Energy and ecology Magazine

May 2017 issue 4

Key electricity trends What is the future of coal power in Europe?

Top 10 copper mining companies in 2016

ROSATOM in the Artic Alexey Likhachev, Chief Executive OfďŹ cer, ROSATOM

contents ENERGY 4 | Energy Financing Group – Import, export and trade of electricity 5 | RPC Radiy – The road to success 9 | The top 3 states for business model reform and utility grid modernization 10 | ISCAR Drilling for Profit with SUMO3CHAM 11 | Is rooftop solar just a toy for the wealthy?

13 | Can group purchases help scale renewable power?

14 | Key electricity trends

OIL&GAS

ECOLOGY 18 | Residues reaching end of life cycle better development policy than burning high grade biomass fuel 20 | Salt, silicon or graphite: energy storage goes beyond lithium ion batteries 21| Hazelwood's closure shows industry and government must plan ahead for climate change 22 | The end of coal: EU energy companies pledge no new plants from 2020 23 | New Eco Park designs unveiled at business breakfast 23 | Low-cost 'solar absorber' promising for future power plants

MINING

25 | Rosneft starts drilling northernmost Russian Arctic well

35 | Top 10 copper mining companies in 2016

26 | Persian Gulf Star Refinery, Iran's Major Step for Self-Reliance in Gasoline Production

36 | Mined into extinction: is the world running out of critical minerals?

27 | Israel signs pipeline deal in push to export gas to Europe

37 | Look at the evolution of mining apps with MiPlan

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

38 | Dust Suppression Overview

32 | Gas in Europe

39 | Scoping Australia’s mines with the latest drone technology

33 | Azerbaijan To Provide Georgia With Alternative to Russian Gas In 2017

40 | What is the future of coal power in Europe?

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Alexei Likhachov, Rosatom CEO

Lukas Schirnhofer, CEO of Polytechnik energyandecology.com

Issue 4 May 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 4 May 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 4 May 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 4 May 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 4 May 2017

Energy

Rosatom in the Arctic Rosatom CEO Alexei Likhachov speaks about Rosatom’s plans for mining operations on Novaya Zemlya, icebreakers of the future and energy security of the Arctic region.

Rosatom was represented by more than one group company at the International Arctic Forum. What are your basic lines of business in the Arctic?

The Arctic is a region with a vast, yet untapped potential. First, it is rich in natural resources, but their development per se can deliver a huge boost to the national economy. Second, it is the Northern Sea Route offering expansion of Russia’s transit capacity. It holds much promise both for the national economy and Russia’s position on the international market. Third, it is about national defense and security. Rosatom is present in each of these areas and therefore takes much interest in this forum.

Which of the areas you have mentioned is of the highest priority for Rosatom in the Arctic?

They all are of equal importance for us; we have projects and boast achievements in each of them. Our flagship project is the Northern Sea Route. Rosatomflot [Russia’s nuclear fleet operator] gains momentum and will not lose it because year-round navigation on the Northern Sea Route is impossible without nuclear icebreakers. As for Russia’s largest Pavlovskoye deposit of lead-zinc ores, the project has more than regional or even national importance. It has great potential and excellent prospects.

What does it mean that the Pavlovskoye deposit on Novaya Zemlya ‘has more than regional or even national importance’?

A specific feature of the Arctic is that development of the Pavlovskoye deposit goes far beyond ore mining or processing. It will entail development of the archipelago, construction of a sea port infrastructure on the Yuzhny Island, inclusion of the new port 8

into the Northern Sea Route, and new contracts for companies in the Arkhangelsk Region. In fact, the deposit becomes a local economic hub that will bring in more taxes on the municipal and regional levels, create new jobs and open up new prospects of the regional development. Proven lead and zinc reserves measure around 50 million tons. We think that, following detailed exploration, this figure is likely to double.

Ores from the deposit also contain silver.

These reserves are sufficient for 30–35 years of production at the Pavlovskoye deposit. I think, though, that the economic life of the deposit will be twice as long if we take into account total mineral resources available on Novaya Zemlya. Our key interest is zinc as it is used in many of Rosatom’s technologies and products. For example, zinc is used to increase the service life of primary loop piping and in high-precision medical equipment. It is also in demand in metallurgy. After the deposit reaches its designed capacity, we expect it to yield annually up to 65,000–70,000 tons of zinc concentrate. I believe that this total amount will find a buyer on the Russian market. I should also add that zinc is one of a few metals growing in price. It means the project has good economic prospects. By contrast, lead and lead concentrate are planned to be exported.

We have already reached a preliminary agreement with China’s largest state-run steel manufacturing company and Sweden’s Boliden. Boliden has expressed its preliminary consent to being our partner in the lead concentrate processing and distribution on the European market.

At present, Rosatom is building three new icebreakers. Will they be enough to support major Arctic projects to be commissioned soon and deliver the company’s strategy for the Northern Sea Route?

Does Rosatom consider placing orders for the fourth and fifth icebreakers?

It is true that the icebreakers in operation – Vaygach, Yamal and Taymyr – will be decommissioned in the mid-term. We will take steps to extend their service life, but they will be nevertheless taken out of service in the 2020s. The 50 Let Pobedy nuclear icebreaker and the Sevmorput nuclear lighter will not be decommissioned.

At present, the Baltic Shipyard is constructing a new line of nuclear icebreakers – Arktika, Sibir and Ural – to replace those in operation. We expect them to be accepted in 2019, 2020 and 2021

respectively. We look forward to receiving these icebreakers and hope that the shipbuilders will not let us down. This is our tomorrow, but we are already thinking about the day after tomorrow and have designed the next-generation nuclear icebreaker Lider (Leader). With a capacity of 110 MW, it is almost twice as powerful as the current generation and three times wider, thus being capable of escorting bigger vessels. I believe that further expansion of the icebreaker fleet should be based on more powerful vessels like Leader. It makes no sense to build one flagship vessel with no plans to build more, and we will need to construct three to five icebreakers of the new generation. In any way, we now have to make a decision about when to lay the keel of Leader.

How much cargo did the nuclear fleet escort through the Northern Sea Route in 2016? What is your forecast for 2017 and for the medium term till 2025?

In 2015, Rosatom’s nuclear fleet escorted 195 vessels with a total capacity of 2 million tons. In 2016, the number rose to 410 vessels that carried 5.3 million tons of cargo. The year on year growth is more than twofold, and I expect it to continue into 2017 since we already have relevant contracts.

We will see how it goes, though. We also believe that the freight traffic on the Northern Sea Route will reach 30 or even 35 million tons in 3–5 years. The best proof is that Novatek’s Yamal LNG and Gazprom Neft’s Novoportovskoye oil field projects already use it.

Being in Arkhangelsk, it is reasonable to ask about Rosatom’s approach to organizing power supply in the Arctic region.

Rosatom builds many power plants both in and outside Russia. However, technologies we use in nuclear power plants are too powerful for the Arctic. For instance, our flagship project Novovoronezh II Unit 1 launched in March has a capacity of 1,200 MW. We realize that projects with a capacity of over 1,000 MW are hardly suitable for the Arctic.

Once implemented in the Russian Arctic, this project may well become exportable.

But we should first try it in action in Russia before bringing it to the global market. We also have power plant designs with even lower capacities of 5–6 MW or 20–30 MW. These are movable – and even underwater – power plants to be used at offshore fields.

energyandecology.com

Issue 4 May2017

Energy

The top 3 states for business model reform and utility grid modernization The DRP proceeding guides California’s three investor-owned utilities in finding opportunities to site, value and integrate renewable energy. Throughout the process, utilities will continue to delineate their roles and business opportunities on the distribution grid, likely setting precedents for other states to follow suit.

The IDER proceeding, on the other hand, directs utilities to manage DERs on the grid through demand-side management. Other proceedings bolstering these dockets include rate reform efforts, a DER incentive proposal and numerous filings for electric vehicles, energy storage and distributed energy resource management (DERMS).

And the Chairman of the California Public Utilities Commission Michael Picker recently released his Action Plan summarizing the complex tangle of proceedings neatly into seven pages.

New York New York’s Reforming the Energy Vision captured the nation’s imagination three years ago. An ambitious undertaking, regulators sought to remake the utility business model to incentivize deployment of DERs and demand management as an alternative to traditional infrastructure. To make this goal palatable to utilities—used to collecting a hefty rate of return on massive infrastructure projects—regulators are devising a framework allowing them to earn a rate of return tied to investing in DERs and achieving societal and energy goals.

Eventually, regulators envision the new performance incentives and market-based earnings to facilitate the development of distribution system-level electricity markets — often referred to as transactive energy — where consumers could receive locational and temporal valuation for their customersited resources in real time.

Regulators divided the proceeding into two tracks: Track 1 focuses on developing DER markets and the utility as Distributed System Platform provider — akin to an air traffic controller that will interconnect and facilitate the DERs. Track 2 focuses on reforming ratemaking practices for utilities and revenue streams for the DSP provider model.

For the past three years, regulators, utilities and other stakeholders concentrated on filing proposals for the DSIP (Distribution Service Implementation Plans) process 9

and rolling out pilot programs. Within the first three months of 2017, regulators issued a series of orders to find a new compensation structure for DERs, guide the development of DSIPs and deploy two grid-scale battery storage systems.

In particular, the new compensation scheme is a first step toward a gradual transition from retail net metering—a policy crediting rooftop solar users for excess energy sent to the grid.

The proposed pricing mechanism, called the Value Stack, proposes four separate pricing components for DERs and gives utilities 45 days from its filing (March 9, 2017) to outline locational pricing that reflects the stack's components.

California New York might have captured the spotlight with its utility business model reforms, but California has hammered away its own efforts to integrate DERs since 1998.

A plethora of dockets make up the state’s grid modernization proceedings. Some efforts are aimed at rate reforms and the valuation of distributed energy resources.

Others are more comprehensive efforts aimed at easing the integration of renewable energy and distributed energy.

Out of all the dockets, two stand out as the biggest proceedings designed to bolster DERs on the grid: The Distribution Resource Plan (DRP) proceeding and the Integrated Demand-side Resource Proceeding (IDER).

Going forward, utilities are looking to increase DER deployment in the distribution system through pilot programs designed to allow utilities to collect 4% annually on expenses, as long as they show the investments can defer traditional infrastructure expenses, Frantzis said.

It’s unclear when, or if, California will wrap up its grid modernization efforts, but 2017 promises many more developments as utilities deploy DER pilot projects and prepare to shift their customers to default time-of-use rate structures in 2019.

Minnesota Minnesota, not a state known for its high solar penetration, found itself entangled in a familiar policy battle over net metering compensation rates three years ago.

As lawmakers sought to resolve this familiar conundrum, a group of stakeholders embarked on a collaboration effort to reform the utility business model in preparation for a changing energy landscape. While many of these reforms are taking place in deregulated states, Minnesota marks the first time a vertically-integrated market entered the grid modernization challenge.

In contrast to deregulated states, tackling grid reforms in vertically integrated markets— where the utilities own the transmission, distribution and generation systems—is an even harder challenge.

energyandecology.com

Issue 4 May 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 4 May 2017

Energy

Is rooftop solar just a toy for the wealthy?

