The Martabe Gold Mine is managed and operated by Singapore-based PT Agincourt Resources, while Sewatama is one of the leading energy service providers in Indonesia.

With an area of 2500 square-kilometres, Martabe is roughly double the size of Los Angeles and has an annual extraction capacity of approximately 4.5 million tonnes of gold and silver ore. The energy-intensive processes in extracting and treating the valuable raw materials require a reliable and permanent power supply.

However, Indonesia’s state electricity supplier Perusahaan Listrik Negara (PLN) cannot guarantee this supply on account of the remote location in the Indonesian mountains and a patchy transport grid. PLN is therefore implementing an independent solution to produce electricity where it is needed, in the immediate vicinity of gold mine.

Off-grid power generation

The four-stroke MAN engines, once installed at Sewatam’s 24 MW offgrid power plant at the Martabe mine, will eliminate an acute energy bottleneck. Moreover, the will also help ensure a stable supply to cover the requirements of the mine in Batang Toru province in the north of the Indonesian island of Sumatra.

"Our engines solve energy bottlenecks on location and secure an economically viable, stable power supply for industrial plants also in remote locations, such as here in the Indonesian mountains," explains Massimo Casal, Sales Manager of MAN Diesel & Turbo in Indonesia.

Decentralised supply grids

With over 250 million inhabitants, Indonesia is the largest economic region in south-east Asia. With an annual growth in gross domestic product of 4-5%, power requirements are rising. The government in Jakarta in 2014 announced a comprehensive expansion programme of the national electricity network. The government's aim is to increase Indonesia’s overall available power supply by 35 gigawatts by 2019.

"The current development on the Indonesian energy market is of particular interest to us. Owing to the geographical structure – Indonesia is the largest island state in the world – many small and decentralised supply grids are required. With its wide-ranging experience of island power plants, MAN Diesel & Turbo has the right solution both for industrial applications and for local network operators," says Massimo Casal.

MAN Diesel & Turbo currently employs 20 staff in Indonesia and in recent years has delivered engines with a total output of 158 MW to the country.

“The future grid will have to deal with differences from country to country in terms of mixes of centralized vs. decentralized, and regulated vs. unregulated sources of renewable, fossil and nuclear energy.

“Cloud computing, machine learning and autonomous subsystems will become a necessary part of the management of this increasingly complex system that must remain robust and secure,” he explained.

Asked what technologies offer the greatest hope for a sustainable energy future, Mr Chu called on utilities to focus on energy sources that are inexhaustible. Notably heat pumps, photovoltaics, solar thermal and biofuels.

In his view, the industry is to developing affordable batteries that will allow for greater deployment of renewable energy sources and can also power plug-in hybrids and all-electric vehicles.

Siemens, conducted the interview with Prof Chu to position itself, who said the German engineering conglomerate would be one of the few companies in the world that have the opportunity to become a “complete solution provider to a cleaner energy future.”

Natural gas supply for the new-build will be available from Ghana National Gas Company and West Africa Gas Pipeline, Amadi Energy said, adding that it will initially source light crude oil to fuel the plant from nearby Volta River Authority’s single point mooring facilities which allow for the pumping of oil from tankers offshore.

The Amandi Power Plant is being constructed on a 25 hectare site approximately 1 kilometre west of Aboadze and 12 kilometres from Ghana’s western regional capital of Takoradi. The site is close vicinity to three thermal plants run by the Volta River Authority, which means that considerable service infrastructure is already in place (see map).

Once operational, the turnkey power project will help tackle Ghana’s persistent energy deficit and provide much-needed stable electricity supply to nearby industry and household offtakers. To that end, the 200 MW plant will be powered by GE’s 9E.04 gas turbine with tri-fuel capabilities. The rugged 9E can burn more than 50 types of fuels and can switch between natural gas, distillate and heavy fuel oil while operating under full load. This particular turbine has features that help reduce fuel costs and increase revenue, such as a 145 MW output and 37% efficiency in simple-cycle.

Amandi Energy Ghana’s general manager Boaz Lavi called GE’s fuel capabilities unmatched. “Having a turbine that is able to switch between fuels can provide increased plant operability allowing for power generation months before the indigenous gas supply would otherwise be available,” he said. “This is crucial in helping Ghana meet its growing power needs.”

