"Like millions of working families, I am fed up with rip-off energy prices," she wrote in The Sun. "Gas and electricity bills only ever seem to go in one direction, eating up more and more of your monthly pay packet."

Ms May accused the UK’s Big Six energy companies of continuing to raise prices in recent months while the firm’s profit margins reached “record levels.” The PM said the energy market would “not work for ordinary people” who would not be getting a “fair deal.”

Greg Clark, the British Business Secretary, had earlier publicly accused the energy industry of overcharging customers by an average of £1.4 billion a year between 2012 and 2005, equivalent to between £70 and £200 extra on bills.

Election bribe?

The Scottish National Party (SNP) called Ms May’s proposal an “election bribe,” while Labour leader Jeremy Corbin rushed to dismiss the Prime Ministers plan as "desperate stuff", claiming it would lack “any proper detail.”

The main opposition party in Britain already promised to freeze energy bills in its 2015 election manifesto, but pollsters suggest that it still faces an uphill struggle if it wants to come anywhere close to winning the upcoming election.

Ground-breaking of the new manufacturing facility is scheduled to take place later this year; however, the location is still being finalized and multiple Southern states are under evaluation. The facility is scheduled for completion in the autumn of 2018.

Once up and running, the stand-alone manufacturing plant will supply only to Siemens. Beforehand, start-up part qualifications and production shipments are in process at Chromalloy’s existing facility.

“The decision to form a joint venture and a new production facility continues our strong commitment to the US as a business location,” said Willi Meixner, CEO of the Siemens Power and Gas Division. The German engineering conglomerate has more than 60 manufacturing sites and approximately 50 000 employees in the U.S.; it invested $50 billion in the country over the past 15 years.

Based on a a long-lasting supplier relationship between the two firms, the new JV Advanced Airfoil Components will “exclusively supply Siemens with casting components for[its] gas turbines,” Meixner pointed out. “We will continue our established key casting supplier partnerships and all the existing long-term agreements will be executed.”

Carlo Luzzato, President of Chromalloy, commented that the continued expansion of the firms’ partnership “shows the value we place in each other’s capabilities and expertise.”

Chromalloy provides high-technology manufacturing capabilities for gas turbine engines. “And we are excited to bring those capabilities to help create and grow this new business with Siemens,”said Mr Luzzato.

In today’s competitive power generation market, where profits are being squeezed and reliability in hardware is critical, any cost-saving is critical and can be re-channelled by the genset customer into other areas of his business.

The C1540 N5CC, the latest member of the QSK60 Series, offers customers operational options that make it suitable for both CHP and independent power producers (IPP), the manufacturer stated.

The upgraded QSK60 series is said to be “ideal” for integration into cogeneration and trigeneration plants. Cummins said the new gesnset allows power plant operators increase “time per year availability,” reduce downtime and cost of maintenance.

“Given fuel costs constitute the largest portion of total cost of ownership, any gain in efficiency can translate to significant savings for the users.  “With C1540 N5CC, we are extremely pleased that we can deliver stellar efficiency and savings to our customers,” commented Govindaraj Ramasamy, director of projects delivery.

Cummins, a full system provider, provides end-to-end solutions for a number of applications such as baseload power and CHP to meet the needs of a diverse customer base.

Its bespoke programme, ‘The Power of One’, all major components are designed and manufactured in Cummins’ own factories rather than being sourced from OEMs. This offers direct factory-to-market path with solutions tailored to suit specific customer needs.

"There is a window of opportunity for outside investment into plays such as the Permian. The key is identifying the many financially-stretched tight oil operators looking for capital injections to help realise ambitious growth plans," said Adrian Pooh, senior research analyst, Asia upstream.

Many Asian investors come from positions of financial strength, with healthier cash flows and lower leverage and gearing than many international and US oil companies. The huge commercial resources and comparatively low break-evens of US shale oil is, in his view, “a compelling combination,” plus assets are actively traded in the biggest and most dynamic upstream M&A market in the world.

By comparison most pre-development Asian upstream projects lack scale and are located in countries with tougher fiscal terms. "US tight oil offers huge volumes and rapid development cycles, so if Asian players want to grow, they cannot continue to ignore this sector," said Pooh.

