Sales challenges and supply issues of key storage components are other issues that energy storage manufacturers need to cope with in the current health and economic crisis. Travel bans and regional ‘shelter-in-place orders’ create significant hurdles for late-stage project implementation which requires on-site personnel.

"This has led to project delays and additional costs which, if they continue long enough, will lead to projects missing crucial deadlines - such as ITC qualification - which could destroy project economics,” said Brett Simon, Wood Mackenzie Senior Research Analyst.

A few forward-thinking developers have built longer delivery timelines into their contracts, allowing them to shift projects back from the original proposed commissioning date. Going forward, however, these problems are likely to escalate as permitting agencies for energy storage facilities begin to pull back personnel as further travel limits are imposed.

Product supply remains less of an issue today, yet this could change in the coming weeks. Most North American storage developers source batteries from Asian manufacturers, which are ramping back up as coronavirus impacts abate in manufacturing hubs. Delays will hence be on the order of weeks, rather than months, for product delivery.

Things are more critical for components made in the United States and Canada. “There is some murkiness around the supply of components manufactured in North America, such as steel enclosures for larger scale non-residential projects,” Simon commented. “Developers remain unsure how much of an impact manufacturing slowdown in the US and Canada will have and continue to monitor the situation closely.”

Putin instructed the go-ahead for both the liner part of the pipeline and the resource bas creation, allowing Gazprom to start the pre-investment phase and design-and-survey works. Under the Russia-China gas deal, supplies are being delivered at an estimated price of $350-$400 per thousand cubic meters.

Power of Siberia 2 allows for pipeline gas deliveries from Russia’s Western Siberian fields to China, complementing the eastern route - the initial Power of Siberia gas pipeline - which already supplies 38 Bcm/y under a 30-year sales and purchase agreement between Gazprom and CNPC.

China lifts lockdown but energy demand stays low

Analysts doubt, however, that China will need much additional natural gas supplies in the short- to medium-term as the country is slowly recovering from the coronavirus pandemic. Though manufacturing is resuming, the tepid recovery still needs to translate in a substantial rise in energy demand.

The rebound is patchy, our LNG Unlimited data shows, with imports recovering from less than 0,8 million tons at the height of the pandemic in China to 1,06 million tons in the last week of February – just to fall off again to less than 0.9 million last week.

Power generation in China notched up March, after falling by a staggering 8.2% in January and February when the country was on lockdown to contain the coronavirus pandemic. Factory output in the first two month of 2020 turned out 13.5% lower from the pre-year period, while retail sales plunged by 20.5%, according to government data.

V-shaped recovery deemed ‘unlikely’

Early signs of China’s economic recovery were overrated by analysts in the hope of a quick rebound in oil and gas demand of the world’s largest commodities buyer. However, the Shanghai Petroleum & Natural Gas Exchange cautioned that the oversupply situation remains relatively unchanged; hence LNG imports are expected to remain sluggish through April.

The Chinese government has resorted to a range of fiscal stimuli to jumpstart economic activity, including cutting electricity tariffs by 5%. Analysts are unimpressed, saying “a V-shaped recovery remains unlikely” and Kpler ship tracking data indicates there will be year-on-year cargo losses in March.

Demand destruction is particularly striking when it comes to natural gas. China’s LNG imports growth slumped to 2.3% in January and February, down from 19% in the same period last year. China imported 11.13 million tons of LNG in the first two months of this year, up 2.3% year on year, latest data released by the General Administration of Customs shows.

Working with Chiyoda, a supply chain solution partner, Mitsubishi wants to identify cases how to transport hydrogen in chemical tankers at normal atmospheric temperature and pressure. The aim is to develop a business case for importing and utilizing hydrogen in Singapore as a transport fuel and for power generation.

Alternative to fossil fuels

The Singapore government was instrumental in bringing together industry and researchers, such as the National Research Foundation (NRF) to explore how hydrogen can be used as an alternative to existing carbon sources, notably coal and natural gas.

Researchers are looking how existing catalysis and membrane technologies can be enhanced and applied to produce green hydrogen at a competitive cost.

Sembcorb Industries will leverage its technology integration know-how to support the development of a hydrogen economy in Singapore. President & CEO Neil Mc Gregor said Sembcorp was committed to sustainability and sees hydrogen and renewable energy as key game-changers of Singapore’s future energy mix.

