“The extremely competitive global gas turbine market has moved in our direction with a clear preference for our JAC gas turbines, which are more reliable than competitor’s gas turbines while providing record-setting fuel efficiency and output,” said Ken Kawai, MHPS President and CEO.

Sales of MHPS’ gas turbines in both the advanced class and aero-derivative segments have gained momentum as utilities, independent power producers and municipalities seek to lower their electricity cost, he said, pointing out the turbines’ “unique combination of proven reliability and world class performance.”

J-Series gas turbines, on the market since 2011, operate with world-record reliability at 99.5% and can deliver combined cycle efficiency greater than 64%. The installed fleet of J-Series gas turbines recently achieved one million hours of commercial operation worldwide – nearly double that of competitors’ similar sized gas turbines.

Focus on hydrogen co-firing

Boosting MHPS’ first quarter 2020 market share was an order for the first two renewable-hydrogen-capable JAC gas turbines for the Intermountain Power Agency in Delta, Utah. The customer said it chose the JAC power trains for their fuel flexibility which enable them to meet incremental goals toward 100% carbon-free power generation by 2045.

Forty-five J-Series gas turbines are in commercial operation, and total ordered capacity exceeds 25 GW globally. One hundred and four units have been technically selected in Brazil, Canada, Japan, Mexico, Peru, South Korea, Taiwan, Thailand, and the United States.

Continuing to improve its turbine technology, MHPS recently reached full load with the latest 60 Hz enhancement of the JAC in Takasago, Japan, demonstrating record-setting output and combined cycle efficiency. “Competitors are years away from entering operation with a gas turbine of this size or efficiency,” said Junichiro Masada, Co-Chief Technology Officer and deputy of MHPS turbomachinery headquarters.

Enhancing FT4000 performance

The Japanese manufacturer also demonstrated a significant performance enhancement of the FT4000 at our test facility in West Palm Beach, Florida. Over the past two years, the FT4000 aero-derivative gas turbine tripled its global footprint since it bought the technology by taking over PW Power Systems in 2013.

The PWPS FT4000 first entered commercial operation in 2015 and delivers industry-leading simple cycle efficiency, start time and ramp rate.

Investment in renewables and energy storage is the new trend among U.S. corporates. Google’s portfolio of renewable energy increased 43% in 2019 alone and has been 100% powered by renewables since 2017. Apple achieved 100% renewable energy in 2018, and is planning to buy ‘green aluminium’ from Elysis, a joint venture between Rio Tinto and Alcoa.

Facebook is on track to hit its 2020 target of 100% renewable energy as a result of large PPAs for wind and solar, while Microsoft already reached that target. Amazon also heavily invested in utility-scale wind and solar energy projects in the U.S and around the world.

IBM and HP Enterprise have committed to 55% renewable energy by 2025, and Accenture has committed to only rely on renewable energy by 2023.

U.S. President Trump, in contrast, has removed the world’s second largest greenhouse gas emitter from the Paris Climate Agreement, which “makes private sector efforts on sustainability all the more important,” IEFFA analyst Clark Butler commented.

“Corporates realised early that investing in renewable power purchase agreements (PPAs), makes good business sense,” he said, and “the more electricity-intensive an industry, the larger the financial savings.”

The fossil fuel energy sector commanded just 4.3% of the Standard & Poor’s 500 index at the end of 2019, “and probably just half of this today,” Butler said. That’s a stark contrast to the 1980s, when oil and gas companies represented seven of the top 10 companies in the S&P 100, accounting for 25% of the index.

Energy demand in Asia is expected to almost double by 2030. India, for instance, has a current installed capacity of approximately 365 gigawatts (GW) is expected to grow five-fold in the next 30 years to a whopping 2,300 GW. Hence, investment in new gas power projects is see surge 64% in the next five years amid escalating energy demand.

“We anticipate that the spending on gas-fired projects will surpass coal investment as spending is driven by sustainability goals, financing issues and government regulations,” said Narsingh Chaudhary, Executive Vice President, Asia Power Business, Black & Veatch.

To promote energy security and access, Asian utilities are integrating their generation, transmission and distribution assets. According to Mr Chaudhary, “this approach helps them overcome the pitfalls of aging infrastructure assets while meeting rising customer demand for energy that is renewable and reliable.”

Debt financing is also forthcoming for projects in fast-growing Asian markets – both from commercial and development banks. The Asian Development Bank (ADB), for example, recently provided $305 million for the Jawa-1 project, Indonesia’s largest combined cycle gas turbine power plant (1,760 MW). The integrated LNG-to-power project is expected to supply electricity to 11 million homes from 2021.

In Thailand, Black & Veatch in consortium with Marubeni Corp recently provided EPC services to Glow Energy for the completion of a combined-cycle cogeneration plant near Rayong, Thailand. Glow Phase-5 delivers up to a nominal 382 MW of electricity when operating in full condensing mode, and 342 MW in cogeneration mode.