Rising cost inflation in tight oil are also likely to further erode margins and increase funding pressures. “And if the oil price weakens, more opportunities will arise as struggling players turn to asset sales to free up capital,” he added.

Although Pooh’s logic seems to be sound, he cautioned there are also reasons why many Asian players remain “reluctant to get involved in such a hot M&A environment.” The fast-moving tight oil market-place is particularly challenging for larger Asian companies who traditionally have long lead-times for decision-making.

The Top20 upstream companies in Asia are heavily invested in conventional plays across the US Lower 48 States, where fields are mature and production is forecast to shrink by 20% over the next decade, Mr Pooh explained. Still, he anticipates that output from the tight oil-driven U.S. unconventional plays will grow exponentially over the same period, but their overall portfolio exposure to the theme is under 1%.

Based on their global upstream portfolio value, Asia's top 20 companies include CNPC, CNOOC, Sinopec, ONGC, INPEX, Petronas, Shaanxi Yanchang, Pertamina, Mitsui, PTTEP, Mitsubishi, JOGMEC, Kogas, KNOC, PetroVietnam, JX Nippon, Sinochem, Oil India, CPC and Marubeni.

During 2010-2013, there were active buyers in shale plays, but most of these deals failed to generate expected levels of value and returns. For some player, bad memories will inhibit a return to US unconventionals.

"While there is room for more US exposure, there also needs to be a clear strategy to navigate through the risks and challenges," says Pooh. “Deal clauses have to be carefully evaluated to avoid value-dilution of assets, while partnering with the right operator is needed to ensure longevity of the project and a sustainable relationship.”

The International Finance Corporation, the World Bank’s private-sector lending arm, considers investing up to $1.3 billion in power projects and electricity distribution companies across Nigeria. In addition, the bank’s the Multilateral Investment Guarantee Agency, which acts as a political risk insurer, could provide equity and debt of $1.4 billion for natural gas and solar power projects.

These funds come in addition to a $2.5 billion loan that Nigeria has already been seeking from the lender to improve its power transmission and distribution grids, and increase electrification rates in rural areas.

“Disbursements with the World Bank are being worked out to start from around June, July this year,” Bloomberg News learnt from the Nigerian Power, Works and Housing Minister, Babatunde Fashola.

Transcorp aims to cover 25% of power demand

Transcorp Power, part of Transnational Corporation of Nigeria Plc,  is committed to generating 25% of the country’s total electricity demand before the end of 2018.

The commissioning of a 115 MW gas turbine in mid-March already increased the capacity of Transcorp’s Ughelli Power Plant to 620 MW.  

But Tony Elumelu, Transcorp chairman, has even bigger plans: “Our goal is to increase our capacity from 620MW to 850MW with the return of three turbines by the fourth quarter of 2017.”

Government pledges to triple capacity by 2025

Investment in new generating capacity in Nigeria is urgently needed to balance supply and demand; but persistent fuel shortages and political risk have for long detered international project partners.

Much of Nigeria’s gas-fired capacity is at a standstill due to fuel shortages:Less than half of the installed capacity of 6,000 MW can be dispatched and electricity transmission infrastructure is patchy at best.

It is questionable if the Nigerian government can reach its goal of tripling generating capacity from 3 GW last year to 105 GW by 2025.

Different consumer groups experience different disutilities for the various dimensions of flexibility they provide, researchers at the Oxford Institute of Energy Studies (OIES) pointed out. Hence, electricity contracts should ideally be designed in a way to allow the participant self-select the parameters. The ‘Rush hour rewards’ programme has been singled out as a “good real-world example” as an attribute of the contracted consumer’s electricity consumption is adjusted automatically by an utility to manage fluctuations of demand and supply.

Targeted incentives make demand-side response mechanisms work more effectively, so utilities can fine-tune the behaviour of electricity end-customers through bilateral flexibility contracts –  taking some strain off TSOs to keep the grid in balance. OIES analysts recommend multi-dimensional bilateral contracts – as well as remunerating schemes for different kinds of flexibility, notably MW, MW/min and emission performance.

