Energy and ecology Magazine

April 2017 issue 3

THE SPECIFIC FEATURES OF THE URANIUM MARKET VASILY KONSTANTINOV, THE PRESIDENT OF URANIUM ONE GROUP

contents

ENERGY

ECOLOGY

4 | Energy Financing Group – Import, export and trade of electricity

18 | Global greenhouse gas emissions flat for third consecutive year

5 | RPC Radiy – The road to success

19 | Coal power plant pipeline goes into 'freefall'

8 | Pyotr Lavrenyuk – We Have a difficult exam ahead

20 | EPA head Scott Pruitt denies that carbon dioxide causes global warming

9 | Russia and Tajikistan to cooperate in nuclear 12 | Power production and distribution companies in the Balkan region 13 | Natural solution: Saudi's renewed plans meet growing energy demands

OIL&GAS

21 | Here comes the sun: solar power finance for the 21st century 22 | World's largest artificial sun switches on in Germany 22 | Banks give €1 billion to build “Smart Europe”

MINING

24 | Iran's Gas Industry

38 | Coal and Bulgarian Power Sector

29 | Flue gas analysis – brilliantly easy: testo 350 – the first flue gas analyzer that thinks ahead

41 | Ecuador anticipates $4 billion in mining investments by 2021

31 | 5 oil & gas projects to watch in 2017

42 | Secret of the Kibali Mine: Flying People In and Gold Bars Out

32 | Exploring best practices for ensuring gas pipeline integrity

34

Adriano Gentilucci, Commercial director IMEA for Dow, oil, gas and mining

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43 | World's First Deep-Sea Mining Venture Set to Launch in 2019

36

Vasily Konstantinov, the President of Uranium One Group

energyandecology.com

Issue 3 April 2017

Energy

- Import, export and trade of electricity

Energy Financing Group AD was established in 2004 and it operates on the free electricity market in Bulgaria since its inception in 2005 through its 49% share in the first trading company involved in the market of electric energy.

After the experience accumulated, on December 18, 2006, EFG AD received its own license № Л-219-15 for the trade in electricity in the territory of Bulgaria for a period of 20 years, as well as its EIC code 32XEFG-AD - N, which allowed it to conduct import and export of electricity.

Thanks to the experience of the staff and the excellent reputation of the owners of our company in the energy sector in Bulgaria and Europe EFG AD achieved excellent results at the start of its participation in the free market of electric energy both in Bulgaria and on the Balkan Peninsula.

Energy Financing Group AD is certified by Bureau Veritas in accordance with the requirements of management system standards ISO 9001:2008.

The chief aim and mission of Energy Financing Group AD is to fully meet the requirements and challenges of the liberalized energy market in Bulgaria and in the region.

This gives a real opportunity to Energy Financing Group AD to consolidate its position on the electricity market as a reliable and preferred partner.

For the last four years of work we have been exporting electricity to Greece, Serbia, Macedonia and Romania.

Our company has worked and continues to work with the largest power plants in Bulgaria – Kozloduy Nuclear Power Plant, 4

Maritza East 2 TPP and Varna TPP. Our clients include Lukoil Neftochim, CEZ Trade, Ideal Standard, Agropolychim, KAI Group and some other commercial companies.

Our company has also built long-term relationships with the National Electricity Company EAD (NEK EAD), both on the domestic and the external market of electric energy.

After receiving the license for electricity trading at the end of 2006, EFG AD started its activities and from April 1, 2007 commenced its actual trading of electricity.

As seen from the chart below, thanks to the experience gained on the open market for electricity in the Republic of Bulgaria, the company is rapidly gaining its portfolio of clients.

Services 1. Following the submission of a notarized power of attorney – registration of customers or full assistance in the preparation of documents for registration of the customer on the free market; 2. Working out of detailed analyses of the company’s customers energy consumption; 3. Consultancy by our leading experts on issues related to the work and the electricity market development in the Republic of Bulgaria, the region and the European Union; 4. Analysis and experts evaluation of the benefits of a possible participation on the free electricity market;

legal requirements and changes to the internal energy market; 6. Short-term and long-term forecasting and balancing of electric energy consumption; 7. Consultancy and full cooperation in the carrying out of the procedure for connection to electricity transmission and distribution networks; 8. EFG AD builds and operates a real-time electric energy monitoring system of its customers. We have built a SCADA system to transmit the information in real time to the central dispatching office in Sofia. The data are received and processed in a specially designed software system for marketing and management of electricity trading and accompanying activities, including measurements monitoring. The system is available online to our customers with possibilities to monitor the actual consumption and delivery schedules.

ENERGY FINANCING GROUP Direct correspondence: Sofia, Bulgaria 10, Vihren Str. Tel.: + 359 2 892 88 08 Fax: + 359 2 892 88 13 E-mail: office@efg.bg web: www.efg.bg

5. Legal and technical consultancy on the

energyandecology.com

Issue 3 April 2017

Energy

: The Road to Success developed RadICS Platform, which includes Analog Input for Neutron Flux Measurement Module (AIFM).

The digital I&C Platform RadICS consists of a set of general-purpose modules that can be configured and used to implement application-specific functions.

The RadICS Platform, including AIFM, is certified as Safety Integrity Level (SIL) 3 and complies with IEC 61508:2010 “Functional Safety of Electrical /Electronic /Programmable Electronic Safety Related Systems”.

Using RadICS Platform gives the following advantages in the process of I&C modernization:

Opening of Memorial to Taras Shevchenko in Sofia, Bulgaria. June 30, 2016 In the center: President of Ukraine Petro Poroshenko On the left: Chairman of the Council of PC RPC Radiy Ievgenii Bakhmach

Public Company Research and Production Corporation Radiy is a leading Ukrainian designer and supplier of advanced digital instrumentation and control (I&C) systems for operational safety of nuclear (NPP) and thermal (TPP) power plants. Radiy is a full production cycle company that includes equipment design, development, manufac ture, qualification and installation.

NPP. Since its installation at Kozloduy NPP RPC Radiy's equipment has demonstrated high reliability level performance and received a positive evaluation of the NPP personnel.

Digital I&C Platform RadICS

With a roster of over 900 professionals including more than 200 highly qualified design engineers, Radiy is dedicated to scientific research to support development of new technologies.

RPC Radiy has a long positive history of cooperation with NPPs by installing I&C systems as turn-key projects.

· Engineered Safety Features Actuation System (ESFAS), · Reactor Trip Breakers,

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- Average frequency of dangerous failures of continuous safety function – < 10-7; - Diagnostic coverage ≥ 99%. · RadICS Platform enables to implement inter-channel or inter-system redundancy using voting “2 out of 4”, “2 out of 3” or “1 out of 2” within I&C system in order to increase reliability and fault tolerance.

· RadICS platform is designed using the design-process infrastructure to support all life cycle processes, including the procedu res and development tools, verification and validation, configuration management and changes, recruitment and personnel training, project management and electronic workflow, requirements tracing, equipment qualification, as well as customer support.

Since 2007 PC “RPC Radiy” has successfully completed installation of the following I&C systems at Kozloduy NPP:

All delivered systems meet the most stringent requirements of international and national standards in the field of I&C for

RadICS Platform complies with the highest requirements of functional safety, providing the following values of reliability and safety parameters:

· RadICS Platform can significantly reduce the number of electrical communication lines within the system and consequently, the amount of copper wire required for I&C modernization at NPP. Minimizing the number of electrical communication lines is achieved through the extensive use of fiber-optic communications.

Radiy's I&C systems have been parts of the safety related systems in all operating NPP sites in Ukraine and Kozloduy NPP in Bulgaria.

· Switchgear and Electrical Distribution Systems for ESFAS.

· RadICS Platform complies with the best engineering practices, used by leading suppliers of safety I&C platforms for NPPs (many companies, such as Areva, Invensys, and others have SIL3 certificate anduse a multi-channel configuration in their platforms).

To implement current requirements to instrumentation and control systems, including control and instrumentation of neutron flux, Radiy has

The same infrastructure is used for the development of RadICS Platform-based I&C.

energyandecology.com

Issue 3 April 2017

Energy

: The Road to Success Certification of the RadICS Platform under requirements of IEC 61508:2010 The IEC 61508 standard provides methods for systems certification on the basis of four predefined Safety Integrity Levels, where SIL4 is the most demanding level. The SIL certification process requires that products developed under a Functional Safety Management Plan (FSMP) should be audited in stages by the independent certification agency . The FSMP meets all the requirements of IEC 61508 and guarantees that they are applied throughout the product life cycle.

The SIL certification process outlined in IEC 61508 requires the preparation of a set of documents specific to each phase of the product life cycle. These documents are be subject of an independent auditing and assessment process performed by a Certification Body.

Typical SIL certification process covers the following areas: Product reliability; Process execution; Human factor; Functional safety assessment.

Safety Life Cycle of the RadICS Platform implements specific stages of FPGA design development and verification. Specific technique of fault insertion testing has been performed for both hardware and software parts. One of the most critical features required for successful SIL3 certification is Requirements Tracing process. The main idea behind it is to achieve complete traceability at all project stages in order to implement all initial requirements and restrict functions to the required ones only.

Below are some results of quantitative assessment received in the process of of RadICS Platform SIL3 certification: compliance with 737 requirements of IEC 61508 (items of Safety Case); development of 200 docs of the Documentation Plan ; certification time period: one year (20102011) for preparation and 3 years (20112014) for performance; effort taken: more than 50 man-year.

On completion of the independent Functional Safety Assessment, the certification agency issues the following documents: Functional Safety Assessment Plan, Functional Safety Assessment Report and the certificate of product's compliance.

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The assessments performed by exida, as well as final independent Functional Safety Assessment, confirmed that Radiy's processes comply with SIL3 requirements and the RadICS Platform meets SIL3 requirements.

Certification of the RadICS Platform under U.S. NRC requirements RPC Radiy has always looked for new opportunities for its products and business development. One of the most ambitious business goals is to bring all benefits of RadICS digital I&C platform as a safe and reliable product to the U.S. nuclear market.

The key point of the U.S. licensing strategy is to demonstrate that the generic RadICS Platform and the associated quality and software life cycle processes comply with U.S. nuclear safety requirements.

In 2015, Radiy started working with Global Quality Assurance that was supposed to to assist RadICS LLC to fully align its QMS with 10 CFR Part 50, Appendix B, ASME NQA-1-2008, NQA-1a-2009 and 10 CFR 21.

These activities include the following steps: QA Program documents development; Quality procedures development to cover 18 criteria from Appendix B; Learning QA documentation and process of their implementation by arranging training sessions for RadICS personnel; Arranging training to obtain qualified Lead Auditor and Inspector. , etc.

On February 23-26, 2016, Global Quality Assurance successfully performed a Commercial Grade Dedication internal audit at PC RPC Radiy in Kropivnitskiy (former Kirovograd), Ukraine.

The scope of the audit was to verify and confirm that PC RPC Radiy's Quality Management System incorporates all the control required for identified characteristics to meet all manufacturing requirements commensurate with a Commercial Grade Dedication plan in compliance with 10CFR50 Appendix B program.

On July 14, 2015, PC RPC Radiy representatives met with the U.S. NRC in Rockville, the United States, as part of the certification process of the RadICS FPGAbased platform. The purpose of meeting was to present technical information about RadICS Platform, to plan i RadICS Topical Report submittal, and to receive U.S. NRC's feedback on the RadICS platform

features and the overall licensing schedule expectations..

The detailed discussions included the following areas: ·Features of the RadICS digital I&C platform and its development processes; ·RadICS quality management system and licensing program; ·Commercial grade dedication and qualification plans.

In September 2016 RPC Radiy submitted Topical Report to the U.S. NRC and in December 2016 the Report was accepted

by U.S. NRC for the detailed analysis.

PC RPC Radiy's experience in implementation of I&C systems on the basis of RadICS platform Case Study – Embalse refurbishment project In 2014 RPC Radiy successfully completed two modernization projects for Embalse NPP, Argentina, in cooperation with CanadiancompanyCANDU Energy. The first project involved the development of Window Alarm Annunciator (WAA) systems for Main Control Room (MCR) and the Secondary Control Area (SCA) at Embalse NPP. WAAs were designed to use in the Main Control Room (MCR) and Secondary Control Area (SCA) to generate alarms associated with the plant's Shutdown System One (SDS1), Shutdown System Two (SDS2) and Emergency Core Cooling (ECC) system.

Three main components were developed as part of the WAA system, two associated with the MCR. They were housed in the same Logic Card Assembly use two separate Alarm Logic Controllers (ALC) in the same chassis.heThe third one is associated with the SCA. The MCR parts of the equipment are galvanically isolated from each other.

Three main components mentioned above control alarm annunciation process by sending alarm signals to the annunciation panel. As a hardware platform for WAAs equipment, Radiy used modules and chassis of the standard RadICS FPGAbased Safety Platform.

The manufactured equipment was tested according to specific IEEE and IEC standards requirements, and demonstrated stability in different operational conditions.

energyandecology.com

Issue 3 April 2017

Energy

: The Road to Success The second modernization project for the Embalse NPP involved developing the Signal Processing Unit (SPU) of the pump motor speed measuring device (see figure below) that was designed to replace the obsolete unit in the trip signal of “pump low speed” trip in Shutdown System No. 2 (SDS2).

The SPU may be viewed as having two main components as follows: A signal acquisition and analog output components, controlled by logic configured in an FPGA chip with self-diagnostics capabilities;

additional three years.

In the scope of the project, Radiy's specialists delivered a training course on the RadICS I&C platform and its operational capabilities to the EdF researchers in Chatou, France.

This project enabled EdF engineers to get familiarized with design of FPGA-based I&C applications for both NPP modernization and new build projects.

I&C for IEA-R1 Research Reactor Control Console and Nuclear Channels

Factory Acceptance Test was successfully performed in May 2016 with the participation of customer's representatives.

The commissioning of the delivered equipment is planned for the 2017.

Conclusion RPC Radiy is one of the worldwide leaders of FPGA-based safety-related turnkey applications and other modernization projects for NPPs, both in terms of the number of installations and variety of systems . RPC Radiy has positive history, extensive knowledge and experienced

A separate power supply and monitoring system implemented via a Complex Programmable Logic Device (CPLD) to constantly monitor the FPGA. The monitoring and diagnostics drives the SPU to a safe state in case of detection of critical failures. The SPU designed and manufactured by Radiy was qualified to IEC 61513 Class 1 and it proves to support Category A safety functions.

After Radiy conducted all required qualification testing internally, Factory Acceptance Tests (FATs) of MCR and SCA Window Alarm equipment were carried out and witnessed by Candu Energy on March 11-21, 2014.

The results of the FAT and qualifications tests showed that the equipment is in full compliance with client's specification and applicable standards.

The application of FPGA-based RadICS platform in close cooperation with Candu Energy Inc., Radiy's sufficient experience and strongly developed good practices were the essential constituents for the successful completion of the projects.

Case Study – Project with Électricité de France In October 2014 RPC Radiy signed a contract with Électricité de France (EdF) to provide FPGA-based I&C Testbed based on RadICS Platform. The testbed is supposed to serve research purposes for possible future implementation in NPPs operated by EdF. The six-month development project was followed by the delivery of the testbed and its documentation, engineering tools to design safety applications in general and an EdF-specified control application. The service also includes a training course on start-up and operation of the testbed, it includes a three-year research with an optional extension of the contract for 7

Safety System Control Console for the IEA-R1 nuclear research reactor operated by Instituto de Pesquisas Energeticas e Nucleares (IPEN) – San Paulo, Brazil Factory Acceptance Testing – May 2016

Modernization: Case analysis IEA-R1 Open-pool Reactor built by Babcock-Wilcox and commissioned in 1957, 2-5 MW power, is currently operating on 3,5 MW power.

The project of I&C systems modernization of the IEA-R1 Research Reactor in IPEN Institute (San Paolo, Brazil)started in 2015 and was successfully completed in 2016.

The scope included turnkey modernization of Control Console, I&C for Nuclear Measurements, Reactor trip, ESFAS systems, and HMI Panels. Equipment list includes two Signal Processing Cabinets, Computer Cabinet and Operator Consol.

The I&C system in this project was implemented implemented on the basis of RadICS Platform.

The qualification of the system included seismic and environmental testing.The

personnel to design I&C systems for new NPPs and existing NPP modernization projects. Since 2003 RPC Radiy has designed, produced and commissioned over 100 FPGA-based turnkey applications at NPPs. PC RPC Radiy has SIL 3 certified FPGA-based safety Platform RadICS that can be used to implement different types of I&C systems for NPP. Currently RadICS platform is being certified under U.S. NRC requirements.