GE’s scope of supply for the turnkey project also includes the steam turbine, heat recovery steam generator (HRSG), associated balance of plant, and 7-year CSA.

In Ghana, GE has been working with the government and corporate customers to support economic growth through infrastructure development in the power, healthcare and transport sectors. In 2014, GE opened a 200-capacity permanent office in Accra, and now has over 80 employees – 95% of which are Ghanaians.

Looking at the electrification of transport, she pointed out that the Netherlands was the sixth country in the world to reach 100,000 electric vehicles (EVs). “The long term plan is that, from 2035, only clean-fuel cars can be sold – a target that is more than achievable and will provide a substantial reduction in carbon emissions. At Royal HaskoningDHV, we’re piloting an EV fleet of 26 cars – saving up to 100 tonnes of CO2 every year,” she said.

However, this move towards EVs means a huge rise in electricity demand. The European Environment Agency estimates that EVs could account for 9.5% of European electricity demand by 2020 – up from 0.03% today.

“Governments are aware of this – perhaps it’s why many are reluctant to accelerate the phase-out of coal. It’s up to the renewable industry to step forward with solutions and campaign for change,” Zwickels commented.

As for the electrification of heating, she outlined the Dutch government initiative to scrap gas for domestic heating and cooking by 2050 under its recent energy strategy. At the moment, the plan is thwarted by a legal requirement for DNOs to connect new housing developments to the gas network. Two political parties have submitted a bill stating that this requirement must be removed, allowing developers to save on costs and build cleaner, electric-only, gas-free neighbourhoods for the first time.

It is still open how the renewable industry will respond to this, but Zwickels hope that the industry will step in with bold propositions for distributed energy, so that the extra demand can be met by clean sources. Bringing in partners from the smart technology space could also help.

“The opportunity exists to show the world that a gas-free future is possible, and that it can benefit consumers,” she said, calling on the industry to “be part of these major changes from the outset – the challenge is to identify, then give our backing to the most important ones.”

Renewable finance

Subsidies have been hugely successful in getting renewable sources off the ground. In the Netherlands, the Stimulation of Sustainable Energy Production (SDE+) scheme has been “a great triumph”; so much so that last year’s €9 billion funding has been increased to €12bn in 2017.

“Subsidies are, however, not the only answer and weren't designed to be long-term. What’s more, they are vulnerable to political changes and can have negative, unpredicted side effects on the transition,“ Zwickels commented.

Despite its overall success, the SDE+ scheme currently favours the most profitable technology. This has led to increased funding for biomass substitutes in coal fired plants, meaning that solar and wind energy is competing with subsidised fossil fuel plants, which is a step in the wrong direction.

There are other ways that governments can provide support:

·         Tax on renewable energy production could be cut to give suppliers a competitive advantage.

·         Alternatively, fossil fuel industry tax revenues could be used to fund renewable energy projects, as well as schemes to mitigate the negative effects of non-renewable energy generation.

“The challenge is to move away from public funding. But when developing new financing methods, we should be aware of the challenges – renewable energy projects have higher risk profiles, longer-term ROI and relatively complicated division of profit,” she said, with reference to a number of innovative sources of finance that are used in the Netherlands, e.g. revolving funds, crowdfunding and financial participation.

The province of Overijssel, for example, has experimented with issuing equity and debt in renewable energy schemes, raising funds without subsidy and has now started an arrangement for measures at a domestic level.

Ms Zwinkels works as consultant at Royal HaskoningDHV and is also on the advisory board for POWER-GEN Europe and Renewable Energy World Europe that will be held in Cologne, Germany, from June 27-29, 2017.

By doing so, the two partners aim to unlock the full potential of the UK gas network to distribute renewable and low carbon alternative gases.

“We believe gas has a key role to play as an affordable and cleaner energy source. However, times have changed and renewable gases are increasingly being introduced into the grid, requiring more accurate billing methodologies,” commented DNV GL’s regional manager UK & Ireland, Hari Vamadevan.

The project with National Grid, in his view, will give “new insights on the financial consequences of new billing methodologies for gas consumers, and will help give confidence in gas pricing based on energy content.”