A new report finds the income gap for rooftop solar is narrowing, but work remains to spread distributed energy to all. offering in recent years. And increasingly, utilities are getting involved behind the meter as well.

Arizona Public Service Co., a key player in the state’s notorious solar policy battles, pledged $10 million to expand rooftop solar access to low-income customers as part of a settlement with solar installers in the state over rate design in March. And in San Antonio, municipal utility CPS Energy has a 10 MW project with installer PowerFin that allows customers to host panels at no upfront cost and receive credits on their bills.

In the mid-2000s, companies rolled out innovative financing models making solar system purchases easier. Through leases and power purchase agreements, more consumers could purchase systems and pay them back usually over years, aided by electricity bill credits from net metering.

The idea of reducing electrical bills and achieving a sort of energy independence appealed to many people, and in some parts of the U.S., the technology really took off. In Hawaii, with the highest electrical rates in the nation, adoption skyrocketed.

California enacted generous subsidies, helping spur growth, and even a conservative state like Arizona saw a surge in those contraptions.

But as more customers began trimming bills, the incumbent players started fighting back. Utilities proposed adding fixed fees, reducing compensation for any extra energy generated from solar systems and otherwise searching for ways to recoup grid costs.

For most people, adding a solar system on top of other bills and priorities is a luxury — a fact utilities have long exploited in their ongoing policy battle with private rooftop solar developers.

But a new report from GTM Research suggest that while rooftop solar companies by and large cater to the wealthier portions of the American population, the income disparity isn’t as dire as some of the rhetoric, and it's not as bad as it was in the past.

What do the data say?

So far, two other studies within the past five years have attempted to tackle the rooftop solar income debate: The left-leaning Center for American Progress and Kevala Analytics. Both studies tracked solar 11

adoption using zip codes, but failed to account for the “income variations within zip codes,” according to GTM. To remedy this issue, GTM partnered with PowerScout, a self-styled smart homes company using satellite imagery to collect data on homes hosting rooftop solar within a zip code. They drew a sample from four states: New York, Massachusetts, California and New Jersey. All told, the four states account for more than 65% of the total rooftop solar market share, according to the study.

The study defines middle-income as a range between $45,000 to $150,000 per year. The average solar household income lands roughly around $100,000. Lowincome households are defined anywhere below $45,000.

Based on the findings of the study, GTM researchers estimate that the four solar markets include more than 100,000 installations at low-income properties.

Private sector vs. utility solutions Should the private sector or the government drive rooftop solar adoption forward for lowincome consumers?

Solar companies have always had to live and die by the consumer market, accusations of subsidy dependency aside.

Many of them argue the competitive market will naturally evolve progress to serve all customer segments as price declines and financing options expand.

A growing number of utilities, on the other hand, see their ability to rate base power resources as an opportunity to ensure equitable access to the benefits of distributed solar. Community shared solar, which allows consumers without suitable roofs to buy subscriptions to central-station arrays, has become a common utility

But these utility moves into rooftop solar are often controversial among third-party installers, who fear they will stifle the competitive market. Simply leaving it alone, they argue, will allow them to expand coverage to all.

Sunrun recently partnered with Grid Alternatives, a non-profit solar installer, for a program to boost rooftop solar adoption among low-income households. Under the program, Sunrun will own, operate and maintain the solar arrays while Grid Alternatives will fund each customer’s prepaid 20-year solar PPA or lease bill.

But despite a growing number of lowincome programs from utilities and installers alike, the scale remains relatively small. Sunrun's partnership with Grid Alternatives aims for 500-1000 customers annually, and utility programs to date have either been pilots or limited to a relatively small capacity.

That may be set to change. Utility Dive's recent survey of more than 600 utility professionals revealed 95% think utilities should be allowed to rate base distributed resources in all or some circumstances.

That could portend a coming wave of proposals to get involved behind the meter — if utilities see a business opportunity.

In the meantime, until utilities or private installers step up, GTM’s Kann said the enduring solar gap could be an opportunity for the public sector to intervene.

In the end, current data show rooftop solar to still be mostly a device for the relatively well-off, but the growing discussion on equitable access could spur more programs like those at CPS and Sunrun.

Moving forward, Kann stressed that continued research will be key in helping policymakers and the solar sector understand where to expand offerings.

energyandecology.com

Issue 4 May 2017

Energy

Can group purchases help scale renewable power? practice comes from India. Back in 2014, the World Resources Institute helped launch a pilot project to aggregate rooftop solar demand for six parties: Coca Cola; Infosys; IBM; Cognizant; Philips; and Bangalore International Exhibition Center.

"The aim was to combine their renewable energy procurement into one bid to achieve economies of scale and reduce transaction costs per project," wrote the WRI staffer overseeing the project.

Problems arose, however, when it came to how much information would have to be shared for buildout.

"Buyers we worked with were typically wary of disclosing rooftop data to the solar power vendors because of perceived security concerns," the paper explained.

A primary knock against corporations getting into the business of backing largescale clean energy projects is that high rollers tend to dominate the field. Think Apple's $850 million deal back in 2015 to build a California solar farm, or Google, Ikea and Walmart's $1 billion-plus renewable power portfolios.

For those without 10-figure sums on hand, however, a new option soon could be on the table.

Instead of relying on one blockbuster energy user to solely finance a new solar, wind, hydropower or other renewable energy project, so-called "aggregated" purchasing models hold promise to broaden the field of potential corporate backers by bringing multple companies together in one deal. That is, if different parties can get on the same page and hash out familiar obstacles related to the complexity of long-term clean energy purchases.

"For several years now, thereâ&#x20AC;&#x2122;s been an interest in how we can make this type of transaction more available to companies beyond the really big ones," said Ian Kelly, who manages the Rocky Mountain Institute's Business Renewables Center.

"Aggregation is seen as one of the primary ways people have come up with to make that possible."

Limited examples of the model already are in action, such as the Massachusetts Institute of Technology (MIT), Boston Medical Center and Post Office Square Redevelopment Corporation teaming up on a 60 megawatt North Carolina solar farm owned by Virginia-based energy company Dominion. In Europe, Google also has 13

joined forces with Philips, AzkoNobel and DSM to build a Dutch wind farm slated for completion in 2019.

Public sector entities, too, are exploring the space. In the San Francisco Bay Area, a group of local governments have come together with think tank Joint Venture Silicon Valley to pioneer joint procurement projects in the region.

Now, the question is if and when others will follow suit.

At Salesforce, for instance, Senior Director of Sustainability Patrick Flynn said the company hasn't yet participated in a group purchase but is closely monitoring the evolution of financial models in the space after participating in multiple long-term deals to power data centers with renewable energy in recent years.

Growing the field Aggregation is still in its infancy, but there are reasons beyond sharing the financial burden of a big energy project for companies to consider.

Some companies don't have the electricity needs to justify building a whole solar farm.

Some prefer a portfolio approach to renewable energy, investing in multiple projects in different locations. In both cases, Kelly said, aggregation could help bring more businesses into the field.

Still, renewable energy power purchase agreements (PPAs) of any kind are already complex, particularly for companies whose core business isn't related to energy. The model also requires organizations to align on goals and financial terms, complicating the fine print on transactions.

How pronounced concerns about facility design or other operational details may be in fields aside from rooftop solar will depend on the company. More broadly, Kelly said, RMI also has seen a shift in the type of energy that corporate buyers demand across the board.

Before about 2014, Kelly said upwards of 98 percent of all renewable energy transactions involving corporate buyers went to wind projects. Now, with solar cost declines in recent years well documented, he estimated the split at more like 80-20 wind and solar, and it's unclear whether aggregation would change those proportions.

Finding a sweet spot in project size also will be a variable to watch moving forward for aggregated deals. So far, Kelly said participants in successful aggregation deals have tended to need more than 10 megawatts each to justify the cost. The WRI deal in India recommended a minimum of 56 megawatts for each party.

Going virtual One thing group purchases can't do for companies interested in renewable energy investing is simplify the sometimes dizzying underlying deal structure.

The first thing to know is that businesses (or other renewable energy investors) aren't actually buying clean power to physically power their operations.

One example of how this can play out in energyandecology.com

Issue 4 May 2017

Energy

Key electricity trends potential in OECD countries is already utilised. The increase in Hydro for 2016 was predominately a result of higher rainfall in many countries, especially in Canada, the United States and Norway, the top three Hydro producers in the OECD. These increases compensated for significant drops of Hydro production in Finland and Sweden.

The largest percentage increase throughout the OECD was seen in Portugal, 173% higher in 2016 than the average Hydro production during the 2005 - 2015 period and 73% higher in 2016 than in 2015.

This allowed for the highest level of electricity exports to Spain since 2005. As Spain increased its use of electricity imports, from Portugal and other countries, it saw the lowest level of indigenous production in 2016 since 2005.

Electricity Production An assessment of monthly data shows that in 2016, OECD net electricity production grew by 0.9% compared to 2015. Within this small overall change there was a large increase of 9.5% in Geothermal, Solar, Wind and Other renewables1 generation and a smaller, but still significant, increase of Hydro, 2.2%. Combustible Fuels2 and Nuclear fell by 0.2% and 0.1%, respectively.

Overall production rose by about 0.9% in the OECD, but each OECD region saw different changes in production shares by fuel type during 2016. In OECD Americas (hereafter, “the Americas”), Combustible Fuels dropped by 1.5% while Nuclear increased 0.7%, Hydro increased by 3.2% and Geothermal, Wind, Solar and Other renewables increased significantly by 22.5%. OECD Asia/Oceania (hereafter, “Asia/Oceania”) showed the same trends, with Combustible Fuels dropping 0.5% but increases in Nuclear, 6.6%, Hydro, 1.4%, and Geothermal, Wind, Solar and Other renewables increasing the most, 12.6%.

OECD Europe (hereafter, “Europe”) showed a different trend with the largest increase coming from Combustible Fuels, 2.6%, and a smaller increase in Hydro of 1.0%. Other non-combustible renewables remained virtually flat while the only decrease came from Nuclear, 2.4%.

In terms of shares of generation, noncombustible renewables accounted for 30% of generation in Europe compared to 21% in the Americas and 12% in Asia/Oceania. Combustible Fuels remain the dominant source of electricity and accounted for 61% in the Americas, 78% in Asia/Oceania and 47% in Europe. Nuclear 14

produced 23% in Europe, 18% in the Americas and 9.5% in Asia/Oceania.

Geothermal, Solar, Wind and Other Renewables

Combustible Fuel

Total OECD production of electricity from Geothermal, Solar, Wind and Other renewables was 873.9 TWh in 2016, which was 75.6 TWh, or 8.4%, higher than in 2015, with increases seen in all OECD regions. Europe had the smallest increase in this category of 1.9 TWh, or 0.4%. In Asia/Oceania, there was an increase of 9.6 TWh, or 12.6%. The Americas rose the most with 64.1 TWh, or 22.5%, driven by increases in U.S. Solar and Wind of 45% and 19%, respectively.