Contact us: 29, Geroyiv Stalingrada Street, 25009 Kirovograd, Ukraine Reception: +38 (0522) 37-30-20 International Projects Coordination: +38 (0522) 37-33-28 Technical support: +38 (0522) 37-32-44 Fax: +38 (0522) 37-33-28 http://radiy.com energyandecology.com

Issue 3 April 2017

Energy

Pyotr Lavrenyuk: We Have a Difficult Exam Ahead TVEL Senior Vice President for R&D, Technology and Quality speaks about TVS-K fuel and its promotion on the international market.

Our fuel differs from the fuel of Westinghouse or Areva in a number of parameters, including structural materials, spacer grids and manufacturing technology. We strive to make a fuel that will be trouble-free for the operators in terms of control. We managed to design fuel elements that do not change their geometrical shape after five years in operation in very tough conditions. When designing TVS-K, we relied on our expertise in producing nuclear fuel for VVER reactors. Fuel burnup is another important parameter. We have reached a burnup of 60 MWd/kgU while maintaining safe and reliable operation of the fuel assembly.

What is the progress in promoting TVSK fuel on the American market?

When and how did the idea come up to manufacture TVS-K fuel?

In the early 2000s, we came to an understanding that many Western nuclear operators were looking for new suppliers of nuclear fuel in addition to Westinghouse and Areva. Evgeny Adamov, the then head of the Russian nuclear industry, gave TVEL a task to consider a possibility of entering the Western fuel market. And yes, there were those who were skeptical about the feasibility and prospects of the project; there were financial difficulties, but they did not stop us.

What companies were involved in the development of the new fuel?

The TVS-K fuel development project was coordinated by OKBM Afrikantov. Materials and design were developed by Bochvar Russian Research Institute of Inorganic Materials. Leipunsky Institute and Kurchatov Institute were also involved in the project. An important role in testing fuel designs was played by Novosibirsk Chemical Concentrate Plant. Some ideas about the guide rod technology were proposed by Chepetsk Mechanical Plant.

How difficult was it to develop such fuel in technical terms?

We had all the research, design and production capacities required to start the project. But true, it was difficult because our fuel had to be compatible with that used in Western-designed reactors. We did not have enough information to quickly produce a fuel assembly like that, so it took us some time. We completed all the calculations, 8

testbed experiments and in-pile studies of different fuel components by 2007 and came to the conclusion that we were capable of offering the market a new product. In 2008, we began working in close contact with Swedish company Vattenfall that provided us with data needed to finalize the project. It took TVEL two years to have been qualified as a fuel supplier.

In 2011, our Swedish partners made sure that our product met their requirements and decided to work with us.

Was it difficult to reach an agreement?

I would not say it was very much difficult.

We had a clear understanding of our capabilities and the customer ’s requirements, so it was not a problem to make an agreement. In 2011, we signed a contract to produce pilot fuel assemblies.

From the very beginning, we set ourselves a task to make no mistake. We were told that we should make a fuel to be used at uptated power. When the talks reached a point of discussing commercial supplies, it meant that the fuel met the customer’s requirements. Our initial design underwent minor changes only.

The contract for commercial supplies of TVS-K fuel was a 2016 milestone for Rosatom. Was it easy to sign the contract?

It was an idea of the Swedish customer to sign this contract. It should be noted that this is a ‘deferred decision’ contract.

Deliveries will begin in 2021.

What are the advantages of TVS-K over Western fuel?

The process is underway without fail, but it is strictly regulated. It is not a task of TVEL as Rosatom’s fuel division alone. It is a task of Rosatom. Test operation requires delivery of four to eight fuel assemblies. If our plans are fulfilled, production of TVS-K will be organized in the USA. Why did you make this decision? Do Americans have capacity to fabricate this fuel?

This decision was made for the reason of logistics. The U.S. nuclear industry is a welloiled mechanism. No stock is kept at the plant. To supply fuel from Russia means to ship it across the ocean. This is too long.

And there should be no failures. This is why we had discussed the possibility of organizing fuel production in the USA from the very beginning. More important is to decide whose uranium to use. We will insist on using our uranium.

Have you assessed the market for TVS-K fuel?

The market assessment has been carried out, and goals are set. The main thing is to achieve these goals. We do not want to limit fuel supplies to two or three reactors. I would like to stress it once again that we plan to supply TVS-K fuel on a commercial scale. Rosatom has set an ambitious promotion goal with regard to TVS-K fuel.

Apart from business, there is politics, and our task is to convince customers that the product we offer is reliable and has excellent performance characteristics and a competitive price. The market is vast, but we understand that no one will give up its market position. Most of the target reactors are located in the USA.

energyandecology.com

Issue 3 April 2017

Energy

Russia and Tajikistan to Cooperate in Nuclear The countries signed an agreement on civil nuclear cooperation during the visit of Russia's President Vladimir Putin to Tajikistan in late February.

This is the first document in the history of the two countries to establish a legal framework for nuclear cooperation between them.The document was signed by Rosatom CEO Alexei Likhachov on behalf of the Russian government and Farhod Rakhimov, President of the Tajikistan Academy of Sciences, on behalf of Tajikistan's government.

Areas of prospective cooperation are extremely diverse and include design, construction, operation of research reactors, spent nuclear fuel and radioactive waste management, reclamation of uranium tailing dumps, and disposal of decommissioned uranium extraction and processing facilities. Cooperation between the countries will be also focused on radioisotope production, the use of nuclear technology in the industry, medicine and agriculture, and professional workforce training for the nuclear power industry.

The nuclear power development has long been on the national agenda in Tajikistan.

The country has been an IAEA member since 2000 and is an active participant in international meetings, forums and other events dedicated to peaceful uses of nuclear power. Last year, Tajikistan launched a program to restore the ArgusFTI nuclear research reactor in 2016–2020.

The reactor was designed by Soviet scientists, but has never been put in 9

operation after the Chernobyl disaster.

According to Ivan Andrievsky, Chairman of the Board of 2K Engineering Company, the research reactor is the most likely site for joint nuclear projects between Russia and Tajikistan. “Tajikistan plans to revitalize the project and will need Rosatom’s competencies in this field,” he said.

Reclamation of Taboshar One of the most important joint projects is reclamation of tailing dumps and dumping grounds of the beneficiation plant near the town of Taboshar. This project is part of an international program focusing on the rehabilitation of former uranium production sites. The program was developed to mitigate environmental impacts of uranium tailing dumps in Kazakhstan, Kyrgyzstan, Russia and Tajikistan.

Launched on 1 January 2013, the program is coordinated by Rosatom. The national project owner in Tajikistan is the Ministry of Industry and New Technology of the Republic of Tajikistan. Phase 1 of the project is carried out by the Federal Center for Nuclear and Radiation Safety (FCNRS), a subsidiary of Rosatom.

the Taboshar site. In November, FCNRS submitted design documents and cost estimates of the Taboshar site reclamation project to the government of the Republic of Tajikistan for examination.

Not long ago, Tajikistan’s ministers and Andrei Golinei, CEO of FCNRS, had a meeting on the Taboshar reclamation project. They discussed an approval procedure for the buffer zone borders and expert examination of the project documents submitted to the Committee for Architecture on 30 November.

Hochien Mirsoshokir, Deputy CEO for Science, Environment and New Technology of the state-owned company Tajredmet, is sure that the submission of project design documents to the Committee for Architecture is an important step that speaks for their soonest approval.

“Official examination of the project design will be a starting point for the massive effort of bringing the Taboshar site back to radiation safety,” he said.

In accordance with the program, FCNRS has conducted engineering and environmental surveys, updated the geological and hydrological parameters of the area, and performed land surveying on

energyandecology.com

Issue 3 April 2017

Energy

ISCAR Drilling for Profit with SUMO3CHAM The entire machining process becomes much easier as the cutting forces are spread across 3 cutting edges, the drilling process is more stable and the penetration into the part's material is more balanced. Thus, users can work up to twice as fast, as the feed per tooth can be increased significantly. Alternatively, users can maintain the same feed per revolution as with a two flute drill and achieve much longer tool life.

The SUMO3CHAM clamping, which relies on 3 points of positioning, provides high levels of repeatability when replacing the drilling head.

The global metalworking industry is driven by the relentless progress of highend technologies that are becoming ever more sophisticated. The challenging requirements of advanced production equipment demands the provision of 'out of the box' advanced machining solutions.

Innovative cutting tools release the latent productive capability of modern machine tools and deliver enhanced profits to users.

In order to comply with market demand, ISCAR recently exhibited its next generation, advanced indexable drill and further extended its comprehensive product portfolio with the launch of SUMO3CHAM – an advanced three flute indexable drill. The innovative design of the SUMO3CHAM raises users manufacturing productivity to new levels by reducing machining cycle times by up to 50% when compared to the conventional two flute drills.

The new product's pocket configuration is constructed on a 'close structure' design with three contact areas based on a dove tail joint. This rigid clamping configuration divides the forces applied to the tools' pocket into 3 segments. This arrangement dramatically reduces harmful influences on the pocket's life and also substantially prolongs tool life.

Three radial and 3 axial stoppers secure the drilling head and ensure a reliable drilling process in high feed machining environments. Furthermore, due to its sharp edges and the low axial force it applies, the SUMO3CHAM is very efficient when drilling a through-hole when the drill breaks through a slanted surface, also creating fewer burrs on the hole exit. Since the material work hardening is low, a reamer or a tap which may be used for a subsequent operation will gain from extended tool life and accomplish improved results. The unique geometry of the SUMO3CHAM selfcentering head shapes the produced chips optimally to allow smooth evacuation throughout the 3 high helix polished flutes.

ISCAR maintains its proud tradition of designing user-friendly drilling systems for easy handling. These unique drilling systems eliminate the use of tightening screws to clamp the drilling head in accordance with the company motto "No Set-up Time".

SUMO3CHAM is now available for machining alloy steel, carbon steel, soft and gummy low carbon steel as well as cast iron.

In a similar way, the cutting forces are equally divided across the 3 cutting edges of the drilling head. The application of less pressure to each of the contact surfaces further extends the life cycle of the drilling head.

ISCAR's vision is to remain the global metalworking market leader by the continuing work of its prolific R&D department and remaining aware of its customers evolving needs. Innovative developments allow the launch of products that bring manufacturers an array of efficient drilling solutions based on uncompromising quality.

"The combination of the self-centering geometry, along with a robust and accurate clamping system results in SUMO3CHAM providing ultimate performances relating to hole cylindricity, roundness and enhanced productivity.

ISCAR Bulgaria is located in Kazanlak to serve the Bulgarian metal working industries. ISCAR Bulgaria is registered with the Bulgarian Chamber of Commerce and Industry and abides by its standards of conduct. The trained staff of

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experienced sales engineers at ISCAR Bulgaria is ready to provide support, testing, demonstrations, consultations and quotations for ISCAR tools — the world’s finest metal cutting tools.

ISCAR is the largest of the 15 companies comprising the IMC (International Metalworking Companies). Together, they supply a dynamic comprehensive line of precision carbide metalworking tools. These companies produce a wide range of carbide inserts, carbide endmills and cutting tools, covering most metal cutting applications.

IMC also provides engineering and manufacturing solutions to major industries throughout the world. Many innovative products, designed specially for customer requirements, have made the IMC a world leader in the major manufacturing industries such as automotive, aerospace and die & mold production.

For more information: ISCAR Bulgaria. Starozagorska 1, Str. Floor 1, Office G, 6100 Kazanlak Tel/Fax:+359 431 62557; Tel: +359 431 64361 e-mail: apostolov@iscar.bg www.iscar.bg

energyandecology.com

Issue 3 April 2017

Energy

NuScale Technology The NuScale SMR is an advanced light-water reactor wherein each NuScale Power ModuleTM is a self-contained unit that operates independently within a multi-module configuration.

NuScale Power ModuleTM details include: Thermal capacity – 160 Mwt Electrical capacity – 50 MWe (gross) Capacity factor – >95 percent Dimensions – 76' x 15' cylindrical containment vessel module containing reactor and steam generator Weight – ~ 700 tons as shipped from fabrication shop Transportation – Barge, truck or train Cost – Numerous advantages due to simplicity, off-the-shelf standard items, modular design, shorter construction times, <$5,100/KW Fuel – Standard LWR fuel in 17 x 17 configuration, each assembly 2 meters (~ 6 ft.) in length; 24-month refueling cycle with fuel enriched less than 4.95 percent.

NuScale Technology Innovations NuScale Power is creating a new kind of nuclear power plant, one that is safe, reliable, and economical. The innovative concept incorporates all of the components for steam generation and heat exchange into a single integrated unit, the NuScale Power ModuleTM (NPM). The compact design of the NPM allows it to be built and assembled in a U.S. factory, then shipped to a prepared site for easy deployment.

The NPM design eliminates many costly, complex systems while cutting-edge manufacturing cuts time and cost of production. The result will be a power source that is simultaneously safe, reliable, scalable, carbon-free, and economical.

Continuous improvement is a philosophy that has been integrated into the entire design process.

Up to 12 modules are monitored and operated from a single control room.

(1) The reactor measures 65 feet tall x 9 feet in diameter. It sits within a containment vessel.

(2) The reactor and containment vessel operate inside a water-filled pool that is built below grade. The reactor operates using the principles of natural circulation; hence, no pumps are needed to circulate water through the reactor. Instead, the system uses a convection process. Water is heated as it passes over the core.

(3) As it heats up, the water rises within the interior of the vessel. Once the heated water reaches the top of the riser, it is drawn downward by water that is cooled passing through the steam generators.

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(4) The cooler water has a higher density. It is pulled by gravity back down to the bottom of the reactor where it is again drawn over the core. Water in the reactor system is kept separate from the water in the steam generator system to prevent contamination.

As the hot water in the reactor system passes over the hundreds of tubes in the steam generator, heat is transferred through the tube walls and the water in the tubes turns to steam. The steam turns turbines which are attached by a single shaft to the electrical generator. After passing through the turbines, the steam loses its energy. It is cooled back into liquid form in the condenser then pumped by the feed water pump back to the steam generator where it begins the cycle again.

NuScale Power London Office 1st Floor Portland House Bressenden Place London SW1E 5BH United Kingdom Phone: +44 (0) 2079 321700 Fax: +44 (0) 2079 321722

energyandecology.com

Issue 3 April 2017

Energy

Power production and distribution companies in the Balkan region

By Vladimir Spasić, energy journalist and analyst It is not just that the governments in the Balkan region do not consider selling their power utilities, but they covet buying what they sold twenty years ago, or at least buying from their neighbors.This can be illustrated by the announcement of Serbian power utility Eletkroprivreda Srbije (EPS) intention to buy Elektroprivreda Republike Srpke, power utility from Bosnia and Herzegovina entity Republic of Srpska.

Serbia has recently formed a governmental working group with a task to evaluate purchases of power utilities from the region, primarily the ones from Republic of Srpska and Montenegro. The response came instantly: Republic of Srpska replied that their power utility is not for sale, and Montenegro kept quiet, which in a way speaks more than the proper answer was provided.

During the last century’s decade or at the beginning of this century, the governments from the region were competing in the speed of transforming their vertically organized power utilities, comprising power production, transmission and distribution.

Distribution companies have been privatized in the first round. At the end of 1996 all six power distributions from Hungary were privatized. Companies that bought them were French EDF and German companies RWE, Bayernwerk and ISAR (last two became later on E.ON).

However, at the end of 2016, state owned company ENKSZ, formed in 2015, bought one distribution company from EDF, while a year before it also bought two distribution companies from German E.ON and RWE. This transaction came after the state’s takeover of gas distribution companies from German E.ON and RWE. As early as in 2012 the state promoted the idea of regaining ownership over gas and power distribution, and it has been slowly accomplishing this.

Bulgaria first privatized power production in 1998. Power plant Mariza Istok 1 was sold to America AES, while Mariza Istok 3 to American Entegra. Its share in ownership was later on purchased by Italian Enel, consequently by Amerian company CounturGlobal. Six years later, Bulgarians sold all seven distributions. Czech CEZ bought three, Austrian EVN and German E.ON two each. In 2011 E.ON sold to Czech Energo-pro its distributions explaining this move as a part of broader strategy to sell its assets worth more than EUR 15 billion.

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Soon after that disputes between the buyers and the state appeared. Due to this, as noted, serious damage to the business, EVN sued the state in 2013, Energo-pro sued it in 2015, and CEZ did the same last year, and all companies requested hundreds of millions of damages.

One year after Bulgarians, in 2005., Romanians sold five out of eight distribution companies to similar buyers. Enel bought three, CEZ and E.ON bought one each.

However, state Electrica kept three. The same scenario with court cases was repeated in Romania.

This year international arbitration brought the decision that E.ON had to pay to the state little less than EUR 1 million for not paying dividends to the state as minority owner, Italian ENEL even EUR 400 million of damage. Italians, as if they could predict the future developments, announced in 2014. that they want to sell its assets in Romania.