David Parkin, director of Network Strategy at National Grid Gas Distribution, added: “OFGEM’s decision to award National Grid £4.8 million for this programme reflects how serious the UK’s gas grids are about delivering low carbon heat, as well as delivering a sustainable gas future which works for consumers as well.”

The United Kingdom has been dependent on North Sea gas since the 1970s, with regulations and billing regimes designed for this source of gas. However, the supply market is changing rapidly with LNG imports making up 18% of supply already back in 2015.

By 2030, hydrogen, biomethane and bio-substitute natural gas from a large number of sources are estimated to account for up to 10% of domestic gas usage – hence the UK gas distribution network has to be able to accommodate the “differing constitution”.

At Gastech, held in Tokyo in early April, Wärtsilä together with marine design consultancy Houlder and hose supplier Trelleborg showcased a system transferring LNG from the carrier vessel to shoreline terminals where no jetty exist. For island nations and other coastal communities around the globe, the transporting and bunkering of LNG is becoming increasingly important as a means to fuel distributed power stations.

Distributed power stations in off-grid locations tend to be often fuelled by LNG, which can be delivered to site via small, dedicated LNG vessels.

Case study Aruba

 In Aruba, a Caribbean country situated just north of Venezuela, energy is needed for three main industries: tourism, aloe export, and petroleum refining. There is no LNG import terminal on the island and the government plans to step up the share of wind power and add some solar PV installation.

However, the steep rise in electricity demand for air conditioning, combined with switch to LNG-fuelled cruise ships has prompted Wärtsilä to calculate Aruba’s future demand as approximately 81.1 million cubic metres of gas or 62,400 tonnes per annum of LNG.

To import LNG to Aruba, one can as of October 2016 benefit from the AES Andres LNG terminal in the Dominican Republic which now offers reloads to small-scale LNG carriers. Alternatively, importers are counting on the the 138,500 m3 Golar Arctic – moored as a floating storage unit (FSU) offshore Jamaica – to be made available as a supply point for other small-scale LNG projects in the Caribbean.

Once LNG supply is in place in Aruba, flexible gas-fired power stations can be more easily run on the island.

Cooperation on small-scale LNG with Engie

Together with Engie of France, Wärtsilä is working on four work streams: LNG-to-Power solutions, LNG distribution in islands and remote areas, a LNG for ships, and small scale LNG and bio liquefaction.

The Finnish-French energy partnership was forged in November 2016, when senior executives signed a memorandum to “co-develop technical solutions that would enable both Wärtsilä and Engie to expand their small scale LNG businesses.”

Since then, the two companies are working on projects for a low-carbon economy: Wärtsilä is bringing to the table is its technical expertise and Engineering, Procurement and Construction (EPC) capabilities, while Engie’s builds on its experience in natural gas distribution and commercialisation.

Pilot projects in Finland

Back in Finland, Wärtsilä’s home market, the manufacturer works as EPC contractor for the onshore Manga LNG terminal, and has also delivered several small-scale power barges and a biogas liquefaction plant. The cooperation with Engie is meant to help replicate similar projects in Europe, the Americas and Asia.

Engie has pioneered the development of small-scale LNG to remote customers; its focus is on small liquefaction plants; LNG truck loading, bunkering and fuelling, and not least LNG for power applications.

The benefits of electrification, in his view, will be “recognized” – not just in helping reduce carbon emissions, but also offering significant cost and efficiency savings. “Through electrification, we can make energy production cleaner, more robust and sustainable. Electric machines are more efficient, more capable and require less maintenance,” Zhang explained.

Cleaner system for LNG and marine applications

General Electric has a steep history in electrification, going back over 100 years and stretching across the company’s multiple business segments. For example, GE has developed electric-drive compression systems for LNG projects which provide an alternative to mechanically driven devices, powered by gas itself or other fossil fuels.

“Electrified LNG infrastructure holds the key to transforming LNG production by making it cleaner and more efficient. It helps LNG production plants to meet the stringent environmental and carbon emission standards expected,” says Richard Zhang, technology executive, GE’s Power Conversion.

Looking to the marine industry for a further example, GE’s Marine Solutions’ power take off and power take in (PTO/PTI) technology harnesses the mechanical energy of the vessel’s propulsion shaft to convert it into electrical energy.