City Gas, producer and retailer of piped town gas for more than 860,000 homes and businesses in Singapore, is also supporting the hydrogen initiative. CEO Kenny Tan said the retailer seeks to “study and develop the viability of using green hydrogen in the town gas manufacturing process.”

Ong Kim Pong, regional CEO Southeast Asia at PSA International called hydrogen a “vital pillar” of the company’s business and a key tool to reduce its carbon footprint. “Powering our horizontal transport with hydrogen is just the beginning, and we will see its application expanding in the future, playing a part in our Smart Grid systems with EMA, and augmenting business adjacencies in our future Tuas Ecosystem,” he said. The two other partners involved are Jurong Port and Singapore LNG Corp.

Shipping data shows, the ‘SK Resolute’ carrier left the Sempra-operated Cameron LNG plant in Louisiana on March 22 and is expected to arrive in Tianjin on April 29.

The 180,000 cubic metres capacity carrier was originally headed for Cristobal, the port on the Panama Canal though changed its destination to Tianjin in China on March 28. If the ‘SK Resolute’ discharges its cargo in China at the end of April it would be the first to be unloaded since March 2019 when China raised tariffs on LNG imports from the US to 25 percent as part of the trade war.

Record storage injections

In the U.S., meanwhile, gas storage is expected to ramp up to a record 4.078 trillion cubic feet (tcf) at the end of the summer (April-October) injection season, analysts said in a Reuters poll, as the pandemic is slashing domestic demand from industries and power generators before producers can shut in rigs to reduce output.

The slump in demand occurs at a time when gas use for heating is pattering out as the spring and summer season approaches. Mild winter weather had already lead to smaller gas withdrawals from storage for heating and power generation. From mid-March, government restrictions on travel and manufacturing to contain the coronavirus brought fuel demand into freefall. Low domestic gas use, combined with reduced demand from Europe, will lead to a further decline in U.S. gas prices.

Most of the excess gas production will end up in storage. Net injections during the refill season (April 1–October 31) will bring the total working gas in storage to 4,029 Bcf, the U.S. Energy Information Administration’s (EIA) forecast. If realized, would be the largest monthly inventory level on record.

However, storage capacity is limited after investments dried up in recent years to expand it. The gas price differential, or spread, between the winter and summer has been structurally shrinking in recent, decreasing from more than $0.50 per million British thermal units (MMBtu) within the last ten years to less than $0.20/MMBtu for much of 2018.

“This narrower difference has reduced the economic incentive to invest capital expenditures in increasing gas storage infrastructure,” analysts at the U.S. Energy Information Administration (EIA) commented. These days, new-build gas storage is missing as an outlet to balance the oversupplied market.

Shut-ins become ‘more real’

US LNG exporters – who last year turned largely to Europe to in search of buyers – would likely be compelled to rein in their output this year, even as new projects continue to come online. Prior to the coronavirus outbreak, Wood Mackenzie was expecting US LNG producers to curb their output by 0.5bcf/day – or roughly 14 Mcm/day. By comparison, the US averaged gross LNG exports of almost 5bcf/day last year and the EIA expected an average of 6.4 Bcf/day this year.

“Half a Bcf per day of shut-ins, which is what we are modelling, probably won’t really move the needle for the LNG market – it will have to be relatively substantial,” said WoodMac’s Asian gas and LNG research director Robert Sims.

Asian buyers are trying to resell their contracted US LNG volumes and portfolio sellers offload their excess cargoes into Belgium, the United Kingdom, and France. Imports into the UK and France are scheduled to be around 2 MMt each by the end of the month, while over 1 MMt could have discharged in Belgium.

Total LNG deliveries to Europe are expected to reach nearly 11 million metric tons (MMt) - a 14% hike from the previous record set in December. The record influx comes at a time when the coronavirus pandemic has made EU-wide gas demand collapse at double-digit rates.

“This unprecedented surge of LNG supply to Europe is certain to cause knock-on effects. Storage inventories will build up earlier than normal and that will put additional downward pressure on prices in the third quarter and winter delivery months. It is a chain reaction,” said Shankari Srinivasan, vice president, gas and power, IHS Markit.

Downward pressure on Q3 gas prices

Short-term demand is expected to decrease substantially in the coming weeks as several European government are likely to extend lockdowns to slow down the spread of the coronavirus until after Easter, and potentially into early May.