Montenegro is the only country that privatized its power production company by selling 41 percent of minority share package to Italian A2A in 2009. This power company, at the same time, generates the most attention of potential buyers. Both Croatian power utility company HEP and Serbian EPS are in a que for it.

The negotiation package includes the construction of thermal power plant Pljevlja (TPP Pljevlja), whereas Škoda Praha was chosen for the job, while GE was also mentioned as a partner.

Serbia, Bosnia and Herzegovina, Croatia and Slovenia haven’t followed the neighbours’ steps. Slovenia hasn’t joined the privatization trend since it rarely decides to sell its state property and on the other hand, there are Serbia, Croatia and Bosnia and Herzegovina that were late in reforms and “missed” the trend. While they were working their homework, lessons learnt from the neighbouring countries have proved that privatization may not be the best solution.

Those countries plus Montenegro are nowadays in the focus of regional privatization stories. Recently there was an information about expansion plan of Elektroprivreda Srbije (EPS) in the region.

The same message has been several times reiterated during last couple of years, usually by politicians.

No concrete steps followed the statements.

Branko Kovačević, the President of EPS Board of Directors, confirmed that the plans

for the purchase of power utilities in the region exist, reminding at the same time that it is an old idea.

Otherwise, the expansion over countries’ borders in energy sector was a successful one only for transmission companies. At the end of 2015. Serbian transmission system operator Elektromreže Srbije (EMS) purchased 10 percent of ownership of the Montenegrin Electric Power Transmission System (CGES) for EUR 13.8 million. This transaction provides EMS with a seat in CGES Board of Directors and dividends.

However, certain analyses say that this was a wrong movement from the economic perspective, having in mind that the shares could have been bought at lower price and that the investment will not be returned so soon.

Croatia also expressed its interest in purchasing Montenegrin power utility several times. Information that Croatian Government is considering an option for IPO of HEP could be also heard. Croatian Prime Minister Andrej Plenković announced an IPO of 25% of HEP until the end of 2017., primarily in order to collect money to regain majority share in oil and gas company INA. Bloomberg agency has recently published an analysis, based on views of Croatian and Hungarian experts.

According to the analysis, HEP is worth EUR 2,4 billion and IPO will not be successful. Analysts also believe that Croatia will regain INA, however only in a couple of years.

Though it looks like the state comes back to the sector of electrical energy, it could be said that it has actually never left it. Only distribution companies have been sold, while the production part has remained untapped with the exception of Bulgaria.

The privatization of TSOs hasn’t almost been discussed anywhere.

In Romania, the power production is in the hands of the state. In Bulgaria, NEK controls about half of the power production through 30 HPPs, NPP Kozloduy and TPP Mariza Istok 2. The power production in Hungary has also remained under the state’s control, i.e. company MVM, that controls several power plants and NPP Paks. In Macedonia state owned ELEM is the main power producer with three thermal power plants and more hydropower plants.

If we take into consideration the situation in Serbia, Croatia, Bosnia and Herzegovina and Slovenia, it is absolutely clear that the state is the key player in the power sector.

energyandecology.com

Issue 3 April 2017

Energy

Natural solution: Saudi's renewed plans meet growing energy demands

When it comes to renewable energy in Saudi Arabia, there still remains more than a hint of scepticism.

Multi-billion dollar plans have come and gone and the kingdom has made little progress developing renewable energy capabilities to harness its advantageous climatic conditions.

In 2010, the King Abdullah Centre for Atomic and Renewable Energy (KA-Care) was established to develop the country’s renewable and nuclear capabilities, as the country looked to generate more income from oil, instead of using it for power generation.

Following a number of studies, the world's top oil exporter said in 2012 it would install 17 gigawatts (GW) of nuclear power by 2032 as well as around 41GW of solar capacity.

Currently it has no nuclear power, but has managed to develop some solar capability, albeit on a much smaller scale, including the 500 kilowatt (kW) pilot solar power plant on Farasan Island in the Red Sea, which opened in 2011.

Makio Yamada, a researcher specialising in the political economy and international relations in the Gulf Cooperation Council (GCC), wrote a paper last year entitled ‘Vision 2030 and the Birth of Saudi Solar 13

Energy’ for the Middle East Institute in Washington.

He surmised that the growth of Saudi Arabia’s renewable industry has previously been hindered by “institutional ambiguity and fragmentation”. But the Saudi 2030 Vision, the economic reform plan launched last year to diversify the economy beyond oil, gives some hope.

The newly created super-ministry of Energy, Industry, and Mineral Resources, headed by Khalid Al Falih, who is also the chairman of the state oil giant Aramco, has paved the way for solar energy’s longawaited rise in the kingdom.

The renewable plans were significantly accelerated in January when Al Falih announced that Saudi Arabia would unveil a renewable energy programme that would require investment of between $30bn and $50bn by 2030.

The first details of the programme were finally announced late last month when the minister said the kingdom was targeting 9.5GW of renewable energy by 2023.

The first phase will see the development of a 300 megawatt (MW) solar photovoltaic (PV) plant in Sakaka, the capital of Al Jouf Province in the north, and a 400MW wind project in Midyan in the northwest.

The projects will be backed by 25-year power purchase agreements (PPAs) for solar PV and 20-year PPAs for wind energy.

The ministry has invited investors to submit requests to qualify for the first round.

The energy ministry has also created The Renewable Energy Project Development Office (REPDO) to oversee the deployment of clean energy, in a sign momentum to see real development in renewables is finally gathering pace.

Al Falih made the announcement at the recent Abu Dhabi Sustainability Week, which was hosted by Masdar.

Bader Al Lamki, Masdar’s executive director for clean energy, says the event focused on the emerging renewable markets of India and Saudi Arabia and it was therefore no surprise that the Saudi minister announced the kingdom’s plans in the UAE capital, where renewables have been on the agenda for 10 years.

Masdar, a pioneer in the Middle East for developing and adapting various renewable technology, has 2.7GW of renewables around the world in its portfolio.

“We had a number of working sessions with them, primarily to understand their aspiration, their vision and their plans in this regard,” Al Lamki reveals. energyandecology.com

Issue 3 April 2017

Energy Saudi Arabia’s previous large scale targets were hard to progress, and so Gus Schellekens, partner in EY’s MENA clean energy and sustainability services team, says it is encouraging to see that the plans have been “refined and scaled down to more manageable sizes”.

“The question now is how it's going to be taken forward; how the capacity is procured [and] managed; how the installation goes; what the international arbitration rights are like; and whether the bills get paid.”

The kingdom’s construction sector, in particular, suffered with delayed payments as low oil prices prompted governments to conserve cashflow. Saudi Arabia paid in excess of $26bn in November and December last year, according to statements by officials and central bank data. While the situation is expected to ease this year, according to credit insurer Coface, it is these kind of “practical concerns that the international players will have”, according to Schellekens.

“Whether or not they get involved will also come down to their appetite for country risk, operational risk and cost of financing projects,” he says.

“What we have previously seen in some other countries, for example, where the commitments or requirements are too onerous, is that a number of the key players will decide that it’s not within their risk or investment profile and they decide that they will pass.”

Ahmed Nada, First Solar vice-president and regional executive for the Middle East, says the strategy will be to attract foreign investors to the country, and also to encourage local participation.

“The programme is not designed to attract small players or those who are not capable of raising serious funds; it’s a model that requires certain development skills and abilities, including being able to raise the right equity and financing from local or international sources,” he says.

“At this pre-qualification stage, I believe it’s designed to attract the strong players, whether they are local in partnership with international developers, or those who are purely international developers with the total expertise.”

While the investment upfront is significant, as is the case with most renewable projects, the lower operational costs over the lifetime of the project will give investors an opportunity to recoup the outlay.

“There’s a big risk for initial investors because they have to put almost all of their money down up front and they only get paid back over time. One way the finance sector addresses this is by adding risk premiums

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to the cost of capital to cover the investment made. The more comfortable they are, the less of a premium asked, and the less the whole programme costs and the faster the outcomes are likely to be achieved.”

He says there is an opportunity for the Saudi government to make this programme as risk-free and as open and transparent as possible.

“This will create broader momentum, because by automatically driving down the costs, more domestic and international investors will get involved, and the larger sums of money being committed will allow the creation of the supporting industrial infrastructure, in terms of manufacturing, assembly, construction, operation and maintenance,” he says.

Schellekens cites the examples of Morocco and South Africa, where international and domestic companies were able to achieve very low prices per kilowatt because large domestic operations were set up.

“Local partners were very tightly embraced as part of the project structure, and that brought about 30 to 40 [percent], sometimes 50 percent, savings in certain areas of project development and delivery,” he says.

Masdar, as one of those who will submit a bid for the projects, says the business case for renewables in general “is quite solid”.

“The cost of generating electricity from renewable sources is quite competitive now, and has reached parity in many places. In this region, we take pride that in 2016 we submitted the lowest tariff in this industry - 2.9 cents per kilowatt hour for the DEWA tender for 800MW. That's already competitive and cost-effective to the alternatives,” Al Lamki says.

“The renewables as an emerging sector will have a positive ripple effect in terms of diversification of the economy [and] creation of new jobs. The kingdom is also known to be an industrial hub for many sectors and I think this ingredient that the renewables represent will bring value to the kingdom. We are very excited about their pursuit in this sector.”

While the momentum is strong, particularly following the minister’s announcements, Schellekens says a more general challenge remains around taking forward the renewable energy agenda.

“How do you operationalise the procurement and roll out of renewable energy? Because it’s being done in a country that has been defined by oil and gas for decades,” he says.

room and support a new industry that will require a different focus by industry, government and the finance community.”

Schellekens says, ultimately, the success of renewables in Saudi Arabia will be built around the core reason that it makes economic sense for the kingdom, just as it has for Dubai and Abu Dhabi.

“By producing electricity using sustainable resources, it saves the government consuming oil for domestic purposes that it could sell to the outside world,” he says.

“So you’re expanding the amount of revenue that you can achieve from your domestic resources. At current international price levels, solar and wind are also cheaper than many conventional options.”

Dubai and Abu Dhabi have led the way in terms of making solar energy, in particular, competitive when it comes to pricing.

However, being able to achieve that lower rate depends on a number of key factors.

“Nobody has executed a large project in Saudi Arabia yet, so many will have different views on whether it’s going to be higher or lower than the rest of the Gulf,” Nada says.

“A very important part of the equation on the tariff value is financing,” he adds.

The cost of funding from financiers and lenders will have a significant bearing on where the tariffs are set.

“It’s the timing and the worldwide situation that can impose that, plus of course how the international developers in particular will look at the creditworthiness of the offtakers and to which extent they will be happy with the lower returns on investment. All of that will determine whether we see higher or lower prices.”

In addition to the planned projects under the renewables plan, Nada says he would like to see legislation introduced to encourage private solar projects.

“Saudi has very large industrial cities and is looking at adding more and more cities as part of the Vision 2030 programme.

Broadly, it’s time for Saudi Arabia, maybe one year from now to also launch guidelines or incentives or regulations that certain industries in particular should start to have 20 to 30 percent, or even 10 percent, of their energy renewable,” he says.

The global renewables industry will be closing monitoring Saudi Arabia's first round of project tenders. Thus, they may do more than supply energy to homes and business but potentially energise an entire new sector.

“The current infrastructure and everything else has been set up to support this focus [on oil and gas]. Now you need to make energyandecology.com

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Energy

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Issue 3 April 2017

Ecology

Global greenhouse gas emissions flat for third consecutive year

Global energy-related carbon dioxide emissions were flat for a third straight year in 2016 even as the global economy grew, according to the International Energy Agency, signaling a continuing decoupling of emissions and economic activity.

This was the result of growing renewable power generation, switches from coal to natural gas, improvements in energy efficiency, as well as structural changes in the global economy.

Global emissions from the energy sector stood at 32.1 gigatonnes last year, the same as the previous two years, while the global economy grew 3.1%, according to estimates from the IEA. Carbon dioxide emissions declined in the United States and China, the world’s twolargest energy users and emitters, and were stable in Europe, offsetting increases in most of the rest of the world.

The biggest drop came from the United States, where carbon dioxide emissions fell 3%, or 160 million tonnes, while the economy grew by 1.6%. The decline was driven by a surge in shale gas supplies and more attractive renewable power that displaced coal. Emissions in the United States last year were at their lowest level since 1992, a period during which the economy grew by 80%.

In 2016, renewables supplied more than half the global electricity demand growth, with hydro accounting for half of that share.

The overall increase in the world’s nuclear 18

net capacity last year was the highest since 1993, with new reactors coming online in China, the United States, South Korea, India, Russia and Pakistan.

as well as nuclear. Five new nuclear reactors were connected to the grid in China, increasing its nuclear generation by 25%.

Coal demand fell worldwide but the drop was particularly sharp in the United States, where demand was down 11% in 2016. For the first time, electricity generation from natural gas was higher than from coal last year in the United States.

“In China, as well as in India, the growth in natural gas is significant, reflecting the impact of air-quality measures to fight pollution as well as energy diversification,” said Dr Birol. “The share of gas in the global energy mix is close to a quarter today but in China it is 6% and in India just 5%, which shows they have a large potential to grow.”

With the appropriate policies, and large amounts of shale reserves, natural gas production in the United States could keep growing strongly in the years to come.

This could have three main consequences: it could boost domestic manufacturing, supply more competitive gas to Asia through to LNG exports, and provide alternative gas supplies to Europe.

US and natural gas prospects will be explored in details in the next World Energy Outlook 2017.

In China, emissions fell by 1% last year, as coal demand declined while the economy expanded by 6.7%.

There were several reasons for this trend: an increasing share of renewables, nuclear and natural gas in the power sector, but also a switch from coal to gas in the industrial and buildings sector that was driven in large part by government policies combatting air pollution.

Two-thirds of China’s electricity demand growth, which was up 5.4%, was supplied by renewables — mostly hydro and wind –

In the European Union, emissions were largely stable last year as gas demand rose about 8% and coal demand fell 10%.

Renewables also played a significant, but smaller, role. The United Kingdom saw a significant coal-to-gas switching in the power sector, thanks to cheaper gas and a carbon price floor.

Market forces, technology cost reductions, and concerns about climate change and air pollution were the main forces behind this decoupling of emissions and economic growth.

While the pause in emissions growth is positive news to improve air pollution, it is not enough to put the world on a path to keep global temperatures from rising above 2°C. In order to take full advantage of the potential of technology improvements and market forces, consistent, transparent and predictable policies are needed worldwide.

energyandecology.com

Issue 3 April 2017

Ecology

Coal power plant pipeline goes into 'freefallâ&#x20AC;&#x2122; Study details how global pipeline for new coal plants has almost halved in the past year, as shift to cleaner power sources gathers pace.

Lauri Myllyvirta, senior global campaigner on Coal and Air Pollution at Greenpeace, hailed 2016 as "a veritable turning point" for efforts to tackle climate change. "China all but stopped new coal projects after astonishing clean energy growth has made new coal-fired power plants redundant, with all additional power needs covered from non-fossil sources since 2013," he said.

"Closures of old coal plants drove major emission reductions especially in the U.S. and UK, while Belgium and Ontario became entirely coal-free and three G8 countries announced deadlines for coal phase-outs."

Tim Buckley, director of energy finance studies at the Institute for Energy Economics and Financial Analysis, said the report should provide a wake-up call to investors in fossil fuel assets.

The global pipeline for new coal-fired power plants is contracting fast, offering fresh hopes that the global economy could meet the ambitious climate goals set out in the Paris Agreement.

climate security, and jobs. And by all indications, the shift is unstoppable."

That is the conclusion of a major new report from Greenpeace, the Sierra Club and CoalSwarm, who today publish the third edition of their annual report on the global coal power plant pipeline.

The report also revealed how in industrialised nations the speed of coal plant retirements is gathering pace. The survey found a record-breaking 64GW of coal plants have been retired in the past two years, mainly in the EU and US taking the equivalent of nearly 120 large coal-fired units off the grid.

The report, entitled Boom and Bust 2017: Tracking The Global Coal Plant Pipeline, details how new policies in a number of Asian countries has led to a sharp contraction in the number of coal plants in development over the past year.

The report comes within days of US energy firm Dayton Power & Light announcing it is to shut down two coal-fired power plants in southern Ohio, and further confirmation from the UK government it expects coal to be fully removed from the grid by 2023.

Specifically, the level of pre-construction activity in 2016 fell 48 per cent year-onyear, while the number of new projects starting construction fell 62 per cent, and the number of coal plant permits issued in China, the world's largest consumer of coal, slumped 85 per cent.

The report concludes the combination of a significantly curtailed coal plant development pipeline and an increase rate of coal plant retirements brings the possibility of meeting the Paris Agreement target of keeping global temperature increases below 2C "within feasible reach", as long as the shift away from coal power continues to accelerate.

The report said the primary driver of the trend was to be found in China and India where a combination of new air quality policies, clean energy programs, and financial retrenchment by Indian developers has resulted in construction being frozen at over 100 project sites.