Total OECD cumulative production of electricity from combustible fuels in 2016 was 6 174.3 TWh, which was 12.9 TWh, or 0.2%, lower than in 2015. This comprised reductions in Asia/Oceania and the Americas of 0.5% and 1.5% but an increase in Europe of 2.6%.

One element within Combustible Fuels was the switch from coal to natural gas in the United States and the United Kingdom, continuing the trend from within the last year. In 2016, the United States reduced use of coal plants in favor of natural gas plants due to the low price of natural gas.

The same trend was seen in the U.K., although the shift was larger with the added influence of carbon pricing in the U.K. Nuclear Electricity Total OECD cumulative production of nuclear electricity in 2016 was 1 873.6 TWh, 2.7 TWh, or 0.1% lower than in 2015.

Europe was the only region which decreased its nuclear production, by 19.6 TWh, or 2.4%, to 790 TWh led by the continued phase out of nuclear electricity in Germany as well as decreases in the Czech Republic and France caused by extended outages. There were also operational outages in Slovenia and Switzerland.

Hydro Electricity Total OECD production of hydroelectricity in 2016 was 1 451.6 TWh, which was 30.7 TWh, or 2.2%, higher than in 2015, and increased in each OECD region. From 2000 to 2015, Hydro production has only grown 0.8% because most of the available

The European trend contrasts with last year, when Europe showed the highest increases of all of the OECD regions. Solar and Wind dominate, producing roughly 25% and 70%, respectively, of the electricity in this category for Europe and whilst it was a good year for European Solar production, which increased 4 337 TWh, or 4%, Wind production fell 1%. Germany, which produced roughly 28% of the European Solar and Wind for 2016, had decreases of 1% and 7%, respectively, due to weather conditions. With the aforementioned phase-out of Nuclear, this necessitated an increase in Combustible Fuels.

Electricity Trade Trade increased this year in the Americas by about 8% for Imports and Exports. In Europe, imported electricity in 2016 fell 8.7% to 386.1 TWh and electricity exports fell 9.8% to 378.4 TWh.

energyandecology.com

Issue 4 May 2017

Energy

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energyandecology.com

Issue 4 May 2017

Energy

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energyandecology.com

Issue 4 May 2017

Energy

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energyandecology.com

Issue 4 May 2017

Ecology

Residues reaching end of life cycle better development policy than burning high grade biomass fuel Waste has no additional values while residue is a highly sought commodity.

What does it take for a small family business to become a company with a global footprint and thousands of successfully realized projects? What is the secret of Polytechnik’s success?

Lukas Schirnhofer, CEO of Polytechnik, Austrian to energy technology providers Being one of the world’s leading suppliers of biomass to energy technologies, could you tell us what are the trends in utilizing biomass potentials worldwide? How does Polytechnik fit into those trends?

The wood industry, being the biggest consumer of biomass in the world, is setting trends in lowering costs and becoming more competitive on the global stage.

Of course biomass comes from all sorts of industries and Polytechnik has built plants in almost all of them. By no means are we putting the emphasis on the wood industry but the examples of good practice are the easiest to show there.

Trends show that utilization of low quality biomass fuel that cannot be used any more in a cascade approach becomes more important. Raw material is a commodity and the only way for production of any kind to be competitive in the global market is by utilizing its production residues, reducing the energy share in the final product and avoiding dependency on third parties. The circular economy or zero waste production is major trend today regardless of the industry – from the wood to the food industry.

Utilizing natural byproducts and residues which have reached the end of the life cycle have proven to be a good development policy instead of burning high grade residue or fuel (i.e. sawdust, dry wood) that can be transformed into another valuable product i.e. in the wood industry pellets or briquettes.

Polytechnik has long term experience and know-how in combustion of low grade biomass fuels whilst keeping up output and guarantee levels. It is important to differentiate between waste and residue.

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This family owned business owes its success both to its openness to innovation and continued technological development, but mostly to its outstanding qualified employees. It is our goal to gather in Polytechnik people who are professionals, intellectually curious and passionate for their work to be a part of our team and work together as partners for many years.

The employees are regarded as members of the extended family. This has in turn created an environment of motivation, loyalty and team spirit. Employees are the firms human capital.

We have gone from two to 250 in a single generation. In the beginning, back in 1965 and the early seventies, the use of biomass for energy production was still not on the public radar, despite the oil crisis, but we believed in our technology, because the basic idea behind it was both simple and inspiring.

Polytechnik then optimized its combustion technology to make it economically viable to use wood residues and other organic waste materials from various production as sources of fuel.

The philosophy behind biomass – based on our corporate credo which can be summed up as “think locally act globally” – is now spreading around the world, with over 3,000 Polytechnik systems in operation. Frankly it takes a lot of work, travel and effort to be successful, you don’t sell more than three thousand specialized systems from your desk.

The longer we have been producing combustion systems, the more we have come to respect fire as the main element involved. Each of our automation related developments has been concerned with taking system safety to another level.

Definitely another answer to your question is to be where the demand is and to create solutions that serve the demand. It’s our curiosity and the desire to constantly improve our product and performance that drives us to be one step ahead.

As my father, the founder of Polytechnik, considered to be a pioneer in the sector would say, “I am a technical specialist with a desire to make the best of the space

available to me. If our systems can contribute to us leaving behind a world that is at least similar to the one I was able to experience as a child, I will be satisfied”.

Finally, the purchase of the product does not mark the end, but rather the beginning of our relationship with the customer. Our customers are always repeat customers.

Which industries do Polytechnik’s major clients come from? Which industries do record the highest energy efficiency when applying biomass technology? What about district heating companies?

The company has clearly grown with the wood working industry. This sector was our first but it is not the only client today.

Obviously the reason for this sector being in need of our products was the abundance of waste material/residue.

And while at the beginning the need was to safely, economically and efficiently dispose of this natural waste material while satisfying the production needs for energy, today this industry has greater appetites.

New business opportunities through cogeneration plants, energy efficiency and other incentives have increased the appetites of investors.

Besides, the average age of the energy systems (boilers) within the wood working industry, for example in Southeast Europe, is 25-30 years, which means that efficiency can be improved by at least 25%. Plus the range of residues that can be burnt is more flexible.

The need for reinvesting, modernizing and installing energy efficient, cost reducing solutions is real, only the mindset of the decision makers sometimes still remains a question mark. Highest energy efficiency is the demand of utility companies and also district heating companies. In these cases all savings or life cycle planning mostly depend on the efficiency levels and feedstock consumption.

Maximizing the benefit from a given technology is the key while lowering fuel quality dependency and feedstock supplier risk. These operators are realizing that by burning local, carbon neutral, often subsidized domestic fuel is the only way to reach full independency from global trends and prices, while maintaining high quality service, sustainability and employing the local workforce, while reducing emissions.

energyandecology.com

Issue 4 May 2017

Ecology

Residues reaching end of life cycle better development policy than burning high grade biomass fuel Due to emissions restrictions it becomes more and more important for district heating companies to diversify their energy portfolio where biomass should have a significant share to be considered. Just looking on the control side with our fully automatic systems we can increase efficiency by at least 5-10% as opposed to the industry standard. Utilizing the modern technology of biomass solid fuel combustion we are erasing stereotypes which depict biomass as dirty, inefficient, complicated, or labor intensive.

Biomass today comprises very diverse range of fuels and each type has its own potential for a given application. Natural residues or by-products or waste produced in the food industry, paper/pulp industry, dairy and poultry/broiler farming can all be applied. Energy crops such as mischantus, poplar, willow should also be considered.

We all have to be aware that it is not feasible for every district heating company or industry to switch to biomass. The necessary conditions have to be met for this transition.

In any case examples from Austria, Germany and the Nordic countries have shown both good and bad practice of utilizing biomass. The eastern European and Asian markets with their wellestablished network of district heating systems are increasingly converting to biomass. Utilizing low grade biomass the savings on feedstock can be between 2040%.

Recently you celebrated 50th anniversary of Polytechnik. What are Polytechnik’s development and investment plans in the coming period?

First thing: continuity. It is important to our customers. We want to follow a way of sustainable growth in our current markets and to invest in new markets and new technologies such as gasification and utilization of untreated agricultural biomass fuels.The supply of turnkey plants, which allow new users, once fully trained, to operate their systems with the flick of a switch, has been the underlying sales success and worldwide hit. We want to continue this in the future. Having everything under one roof has enabled us to venture successfully into new markets. Our biomass-fired systems developed into core elements of our customers operations. We have become their equal partner.

Second word: innovation. Polytechnik will 19

continue innovating and growing. Currently the company reinvests around 3% of its turnover for R&D. Once we establish a presence, the customers rely on us for stability and support. Biomass has a future because it is available everywhere in the world. It is sustainable and local. Long transport chains are not needed, and international dependency on raw materials, often the cause of many political conflicts, is reduced.

Currently the export rate is almost 100%. To keep this rate of growth we are planning on expanding our production facilities by more than 10.000 m² by 2020. Appreciation of the company’s performance has spread far beyond our customers. In 2014 the Austrian Ministry for Industry and Commerce awarded the Austrian Coat of Arms to Polytechnik in recognition of our outstanding contribution to the national economy. At the moment we are the only company from the energy and renewables sector in Austria to have this honour. Other significant awards include: the State Quality Aw a r d ( 1 9 9 1 ) , D a p h n e P r i z e f o r Environmental Technology (2002) and the Hidden Champions Award (2014). This is proof that the company is headed in the right direction.

In the Balkans, biomass is the most significant renewable energy source, due to abundance of forests and agricultural areas. However, the potential is almost untapped. What are the major obstacles, according to your opinion and do you see some light at the end of the tunnel?

One major demand of a vibrant biomass market is the constant fuel supply chain and a competitive environment of the fuel market. The increasing investment opportunities and the maturity of boiler systems that are currently under operation will create a demand that will speed up the process getting the biomass energy market out of its baby shoes.

To elaborate on the points let’s start with the maturity of the operating boiler systems. A boiler plant is the heart of energy production facility in any industry or public utility. If the age of these plants is on average 25-30 years, then it is safe to say that these systems have reached the end of their life cycle. They are expensive, inefficient, labor intensive, dirty and poorly maintained, while there is no clear replacement or refurbishment planned. So of course the potential is there. The biomass market will develop with demand

and is precisely why biomass-burning plants that are able to operate efficiently and reliably, within emission limits, for a wide variety of biomass quality are the only real solution. This is where Polytechnik, arguably the only organization to handle such a wide range of fuels, has claimed the place as technology leader.

In a developing market such as the Balkans area, it is the chicken and the egg situation.

To avoid this the right technology has to be applied otherwise the market will never develop while one side waits for the other to develop capacities or demand. This is especially the case for biomass to heat projects, not such much the industrial sector. Next we have the investor state of mind and the support of the financial sector.

Typically the boiler plant is somewhere in the back of some factory, away from anyone’s view. It is a place where energy comes from and often the user has no information on the energy needs, fuel consumption and potential savings.

Somehow the energy is taken for granted, a remnant from the era of abundance in the past.

