The correlation of daily price movements between West Texas Intermediate (WTI) and Brent for the past year was 0.44, indicating a positive connection between these crude oil benchmark prices. Analysts at the U.S. Energy Administration (EIA) point out that this number is typically higher than 0.90, indicating a strong positive relationship. But recent volatility in the spread between WTI and Brent has lowered the number in 2020.

In contrast, the daily gas prices at the U.S. Henry Hub, Asia’s Japan/Korea LNG (JKM), and the UK National Balancing Point (NBP) show little correlation largely because most natural gas is still transported through pipeline systems, though the share of LNG trade is rising consistently.

Cost of transport hamper gas market integrated

Shipping crude oil is comparatively cheap, while the cost of liquefying and transporting natural gas in the form of LNG can, in some cases, cost as much or more than input cost of the natural gas. According to the EIA, these high costs transport costs have hindered natural gas trade in the past and helped to keep regional markets isolated.

Cheaper U.S. LNG, liquified under tolling models, has led to increases in both the number of LNG importers and exporters. More and more natural gas gets traded on a short-term or spot basis, which increased to 34% of volume traded last year, according to U.S. government figures.

Higher spot market liquidity will gradually shift the gas trade way from long-term, oil-linked contract pricing toward more short-term, spot-based transactions which is seen as an enabler of a more integrated global natural gas market. Growing U.S. export capacity contributes to this transition, provided that the volumes of gas production and exports get maintained as economies around the world struggles with a global health crisis and economic recession.

As one of California’s load-serving electric entities, SCE won bids to develop several solar-plus-storage projects, located at the same point of interconnection. “These new emissions-free projects will help us ensure the reliability of the grid for our customers and integrate an ever-increasing amount of clean renewable energy over the next decade,” said William Walsh, SCE vice president of energy procurement and management.

Regulator requests available backup capacity

To mitigate the risk of intermittency issues from rising renewable energy deployment, the California Public Utilities Commission (CPUC) granted permission to extend the lifetime of several gas peakers. The regulator also requested that 3,300 MW of “system-level resource adequacy capacity” - notably energy storage - needs to start operating incrementally.

At least half of that capacity, including the seven new power storage units, needs to be built and commissioned by the beginning of August 2021, with the full capacity due operational by August 2023. To that end, the energy regulator has awarded several projects, with a contract length ranging from 10 to 20 years.

Tender for solar-plus-storage projects

The largest energy storage project, awarded through the CPUC tender, is the 230 MW/920 MWh McCoy project connected to NextEra’s 250 MW solar farm, followed by Blythe 2 and 3 projects (both 115 MW/460 MWh), under development by NextEra Energy.

Southern Power was awarded two energy storage projects, both coupled with solar PV installations owned by Canadian’s Solar Recurrent Energy. These projects are the 88 MW/352 MWh Garland Project and the 72 MW/288 MWh Tranquility Project.

The smaller 50 MW/200 MWh Sanborn project went to TerraGen, while a development contract for the stand-alone 100 MW/400 MWh storage project was won by LSPower.

All of the energy storage projects are situated across Southern California’s Kern, Fresno, Riverside and San Diego counties, set to enhance the energy supply security of approximately 15 million people.

For the product launch, PowerPHASE has been focusing on applications on GE’s 7FA turbines, the company said in a technical presentation seen by Gas to Power Journal.

Storing compressed air

The Storage Engine, a flexible version of its compressed-air energy storage (CAES) plant, is based on a repowered gas turbine. It combines the company’s compressed-air technology with its FastLight energy storage solution, which is designed to convert 10% of the output of any gas turbine into energy storage.

The technology is based on a repowered gas turbine whereby the compression process has been amended and replaces with fuel-driven compressors. The system captures excess electricity and stores it in the form of compressed air in dedicated cylinders, for later use. When discharged, the stored energy can generate between 90 MW and 400 MW for a limited number of hours.

Functionality of peaking plant

“The unique feature of the Storage Engine is that is functions as a peaking gas turbine by displacing a series of electrical and fuel-driven Turbophase compressors when the stored compressed air has run out,” Kraft explains. The novel way of energy storage enables to quickly supply megawatts of power to the grid.

Turbophase is essentially a modular air injection system, using a four- or five-stage intercooled centrifugal air compressor to make air-flows more efficient than in a traditional gas turbine and increases output by 10-20%. The system enhances the mass airflow by injecting air into the compressor discharge, which reduces the power needs per pound or air, compared to traditional axial air compressors.