“The shaft generator motor, installed between the engine and the propeller, can either contribute to propulsion power with onboard power generation or ‘absorb’ power from the rotation of the propeller shaft and redirect it to onboard systems. Therefore, it diminishes the need to burn fuel to power onboard systems and resulting in significant fuel savings,” he said.

Using new materials for electric components

Silicon Carbide (SiC), a synthetically produced crystalline compound of silicon and carbon, is now being used as material for electric components to help increase efficiency. SiC-based power semiconductor devices are just one possible use.

First discovered in an attempt to produce artificial diamonds, SiC shares many of its characteristics such as strength and resistance to high temperatures.

“These features, combined with electrical conductivity with 10 times faster switching and heat losses reduced by half, make the material the ideal substitute for traditional semiconductors,” according to Zhang, who thinks SiC has “the potential to completely transform the power conversion methods used today.”

Intelligent machines increase productivity

Adding intelligence to machines increases productivity and efficiency. In GE’s Brilliant Factories, it is optimizing performance by embedding sensors throughout all machines and operations. This allows them to work efficiently and intelligently with increased speed, less waste and decreased unplanned downtime.

From the shop floor to equipment performance, electrification is in expansion and while some of the benefits are already being felt, GE’s Mr Zhang underlined “the development in the industrial world must be accelerated.”

Under the order, Siemens will act as general contractor for Vattenfall to build and start up the CHP; the order also comprises a long-term service agreement covering the gas turbine-generator set.

The scope of supply includes the major components, i.e. the gas turbine, steam turbine and two electrical generators, all to be fabricated at Siemens manufacturing plants in Berlin, Görlitz and Erfurt. Siemens will also supply the heat recovery steam generator. The unit is to be erected in a multi-shaft configuration, and will achieve a fuel efficiency rating of approximately 90%

Gunther Müller, Speaker of the Managing Board of Vattenfall Wärme AG in Berlin said the utility’s district heating systems help achieve climate neutrality in Berlin. “The new combined heat and power plant in Berlin's Marzahn district will play a major role in these efforts, ensuring reliable, climate-friendly district heat for the coming decades and assuming the duty of base-load power plant for the district heat supply networks in the eastern part of the city," he said.

Plans for the Marzahn CHP are part of the 2009 climate protection agreement between Vattenfall and the Berlin Senate by which Vattenfall committed to half its carbon emissions by 2020, based on the 1990 benchmark.

Willi Meixner, CEO of Siemens' Power & Gas Division added that “environmentally friendly gas-fired cogeneration plants like Berlin-Marzahn can play an important role in pursuing the energy turnaround in Germany and urban centers around the globe."

To meet versatile requirements, AG&P designed a small-scale LNG carrier (LNGC) – a workhorse to meet delivery challenges posed by shallow rivers and restricted harbours. To that end, the vessel is capable of both self-propulsion across open waters and the ability to de-ballast to two meters or less, whilst fully laden with its cargo of LNG.

Cargo capacity of the vessel is scalable from 4,000 cubic metres to 8,000 cbm, allowing access to restricted harbors so that the vessel can travel near shore or receive LNG cargo from FSU anchored offshore.

The ultra-shallow draft LNGC has a delivery time of approximately 14-16 months from order placement based on existing design specification.

Modularisation helps the Philippines-based company speed up delivery times. AG&P says it “builds the infrastructure in Lego-like pieces.”

Product design and production is carried out at AG&P’s two manufacturing facilities, situated some 80km south of Manila. The production sites span 150 hectares of land where the company produce 125,000 tons of assembled modules per year.

Over the years, AG&P has modularized refineries, chemical, petrochemical, power and water plants, LNG apparatus, mining systems and offshore topsides.

Putting a positive face on it, the man at the helm of Rolls-Royce underline the firm made “good progress in cost cutting and efficiency programmes.”

The drop in free cash flow is, however, a reflection of the higher volumes of large engines sold at a loss. Hence the H1-2017 profit is anticipated to be of a similar proportion to that achieved in 2016.

Priorities for 2017 are fourfold: focus on engineering, operational and aftermarket excellence; to sustain the transformation programme; rebuild trust in the firm’s long-term growth prospects; and, deliver an update on our long-term goals.

“We remain on track to deliver the expected year-on-year incremental cost savings in 2017 of between £80-110m and achieve our target of £200m per annum by the end of 2017,” Mr East pointed out.