"This has been a messy year, and an unusual one," said Ted Nace, director at the CoalSwarm research network. "It's not normal to see construction frozen at scores of locations, but central authorities in China and bankers in India have come to recognize overbuilding of coal plants as a major waste of resources. However abrupt, the shift from fossil fuels to clean sources in the power sector is a positive one for health, 19

Nicole Ghio, senior campaigner for the Sierra Club's International Climate and Energy Campaign, said the trend was particularly encouraging, given it is being driven in large part by commercial pressures.

"The staggering uptick in clean energy and reduction in the new coal plant pipeline is even more proof that coal isn't just bad for public health and the environment - it's bad for the bottom line," she said. "Markets are demanding clean energy, and no amount of rhetoric from Donald Trump will be able to stop the fall of coal in the US and across the globe."

"The Coalswarm data precisely underlines the growing stranded asset risk evident in thermal coal power plant investments globally, particularly when read in the context of other developments in the global coal power industry," he said. "With collapsing coal plant utilisation rates across China and India, and plans to build new plants in those countries drastically curtailed, it has become clear that the world has dramatically overbuilt coal power plants and overestimated the now declining thermal coal demand profile."

His comments were echoed by Paul Massara, CEO of North Star Solar and former CEO of RWE npower, who argued policy interventions and the emergence of cost effective renewables and storage technologies were "making new coal plants redundant before they are even built".

He added that the latest evidence further strengthened the rationale for ambitious climate policies in industrialised nations.

"For us in Britain, there are two clear messages from this report," he said. "One is that the government's decision to phase out coal power is, far from being a risky move, actually putting us ahead of the pack in moving away from the dirtiest form of energy. Secondly, it should challenge Germany and other Western nations who still rely on coal to adopt a faster timescale to close existing plants.

"It also highlights that those claiming that it is pointless, our taking action to tackle climate change because Asian countries are still building coal stations, are increasingly wrong."

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Issue 3 April 2017

Ecology

EPA head Scott Pruitt denies that carbon dioxide causes global warming

Scott Pruitt, Donald Trump's head of the US Environmental Protection Agency, has dismissed a basic scientific understanding of climate change by denying that carbon dioxide emissions are a primary cause of global warming.

“I think that measuring with precision human activity on the climate is something very challenging to do and there's tremendous disagreement about the degree of impact, so no, I would not agree that it's a primary contributor to the global warming that we see,” he told CNBC. “But we don't know that yet ... We need to continue the debate and continue the review and the analysis.”

This stance puts Pruitt at odds with his own agency, which states on its website that carbon dioxide is the “primary greenhouse gas that is contributing to recent climate change”. This finding is backed by Nasa, which calls CO2 “the most important longlived 'forcing' of climate change”.

along with other greenhouse gases such as methane, has caused most of the global warming experienced since the 1950s.

Pruitt's comments were quickly condemned by scientists, environmental activists and even his immediate predecessor as EPA chief, Gina McCarthy.

“The world of science is about empirical evidence, not beliefs,” said McCarthy, an appointee of Barack Obama. “When it comes to climate change, the evidence is robust and overwhelmingly clear that the cost of inaction is unacceptably high.

Kevin Trenberth, senior scientist at the National Center for Atmospheric Research, said: “Pruitt has demonstrated that he is unqualified to run the EPA or any agency.

There is no doubt whatsoever that the planet is warming, and it is primarily due to increased carbon dioxide in the atmosphere from burning of fossil fuels.

Scientists have understood for more than a century that CO2 traps heat. Atmospheric concentrations of the gas have increased by more than a third since the industrial revolution, driven by the burning of fossil fuels and deforestation.

“Carbon dioxide is a greenhouse gas and we can demonstrate clearly that the observed warming of the planet would not have occurred without that change in atmospheric composition. These are scientific facts, not opinion, and it is incumbent on politicians to take account of the scientific evidence.”

The Intergovernmental Panel on Climate Change report from 2014, which summarized the findings of 2,000 international scientists, states it is “extremely likely” that the steep rise in CO2,

Pruitt has previously equivocated on the issue of climate change, telling his Senate confirmation hearing that while he accepts the world is warming it is “hard to measure with precision” the human influence.

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A core EPA function is the regulation of greenhouse gases, including CO2. Pruitt, in his previous role as attorney general of Oklahoma, sued the EPA to halt Obama's Clean Power Plan, which imposes emissions limits on coal-fired power plants.

The plan, similar to many of the other Obama-era policies to combat climate change and safeguard clean air and water, is likely to be dismantled by the Trump administration. The president has previously called the EPA a “disgrace” and promised to reduce it to “tidbits” in order to spark economic growth.

The EPA faces severe cuts under a proposed White House budget proposal, with Pruitt set to review the agency's role in vehicle emissions standards, methane emissions and protection of America's waterways.

Pruitt sued the EPA 14 times while attorney general of Oklahoma and has worked in concert with fossil fuel interests in many of these cases. The recent release of thousands of Pruitt's emails during his tenure showed an extremely close relationship between Pruitt's office and oil and gas companies.

The EPA administrator has insisted that the regulator does work that could be delegated to the states, has overreached and needs to be reined in.

energyandecology.com

Issue 3 April 2017

Ecology

Here comes the sun: solar power finance for the 21st century Solar power, along with onshore and offshore wind, is one of the most mature and promising renewable energy sources available. And because solar photovoltaic (PV) panels work well in small off-grid applications as well as medium-sized and larger projects, it is also particularly wellsuited to the decarbonisation efforts of developing countries, many of which have access to ample reliable solar resources.

But as with any green energy source, access to finance for new projects is essential to push solar adoption to new heights, as recognised in a recent report published in January by trade association SolarPower Europe.

With green finance a recurring talking point as the developed world discusses its roadmap to mobilising $100bn a year for climate action in developing countries, how does this discussion impact solar power's global prospects?

Public finance: international efforts Public finance is often cited as the essential instigator for vital but high-risk projects to help combat climate change, creating a climate that allows private sector investment to take the baton and run with it.

In this sense, the wheels of public green finance are finally starting to turn in earnest, with public climate finance flowing into developing countries set to rise from an average of $41bn in 2013-2014 to $67bn in 2020, a 60% increase.

Much of this increase is being driven by increased finance flowing from the state level to developing countries, as well as from multilateral development banks (MDBs) and specialised climate funds. The World Bank, for example, announced in May 2016 that it would be allocating a $625m loan to the State Bank of India, along with $125m in concessional cofinancing and a $5m grant from the Climate Investment Fund, to invest in widespread solar rooftop installations across the country.Major international collaborations, meanwhile, are also focusing on freeing up more capital for solar and other renewable sectors.

The India-led International Solar Alliance (ISA), which aims to bring together a host of sun-rich nations in the tropics to promote solar power, is looking to mobilise $1tn worth of investments by 2030, through what it calls “innovative policies, projects, programmes, capacity-building measures and financial instruments”, with the international group acknowledging that “the reduced cost of finance would enable us to 21

undertake more ambitious solar energy programmes”.

COP22 in November saw 20 countries sign an ISA framework agreement, with the agreement set to become operational once 15 countries have ratified it.

Blended financing and co-investment: derisking solar projects for private investors A potent and relatively recent method of international collaboration is through coinvestments and blended financing models, which essentially create microcosms of the traditional relationship between public and private financing for climate projects – public finance to assume the lion's share of risk, and private investment to fill the gap and sustain development.

Blended and co-financing models involve strong participation or co-investment from MDBs and state-run development funds to help de-risk renewable projects and stimulate private investment. The Global Energy Efficiency and Renewable Energy Fund, for example, provides layered risk through €112m investment from Norway, Germany and the EU, which it used to entice €110m in further private sector investment for developments, such as solar power projects in India, which traditionally have proven too risky for private investors.

China leads the way Of course, it would be impossible to have a serious discussion about green financing without mentioning China, the dominant force in renewable energy technology – five of the world's six largest solar module manufacturers are now based in the country – and global leader in renewable energy investment.

China's top-down public investment in renewable technologies has spurred massive growth in its domestic industry, with solar playing a prominent role.

The country's massive investments – it spent $102bn on domestic renewable energy in 2015, more than twice that of the US – have spurred an active private investment scene in solar power. Chinese domestic solar installations doubled to 50GW in the two years up to the end of 2015, and Bloomberg New Energy Finance has estimated that this figure will more than double again with 109GW installed by the end of 2018. The government has stated that it wants to invest a total of at least $360bn in renewable energy sources by the end of 2020.

the world's total population, it could make a massive impact on worldwide efforts to fight climate change just by focusing on its internal market. But the country has also been rapidly ramping up its foreign investments in renewables; the Institute for Energy Economics and Financial Analysis tracked 13 Chinese overseas renewable investments of over $1bn in 2016, a 60% year-on-year increase.

The surge of green bonds Green bonds, which are issued specifically to finance clean energy or other climatebeneficial projects, are another growing mechanism helping to spur investment in solar power and other renewables. Green bonds were first issued in 2007 by MDBs such as the European Investment Bank and the World Bank, but have rapidly increased their presence, with issuances growing from $2.6bn in 2012 to $41.8bn in 2015.

Green bonds allow renewable energy issuers access to a more diverse pool of institutional investors than they are traditionally able, unlocking low-cost capital for infrastructure projects. Investors, meanwhile, get more transparency on where their money will be invested while also having a positive impact on their corporate social responsibility goals.

Understandably, these clean energy bonds have attracted some accusations of 'greenwashing' – a PR-inspired 'clean' investment that turns out to be more for show than for actually making an environmental difference. But the credibility of green bonds seems to be improving quickly. On the eve of COP22, the Moroccan Agency for Solar Energy (Masen) issued Morocco's first green bond, worth $118m, to help fund three solar projects with a total capacity of 170MW as part of the country's massive NoorOuarzazate concentrated solar power complex.

Perhaps the best sign of the growing health of the green bond market is the launch in September of Luxembourg Stock Exchange's Green Exchange (LGX), the world's first stock exchange-backed platform exclusively for the issuers of green bonds and financial instruments that should also help to address greenwashing concerns.When we look at the market it is good news that it is growing so fast, but is it growing fast enough? No, it is not.

A dedicated green exchange will raise the bar for disclosure.

Given that China hosts just under a fifth of energyandecology.com

Issue 3 April 2017

Ecology

World’s largest artificial sun switches on in Germany achieved.” They create a brilliant array, which scientists hope will help them figure out how to best use the huge quantity of energy from sunlight hitting Earth. The experiment doesn’t come without a cost: Synlight sucks up as much electricity in just four hours as a family of four could use in an entire year, according to the Associated Press. It’s also housed in a specially built structure in Germany.

German scientists are hoping to shine new light on ways to generate environmentally friendly fuels. At the German Aerospace Center (DLR)’s Institute for Solar Research, they have flipped on a system called Synlight, which they describe as the largest artificial sun on the planet. Synlight is comprised of 149 huge spotlights, pouring out a light intensity around 10,000 times the

solar radiation naturally found on Earth.

Synlight’s 149 spotlights are similar to those commonly used in cinema projectors.

According to DLR, “These enable solar radiation powers of up to 380 kilowatts and two times up to 240 kilowatts in three separately usable irradiation chambers, in which a maximum flux density of more than eleven megawatts per square meter can be

The focus for Synlight researchers will be on solar fuels, according to DLR, which said scientists will zero in on developing manufacturing processes. Scientists will delve into new ways to create hydrogen, which isn’t found naturally but must be created by splitting water into hydrogen and oxygen, according to ABC News. The publication quoted the institute’s director Bernhard Hoffschmidt, who said the furnace-light conditions Synlight can produce – up to 5,432 degrees Fahrenheit – are crucial to experimenting with new methods of creating hydrogen.

Banks give €1 billion to build “Smart Europe” pivotal role in elevating the quality of life among residents, creating a desire to explore new pursuits and enjoy favorite pastimes. In addition, such parks act as important links between different parts of the wider city, positioning them as popular destinations drawing people together.

The park also aims to decrease population density in Dubai to a total of 12.5 square kilometers per person-down 17 percent from its current density.

At the same time, adding the large natural landscape and trees is expected to improve air quality in the area surrounding it, while preserving existing biodiversity and enhancing the area’s urban ecology.

Dubai is working on an ambitious plan to build a massive 800,000 square-mile “ecofriendly” public park on par with those of major capital cities around the world.

also include 55 playgrounds, 45 “sports grounds” five major event venues along with retail spaces for shops, restaurants and cafes.

The park, a joint project between Dubai Holding and Dubai Municipality, will feature 18 miles of pedestrian pathways, 12 miles of jogging track, 9 miles worth of cycling tracks and 4 miles of nature trails. As if that’s not enough to keep folks busy, it will

Located in Dubailand, the first phase of construction is set to start later in 2017, with the beginnings of the jogging and cycling tracks, along with some pedestrian walkways.

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Integrated into the park will be sustainable on-site power generation, waste recycling, natural shading, wireless internet connectivity – as well as a low water consumption of five liters per square kilometer and a home for 15,000 native and adoptive tree species.

The provision of green, open spaces play a energyandecology.com

Issue 3 April 2017

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OIL&GAS

Iran's Gas Industry Member of Executive Committee of the International Gas Union (IGU) 2015-2018.

Member of Group of Experts on Gas of United Nations Economic Commission for Europe(UNECE) 2016-2017.

Letter of Commendation As the Exemplary Research Expert Received From the Deputy Petroleum Minister & Managing Director of NIGC 2008.

Letter of Commendation Received From the Deputy Petroleum Minister & Managing Director of NIGC 2011.

Letter of Commendation Received From the Deputy Petroleum Minister & Managing Director of NIGC 2013.

1.Iran's Gas Industry History

By Hedayat Omidvar Graduated in Industrial Engineering (MSc) in 2002.

He has been working since 1992 as Natural Gas consumption expert in Corporate Planning Dept., National Iranian Gas Company (NIGC), responsible for treatment, transmission, storage and distribution of natural gas.

At present, he is Head of Communication Affairs with Science & Research Centers, Research & Technology Dept.

Member of Institute of Industrial Engineers (IIE) since 1992.

Member of American Industrial Hygiene Association (AIHA) since 1994.

Member of Iran Institute of Industrial Engineering (IIIE) since 2001.

Member of the Programme Committee A (PGC A)â&#x20AC;&#x153;Sustainable Developmentâ&#x20AC;? of the International Gas Union (IGU) 2003-2006.

Member of the Marketing and Communication Committee (PGC E) of the International Gas Union (IGU) 20062012.

Member of the Gas Advocacy Task Force (TF2) of the International Gas Union (IGU) 2012-2015.

Secretary of Utilization Committee of the International Gas Union (IGU) 2015-2018.

Member of Marketing and Communication committee of the International Gas Union (IGU) 2015-2018.

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Having a glance at the writings of the ancient historians, one can realize that Iranians were pioneers of using petroleum derivatives and gas. For example, the existence of the ruins of fireplaces and temples like immortal fire near Kirkuk, Known as Bokht-Ul-Nasr torch located near a natural gas reservoir.

Zoroastrians' temple near MasjidSuleyman and historical narrations regarding Azargoshasb fireplace, all together is a proof for this very claim.

Ancient Iranians, based on the norms of their own religion, esteemed fire, and tried to keep it alive. In central and southern highland of Iran where dense woods existed, Iranians used some other things apart from wood taken from jungle. In other words, this was fulfilled through benefiting from the underground reserves. In western, southern and southwestern Iran, as today we know, a huge amount of oil and gas is there.

1.1.Natural Gas Industry Birth Although, Iranians were the pioneers of using gas and other petroleum derivatives, the first historical documents related to planned using of gas in Iran goes back to the era of Qajar kingdom. In 1873, when king Naser-ul-din had a visit from London, he was surprised when he saw lights in the streets of London. Returning home, he ordered to construct and use gaslight factory.

In 1908, the first oil well drilled in Masjid Suleyman reached oil; and a huge amount of associated gas was flared due to the long distance between the production sources and consumption destinies on one hand and high cost of investment and low consumption rate in the south of Iran, on the other. But gradually oil reservoirs came into

stream one by one and Iran thought of using natural gas for supplying the required usages of residential sector, especially the houses of NIOC staff in oil-bearing regions such as Masjid Suleyman, Aghajari, Haftgel and Abadan. Even though the major activities of petroleum industry in those days included crude oil production, transmission and refining in southern Iran, agent companies carried out some limited activities for production and process of natural gas. From 1910 to 1960s, oil was discovered and the associated gases were mainly flared. In early 1960s based on a contract signed with Russia, associated gases were gathered and transferred to Russia in lieu of constructing a steel mill in Iran. In fact, for 50 years, the associated gases were flared, but after exporting gas to Russia associated gas was supplied in Shiraz for the first time. In fact, Shiraz cement factory was the first factory, which received gas as its fuel. Later on gas network was expanded to some other cities in Iran. In this way, the gas, which was flared for 50 years entered the gas distribution network and was used at residential sector.