As Europe absorbs increasing LNG arrivals, storage has begun net injections and pipeline supply is already reducing compared to this point last year. Early storage fill will further pressure Q3 and winter delivery prices.

EU and UK underground storage facilities were 55% full as of 25 March, 21 points above the five-year historical average, according to IHS Markit data.  LNG inventories in Northwest Europe stood slightly above 50%, with no signs of send-out abating as volumes surge into Northwest Europe.

“Some volumes are increasingly being redistributed between Northwest European and Spanish terminals as capacity holders juggle deliveries between terminals,” Srinivasan commented. Pipeline supplies are also coming under pressure, with Russian pipeline flows already down 16% year-on-year in February, and likely to ease off further.

GE, together with the EPC contractor Polimex Mostostal, is building the two gas-fired units on a turnkey basis. Equipped with two 9HA.01 gas turbines and two STF-D650 steam turbines, the two CCGTs will provide up to 1.4 gigawatt (GW) of flexible power at Dolna Odra – enough to meet the electricity demand of about 1 million Polish households.

With the commissioning of the new units in 2023, PGE hopes to reduce CO2 emissions at Dolna Odra by about 2-3 million tonnes per year. The coal-fired plant currently consists of eight units, two with 220 MW and six with 232 MW. Units 5-8 have already been retrofitted with a Lurgi-built flue gas desulfurization plant.

Capacity contract

The Dolna Orda power plant, situated near the town of Gryfino, plays a critical role for the Polish National Grid as it is the only system-relevant producer for the country’s industrialized north-western region. The plant expansion with two flexible CCGTs has been awarded a 17-year contract in the main power market auction, with electricity supply due to start in 2024.

“PGE's investment in Dolna Odra Power Plant based on gas fuel is our contribution to preparing the Polish power system for further development of renewable energy, in particular wind energy," said Wojciech Dąbrowski, President of PGE’s management board.

By retrofitting the coal power plant, first commissioned in 1974, with two modern gas power units, the operator aims to enhance the plant’s operational flexibility and reduce overall emissions. The cleaner-burning units also help prolong the life-time of the system critical power unit in West Pomerania.

“Our existing funding is sufficient to meet all of LNGL’s commitments until late April 2020, but we need to secure additional funding urgently to continue operating beyond then,” the developer had to admit. Temporary financing is – much needed to avert a financial crunch – not now forthcoming either from a U.S. equity and capital fund.

The delay of the takeover bid has been caused by the “unavailability of relevant personnel” due to Covid-19 contingency measures. The bidder’s statement from the Singaporean entity, known only as LNG9 Pte Ltd, has not yet sent to LNG Ltd shareholders, though the Australian developer indicated it would accept the offer once received.

Bridge financing now needs to be forthcoming quickly allow the Magnolia liquefaction plant proceed operations. However, an U.S. fund declined to provide any debt financing, leaving LNG Ltd high and dry.

Vietnam awaits first US LNG cargo in early June

The first LNG cargo from the Magnolia LNG project in Louisiana, U.S., had initially been scheduled to arrive in May, or early June, but this timeline is now looking increasingly unrealistic. Despite its financial squeeze, LNG Ltd. needs to honour its gas supply agreement with the Bac Lieu import terminal from 2023.

The contract stipulates the shipment of 2 million tons per annum from Magnolia LNG to Vietnam, on a free-on-board (FOB) basis, for used in $4 billion power project on the Mekong Delta. Singapore-based Delta Offshore Energy in late January was handed an investment permit to develop a 3,200 MW combined-cycle power plant with adjacent regas terminal.

CCGT scheduled to start-up in 2023

Delta is the lead-developer for the 3.2 GW power station at Bac Lieu, designed to consist of four 750 MW gas turbine units and a fifth unit with 200 MW. The integrated LNG import and power gen project is scheduled to start operations in 2023.

Detailed engineering work and a full feasibility study have been completed, with the LNG import solution being developed in cooperation with Norway’s 7 Seas.

Vietnam seeks to shifts its power sector towards gas generation and has made plans to import 5 mtpa of LNG by 2020, which will be gradually increased to 10 million tons per annum (mtpa) by 2030 and 15 mpta by 2035.