Still, Rolls-Royce’s 2017 outlook excludes the effect of volatility at the foreign exchange, notably regarding the value of the British pound against the US dollar and the Euro. “If FX rates remain unchanged from those seen recently, the impact (…) on our overseas subsidiaries results would improve reported revenues by around £400m and improve reported profit before tax by around £50m,” the firm said in an investors’ note.

The acquisition of a 53.1% share in ITP, currently owned by SENER of Spain, was cleared by the European Commission on April 19. Completion of the deal remains subject to approval by relevant Spanish authorities, expected later in 2017.

“Energy is an engine for development,” REA’s Project Identification Manager Elineema Mkumbo said, underlining the agency’s legal mandate to provide fund for such projects.

Tanzania aims to get most villages connected to the central electricity grid or advance decentralized power generation for remote rural areas. Development partners from Sweden, Germany and Norway, accompanied Mkumbo on visit to biogas producers and refiners in Simanjiro district.

Mini-grid electrification in rural areas enjoys special support the Swedish International Development Agency (SIDA) Programme. Initiatives have sprung up to help people to access energy through mini-grid extension. 

Government aims to close power deficit 

Tanzania is at the brink of an energy crisis. Ambitions are riding high, seemingly despite all odds, and the government stays optimistic it can close the 1,290 MW power deficit and achieve its goal of generating close to 2,800 MW by the end of this year.

At present, Tanzania can draw on 1,490 MW of installed capacity but the National Five-Year Development Plan, which ends this year, seeks to reach a target of 2,780 MW. Peak demand currently is only 900 MW, but many regions only sparsely electrified. At present, just 24% of Tanzania's 45 million population is connected to the power grid, but this is expected to rise to 30% by the end of next year.

To improve gas supplies to existing gas power plants, the government in mid-2015 freed up $1.2 billion (Tsh.2.4 trillion) that is partly used to build a gas pipeline from Mtwara to Dar es Salaam while the remainder goes towards the construction of a power plant at Kinyerezi in Dar es Salaam.

Payment is another issue: Independent power producers such as Sonagas have repeatedly called on the national grid operator TANESCO to settle outstanding debts and pay them on time for the provision of contracted electricity to the grid. Otherwise, Sonagas may opt to gradually suspend operations at its Ubungo power plant.

Technical experts at TANESCO warned of an imminent power crisis due to rising operational costs during the winter season. The state-owned utility is allegedly operating at a loss since domestic electricity tariffs were lowered as of February 2015, as it covers part of its oil and gas needs through costly imports.

"Producing hydrogen via renewable energy is not a new idea. Still, the vast majority of this industrial hydrogen is produced from coal gasification or SMR, both highly energy-intensive and polluting technologies," he commented

Breaking hydrogen out of water through electrolysis is a technology that is currently much less used; but it can when using cheap hydropower in regions such as Norway and Iceland, or wind and solar power.

Competing on price and runtime hours

“Price is not the only consideration however,” Mr Philibert pointed out. “To be competitive, the electroylzers would have to have relatively high utilization factors – that is, they would have to run for several thousand hours per year.” But under the right conditions, e.g. in the agriculture sector, electrolyzers can have massive consequences for sustainability.

About half of industrial hydrogen is used in ammonia production. Ammonia production alone is responsible for about 360 million tonnes of CO2 emissions each year, or about 1% of the world’s total emissions. By 2050, we expect that the consumption of ammonia will increase by around 60%, according to IEA estimates.

The best of both worlds – places with low prices and a high ulilization factor – can be found in sunny, windy regions with the right combination of solar plants and wind farms.

“Some of the areas with the best resources, in China and in the US, are far from fertilizer demand centres but both electricity and ammonia could be transported. Other places, such as Western Australia, Western Sahara, the horn of Africa or Patagonia to name some, may also be very far from demand but they offer large sparsely-populated areas and have access to oceans. In that case, ammonia plants would likely be sited directly next to the electrolysers,” he explained.

Use as future energy carrier, CO2-free fuel

Future use of ammonia includes stand-alone use as carbon-free fuel or as an energy carrier to store and transport energy or else as a process agent in CO2 emissions-free steelmaking.