Considering the small footprint of Turbophase unit, the add-on energy storage unit can be configured in a modular way to suit the various needs of utility customers.

Florida-based PowerPHASE has over 100 patent and is striving to use its air-compression technologies to help solve the intermittency challenge of renewable power supply through energy storage. CEO Bob Kraft claims the company’s new Storage Engine comes at less than a tenth of the cost of battery-based energy storage.

The DPP2 Bernland power plant, operated by state-owned utility Energiebedrijven Suriname (EBS), was built by BWSC and MAN in 2012 in Suriname's capital, Paramaribo, and expanded three years later by an additional 21 MW.

The latest plant expansion will be achieved by adding two MAN 18V48/60TS engines, each driving a 21 MW alternator. This second expansion of 42 MW the project is again being financed by OLIBIS in conjunction with EBS and the Surinamese Government.

OLBIS chief executive Otmar Sibilo commented that “despite Suriname going through very difficult financial times and serious currency devaluation, OLIBIS will be sponsoring the much needed expansion of EBS’s generation capacity.”

Reducing noise levels

After the expansion, EBS will gradually reduce the operation of the less efficient and smaller engines in the adjacent DPP1 power plant to reduce noise levels to the benefit of local residents.

“The project demonstrates the success of our long-term customer relationship with OLIBIS and EBS which valued our power-plant technologies as reliable and efficient solutions for their energy projects for 15 years,” said Thorsten Dradrach, MAN’s Head of Sales for Power Plants in the Americas. Together with BWSC, the Augsburg-based manufacturer already installed more than 1,000 MW of power-plant capacity worldwide.

Under a memorandum of understanding, Hyosung and Linde agreed to jointly build a liquid hydrogen plant will have a capacity of 13,000 million tons per year. To that end, the two chemical companies aim to set up a joint venture before the end of this year.

Ulsan was chosen as the plant’s location as it is home to some of South Korea’s largest refineries and petrochemical industry as well as the carmaker Hyundai Motor, which develops hydrogen powered-vehicles.

Construction is scheduled to start in the first quarter of 2021 and is due completed in the following year.

The 13,000 mt/year liquid hydrogen plant, which can power 100,000 hydrogen vehicles on a single charge, will be the world's single biggest such plant, Hyosung said in a statement. Initially, the liquid hydrogen will be used mainly as a fuel for ships, vehicles and forklifts but it can be amended for use in the power sector as well.

Korea aspires to become hydrogen economy

Hydrogen is a zero carbon fuel source, deemed vital to change the carbon-centered economies.

“The investment will play a big role in facilitating South Korea's hydrogen ecosystem and the government's push for hydrogen economy," Hyosung Group chairman Hyun-joon said. The government’s so-called ‘Roadmap for a hydrogen economy’ envisages that South Korea will produce 81,000 hydrogen-powered cars by 2022, which will increase to 6.2 million units by 2040.

The government’s strategy also aims for Korean manufacturers to produce 15 GW of hydrogen fuel cell capacity for electricity production in 2040, of which 8 GW will be for domestic use. This 8 GW capacity equals about 7% of South Korea's currently installed power gen capacity of 116 GW.

Hydrogen or synthetic methane can be produced locally with wind and solar energy, using just water and air as the raw materials, and stored in underground gas taverns for use during times when little renewable energy is available and batteries are drained.

Burning renewable fuels in flexible, fast-start gas power plants dramatically reduces the required size of battery storage, improves power system efficiency and, lowers generating costs, and provides high security of supply even during rare and unusual weather patterns.

“The market for hydrogen-fuelled power plants will emerge along with regulations restricting the burning of fossil fuels. We are well positioned to serve the power industry in its transition to 100% renewable electricity generation,” said Marco Wiren, president of Wärtsilä’s Energy Business.

Wärtsilä engines already run on a variety of sustainable fuels, he pointed out, and “are offering a highly dynamic balancing power for these future [decarbonized] generating systems.”

The Finish technology group sees hydrogen co-firing as a way to future-proof its engines at a time when more stringent emission regulators accelerate the trend towards decarbonisation of the shipping and power generation sector. In addition to hydrogen, other potential renewable fuels are being studied for future applications.