To accommodate these LNG import volumes, the Vietnamese government is supporting plans to develop a second LNG import terminal near a projected power plant in Ninh Thuan province. That project is backed by Novatek which will seek to supply it with fuel from its Yamal LNG export plant in northern Siberia, or the Arctic LNG II project in the long run.

Daily tariff indicators suggest transport and logistics constraints are being lifted quickly. With a resumption in economic activity, Wood Mackenzie estimates a full-year gas demand reduction of between 6 billion cubic metres (bcm) and 14 bcm in 2020, translating to a 4% to 6% growth in gas demand this year.

China’s LNG demand is expected to reach 65 million tons this year, representing a 6.6% growth year-on-year. In fact, the first U.S. LNG cargo in more than a year is on route from

Europe braces for economic impact

With China hoping to have passed the pandemic, Europe is still fighting to contain the outbreak and braces for the economic impact of wide-spread lockdowns which severely impact on energy demand. At the same time, the energy demand destruction worldwide has caused record-low oil and gas prices which greatly supports gas-fired generation.

Worst-case scenarios could see more lockdowns deployed in more countries, including Sweden and the Netherlands which so far took a different route, risking severe disruptions to global supply chains by restricting movements of people and goods.

Low oil prices support coal-to-gas switching

Record low global oil prices, caused by Saudi Arabia flooding the market after a spat with Russia, are feeding through to oil-indexed LNG contracts in Japan and South Korea. Analyst suggest this could disrupt coal generation in favour of gas in both markets, as soon as August this year, similar to how sustained low TTF prices in 2019 removed coal from power grids across North West Europe.

“We expect Japan’s LNG demand to grow 5.1% to 81 Mt in 2020, compared to last year. At the same time, South Korea’s LNG demand is expected to rise 7.7% to 42 Mt, as more LNG displaces coal in the power sector of both countries,” said Wood Mackenzie research director Robert Sims.

Elsewhere, attention moves to potential loss of associated US gas supply, which could hurt U.S. LNG producers further, although the impact will likely be felt through 2021 due to the delayed nature of drilling reductions. “At a lower $35 per barrel oil price, we could expect about 2 billion cubic feet per day (bcf/d) of US gas production to be impacted by middle of next year,” Sims said.

U.S. production shut-ins on the cards

The fundamentals behind the global LNG oversupply remain: strong production growth, weak Northeast Asian demand with prices as low as $2.75/mmbtu and an increasingly saturated European gas market whereby TTF prices have sunk to $2.98/mmbtu.

Prospects of any quick recovery of Japan Korea Marker (JKM) or TTF prices have been dealt a blow due to the impending global economic downturn. So, supply cuts are the only option left to balance the market, notably a turn-down of US Gulf coast production. “We forecast 0.5 bcf/d of production will be lost through Q2-Q3,” Sims said but cautioned “there is risk that this number may prove too conservative if demand drops further.”

A day after the government imposed lockdown, energy demand was down 13% across the day (Wednesday 25 March). According to Cornwall Insight figures, this was much lower than the average Wednesday in March 2019, which is shown in the below graph.

Over the coming weeks, electricity demand and gas is bound to fall further as most of the British economy grinds to a halt. “The government announced lockdown resulted in further reductions. This is most notable in the morning peak and middle of the day when we would typically expect the industrial and commercial load to be ramping up” Cornwall Insight commented.

Challenges of low load

Low load makes it more difficult for National Grid to ensure system stability. “Low demand means there is less space to operate larger synchronous generators. This can affect system inertia and Rate of Change of Frequency – how quickly the system responds to a change of conditions.

“To cope with this, the Electricity System Operator (ESO) could constrain wind and keep thermal plant such as gas or coal running,” suggested Tom Edwards, Cornwall Insight’s senior modeller.

So far, no large industrial consumers had announced closures. Many market observers say, however, the coronavirus will have a long-lasting effect on the way we work, travel and live. Providers of electricity and natural gas will eventually have to adapt to these changes.

As ammonia does not emit carbon dioxide at the time of combustion, the co-firing of this fuel can greatly reduce emissions at thermal power plants.

The Marubeni-led technical study - running through to the end for February 2021 - prepares a trial for direct usage of ammonia as a fuel in JERA’s thermal power plant. Researchers are also scrutinizing the economics of equipment cost, operational expenses as well as the cost for producing and transporting ammonia to the power stations.

