations.

Tidal lagoon technology is very much like large-scale hydro. There is a significant and capital intense build of relatively simple infrastructure. Once built, its ultra-long lifecycle has a very low operating cost. If you integrate these features into an efficient financing and support structure, you can leverage the unique properties of the asset to get the best deal for the consumer.

The pathfinder lagoon at Swansea Bay is a much smaller project, essential to prove the concept and kick-start the industry.

You will see that it registers an equal score on the league table to new nuclear. But because the project is small, its total cost to bill payers is also small, at around 20–30 pence per household each year on average.

For comparison, each UK household will pay over £12 each year to support the Hinkley Point C new nuclear facility.

Major components can be sourced in the UK – a first-mover advantage for those suppliers

Table 1. The New Power Cost League Table 2016 UK Consumer cost over lifetime £/MWh: (2012 prices) Solar feed-in-tariff 2012

Biomass conversion final investment decision enabling for renewables 2016

£32.99

£89

New nuclear

Offshore Wind final investment decision enabling for renewables 2017

Tidal Lagoon Swansea Bay

£25.78

£74.04

£25.78

Combined cycle gas turbine DECC levelised cost of electricity 20% load factor

Combined cycle gas turbine DECC levelised cost of electricity 93% load factor

£53.73

£21.95

Solar feed-in-tariff 2015

Onshore wind contract for difference 2019

£50.88

£20.07

Offshore wind contract for difference 2018

Offshore wind contract for difference 2025

£50.33

£19.72

Onshore wind feed-in-tariff 2012

Solar contract for difference 2017

£43.37

£18.68

Offshore wind contract for difference 2020

Tidal Lagoon Cardiff

£36.39

“Tidal lagoons are clearly part of the UK’s longterm energy solution” And from Swansea we move straight to much larger lagoons. Because the carrying capacity of the lagoon increases geometrically – a function of the square of the diameter – the economies of scale are considerable. The decline in cost as shown in the league table is not about a technology learning curve (although we will get more efficient), it is about the laws of physics.

Associated benefits The strategic case for tidal lagoon energy runs deeper than the provision of secure and affordable power. Charles Hendry and

£7.80 The 2016 New Power Cost League Table illustrates that tidal lagoons in Swansea Bay and Cardiff require very little subsidy per MWh over the project lifetime his review team will also consider value-formoney as it pertains to the multifunctional role that tidal lagoon infrastructure can play at the heart of our coastal communities.

This includes the ability to protect against coastal flooding and sea level rises, and the provision of major opportunities in tourism, leisure, conservation and marine aquaculture.

And then there are the direct economic and employment benefits derived from first-mover advantage in a new global industry. Our Britishmade turbines and generators will present UK steel sector businesses with a vital new market.

Industrial facilities across the UK are already planning for the prospect of scaling up to meet the need of lagoons in UK and international waters, buoyed by both the UK government review and the interest Tidal Lagoon Power’s development team has reported in France, India, Canada and elsewhere.

Towards the future system As the UK power system evolves, the management of supply and demand must adapt to reflect the characteristics of its generation components. Energy storage, demand-side management and plant flexibility will play an increasingly important role.

Tidal lagoons can provide predictable and affordable electricity at scale. They can be brought forward quickly, and their flexibility can be leveraged to facilitate the integration of intermittent wind and solar with baseload nuclear, paving the way to a low cost, low carbon power future for the UK. With the government’s independent review of tidal lagoon energy soon to report, this future is now within touching distance. n

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Global opportunities in solar PV

Renewables

by William Sharkey, EIC Sector Analyst – Renewables

As costs in solar PV continue to decline, global solar markets are experiencing phenomenal growth and are becoming increasingly attractive destinations for foreign investment. 2015 saw record deployment rates as the world's cumulative solar PV capacity reached 227GW The UK Since May 2015, the Department for Energy and Climate Change has reviewed and made changes to the level of financial support provided to renewable energy technologies.

The UK’s solar industry has built steady momentum over the last 10 years and substantial cost reduction has been achieved.

The support available through the Feed-in Tariff scheme has, however, now been cut by 64% and the Renewables Obligation (RO) scheme was closed to all new solar projects on 1 April 2016. With the removal of ‘grandfathering’, which provides a fixed rate of support over a project’s lifetime, and no mention of solar energy in the 2016 Budget, the UK’s solar market faces an uncertain period.