Moreover, demand aggregators and small energy storage are key measures to enhance the overall flexibility of electricity transmission network, but high transaction costs - relative to the size of resource – prevent these emerging small resources from participating directly in electricity markets.

Remunerating different kinds of flexibility – MW, MW/min and emission performance – would facilitate a more balanced competition. As a multi-dimensional commodity, flexibility can be described by many elements such as ramp rate, duration of plant dispatch, and lead time for capacity to be called upon.

Thermal storage for wind power

Affordable storage is seen as the missing link between intermittent renewable power and reliable energy supply. Yet, costs of power storage continue to fall as researcher race to develop an economically viable backup. 

McKinsey research anticipates costs could fall to $200 per kWh in 2020 – half of today’s price, which would help transform the energy mix of many nations. By 2025, costs of power storage are expected to fall to $160 kWh or less, making it affordable to use for utilities and grid operators.

Working with the utility Hamburg Energie the Technical University Hamburg Harburg (TUHH), Siemens is developing a thermal storage solution to be paired with wind energy, which it hopes “will set a future standard in efficiency.” Excess wind energy is used to heat rock-fill, protected by an insulated cover – when stored electricity is needed a steam turbine converts the heat energy back to electricity.

Tests in spring 2017 will evaluate the energy conversion of a 36 MWh test bed based on a container holding approximately 2,000 cubic meters of rock-fill.

Demand for electricity in Qatar has been steadily rising over the past decade, driven by the Government’s strategy that seeks to develop various sectors of the economy and reduce reliance on hydrocarbons. KAHRAMAA has closely aligned its strategy with the Qatar National Vision 2030; Phase 13 of the Qatar Power Transmission System Expansion project is due for completion by 2020, helping the country prepare for hosting the 2022 FIFA World Cup

Siemens has been involved in the Qatar Power Transmission System Expansion since project phase 4. At present, the German OEM is carrying out an €470 million order to deliver 18 turnkey substations for Phase 12, part of its plans to expand its power transmission network. The partnership with KAHRAMAA dates back to 2005 when the utility was founded. Siemens has been operating as a local company in Qatar for over 40 years, now with early 500 employees.

As part of the latest contract, an existing 'super substation' – one that allows multiple voltage settings – in Doha will be upgraded with new 400kV/200kV gas-insulated switchgear and associated equipment, before connecting to the grid. Another substation will be used to meet rising demand for electricity in Al Jahhaniya and surrounding area, including temporary power feed to Rayyan Stadium, one of the venues for the upcoming world soccer championship. Substations will also feed power to steel, oil and gas and petrochemical facilities in Mesaieed industrial area, as well as Al Sadd area in Doha.

In addition to Phase 13, Siemens also received a second order from KAHRAMAA to supply and install more than 2,170 medium-voltage switchgear boards. The 8DJH switchgear will be used as ring main units (RMU) in the 11 kV distribution network. RMUs protect, for example, transformers connected to the grid against overloads and short-circuits, ensuring a reliable power supply.

The switchgear will be manufactured in Frankfurt, with the first units expected to go into operation by end-2017. The order is valued at roughly €27 million.

Costa Norte LNG, owned 50/50 by AES and Inversiones Bahía, is currently under construction in Colón; whereas AES owns the Colón CCGT that is being build nearby the regas facility. ENGIE committed to supply up to 0.4 mtpa of LNG to the gas power station starting from 2018.

The remaining capacity of the Costa Norte regas terminal is primarily available for the joint venture to market and sell to third parties. This includes up to 0.7 mtpa of LNG sourced from ENGIE mainly through the Cameron gas liquefaction project in the United States.

In a joint statement, Engie and AES said their joint venture would reinforce their joint marketing agreement signed in the autumn of 2016. Hereby both groups agreed to jointly market LNG in the Caribbean, from AES’ Andres regasification facility in the Dominican Republic. The combined regasification capacity of Andres in the Dominican Republic and Costa Norte in Panamá is approximately 3 mtpa.

With a total installed generating capacity of 210MW, it is also the largest gas power project in the whole of Guangxi province. At full operation, the decentralized power station will supply electricity to seven industries across Guilin – one of the world’s most iconic tourist destinations.