The trial runs of ammonia co-firing are in line with Japanese government’s efforts to implement hydrogen-based energy projects. Dubbed NEDO, the research project seeks to develop multi-burner ammonia co-firing technology for pulverized coal boilers, which can later be amended for use in gas-fired power units.

JERA is looking to find out the necessary capital investment to retrofit its existing plants with the novel ammonia co-firing technology, once it is ready for commercialization. To this end, it is allowing researchers to carry out tests and trial runs at some of its thermal power plants.

Australia-based Woodside Energy is also participating in the study, striving to identify challenges related to realizing large-scale ammonia production lines.

Under the previous government, Pakistan LNG Ltd had signed a deal with Qatargas to offtake LNG long-term on oil-indexed price. Today, these import volumes are now uneconomical compared with cheaper spot cargoes. LNG-based power plants in Punjab are standing idle as operators have ramped up cheaper coal-fired power plants instead.

Qatar now seems to accommodate and has reportedly offered to reduce shipments to three cargoes per month, down from the contracted five cargoes. At the same time, K-Electric has offered Pakistan LNG to buy the regasified Qatari gas for its Bin Qasium power project.

Test runs for Bin Qasim Unit-1 start in early 2021

Bin Qasim Power Station-3 (BSPS-III), a 900MW combined-cycle power plant, is under development in Karachi adjacent to two ageing coal-fired units. Built at a cost of $650 million, the CCGT is designed for a 30-year lifetime and will be dual-fired with regasified liquid natural gas (RLNG) as the primary fuel.

The first 450 MW unit of the plant is scheduled to start operation in April 2021, followed by a second equally-sized unit in September that year. Testing and commissioning of the two Siemens SGT5-4000F gas turbines and the balance of the plant will start in January 2021, by when the operator needs some 150 mmcf/d to fuel the plant.

K-Electric proposed to build a pipeline for regasified LNG from Pakistan LNG’s import terminal to the Bin Qasim Power Complex. Both parties agreed that RLNG will be provided from January 2021 through to December 2025, at prices determined by the Pakistani Oil and Gas Regulatory Authority.

Factoring in the cost of storage and gas pipeline infrastructure, the the delivered cost of renewable hydrogen could fall to around $2/kg in 2030 and $1/kg in China, India and Western Europe by 2050. In this event, green hydrogen would effectively outcompete both coal and natural gas as a fuel for power generation.

Clean fuel for energy-intensive industries

Today, some 70 million tonnes of hydrogen are already used for oil refining and in the petrochemical industry worldwide. Falling costs for hydrogen would spiral up the use of that clean fuel and help decarbonizes some of the most energy-intensive industries.

However, a decisive build-out in electrolysers to get hydrogen produced in sufficient quantities will require a determined push by policymakers, BNEF underlined. “The clean hydrogen industry is currently tiny and costs are high. There is big potential for costs to fall, but the use of hydrogen needs to be scaled up and a network of supply infrastructure created,” said Kobad Bhavnagri, head of industrial decarbonisation for BNEF.

“This needs policy coordination across government, frameworks for private investment, and the roll-out of around $150 billion of subsidies over the next decade,” he forecast.

EU-wide push to deliver hydrogen at scale

Across Europe, hydrogen gains momentum with up to 10 MW of larger-scale project announced, amid supportive policies in France and soon also in Germany.

The European Commission is preparing to launch an EU-wide “clean hydrogen alliance” in the summer, bringing together national governments and companies involved in the hydrogen value chain. The initiative will be modelled on the European Battery Alliance, which brought together more than 200 companies, policy makers and research organisations around battery manufacturing.

Demand has spiked for storage systems with an emergency power function as well as for off-grid storage, Tesvolt said, indicating it will amend its lithium-ion based battery production accordingly.

"Tesvolt will be gradually adding capacity to account for the current increase in demand, seeing as its order volume has almost tripled since the same quarter last year," the company stated.

Test-bed for storage technologies

Germany's rapidly rising share of weather-dependent renewable energy makes the country a test-bed for storage technologies, to enable its use when there is only little or no sun or wind power available.

Though truly large-scale storage might not be needed for another decade, the technology has started to spread small-scale in the form of batteries in cars, homes and companies. Falling technology costs encourage a larger-scale deployment.