To identify opportunities in complexities and sustainability, the energy leaders in region are teaming up with business partners that provide quality engineering, procurement and construction solutions at varying scales.

According to Black & Veatch, global EPC firms and project financiers can offer local utilities consistent execution and safety practices to make LNG import and power generation projects more bankable and revenue more certain. On the other hand, international project developers are relying on regional experts to mitigate business risks and overcome complexity from planning and development to construction and operations.

In liberalised markets, the economics of natural gas are not intrinsically linked to the price of oil products. Developments in hydraulic fracturing drove the cost of gas production down but did not have any considerable impact on the price of oil. This relatively ‘cheap’ gas flooded the markets and drove the price of gas down, without a similar impact on the price of oil, according to a paper published by the international legal firm, DWF Law.

At the same time, electricity generated from gas and other fossil fuels is challenged by rising volumes of wind and solar power supply, produced at near-zero operating cost. This greatly impacts the cost of energy, although to a different extent in any given market.

“All of these factors undermine the notion of a ‘positive’ correlation between the prices of oil and natural gas. Furthermore, these factors argue against the proposition that oil products and natural gas are close pricing substitutes,” the paper states.

Hub-indexation

Oil-indexation is increasingly viewed as outdated. Due to its high liquidity, price transparency and relevance, many argue that hub-indexation is more preferable for the purposes of long-term gas sales agreements (GSAs) than oil-indexation.  

“The indexation of gas to oil products made the gas price formulae volatile. A large movement in the oil price of oil affected the price of alternative fuels and, consequently, the potential margins of the sellers and buyers of gas,” lawyers at DWF pointed out. “In the past decade, we have seen oil volatility materialise through the peaks and troughs of 2010, 2011, 2015, 2016, 2018 and now 2020.”

“Due to its high liquidity, price transparency and relevance, many argue that hub-indexation is more preferable for the purposes of a GSA than oil-indexation,” they underlined.

The U.S. Henry Hub, created in the early 1950s, is the world’s most liquid gas trading hub by a long run. European hubs like the UK’s National Balancing Point (NBP) and the Dutch Title Transfer Facility (TTF) are more recent and date back to 1996 and 2003, respectively.

Asian markets open up

Gas markets in Asia are not fully liberalised yet. Most gas is still sold under oil-indexed long-term gas sales agreements (GSAs), using different baskets/cocktails of oil products).

Some buyers have partially linked their GSA prices to European hubs, but this is not an ideal proxy. The Platts Japan Korea Marker (JKM) is growing in popularity and has led to some buyers seeking to re-negotiate their terms under oil-indexed GSAs previously linked to the JCC (Japanese Crude Cocktail).

“In order to make the shift from oil-indexed contracts to gas-indexed contracts, a benchmark price will have to be generated. This could only be done by the liberalisation of the markets,” the report points out. “In the meantime, it is likely that the frequency of gas price review arbitrations will steadily increase as the price of oil has taken a dramatic turn.”

Many large Asian gas buyers have started reviewing their GSAs and market observers see companies like Korea’s Kogas, the Chinese majors and Petronet LNG in India “facing new price review challenges in the current economic climate.”

The Japanese market has been fully liberalised since 2007. “However, this growth is stunted due to limitations of domestic pipeline connections, which pose barriers to new entrants into the market,” said the report.

South Korea is at an earlier stage of liberalisation, with state-run Korea gas Corp. importing around 90 percent of the country's gas demand. China's increased demand for gas has also resulted in accelerated development in the country's infrastructure in order to accommodate the additional supply.

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. The 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.

Orders for FSRUs from Africa

AG&P and majority-owned GAS Entec have recently been awarded several component contract, among others for converting an LNG carrier into a floating storage and regasification units (FSRUs) to be deployed in West Africa and help fuel decentralized power stations and stabilize local electricity grids

“AG&P’s goal is to bring LNG to new markets. One of the missing links has been the capability to import and distribute LNG in affordable and smaller volumes to non-traditional and off-grid customers,” said Chong-Ho Kwak, CEO of Gas Entec.

Modularized infrastructure

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. In November 2019, AG&P acquired a minority stake in Norway-based Kanfer Shipping, adding a proprietary LNG articulated tug-barge (ATB) to its suite of LNG technology solutions.

Going forwards, AG&P focuses on building a substantial of fleet of LNG tankers that deliver LNG from terminals to industry and power generators.

The licence awards support Thailand’s plans to increase imports of LNG, taking advantage from the current low prices in an oversupplied market to shift the Thai power mix from coal to gas generation.

Imported LNG to fuel 1.4 GW power project

Gulf Energy Chief Financial Officer (CFO), Yupapin Wangviwat, said the regulator approved a licence for the amount to 1.4 million tons per year, to be used as a fuel for electricity production for Hin Kong Power Project with capacity of 1,400 MW.