Upon completion, the gas power project is expected to replace 300,000 tons of standard coal as well as substantially reducing emissions (up to 527 tons of sulfur dioxide and 1,560 tons of nitrogen oxide, and up to an 85% drop in dust and 70% drop in CO2).

Critical milestone 

First fire is a critical milestone during construction or retrofit, whereby the gas turbine is switched on and reaches full speed. At the Huaneng Guilin project, the first firing of the gas turbine followed several months of installation and commissioning work.

The power station design is based on a combined cooling, heating, and power (CCHP) configuration, driven by three 6F.01 gas turbine units that can reach fuel efficiency of 81.15%.

Li Xiaodong, general manager of Huaneng Guilin Gas Distributed Energy underline the project is cleaner, more stable, and safer with strong peak-load-dispatching operation.

“It provides a new model of high-efficiency energy use for this city,” he said. This pilot project allows Guangxi explore the smart energy initiatives. It also reflects the theme of ‘new city, new energy, new life’ that the new district is advocating, Mr Li underlined. “Going forward, this secure energy supply will support Guilin in pursuing its ambition to become a major international tourism destination.”

Yang Dan, President of GE Power China added that the American manufacturer provides Wtimely, reliable, and customized solutions that help our customers achieve breakthroughs and create more value while contributing to the sustainable development and transformation of China’s power industry.”

During his presidential campaign, Mr Trump railed against the Paris agreement. He said he was going to "cancel" the landmark climate change deal that has now been ratified by more than 140 countries and legally entered into force last November. Under the agreement, all signatories – including China and the US – committed to keeping the global temperature increase below 2 degrees Celsius above pre-industrial levels.

However, falling costs of wind turbines, solar panels and batteries storage are an economic fact – and the main driver behind the deployment of renewable energy source. Renewables now attract two-thirds of the investment in power generation worldwide, EIU figures show.

Fossil fuels will still remain the mainstay of the energy system, with hydrocarbon accounting for 85% of the world’s primary energy consumption.

As for cost, fossil energy will come comparatively cheap in 2017. The EIU believes that the prices of oil, natural gas and coal have already bottomed out, but over the year “we expect them to remain well below recent highs,” analysts said.

“Strategic cuts in Chinese coal output, driven by climate policy and safety concerns, will tighten market conditions somewhat,” analysts say. Hence the EIU forecasts a modest increase in coal (Newcastle thermal) prices, to US$62.9/tonne in 2017 from US$58.8/ tonne in 2016.

On the demand side, weak consumption globally is likely to prevent prices from rebounding further. “The demand for coal in electricity generation will be stagnant in the US and Western Europe, while losing momentum in China.”

New nuclear had for long been presented by Zuma’s ruling ANC party as a panacea to high electricity prices and frequent shortages of power supply that crippled South Africa’s heavy industries. Declining global commodity prices and increasing electricity prices have had a detrimental impact on the mining and manufacturing industry, which have experienced sluggish growth.

However, as the economy of South Africa shifts towards the services sector, demand for electricity has dropped and other options come into play:

Falling costs of renewable energy technologies, regulatory reforms, market restructuring, coupled with the risks and delays associated with base-load coal and nuclear power will largely determine the future of the electricity sector in South Africa.

Incentives for LNG-to-Power projects

As of late, Government in Pretoria reiterated promises to expand the gas sector – industry players, however, still wait that such words will be followed by concrete action. With a glut of cheap LNG available on global markets, South Africa’s energy industry is seeking to realise flexible gas-fired power project, ideally fuelled via adjacent LNG regas terminals.

Government policy aspires to realising a massive shift in South Africa’s fuel mix and has set out incentives to promote a switch from diesel to cleaner-burning natural gas for power generation.

The LNG to Power IPP Programme, announced in summer 2016 by the Department of Energy in August, envisages construction of some 1 GW of new gas fired generation capacity is to be constructed at South Africa's Coega port, with the remaining 2 GW to be built at Richards Bay.Successful bidders at auction will develop, finance, construct and operate a gas-fired power generation plants at each of the two ports, South Africa's department of energy said on its website.

They also have to put in place the gas supply chain to fuel the plant with gas from imported LNG, with the LNG to Power IPP Programme providing “the anchor gas demand on which LNG import and regasification facilities can be established”, as electricity is to be sold on a long-term contract basis to state utility Eskom.