To attract US spot cargoes going to North East Asia, instead of Europe, JKM would have to rise substantially above their current premium of $0.50/MMBtu to the TTF. Rising demand in Asia, both from Korea as well as China and potentially Japan, could increase the JKM premium to take account of higher shipping costs from the Atlantic Basin.

But price direction on global gas markets will also largely depend on Henry Hub, which is currently torn between falling domestic demand due to coronavirus effects and associated gas production winding down in response to the crash in global oil prices.

Korea demand could tighten gas market

The extend of the fuel switch largely depends on the price flexibility of thermal coal price in Asia, which are seen having “only limited downside in the event of coal being squeezed out of South Korea’s power sector.” Moreover, commercial Korean fuel switching would take time to implement on a large scale, so it would happen too late to bolster Asian gas prices in summer 2020 and only have an effect starting from October.

KOGAS’ substantial amount of spare gas-fired power generation capacity could, in the event of a fuel switch, substantially tighten global LNG markets. Utilizing all spare gas-fired capacity would boost Korea’s would add 1.9-2.8 million tons of demand year-on year in South Korea, according to Energy Aspect calculations. The aggregate Northeast Asia fuel switch would be up to 7.4 million tons per month if Japan also switched.

At current prices for Australian thermal coal, the price of feedgas for generators would need to be around $6/MMBtu in South Korea and $3/MMBtu in Japan, with analysts noting a major Japanese fuel switch is “mostly out of reach” due to the lower switching price.

Fuel taxes favour gas over coal

The higher fuel switching price in Korea than in Japan is caused by a different tax system for thermal fuels. The South Korean government in April 2019 reset taxes to favour gas over coal in the power sector and also levied a price on carbon emissions.

Factoring in these taxes, Energy Aspects estimates that for Korean oil-indexed gas contracts to drop below the fuel-switch level, crude prices must average below 27 $ per barrel over the indexation period. For Japan it would be 15 $ per barrel.

Brent forecasts indicate that KOGAS’ oil-indexed gas prices would be sufficiently low for a fuel switch in the period between September 2020 and January 2021. Maximum coal-to-gas switching in this period would push up Korea’s LNG demand by about 11.6 million tons, with 7.0 Mt of that in the fourth quarter, analysts forecast.

For US LNG shipments, the rising gas demand in Korea in the autumn could help offset some lost shipments for this June – reportedly up to 25 cargoes.

Coal-fired generation has borne the brunt of the Covid-19 power demand loss, running at half the capacity rate assumed in the Indian Central Electricity Authority’s modelling guidelines used to evaluate the financial and operating performance of new coal-fired power plants.

"Coal-fired power generation has worn more than 100% of the COVID-19 power demand loss," commented Tim Buckley, director of energy finance studies, Institute for Energy Economics and Financial Analysis (IEEFA). "Renewables get priority over coal when power demand drops given their "must run" status, which is a reflection of their zero marginal cost of production. Coal-fired generation, the high marginal cost producer, is losing out," he explained.

Renewables accounted for more than two thirds or 9.39 GW of India's capacity additions in fiscal 2019/20, while new thermal power plants delivered 4.3GW, net the of the 2.5GW removed due to end-of-life plant closures.

Looking ahead, the pricing trends for new electricity generation clearly favour renewable energy over coal, particularly when it comes to expensive non-minemouth or import coal-fired power proposals.

New finance gets behind solar

Financing has dried up for coal, with most of India’s domestic banks following low-carbon strategies of international finance. A landmark 2GW solar tender awarded by NHPC in April 2020 priced at a near record low of Rs2.55/kWh, fixed flat for 25 years. This tender was won by leading Indian renewable energy developers, most of whom have access to global capital backers like SoftBank of Japan, EQT Infrastructure of Sweden, Temasek of Singapore, EDF and Total of France and Brookfield of Canada.

Considering changing preferences of energy finance, IEEFA analyst indicate that India’s National Electricity Plan might have to be reworked. The government assumes an additional 70GW or more of new coal-fired power plants installed by 2026/27, and the closure of another 39GW, relative to the position as at 31 March 2020.

“That assumes some $70bn of new investment in coal-fired power,” Buckley said, suggesting financing for new coal plants will be hard to come by: “Why would any debt or equity capital providers fund a high emission, highly polluting new coal-fired power plant at double the cost of deflationary, domestic renewables?”

At a cost of $350/kWh installed, Order 841 could unlock 7,000 MW of new storage based solely on wholesale market participation in the market zones of U.S regional transmission operators (RTOs).