Until no independent gas fields were discovered in Iran, it was natural to process and use associated gas. Nevertheless, after discovery of some independent gas fields such as Kangan and Pars, it was necessary to divide responsibilities regarding gas extraction between NIOC and NIGC. In other words, crude oil production, extraction, sales and export was left to NIOC; and natural gas refining, transmission and distribution was left to NIGC. 2. National Iranian Gas Company (NIGC) Around 40 years ago, the policies adopted

by NIOC paved the grounds for NIOC to have access to technical and economic requirements to handle and restrain associated gases and consequently gather, refine, transfer and sell them. Due to raising the issue of exporting gas, abroad comprehensive studies were made and the project for the overall gas pipeline known as IGAT I carried out and came into stream.

Due to the essentiality of leaving all the gas affairs to a single organization responsible for the determined responsibilities and objectives in future, and because of the general agreements between Iran and Former Soviet Union to expand economic cooperation in 1965 which led to inking a protocol in the same year, the issue of gas export was raised, and NIGC was established in March 1965 and started its activities. energyandecology.com

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OIL&GAS

Iran's Gas Industry and dehydration, gas transmission, gas engineering and development, and commerce.

The affiliated companies supervise the activities of some independent directorates.

The aforementioned companies are as follows: 1- Iranian Gas Engineering &Development Company.

2- Iranian Gas Transmission Company.

3- Iranian Gas Industrial Refining Services.

4-Iranian Underground Gas Storage Company.

5- Iranian Gas Commerce Company.

Iran's Natural Gas Production

At present, NIGC is one of the four major subsidiary companies of the Petroleum Ministry. The chair of its general assembly is the esteemed president and the chair of its Board of Directors is the Petroleum Minister.

Based on article 5 of the company statute, NIGC is authorized to deal with the following: 1-Carrying out economic and feasibility studies of the projects left to the company.

2-Carrying out basic and detailed engineering affairs and implementing all the projects left to the company.

3-Design, supervision and implementation of all engineering and construction operations such as construction and development of oil and gas production, collection and transfer systems, wellhead facilities, refineries and dehydration facilities, underground gas storage, transfer pipelines, gas supply and distribution, natural gas, CNG and CGS, telecommunication systems, pump stations, construction and infrastructure works, various offshore structures and the relevant facilities in Iran and abroad 4-Carrying out all scientific, technical, financial, commercial and service activities essential for expansion of the company's operation 5-Carrying out any scientific, technical, financial commercial, and service activities required for development of operation in the company.

National Iranian Gas Company is comprised of six directorates as follows: 1- Finance 25

2- Planning 3- Research and Technology 4- Human Resources Development 5-Gas Distribution Coordination 6-Production Coordination and Supervision (Dispatching) In addition to the above-mentioned directorates, there are twelve affairs, which directly report to the Managing Director as follows: 1- Public Relations 2- Legal Affairs 3- Inspection and Complaints Consideration 4- Internal Affairs 5- International Affairs 6- Security 7- Assemblies Affairs 8- Executive Affairs of Violations' Investigations 9- Technical Inspection 10- Health, Safety and Environment (HSE) 11- Information Technology 12- Commerce Among the previously mentioned directorates, Gas Distribution Coordination directorate is comprised of 30 provincial gas companies, which are responsible for delivering gas to cities, villages, power plants, industries and commercial centers.

National Iranian Gas Company is comprised of six affiliated companies active in various activities such as gas treatment

This is a list of countries by natural gas proven reserves based on The World Factbook or other authoritative third-party sources. Based on data from BP, at the end of 2013, proved gas reserves were dominated by three countries: Iran, Russia, and Qatar, which together held nearly half the world's proven reserves. Since 2000, some countries, notably the US and Canada, have seen large increases in proved gas reserves due to development of shale gas, but shale gas deposits in most countries are yet to be added to reserve calculations.

According to the Iran Petroleum Ministry, the proved natural gas reserves of Iran are about 1,046 trillion cubic feet (29.6 trillion cubic metres) or about 15.8% of world's total reserves, of which 33% are as associated gas and 67% is in nonassociated gas fields. It has the world's second largest reserves after Russia.

Despite Western sanctions, Iran's natural gas production continues to grow as more phases of its largest natural gas field, South Pars, come online. In all, the field Iran shares with neighboring Qatar is being developed in 24 phases. About half of the phases have been completed, and Iran hopes the field, including those centered on oil, will be fully operational in 2018. Located over 60 miles offshore, South Pars holds nearly 40% of Iran's gas reserves.

Iran's natural gas imports declined in 2012 from the previous year (by more than 35%) and in 2013 (by 21%), reflecting much lower volumes imported from Turkmenistan. The U.S. and EU sanctions interfered with transactions between Turkmenistan and Iran in 2012 and 2013, resulting in the decline of Turkmen gas imports.

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OIL&GAS

Iran's Gas Industry In 2011, Iran received almost 30% of Turkmenistan's natural gas exports, but the share dropped to less than 12% in 2013, according to BP Statistical Review of World Energy. Nonetheless, more than 90% of Iran's natural gas imports still came from Turkmenistan in 2013 and 2014, and the remainder from Azerbaijan. Imports of Turkmen natural gas are essential to Iran's ability to meet both seasonal peak demand and industrial demand in northern Iran.

Iran exports natural gas to Turkey, Armenia, and Azerbaijan. More than 90% of Iranian exports went to Turkey in 2014, and the remainder went to Azerbaijan and Armenia.

Armenia uses most of its imported Iranian natural gas to produce electricity at Hrazdan power plant. In return, excess baseload electricity generated from the Armenian Nuclear Power Plant is exported to Iran. Iran exports natural gas to the isolated Azerbaijani exclave of Nakhchivan via Salman-Nakhchivan pipeline. In exchange, Azerbaijan exports natural gas to Iran's Northern provinces via AstaraKazi-Magomed pipeline.

Liquefied natural gas (LNG): Although Iran's aspirations to build a liquefaction facility date back to the 1970s, the country has yet to build one. The NIOC started construction projects in the past to build an LNG export plant, but most of the work has been halted, mainly because of the lack of technology and foreign investment, stemming from international sanctions that made it impossible to obtain financing and to purchase necessary technology. Given the political constraints, Iran's LNG projects are years away from completion.

Proposed regional pipelines: Iran has the potential to become an important gas supplier to its region, and has established agreements with some of its neighboring countries to export natural gas via planned regional pipelines. However, there are several challenges related to Iran's natural gas sector that may complicate volumes expected from these projects. Some of these challenges include: Iran's growth in natural gas demand; Iran's reliance on its natural gas to augment oil recovery by reinjecting it into oil wells; international sanctions that have hindered Iran's access to technology and foreign investment; and some disagreements between Iran and potential buyers over natural gas prices.

Iran-Iraq Pipeline:Based on recent progress, natural gas pipeline exports from Iran to Iraq are expected to begin soon. A natural gas pipeline from Iran's Ilam 26

province to the Iran-Iraq border is complete and the construction of the pipeline on the Iraqi side, which will supply the Mansourieh power plant, is near completion. Initial gas exports are expected to be about 50 billion cubic feet (Bcf) per year and to increase in the future. Iraq and Iran signed an agreement in the past to supply natural gas to fuel Iraqi power plants in Baghdad and Diyala. The initial contract covered 320 Bcf per year over five years. However, securityrelated concerns may delay plans to increase gas supply to this level.

Iran-Oman Pipeline: In March 2014, Iran and Oman agreed that Iran would export 350 Bcf per year of natural gas via pipeline to Oman. The construction of the pipeline may be delayed because of pricing disagreements. Iran expects gas prices of $11-14/million British thermal units (MMBtu), while Oman is looking to pay $68/MMBtu. Iran-Pakistan Pipeline: Although the IranPakistan Pipeline has experienced considerable financing difficulties, both countries seem committed to complete the project. Construction of the pipeline on the Iranian side is almost complete, while construction on the Pakistani side has been delayed. The initial pipeline agreement called for the delivery of 274 Bcf per year of natural gas over 25 years.

Iran-UAE Gas Contract: The Iran-United Arab Emirates (UAE) natural gas contract outlined an agreement to transport natural gas from the Salman field to Sharjah in UAE. Contract negotiations were not concluded because of a pricing and volume dispute, and the contract was referred to international arbitration.

After increasing both Iran's oil production and exports by about one million barrels per day since elimination of sanctions in midJanuary, it is the time to wait for Iran's gas surprise.

Iran's actual sweet gas production level increased to above 178bn m3 last year, while the raw gas production capacity reached 260bn m3/yr, thanking to commencing new phases of giant gas field shared with Qatar, South Pars.

Iran has boosted the raw gas output from this field to above 132bn m3/yr last fiscal year, which ended on March 21, but 5 new phases are expected to become operational during current year. The final production capacity of these 5 phases is about 55bn m3/yr and some of them are currently producing gas with half capacity.

The Iranian side of South Pars has been divided to 24 phases, of which stages 1-10, 12, 15 and 16 are fully operational now.

Once, the all 24 phases of this filed become operational by 2019, the country's raw gas production capacity would increase from the current 260bn m3/yr to around 390bn m3/yr.

However, South Pars is not the all of Iranian gas story. The country has introduced 49 oil and gas fields for foreigners based on a new designed contract model, so called Iran Petroleum Contract, or IPC. Among the introduced fields, there are 21 gas fields, of which only two are brown fields with the current 28mn m3/d output.

Once, the all of these fields become operational, about 380mn m3/d of gas would be added to the production level, while the produced associated gas from the oil fields would add further 200mn m3/d to the output level as well.

It is not clear how much the foreign companies invest in these fields based on IPC, but Iran hopes to attract $30b in coming years. In total, Iran has planned to invest $231 billion investment (including foreign funds) in upstream oil and gas projects by the March 2025.

For now, the natural gas shares above 68 percent in Iran's total primary energy consumption, but gasification of further 2 million households, tripling gas re-injection to to oilfields to around 100bn m3/yr as well as boosting gas deliveries to power plants by more than 20bn m3/yr of gas to power plants to curb liquid fuels burning in this sector is in agenda.

In total, Iran would have a significant amount of surplus gas to be exported, not only thanking to the production increase, but also due to fuel conservation projects.

Iran's Fuel Conservation Organization plans to spend over $16bn on improving energy efficiency projects to save $170bn â&#x20AC;&#x201C; over ten times more â&#x20AC;&#x201C; in fuel.

Beside upstream sector, Iran has $55.8bn worth gas transit projects in next 10 years, including several cross-country pipelines, enabling the country to export gas in several directions. For now Iran export about 9.7 bn m3/yr gas to Turkey, but there are around 100mn m3/d of gas export deals with Iraq, Pakistan and Oman.

The country also has a 10.5mn mt/yr-LNG plant, developed by 50%, aimed to liquefied 14bn m3/yr of gas and export to foreign markets, including EU by 2019. energyandecology.com

Issue 3 April 2017

OIL&GAS

Flue gas analysis – brilliantly easy: testo 350 – the first flue gas analyzer that thinks ahead data even when the flue gas pipe and the adjustment site are separated, especially helpful for industrial burners, for example.

Measurement data can be transferred from the analyzer box to the control unit. This means the analyzer box can remain at the measurement site for further measurements, and the control unit taken away in order to process the measurement data.

In order to protect the display in measurements over a longer period or during transport to different measurement sites in a system, the control unit can be attached to the analyzer box facedown.

Large colour graphic display with application-specific menu The following measurement objects are available: - Burner - Gas turbine - Engines (Select λ > 1 or λ ≤ 1 regulated industrial engines) User-defined.

Typical fuels, a practicable order of the exhaust gas parameters in the display, the corresponding calculations as well as useful instrument pre-settings, are stored under each of these measurement objects. Examples of these are the activation of the dilution in measurements on λ ≤ 1 regulated industrial engines and gas turbines, or the testing of the relevant gas sensor in the dilution slot.

The advantages of the application-specific menu -Information in the display guides the user through the menu.

-Easy operation without previous knowledge of the instrument -Reduction of the work steps before the start of the measurement.

Analyzer box – industrial standard, robust and reliable The portable flue gas analyzer testo 350 is the ideal tool for In the analyzer box are the gas sensors, the measurement gas professional flue gas analysis. Helpful instrument settings guide and rinsing pumps, the Peltier gas preparation (optional), gas paths, filters, analysis and storage electronics as well as the the user safely through typical measurement tasks such as: mains unit and the Li-ion battery.

- Flue gas analysis in commissioning, setting, optimization or The robust housing has built-in impact protection (specially operational measurements on industrial burners, stationary constructed X-shaped rubber edges), allowing the analyzer box industrial engines, gas turbines and flue gas purification systems. to be used in tough conditions. Downtimes due to dirt in the - Control and monitoring of officially prescribed emission limits in instrument are almost completely eliminated by intelligent design and robustness. Inherently sealed chambers protect the interior exhaust gas. of the instrument from dirt from the surroundings.

- Function testing of stationary emission measuring instruments.

Operation can be carried out with the control unit or in direct - Control and monitoring of defined gas atmospheres in furnace connection with a PC or notebook (USB, Bluetooth® 2.0 oder rooms or kilns in different processes.

CANCase). The analyzer box can, after programming, independently carry out measurements and store measurement Control unit – small and convenient The control unit is the operating and display unit of the testo 350. data.The plug-in connections for the probes and bus cables are It can be removed and equipped as standard with a Li-ion locked by bayonet fittings, and therefore securely connected to rechargeable battery. All settings are carried out using the cursor the analyzer box. This prevents unintentional removal, avoiding button. The presentation of the measurement values takes place false measurements. via the colour graphic display. Thanks to the internal memory, testo 350 – Flue gas measurement at the highest level, measurement data can be transferred from the analyzer box to the control unit. If required by the measurement, several thanks to: analyzer boxes can conveniently be operated and controlled Easily accessible service opening The service opening in the underside of the instrument allows using one control unit very easy access to all relevant service and wearing parts such as pumps and filters, which can then be quickly cleaned and/or The advantages of the testo 350 control unit: Operation of the analyzer box and transfer of the measurement exchanged on site.

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Issue 3 April 2017

OIL&GAS The advantages: - Reduction of instrument unavailability due to service times.

- Cost savings due to instrument maintenance and/or exchange and cleaning of wearing parts by the user.

- Immediate access to all relevant wearing parts

- The instrument can also be safely used in dusty or dirty atmospheres Further advantages...

Diagnosis function â&#x20AC;&#x201C; integrated and intelligent The testo 350 has a number of instrument diagnosis functions.

Error reports are issued in clear text, and are thus easily understandable. The current status of the flue gas analyzer is constantly displayed. This guarantees: - Low downtimes thanks to early warning reports, for example when gas sensors are spent.

- No false measurements due to faulty instrument components.

Easy exchange of the gas sensors The gas sensors are pre-calibrated and can be exchanged, - Better planning of measurement work replaced or extended by further measurement parameters without - More reliability in emission measurement and up-to-date information on the instrument status. test gas â&#x20AC;&#x201C; if necessary directly at the measurement site.

- No more long service times Automatic zeroing of the pressure sensor -Flexible extension of the testo 350 by further gas measurement This option allows volume and mass flow velocity to be measured parameters when applications or regulations change. without supervision over a longer period of time and parallel to the - A report is immediately issued when the NO sensor filter is used up. Then only the filter needs to be changed, and no longer the emission measurement. The pressure sensor is automatically zeroed at regular intervals. This avoids the typical drift of the whole NO sensor. pressure sensor when ambient conditions change.

Automatically monitored condensate trap The automatic monitoring of filling level reports when the Gas sensor zeroing condensate containerneeds to be emptied, and a few minutes after When the instrument is switched on, or manually if needed, the gas the report, the measurement gas pump is automatically stopped. sensors are zeroed with ambient air. In the testo 350, this This provides the highest protection of the analyzer box and the procedure is already completed in 30 seconds. This means that fast availability with tested and zeroed gas sensors is always gas sensors from damage by condensate entry. guaranted.

External cooling loop Closed cooling loops isolate the instrument electronics and GLOBAL â&#x20AC;&#x201C; TEST EOOD sensors from the ambient air. The interior of the instrument is 1408 Sofia, Janko Zabunov str., bl. 3, ent. B, P.O.Box 21 cooled via a heat exchanger and therefore does not come into tel. (02) 953 07 96 ; (02) 953 29 56 contact with dirty or aggressive ambient air. fax (02) 952 51 95 e-mail: office@global-test.eu - Damage to the internal electronics are thus effectively prevented. www.global-test.eu Thermally separated sensor chamber The sensor chamber is thermally separated from the other instrument components. This reduces possible sensor drifts caused by thermal influences. This allows the maximum reliability pf the measuring instrument to be achieved.