Sudden changes to policy mechanisms have created investor uncertainty in the UK solar market. With investment not forthcoming, solar projects are being delayed and proposed developments have been cancelled. As a result, only 3.8GW of UK solar capacity is expected to be added by 2020. This dwindling installation rate and lack of continued government support is at odds with what is happening in an increasing number of export markets around the world.

Export opportunities Despite being in its infancy (relatively), the global solar industry has proved both its resilience and maturity in the wake of SunEdison’s bankruptcy. Since its collapse in April 2016, the market value of other leading players has remained constant and, with companies already moving to acquire SunEdison’s assets, global growth is not projected to stall.

According to research by the International Renewable Energy Agency, the price of solar photovoltaic (PV) modules has dropped by 80% since 2010 while installed capacity has increased by 26%. In 2015, solar power attracted US$161bn of new investment and in 2016 67GW of global PV capacity is expected to be added. While global growth

“In 2015 solar power attracted US$161bn of new investment” has predominately been driven by China, Japan and the United States, nascent markets are now making a telling contribution.

Competitive auctions that offer long-term contracts to developers are helping companies secure investment and drive down cost. From South Africa to Peru, this model is successfully encouraging the solar PV industry to scaleup. Stable regulatory frameworks, long-term visibility and supportive government policies can now be observed in markets where solar PV has become cost competitive with conventional forms of power generation.

India In 2014 the Indian government set an ambitious target to install 100GW of solar capacity by 2022. Of this, 60GW is expected to come from utility-scale solar PV and concentrated solar power projects. The Frankfurt School of Finance and Management

With 5.4GW of solar capacity expected to be added in 2016, the Indian market offers an abundance of short and long-term supply chain opportunity

estimates that India will need to add 12GW of capacity each year in order to meet this target. Through the successful launch of the government-led National Solar Mission India’s solar market is gathering momentum and galvanising public and private sector investment through investor-friendly policies.

State governments across India are incentivising the growth of solar by offering tax breaks and promoting de-risked competitive bidding. The state of Gujarat, for example, originally introduced a solar policy in 2009 to remove obstacles to investment by eliminating cross-subsidy charges and making the process of acquiring land easier. The results have seen Gujarat emerge as one of the states with the highest solar capacity rates in India. The state of Telangana has helped spur investment by launching the renewable energy certificate mechanism. Offering VAT exemption, this mechanism appears to be having the desired effect as the Canadian company SkyPower signed for power purchase agreements (PPAs) with the state in February 2016 to construct and operate 200MW of solar projects.

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Renewables The implementation of solar auctions has seen competitive bidding bring the average levelised cost of electricity from utility-scale solar down by 50% since 2010. Persistent low bidding has led to calls that projects could prove to be economically unviable as investors will be unwilling to provide the necessary finance. With an increase in the number of companies seeking equity partners, the sector is set to undergo a period of consolidation. This was demonstrated

by Tata Power’s recent acquisition of local developer Welspun Renewables and a solar project portfolio of 990MW. With Indian state governments setting individual installation targets and driving utilityscale growth, state policies are encouraging the Make in India programme. Designed to facilitate investment and protect intellectual property rights, the programme includes a number of new incentives that seek to benefit the solar industry. Up to 100% foreign direct investment is now permitted and a 10-year tax holiday for solar projects has been introduced.

With preferred status given to domestic manufacturers, the programme has contributed to a renewed interest from Indian companies and authorities, as well as a growing interest in the construction of solar components in India.

Given the UK’s strong economic ties with India, UK companies are well placed to benefit from the Make in India campaign. Each of India’s 29 states come with local challenges and opportunities and international developers are advised to take the time to understand local customs and community requirements.

Establishing a local partner or forming a joint venture is a prerequisite to winning business in the sector and is an effective way to overcome key barriers to market entry.

From land acquisition to permitting and signing offtake agreements, the Indian solar market poses a number of challenges. Project financing remains an issue as domestic banks are reluctant to lend to those with no prior experience in the marketplace. Partnering with a local developer, however, gives confidence to the lender that a foreign company will operate in the market for a prolonged period.

Taking into account recommendations from international players, the Indian government is attempting to remove obstacles and streamline the development of solar projects.