This is a commodity which greatly impacts the competitiveness of a product and needs more attention. Our sales and support staff have been working to develop this state of mind, to raise awareness and help investors understand that an investment in the boiler plant is a long term investment with long term gains, not something to be taken lightly for the short term gain of a lower initial investment.

In most cases, especially in high energy demand sectors, the burning of low grade biomass and investing in a more advanced system evens out with a standard equipment and high grade fuels within 2-3 years. Due to the poor investment climate, Polytechnik is prepared to be a full partner from the design, build and financing phase.

With our team of experts we can find a technical solution and provide support in finding the financing either through international banks and/or European grants/funds.

energyandecology.com

Issue 4 May 2017

Ecology

Salt, silicon or graphite: energy storage goes beyond lithium ion batteries heat to be used in district heating systems for hot water or space heating.

The company has developed 10MW or 200MW systems, which can store heat for up to two weeks, although they are designed to be able to constantly charge and discharge according to demand. Unlike batteries, which have a finite number of charge/discharge cycles, the molten silicon can be used indefinitely and can be recycled when the units reach the end of their 20-year service life.

Other thermal storage systems take heat directly from the sun to heat storage materials. In these systems, concentrating solar collectors – rather than photovoltaic cells – are used to heat a liquid that can then heat a storage medium. Pilot scale facilities in Jemalong and Lake Cargelligo, both in central west NSW, use molten salt or graphite, respectively, to store heat.

Between the political bickering following a spate of blackouts in South Australia and the billionaire entrepreneur Elon Musk tweeting that he had a fix, and then the South Australian government announcing that it will build a grid-connected battery storage facility, interest in renewable energy storage has never been higher.

While lithium ion batteries sold by Tesla and others are perhaps the most widely known storage technology, several other energy storage options are either already on the market, or are fast making their way there.

All are hoping to claim a slice of what, by all indications, will be a very large pie. The Australian Energy Market Operator forecasts that more than 1.1m new battery storage systems will be installed in Australian households by 2035. And, according to a 2015 report by the Climate Council, battery storage capacity is expected to grow 50-fold in under a decade.

“The market for storage is huge,” says Kevin Moriarty, the executive chairman of 1414 Degrees, an Adelaide-based thermal storage company hoping to win South Australia’s 100MW storage system tender.

The South Australian system will be the largest in Australia so far but Moriarty describes it as “a drop in the ocean” compared with what will be needed as Australia transitions away from carbondioxide emitting fossil fuels.

The need for energy storage solutions is the natural consequence of an energy grid that has an increasing amount of renewable energy sources. Solar power plants don’t produce energy when the sun doesn’t shine and windfarms grind to a halt when the wind 20

doesn’t blow.

At the grid level, the resulting fluctuations in supply, combined with demand that can rapidly spike during hot weather, for example, can play havoc with the steady 50Hz electricity supply needed to power everything from microwaves to factory production lines.

Traditionally, fossil fuel-powered turbines are used to rapidly respond to load changes. If switched on when needed, electricity output ramps up or down so that there is enough electricity, at the right frequency, to supply demand.

Renewable energy storage systems, which include batteries and thermal storage systems, run from small household units to power plant and grid-scale technologies.

What they aim to do is enable electricity to be released into the system when it is needed – so-called load shifting – rather than only when solar collectors or wind turbines are operating.

“Storage allows you to spread out the load and, if you can do that, you no longer need the big so-called base-load generators,” Moriarty says.

In thermal storage systems, renewable electricity or electricity purchased from the grid at off-peak rates is used to heat a material to a high temperature. 1414 Degrees uses molten silicon – an abundant and cheap element that is the main component of sand – that is heated to its melting point of 1414 degrees. The stored heat can then be used at a later time to generate electricity – using turbines – that is fed back into the grid. It can also release

According to Prof Frank Bruno, leader of the Thermal Energy Storage Group at the University of South Australia, one of the advantages of thermal storage is the ability to operate at high temperatures, unlike batteries, whose components suffer once temperatures go above about 50 degrees.

The other advantage is price. “Storing energy as thermal energy is much cheaper that battery storage,” says Bruno, although photovoltaic power plants currently out compete concentrated solar collectors.

The Australian Solar Thermal Research Initiative, of which Bruno is a member, is trying to bring the cost of concentrated solar collectors down, which would make integrated solar thermal storage systems more price competitive overall.

Battery makers are concentrating on trying to solve some of the key limitations of lithium ion batteries. One of those is the scant supply of raw materials required to make them, a supply that is unlikely to meet future energy storage demands, according to Prof Thomas Maschmeyer, co-founder of the University of Sydney spin-off company Gelion.Gelion batteries use zinc and bromide, elements with more stable and abundant supplies than the lithium and cobalt of lithium ion batteries. Unlike lithium ion batteries, which will become more costly as demand for raw materials outstrips supply, the price of Gelion’s batteries will only decrease with increased production scales.

energyandecology.com

Issue 4 May 2017

Ecology

Hazelwood's closure shows industry and government must plan ahead for climate change five months’ notice, the state and federal governments have pulled together transition plans worth over $300m. Time will tell whether this is sufficient to smoothen the local impacts, but repeating this level of funding for the remaining 20 coal generators could mean finding $6bn in government budgets in coming years.

For clean-energy investors, knowing when a power station will close gives confidence about when new renewables projects will be needed. A timeline for the retirement of Australia’s remaining fleet of coal-burning power stations would provide this certainty.

There’s a compelling case that to avoid energy market chaos, we need to set closure dates from now until 2030.

When Hazelwood stops generating electricity this week, it will be the first Australian power station to close, at least in part, because of climate change.

Hazelwood’s owner, French energy giant Engie, has said it is “making climate a priority” and has committed to retiring its most outdated coal plants worldwide.

close the equivalent of another five large coal power stations (a total of about 8700MW of capacity) by 2030 in order to meet even the Turnbull government’s manifestly weak climate targets. Targets more in line with keeping global warming under 2C involve closing one Hazelwoodsized power station each year from now on.

Hazelwood’s closure will bring the total to nine coal power stations in Australia that have retired in the last five years – including the Port Augusta power stations in South Australia, the Munmorah and Wallerawang power stations in New South Wales and the smaller Energy Brix and Anglesea power stations in Victoria. It’s a clear indication the global industrial transition from coal to renewable energy across the world has reached our shores.

While coal generators have been closing, they have not necessarily been closing in a way that serves local communities: the closures at those nine power stations in the past five years have given workers an average of just four months’ notice from announcement to turning off the boilers. For communities where coal is a large part of the regional economy, this is too little notice.

Like all such transitions, this one will involve a big upheaval for the affected workers, but never before has an industrial transition had so much else at stake. Never before has the end of one industry been so essential to the wellbeing of the rest of society.

Burning coal for electricity accounts for a third of Australia’s greenhouse gas pollution. It is the country’s largest single source of carbon dioxide, and it’s likely to be the easiest to reduce – cutting climate pollution from more diffuse sectors such as transport and agriculture will be more challenging.

Globally, the International Energy Agency identified phasing out inefficient coal power stations as a key plank in any effective global agreement on climate change.

Domestically, the Australian Energy Market Operator has estimated we would need to 21

But neither have they been closing in the best way for our climate. Economics has driven decisions. Unprofitable generators – the lame animal in the moving pack that is the National Electricity Market – have stumbled and fallen quite suddenly, but these power stations aren’t necessarily the worst or biggest polluters.

A Senate inquiry into the retirement of coalfired power stations, due to report this week, provides an opportunity to move the public debate beyond political blame games and into the realm of responsible policymaking. In recent months, green groups, business groups, unions and even the energy industry itself have called for a greater government role in planning the phaseout of coal-burning power stations.

For communities, knowing when a power station will close gives much-needed impetus to diversify the regional economy.

While Hazelwood’s closure came with just

Even some big power companies are on board. AGL, owner of three large coal power stations, has previously advocated for setting 50-year lifetime limits on each generator. Energy Australia recently argued that companies should be required to provide much earlier notice of when their own generators will close.

As of next week, Energy Australia’s Yallourn power station in Victoria’s Latrobe Valley will be the dirtiest coal generator in the country, and one of the oldest. The company’s public position that it will remain open until 2032 seems unlikely at best and deceptive at worst – a deception that has consequences for workers, communities and energy markets. Scepticism is warranted: Hazelwood’s owners gave the same 2032 closure date just months before announcing the power station would bow out in March 2017.

Last month the Australian Prudential Regulation Authority warned that companies need to appropriately manage their exposure to climate risks, effectively putting the owners of coal-burning power stations on notice. Telling shareholders an asset might be open for another 15 years when a much shorter life is likely, or even possible, could have serious legal consequences.

We don’t have to choose between coal power and renewables – community attitudes and energy markets have already decided. The choices now are about speed and justice. Will this industrial transition be fast enough to avoid the worst risks to our climate, and fair enough to sustain regional communities? Will it be chaotic and disruptive, or planned and orderly?

energyandecology.com

Issue 4 May 2017

Ecology

The end of coal: EU energy companies pledge no new plants from 2020 “The debate about coal is over,” one industry insider told The Guardian.

“This is the only way that we can go forward with decarbonisation. But it would be good to see a phase-out of existing coal plants.”

The energy utilities’ initiative faced initial resistance in Germany which is relying on coal to bridge a move away from nuclear energy to renewables under the Energiewende transition.

In the end, though, only Poland which depends on coal for around 90% of its electricity and Greece, which still plans new coal plants, bucked what is becoming a global trend.

Companies from every EU nation except Poland and Greece sign up to initiative in bid to meet Paris pledges and limit effects of climate change.

Coal has been central to Europe’s development, powering the industrial revolution, trades union history, and even the EU’s precursor, the European coal and steel community.

Europe’s energy utilities have rung a death knell for coal, with a historic pledge that no new coal-fired plants will be built in the EU after 2020.

But it also emits more carbon dioxide than any other fossil fuel, plus deadly toxins such as sulphur dioxide, nitrogen dioxide, and particulate matter, which are responsible for more than 20,000 deaths each year.

The surprise announcement was made at a press conference in Brussels on Wednesday (5 April), 442 years after the continent’s first pit was sunk by Sir George Bruce of Carnock, in Scotland.

National energy companies from every EU nation – except Poland and Greece – have signed up to the initiative, which will overhaul the bloc’s energy-generating future.

A press release from Eurelectric, which represents 3,500 utilities with a combined value of over €200bn, reaffirmed a pledge to deliver on the Paris climate agreement and vowed a moratorium on new investments in coal plants after 2020.

“26 of 28 member states have stated that they will not invest in new coal plants after 2020,” said Kristian Ruby, Eurelectric’s secretary-general.

“History will judge this message we are bringing here today. It is a clear message that speaks for itself, and should be seen in close relation to the Paris agreement and our commitment to provide 100% carbonneutral electricity by 2050.”

“Europe’s energy companies are putting their money where their mouths are,” he added.

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Wendel Trio, the director of Climate Action Network Europe, hailed the new move as “the beginning of the end for coal”.

“It is now clear that there is no future for coal in the EU,” he said.

“The question is: what is the date for its phase out in the EU, and how hard will the coal industry fight to keep plants open, even if they are no longer economically viable?”