According to analysis by the Brattle Group, this increases to 50,000 MW if all benefits of energy storage can be capture, e.g. ancillary services. The highest potential for storage additions is seen in PJM and in MISO Interconnection, followed by the Electric Reliability Council of Texas (ERCOT).

Storage becomes a price-setter

The FERC Order 841 requires regional transmission operators (RTOs) to execute energy storage transactions at the locational marginal price, allowing storage to directly compete with coal- and gas-fired power plants. RTOs need to ensure that energy storage can be dispatched, when needed, and set the wholesale price.

“How RTOs implement Order 841 will directly affect storage’s market value,” analyst commented.

Grid operators have flexibility to launch new ancillary service products, set appropriate minimum run-time requirements and determine if storage can sell ancillary services without participating in the energy markets. For new-build storage units, the grid operator can set a minimum size requirement that may not exceed 100 kW.

Need to remove T&D barriers

“Though FERC’s order 841 addressed wholesale barriers, state regulatory action is needed to address transmission and distribution as well a customer-related barriers,” analyst said.

To realise the goal of 50 GW energy storage deployment, there needs to me a more granular, cost-based and stable rate design, the Brattle Group said. Today, storage is often not considered in T&D planning processes and there is no clear dispatch priority for storage.

Figures by the US Energy Information Administration (EIA) also show coal’s share continued to erode, falling to 18.3% in February and 17.3% in March – down from levels above 50% a as recently as 2008 for the same months.

Lockdowns to contain the coronavirus outbreak slashed energy demand and accelerated a shift from coal power to renewables, which keep producing electricity at near-zero operating costs. Other reasons for the demise in coal power are low gas prices, unseasonably warm weather and new and cost-effective wind and solar capacity connecting to the grid.

Energy demand destruction due to the coronavirus pandemic could see renewables surpass thermal energy sources already this year, rather than in 2021 as forecast by the U.S. Energy Administrations.

In its latest projections, the EIA had estimated projects electricity generation from renewable sources such as wind and solar to surpass nuclear and coal next year and to surpass natural gas in 2045.

Learning rates for wind and solar PV technologies are assumed to lead to 40% drop in capital cost by 2050, pushing up the market share of in the U.S. energy mix to 19% in 2019 to 38% in 2050.

Deployment of renewables varies greatly across the United States. Wind-powered generation grows the most in the West and Mid-Continent regions, and solar-powered generation grows the most in the Southeast. Offshore wind is only built off the coast of the Northeast and the PJM Interconnection.

In the second quarter, Siemens was noticeably impacted by the coronavirus pandemic in the areas of volume, profit and cash. Orders declined 9% on a comparable basis to €15.1 billion, while revenue was flat at €14.2 billion.

With an order backlock at €69 billion and a further €81 billion at Siemens Energy, Group CEO Joe Kaeser said the company “performed solidly” in the second quarter of fiscal 2020.

At €1.6 billion, the adjusted EBITA for Siemens’ Industrial Business was only 18% lower year-over-year, impacted by sharp drop earnings in the energy business and tax expenses for the care-out of Gas and Power. As a result, net income dropped 64% to €697 million

Turn-around expected in Q3

“We delivered a robust quarter given the serious circumstances,” said Joe Kaeser, President and CEO of Siemens AG. He lauded his team for keeping up the original timeline for the spin-off of our energy business, adding “we expect to reach the bottom in the third quarter of fiscal 2020.”

In view of the economic uncertainty arising from the pandemic, Siemens ditched is original guidance for fiscal 2020, but still sees itself “well positioned both operationally and strategically for the coming quarters.

Spin-off of energy business on track

Anticipating an “even stronger impact” of the pandemic on business development in the third quarter and beyond, Siemens noted “reliable estimates are not yet possible” and withdrew its original growth guidance. Instead, the company expects a moderate decline in comparable revenue in fiscal 2020, notable for Digital Industries and Smart Infrastructure.

Despite the current economic uncertainty, Siemens sticks to its plans to spin off and publicly list Siemens Energy before the end of fiscal 2020. Kaeser indicated the company expects to record a spin-off gain.

Financially, Siemens is well prepared for challenges ahead. “We have a strong rating and a very solid liquidity position,” said Ralf P. Thomas, Siemen Chief Financial Officer (CFO). “If needed, we have direct access to more than €11.4 billion in net liquidity.”