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OIL&GAS

5 oil & gas projects to watch in 2017 through Novorossiysk on the Caspian Sea. The Baku-Tbilisi-Ceyhan route has been proposed as an alternative, with another cheaper option being a southern Iranian route. At present, oil flows remain routed through Russia.

Leviathan gas field – Israel (Mediterranean Sea) • Cost: $4 billion •Timeframe: 2016-2019 (first gas production)

Here are five projects to monitor in 2017 and beyond.

substantially increase Nigeria’s oil revenues and production output.

Turkish Stream - Russia to Turkey

The Egina Field has been in development since December 2014, when the first deep sea drilling efforts began. Total will ship a Floating Production Storage Offloading (FPSO) vessel to Egina Field in April 2017 – and the first barrels of oil could be produced by the end of that year. Once production hits full tilt, Total expects peak capacity to be around 200,000 barrels per day. Total has been operating in Nigeria for over fifty years, setting record production levels in 2012 of 279,000 bpd. Egina alone could nearly double Total’s Nigerian output and could establish the French company as the region’s pre-eminent oil producer.

• Cost: $15.1 billion (estimated) • Timeframe: 2017 – 2019 (first phase) After years of development, followed by a period of political uncertainty, Russia and Turkey have finally re-agreed to push ahead with the Turkish Steam pipeline. The decision was reached at 2016’s World Energy Conference (WEC) in Istanbul. 909 kilometres of new pipeline will travel beneath the Black Sea, linked to 177 miles of onshore pipes, transporting gas from Russia via Turkey to Europe. The project, which has been in the planning stages since 2014, is expected to reach deliverability of 63 billion cubic metres of natural gas annually once operational.Gazprom expects total costs on the project to reach $15.1 billion.Alexi Miller, Gazprom’s chairman, stated the first phase of undersea pipe laying could be completed as early as 2019. Gazprom will be working alongside Turkey’s BOTAS to complete the project. BP’s CEO Bob Dudley, speaking at the WEC, also expressed his eagerness to get involved with the Turkish Stream, citing the pleasing results of BP’s involvement on another Turkish-involved project – TANAP, the Trans Anatolian Natural Gas Pipeline.

Egina Field development - Nigeria • Cost: $16 billion •Timeframe: 2014-2018 (first oil production) Oil has already provided a huge boost to Nigeria, propelling it to the status of Africa’s biggest economy. Total has been developing an ultra-deep offshore operation in the Egina oilfield, 130 km off Nigeria’s coast, in a development that could 31

Tengiz Field Expansion – Kazakhstan • Cost: $36.8 billion • Timeframe: 2017-2022 Chevron affiliate Tengizchevroil has stated it will begin expansion of its Tengiz Field operations in 2017, under the auspices of the firm’s Future Growth and Wellhead Pressure Management Project. Costs for the project, slated to start in 2017, could reach $36.8 billion.

Tengiz is already the world’s sixth largest oil field, with approximately 25 billion barrels originally in place at the site. In 2003, the site was responsible for one third of Kazakhstan’s daily production output.

Successive expansion initiatives, the last in 2008, have pushed daily production levels to over 500,000 barrels per day (bpd).

850,000 bpd is Chevron’s post-expansion goal. The first oil production is expected in 2022. The thorniest issue regarding the site, however, is the oil’s routing. Currently, oil from Tengiz Field is primarily routed

2010’s discovery of the Leviathan field, 130 kilometres of the coast off Israel, was one of the region’s most significant deep water finds of the decade. A US Geological Survey of the 83,000 square kilometre Leviathan basin revealed substantial reserves: 1.7 billion barrels of oil alongside 3.4 trillion cubic metres of recoverable natural gas. After four initial deep drilling operations halted at a maximum depth of 6,522 metres – and years of legal wrangling – the field saw production development begin in earnest in 2016. After a UN resolution, it was agreed that the field lay in Israel’s territories, which subsequently led to the large scale operations taking place across the site.

Shah Deniz gas field expansion – Azerbaijan • Cost: $28 billion •Timeframe: 2015-2018 (first gas production) Fitting Azerbaijan’s biggest natural gas field, BP’s Shah Deniz second phase expansion is one of the world’s largest current gas projects. The field itself holds around 100 billion cubic metres of gas, and has been producing since 2007. BP’s $28 billion project will add an additional 26 production wells, 500 kilometres of subsea pipelines and two bridge-linked offshore platforms.

Capacity is set for expansion to around 10.8 billion cubic metres per year, making this a vital project in terms of energy security for both Azerbaijan and Europe. Shah Deniz is part of an extensive network of pipelines, including the South Caucasus, Trans Anatolian and Trans Adriatic Pipelines. As of the first half of 2016, the project was 77% complete and remains on target for first gas production in 2018.

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OIL&GAS

Exploring best practices for ensuring gas pipeline integrity topographical and geological maps, satellite imagery, aerial photography, and surveys available in the public domain, all are suitable methods. In addition to natural disasters like landslides and earthquakes, soft soils like swamps and bogs as well as underground cavities like coal mines and caves should also be of concern.

In addition to thorough terrain assessment, implementing equipment that is correctly sized is crucial.

The pump or compressor must be sized correctly – a steady state pipeline simulation tool can validate the specified size of the pump or compressor through a computational model of the pipeline’s operating conditions.

Oil and Gas exploration continue all over the world and as more hydrocarbon sources are found the demand for pipelines to transport oil and gas increase. However, pipeline operators are under severe financial and social pressure to avoid incidents that cause crude oil and natural gas leaks.

With regulators scrutinizing pipeline projects, the reputation of the entire industry is at risk. This is why pipeline integrity must become the focus of discussion. „Pipeline integrity“ refers to a comprehensive program that works to ensure hazardous resources are not released from a pipeline while minimizing the impact in the event a release does occur.

Although some may think prevention methods have a one-size-fits-all solution, pipeline integrity encompasses a much broader definition and is comprised of three phases: - Prevention activities and solutions seek to avoid gas leaks from happening in the first place through proper design, construction, operation, maintenance, training, and education.

- Detection activities and solutions help pipeline operators quickly identify that a leak has happened.

- Mitigation activities and solutions minimize the extent or impact of the leak and the damage that results.

With leak prevention being of the utmost importance, the three phase process is understandable.

As with most catastrophes, the best defense is a proactive offense. The good 32

news is that the technology and tools needed to anticipate potential threats to pipelines and identify anomalies are available today.

The age-old expression, “an ounce of prevention is worth a pound of cure” holds true for pipeline integrity: the costs that come with preventing a leak are much less than the costs of cleanup, fines, and other civil liabilities – not to mention the cost of a company’s reputation.

The process and planning that goes into the prevention of gas leaks is a multi-tiered strategy that can be split into three categories: - Design and construction.

- Operation and maintenance.

- Training and education.

Pipeline integrity begins with design, and construction No two pipeline routes are the same, which is why gas leak prevention starts with specifying the technical requirements for each one. Advances in construction practices, such as more sophisticated testing prior to the pipeline’s fruition, and increasingly protective technology further safeguard pipelines vulnerability.

While it may seem like common sense to avoid areas that are susceptible to natural disasters and other geo-hazards, history has proven that one small mistake or lack of consideration of this detail plays a large hand in events that can lead to pipeline explosions.

Critical to pipeline integrity, the geography of the terrain surrounding the pipeline must be evaluated, whether it be by

This simulation can also ensure that it is hydraulically feasible for the pipeline as designed to cross the terrain.

Lastly, but certainly not least, surge suppression equipment must also be sized correctly. A transient pipeline simulation tool can model the pipeline hydraulics to determine the design criteria for the surge suppression equipment.

Surge effects like water hammer can severely damage a pipeline, thus causing hundreds of thousands of dollars in repair.

Operation and maintenance is imperative to pipeline integrity Beyond the construction of the equipment, a major component of pipeline integrity is implementing a proper operations and maintenance schedule. When a pipeline is in service, continuously monitoring the operational and structural conditions within the pipeline can identify circumstances that, if not mitigated, could lead to major problems.

Inspection and monitoring technologies provide pipeline operators with the information and resources they need to accurately assess the functionality of their pipeline and perform proactive maintenan ce on “at risk” areas.

Some of the more important aspects to monitor and inspect include: - Monitor operating pressure.

-Inspect the integrity of the pipeline externally.

-Inspect the integrity of the pipeline internally.

-Monitor depth of cover.

-Properly calibrate monitoring devices.

energyandecology.com

Issue 3 April 2017

OIL&GAS

Exploring best practices for ensuring gas pipeline integrity Monitor ground temperature and excavation activity Operating a pipeline is like flying a plane â&#x20AC;&#x201C; training should be required. Just like a pilot is in control of a flight, pipeline controllers are in charge of operating very expensive pipeline assets and should be required to have training or even certification. Teaching operators what to look for in a gas leak is an important step in prevention.

In addition to operators, education among residents living along the pipeline can also help avoid problems.

Operators and civilians alike can benefit from the various tools that are becoming increasingly available. Computer-based simulators can help improve operational safety and meet regulatory requirements.

Enabling the most realistic training experience is essential in making sure the pipeline controller is exposed to both normal operating conditions and abnormal operating conditions.

Detection is also part of Pipeline Integrity As mentioned earlier in this article, the activities and solutions associated with the detection of commodity releases is also an important part of Pipeline Integrity.

There are potentially many ways of detecting a pipeline leak, however in general these detection methodologies can broadly be divided in two approaches: External and Internal.

External-based gas pipeline leak detection has been a method since pipelines were first used to transport fluids of all types.

pipelines are the same and that the specific detection methodologies used for one pipeline may not be useful for another.

It involves surveying the external surroundings of the pipeline to detect any releases on the outside of the wall of the pipeline. External-based systems continue to rise in popularity due to their ability to detect even the smallest of leaks and locate gas leaks with a high degree of accuracy.

For example, a pipeline company operating pipelines in remote areas could rely solely on internal based systems, while a pipeline company operating pipelines in what is classified as High Consequence Areas (HCA) could have both external and internal-based systems installed for the same pipeline. All detection methodologies, whether external or internal, has pros and cons, and it is important to take into account a lot of factors prior to selecting the detection methodology, including length, elevation, HCA, environment, cost etc.

Internal-based gas pipeline leak detection systems look at conditions inside the pipeline to discover gas leaks, typically based on measurement readings at specific locations along the pipeline.

More commonly known as (CPM), this methodology has been around for only about 30 years and uses software that takes a variety of measurements available on the pipeline to establish what is happening within the pipeline.

Each pipeline is unique and requires a different combination of methodologies. Itâ&#x20AC;&#x2122;s important to remember that no two 33

Taking on the gas Pipeline Integrity challenge From a business standpoint, gas leaks can be incredibly costly. For example, the company could be out tens to hundreds of thousands of dollars in lost product if there is a moderate or even a minor leak. It may have little environmental impact, but it will

be costly if it goes undetected for a few days.

While gas Pipeline Integrity can seem daunting, it is not something to be feared if proper steps of precaution are taken.

Implementing a tiered methodology for Pipeline Integrity significantly improves a businessâ&#x20AC;&#x2122; chances of firstly preventing leaks from appearing in the first place, and secondly improves the probability of detecting leaks, while giving additional benefits in other types of gas applications, this paired with a high level of maintenance provides companies with peace of mind.

The main goal of pipeline prevention, detection and mitigation activities and solutions is to avoid detrimental leaks down the road for pipeline operators. By putting effort into the three tiers of pipeline integrity, operators will continue to reap the benefits of gas pipeline prevention, detection and mitigation technology in the future.

energyandecology.com

Issue 3 April 2017

OIL&GAS

Interview with Adriano Gentilucci, commercial director IMEA for Dow, oil, gas and mining treat the majority of the region’s liquid natural gas. Dow solvents are also used for the removal of H2S and CO2 in the Acid Gas Removal Unit (AGRU) and selective separation of CO2 and H2S in the Acid Gas Enrichment Unit (AGEU). Dow has a regional headquarters in Dubai and has significantly increased its investment in customer-facing local technical engineers throughout the region.

How has gas processing in the region evolved?

To coincide with SOGAT 2017, which is taking place from 26-30 March in Abu Dhabi, Adriano Gentilucci, commercial director – IMEA for Dow Oil, Gas and Mining, discusses how Dow is contributing to tackling the region’s gas treatment challenges.

What is Dow’s history and pedigree in gas treating solutions?

For over 65 years, Dow has led the way in gas treating. Today we offer one of the broadest and most in-depth portfolios of gas treatment products, services and technologies for natural gas applications in the world. Our UCARSOL™ solvents, specialty amines and specialised technologies – together with unsurpassed industry expertise – bring you the most advanced solutions available for gas treatment.

Dow’s core expertise in gas treating also lies in providing engineering consultancy services and simulation capabilities to engineering companies and oil and gas operators backed by over 1,000 references worldwide dealing with a wide ranges of gas compositions and process conditions.

What is Dow’s gas-treating “footprint” in the Middle East?

Abu Dhabi is actively investing in developing new gas fields, due to come onstream in the next few years. These fields contain some of the most sour (high sulfur content) gas in the world, meaning significant levels of H2S – a contaminant that must be removed from the gas before it goes to market. Dow is an expert in this area and we continue to work with leading engineering companies to design best-inclass facilities to treat this gas.

Incidentally, as a result of the high sulfur content recovered from the region’s natural gas, Abu Dhabi is fast becoming one of the world’s biggest markets for sulfur, especially as production from the Al Hosn sour gas project ramps up. This is significant given the high demand for sulfur as a raw material for the production of phosphate fertilizers for agricultural use.

We therefore anticipate continued increases in the sulfur content of the natural gas coming out of the ground in the region, as well as tightening environmental regulations. This adds to the complexity of gas processing, and the demand for more customised solutions to better treat sour gas. However, the recent advances in technology have rendered the highly sulfurous fields both safe and economically feasible for development.

What are the biggest challenges in sour gas treatment in the region?

The Middle East has some of the world’s most sour gas reserves. Gas treating here is primarily about removing sulfur, and Dow is an expert in this area. Dow has more than 50 gas treating references in the Middle East, including plants in Kuwait, Qatar, Oman, Saudi Arabia, and the UAE. Our Middle East references include the use of Dow UCARSOL™ and SELEXOL™ solvents in five world-scale LNG plants in Ras Laffan, Qatar.

We are seeing a significant increase in the concentration of sulfur in natural gas and refinery gas, along with an increase in efforts to improve air quality through reductions in sulfur dioxide emissions.

More sulfur in feed gas is driving a need to upgrade existing plants and design new plants to accommodate greater levels of H2S removal while optimising throughput and cost efficiency.

It is estimated that Dow solvents are used to

Moreover, we’re also seeing interest in generating more concentrated sulfur

34

streams from acid gas enrichment units.

Collectively, these factors are increasing the potential complexity and cost of sulfur removal.

One of the other main challenges facing sour gas processors in the Middle East t o d a y i s t h a t o f e ff i c i e n t a m i n e management. Amines, a chemical compound used to treat sour gas by removing harmful hydrogen sulphide (H2S) from the useable gas, works best in cool conditions, which means the added costs of thin fan coolers or chillers to the sweetening process. Dow’s amine technology works by allowing the amines to operate efficiently for H2S removal even at relatively high temperatures. This eliminates the cost for cooling the amines.

A relatively recent phenomenon we are witnessing is that a large number of mature gas plants require upgrades in order to fulfill evolving feed gas and gas treating specification objectives. Dow has the engineering capabilities to help in the retrofitting of these plants to match new specifications at minimum capex. This is achieved by deploying our process simulation tool to evaluate the extent of upgrade required and providing the optimal UCARSOLTM solvent needed.

Why are companies moving towards hybrid solvent in place of physical and chemical solvents?

An important trend in the Middle East is the tightening of regulations for controlling emissions that are in line with international standards. As a result, it is no longer sufficient to just remove H2S from natural gas to meet regulation, but the removal of other exotic contaminants for e.g. mercaptans. The removal of these requires a different approach and more specialised amine technology.

To address this need, Dow introduced hybrid solvents, a combination of chemical and physical solvents which are capable of removing organic sulfur compounds from natural gas streams, with reduced hydrocarbon uptake compared to physical solvents, while still reaching the customer’s stringent gas specifications on acid gas removal. These hybrid solvents can be applied at natural gas plants and refineries, and also be extended to other potential applications in the oil & gas industry.

Over the last few years, Dow has invested in further R&D efforts to develop an accurate simulator tool for hybrid solvents. energyandecology.com

Issue 3 April 2017

MINING

Making the company a global leader in the uranium market fundamental factors.

I would like to point out that the uranium market behaves as it does because of a variety of diverse problems; however the above stated features seem to be specific enough.

Your company has recently sold a share in the Australian project. Is it time to sell or temporarily freeze low-profit mines as a result of reduced demand for uranium?