“The market for climate-friendly hydrogen generating technologies can only expand in a world striving to mitigate climate change,” Mr Philibert said, underlining that “SMR with CCS remains an economic option. However, as many countries are considering how to produce synthetic methane or other hydrocarbons from renewable hydrogen – exactly the inverse of SMR – manufacturing ammonia with renewables-based hydrogen is the simplest first step.”

Assuming that Indonesia’s electricity demand will rise by nearly 9% a year, following through with the 35GW of capacity addition would boost Indonesia’s electrification ratio to over 90% by 2020.

Despite the short timescale and bureaucratic hurdles surrounding land acquisition, Indonesia’s growth targets present an opportunity for foreign energy companies. The government in Jakarta has put processes in place to help foreign investors by cutting the time it takes to acquire permits from around two and a half years to just eight months.

Fast delivery, local content

“To achieve its goals, the government will require agile and efficient work by foreign energy companies, said Arka Wiriadidjaja, sales manager at GE’s Power Conversion.

To put this into context, a coal plant—currently Indonesia’s dominant energy source—takes four to five years to construct. So, given the five-year window, there is little margin for error.

“This means that energy companies with a strong local presence will be preferred, as they will have an established local supply chain, which meets the local content requirement,” he said, explaining that depending on the generation type and the size of the plant, the local content initiative can require up to 60%of components to be locally sourced.

Regulated power prices

The Indonesian government also fixes the price per kilowatt-hour and therefore, subsides the gap between the true cost of energy and the price it is bought at. Because of this, the cost of energy needs to be kept to a minimum.

In order to meet these stringent cost requirements while also delivering reliable, high-quality energy, innovative technology needs to be deployed. Solar power and flexible gas generation spring to mind – both fuels have the potential to challenge, if not reign in, Indonesia’s dependency on coal power.

To that end, eThekwini’s contracted ABB of Switzerland to strengthen the resilience of its existing back-haul network. 80 wireless mesh routers have been installed, connecting 30 substations across industrial complexes with more than 35 router nodes mounted on streetlights.

ABB Ability, a digital initiative of the Swiss company, and its partnership with Microsoft, is meant to leverage Azure as the cloud for its integrated connectivity platform. The new system has been designed to support Internet Protocol (IP) linked services such as Supervisory Control and Data Acquisition (SCADA), metering and future video and Voice over Internet Protocol (VoIP) applications, which will improve efficiency and connectivity.

Monitoring power assets

Power assets can now be closely observed by the operator, with the higher visibility enhancing operational control and reliability of electricity supply, transmission and distribution across the city of Durban.

Large industrial complexes, in particular, benefit from better visibility and management of their decentralised power generation assets, which helps prevent electrical network outages and provides a platform for smart metering.

“This pioneering smart city solution is an important reference for the African continent where eThekwini will benefit from increased connectivity and real-time visibility of their power network, and have better control of their assets to deliver reliable power to consumers” commented Massimo Danieli, head of ABB’s Grid Automation business.

The certification verifies that the Wärtsilä 34DF engine complies with the EPA emission standards in gas mode operation. As required, the engine is equipped with a continuous nitrogen oxide (NOx) measuring and monitoring system for verifying emissions compliancy inside NOx Emission Control Areas (NECA). Outside of that area, the fuel-flexible 34DF engine can also run on conventional marine diesel.

Category 3 relates to engines with a displacement per cylinder of greater than 30 litres. For marine applications, it is manufactured in configurations from 6 to 16 cylinders covering a power range of 2880 - 8000kW.

According to Wärtsilä, these are the first Category 3 Tier III certificates issued by the EPA to any manufacturer. "Once again Wärtsilä technology is leading the way to greater environmental sustainability and a cleaner shipping industry," commented Patrik Wägar, product director, Medium Bore Engines.

Ms Good explaining that by retiring coal plants and bringing on more natural gas and renewables, the utility since 2005 curbed carbon emissions by nearly 30%.

To achieve this strategic goal, Ms Good is implementing steps that will increase the share of gas power generation to 35% of Duke Energy’s power plant portfolio over the next ten years. Moreover, the share of solar, wind and hydropower combined will grow to approximately 10%, she said.

“Today, we are among the top five companies in terms of renewable capacity, and we are committed to doing more," Ms Good told investors last week in during the company's first online shareholder meeting.