The energy storage sector in Germany recorded sales growth of 10 percent to 5.5 billion Euros in 2019 and expects continued growth. Industrial applications saw a particularly strong increase to 1.3 billion Euros, and are likely to become the industry’s prime market segment.

The new T-Point 2 replaces the iconic T-Point in order to enable more robust turbine validiations, notably the 1650℃-class JAC model and 1700℃-class ultrahigh-temperature models. MHPS claims the T-Point 2, like its predecessor, “stands apart as the only facility in the world that performs full-scale long-term reliability verification for gas turbines.”

Synced to the Japanese power grid, it is the only plant of its type in the world to function as both a technology demonstrator and an electric power producer and supplier. Also housed within Takasago Works are centers for R&D, design, manufacturing, and short-term component testing.

Commercial start in July 2020

Once commercial operations begin in July 2020, T-Point 2 is expected to achieve power output of over 566 MW at 60Hz, with nearly 64% efficiency, 99.5% reliability and a world-first turbine inlet temperature of 1650℃ – raising industry standards for gas turbine combined cycle performance globally. This improved performance is possible due to the upgraded J-Series Air-Cooled (JAC) model, the first gas turbine being validated at T-Point 2.

The new facility features a triple-casing steam turbine, augmenting overall system efficiency through a multiplier effect with the JAC gas turbine. This greater efficiency reduces carbon emissions and heat loss.

“The prototype validation system established by MHPS has given our customers the clear assurance that they are receiving the highest caliber and most reliable energy solutions in the market,” said Junichiro Masada, Senior General Manager of Gas Turbine Technology & Products Integration Division, MHPS.

Going forward, MHPS will use the facility to conduct validation of the next-generation 1700℃-class ultrahigh-temperature gas turbines, steam turbine upgrades, air-cooled condenser technology, generators, and static frequency converters.

Installing AI at T-Point 2

Work is underway to install and train advanced artificial intelligence (AI) technology at T-Point 2, such as the MHPS-TOMONI suite of digital solutions. During the 8,000 hour durability demonstration period, MHPS will also be training its AI apps, allowing T-Point 2 to eventually become the world’s first autonomous combined cycle power plant.

The aim is to fully integrate AI into plant operations, allowing plant owners to leverage data to optimize performance, enable condition-based predictive maintenance for equipment, selectively automate operation and maintenance (O&M) decision-making, and reduce risk.

With these building blocks, MHPS will remotely monitor and manage total plant performance; remotely operate the plant in coordination with grid and fleet-wide energy management objectives; and utilize sensor and control system data to make smarter operation decisions in real time.

Striving to sell surplus gas production abroad, net natural gas exports from the United States exceeded 12 Bcf/d for the first time on March 30, according to the U.S. Energy Information Administration (EIA).

The rise in net gas exports from the Lower 48 states is facilitated by several new liquefaction trains in the Gulf of Mexico and lower exports from western Canada to the United States. Higher year-over-year natural gas production in the United States also reduced the need for natural gas from Canada, and a mild winter decreased the need for LNG imports into the United States.

As a result, net natural gas exports are up from about 9 Bcf/d in early January 2020 to about 12 Bcf/d as of March 30, 2020, EIA analysts noted.

LNG was the fastest growing source of gas demand in the U.S. last year, followed by gas demand for power generation. Feedstock needs for liquefaction and export plants increased by more than 2 Bcf/d, or 68%, the EIA EIA’s Natural Gas Storage Dashboard shows.

Rising gas use for power gen

Natural gas use for power generation is a key part of the natural gas supply and demand balance, even in winter, analysts underlined. Gas-burn in the power sector averaged about 28.4 billion cubic per day (Bcf/d) from the start of November 2019, until the end of January 2020. That is an increase of 3 Bcf/d, or 12%, compared with the pre-year period.

Power burn, estimated based on S&P Global Platts data, reached 34 Bcf/d on January 20, 2020—the second-highest natural gas use for power during a day in the winter.

Gas gained the upper hand over coal this winter, as spot gas prices at Henry Hubs fell to lows not seen since 2016. Mild winter weather lowered gas demand for heating and reduced pipeline congestions, freeing up plenty of cheap fuel for operators of gas-fired power plants.

New high-efficiency combined-cycle power capacity also adds to the attractiveness of generating electricity from natural gas. U.S. utilities added 8,843 MWgas-fired capacity last year and another 18,648 MW in 2018, according to EIA figures. At the same time, nearly 12,400 MW of coal-fired capacity was retired, mainly ageing and less energy-efficient plants.