The plant is located in the Hin Kong subdistrict in Ratchaburi province and is expected to commence commercial operation in 2024 and 2025.

New regas unit at Map Ta Phut industrial port

A new regasifiaction terminal is under construction at Map Ta Phut industrial port, adjacent to Thailand’s only operating LNG import facitiliy which last year imported around 5 mtpa, mostly under long-term contracts with Qatargas and Malaysia’s Petronas.

Gulf Energy has a 70% stake in the new LNG import terminal, called Map Ta Phut Phase-3, and currently under construction. The project includes a port to facilitate shipments of 5 mpta, which could be increased to 10.8 mtpa at a later stage.

Once fully operational, the Map Ta Phut Phase-3 regas unit will allow Gulf Energy to source attractively-priced spot LNG cargoes in order to strengthen its position in Thailand’s gas and power sector.

The scope of the contract includes the management and call off support for turbine overhauls, spare parts supply, field service and, planned and unplanned maintenance.

Ana Amicarella, CEO of EthosEnergy, said the company’s integrated solution allows it to provide a “wide breadth of [service] capabilities as OneEthos” to support the breadth of the customers’ fleet technology. “This cohesive approach proved the value of EthosEnergy and allowed the customer to select us with a high degree of confidence for the project,” she added.

Though EthosEnergy did not name the customer - a major oil and gas producer active in the UK North Sea - it said the contract award solidifies a 15-year relationship with this particular customer.

Headquartered in Houston, Texas, and in Aberdeen, UK, Ethos Energy is an independent service provider of rotating equipment services and solutions to the power, oil & gas and industrial markets. Globally, these services include facility operations & maintenance; design, manufacture and application of engineered components, upgrades and re-rates; repair, overhaul and optimization of gas and steam turbines, generators, transformers, pumps, compressors and other high-speed rotating equipment as well as power plant engineering and procurement and construction.

In natural gas-focused plays, rig count also fell although those plays had fewer rigs to start with. The top gas-producing regions –aside from the Permian basin, where much of the U.S. associated gas is produced though all rigs are classified as oil-directed –were the Marcellus region in Ohio, Pennsylvania, and West Virginia and the Haynesville region in Louisiana and Texas.

Exclusively gas-directed drilling rigs in the Marcellus and Haynesville regions declined by 23% and 26%, respectively, from mid-March to May 12.

Rapid reaction to falling oil prices

Changes in rig counts follow changes in oil prices, normally with a lag time of about four months. “However, the current drop in rig count followed the recent decrease in the oil price much more rapidly than in the past,” analysts at the U.S. Energy Information Administration (EIA) pointed out

The spot price of West Texas Intermediate fell from $46.78 per barrel in early March to $20.51/b at the end of the month, and the rig shut-ins began already in mid-March.

“The quick reduction in active rigs reflects the sudden loss of petroleum demand related to coronavirus-related mitigation efforts that also resulted in recent increases in the amount of crude oil placed in storage,” EIA analysts commented.

Gas prices subdued before pandemic

Similarly, natural gas rig activity has decreased along with the natural gas price, though gas prices have been falling over a longer period than oil prices. Oversupply has kept building on global gas markets long before the recent lockdowns to contain the coronavirus pandemic, with Henry Hub gas prices having already at multi-year lows in early 2020.

“Record-high dry natural gas production in autumn and winter 2019, low demand because of warm weather, and relatively small withdrawals from storage during the winter heating season (November 1–March 31) have led to a sustained decrease in the gas price,” EIA analyst said, indicating prices are likely to remain low for the foreseeable future.

“I think it will be depressed this year and to some extent next. This depends in part on the economic recovery, which will depress prices,” he said at a virtual conference, organised by Eurelectric.

Remaining cautious about the pace of recovery, the SSE head warned that a prolonged recession may keep energy demand and wholesale power prices subdued. Though lockdowns are gradually lifted in the UK, he still expects the country’s electricity demand to stay 8-10% lower than in 2019 this summer, and 3.5% lower in winter 2020/21, largely due to coronavirus containment measures.

Demand for electricity, gas and fuels is being help back as many employees would continue working from home instead of returning to the office, he suggested.

Call for “onshore supergrid”

SSE has urged the UK government to issue permits for some 75 gigawatts (GW) of offshore wind farms by 2050, a significant rise from the current 8.5 GW, and the development of an “onshore supergrid” to help speed up the electrification of the British industry.

Greater grid interconnectivity across Britain and the EU is vital for the green energy transition, and utilities across Europe are urging national government to take action now and invest in infrastructure.

Electrification is a “critical facilitator” for the continent’s economic recovery, Phillips-Davies said, stressing “it is essential to invest in tackling the barriers that prevented an accelerated electrification of buildings, transport and industries, during the first quarter of 2020.”