Moving forward, the majority of solar auctions will be for the development of large-scale solar parks where the government will have responsibility for connectivity and land acquisition. Developed in collaboration with state governments, these solar parks will act as concentrated zones where tenders will be separated into individual projects.

With 5.4GW of solar capacity expected to be added in 2016, the Indian market offers an

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“The Indian government has set an ambitious target to install 100GW of solar capacity by 2022” abundance of short and long-term supply chain opportunity. New market entrants with the required engineering, construction and procurement services and international companies can benefit from a variety of support mechanisms including accelerated depreciation of 80% on solar assets. To ensure growth and sustainability in India a long-term view of the business is essential.

South Africa With strong solar irradiance, a high power demand and a transparent procurement programme, South Africa is leading the growth of solar in Africa. Set up in 2011

by South Africa’s Department of Energy, the Renewable Energy Independent Power Producer Procurement (REIPPP) programme aims to develop a successful renewable energy industry through competitive auction.

The programme has enticed international players to the solar market and directed significant private investment at increasingly low prices. The first three rounds of the REIPPP programme saw average PV tariffs fall by 68% over a two and a half year period.

In South Africa competitive tendering through its REIPPP programme has seen some of the world’s most cost-effective solar PV projects proposed

The 2015 Bid Window 4 of the procurement programme received 49 solar PV proposals of which six were accepted. The number of preferred bidders increased to 12 as Bid

Table 1. Bid 4 preferred bidders announced April 2015 Project name

Capacity (MW)

Operator

Nearest town

Aggeneys Solar Project

40

BioTherm Energy

Aggeneys

Droogfontein 2 Solar

75

SunEdison

Kimberley

Dyason’s Klip 1

75

Scatec Solar

Upington

Dyason’s Klip 2

75

Scatec Solar

Upington

Konkoonsies II Solar Facility

75

BioTherm Energy

Pofadder

Sirius Solar PV Project One

75

Scatec Solar

Upington

Table 2. Bid 4B preferred bidders announced June 2015 Project name

Capacity (MW)

Operator

Nearest town

Bokamoso

68

SunEdison

Leeudoringstad

De Wildt

50

SunEdison

Brits

Greefspan PV Power Plant No.2 Solar Park

55

SunEdison

Douglas

Solar Capital Orange

75

Solar Capital and Black Enterprise Empowerment

Loeriesfontein

Waterloo Solar Park

75

SunEdison

Vryburg

Zeerust Solar Park

75

SunEdison

Zeerust

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Renewables

“South Africa offers a gateway to enter emerging solar PV markets across Sub-Saharan Africa”

Window 4 was extended to those previously unsuccessful. Table 1 details the results of the initial fourth round of the REIPPP programme, while Table 2 shows the winners of the extension round. In total over 800MW of solar PV capacity was secured in the fourth bidding round, representing R10bn of spending. The supply prices for the successful projects will be sold to state utility Eskom under a 20-year PPA. While ownership structures vary from project to project in South Africa, solar schemes often involve a variety of stakeholders. In order to enter the REIPPP programme 40% of a project must be South African owned, with black ownership comprising 12% and communities residing within a 50km radius of the project site comprising 2.5%.

Project developers must therefore contribute to socio-economic development such as employment, education and community empowerment when taking a project forward.

To fast-track solar projects through the REIPPP programme, the South African government plans to introduce Renewable Energy Development Zones. By incentivising solar projects in priority areas, the Department of

Environmental Affairs intends to ease pressure on the grid and direct grid expansion. Eight zones have been identified to date and projects situated outside these zones will still be able to participate in the procurement process.

Competitive tendering through the REIPPP programme has seen some of the world’s most cost-effective PV projects proposed and South Africa identified as one of the most attractive markets for solar energy, despite the current weakness of the rand. For international companies looking to enter the sector, one of the main challenges is the ability to compete with those that have already established a strong foothold in the market. Early movers such as Mainstream Renewable Power have formed consortiums with local companies such as Thebe Investment Corporation to successfully develop solar PV projects. UK companies are therefore advised to identify Black Economic Empowerment partners and set up locally or, alternatively, find a local distributor to save on setting up costs. By partnering with South African companies UK developers can work with the system to overcome general red tape issues more easily and develop a socio-economic criteria.