“As the Covid-19 pandemic continues and oil and stocks continue to suffer shocks, investment in renewable energy projects is now the way forward,” IEFFA analyst Clark Butler said, noting that tech giants and financial institutions increasingly set their own decarbonisation targets.

“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.” Large U.S. tech players strive to migrate large data centers to wind and solar-powered energy.

Bloomberg New Energy Finance data shows a record take-up of 13.6 gigawatts (GW) capacity, contracted by U.S. companies under either PPAs or green tariffs.

Oil and gas stocks are in the doldrums, hit by a sharp fall in energy demand in the face of the Covid-19 crisis and no supply reductions from OPEC+ or U.S. fracking companies. 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 suggested. 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.

Striving to go green

Investment in renewables and energy storage is the new trend among U.S. corporate. 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. The U.S. tech sector, along with some banks is setting an example for promoting the use of renewable PPAs and energy storage. “Governments should do more, but the least they can do is get out of the way of the private sector,” Butler concluded.

“Cash distributions from Australia Pacific LNG are subject to debt serviceability tests under the project finance arrangements, which are satisfied at current forward oil prices,” Origin said in its investors update today.

With no further material decline in forward oil prices, Origin continues to expect total cash distributions in FY2020 from Australia Pacific LNG of A$1.1 billion to A$1.3 billion although the company’s overall Capex will be lowered by up to 10%

The Sydney-based company now focused even more on cost efficiencies, which had already driven Australia Pacific LNG’s FY2020 forecast distribution break-even down to between US$29 and US$32 per barrel (incl. about US$8 per barrel of project finance principal repayment).

Resilient due to low upstream cost

Acknowledging adverse effects of COVID-19 and the slump in oil prices, the Origin CEO pointed out that “action taken in the last three years to simplify the business, significantly reduce upstream costs at Australia Pacific LNG and materially reduce debt, has put us in a financially resilient position.” Hence, Origin’s Energy Markets’ FY2020 Underlying EBITDA guidance of AS$1.4 to AS$1.5 billion is maintained.

Uncertainty abounds how long the pandemic ill last and how deeply it will affect the economy and energy demand. “The impacts have not been material to date and can be absorbed within our existing FY2020 guidance range,” Calabria said but conceded it was hard at this point in time to accurately assess the impacts on provisioning for bad and doubtful debts.

Eager to reassure customers, the Origin CEO added it will not disconnect any residential or small business customers in financial stress. This will apply until at least 31 July 2020.

By early 2021, the rating agency expects the global economy will recover and oil prices return to $50-$55 per barrel (bbl), recovering from current lows in the $40-$45/bbl price range. However, should this outlook on the resilience of the global economy prove too optimistic, oil and gas prices remain in the doldrums.

A supply correction would be urgently needed to lift energy prices, but OPEC plus Russia have so far not agreed to reduce production. “The sharp reduction in demand for oil products worldwide and the supply shock resulting from disagreement among oil-producing countries in the face of the coronavirus crisis has led to depressed and extremely volatile oil prices,” said Steven Wood, Managing Director of Moody’s Corporate Finance Group.

“We expect prices to remain low through 2020, before the market rebalances as supplies finally decline,” he said. However, Moody’s also considers downside scenarios, in which oil and gas prices remain weak into 2021 on the back of longer-than-anticipated economic weakness due to the global health crisis.

‘Negative’ outlook for oil & gas sector

As the pandemic progresses, Moody’s also changed the outlooks for the global integrated oil and gas sector and for the global E&P industry to negative from stable. The upstream industry’s EBITDA is expected to fall by more than 30% this year, no longer achieving a previously anticipated 5% growth. The fall is largely driven by lower earnings and cash flow from upstream operations amid substantially lower oil prices.

The outlook for the exploration and production (E&P) sector has also been lowered to negative, with EBITA seen fall by more than 20% this year amid plunging demand and low prices. After oil prices dropped more than 70% in Q1-2020, upstream companies slashed capital spending and dialed back production and growth estimates, with related run-on effects on midstream companies such as pipeline operators.