Bidders for gas-to-power projects are required to set up private sector special purpose vehicle (SPV) for each project. The SPV will be responsible for the design and development, project finance and the supply of LNG. Exxon Mobil and Royal Dutch Shell are among more than 100 bidders for these gas power projects. Siemens said it is one of the competitors; having entered a bid for the development of 3 GW of new LNG-fired generation.

President Donald Trump and his Chinese counterpart Xi Jinping evolved this latest agreement from a 100-day action plan that was announced when they met in April this year. The trade deal covers 10 key areas, including energy resources, agricultural trade and market access for financial service. Matters are, however far more concrete for US exports of beef than they are for US LNG:

As of July 15, American beef producers will be guaranteed fairly free access to the Chinese market in return for Washington allowing the import of cooked poultry from China.

On natural gas, the agreement doesn’t spell out how state-owned Chinese energy companies will import natural gas from the Lower US 48 States. It merely welcomed Chinese buyers to receive LNG shipments and offers the possibility to engage in long-term supply contracts with American suppliers. Long-term gas import is much preferred by Chinese state energy companies over purchasing LNG cargoes on the spot market.

In a briefing at the White House, the Commerce Secretary Ross underlined that ramping up exports of natural gas from America is not believe to push up energy prices domestically that could harm the US energy-intensive industry.

“This will let China diversify, somewhat, their sources of supply and will provide a huge export market for American LNG producers,” Ross told reporters on Thursday. He added that a deal for coal exports to China was “not likely”, given the far shipping distances.

Expanding US LNG exports beyond 12 billion cubic feet per day (Bcf/d) is believed to benefit the US economy while maintaining cheap gas prices at home that give the domestic industry a competitive edge, according to findings by the Center for Energy
Studies at Rice University and Oxford Economics. Examining export scenarios of up to 20 Bcf/d, the study expands on the 6-12 Bcf/d scenarios studied in a previous DoE-commissioned report.

With just under 22GW installed of utility-scale solar (plants over 1MW), these plants account for roughly 2% of the entire electric capacity, and 0.9% of output. Monthly generation from small-scale solar capacity reached 1.6 million MWh on average in 2016, according to estimates by the US Energy Information Administration (EIA).  

California has by far the highest total installed capacity of any state with 9.8GW of operating capacity, followed by North Carolina with 2.3GW. Rooftop and other customer-sited PV systems are most frequent in California, New Jersey, and Massachusetts.

Gas generation dominates US power mix

Natural gas as a fuel for power plants in 2016 made the largest contribution to the US power mix.

Gas-fired generators accounted for 42% of the operating capacity in the US that year, and provided 34% of total electricity output – surpassing coal to become the leading generation source.

“The increase in natural gas generation since 2005 is primarily a result of the continued cost-competitiveness of natural gas relative to coal,” EIA analysts said.

Combined-cycle gas turbine (CCGT) units accounted for 53% of the 449 GW of total gas-fired capacity in the United States during the past year.

The threefold solution comprises hybrid power plants, engines+storage and energy storage. Still, the Finish OEM ihas little interest in developing its proprietary power storage technology; having stated earlier that remaining technology neutral would "help de-risk the business."

Energy storage is gaining momentum and large markets for stand-alone power storage already exist in the US, Western Europe and in the UK. Hybrid solutions such as energy storage are now financially attractive, notably in areas with high fuel prices and a stark contribution of renewable power sources.

Risto Paldanius, Wärtsilä Energy Solutions director, underlined that the launch goes beyond providing energy storage, so the company sees itself as a systems integrator, “as we are able to optimise the usage of our hybrid power plants with EMS software”.

To complement its latest hybrid power gen+storage technology, Wärtsilä also introduced an energy management system (EMS). In mid-2016, Wärtsilä started cooperating with energy storage software provider Greensmith to license the latter’s GEMS platform. The Finnish manufacturer now claims this software is the “most widely-deployed” solution and allows to run hybrid power plants “in an optimal way at all times,” ensuring ideal utilization of engines and energy storage.