In this context, SSE also reiterated its call for more government support for electric vehicles and a gradual rise in the UK carbon tax. So far, only 17% of the one million public electric vehicle charging stations needed by 2025 have been built, as several projects were pushed back or cancelled this year.

Critics oppose the go-ahead of Datteln 4, arguing the start-up of a new coal-fired power station contradicts Germany’s agreed plans to phase out all coal power plants by 2038.

The test runs take at a time when most hard coal and lignite-fired power plants in Germany are not running, as lockdowns to contain the coronavirus have slashed Germany’s electricity demand while output from wind and solar power installations remained high.

Germany’s most flexible coal unit

The hard coal-fired Datteln 4 unit will be Germany’s most modern coal-fired power plant with an exceptional level of operational flexibility, allowing it ramp up or down quickly to balance renewables powers supply to that grid. That grid balancing role is traditionally fulfilled by combined-cycle gas-fired power plants.

With 1,100 MW installed electric capacity at 45% net efficiency plus 380 MW thermal power output, the plant’s overall efficiency reaches 60%. Uniper already sold 413 MW of the electric power output to the German rail operator DB.

Uniper CEO Andreas Schierenbeck indicated Datteln 4 is expected to generate an annual operating profit of at least 100 million Euros.

Uniper offers to shut old coal plants

Düsseldorf-based Uniper operates coal plants with a capacity of 3,800 megawatt (MW) at five locations across Germany. The Datteln 4 coal project had been highly controversial throughout its construction period.

“We will take older coal-fired power plants off the grid in in return for Datteln 4. Our goal is that our overall carbon emissions output will be significantly lower as a result,” the Uniper CEO said.

Works on Datteln 4 started back in 2007 and the unit was initially meant go online in 2011. However, the project was delayed several times and ended up costing 1.5 billion Euros. The German government finally approved the plant's commissioning in October 2019, despite public protests. Now, Uniper is striving to bring the plant in full operation before the summer.

Finland’s Fortum owns a 49.99% stake in Uniper and both utilities are committed to convert most of their coal-fired units to gas where possible in an effort to reduce emissions.

“Data centers are the nodes of the global information and communication network, whose vital importance has become particularly clear in these difficult times,” said Andreas Schell, CEO of Rolls-Royce Power Systems. “Under our MTU brand, we develop customized solutions, thousands of which we have already installed, for data centers’ individual, complex and growing energy needs

The technology cooperation will start before the end of 2020, with the aim of using fuel cell modules, such as those to be produced for commercial vehicles in the future, for stationary energy supply.  Daimler and Rolls-Royce’s have been working together for many years on conventional drive systems and in December 2019 agreed to develop a demonstration plant for stationary power supply on the basis of fuel-cell modules from the automotive sector. The pilot plant will go into operation in Friedrichshafen by the end of this year.

Decarbonization of drive systems

Looking ahead, Rolly-Royce has singled out the decarbonization of drive systems and power supply as a central strategic goal of its PS2030 strategy, whereby fuel cells will play a key role.

“No other technology offers such high reliability, modular scalability and all the advantages of renewable energies without dependence on the conventional energy market,” Schell said, adding the cooperation with Daimler Trucks will give Rolls-Royce access to fuel-cell systems with the aim of strengthening the company’s position in this growth market.”

Daimler, Volvo to set up fuel-cells JV

In April, Daimler Truck and the Volvo Group agreed to set up a joint venture for the large-scale development, production and commercialization of fuel-cell systems for heavy-duty commercial vehicles and other applications.

Rolls-Royce said its Power Systems business unit “plans to rely on these fuel-cell systems from the planned joint venture – as well as Daimler’s many years of experience – in the emergency power generators it develops and distributes for data centers under the MTU product and solution brand.”

Supplement to battery-electric drive

Daimler Truck board chairman Martin Daum said the German vehicle maker sees fuel-cell systems as a supplement to battery-electric drive. Referring to the forthcoming JV with Volvo, he said: “With the agreement for stationary fuel-cell systems concluded, we are demonstrating very concrete opportunities for the commercialization of this technology.”

The latest cooperation agreement with Rolls-Royce, in his view, gives “further impetus for the development of a hydrogen infrastructure across all sectors and applications.”

Over the past two decades, Daimler has done research on fuel-cell technology at Mercedes-Benz Fuel Cell headquarters in Nabern, Germany, as well as at other production facilities in Canada. The aim is to start producing heavy-duty fuel-cell commercial vehicles for long-haul applications together with Volvo by 2025.

Fuel-cell systems for stationary power applications, meanwhile, can be produced already “at an earlier stage,” the company indicated, as specific requirements for use in transport on public roads do not apply.

The mother company has placed itself under a contractual obligation to refrain from exercising a controlling influence over Siemens Energy in the future.

Subject to approval by the extraordinary shareholders’ meeting, the spin-off will take place as announced by the end of September. The initial listing is to take place on September 28th, 2020.