The Hybrid STATCOM technology has been deployed over three separate substations – Bolney, Ninfield and Richborough – along the transmission network in southeast England. With less than 90 millisecond response time, three units delivers dynamic reactive power range from -300 Mvar inductive (absorbing vars) to +675 Mvar capacitive (injecting vars) with availability of 95%, as per customer requirement.

Stabilizing Nemo Link

The DRC compensators support help National Grid enhance regional voltage stability for the UK-Belgium HVDC interconnection, also known as Nemo Link. The Interconnector commenced operation at the end of January 2019 and is capable of delivering more than 1 GW of bi-directional power between the two countries.

The UK has been using Nemo Link to import cheap electricity from the Continent. Over 5,889 Gigawatt-hours (GWh) of electricity were imported to the UK in the first year of operations and nearly 176 GWh to Belgium through a "near real-time" power trading system.

Near ‘real time’ power trading

Electricity traders can choose from a variety of products to move electricity back and forth between the two countries across the English Channel. Capacity can be bought closer to real time through hourly nomination gates. This “closer to real time service” enables traders to respond quickly to sudden changes in supply and demand, thereby reducing the potential for spikes in power prices.

“By enabling the market to react immediately to rapid changes in supply and demand, Nemo helps to better balance an energy system that is more reliant on intermittent wind and solar energy;” explained Jon Butterworth, President of National Grid Ventures. “In the coming years, interconnectors like Nemo will play an increasingly important role,” he forecast with reference to the TSO’s aim to “share renewable energy resources across borders” to reach net-zero carbon emissions by 2050.

For National Grid, Nemo Link is the third interconnector to Europe next to the IFA link to France and BritNed to the Netherlands. Three further projects are under construction to France, notably IFA2 due operational 2020, the North Sea Link to Norway due operational 2021, and the Viking Link to Denmark due onstream in 2023.

By 2030, some 90% of electricity imported via National Grid’s interconnectors is meant to originate be from zero carbon sources.

By late March, lockdowns caused a 13% drop in average daily demand in the overall in the area of the New York Independent System Operator (NYISO). Demand remained subdued through April, analysts at the U.S. Energy Information Administration (EIA) noted.

In its hourly electric grid monitor, the EIA compares demand data from the 64 balancing authorities in the contiguous United States, including NYISO. Using this data, analysts compared daily electricity demand in 2020 through May 1 with the same daily averages from January through June in 2016–2019, excluding weekends.

NYC hit hardest

New York City, hardest hit by the pandemic, saw the most pronounced changes in electricity demand and usage patterns, the EIA hourly electric grid monitor shows.

Downtown New York, the NYISO Zone J, normally consumes about one-third of total NYISO supply. However, the lockdowns from late March through April slashed daily weekday electricity demand to levels 16% lower than historical demand.

NYISO reports that “the reduction in electric demand from commercial customers is a leading driver of overall reduced electricity consumption.” More than half of New York State’s electricity sales go to commercial end-users, a percentage only exceeded by the District of Columbia (72%), according to data in the EIA’s Electric Power Monthly.

The ‘Energy Transition Lab’, established by Wärtsilä, tracks supply and demand pattern throughout Europe with the aim to make industry and policy makers understand the impact of the coronavirus containment measures on electricity markets. The aim of this platform is to help accelerate a green energy transition.

Lack of flexibility at grid level

The lockdown period has unintentionally served as a test of what a system would look like if the dominant energy source was renewables, exposing countries with a lack of flexibility at grid level. Unprecedented demand destruction during the lockdown meant that Germany, Spain and partially the UK, were running their supply-demand balance based on 50-78% renewables on most day since lockdowns began in mid-March. “Germany could have run on 100% renewables, but fossil fuel plants didn’t shut down likely because of what it takes to start back up,” analysts commented.

The coronavirus crisis has caused an average 20% drop in electricity demand across Europe, forcing utilities to stop running many fossil power plants due to their higher marginal costs compared to renewables. However, asynchronous generation (wind, solar) cannot provide this inertia - a feature related to the energy stored in rotating motors of synchronous generators at coal, gas and nuclear power stations. It prevents grid frequency from falling too quickly after a disturbance, e.g. a generator trip, because the inertia stored in rotating motors provides resistance and frequency response.