Javier Cavada, president of Wärtsilä Energy Solutions stated that the new solution would provide value-added for customers through optimized spinning reserve, fuel savings through runtime optimization between engine and power storage in a hybrid power plant, lower need for maintenance, regulation compliance and reduced emissions.

Public and private companies and the state will take part, as in the previous two auctions. However, unlike in last year’s auctions however, it will be possible to sell power to participants other than state-owned utility Comisión Federal de Electricidad (CFE). This will proceed through a clearing house, that will act as the counterpart in the contracts signed between the buyers and the winning sellers.

Mexico seeks to attract investment in renewables to meet Government targets: Under the Energy Transition Law, by 2050, half of Mexico's electricity is meant to originate from renewables, up from a 35% target in 2024. The Government is also keen on diversifying the country's energy mix and reducing  reliance on fossil fuels. 

For the upcoming power auction SENER will publish an operational handbook, pending regulatory approval, on how the clearing house will function. More information about the auction will be published in due course, including the characteristics of the bid round and the contract models.

It is not yet clear whether the upcoming auction will take into account the differing costs of electricity generation across the country, as did the second auction.

Bids submitted to CFE will be published on July 31, while those made to other participants will follow on August 14. Technical bids will follow in September. The results of the auction are scheduled to be announced at the end of November, the statement added, and projects must commence generating by January 2020.

Following the early stages of energy market reform, Mexico’s first auction saw a total of 1,720 MW of capacity awarded. Seven major wind and solar firms won 15-year contracts for large-scale projects, including SunPower Systems Mexico, Enel Green Power and JinkoSolar.

The second power auction resulted in a further 8.9 TWh of renewable supply contracts awarded, of which 4.8 TWh were for solar and 3.9 TWh for wind power projects.

A combination of upward strength at Dominion and a downward trend at TCO tightened the location differential at these two hubs since this past winter – the third warmest winter in the Northeast since 2010.

Starting from December 2016, the spreads between Dominion South and TCO Appalachia started to narrow. “In May last year, the two hubs had exited an extremely bearish winter, and Dominion South cash basis averaged at $0.5/MMBtu, per OPIS Natural Gas Index. TCO’s discount to Henry averaged $0.10/MMBtu, or a 43-$cent spread from Dominion South,” says Point Logic analyst Callie Kolbe.

In 2017, the two fields have exited again from a relatively mild winter. Over the last 16 months, a combination of increased net deliveries of gas to interconnecting pipelines targeting the Midwest and Gulf Coast, flat year-on-year demand and marginal production growth have changed the storage patterns on these two pipelines.

“As a result, this has altered the relationship between the two hubs. Since April, Dominion South has traded at an average of roughly a $0.27/MMBtu discount to TCO Appalachia, narrowing the spread by 16 cents,” Kolbe explains.

From January 2016 to May 2016, Dominion South cash basis averaged $(0.53/MMBtu) below Henry Hub, while TCO traded at a $(0.10) deficit. Since then, PointLogic Energy estimates that Northeast production has only increased by roughly 1 Bcf/d -- growing from 21.8 Bcf/d in 2016 to a current year-to-date average of 22.8 Bcf/d. This is far below a 2.6 Bcf/d increase in production between the same months in 2016 compared to 2015. 

Additionally, during the same time frame, Northeast demand softened by 2 Bcf/d from 2016 to 2017 as compared to 2016 over 2015. So while the period this year showed that the Northeast was producing an excess of about 1 Bcf/d of gas, this was actually a stronger performance than the prior year when demand softened by 4 Bcf/d during that time and created an excess of about 1.4 Bcf/d of gas. In short, despite the mild winter, the Northeast experienced a tighter supply and demand balance this year as compared to a year ago.

Looking to the summer season, should we anticipate this tight trading between TCO Appalachia and Dominion South to continue?

The current storage deficit and resulting need to inject is likely supporting the current stronger basis at Dominion South. However, Dominion’s system is more dependent on the expansion of interconnected pipeline systems to find an outlet for gas downstream, while TCO’s system is more interconnected and flexible.