The coal industry though was sceptical about the utilities’ announcement. Brian Ricketts, the secretary-general of the Euracoal trade group said: “Steam engines were replaced by something better, cheaper and more productive – electric motors and diesel engines.

When we see a new energy system – with lots of energy storage – that works at an affordable price, then coal, oil and gas will not be needed. In the meantime, we still rely on conventional sources.”

New coal plant constructions fell by almost two thirds across the world in 2016, with the EU and US leading the way in retiring in existing coal capacity.

The move is also in line with a pathway for meeting the 2°C target laid out by climate scientists last month, as a way of limiting future stranded asset risks.

Europe will have to phase out all of its coal plants by 2030 or else “vastly overshoot” its Paris climate pledges, climate experts say.

António Mexia, the CEO of Portuguese energy giant EDP and president of the Eurelectric trade association, said: “The power sector is determined to lead the energy transition and back our commitment to the low-carbon economy with concrete action.”

“With power supply becoming increasingly clean, electric technologies are an obvious choice for replacing fossil fuel based systems, for instance in the transport sector to reduce greenhouse gas emissions.”

“The challenge for policy makers in the next two years will be to target the political instruments, ensure that they are complementary decarbonisation and electrification at the same time,” said Ruby.

Ruby called for a ratcheting up of the cap on CO2 emissions under the EU’s emissions trading system, to speed the transition to a low carbon economy.

Renewable industry sources also welcomed the news, albeit with the caveat that it would allow continued new investments in the industry for another three years. energyandecology.com

Issue 4 May 2017

Ecology

New Eco Park designs unveiled at business breakfast Eco Park we hope to push the boundaries of sustainable development, create 4,000 jobs in the green economy, a world class football stadium and make more room for nature with a big biodiversity boost. As well as creating a new ‘Gateway to Stroud’.”

“The Green Technology Hub proposals apply the latest sustainable design technologies with ecologically sound materials and construction methods to create an integrated community for worldleading research and development.”

Ecotricity has unveiled a proposed new ‘Gateway to Stroud’ at an Eco Park business breakfast – including new concept designs for the Green Technology Hub designed by Zaha Hadid Architects.

Over one hundred businesses attended the event, which featured the ‘Gateway to Stroud’ proposal – comprising a new dualcarriageway on the A419, concept designs for Eco Park’s Green Technology Hub, the

new Forest Green Rovers football stadium, and a Zaha Hadid designed footbridge linking the two main sides of the development.

Ecotricity has applied to Stroud District Council for outline planning permission for the development, which the company hopes will be granted in the next few months.

Dale Vince, Ecotricity founder, said: “With

While currently just at the concept stage, a decision on the final design of the Green Technology Hub will be made as part of the full planning application.

Eco Park is a proposed 100 acre sports and green technology centre at Junction 13 on the M5 – with 50 acres dedicated to creating state-of-the-arts sporting facilities, including a new stadium for Forest Green Rovers, while the other 50 acres will comprise a green technology business park capable of creating up to 4,000 jobs.

Low-cost 'solar absorber' promising for future power plants Researchers have shown how to modify commercially available silicon wafers into a structure that efficiently absorbs solar energy and withstands the high temperatures needed for "concentrated solar power" plants that might run up to 24 hours a day.

The research advances global efforts to design hybrid systems that combine solar photovoltaic cells, which convert visible and ultraviolet light into electricity, thermoelectric devices that convert heat into electricity, and steam turbines to generate electricity. The thermoelectric devices and steam turbines would be driven by heat collected and stored using mirrors to focus sunlight onto a "selective solar absorber and reflector."

To efficiently collect heat from the sun, specially designed surfaces based on lowcost materials are needed to selectively absorb only photons from a certain range of the light spectrum while reflecting others.

"The key point is that to capture sunlight as efficiently as possible you have to do two things that compete with each other: one is 23

to absorb as much power from the sun as possible, but secondly, not reradiate that power," said Peter Bermel, an assistant professor in Purdue University's School of Electrical and Computer Engineering. "If you make something really hot it starts to glow red, and we are trying to prevent that re-emission from happening while still absorbing the sunlight.“ The silicon solar device contains an upper layer of an anti-reflection coating made of silicon nitride and a back reflective layer made of silver. Complicating the research is that properties of the material change dramatically while going from room temperature to around 500 degrees Celsius. Extending previous work by researchers in the field, the team developed a detailed model that simulates how the material properties change with rising temperature.

The model helped researchers design the structure built from silicon wafers, and led to the discovery that a selective absorber made of thin films of silicon can exhibit even higher performance.

At the same time, the flexibility of thin films offers potential advantages, since they can be applied to curved structures such as the mirrored "parabolic troughs" used for concentrated solar power systems. The troughs track the sun all day, concentrating the sun's energy by about 50 times.

Ideally, the hybrid solar-power system could achieve efficiencies of more than 50 percent, compared to 31 percent for photovoltaic cells alone. The researchers estimated that with 50 suns concentration produced with the parabolic troughs, it is possible to convert 51.5 percent of sunlight into usable, high-grade heat at 490 degrees Celsius. The Applied Physics Letters paper was authored by Tian and Zhou; undergraduate student Tianran Liu; graduate student Cindy Karina from the Swiss Federal Institute of Technology; Purdue postdoctoral research associate Urcan Guler; Vladimir Shalaev, the Bob and Anne Burnett Distinguished Professor in Electrical and Computer Engineering; and Bermel.

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Issue 4 May 2017

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OIL&GAS

Rosneft starts drilling northernmost Russian Arctic well that will be drilled in the offshore area of the Laptev Sea. Sechin informed President Putin during their video call that the drilling would be done from the coast, as it considerably reduces construction costs of the well.

“The design depth is up to 5,000 meters with a subsequent horizontal leg.

The technology we have enables us to drill with a vertical deviation of up to 15,000 meters,” added Sechin.

Rosneft said that, since 2012, investments in Arctic shelf development amounted to about RUB 100 billion ($1.8 billion).

The company plans to maintain the pace of its activities, and investment volumes are expected to grow two and a half times, up to RUB 250 billion ($4.5 billion) in the period from 2017 to 2021.

Russian oil firm Rosneft has started drilling of the Tsentralno-Olginskaya-1 well at the Khatangsky license area in the Laptev Sea. The Khatangsky license area is located in the Khatanga Bay in the north of the Krasnoyarsk Region. Area acreage is 18,709 square kilometers at a sea depth which reaches 32 meters.

Currently, Rosneft holds 28 license areas on the Arctic shelf with total resources of 34 billion tonnes of oil equivalent.

The exploration drilling was launched by the President of the Russian Federation Vladimir Putin via video link-up with Rosneft CEO Igor Sechin who was on the shore of the Khatanga Bay. During the video link-up, Putin said: “We are seeing the start of work to develop a whole oil and gas province, which preliminary data suggest contains a vast quantity of energy resources.

“Horizontal drilling is a complex and hightech operation. This is just the first well.

There is much more work ahead.

I would like to wish you good luck, and I hope for this undertaking’s success.”

Rosneft head Sechin added: “We completed 21 linear kilometers of seismic 25

studies that revealed the existence of 114 promising oil and gas-bearing structures.

Preliminary estimates suggest that the Laptev Sea’s total potential geological resources could come to 9.5 billion tonnes of oil equivalent.”

There are no sea ports in the vicinity of the K h a r a - Tu m u s p e n i n s u l a a n d t h e navigation period in this area lasts no longer than two months a year.

Despite that, Rosneft said it delivered more than 8,000 tons of cargo from the sea port of Arkhangelsk to the drilling site during the 2016 summer navigation period.

Two ice-class cargo vessels delivered the drilling rig, equipment and materials for drilling, and accommodation modules over a distance of 3,600 kilometers across the White, Kara, and finally the Laptev Sea. The drilling operations will be performed by RN-Burenie, Rosneft’s in-house service company.

Rosneft CEO Sechin also mentioned other plans regarding the Russian offshore: “We started working in the Kara Sea in 2014, acting on your (President Putin’s) instructions, and discovered a very important field – the Kara oil and gasbearing province.

“This year, after starting on the Khatanga block, we will be drilling in the Black Sea. Next year, we will drill in the Barents Sea, and in 2019, we will return to the Kara oil and gas field, and will continue our work in the eastern Arctic.”

President Putin emphasized the importance of the development of Arctic oil and gas potential by state-owned companies: “We have tremendous untapped offshore and coastal reserves in the Arctic.

“Given the tremendous value and importance of these reserves of hydrocarbons and other minerals, we have allowed only companies in which the state holds a majority stake to take part in this work.

Licenses have been accorded only to Rosneft and Gazprom. Rosneft should undoubtedly make the best possible use of these privileges.”

During the project’s implementation results of the work of the first year-round research base in the Arctic region will be used.

The research base was set up by Rosneft in 2016 in the proximity of the drilling site in Khatanga Bay. Tsentralno-Olginskaya-1 is the first well energyandecology.com

Issue 4 May 2017

OIL&GAS

Persian Gulf Star ReďŹ nery, Iran's Major Step for Self-Reliance in Gasoline Production

Construction of the refinery started in 2006, but the project was stymied by mismanagement as well as financial constraints due to international economic curbs imposed over Tehran's nuclear program.

The launch of the first phase of PGSR means the refinery is now operating at onethird of its total crude oil processing capacity of 360,000 barrels per day.

Once in full swing, the star refinery will produce 36 ml/d of gasoline, which will effectively cut gasoline imports and turn Iran into an exporter of the product, according to Financial Tribune.

Rouhani said the easing of trade and financial curbs under the nuclear accord with world powers breathed a new life in the Star refinery project which had been left in a state of limbo.

Update: "The refinery's equipment was held up in other countries (due to the sanctions) and had it not been for the nuclear deal, the refinery couldnâ&#x20AC;&#x2122;t be launched today. Those who say they can't see the fruit of the nuclear deal should come and see that the Persian Gulf Star Refinery's equipment and machinery has been purchased and installed," said the president.

He was accompanied by Oil Minister Bijan Namdar Zanganeh and General Ebadollah 26

Abdollahi, head of Khatam-al-Anbiya Construction Headquarters, an affiliate of the Islamic Revolutionary Guard Corps and the refinery's contractor.

After years of arduous negotiations, Tehran and world powers (the five permanent members of the UN Security Council plus Germany) struck a landmark deal in 2015 on removing some economic curbs against Iran in exchange for limiting the country's nuclear activities. The deal, officially known as the Joint Comprehensive Plan of Action, came into force in January 2016.

The launch of the first PGSR development phase means the refinery is now operating at one-third of its oil processing capacity of 360,000 barrels per day. It is some 20 kilometers west of Bandar Abbas and 12 kilometers north of the Persian Gulf coast.

In the first development phase, 12 million liters per day of Euro-4 grade gasoline, 4.5 ml/d of Euro-4 diesel, 1 ml/d of kerosene and 300,000 liters per day of liquefied petroleum gas will be produced at the sprawling complex.

"The commissioning of Persian Gulf Star Refinery's first phase puts Iran on track for self-reliance in gasoline production and its export in the near future," Rouhani noted, adding that $1.4 billion was invested in the refinery over the last four years.