Need for energy storage, more interconnectors

Since mid-March, wholesale power prices have been down 50% year over year across most of Europe, some days prices are even negative. Flexible generation, however, has been outperforming during that time, and is up 20% in usage compared to last year. Energy storage providers have been benefitting from their ability to charge batteries when prices are low and discharge when prices are higher.

Energy storage and flexible, fast-ramp power sources proved to be vital to balance the sudden rise in renewable contribution. To handle the intermittency challenges of weather-dependent supply from wind and solar power sources, analysts call for stronger interconnection capacity across the EU, to prevent curtailment of excess offshore wind and/or solar power in-feed to the grid.

„The current dynamic shows the need for more power supply flexibility and energy storage across Europe,” analysts concluded.

Apart from inviting bids for the proposed CCGT near the city of Orange, Texas, Entergy Louisiana issued an RFP for 250MW of solar resources. The bidding process for the Texan project includes a market test for a self-build option. Bidders are asked to submit proposals for power purchase agreements, spanning for ten to 20 years, starting no earlier than June 1, 2025.

To help finance new generating capacity, Entergy Texas filed for an increase in its distribution cost recovery factor. To curb Entergy Group‘s overall operating costs, the Indian Point Unit 2 was permanently shutdown. Business highlights in the first quarter was the commissioning and operational start of the Lake Charles Power Station on budget and ahead of schedule, as well as approval for the Sunflow solar project in Mississippi and the Searcy solar project in Arkansas.

For the first quarter of 2020, Entergy reported earnings of 59 cents per share and affirmed its 2020 adjusted EPS guidance of $5.45 to $5.75. The New-Orleans based company delivers electricity to 2.9 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. To this end, it owns and operates power plants with approximately 30 GW and generates annual revenues of $11 billion.

Entergy Entergy Chairman and CEO, Leo Denault, said first quarter results were “solid,” in the face of the energy demand destruction during the current pandemic. “The past few months have presented extraordinary circumstances,” he said, stressing “providing safe, reliable power is essential [and] recent events have not changed our objective to be the premier utility that delivers sustainable value for our stakeholders."

Infrastructure issues had kept a lid on storage injections as U.S. network operators have been struggling to balance high levels of domestic production and a sharp drop in demand due to lockdowns to contain the coronavirus.

Debottlenecking in the South Central storage region, as of late, helped increase storage injections to levels not seen over the past five years.

South Central net injections of 48 Bcf last week were the third biggest volume of gas put into storage in the five regions ever reported by EIA over the past decade. Weekly net injections of natural gas have equaled or exceeded 100 Bcf a total of 36 times since 2010; and EIA figures show that 16 of those occasions occurred during the month of May.

Net injections into storage tend to be high in May because of the availability of free working gas capacity and reduced, shoulder season load levels.

High inventories in winter 2019/20

Continued rise in U.S. gas production, combined with limited demand due to unseasonably mild winter weather, has left gas storage on relatively high levels during the past winter.

The average daily natural gas supply for the Lower 48 states grew about 6 billion cubic feet per day (Bcf/d) over the winter 2019/20, while average daily demand from industry, the power sector and net exports to Mexico and LNG feedstock) was up about 3 Bcf/d, according to IHS Markit data.

The EIA’s report on natural gas working stocks through mid-April 2020 shows that inventories are already at least one-half full in the Lower 48, South Central Nonsalt, South Central Salt, and the Pacific storage regions.

Saudi Arabia-based developer ACWA Power has signed three strategic agreements, worth up to $2.5 billion, with Uzbekistan’s Ministry of Energy to enhance the country’s installed generating capacity. The main deal is a 25-year power purchase agreement (PPA) and investment agreement, valued at $1.2 billion, which includes the development of 1,500 MW combined cycle gas-turbine (CCGT) power plant.

Situated in Shirin City, the Syrdarya region, the CCGT is being developed as a build-own-operate-transfer (BOOT) project, with ACWA Power assigned to lead in constructing, engineering, operating, and maintenance works.

Initially, Uzbekistan wanted the power plant to be developed in two stages so it could eventually be expanded to 2.600 MW. If it reaches that capacity, the mega plant would significantly enhance Uzbekistan’s installed power generation capacity of currently just over 12,400 MW.

In addition, ACWA Power signed an implementation deal worth between $550 million and $1.1 billion to deploy renewable energy sources and help bring Uzbekistan’s installed wind power capacity to nearly 1,000 MW. Under a third deal, Air Products & Chemicals and ACWA Power agreed a equip Uzbek students with the tools and knowledge to gradually support a local supply chain for the country’s utilities and chemicals sectors.