“Given Dominion’s less flexible system, the current price support could dissipate very quickly if mild cooling degree day demand is realized this summer, and if Northeast production continues its recent upward momentum That said, most three-month weather forecasts indicate average or above-average temperatures, which could help keep upward pressure on the Northeastern hubs,” Kolbe said.

Consideration also needs to be given to several pipeline expansion projects, scheduled for this summer, she said, suggesting “these could provide relief to discounted basis values at TCO and Dominion.” This rings true particularly for Energy Transfer Partners’ Rover Phase I and TETCO’s Gulf Market Expansion Phase II, which are expected to enter service in July and August 2017.

“Increased production and the additional outlets to the Midcontinent and Southeast will likely keep the hubs trading closer than in the past,” she added. PointLogic will continue to closely monitor Northeast storage, production and expansions over this summer.

Bolivia’s power provider Ende Andina in early May signed a binding agreement with Siemens that will see the German manufacturer supply 14 SGT-800 gas turbines, 11 SST-400 steam turbines with condensers, 22 steam generators and the instrumentation and control system SPPA-T3000.

Sweden – Chile - Bolivia

All turbines subject to this order win are being manufactured at Siemens Industrial Turbomachinery in Finspang, Sweden. On Friday, the two first SGT-800s were loaded onto a heavy load carrier in the harbour of Norrköping, Sweden.

Now the cargo with more than 170 tons is travelling the first 14,000km on sea route from the Northern Atlantic via the Panama Canal to the Pacific harbour of Arica in Chile. From there the modules will be transported 1,800km overland to Bolivia, crossing the Andes.

"With this project we achieve the fastest, most efficient and most cost-effective expansion of the power generating capacities in Bolivia. The country will save a lot of natural gas by the distinct increase of efficiency of the three power plants,” commented Willi Meixner, CEO of Siemens’ Power & Gas division".

Cristian León, Ende Andina’s site manager for the Termoeléctrica del Sur expansion project, added: “We are prepared on site to receive these turbines, since the foundations of both turbines and generators are ready with much time in advance to ensure (…) the assembly process can run within schedule. Thanks to the civil works activities carried out in our three plants we ensure that the project will not suffer any delays".

Installation to be carried out by TSK

On site in Bolivia, Siemens’ consortium partner – the Spanish industrial group TSK – signs responsible for civil works, balance of plant, delivery of high-voltage substations as well as for the mechanical and electrical erection of the projects.

• The first expansion project – the Termoelectrica del Sur CCPP, situated near the Bolivian/Argentine border - will be equipped with additional four SGT-800 gas turbines, four steam turbines and eight steam generators.
• The second plant - Termoelectrica de Warnes - will be expanded by four SGT-800 gas turbines, four SST-400 steam turbines and eight steam generators.
• Third, the Termoelectrica Entre Rios power plant, situated some 220km southeast of La Paz, will get retrofitted with six SGT-800s, three SST-400s and six steam generators.

With the expansion projects, Siemens and its Spanish consortium partner TSK are adding more than 1 Gigawatt (GW) to the Bolivian power grid. The three CCPP expansions will boost Bolivia’s installed power generating capacity by 66%, increase electrification levels and lay the foundation for future electricity exports.

“One reason demand-side policy is so underrated is because energy efficiency is not very sexy. It lacks wonderful ribbon-cutting photo-ops for politicians, and it often can mean higher upfront costs that may put off consumers, even if that leads to long-term savings,” he said. “And yet the important efficiency gains that we have experienced in the last decades have been driven by stronger policies.”

The over 60% plunge in oil prices since the mid-2014s coincided with strong policy drivers that helped to improve global energy intensity by 1.8% since 2015 – more than three times the average rate of improvement seen in 2003-13, as documented in the IEA Energy Efficiency Market Report 2016.

Energy intensity trend seen continue

Today, a third of the world’s energy consumption is covered by mandatory standards and regulations, compared with just 11% in 2000. This helped boost energy efficiency in the areas of lighting, cars, and space heating, and to a lesser extent, appliances.

Global energy intensity improved 1.8% in 2015, three times the annual average of the last decade, while investment in energy efficiency rose 6% to $221 billion, led by growth in the buildings sector. Intensity gains were higher in the emerging economies like China, a trend that is expected to continue. Had efficiency levels not improved substantially over the past 15 years, energy demand in IEA member countries would have risen 12%, to surpass the 2007 peak already two years ago.