Strikingly, Moody’s changed its outlook for the global midstream energy sector to stable from positive. “Although attributes such as the regulated fee-based contracts associated with US interstate natural gas pipelines lend the sector stability, supply and demand shocks in the broader energy environment will see EBITDA grow only negligibly, if at all, this year,” analysts commented. The rating agency hence expects global midstream sector EBITDA to grow within the -5% to 5% range in 2020.

At the moment, about 5 million barrels of oil produced worldwide each day is not fetching high enough prices to cover the costs of getting it out of the ground, based on Brent crude at $25 a barrel. “These operations have been losing money on every barrel they produce,” IEA analysts noted. As of late, however, the Brent front-month June recovered to around $33.70 a barrel, loosening the squeeze on upstream companies.

Still, in the new environment, projects considered low cost yesterday (i.e. those that are viable at around $35 to $45 a barrel already look high cost today. “The scope of cost reductions is limited because much of the efficiency gains have already been harvested,” analysts noted. “As a result, the current declines in investment are translating more directly into cutting back activity.”

Cash-strapped wildcatters are losing out

Cutbacks and production shut-ins are especially stark among some smaller independent U.S. upstream companies, dubbed wildcatters that are often engaged in shale fracking. Many wildcatters are debt-financed and were already facing strong demands from investors to shore up business models and improve cash flow before the latest price crash.

For vulnerable producer economics, the looming global recession poses a great risk. The IEA’s initial estimates of 50%-85% drops in net income for selected producer countries in 2020, compared with 2019, “were dramatic already.” But analysts now warned “these declines could be even greater depending on the final extent of the demand drop and the economic slowdown.”

Economics of oil production are, however, not necessarily indicative as to which operations will be shut in. Some more robust and financially sound producers may continue pumping oil and associated gas even if they are losing money. This tends to occurs it the costs of shutting down production are higher than the operating losses.

Bankruptcies and takeovers more likely

Hard-nosed producers may opt to wait and see if weaker rivals go out of business, which would improve the environment for those who stay in the game. Some large players might even be hoping to acquire a cash-strapped wildcatter at a bargain price.

However, there is now an additional, even more pervasive threat facing many producers, irrespective of their operating costs or strategies. “As demand plummets, the entire supply chain of oil refining, freight, and storage is starting to seize up, making it increasingly difficult to push new supply into the system,” IEA analysts warned. Much the same holds true for the natural gas supply chain.

Changes in oil markets ripple across all parts of the energy sector, notably on the natural gas due to oil-indexation of many long-term gas supply contracts. Over the next 6-9 months, the current rock-bottom oil prices filter through into gas contract prices and at oil around $30/bbl, many gas suppliers would struggle to cover their operating costs.

The successful first turbine start-up confirms the engine and auxiliary systems – including the gas supply, lube oil system, control system and startup systems – are working together as designed, Siemens noted. During first fire, the SGT6-9000HL ramped up to a pre-determined test speed, and the combustion system ignited.

The SGT6-9000HL is at the heart of a new fast-ramp, simple-cycle gas power unit at Duke Energy’s Lincoln station. Siemens delivered the 340-ton turbine in November 2019, and supervised commissioning of the 402 MW unit.

Four year testing plan

After the first phase of testing is completed, the SGT6-9000HL will continue its four-year testing plan (2020-2024), gradually introducing technologies to achieve the next level of efficiency. The unit will operate in simple-cycle mode under real-world power plant conditions, allowing Siemens to continually assess and optimize the performance while gaining valuable commercial operating experience.

The architecture of HL-class engines consist of an air-cooled four-stage power turbine, hydraulic clearance optimization for high-efficiency at full load while facilitating immediate restart. The steel rotor design has Hirth serrations, a can-annular combustion system.

With a ramp-up rate of 85 MW per minute, the turbine maximizes operational flexibility to help integrate fluctuating supply of renewable energy sources. Inspection intervals of intervals of 33,000 equivalent base-hours and 1,250 equivalent starts, mean the unit is highly reliable and has low life-cycle costs.

Hand-over to Duke in 2024

When all testing is completed in 2024, Siemens will turn over the advanced unit to Duke Energy. The unit will be the most efficient of its type in Duke Energy’s fleet, generating enough energy to power more than 300,000 homes in the Carolinas.

Investing in natural gas technology will also help Duke Energy close coal plants faster and reach its aggressive goals for cutting carbon emissions by at least 50% by 2030.