Established as a global solar manufacturing hub, South Africa offers a gateway to enter emerging solar PV markets across Sub-Saharan Africa. The success of the REIPPP programme has been hailed as a benchmark for introducing renewable energy procurement programmes in other markets and a blueprint for scalingup renewable energy across the region.

Solar on the rise As costs in solar PV continue to decline, global solar markets are experiencing phenomenal growth and are becoming increasingly attractive destinations for foreign investment.

The growth markets of India and South Africa highlight the extensive export opportunities that are available as each has sought to create a favourable investment climate and improve the ease of doing business for international players. With a healthy pipeline of solar PV projects, both markets encapsulate the success of a technology that offers a clean and increasingly cost-effective means of meeting a rising global energy demand. n

“Solar power offers a clean and increasingly cost-effective means of meeting a rising global energy demand” 127

Renewables

Leading the way in wave energy

by Daniel Taylor, Research and Intellectual Property Coordinator, Carnegie Wave Energy

Following research and development in Australia, Carnegie is bringing the CETO solution to the UK for pre-commercial testing

Carnegie’s innovative CETO technology is making waves in Australia’s clean energy future and offers the potential to revolutionise power and water production globally

O

cean energy is a renewable resource with tremendous potential but to date it only represents a very small share in the global energy mix.

According to the International Energy Agency (IEA), the theorectical resource potential of ocean energy is more than sufficient to meet present and projected global electricity demand well into the future. The IEA estimates that the potential ranges from 20,000 to 80,000TWh of electricity a year, which is 100 to 400% of current global demand for electricity.

Australia is perfectly positioned to take advantage of the resource with its powerful waves along its western and southern coastline. In its Ocean Renewable Energy: 2015–2050 report, the Commonwealth Scientific and Industrial Research Organisation – the federal government agency for scientific research in Australia – estimates that the total wave energy between Geraldton and the southern point of Tasmania is more than 1,300TWh/yr, about five times the country’s total energy requirements.

Having switched on the world’s first commercial wave power station in February 2015, these are exciting times for wave energy in Australia. One of the homegrown technologies being offered to the market is the CETO submerged buoy system by Carnegie Wave Energy Limited. CETO is designed to extract energy from ocean waves to generate clean, renewable and emission-free electricity.

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Technological innovation The CETO technology converts kinetic energy absorbed from wave motion into electricity. The CETO unit consists of a fully submerged buoy (a buoyant actuator [BA]) that is tethered to a pump on the seabed. By operating underwater, the system is protected from the vagaries of the weather and invisible from the shore.

The CETO BA oscillates in harmony with the ocean’s waves, which in turn causes the extension and contraction of a linear hydraulic cylinder. The hydraulic cylinder delivers high pressure flow to the power take off system, which is arranged to convert the high pressure flow into mechanical motion by a swage plate motor. Attached to the swage plate motor are electrical generators.

The output of the generators is then conditioned using power electronics and variable speed drives to ensure stable reliable power is delivered to the electricity grid.

In addition to producing zero-emission power, the CETO technology is capable of producing direct desalinated water. The high pressure water created by the CETO units can be used to supply a reverse osmosis desalination plant, replacing or reducing reliance on greenhouse gas-emitting electrically driven pumps usually required for such plants.

World’s first commercial wave power station Carnegie is now looking to the future, having successfully completed the Perth Wave Energy Project (PWEP). This project used an array of three offshore wave power generators to provide clean electricity and potable desalinated water to Australia’s largest naval base, HMAS Stirling, off the coast of Garden Island in Western Australia.

This was an important step towards unlocking the vast potential of wave energy in Australia and internationally.

The PWEP completed over 14,000 hours of deployment across all four seasons over its 12 months of operation, making it the longest continuous period of operation of any in-ocean wave energy project in the world.

The operational phase of the Perth project was completed at the end of 2015 after the project collected a wealth of key engineering and environmental data, validated its computational models and met all requirements of the funding agreements.

Supported with US$10m of funding from Australian Renewable Energy Agency (ARENA), the US$26m project is the first array of wave power generators to be connected to an electricity grid worldwide.

The ARENA funding for the development

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Renewables has been matched with grant funding from the government of Western Australia’s Low Emissions Energy Development programme.