“The good news is that global energy efficiency gains are accelerating, even in the current low price environment,” van Hulst underlined.

“But the bad news is that this progress on a global scale is still too happening too slowly. Annual intensity gains need to increase to 2.6% to achieve the global climate goals of the Paris agreement,” he added.

Since there is much untapped potential in energy efficiency, it should be feasible for all countries to further boost energy efficiency. In van Hulst view, policy makers should thrive to apply existing best practices and enshrine them in mandatory energy efficiency standards.

Over 70%of global energy consumption is currently not subject to mandatory efficiency standards. India, Brazil and most Middle Eastern Countries have made significant progress since 2000, but some are still lagging behind: According to IEA figures, the share of Middle Eastern energy consumption covered by mandatory efficiency standards is 15% in 2015, just half the global average.

Uncontrolled power flows are putting the system at risk in that region, as rising electricity demand means that thermal limits of the cables and overhead lines are exceeded. The new MVDC link, according to GE, will help improve the flow of electricity, voltage control and enhance the thermal capability of the circuit.

“As electricity demand and the connection of renewable generation continues to grow, the existing network infrastructure struggles to cope and additional reinforcement becomes necessary,” explained Kevin Smith, Future Networks Lead Engineer at Scottish Power Energy Networks.

“The Angle-DC project, being the first of its kind, will hopefully demonstrate that using MVDC on existing assets can be a more innovative alternative to simply building more substations along with the connecting underground cables and overhead lines.”

GE will be playing a key part in the successful delivery of this MVDC trial project: The AC-to-DC converters will be installed at a 33-kV substation in Bangor and at a similar substation on the Isle of Anglesey. The 12 units of MV7000 converters at each substation will convert 33 kVAC to ±27kVDC using the existing AC lines between the two substations.

When carrying out the order, GE will also include VISOR 2.0, a tool to provide remote connectivity to improve service responsiveness, and the Data Historian software that allows data collection, processing and storage.

Data analysis will allow SP Energy Networks review the capabilities of the MVDC system, and develop optimum control algorithms for the distribution grid.

The new wind and solar power installations are meant to supply enough electricity for nearly 2 million homes, supplementing the 1,000 MW renewable capacity DTE has built since 2009. The flexible gas plants will provide a flexible backup power source. With this strategy, DTE aims to produce over three-quarters of its power from renewables and gas.

“We have concluded that not only is the 80 percent reduction goal achievable – it is achievable in a way that keeps Michigan's power affordable and reliable," DTE's chairman and chief executive officer, Gerry Anderson, said in a statement.

Continuous coal power phase-out

Retirement of DTE’s aging coal-fired plants is a “steady process”, which continued in 2016 with the announced shutdown of 11 coal units by the early 2020s.

Previously, DTE retired three of its coal-fired power plants – the Marysville, Harbor Beach and Conners Creek plants. In 2016, three additional coal-fired generating units at plants also were removed from service. This process of retiring coal-fired power capacity will continue with the retirement of the River Rouge, Trenton Channel and St. Clair power plants in the early 2020s.

Gradual shift towards clean gas and renewables

DTE has a gradual approach to curb emission and seeks a 30% reduction by the early 2020s, 45% by 2030, followed by 75% by 2040 and more than 80% by 2050. The company said it will achieve these reductions by incorporating substantially more renewable energy, transitioning its 24/7 power sources from coal to natural gas, continuing to operate its zero-emission Fermi 2 power plant, and strengthening options for customers to save energy.

Since 2009, DTE has spearheaded more than $2 billion of investment in wind and solar resources. The solar project DTE recently completed in Lapeer, Mich., is among the largest solar fields east of the Mississippi River.

To ensure reliable energy supply, DTE plans to spend $5 billion over the next five years to modernize the electric grid and gas infrastructure. Moreover, the utility said it will continue to invest in energy efficiency and energy waste reduction.

"The transformation of the way we produce power is in full swing," said Anderson. "Like all big transformations, this one won't happen overnight. It needs to be planned carefully and will entail big investments, but that can absolutely be done."