Realigning the business

Joe Kaeser, President and CEO of Siemens AG, has been the driving force behind the spin-off of the Siemens Energy section which follows after the listing of the company’s Healthcare business as part of the company’s Vision 2020+ strategy program

“We’ve now reached a major milestone in the overall realignment that is preparing the Siemens companies for the massive technological transformations that we are anticipating,” Kaeser said when announcing the date of the Siemens Energy listing.

“The considerable increase in the value of our healthcare business shows the huge potential we can tap by further sharpening the focus of our company. This applies to both, Siemens Energy and the ‘New Siemens AG,’ which is concentrating on our Industrial Businesses.”

New player with unique setup

The planned public listing of Siemens Energy will create a strong, focused, global company with operations spanning the entire energy value chain, including the service business.

With 91,000 employees worldwide, Siemens Energy will offer products such as combined cycle turbines, generators, transformers and compressors – but also wind turbines due to its 67% stake in Siemens Gamesa Renewable Energy.

The unit’s order backlog stood at €77 billion, as of September 30, 2019, generated revenue of about €29 billion in fiscal 2020. If severance charges of around €0.3 billion had been excluded, the adjusted EBITA would have been about €1.3 billion.

Investment-grade rating targeted

At its launch, Siemens Energy will be “very solidly financed,” Kaeser pointed out. The aim is to meet the requirements for a solid investment-grade credit rating. As of March 31, 2020, equity totaled about €17.3 billion (IFRS), corresponding to an equity ratio of 37.8%.

In addition, Siemens Energy has been provided with €6.2 billion in cash, of which around €4.1 billion will be used to settle liabilities during the period leading up to the spin-off. A bank consortium confirmed a revolving credit facility of €3.0 billion.

Following the spin-off, the mother company Siemens AG will concentrate on Digital Industries, Smart Infrastructure and Siemens Mobility. The healthcare technology business, Siemens Healthineers, has already been publicly listed as a separately managed company since March 2018.

Speed and scale of the fall in energy investment in the first half of 2020 is “without precedent,” the IEA said, as the pandemic caused an unprecedented destruction in energy demand, disrupted supply chains for the construction of new projects and made companies reign in spending.

The largest effects on investment spending in 2020, especially in oil, stem from declines in revenues and uncertainty about the speed of recovery in the years ahead.

Oil (50%) and electricity (a further 38%) were the two largest components of worldwide consumer spending on energy in 2019. However, the IEA’s latest estimates see spending on oil will plummet by more than $1 trillion in 2020, while power sector revenues drop by $180 billion. This would mean an historic switch in 2020 as electricity becomes the largest single element of consumer spending on energy.

“The revisions to planned spending have been particularly brutal in the oil and gas sector, where we estimate a year-on-year fall in investment in 2020 of around one-third,” IEA analyst said, noting this “has already triggered an increase in borrowing as well as the likelihood that restrained spending will continue well into 2021.”

The power sector has been less exposed to price volatility, and announced cuts by companies are much lower, but we estimate a fall of 10% in capital spending. In addition, sharp reductions to auto sales and construction and industrial activity are set to stall progress in improving energy efficiency.

Investors keep focussed on China, turn away from the U.S.

Despite the pandemic, China remains the largest market for investment and a major determinant of global trends; the estimated 12% decline in energy spending in 2020 is muted by the relatively early restart of industrial activity following strong lockdown measures in the first quarter.

The United States sees a larger fall in investment of over 25% because of its greater exposure to oil and gas. According to EIA figures, around half of all US energy investment is in fossil fuel supply.

Europe’s estimated decline is around 17%, with investments in electricity grids, wind and efficiency holding up better than distributed solar PV and oil and gas, which see steep falls.

Developing countries, especially those with significant hydrocarbon industries, see the most dramatic effects of the crisis, as falling revenues pass through more directly to lower funds for investment.

Fracking companies feel the pinch

The cuts in fuel supply investment in 2020 apply to all types of resources and company, but a few elements stand out.

“Some of the most dramatic cuts in the oil and gas sector – in many cases above 50% – have been among highly leveraged shale players in the United States, for whom the outlook is now bleak,” IEA analysts said, although it is too soon to write off shale as a whole.

Funds available to some indebted and poorly performing national oil companies (NOCs) have also dried up, as governments scramble to make up for acute shortfalls in revenue.

Further downstream, a surge in investment in LNG left the sector facing a major overhang of capacity, putting intense pressure on margins and pushing back many investment plans and timelines. “Natural declines in upstream fields offer a hedge against overinvestment, but there is no such protection further down the value chain against demand coming in below expectations,” analysts noted.

Stagnant spending on gas power, rise in RES

In the power sector, many state-owned utilities have shelved investment while larger renewables-focused utilities in advanced economies “appear on firmer footing,” analyst noted, “but also face some revenue risks from shifting market demand and price trends.”