Our major production base includes joint ventures in Kazakhstan where the mining cost is rather low, providing efficient operations of the company even at such low market prices.

We suspend the production or sell the assets at deposits where efficient operation in the current price situation is impossible because of low profitability.

This is the case with the USA today where we are forced to suspend production. It can be resumed once the uranium prices exceed 50 dollars.

Mr. Vasily Konstantinov, the President of Uranium One Group, speaks about the specific features of the uranium market, the challenges faced by the producers, and the connection of African elephants to uranium mining.

Mr. Konstantinov, do you think the uranium market will recover?

Let me first explain some reasons for the falling demand. The commissioning of nuclear plants in Japan turned out to be not as fast as predicted by the IAEA and anticipated by the market. The current uranium market is also under high pressure from secondary uranium sources.

Lower enrichment (SWU) prices have led to rather inexpensive and efficient uranium production using centrifuges. Uranium tailings (a waste by-product of uranium enrichment arising from fuel manufacturing â&#x20AC;&#x201C; ed.) are accumulated in large amounts.

Uranium from the tailings sites is now in demand; it is processed and used to produce reactor fuel, which increases the supply and reduces the market price of uranium.

We should also take into account the uranium stock created by consumers while awaiting development of the market and extensive commissioning of nuclear 36

generation facilities.

The unused uranium stock held by the Japanese consumers is particularly large.

This uranium is also coming onto the market, increasing the supply.

All these factors obviously put pressure on the demand, prevent a price increase, and finally make investments in new deposits unprofitable.

Now my answer to your question: the market will recover when there is a balance between the fuel demand of nuclear generation and the uranium supply to the market from different sources.

This is certain to happen because uranium production will decrease while no new deposits are being developed.

What are the specific features of the uranium business today? What are the main problems in this sector?

Uranium is a market product, and the market of today is rather depressed and volatile. Not only do large producers set the pace in the uranium market, but there is also a large group of traders whose profiteering with small amounts of uranium often pushes the spot market down, affecting even the producers' price.

This is one of the reasons for the excessive volatility of the market, apart from the

The situation in Australia was more pessimistic because of an even higher increase in the price threshold required to ensure effective use of the assets.

Therefore, we decided to sell the Australian Honeymoon, which enabled us to avoid the costs associated with suspending and maintaining the project as required by local regulatory authorities.

For the same reason, last year we parted with a portfolio of uranium assets in the USA that did not involve the ISL (in situ leaching â&#x20AC;&#x201C; ed.) mining method.

Currently, we intend to continue our work with cost-effective assets, maintaining and developing them, and to abandon inefficient ones.

But the depressed market means a good time for buying. Are you not planning to acquire new assets?

Indeed, the prices of shares in public companies today are not so high today because of the lower uranium prices.

However, a comprehensive analysis of such assets is required including an assessment of their development potential following recovery of the market, and of the advantages Rosatom would gain in purchasing them, such as sales growth, entry into new niches, and expansion of the customer base. Then a conclusion can be made as to the advisability of such transactions. energyandecology.com

Issue 3 April 2017

MINING

Making the company a global leader in the uranium market Are you experiencing any problems with debt financing? Does your company plan any borrowings in the current year and – if any – what are your objectives?

It all depends on the reasons for raising the funds. If we speak about debt servicing and further repayment, our financial restructu ring program is being implemented successfully.

As far as fund raising for new projects is concerned, I think that our project will be interesting and competitive both in payback and profitability as compared with other State Corporation projects, which means that we have every chance that Rosatom will find it effective and will allow the use of the investment resource.

doubled to 45 billion rubles.

elephants for ivory.

The main growth occurred as a result of increased commercial activities in foreign markets. The EBITDA also almost doubled in 2015 against 2014 to 18 billion rubles, and this enabled the operational efficiency of the company to be maintained at a high level.

A migration corridor used by the elephants travelling from the north of Africa to the south and back crosses the area of our operations.

It should be mentioned that today we have the best cost figures compared with global leaders in natural uranium production.

Due to joint efforts with Kazatomprom, the production cost last year was brought down below 12 dollars per pound of uranium compared with 14 dollars in 2014. The cost reduction program was launched for 5 years and we expect excellent results from its implementation.

We support a detachment of 20 scouts, helping them with equipment and training.

The young people patrol the territory of the national park on a regular basis.

As a result, they have helped to neutralize seven groups of poachers only last year.

What is the most interesting for you in your work?

Making the company a global leader in the uranium market. This is a challenging yet very interesting task. For this, we'll need total mobilization of the internal resources, the ability to find and take full advantage of new opportunities even under depressed market conditions.

Are you considering the possibility of extending your participation in non-core businesses for the purpose of diversification, for example, getting into the rare earth or precious metals market?

The mining output during recent years has been approximately at the same level of 4.8 thousand tons, taking into account our Kazakhstan JV shares. And the total mining output jointly with Kazatomprom is approximately twice as high.

Development of new businesses is one of the tasks set by ROSATOM together with revenue growth, broadening the portfolio, and cost saving. We cannot operate as a single product company, which for us today means uranium.

We operate under contractual obligations that limit the maximum and minimum production output. Nevertheless, we should focus on an output of about 6 thousand tons under a comprehensive program.

In this case, our dependence on market conditions is too great. Therefore, we should look to new mining and extraction businesses, and this is correct from the diversification standpoint. Such strategy will help us occupy new market niches and increase the company value.

What is the progress of the Mkuju River project involving the construction of a uranium mining enterprise in the south of Tanzania?

Uranium One Holding N.V. is ROSATOM’s global growth platform in the initial stages of the nuclear fuel cycle.

We are keeping the project running and are working with the relevant ministries of Tanzania, promoting an efficient and costeffective mining method, which is new to this country but conventional for us: in situ leaching. Pilot tests are being carried out to prove its viability.

The company’s portfolio contains uranium mining projects in Kazakhstan, the USA and Tanzania. Uranium One Holding is the major shareholder of Canadian Uranium One Inc., a uranium-producing company.

Uranium One Holding is owned by the Russian state-owned nuclear industry operator 'ROSATOM'.

Yes, today this is a really good time to enter into new businesses as metal prices have fallen and assets can be bought at affordable prices.

However, we should basically understand when the asset could “take off”, when the demand for this mineral resource will grow, the payback period, and the impact on the value of the company.

In spite of the problems and the depressed market, U1 closed 2015 with a twofold increase in revenue. Is further growth anticipated in the 2016 results?

2015 was not an easy year for our company and for many other ROSATOM enterprises.

Nevertheless, the year ended with positive results.

The net income of the company amounted to 6.7 billion rubles against 10.9 billion rubles net loss the previous year. The revenue in ruble equivalent more than 37

This technology will enable us to reduce the costs and when prices in the market rise to an acceptable level, start to develop this asset.

I can't help asking about the elephants. We know that Uranium One takes an active part in protection of nature, in particular, by rendering assistance to the Selous Game Reserve near Mkuju River.A part of the deposit is indeed located in the close vicinity of the Selous Game Reserve, one of the largest African nature reserves. At the request of the Tanzanian government, we joined their anti-poaching program aimed at saving the elephant population in the reserve. The number of these animals fell from 100 thousand in the 1970s to 13 thousand in 2013 because of their barbaric extermination by poachers killing the

The challenges in growing the revenue and broadening the portfolio of assets have to be met. Expressing this in figures means the company achieving a sales volume of 1.5 billion dollars. Our current consolidated revenues are 740 million dollars, which means that we have to double it. This is indeed an ambitious and interesting task!

About the company

The company’s key objectives are to maintain its status as one of the most competitive uranium producers in terms of cash costs, maximize Rosatom’s revenue from foreign operations in the initial stages of the nuclear fuel cycle, and provide raw material for ROSATOM’s large-scale program for building NPPs outside Russia.

Uranium One Holding is the continuation of the former first central board of the USSR’s Ministry of Medium Machine Building, which comprised the world’s largest group of uranium enterprises. Acting in the interests of the Russian nuclear industry, the company is currently actively exploring opportunities to scale up its business by diversifying its product spread.

energyandecology.com

Issue 3 April 2017

MINING

Coal and Bulgarian Power Sector

By Dr. Christo Christov - Executive director of the Energy Institute JSC well before the time at which significant deployment of new coal with Carbon Capture and Storage (CCS) can be expected.

The new draft for the Best Available Techniques (BAT) reference document to the Industrial Emissions Directive (IED) proposed by the European Commission, and largely endorsed by the European Parliament, sought to tighten further the emission SOx and Mercury limit values for LCP. This would certainly force further power station closures, and raises serious security of supply concerns in Bulgaria and in several other Central and Eastern Europe Countries (CEEC).

The European Union (EU) average electricity generation from coal and lignite is around 30%, whereas some countries are significantly more reliant, from 40% in Germany to 90% in Poland.

Bulgaria Power sector now relays mainly on local coal (low grade lignite) - about 47% share of the generated electricity. Lignite accounts for 95.2% of the coal mined in the country and 97% of it is used for electricity production.

The share of the imported coal in the electricity generation is almost negligible due to the early closure of the hard coal fired TPP Varna (1260 MWe – tenth part of the total installed capacity of the country) as it was not economically feasible to achieve the Large Combustion Plants (LCP) Directive new NOx emission norms.

Provisions of the LCP Directive already mean that many EU power stations should have been closed before 2016 and others must have already met tighter standards from the same date.

It is not clear if this has happen, and at the same time the debate on LCP rages about how to regulate the new coal stations, how to finance carbon capture and storage (CCS) and how the existing stations have to meet ever more stringent requirements in terms of traditional pollutants such as SOx, NOx and particulate emissions.

The Czech Presidency of the EU was keen to broker a compromise deal at the end of its term but the initiative to maintain the existing LCP Directive flexibilities until 2023 failed. The approved compromise date of 2020 gives a medium-term stay of the execution for coal plants, but this date is 38

The full implications of this Council Decision would have major impacts for power station operators and coal suppliers in Europe. The investments required to stay within IED limits beyond 2020 will be difficult, if not impossible, to justify.

A number of key questions and issues arise for companies and investors involved in coal-fired generation and across the coal supply chain: · What is the future for the suppliers of high SOx coals? · Are there low-cost technical solutions available for power stations to meet the new standards? · How do these regulations impact the risk/reward balance for investing in coal or coal-fired power?

Energy costs, and particularly the forthcoming increase of the electricity prices, are important political question for the CEEC. Bulgaria Governmental policies aim at mitigation of the burden of the increasing prices on the final consumers that does not allow transfer the significantly increasing costs to the households. An average Bulgarian household spends for energy forms 14% of the income.

The poorest 20% strata of the households spend for energy 17.4% of its income while the richest 20% strata spend 11.9%.

Electricity is the main energy source for the majority of the households.

Those households spending on electricity purchase more than 10% of the income are considered vulnerable. About 440 000 most vulnerable households are available in the country.

These are the households allocated in the 25% strata of low income households that spend on energy more than 10% of their budget.

electricity price for households is low – below 10 eurocents per kWh. The forthcoming market liberalization is expected to result in about 20-30% increase of the prices for the households.

Obviously large number of the consumers is not in position to meet any further additional increase of the electricity price that may follow the introduction of the new pollution norms. Investments in meeting these norms by the existing coal fired plants are not feasible mainly due to the resulting increase of the electricity price for the final consumers.

The possible closure of the plans due to the new pollution norms would reduce the base generation capacity of the country on at least 3.5 GW (30%). This very early termination of the operation of the coal fired power plants would result in practical termination of the lignite mining, create electricity shortage and social problems for about 7 000 employees that now are directly involved in lignite mining and most probably for about 20 000 employees engaged in the power sector and related supporting activities.

The tighter emission standards that are pushed by the new draft BAT reference document need to be considered in conjunction with the Paris Agreement on Climate Change that was adopted in December 2015 introducing the 2°C target, maximum increase in the average temperature.

The scientists' common understanding is that by 2050 the world's GHG emissions need to be reduced on 50% relative to the 1990 level to achieve the 2°C target.

The reported in Paris EU Initial Nationally Determined Contribution (INDC) sets GHG emission reduction target of 40% till 2030 and possibly 80% till 2050 relative to 1990.

The Paris agreement may be seen in the context of the EU leading the way towards a smarter and cleaner energy for all, to fuel economic growth, spur investment and technological leadership, create new employment opportunities and enhance citizen's welfare.

Analytics had calculated that the EU will exceed its INDC on the Paris Agreement if existing coal fired power plants continue operating to their full lifespan. The EU will need to phase out CO2 emissions from EU's more than 300 coal power plants in the next 15 years to meet the Paris Agreement's long-term temperature goals.

This is the situation now, when the average energyandecology.com

Issue 3 April 2017

MINING

If the 2°C target is to be achieved, the world's GHG emissions need to rich the peak as soon as possible, meaning coal combustion for power generation will need to start gradually decrease and eventually disappear in that time. The other option is to emit less or become almost free of GHG emissions altogether, for example using CCS. The former is somewhat challenging, as the latter would be possible if wide-scale and fast adoption and installation of CCS occurred before 2035. Certain scientists consider that the cheapest way for the EU to make the emissions cuts required to meet its Paris Agreement commitment is to phase out coal from the electricity sector.

The biggest challenges for Europe will be the phase-out of coal fired power emissions by 2030 - 2035. For any country, in any region, and at any time this would be a major challenge, both economically and politically, but for the CEEC, including Bulgaria, this obviously shall be hardly achievable target. Compromise timelines and significant support shall be necessary for these countries.The required (due to climate change reasons) early closure of the EU coal fired electricity generation rises doubt if the introduction of new pollution norms, planned by the revision of the BAT reference document will be useful and feasible. The industry will need a transition period of least 5 – 10 years to gradually put in operation new pollution control installations at the power plants. The effect on the pollution reduction will come somewhere in 2025 – 2030. Starting from 2030 the industry will be urged to phase out these just refurbished power plants due to climate reasons. Obviously there will not be long enough operation span to get the payback for the investment costs.

Furthermore, the needed investments in pollution control will create shortage of investments in the introduction of carbon free clean energy solutions like energy efficiency, CCS, renewables or nuclear.

The UK referendum decision to leave the EU has created significant additional uncertainty for the EU energy sectors. The UK's departure from the EU places greater pressure on the remaining 27 EU Member States to meet the 2030 GHG emission reduction, renewable and energy efficiency targets. However, the EU already has many of the key policy instruments in place, including those required for fair and just transition strategies. The European Union Emissions Trading Scheme (EU ETS) is the key one.

Phase IV of the EU ETS will cover the period from 2021 to 2030. As expected the proposal ensures the EU ETS will achieve a 43% reduction in emissions from sectors covered under the scheme compared to 2005 emissions. This contributes to the EU 39

emissions reduction target of at least 40% by 2030 compared to 1990 emissions. The share of allowances to be auctioned over Phase IV remains at 57% with member states urged to use auction proceeds to help the transition to a low carbon economy, however, no binding rules on the use of revenues are in place and offset use will not be permitted. Several support mechanisms will be established to help the industry and power sectors meet the innovation and investment challenges of the transition to a low-carbon economy. The main two are the Innovation and Modernization funds.

The Innovation Fund aims to extend the existing support for the demonstration of innovative technologies to breakthrough innovation in industry such as CCS. The Modernization Fund will facilitate investments in modernizing the power sector and wider energy systems and boosting energy efficiency in 10 lowerincome EU Member States.

Under the UNFCCC, the EU and its Member States have taken a joint emission reduction target. No individual quantified economy-wide reduction target is set for Bulgaria as this reduction target will be fulfilled jointly by the EU and its Member States. The EU quantified economy-wide emission reduction target is implemented through the EU Climate and Energy Package. The package introduced a clear approach to achieving the required reduction of total GHG emissions from 1990 levels.

The reduction objective is divided between the European Union Emission Trading Scheme (EU ETS) and the Effort Sharing Decision (ESD) sectors - 43 % reduction target compared to 2005 for emissions covered by the ETS and the rest reduction is placed on the ESD sectors and shared between the 27 Member States (MS) through individual national GHG targets. In this way the ESD sets binding annual greenhouse gas emission targets for each Member State. The targets are distributed according to the principle of “solidarity” in a |”fair and equitable” way allowing for further, accelerated growth in less wealthy countries where economic development still needs to catch up with other Member States.

The EU-wide cap imposed on the EU ETS is determined for all EU Member States and the three non-EU countries (Iceland, Norway and Liechtenstein) without reflecting a specific share for each Member State.

national emissions have decreased by 54 % compared to the country base year (1988) and the energy sector emissions have decreased by 50%. The country has experienced tramendous decrease of the industrial and energy related activities in 1990-ties, during the transition from centrally planned to market economy.