Muskat-listed ONEIC, meanwhile, was awarded a $7.4 million construction contact to build three 20 megawatt-ampere (MVA) substations for industries in the Wilayat of Duqm within the Al Wusta governorate.

Today, the CHP plant generates up to 174 MW of electrical energy and 200 MW of thermal energy. Once upgraded with two MST050 turbines, with the total output of 56 MW, the plant will produce up to 230 MW of electricity and also more heat for district heating.

In the cogeneration process, the condensation heat that is not used to generate electricity is utilized in the citywide district heating network - thus increasing fuel efficiency.

Producing heat from gas CHP, not coal

By investing to upgrade the CHP, Leipzig’s municipal utility intends to use the additional capacity to reorganize its district heating supply. Currently, a large part of the city’s heat supply depends on the Lippendorf coal-fired power plant, but this is meant to cease operations by end of 2022.

Uwe Lauber, CEO of MAN Energy Solutions said the steam turbines will help Leipzig achieve its sustainability goals set out for local energy supply. Sales manager Lars Schumacher added “the customer’s decision to order from MAN Energy Solutions was made due to the high efficiency and flexibility of our technology.”

To optimize the CHP’s overall efficiency, auxiliary cooling circuits were integrated in the district heating system. Analytics Telemetry Unit boxes, connected to the MAN CEON digital platform, will also be integrated in the turbines. “They enable the customer not only to have a round-the-clock monitoring of the machine operation, but also to receive fast access to remote support from MAN”, Schumacher explained.

Delivery and installation of the steam turbines in Leipzig are scheduled for the first quarter of 2021.

The Russian gas major confirmed it is fast-tracking major investments within its Eastern Gas Program to ramp up production and gas transmission capacities from Siberia to China. In Yakutia, Gazprom is working to bring the Chayandinskoye gas field to its design output of 25 Bcm and the Amur Gas Processing Plant is nearly 60% complete.

With a design processing capacity of 42 Bcm/year, the facility is essential to ramp up throughput of the China interconnector. To power the Amur GPP, Gazprom is building a new 160 MW combined-cycle power station called Svobodny TPP which is scheduled to start up in late 2020.

Installation of the first and second production trains is nearly finished and equipment is being prepared for start-up and commissioning. At the same time, gas separation equipment is being installed on train three and four.

New focus on 'Northern Gas Corridor'

The Russian arctic, notably the Yamal Peninsula is another key focus of Gazprom’s upstream efforts. This strategic oil- and gas bearing region has explored gas reserves of 16.7 trillion cubic meters, where Gazprom seeks to achieve an annual output of 310–360 billion cubic meters of gas. To this end, 52 new gas wells will be brought onstream at the Bovanenkovskoye field as well as a connecting pipeline, stretching to the Kharasaveyskoye field. 

Eager to expand the northern gas transmission corridor, Gazprom is setting up compressor stations and workshops at the Bovanenkovo– Ukhta 2 and Ukhta– Torzhok 2 gas pipelines. Supply from the northern gas corridor can be transported westbound and partially serve as a feedstock for the Nord Stream 2 pipeline.

The decrease in revenue was mainly caused by the outbreak of the pandemic and the imposition of various travel and work restrictions in China. “As a result, the only source of revenue earned for the first three months of this year was from the supply of LNG that has a thinner gross profit margin than that of construction related and consultancy work,” Zhonghua said in a statement.

JV with Shanghai Jiulian Group

The Group is planning to strengthen LNG supply during the 2020/21 heating period and beyond. To that end, it set up a 60:40 joint venture with Shanghai Jiulian Group to source stable LNG supplies and expand its business reach in to the high potential market in the Yangtze River Delta region which includes the area of greater Shanghai as well as the neighbouring Jiangsu, Zhejiang and Anhui provinces.

Zhonghua’s JV with Shanghai Jiulian Group focuses on LNG sales, engineering of pipelines and installation of LNG delivery equipment as well as consulting and transfer of heating systems.

At the same time, Zhonghua said it will maintain its solid relationship with Tractebel Engineering of France and Tianjin Jinre Heat-Supply Group on infrastructure-related business.

Looking ahead, the Chinese gas supplier and infrastructure company said it will “stay alert” and “keep a close watch on the Covid-19 development” while implementing timely measures to mitigate any possible business risks and minimize losses.