Overall, ongoing investment in renewable power projects is expected to fall by around 10% for the year, less than the decline in fossil fuel power. The crisis is also prompting a further 9% decline in estimated global spending on electricity networks, which had already fallen by 7% in 2019.

Alongside a slump in approvals for new hydropower and nuclear power units this decade, stagnant spending on natural gas plants, and a levelling off of battery storage investment in 2019, “these trends are clearly misaligned with the needs of sustainable and resilient power systems,” analysts pointed out.

The share of energy investment in GDP has declined and is set to fall to under 2% in 2020 – down from around 3% in 2014 in what the IEA calls “worrying signs” for an economic downturn.

The Polish government supports the Baltic Pipe is a strategic project that helps diversify the country’s sources of gas supply - an increasingly pressing issue due to the May 17 expiry of the Yamal pipeline transit agreement with the Russian major Gazprom. In addition, a long-term gas supply contract between Poland’s state gas company PGNiG and Gazprom will come to an end on December 31, 2022.

Diversifying supply

Eager to ensure supply security, PGNiG arranged bi-directional gas flows and expanded several interconnectors with Germany, the Czech Republic, and Slovakia, increased from 97 million cubic feet per day (MMcf/d) in 2010 to 242 MMcf/d in 2019. Four years ago, Poland also started to import LNG through the 0.5 Bcf/d LNG Polskie LNG terminal in Świnoujście, located on the Baltic Sea near the Polish-German border.

As a consequence, Poland managed to reduce its reliance on Russian gas imports from 90% to less than 60% over the past decade. Ten years ago, Russian gas imports accounted for 90% of imports and more than 63% of Poland’s supply, but these volumes fell to 60% of all imports and 48% of the total consumption.

The Baltic Pipe will open up an entirely new supply source for Poland – natural gas from Norway.

Falling domestic production, rising demand

Poland’s domestic gas production has been in continuous decline over the past decade, falling to 0.4 Bcf/d or 20% of total supply in 2019, while consumption gas grown by over 30% over the same period, rising from 1.4 Bcf/d in 2010 to currently just over 1.8 Bcf/d.

The rise in gas demand has been caused by Poland’s main utilities having added more than 13,000 miles of domestic distribution and trunk lines to connect millions of industrial, residential, and commercial consumers to the national gas grid.

The Golden Pass LNG project comprises the construction of three liquefaction process trains, each with a nominal output of approximately 5.2 million metric tons per annum (mtpa). Construction started in the first quarter of last year and the facility is planned to start up in 2024.

Siemens’ scope of supply covers the engineering, manufacturing, and testing of the three, single-shaft centrifugal BOG compression packages, along with all installation and commissioning activities. Each of the compressor packages will be driven by a 6.8 MW electric motor. Manufacturing, testing, and packaging will take place in Duisburg, Germany.

In addition to the BOG compressor trains, Siemens will provide steam turbine generator sets as well as all necessary low-voltage electric motors and electric variable speed drives (1 – 200 horsepower) and all medium-voltage (250 – 1,500 horsepower) electric motors will also be supplied as part of a framework agreement with McDermott and partners.

“With 90% global market share and a fleet that has accumulated more than 4.2 million hours of service, Siemens Gas and Power is a worldwide leader in cryogenic boil-off gas compression,” said Matthew Russell, executive vice president of LNG for Siemens Energy’s Oil & Gas Division.

“We believe our expertise in the design and manufacturing of BOG compressors, along with our strong presence in the LNG market, played an integral role in securing the Golden Pass compression contract.”

Siemens Energy spin-off on Sept 28

By the end of September, Siemens will spin off and list its energy business. Subject to approval by the extraordinary shareholders’ meeting, the spin-off will and initial listing is to take place on the 28^th of September 2020.

Shareholders will automatically receive one share of Siemens Energy for every two shares of Siemens AG, and in the following 12 to 18 months, Siemens AG intends to further reduce its stake in Siemens Energy by a “significant” amount.

Siemens CEO Joe Kaeser said called the spin-off “a major milestone in the overall realignment that is preparing the Siemens companies for the massive technological transformations that we are anticipating.”

Siemens Energy will create a strong, focused, global company with operations spanning the entire energy value chain, including the service business. Following the spin-off, the mother company Siemens AG will concentrate on Digital Industries, Smart Infrastructure and Siemens Mobility. The healthcare technology business, Siemens Healthineers, has already been publicly listed as a separately managed company since March 2018.

If enacted, that cap would be at just under 50% of total UK regasification capacity and Hadrien Collineau, a senior analyst with WoodMac’s gas team says it might be necessary to take that step given if demand stays subdued through the summer. Currently, demand is regularly testing a floor of just 3 billion cubic metres (bcm) per month.

“The industry and power sectors account for most of the UK’s summer gas demand. And with most lockdown measures continuing throughout May, we expect that demand will come in 18% below its five-year average,” he explained.