Nevertheless Bulgaria will be assigned further emission reduction target, and, most probably, by 2030 it will achieve further emission reductions, and will significantly over fulfill the EU 40% GHG reduction target. If the coal fired power plants are to be closed, the national GHG emission reduction (together with the industrial and agricultural activities decrease) may reach tremendous decrease for the second time in 40 years.

Obviously the EU policy towards part of the countries in transition (CEEC) need to be rearranged and the coal plants activities reduction and closure delayed until appropriate decisions how to keep the upward trend of the economy, and to enhance citizen's welfare are found.

Compromise timelines and significant support shall be necessary for these countries.

The introduction of new pollution norms that are planned by the revision of the BAT reference document will be not useful as the needed investments in pollution control may create shortage of investments for the introduction of carbon free clean energy solutions like energy efficiency, CCS, renewables or nuclear.

Dr. Christo Christov - Executive director of the Energy Institute JSC. The company works in the field of approximation of Bulgaria energy and environmental legislation to the EU legislation, restructuring and deregulation of the energy sector, energy and environmental policy analysis and energy planning, develops greenhouse gas mitigation policy and measures and energy efficiency, nuclear and thermal energy, co-generation, power transmission and distribution, district heating and environment protection projects and performs environmental impact assessment, and emissions projections.

Bulgaria aggregated GHG emissions recently totaled at about 56 million ton CO2e. The coal fired power plants are emitting about 30 million ton CO2 now. The energyandecology.com

Issue 3 April 2017

MINING

Dust Suppression Overview Heavy duty dewatering pumps DWK benefits: ¡ High reliability and flexibility pumps with protection features for harsh operation environments ¡ Top-discharge with different connection types available for multiply uses of the pumps, depending on conditions and specific needs ¡ Pumps up to 15 kW have a double mechanical seal and pump from 22 kW to 90 kW have a triple-seal system, for longer operation and less downtime The working range of DWK pumps is up to 430 m3/h flow rate maximum and up to maximum 89 m pressure head maximum.

Dust suppression is an important aspect of mining operations, and to reduce the volume of raw water required, recycled process water from settlement tanks is often used for this purpose. The creation of dust is an unavoidable result of mining operations and can clog pipes and mechanical parts, creating additional maintenance and repairs.

Water spray systems remain the most efficient and cost-effective means of dust control for both process and fugitive dust emissions. A Grundfos pumping solution can move a large amount of water in a short time, making it possible to use a large nozzle configuration and minimise the need for filtration.

Settlement ponds are a cost-effective way of reducing the size and cost of subsequent water treatment by reducing the organic load in the wastewater, by letting gravity remove impurities. The resulting water can be filtered and treated for reuse in the mineral process, or for dust suppression.

Our range of submersible multistage pumps (SP) along with variable speed drives (CUE) is unmatched for well types. State-of-the-art hydraulic design delivers optimum energy efficiency during periods of high demand with high reliability, very long service intervals and low total cost of ownership. Using of variable speed drive ensures more balanced water drawdown, protecting the water source. Grundfos matches the stainless steel build quality of the SP pumps to the groundwater conditions. Depending of the corrosion risk, high grade stainless steel variants are available. Grundfos is a supplier of the pump, motor and controls for an optimal pumping system.

The working range of SP pumps is up to 470 m3/h flow rate maximum and up to 670 m pressure head maximum.

Correct material selection is the most important method of corrosion prevention, prolonging the life span of pumps and pumps systems.

Grundfos can supply the specialist expertise to help meet your performance objectives, from the initial identification of needs, to the selection, installation, operation, and maintenance of the pumping solution. Furthermore, Grundfos tailors commissioning agreements and service agreements to your requirements, and spare parts kits and on-site recommended spare parts can also be arranged.

The Grundfos Hydro MPC range of multistage pressure boosting systems means you can manage your pressure zones with ease for the optimum transporting of water from settlement tanks, for the filling of tanks, and for delivering water to water spray systems. As standard, Hydro MPC booster systems consist of two to six CRI(E) or CR(E) pumps coupled in parallel and mounted on a common base frame with all the necessary fittings and a control cabinet. The working range of Hydro MPC boosting system is up to 720 m3/h flow rate maximum and up to 160 m pressure head maximum.

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energyandecology.com

Issue 3 April 2017

MINING

Ecuador anticipates $4 billion in mining investments by 2021 Newcrest (ASX:NCM), are already setting foot in the country.

From those requests, 160 has already been granted and the minister says it has secured more than $100 million in investment to explore those gold, copper, silver and molybdenum-rich areas.

Currently, Ecuador’s mining sector employs 3,700 people, a figure that is estimated to rise to about 16,000 for the period 20172020.The nation also expects mining investments to increase 360% in the next four years compared to the period 20132016, totalling more than $4 billion.

The most important of those projects, Córdova acknowledges, continues to be Fruta del Norte, now property of Lundin Gold (TSX:LUG), which the firm acquired it in 2015 and late last year reached a key agreement with authorities that includes an investment protection contract.

Ecuador is quickly gaining ground as a mining investment destination in Latin America thanks to a revised regulatory framework and a major investor engagement campaign that has already attracted around 420 applications for concessions in less than a year.

implemented changes. One of the most crucial ones was the standardization of the unpopular windfall profits tax, a 70% levy on excess profits, the terms of which — such as what constitutes excess profits — had previously been subject to negotiation between company and government.

Getting to this point, however, has not been easy for a nation that has traditionally based its economy on oil, bananas, cacao and coffee exports, but that it is rather foreign to mining, admits the country’s mining minister Javier Córdova.

That levy is no longer based on a prenegotiated base price on a project-byproject basis, but on the average commodity price for the past decade, Córdova explains. It also doesn’t apply once a mine begins production, but four years after a company has recovered its full capital investment.

Speaking to MINING.com on the sidelines of the Prospectors and Developers Association of Canada (PDAC) conference, held in Toronto this week, Córdova says one of the main mistakes Ecuador made in the past was to apply legislation designed for the oil sector to miners, which just didn’t work.

But what really triggered the recent overhaul of the country’s mining regulations was the exit of Canada’s Kinross Gold (TSX:K) (NYSE:KGC) from Ecuador in 2013, after failing to reach an agreement with authorities over the terms for developing its Fruta del Norte project, one of Latin America's biggest undeveloped gold deposits.

Shortly before that, IAMGOLD, another Canadian miner as well as International Minerals had both sold their projects and left the Andean nation.The government then hired consultants Wood Mackenzie to provide recommendations and swiftly 41

Now Ecuador’s net tax take is in line with other countries in the region. “We aren’t as cheap as Chile, but we are not the most expensive either,” Córdova says. What’s more, the minister believes such unpopular tax will likely be eliminated way before any of the current projects has to start paying it.

From promise to reality Another measure recently taken by Ecuador was the creation of a mining ministry. Before 2015, the oil and gas ministry regulated the activity and, as such, quite neglected, the minister says.

Córdova also notes that when his country came to PDAC for the first time, two years ago, it brought just promises. Last year, it was able to present some concrete progress and now it can show that some of the main global mining players, including Fortescue Metals (ASX:FMG) and

The asset, discovered in 2006, is expected to generate 340,000 ounces of gold a year during its mine life. First production is expected in the first quarter of 2020, with full operations beginning in 2021.

There also are other projects worth keeping an eye on it, two of which are being developed by Chinese companies — the large-scale Mirador copper mine, controlled by the CRRC-Tongguan consortium, and Río Blanco, also a copper project now operated by Junefield Mineral Resources.

Growing pains But with success also come growing pains, Córdova admits, such as conflicts with local communities.

In that respect, the minister thinks is "regrettable and irresponsible" as well as “illegal and against the constitution” the decision of the city of Cuenca to ban mining in the municipality.

"What is happening in Cuenca is purely political and related to the upcoming elections,” he notes. “I’m sure that after the elections many of these conflicts will wean off.”

Asked about the potential effects of the upcoming presidential elections in the country’s growing mining sector, Córdova says that given the industry’s relevance to the country’s economy, he does not anticipate major changes in terms of policies.

energyandecology.com

Issue 3 April 2017

MINING

Secret of the Kibali Mine: Flying People In and Gold Bars Out Other miners have been less successful in Congo. Randgold’s partner, AngloGold, suspended operations in 2013 at the Mongbwalu project, also in northeastern Congo, saying that it couldn’t make the economics of the project work. In the past decade, mining majors Rio Tinto Group, BHP Billiton Plc, Vale SA and De Beers have all held and abandoned mining licenses in Congo for different minerals without making headway.

Doing Business Congo was ranked 184th out of 190 countries on the World Bank’s ease-ofdoing business survey in 2016, but Randgold was able to bring Kibali from feasibility in 2010 to first gold less than four years later.

Randgold Resources Ltd. had to haul heavy equipment more than 1,000 miles to build the roads and hydropower plants needed to construct its Kibali gold mine, the biggest in Democratic Republic of Congo.

The sprawling facility in a remote corner of a country the size of Western Europe is a high-tech operation. In one tunnel deep underground, a $1.3 million, 68-metric-ton remote-controlled digger heaves ore out of a cavernous blast hole. The ventilation system hums as 50-ton loads are slowly humped along the 3-kilometer (2-mile) track back to the surface.

The best-performing gold miner of the past decade, Randgold has built its success on getting complicated projects like Kibali into production on time and within budget. It’s the third major mine the company has brought on stream in five years, and it has indeed been a gold mine: It accounts for about a fifth of the company’s production, which tripled between 2010 and 2015 as revenue doubled to more than $1 billion.

Now, with Kibali nearing full production and no new discoveries since 2011, the miner needs to find guaranteed output growth to impress investors wary of the shrinking pool of large-scale deposits.

Dinner Plates The key to making Kibali work: The company and its partners built everything in sight, including housing for more than 4,000 resettled families and an international airport where personnel fly in and gold bars fly out. At the high point of construction, Kibali received as many as 400 40-foot containers a week across the border from Uganda.

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Everything from the plates and cutlery in the large canteen to a plant that processes as much as 7 million tons of ore a year has been driven in across more than 1,120 miles of road from either Mombasa, Kenya, or Dar es Salaam, Tanzania. Three hydropower projects will ultimately provide 42 megawatts of electricity to the mine.

One of the company’s new mines will be in Senegal, according to Randgold CEO Mark Bristow, who has promised the company, which is also exploring in Ivory Coast, will define three new projects in the next five years. Another may be in Congo, in an area next to Kibali: The Moku-Beverendi gold project, a joint venture with Moku Goldmines AG controlled by Israeli billionaire Dan Gertler.

We are looking for “world class 10-plusmillion-ounce deposits,” Bristow said in Cape Town in February. “We think Moku has that potential.”

Four Ventures Moku is one of four joint ventures Randgold has signed in Congo in the past 18 months as it looks to replicate Kibali’s success.A partnership between Randgold, AngloGold Ashanti Ltd. and state-owned Sokimo, Kibali shipped 642,720 ounces of gold worth more than $700 million in 2015.

That helped increase production of the precious metal in the country from almost nothing in 2011 to more than 25 tons a year.

Production last year fell to 585,946 ounces after technical challenges in the first six months, but output is scheduled to peak at 750,000 ounces in 2018 as the underground operation reaches full capacity, Randgold says.

Randgold began due diligence on Kibali in 2006, months after historic elections brought a final conclusion to a violent civil war that left millions of Congolese dead. It acquired the asset in 2009 through a purchase of Moto Goldmines Ltd. “Before Moto every major gold company in the world had this asset and did nothing,” Willem Jacobs, chief operating officer for central and east Africa, said at the site in November. “It is very hard for big companies to do what we have done here.”

Negotiation Possible A new project would benefit from the infrastructure Randgold has built and the lessons the company has learned since 2009, making it easier to replicate Kibali’s success, Jacobs said. "Every country has its own challenges, but the Congolese government is enormously commercial," he said of the complicated operating environment that many miners have failed to overcome. "You can always talk, you can always negotiate."

Gold prices hit $1,257 on Feb. 27, well below a record high of $1,921.17 an ounce in 2011. Randgold, which says all of its mines make a profit at a price of $1,000, has avoided the worst of the slump so far: It has returned more than 500 percent to shareholders in the past decade. That’s more than double the second-best performer on the Bloomberg senior gold miner index and one of only six out of the 16 biggest gold members to have given shareholders positive returns over the period. Competitors AngloGold Ashanti, Barrick Gold Corp., Newmont Mining Corp. and Kinross Gold Corp. have all lost money for shareholders.

energyandecology.com

Issue 3 April 2017

MINING

World's First Deep-Sea Mining Venture Set to Launch in 2019 Lowrey worries that the plume of seafloor sediment stirred up by the mining robots could travel with sea currents, disturbing ocean ecosystems.

Sediment clouds could prove harmful to filter-feeders, environmentalists argue, undercutting the lower rungs of the food chain and potentially causing knock-on effects for other creatures.

"There's a serious concern that the toxicity from disturbing the deep sea can move up the food chain to the local communities," who live along the coast of Papua New Guinea, she said.

Johnston of Nautilus said his company is taking the sediment plume issue seriously, and that the company's machines are designed to minimize the undersea cloud through the collection procedure itself.

The world's first deep-sea mining operation will kick off in early 2019 when a Canadian firm, Nautilus Minerals Inc., lowers a trio of massive remote-controlled mining robots to the floor of the Bismarck Sea off the coast of Papua New Guinea in pursuit of rich copper and gold reserves.

The machines, each the size of a small house, are equipped with rock-crushing teeth resembling the large incisors of a dinosaur. The robots will lumber across the ocean floor on mammoth treads, grinding and chewing the encrusted seabed, sending plumes of sediment into the surrounding waters and killing marine life that gets in their way. The smallest of the robots weighs 200 tons.

If Nautilus succeeds, an undersea gold rush could be at hand.

Over two-dozen contracts have already been granted to explore hundreds of thousands of square miles of ocean floor by a United Nations body called the International Seabed Authority (ISA), which regulates areas of the seafloor that lie outside of any national jurisdiction.Analysts warn that population growth and a transition to low-carbon economies will test global supply constraints for minerals. Indeed, current levels of mining exploration are not keeping pace with future demand. The prospect of mineral demand outstripping supply has led an increasing number of firms to consider operations at the bottom of the ocean, where reserves of copper, nickel, and cobalt are thought to be plentiful, along with lesser amounts of gold and platinum.

thousands of years' supply of minerals in the seabed," Secretary-General Lodge said. "There is just absolutely no shortage."

Nautilus says early tests show their Bismark Sea site, called Solwara-1, is over 10-times as rich in copper as comparable land-based mines, with a copper grade above 7 percent versus an average 0.6 percent grade on land.

The site also boasts over 20 grams per ton of gold, versus an average grade of 6 grams per ton on land.

Many of the world's best options for surface mining have long since been explored and developed, according to Thomas Graedel, an industrial ecologist at Yale University.

Indeed, mining the ocean floor has been under consideration for decades, but seen as a remote possibility.

In one famous case in 1974, the CIA used a fake ocean floor mining expedition, ostensibly backed by the eccentric billionaire Howard Hughes, as cover for an attempt to hoist a sunken Soviet submarine off the coast of Hawaii.

But now, the practice is shifting from fantasy to reality â&#x20AC;&#x201D; a fact that is causing alarm among environmental groups who argue that not enough research has been done to prove seabed mining is ecologically sound.

"There are too many unknowns for this industry to go ahead," said Natalie Lowrey of the Australia-based Deep Sea Mining Campaign, which is calling for the practice to be banned. "We've already desecrated a lot of our lands. We don't need to be doing that in the deep sea."

"When we're cutting, we have suction turned on," he said. "It's not like we're blowing stuff all over the place. We're actually sucking it up. So the plume gets minimized through the mining process."

At Solwara-1, Nautilus is going after a type of deposit known as Seafloor Massive Sulfides (SMS), which form next to subsea hydrothermal vents at the margins of tectonic plates.

The deposits, which include copper, gold, and potentially other valuable minerals, collect after cold water seeps into the earth and becomes geothermally heated, dissolving metals and sulfides from the surrounding rocks before being spewed back out of the vent at temperatures up to 400 degrees Celsius and collecting on the sea floor â&#x20AC;&#x201D; along with the minerals brought up from below.

The mining robots have been designed to operate in near-freezing temperatures, under pressure 150 times greater than at sea level.

The first robot, the auxiliary cutter, carves a level path to make way for the second machine, the bulk cutter, which is equipped with a wide, powerful cutting drum.

The third robot, called the collecting machine, follows behind them, slurping up the seawater slurry with a consistency like wet cement through internal pumps before sending the material to the ship at the surface via a riser system. On the ship, the water is filtered, and solids larger than eight microns are removed, before being returned back into the ocean. The cargo is then transferred to a transport vessel and sent directly to customers in China.

â&#x20AC;&#x17E;It's no exaggeration to say that there are 43

energyandecology.com

Issue 3 April 2017