The CETO desalination plant is 50% funded through a US$1m AusIndustry grant from the Clean Technology Innovation Programme.

Next generation development Work is currently underway on the detailed design of the next generation CETO 6 technology, which for the first time will move power generation offshore to occur within the units themselves. Unlike previous generations of the CETO technology, CETO 6 will not be connected to the shore by a pipeline. Instead, a subsea electrical export cable is used.

Locating the power generation within the buoy removes the need to attach pumps, accumulators and other hydraulic components to the seabed, removing the requirement for offshore heavy lift vessel capacity. This also reduces offshore installation and maintenance time and cost, and will allow installation in deeper, more distant to shore wave resources.

“We are working on development plans to bring the CETO technology to the UK” In addition to design improvements reducing infrastructure and the associated installation costs, the CETO 6 design is a significantly larger unit than the currently used CETO 5, with the buoy nearly doubling in diameter. As a result, the amount of energy captured in any given sea state should increase by a factor of four – each CETO 6 unit will have 1MW of power capacity.

The new US$23.3m CETO 6 project will be used in future commercial projects. US$6m of the funding comes from ARENA, as well as a debt facility from the Clean Energy Finance Council.

Another world first for microgrid Building on the success of CETO 5, we now have plans to take the concept a crucial step further, to a renewable energy microgrid based around wave energy.

To this end, in March 2016, Carnegie purchased a 35% stake in Energy Made Clean (EMC) – a proven specialist in delivery, construction and operation of microgrids, commercial scale solar and energy storage solutions.

There are a number of projects currently underway in partnership with EMC. The world’s first wave energy microgrid is also based at Garden Island and combines wave energy with solar energy, a desalination plant and energy storage facilities. It will use three CETO 6 wave energy machines, each with 1MW of

Carnegie’s CETO 5 unit converts kinetic energy from ocean swell into electrical power and directly desalinates freshwater through reverse osmosis

power capacity, 2MW of added solar power and 500kW hours of battery storage. The unit will provide power and water to the Australian Department of Defence for HMAS Stirling.

These developments are essential to the advancement of wave energy technologies, as well as being a clear pathway to ensuring energy security for remote islands such as Mauritius.

The latest Mauritius Wave and Microgrid Design project will showcase several innovative solutions split between the main island of Mauritius and the island of Rodrigues (to the east of Mauritius). It will clearly show how islands can achieve very high penetration of renewables by using a combination of wave energy, solar PV, wind energy, battery energy storage systems and smart microgrid control systems.

A wave-monitoring buoy was deployed in July 2016 to collect fresh data for a period of about six months. This process is critical to determining the local wave resource and is a key step in assessing the feasibility and design of a commercial scale CETO wave energy plant off Mauritius.

By the end of 2016, the project will deliver a renewable energy roadmap for Mauritius, a wave resource assessment and the detailed design for a microgrid powered desalination plant for Rodrigues.

The early stages of the project are being supported from revenue generated from a partnership between the Australian and Mauritius governments of US$600,000.

Bringing CETO technology to the UK Carnegie is not limiting its development to micogrids alone, with the know-how

and expertise gathered by running the year-long PWEP, we also intend to pursue utility level power from wave energy.

As such, we are working on development plans to bring the CETO technology to the UK. Through the wholly owned subsidiary CWE UK, we have secured berths at both Wave Hub and the European Marine Energy Centre (EMEC) in the UK. We are looking to first deploy a single device in UK waters, followed by an expansion to 15 units in a future project. The 15-unit deployment would be the first commercial scale deployment of wave energy converters anywhere in the world.

Upon a successful deployment of the 15unit project, we will then look at extending deployments in the UK beyond the wave energy incubators of Wave Hub and EMEC to the broader market. The UK and Europe have significant wave resources available, as well as tariff structures which make them ideal markets to develop commercial wave energy projects.

Carnegie already engages with a large number of UK based suppliers for equipment used in the CETO units and is actively interested in creating a solid supply chain of UK suppliers. UK based suppliers were used in manufacturing equipment for the PWEP for equipment including the foundation connectors and tethers. n

Carnegie Wave Energy Limited is the inventor, developer and 100% owner of the CETO wave energy technology. Focused on the global commercialisation of its CETO technology it has 100% owned subsidiaries in the UK, Ireland and Chile. www.carnegiewave.com

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