UK production still profitable

At the same time, UK gas production has been rising by 3% from 2019 levels given that the risk from low prices at the National Balancing Point (NPB) is “minimal,” he noted, explaining “sustained price levels below US$1.5 per million British thermal units (MMBtu) would be necessary to shut in production.”

Though producers’ profits are squeezed by lower gas prices, any material production shut-ins are unlikely as operators will rather choose to cut costs by delaying non-essential spring and summer maintenance. In Collineau’s view “this could add volumes to the market through to July, but potentially ease the pressure in late-summer.”

Exports to EU reach their limits

Exporting the surplus supply is an option, but space in the Irish market is very limited as is transport capacity on the two interconnectors with Continental Europe. The IUK and BBL, connecting UK to Belgium and the Netherlands, are already operating near full capacity.

“The UK’s export capacity to continental Europe via the IUK and BBL are booked at 65% and 100% capacity, respectively, for May, and at 48% and 100% for June, respectively,” Collineau said. “We expect this level of utilisation to be sustained through summer, providing a minimum 1.7 Bcm/month of takeaway capacity.”

Britain’s total gas export capacity to continental Europe is 2.3 Bcm/month, but the NBP discount compared to prices at the Dutch TTF trading hub is currently not large enough to spur higher flows. In April, utilisation averaged 30% and 75% on the IUK and BBL, respectively.

Less supply from Norway, but more LNG

Norwegian suppliers of pipeline gas have reacted to the oversupplied UK market by reducing their exports by more than half in April, but Norwegian flows are unlikely to drop below 1 Bcm/month through the summer period.

In contrast, LNG supply as move in the opposite direction. “Utilisation at the UK’s South Hook terminal has ramped up significantly as it absorbs more Qatari LNG that cannot find a home in premium Asian markets.

Running low on free storage

The UK’s largest and only long-range storage facility, Rough, closed in June 2017. The field contained over two-thirds of the UK’s total storage volumes. “So as, we approach this year’s summer season, storage is already very limited, with inventories more than 60% full. With only 600 million cm of space for storage injections this summer, so there’s a risk that storage could be full by early June,” Collineau warned.

With summer demand subdued and limits on storage capacity, the UK system could run out of space soon, which is why it might be necessary to cap LNG import capacity at 2 Bcm/month through the summer month. “LNG exporters hoping to place cargoes into the UK market have the most to lose,” he noted, but “there simply won’t be any more space.”

“With work already underway, it was crucial that GE complete the turbine modernization to restore the availability of our plant, which produces the equivalent of electricity consumed in average by 3 million homes,” said Alessandro Gaglione, Tirreno Power Head of Power Generation. “Relying on outstanding technical skills of the staff involved in this critical operation, we decided to confirm the work plan in order to make our plant promptly available for the national grid to help secure the energy supply in Italy in the emergency period.”

The modernization consisted of the installation of a new rotor and compressor to increase the robustness and durability of the turbine. The engineering enhancements reduce the impact of degradation naturally occurs with time on the rotor components, improving their operating lifespan and reducing the risk of unplanned downtime.

Extra layer of safety measures

In the face of the pandemic, engineers from GE its field service team FieldCore worked closes with Tirreno Power experts to implement more frequent disinfections at the site, physical distancing rules and the use of personal protective equipment.

“The 9F.03 gas turbine upgrade was critical to increase the current performance and reliability of Tirreno Power’s plant,” said Steven Miller, Service Leader for Europe at GE Gas Power. “During these unprecedented times when access to reliable electricity is more important than ever, we are committed to providing our customers with the exceptional support and services they have come to rely on while leading with safety.

“Despite the daily challenges caused by the pandemic and longer-than-expected isolation from family and loved ones, our 30-strong team worked day and night to complete the outage, safely,” he underlined.

Throughout Italy, GE-built technologies generate over one-third of the electricity supply.

“There is a high degree of uncertainty for the projects currently being planned for the period after 2020 due to the current political and economic conditions,” BDEW head Kerstin Andreae said, forecasting planned investments by power suppliers this year and next are set to fall to levels not seen since 2013.

Key energy policy legislation has been held up in government and parliament for months, undermining planning security for companies and investors in the sector. While the nuclear phase-out by 2022 is regulated, the coal exit act and law amendments for wind and solar power development have yet to be approved.

Coronavirus response could accelerate energy transition

For months, policy makers have been focussed on how to contain the coronavirus while limiting the economic impact of the crisis. But the German Economic Institute (IW) stressed this mean key energy policy measures have to now be delayed.

“Instead, some should even be accelerated,” said IW’s Thilo Schaefer, head of environment, energy and infrastructure. “For some time there has been a lack of clear and reliable perspectives for climate-friendly investments, such as in decarbonising the industry sector.” In this context, he called for an early reduction of the renewable energy levy (EEG levy) to reduce the cost of electricity for households and industry.