Infrastructure spending

Grid investments also will enable higher levels of renewable energy. Duke Energy's planned $25-billion modernization of its energy grid – the largest grid in the U.S. and "a critical part" of the nation's infrastructure – will provide "improved reliability and the services customers expect," Good said.

"The cornerstone of our comprehensive grid investment is Power/Forward Carolinas, our $13-billionplan to upgrade and strengthen our system in North Carolina."

In 2016, Duke Energy completed the sale of its Latin American assets and the acquisition of Piedmont Natural Gas – a move that the CEO hopes will help ensure future financial strength and stable earnings growth. “"With our portfolio transition complete, today's Duke Energy operates as a premier regulated energy company, focused on delivering value for our customers and growth for our investors,” she said.

To improve customer satisfaction, Duke Energy says it has reduced rates to levels below the national average; moreover, it is offering customers outage alerts, usage updates and free home energy audits.

Industry groups like the Association of Decentralised Energy and UK Power Reserve warn that withdrawing embedded benefits threatens to undermine the flexibility of the UK power system and could cause power shortages in the coming winters.

Small gas and diesel-fired plant (with up to 20 MW capacity each) have “taken on a vital role in stabilising the power grid”, they say, as the contribution of larger coal and nuclear plants shrinks due to shut-downs.

The Association of Decentralised Energy, which represents CHP operators, said that removal of these benefits from so-called captive power plants that are run by energy-intensive industries would raise their electricity costs by up to 20% and threaten jobs.

Brawl over embedded benefits

Disputes over subsidies for small-scale generators exemplify the growing tension between energy utilities, regulators and the government over the best way to bring about much-needed investments in Britain’s ageing energy infrastructure.

Distributed generators cash in on £45/kW in embedded benefits in addition to selling electricity.

Concerns about market distortion were raised and the regulator signalled that it would reform the matter. Back in late July 2016, Ofgem said these embedded benefits, paid by power suppliers to distribution grid-connected generators, mostly run on gas and diesel, “seem to put the latter at an advantage over larger plants connected to the high-voltage grid.”

Reform stipulated

When initiating a review that might lead to a reform of embedded benefits, Ofgem particularly addressed small diesel, gas and combined heat and power generators connected to the distribution network who get these payments – even though they don’t have to pay grid fees as they supply electricity directly into the local distribution networks.

“We are particularly concerned about specific payments that these generators receive from suppliers for helping them to reduce the biggest element of the electricity transmission charges they face at peak times,” the UK energy regulator stressed. Some UK power suppliers are even said to pay embedded generators in order to avoid high charges from National Grid for balancing the system.

With the number of distributed generators on the rise, Ofgem finds that “the level of these payments has increased significantly and is due to rise even further.” The amount paid by suppliers to these embedded generators is currently around £45/kW – more than double the clearing price for the 2015 Capacity Market auction. This is forecast to increase in four years to £72/kW.

Level playing field

A KPMG report, commissioned by UK Power Reserve, finds that scrapping embedded benefits could lead to the shutdown of up to 2,100 MW of existing distributed capacity while putting about 500MW of planned capacity. Tim Emrich, chief executive of UK Power Reserve conceded that the contested benefits need to be reined in, but he underlined that any cuts should not be applied retrospectively as this would put project at risk that are already underway.

Investment in energy infrastructure, made on the basis that the existing system of embedded charging was deemed ‘fit for purpose’, should Emrich’s view receive “appropriate and fair protection from the regulator.”

In contrast, Ofgem argues that most intermittent power sources are “unlikely to be affected by any changes to these payments.” Intermittent generators are usually unable to generate during ‘triad period’, since these fall outside daylight hours – so they do not tend to receive the controversial embedded benefits, stressed the British energy regulator.

“In the design of new power plant projects, we found that the designing process has significantly improved with VR,” commented GE Power Technical Product Manager, Deepu Sebastian.

The design methodology of GE typically involves multiple teams, each working on different components of a power plant. At the its manufacturing site in Baden, GE engineers’ can now explore and interact with the design at 1:1 scale which enables them to come up with more imaginative designs and communicate ideas better to potential customer.