Iran Gasoline Production Capacity

Once in full swing, the star refinery will produce 36 ml/d of gasoline, which will effectively cut gasoline imports and transform Iran into an exporter of the product. In the previous fiscal, Iranians burned almost 74 million liters of gasoline daily. The government had to import 12 ml/d to meet demand.

"Before the JCPOA, if we imported equipment and it happened to be defective, that was our own problem. But today, they (foreign manufacturing companies) oversee the equipment."

The refinery's two remaining development phases are scheduled to be completed by the end of the current fiscal in March 2018.

Rouhani's tenure ends in summer. He is running for a second and last term on his 2013 platform of economic development, hope, moderation and normal ties to the outside world. Speaking in the port city, the president denied claims (by his political opponents) that the inauguration of the PGSR and other high-profile industrial projects ahead of the May 19 presidential election are publicity stunts.

"Some people ask why we have commissioned projects in the past few weeks. It is not like flipping the switch of a light bulb. The inaugurations come on the back of four years of investment and development," he said.

energyandecology.com

Issue 4 May 2017

OIL&GAS

Israel signs pipeline deal in push to export gas to Europe For Israel, which has signed preliminary or final gas supply agreements with Jordan, Egypt, and the Palestinian Authority, the pipeline would be its boldest gambit yet in its attempt to become a leading energy exporter. Mr Steinitz said the pipeline might in future be extended to other countries in western Europe or the Balkans.

The minister said he had discussed the plan and other Israeli energy projectswith JPMorgan, Morgan Stanley, Goldman Sachs and other banks and that potential investor interest was enough to “pave the way for a very good and speedy project”.

The proposed project would be the world’s longest and deepest subsea pipeline.

Extending from Israeli and Cypriot offshore gasfields to Greece and Italy, it would run for about 2,200km and reach depths below 3km in places.Yuval Steinitz, Israel’s energy minister, said an initial study showed the project was technologically and financially feasible and could be completed by 2025.

“We are here to start a wonderful project of exporting natural gas from the eastern Mediterranean, mainly Israel and Cyprus, to western Europe,” said Mr Steinitz at a ceremony in Tel Aviv, where he and ministers from the three other countries signed a map of the proposed route and a joint declaration on moving ahead with discussions to build it.

gas available for export within a few years, he added.

“We highly value gas supply from the region that can make a valuable contribution to our strategy to diversify our sources and suppliers,” said Miguel Arias Cañete, the EU’s climate and energy commissioner.

C a r l o C a l e n d a , I t a l y ’s e c o n o m i c development minister, said the pipeline project was “a top priority for our country”.

Speaking earlier to the Financial Times, he said the pipeline would be significantly cheaper to build than liquefied natural gas production and storage facilities, which both Israel and Cyprus have mooted as platforms for their exports.

But the initiative is likely to face industry scepticism amid low gas prices and concerns about political risk and Israel’s patchy record with energy investors.

Leviathan’s development was delayed by more than a year, first by a legal challenge from Israel’s antitrust watchdog and then by a bitter dispute in the government and Knesset over the regulatory framework for gas reserves.

“This is going to be the longest and deepest subsea pipeline in the world.”

However, the project is likely to face tough questions and possible scepticism from the business community amid low gas prices and concerns over political risk.

Israel and Cyprus are promoting their gas reserves as an alternative to Russia and the North Sea, the EU’s two main gas suppliers.

The bloc is trying to reduce reliance on Russian energy and North Sea reserves are depleted.

Israel launched the $3.75bn first phase of its Leviathan gasfield in February and Cyprus recently concluded its third licensing round for offshore blocks.

The two countries had 400-500bcm of gas available for export between them, said Mr Steinitz. The amount so far discovered was “just the tip of the iceberg” and Israel could potentially make more than 3,000 bcm of 27

Giorgos Stathakis, Greece’s energy minister, described Israel as “the most reliable export option”.

Mr Steinitz said the four countries aimed to conclude government-to-government agreements by the end of this year. The ministers would then meet every six months as the project got under way, with a target completion date of 2025.

Israel is also discussing a potential undersea gas pipeline with Turkey, which has an unresolved political dispute with Cyprus over the breakaway Turkish state in the north of the island.

The proposed route would run through Cypriot territorial waters.

energyandecology.com

Issue 4 May 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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energyandecology.com

Issue 4 May 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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energyandecology.com

Issue 4 May 2017

OIL&GAS

Gas in Europe European Energy Security Strategy, which outlined the need to enhance EU resilience to such crises. Alongside diversifying supply routes, the EU seeks to: diversify sources of supply; ensure access to flexible fuel alternatives, such as LNG; and reform internal European markets to allow for greater mutual support – for instance, by enabling pipelines to carry gas in both directions.

Europe’s roadmap for achieving energy security also includes boosting domestic production and increasing the use of sustainable energy.

Russian gas is somewhat of a poisoned chalice for the EU: it is cheaper than almost any other supply Europe could purchase, be they pipeline or LNG imports, yet depending on Russia weakens the EU’s own energy security. One energy expert noted that there is little getting away from this, and that Europe will continue to rely on Russia as its principal supplier of imported gas even if Europe successfully pursues alternative suppliers.

Currently, more than half of all the energy consumed within the EU is imported from abroad, making it heavily reliant on external supply. In the case of natural gas, the proportion of energy imported is closer to two-thirds.

In the two decades between 1995 and 2015, European dependency on natural gas imports rose from 43 percent to 67 percent.[4] Alongside other factors, this was driven by diminished European production, which fell by a Compound Annual Growth Rate (CAGR) of 5.6 percent in the decade between 2005 and 2015.

Germany, Italy, France, Belgium, and Spain are the biggest importers of natural gas, the majority of which comes from Russia, Norway, Algeria, and Qatar.

But Norway’s production is gradually declining and future prospects for Algerian gas remain unclear, because key contracts will end in 2019 and 2020.

Qatar will likely remain an important supplier of Liquefied Natural Gas (LNG) to the EU, particularly to western European states that have the requisite capacity for regasification – the process of converting LNG to gas − in their LNG terminals. But it is Russia that supplies the lion’s share of gas, accounting for around one-third of European gas 32

imports. Member states vary in their dependency on Russia according to internal factors such as domestic production and fuel mix, and external factors such as geographic proximity, geopolitical relationships, and the availability of alternative supply options.

According to the latest figures, countries in eastern Europe such as Estonia, Finland, Latvia, and Lithuania are particularly exposed, as they import all of their natural gas from Russia.

A longtime goal of the EU has been to increase energy security, here loosely defined as the ability to reliably secure access to uninterrupted supplies to meet local demand. Crucial to achieving energy security is ensuring the uninterrupted flow of gas, Russian or otherwise, to Europe. The majority of imported Russian gas currently transits through networks in Ukraine, although pipelines such as Nord Stream and Yamal provide additional security by offering alternative transit routes.

European gas disputes with Russia climaxed in 2014 when Gazprom − Russia’s state-owned gas supplier − cut off exports to Ukraine. This led to severe energy crises in several eastern European states, some of which depend wholly on Russian supplies.

That same year, the EU put forward the

This will be the case particularly if Gazprom reduces its prices further to safeguard its European market share.There is geostrategic value in diversification, but the EU – as a political and bureaucratic body – can only intervene on the policy level and ensure regulatory frameworks allow for the emergence of a competitive market environment.

Whether such markets then meet the EU’s diversification policies depends almost entirely on commercial factors.

The EU may have its hands tied by market dynamics, but it has continued to push forward the political track on diversification.

Some of its initiatives and adjustments have been inward-looking – such as endorsing a shift towards renewables, or making efforts to explore alternative means of European production. The EU28 have been working towards the target of ensuring that renewable energy accounts for 20 percent of the total energy mix by 2020.

This goal has often manifested itself in specific policies that support a market reorientation towards renewables: for example, through direct subsidies for renewables, or through plans to actively decarbonise electricity supply.

These efforts were given a further boost by the COP21 climate deal, which represented a major breakthrough in the international community’s commitment to reduce greenhouse gas emissions.

energyandecology.com

Issue 4 May 2017

OIL&GAS

Azerbaijan To Provide Georgia With Alternative to Russian Gas In 2017 The second was a demand by one of those two factions to establish a parliamentary investigative commission to evaluate the agreement with Gazprom, the website Civil.ge reported on February 23.

It is not only opposition parties that are alarmed by the possibility that the agreement is detrimental to Georgia's interests.

A poll conducted by the International Republican Institute between February 22 and March 8 reportedly found that 58 percent of the 1,501 respondents took a negative view of the agreement, even without knowing the precise terms, InterPressNews reported on April 5. Only 11 percent expressed approval.

Kakha Kaladze, Deputy Prime Minister and Energy Minister of Georgia (file photo).

In reaching an agreement to purchase gas from Azerbaijan, Georgia has both obviated the need to purchase any additional Russian gas in 2017 and temporarily deflected criticism of a recent deal with Gazprom.

The new agreement with Azerbaijan was announced on April 7 by Georgian Energy Minister Kakha Kaladze, who had incurred harsh criticism and faced claims he sold out his country's energy security after signing a two-year agreement with Russia's gas giant in January.

That deal entailed a phased shift from payment in kind to payment in cash of the tariffs Georgia receives for the transit of Russian gas across its territory to Armenia.

Critics of that deal ignore the fact that the volume of gas Georgia has hitherto received from Russia accounts for just under 10 percent of the total 2.4 billion cubic meters it imports annually; the remaining 90 percent comes from Azerbaijan.

In that respect, allegations by the opposition that the deal will result in a budget shortfall and threaten Georgia's energy security are misleading, especially considering that the amount of imported gas in question is consistent with figures from previous years. comparison, in 2015, Slovakia and the Czech Republic depended on Russia for over 90 percent of imports; Germany receives some 30 percent of its gas from Russia.

Cash Payment Kaladze is quoted as saying that, during the first three months of 2017, Georgia received 100 million cubic meters of gas 33

from Russia.

That is the equivalent of 10 percent of the first 1 billion cubic meters supplied via Georgia to Armenia, for which, according to Armenian Prime Minister Karen Karapetian, Georgia was to be reimbursed in kind, with the option of purchasing additional gas at the price of $185 per 1,000 cubic meters.

This year at least, however, Tbilisi will not have to do so. Instead, it has reached agreement with Azerbaijan's state oil company SOCAR and the international consortium currently developing the Shakh Deniz offshore Caspian gas field to supply a total of 2.347 billion cubic meters of gas, adequate to cover its domestic requirements.

The price of that gas has not been divulged.

Meanwhile, Gazprom will pay in cash for the transit of the remaining 1.2 billion cubic meters it is contractually obliged to supply Armenia with in 2017, and for the entire sum due in 2018.

Kaladze has repeatedly declined to disclose the actual tariff, angering the opposition and NGOs that fear unwarranted concessions to Moscow.

Opposition Initiatives The Georgian parliament majority has rejected two opposition bids to force disclosure of the terms of the treaty with Gazprom.