Tax credits for green energy investment

The German finance minister Olaf Scholz said a stimulus package oriented toward international climate targets and Germany’s goal of becoming carbon neutral by 2050 would "make sense," as soon as the most pressing phase of the pandemic has ended.

Proposals include clean energy tax credits, requirements that bailed-out industries like airlines commit to emissions cuts, and investments in green infrastructure. This approach could both ensure that climate action is not neglected during the crisis, and help Germany stay competitive in energy transition technologies, a sector that could be worth about 23 trillion dollars by 2030, according to the World Bank.

COD on the Sergipe power plant will earn Golar approximately 6.9 billion Brazilian Reals, or $1.3 billion, in pre-inflation adjusted revenue less operating costs over the next 25 years, the company said in its first quarter interim results. Acceptance of the charter for FSRU Golar Nanook will bring an additional $549 million in revenue, less operating costs, over the same period.

“We expect Sergipe to take advantage of merchant power opportunities where the marginal cost of power exceeds the LNG purchase price, currently below $2 per MMBtu delivered ex-ship in Brazil,” said Golar LNG chief executive Ian Ross.

Short time-to-cash-flow

“The first three small-scale customers have now been formally signed up and LNG distribution operations are expected to start in 2021,” Ross said, stressing the Brazil FSRU and integrated power project is characterised by a “short time-to-cash-flow” and a “very strong project return.”

Going forward, Golar Power seeks to convert the small-scale letters of intent it has into binding sales agreements over the course of this year, and sign new ones. To date, some 200 potential customers signalled interest to pursue various small-scale LNG opportunities, the Golar CEO disclosed, which demonstrates a “robust consumer appetite to reduce both energy costs and environmental footprints.”

FID on Barcarena FSRU expected in mid-2021

Financial close on a floating LNG import terminal in Barcarena is expected later this year or early next year, with the associated 605 MW power station meant to take a financial investment decision (FID) in mid-2021. The Golar LNG CEO said he expects to reach supply agreement with industrial customers over the next four months for gas offtake from the Barcarena-based FSRU, scheduled to start operations in 2022.

He also wants to finalize arrangements for locating a Floating Storage Unit (FSU) at Suape over the course of the year.

Together Petrobras, Golar is working to overlay its geographical coverage of LNG distribution onto BR Distribuidora’s 7,600 Brazilian fuel stations. The aim is to create the necessary infrastructure to convert current diesel, heavy fuel oil and coal consumers to cleaner-burning gas through the provision of a stable and secure LNG supply.

Throughout Latin America, Golar Power is working to develop an additional 10.6 GW of gas-fired power plants to underpin the development of additional floating regas terminal, some of which are currently in the permitting process. All these FSRU projects have downstream monetization routes through a combination of power generation, gas consumption by industry and small-scale LNG distribution via cabotage and ISO containers to end users.

The expansion will increase the Balikpapan refinery’s output from 240,000 barrels per day (bpd) to 360,000 bpd and enable the facility to produce Euro-V standard fuels. To that end, the development plan for the refinery also foresees the installation a liquefied petroleum gas (LPG) sulfur removal unit; a propylene recovery unit; and an 80,000 bpsd middle distillate hydrotreater.

Siemens’ scope of supply includes 17 reciprocating compressors, along with a single-stage, hot gas expander. Specific compressor models to be provided include eight HHE-VL compressors, two HHE-FB compressors, four HHE-VG compressors, and three HSE compressors. Additionally, Siemens Gas and Power will supply four SGT-800 industrial gas turbines and five SST-600 steam turbines for the Balikpapan power plant.

All the reciprocating compressors will be manufactured in Siemens’ Naroda Gujarat plant in India, while the hot gas expander will be built in Olean, New York, the steam turbines in Görlitz, Germany, and the gas turbines in Finspong, Sweden. Installation and commissioning of the equipment are slated for 2022.

Recovering waste heat from the cracker

Waste heat from the refinery’s cracker, possibly in the form of flue gas, will be recovered by the hot gas expander to produce approximately 20 MW of free power. This energy will then be used to drive the plant’s central air blower, along with a single steam turbine, which helps reduce overall steam consumption and reduces operational costs for Pertamina.

Meanwhile, the HHE reciprocating compressors will be used in various refinery processing units to stabilize plant operation. The compressors comprise a heavy-duty, cast iron frame, which reduces vibrations transmitted to associated piping and provides maximum stability by using internally ribbed walls and integral cross-member bearing saddle supports located between each crank throw.

“The strong performance of our existing fleet of compressors across the region and strong in-country service capabilities played a key role in this strategic win. These factors, coupled with performance, efficiency, and reliability of the SGT-800 gas turbines, will enable the cost-effective expansion of the Balikpapan refinery,” said Matthew Chinn, executive vice president New Equipment Solutions for Siemens Energy Oil & Gas Division.