Design reviews at GE involve an average of 8-10 engineers, and hereby it became clear that the ActiveWall, based on Virtalis’ 3D/VR display systems, provided the best environment for team work.

“Tracking was important to us”, said Sebastian, “we needed to be able to navigate round the model and manipulate it. We’ve been using Visionary Render for only a few months so now we can work on multiple VR models to aid comparison and then make changes in VR that allow us to challenge and improve our original CAD datasets.”

The VR solution is based on active stereo technology and features a custom screen, specialist computer, Virtalis custom software and powerful projectors. For its specific purposes, GE Power has a blended four projector ActiveWall with a 6m x 2.4m screen, plus an ART tracking system.

“Discovering that some of the components didn’t quite fit together during construction is expensive.  Resolving this through re-design was expected and it is this part of the process that we have managed to eradicate, thanks to VR technology,” Mr Sebastian said, stressing that “our design engineers are now fixing errors before construction, when costs are insignificant, and they are also able to think ahead about issues like servicing and maintenance.”

Closer ties between the two long-standing partners were forged as a reaction to the global energy market transition– driven by decarbonization and digitalization, according to Dr. Uwe Lauber, CEO of MAN D&T. “Together, we will offer a solution portfolio that is unique in today’s market,” he said.

Under the latest agreement, MAN and Mitsui will deepen mutual activities within sales, production, R&D, and Engineering, Procurement and Construction (EPC). The deal was signed by Dr. Lauber and Takao Tanaka, President and CEO of Mitsui Engineering & Shipbuilding.

“Together [we] can look back at almost a century of successful cooperation in many fields of business, for example, two- and four-stroke engines for marine and stationary applications”, Tanaka commented.

“With this agreement, we not only consolidate these cooperative efforts, but we also extend them to include the steam turbine and compressor segment.”

The cooperation between Mitsui E&S and MAN D&T started in 1926, when the companies signed a license agreement for the production and sale of two-stroke, marine, diesel engines. Mitsui Engineering & Shipbuilding’s product portfolio focuses primarily on the likes of oil refineries, chemical and petro/chemical plants, steel mills – similar to the offer of MAN Diesel & Turbo.

“Power purchase agreements may involve project- or corporate-specific finance terms, reflect differing contract terms with the power purchaser, or reflect the value rather than the cost of the energy,” said Cara Marcy, Principal contributor at the US Energy Information Administration (EIA).

“Because electricity prices differ throughout the day, the timing of a plant’s output affects its cost recovery. Also, dispatchable generating technologies (such as coal-fired steam or nuclear steam plants, combined-cycle plants, and simple-cycle combustion turbines or internal combustion engines) provide both energy and capacity services to meet daily and seasonal fluctuations in demand”, she stressed.

Comparing new-build capacity with some older power plants has significant limitations: “Some types of existing plants that may have been expensive to build but have relatively low operating costs can continue to operate competitively, even though the LCOE for new plants of these types may be higher than the LCOE for other technologies,” she said.

Different generator technologies are operated in different ways – some are dispatchable, others operate around the clock as baseload energy, and others still hinge on energy sources that are available intermittently, e.g. wind and solar.

Tax incentives, either on a federal, state, or local level, can also affect some of the costs associated with the construction of power generation infrastructure. All these factors make LCOE alone an inadequate metric of measuring the grid-value of flexible power plants.

Alternative concept

Levelized avoided cost of energy (LACE), an alternative cost concept, attempts to measure the value to the electric system that certain technologies provide. LACE reflects the cost that would be incurred to provide the same supply to the system if new capacity using a specific technology were not added and used.

For example, if a hypothetical new natural gas plant were not constructed, other technologies may need to be added or the utilization rate (and fuel use) of existing plants may need to be increased to meet the energy and capacity services that the hypothetical new plant would have provided. A technology is generally considered to be economically competitive when its LACE exceeds its LCOE.

To avoid misconceptions, EIA’s published LCOE estimates are presented with and without relevant federal tax incentives, “but they do not capture the effects of state or local programs, such as payments for compliance with state renewable portfolio standards,” Marcy pointed out.

Although EIA does not directly apply the LCOE and LACE in its modeling, EIA calculates both LCOE and LACE for several technologies for all regions to provide insight into factors driving capacity addition and dispatch decisions. These calculations are available in the Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2017 report.