It is still unclear whether, as veteran parliamentarian Gia Volsky has implied, the Georgian government was strong-armed into making concessions in the face of a threat by Gazprom to suspend gas supplies to Armenia via Georgia altogether and instead supply Armenia through an alternative pipeline via Iran.

Azerbaijan-Georgia-Romania Interconnector (AGRI) project Transit projects add great value to the countryâ&#x20AC;&#x2122;s political significance and energy security of the region. Georgia continues to actively support the development of different projects enabling an alternative transportation corridor for the Western markets, such as AGRI and the projects within the Trans-Caspian transport route.

Georgia is a participant of AGRI project.

Georgian Oil and Gas Corporation JSC is assigned as a shareholder of AGRI LNG Project Company, which is a special purpose vehicle incorporated by the project participants.

In April 2015, shareholders of AGRI LNG Project Company approved the AGRI project feasibility study prepared by UKbased Penspen LTD. It is planned to start preparation to apply for PCI (projects of common interest) status.

The first was a draft legal initiative by the two opposition factions into which the former ruling United National Movement split in January to amend the parliament statutes to permit the creation of an interfactional group that would have access to agreements that constitute a commercial secret. energyandecology.com

Issue 4 May 2017

MINING

Top 10 copper mining companies in 2016 2015 (718 kt).

The decrease in production of payable copper in 2016 as compared to 2015 was due to the lower production of cathodes by KGHM Polska Miedź S.A. and lower production in KGHM International Ltd. mainly due to lower processing of ore by the Robinson mine.

C1 cost of producing copper in concentrate reduced by 11%, which was impacted by a weakening in the PLN and savings initiatives undertaken by KGHM. 7. Rio Tinto British-Australian Rio Tinto (LSE:RIO, ASX:RIO) sits in seventh place and increased its attributable mined copper output by 4%, from 504 kt in 2015 to 523 kt in 2016.

Preliminary production by the top 10 copper mining companies compiled by IntelligenceMine totalled 9,448 kilotonnes of copper in 2016.

1. Codelco Chilean state-owned miner Codelco holds first place worldwide in terms of attributable copper mine output with preliminary estimates of 1,827 kt of copper produced in 2016, including Codelco's stake in Minera el Abra and Anglo American Sur S.A, – an approximate 3% decline on 2015 (1,891 kt).This drop was mainly due to lower production coming from El Abra, Anglo American Sur and Andina division, partially offset by higher production in Salvador, El Teniente and Radomiro Tomic divisions.

During 2016, Codelco’s cash cost was $1.26 per pound, compared to $1.39 per pound in 2015.

2. Freeport Headquartered in Phoenix, Ariz., FreeportMcMoRan Copper & Gold Inc. ranks second in global copper competition. It produced about 1,696 kt of copper in 2016 (based on net equity ownership, including discontinued operations), or about 12% higher compared to 2015 (1,514 kt).

This significant growth was achieved because of the Cerro Verde expansion project that achieved capacity operating rates during first-quarter 2016, as well as copper production increase at Grasberg operations currently mining the final phase of the Grasberg open pit, which contains high copper and gold ore grades.

3. Glencore In third place, Swiss-based Glencore International plc with copper production from its own sources of ~1,288 kt (approximate number; efforts were made to 35

calculate attributable Glencore’s total mined copper originated from Copper, Zinc and Nickel Operating Divisions, but due to a complex nature of the company’s assets, the exact figure might be slightly different), which is 2% lower than in 2015 (~1,311 kt), reflecting the production suspensions at African Copper, partly offset by improved grades and volumes at the South American assets.

Glencore’s copper unit production costs were $0.87 per pound in 2016.

4. BHP Billiton Ranking fourth, Anglo-Australian BHP Billiton reduced its copper output by 6%, from 1,179 kt in 2015 to 1,113 kt in 2016 calendar year.This decrease was due to reduced volumes at Olympic Dam, maintenance at Pampa Norte and lower copper grades, as planned, at Antamina.

Significant reduction in C1 cash cost during half-year ended December 31, 2016 was mainly related to the increase in estimated recoverable copper contained in the Escondida sulphide leach pad following commissioning of the Escondida Bioleach Pad Extension project and a US$120 million planned build of mined ore ahead of the commissioning of the LCE project.

5. Southern Copper Holding fifth place, Southern Copper Corporation, a subsidiary of Grupo México, increased its copper production by record 21%, from 743 kt in 2015 to 900 kt in 2016.

This increase was driven by the expansion of the Buenavista mine, which increased its production by + 57%.

6. KGHM

Production increased at Bingham Canyon, but declined at Escondida. The Grasberg mine put out zero tonnes of copper for Rio Tinto last year.

8. First Quantum First Quantum’s record copper production driven by ramp-up of Sentinel, higher Kansanshi volumes with record annual production at Las Cruces, allowed this ambitious company to broke into the Top 10 copper producers list. First Quantum landed eighth in 2016.

Attributable copper production of 494 kt (including discontinued as of June 2016 Kevitsa mine production) was higher than 2015 by 29% (383 kt).

9. Antofagasta Attributable copper production for ninthplace Chilean-based Antofagasta plc in 2016 was 477 kt, a 15% increase compared with 415 kt in 2015.This increase in production was because of the successful integration of Zaldívar and the ramp-up of Antucoya – alongside the completion of the expansion of Centinela Concentrates.

Group net cash costs were $1.20/lb or 20% lower than in 2015. This reflected the lower cash costs before by-product credits, higher gold production and higher realised prices for gold and molybdenum, partly offset by lower molybdenum production.

10. Vale Brazilian Vale is no.10 in the Top 10 list and produced 453 kt of copper in 2016, or 7% more than in 2015 (424 kt).The strong production performance was a result of the record production in both the Sudbury and Salobo operations.

Sixth-ranked Poland-based KGHM Polska Miedź Group produced 677 kt of payable copper in 2016, which is 6% lower than in energyandecology.com

Issue 4 May 2017

MINING

Mined into extinction: is the world running out of critical minerals?

“Importantly, this does not mean that China would run out of rare earth minerals in 20 years; their reserves two decades from now may be the same (or smaller or larger) as they are now, due to increased exploration drilling. However, China is currently is the world’s largest producer of rare earth elements, and so a disruption of that supply for whatever reason would have profound effects on world markets and global industry.”

In 1950, the USGS estimated global reserves of zinc at 77 million tonnes (Mt). In 2000, the US Government announced reserves were up to 209Mt. Tin, copper, iron ore and lead have all experienced similar increases. As for Cryolite, the mineral is still present in small quantities around the world.

In 1987, in the remote mining town of Ivigtût on the west coast of Greenland, an extinction event took place that went virtually unnoticed and unremarked upon outside of geological and mining circles.

Now abandoned, Ivigtût once contained the world’s largest known reserves of naturally occurring cryolite.

First described in 1798, this rare mineral was primarily used in aluminium extraction, but also as an insecticide and pesticide, to make caustic soda and even to give fireworks a yellow colour.

And then in 1987 the mine simply ran out.

Its demise is a reminder of how susceptible mineral supplies are to the dynamics of global demand, consumption and pricing, and the impact they have on mankind’s social and industrial evolution.

“It is very important to understand that neither ‘reserves’ nor ‘resources’ are the same as ‘all there is’,” says Meinhart, so just because a mineral, such as cryolite, is no longer commercially available does not necessarily mean that it is terminally depleted, simply that greater effort may be required to find it.

“World reserves of almost all commodities are greater now than they were 50 or 100 years ago even though large amounts have been produced.

This is because the time value of money leads most companies to only drill out 20 or 30 years’ worth of reserves even though much larger resources might be available.

Some mines have had 20 years’ worth of ‘reserves’ for more than a century.”

Critical levels: is China running out of rare earth metals?

“Many mineral commodities have changed in importance over time,” says Dr Lawrence Meinert of the US Geological Survey (USGS). “In the Stone Age flint was extremely valuable, but obviously the need for flint arrowheads has diminished and thus the mining of flint has stopped.

Similarly, the Romans prized salt very highly, but it’s centrality to the world’s economy is now much less than in the past.

China, home to more than 90% of rare earth production, claims that supplies of metals such as dysprosium, neodymium and lanthanum – coveted for their conductive and magnetic properties, and used in everything from laptops to missile guidance systems – could be exhausted within 20 years, further spooking global commodity markets.

Reserves vs resources: cost, price and technology

Does Meinert share in the Chinese Government’s pessimism?

Meinert is quick to make the distinction between ‘reserves’, minerals identified in location and quantity therefore relatively easy to factor into supply chains and rates of consumption, and ‘resources’, which often cannot be quantified without longterm geologic and geophysical study.

“We can calculate how long stated reserves of rare earth minerals − often referred to as critical minerals because of their importance to modern society − would last at the current rate of production and that number may well be about 20 years, although reserve estimates are not closely constrained,” says Meinert.

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“You can go to Ivigtût today and grab a handful of cryolite; here in Washington DC, the Smithsonian Museum has samples of it.

However, it is a relatively rare mineral and large deposits are uncommon.

The originally defined resource has been mined out and cryolite’s use as a flux has largely been supplanted by synthetic sodium aluminium fluoride, produced from the common mineral fluorite.”

Supply disruption: USGS methodology and import reliance So are any minerals in terminal decline, according to Meinert, and if so, what can we expect in terms of supply disruption and the potential impact on the US and global economies?

“For some commodities there are long-term trends of increasing or decreasing use but the phrase ‘terminal decline’ suggests an irreversible change that ends in zero use − this has not happened for any of the 90+ commodities tracked by the USGS,” he confirms.

“The production or consumption of a particular commodity may go up or go down, but in no case has the world run out of minerals.

“In addition to supply disruption there is the question of import dependence. As documented in the 2017 Mineral Commodity Summaries, the US is now 100% reliant on foreign sources for 20 different mineral commodities and imports the majority of [its] needs for more than 50 commodities.

energyandecology.com

Issue 4 May 2017

MINING

Look at the evolution of mining apps with MiPlan communicated instantly throughout the business.

In regards to managing the fleet, the union allows the businesses to take the best of both fleet offerings and combine them to provide clients with a comprehensive offering, which can be deployed rapidly, is easy to use and simple to maintain. For example, MiPlan had been interested in finding a way to connect to vehicle health systems to collect additional metrics and Hexagon already has this technology, so we have a huge leap forward in this space.

Australian mining app firm MiPlan has its sights set high after being acquired

by IT company, Hexagon Mining. MiPlan co-founder Louise Daw discusses the role of mobile apps in the mining sector today and how they will evolve in the years to come.

Apps have the potential to completely transform mining operations; in the nearterm allowing companies to track their resources at any location at any time, while in the long-view, supporting the implementation of autonomous mining, the industry’s undisputed future.

One company working to bridge the gap between the industry and app technology is Perth-based MiPlan, which offers a range of tools for field data collection, fleet management, production management and reporting.

MiPlan was recently acquired by Hexagon Mining – a software firm that develops integrated planning, operations and safety solutions – in a move the companies hope will help operators make better sense of their data, resulting in safer, more productive mines.

Elly Earls caught up with MiPlan cofounder and project director Louise Daw to find out how apps have already changed the mining sector, and what we can expect in the future.

Why are your mobile apps so suitable for the mining industry?

Louise Daw: Mines are typically remote and outside of network range, but apps can connect the site through a local network so that people can understand what all of their resources are doing in real-time.

Apps can also help remove the need for paper on site. Regardless of whether an operation has a fleet management system 37

(FMS) or not, there is an enormous volume of paper work and follow on data entry effort required – things like timesheets, pre starts, safety hazards and blast patterns.

An operator might go out into the field to do a job and have six or seven pieces of paper with him but by the time it’s been written on paper and somebody’s entered it into a local system, it’s at least 24 to 48 hours old.

It’s an expensive task for a mine to base decisions on old data. Apps give you the ability to know where your resources are at any time and that’s huge for safety and productivity in the mine.

How big a role are apps playing in the mining industry at present?

The mindset of mining companies is starting to change. We are finding now that people are Googling mining apps a lot more and that’s only started to change in the last 18 months. There is a new generation coming through that is embracing the concept of saying ‘There should be an app that exists for this problem’.

Our mobile solutions cover the full mine lifecycle, including manual activities meaning an operation can maintain and manage all the data collected from the various apps in a single platform. For apps to succeed at mine sites, this must be the way forward.

What key benefits will Hexagon’s acquisition of MiPlan bring to both companies’ clients?

Apps are only as good as the systems they are connected to. The mobile apps MiPlan has developed are dependent on highquality design and scheduling information.

The Hexagon acquisition means design applications and apps can be linked directly allowing changes to the plan to be

We have also been interested in providing solutions with a low or no network cost setup. Hexagon already has a peer to peer network solution which is in use across 25,000 units around the world meaning another leap forward in the capability of our apps and our overall platform.

In five years’ time, how big a role will apps play in the mining sector? What will they be capable of?

I think that everybody who’s working in the software industry in mining knows that the real focuses for the future are predictive maintenance, fleet optimisation and, the big one, autonomous mining. Apps will play an instrumental role in progressing those three areas.

Apps basically collect and present data to the right people in a timely manner so they’re able to start making proactive decisions. As the scope of the apps increase and we’re able to interface with additional planning tools from Hexagon, employers are going to be further empowered with having real-time planning and information updates, so they can ensure that there is continuous business improvement and optimisation.

Moreover, because you’re going to have apps and sensors available in nearly every single activity involved in the mining lifecycle, you can take all of that data and blend it into valuable information on which to base predictive analysis, machine health management and also improved fleet optimisation.

Apps that create and maintain their own peer-to-peer network and can be connected to the machine is the first step towards a realistic vehicle intervention model, the gateway to autonomous mining.

That’s where it’s going and that’s where we want to take the apps.

energyandecology.com

Issue 4 May 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.

Solid construction with high-grade materials such as chromium steel and silicon carbide means the Grundfos DW range of dewatering pumps is ideal for pits, for temporary or fixed installation, and offers high-pressure pump performance unhindered by sand or other abrasives. Solid cast iron construction and narrow design characterises the Grundfos DWK range of dewatering pumps, and this range can pump small stones at greater flow than the Grundfos DW range.

www.adara-bg.com Bulgaria, 1784 Sofia jk"Mladost-1', bul. Andrej Saharov, bl. 75A, ap.2 tel.: + 359 2 974-49-38 fax: + 359 2 974-40-38 GSM: +359 889 161 000; +359 878 405 888 office@adara-bg.com

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energyandecology.com

Issue 4 May 2017

MINING

Scoping Australia’s mines with the latest drone technology The UAV can also operate adequately without GPS. “Drones usually need GPS assistance to be stabilised during flight, but in certain places this is not always possible; for example, under a bridge, inside of a building or in an underground mine,” says Honda “Terra uses its SLAM [simultaneous localisation and mapping] system to stabilise the drone’s flight when there is not GPS available.”

The company also manufactures the Terra Explorer series; a collision-tolerant drone designed to accurately collect data from hostile environments, such as inside oil and gas plants. The explorer drone’s flexible shell design enables it to fly safely through hazardous areas, without getting crushed or damaged as easily as a traditional drone.

Drones are increasingly being used to map, survey and explore Australia’s many operational and abandoned mines. Japanbased specialist unmanned aerial vehicle (UAV) manufacturer, Terra Drone, has opened its first office in the country and is hoping to take the mining market by storm.

Terra’s Tsuyoshi Honda discusses how the company’s technology can access Australia’s mines.

Australia is home to some of the world’s largest open-pit and underground mines and has thousands of abandoned mine sites. In recent years, both the government and operators have been keen to exploit the benefits of drone technology to safely collect data and explore abandoned, or legacy, mines.

In the Northern Territory, for example, where mining dates back to the1860s, legacy mines are a major problem with estimated liability costs of more than A$1bn. The government has started using drones to inspect these abandoned mines to help aid remediation efforts.

In January, Minister for Primary Industries and Resources, Ken Vowles, said that drone technology can reach otherwise inaccessible areas of the mine, producing digital terrain models that give operators a better perspective of the site.

Despite advances, drones still have their limitations, such as the number of sensors they can carry and low in-flight battery time.

supporting Australian mining operations.

The firm is the number one drone provider in Japan, according to Honda, and is a spinoff of Japanese electrical scooter manufacturer, Terra Motors.

Terra Drone’s Laser Drone model is equipped with light detection and ranging (LiDAR) laser technology. It can perform surveying, data capture, and 2D and 3D mapping.

Honda says , the drone, which can carry up to 10kg of payload and fly for two hours continuously, is the only UAV hardware that can integrate the Riegl LiDAR, what he calls the highest quality LiDAR system in the world.

“The LiDAR is heavy but because the drone can carry a larger than normal payload it can be integrated into our special hardware,” says Honda.

Furthermore, it is usually hard to collect relief data from steep surfaces, but, compared with a ground laser scanner, the LiDAR can effectively do this using the UAV. The Laser Drone is also equipped with Terra UTM software, enabling an operator to manage multiple UAV missions simultaneously or to control the UAV, if needed.

Greater range and flexibility of drones

Utilising LiDAR technology

The UAV can travel 100ha per trip, says Honda, come back, refuel and be sent out again, to cover a total of more than 700 ha in one day.

Terra Drone has one of the most advanced UAVs to date, says Tsuyoshi Honda, the branch chief of the company’s first office in Australia, adding that it is ideal for

The technology was used to explore and survey areas of the Fukushima nuclear power plant left inaccessible to humans after the 2011 disaster.

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New ways to explore underground mines Honda is reluctant to say too much but confirms that the company is planning to introduce a drone for scanning and modelling Australia’s underground mines.

“It is a very dangerous area so we want to integrate our specially designed drone with a 3D scanner and provide process data for each customer,” says Honda.

“It is not safe for a human inspector to enter every part of the mine, because it is small, dark and dangerous, and possibly filled with gas, but this kind of drone can fly there without human operation – so it is very safe for the mining companies and a good solution.”

Any data collected by the drone can be used for planning and mine management.

“This is a unique solution for the mining industry that will either be remotely controlled or operate autonomously,” Honda adds.

Since setting up in Brisbane just two months ago, Honda says Terra Drone has made a big impact on the Australian mining industry and has its sights set on expanding its remit.

To this effect, the company is targeting the Australian construction sector and, at the end of the July, is conducting a demonstration for the Queensland Government surveying the Great Barrier Reef. It is also looking to establish a research and development initiative with an Australian university.

energyandecology.com

Issue 4 May 2017

MINING

What is the future of coal power in Europe?

Market conditions In addition to policy factors the market environment for the power sector in Europe is pointing towards continued decarbonisation. With electricity consumption remaining stagnant and growth in renewables generation continuing, coalfired power has been edging back in the last three years.

Furthermore, the collapse of oil-indexed natural gas prices has caused a rebound in gas generation since 2015, adding further competition for coal in the electricity sector.

Coal was once the prime source of power generation in the European continent, but over time this source of energy has lost ground as nuclear power, natural gas and more recently renewables have expanded their share of the region’s power mix.

efficiency), its emissions trading scheme (ETS), and air quality directives are having an impact on coal usage among European utilities. EU proposals to strengthen the efficacy of the ETS, and to limit the ability of coal plants to receive state subsidies to remain operating as back up for renewable power, will force the retirement of some coal capacity in Europe. Industry compliance with air quality directives aimed at reducing pollution from industrial establishments will also have this effect.

In the early 1990s coal accounted for around 40% of EU power generation, but this has since fallen to below 24% in 2015.

Due to a considerable fall, last year in coal generation in the UK, and modest falls in Germany, Spain and the Netherlands, the share of coal in Europe’s power mix will have fallen further last year.

National level policies

While coal generation did experience a modest uptick in the early part of the decade – due mainly to higher natural gas prices – since 2013 coal generation in Europe has been in consistent decline.

EU policies have set the framework for a lower emissions-intensive electricity system in Europe, but the fortunes of coalfired power will also depend on the policies of member states towards coal generation.

This trend is expected to continue due to a range of policy factors and market conditions that are combining to make the outlook a difficult one for coal generation in Europe.

The UK has seen a dramatic reduction in coal generation in the last four years, mainly the result of the introduction of its own carbon price floor. Furthermore, the UK has also pledged to phase out unabated coal generation by 2025.

While it is unlikely that coal in Europe will be completely phased out in the short to medium term, coal producers and exporters will be increasingly relying on growing economies Asia, rather than on high income OECD economies in Western Europe and North America, for future market prospects.

EU Policies Although the EU does not have a direct policy on coal generation, its 2020 and 2030 climate and energy targets (covering emissions, renewables and energy 40

Other countries, such as France and Finland, have also pledged to phase out coal by 2023 and 2030 respectively (although coal only comprises a small share of their power supply in both cases), while the Netherlands and Germany are also taking steps to reduce coal capacity as well.

Due to stagnant demand and additional renewables generation, falling wholesale power prices have made the market environment tougher for coal plants in some cases, with one German utility, STEAG, announcing in November last year that it may have to close 5 hard coal units in Germany because of “changes to the market environment brought about by energy policy and the persistently low electricity price level.”

Announcements such as this could become more frequent if European states continue to push for de-carbonisation of their power systems. Another company, Dong Energy, stated in February that it plans to cease using coal for its power stations by 2023.

Already more than half of Europe’s power generation is sourced from non-fossil fuel usage (renewables and nuclear), a share that is much higher than in the US, China, India, Japan, and Australia.

This share is likely to continue to grow going forward. If coal power is to remain a significant feature of Europe’s energy system older plants will need to be retired and replaced by more efficient, less emissions intensive modern plants, and they will need to be equipped with carbon capture and storage technology.

Given that the EU targets a cut in emissions by between 80 and 95% from 1990 levels by 2050, achieving this goal means that this will be the only way that coal-fired generation can maintain a role in Europe’s power mix.

Coal capacity has been falling gradually over the last decade, and with little new capacity expected to be constructed in the region we expect total capacity to continue to fall further (especially in Western Europe). energyandecology.com

Issue 4 May 2017