Easwaran Kanason

Co - founder of NrgEdge
Last Updated: June 20, 2020
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Business Trends
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Just a few days ago, Chevron sent a tremor through the LNG industry when it announced that it was putting its stake in Australia’s giant North West Shelf project up for sale, having received ‘unsolicited approaches from a range of credible buyers’. The term to zoom in on is ‘unsolicited’. Meaning that Chevron wasn’t actively considering selling its stake in Australia’s oldest LNG project, but had been cajoled into starting a formal sales process by attractive offers. And that itself says a lot about the state of the LNG industry going forward.

A bit of history. The North West Shelf Project kicked off in the 1980s, then the largest engineering project in the world and remains the largest LNG project in Australia, even after the new wave of Western Australian LNG projects over the last decade. Formed as an equal joint venture between Chevron, Woodside Petroleum, BHP Billiton, BP, Shell and Japan Australia (owned by Mitsubishi Corporation and Mitsui & Co) – each holding a 1/6th stake – the North West Shelf brought together gas producing assets in the huge Carnarvon Basin, tying together fields like Perseus, North Rankin and Goodwyn into total reserves of 33 tcf. It put Australian LNG in the headlines, established the healthy LNG trade relationship between Japan and Australia, and transformed the economy of Western Australia;

Three decades later, the North West Shelf is still Australia’s most prodigious LNG-producing project. But one thing has changed. The natural gas drawn from its fields is drying up, or – to use a more appropriate term – evaporating. There’s still plenty of gas in the Carnarvon Basin, but not enough to power LNG production fully for the foreseeable future. Which is why NWS has started to shift its focus to tolling. In this context, it essentially means that the NWS will sells its liquefaction and associated infrastructure capacity to other gas producers in the region, who will process their natural gas into LNG through NWS before selling it on to their own customers. That would flip the NWS – in its current structure – from having full control over assets and production to being a landlord, renting out its infrastructure for someone else to use.

And there are plenty of ‘someone’s around. BHP and Woodside Petroleum’s Scarborough natural gas development is a perfect example, with Woodside also have its Browse project. These assets are nearby, and tying them to the NWS facilities is considerably more economic than having to build a new liquefaction plant from scratch. Even Chevron has its own assets in the area – the giant Gorgon and Wheatstone LNG project – but due to geography and proximity, has developed these as independent projects with individual facilities. The problem is that the potential third-party assets to be tied into NWS are owned by some of the NWS’ own stakeholders. This would upset the delicate balance between the NWS partners – who designed the structure to be equal and equitable.

With this significant misalignment between Chevron and its partners, it makes sense that Chevron would want to sell out of the project, particularly since the sale could fetch as much as US$4 billion, which is a nice chunk of change to help Chevron weather the current Covid-19 storm. It won’t just be Chevron considering this; BP and Shell will be thinking about this as well, although the Japanese partners are likely to remain to continue siphoning the LNG back home. While the potential suitors have not been named, the most likely candidate is Woodside, who could use its additional clout to convince the remaining NWS partners to agree on feeding Browse gas into NWS, a proposal that it has had difficulties with so far. Key Asian LNG buyers could be potential suitors as well, particularly Korean or Chinese companies that are keen to secure LNG assets for their own growing demand.

This problem won’t be unique to the North West Shelf. It is one that most giant LNG projects that were developed in the 1980s and 1990s must confront soon: with associated natural gas reserves running low, these projects must now look for alternative sources to continue LNG production. For some, circumstances may dictate that decommissioning makes more sense. But for others, like the North West Shelf, the presence of other nearby assets is a double-edged sword: it means that the project can keep running, but will have change its business model to adapt. That means ruffling a few feathers. Chevron might be one of the first to take this step, but it certainly will not be the last.

End of Article

Market Outlook:

  • Crude price trading range: Brent – US$38-42/b, WTI – US$36-39/b
  • Fears of a second wave of Covid-19 infections is crippling any optimism in the market, with infections in the US and Latin America still rising, and China reporting new clusters in Beijing and possibly Shanghai
  • This negated signs that OPEC+’s habitual cheaters had improved on their compliance to the supply deal, with Iraq implementing its quota in full for June and agreeing to compensate for falling short in May; other erring countries should follow suit
  • BP joined ExxonMobil and Chevron is writing down the value of its energy assets, which could the largest in its history at between US$13 – 17.5 billion
  • The WTI discount to Brent has narrowed to US$2/b, but could start to widen as US shale production is recovering quickly and possibly unsustainably; however, the US active rig count continues to languish below 300 sites, down 680 rigs y-o-y

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Leveraging Synergies Created by the Convergence of Operational and Engineering Technologies and Digitalisation, Can Deliver Significant Savings for Energy Companies

Pioneering technology expert tells ADIPEC Energy Dialogue up to 80 per cent of plant shutdowns could be mitigated through combination of advanced electrification, automation and digitalisation technologies

 

Greater use of renewables in power management processes offers oil and gas companies opportunities to create efficiencies, sustainability and affordability when modernising equipment, or planning new CAPEX projects


Abu Dhabi, UAE – XX August 2020 – Leveraging the synergies created by the convergence of electrification, automation and digitalisation, can create significant cost savings for oil and gas companies when making both operational and capital investment decisions, according to Dr Peter Terwiesch, President of Industrial Automation at ABB, a Swiss-Swedish multinational company, operating mainly in robotics, power, heavy electrical equipment, and automation technology areas.

Participating in the latest ADIPEC Energy Dialogue, Dr Terwiesch said up to 80 per cent of energy industry plant shutdowns, caused by human error, or rotating machinery or power outages, could be mitigated through a combination of electrification, automation and digitalisation.

“Savings are clearly possible not only on the operation side but also, using the same synergies between dimensions, you can bring down the cost schedule and risk of capital investment, especially in a time when making projects work economically is harder,” explained Dr Terwiesch.

A pioneering technology leader, who works closely with utility, industry, transportation and infrastructure customers, Dr Terwiesch said despite the increasing investment by oil and gas companies in renewables and the growing use of renewables to generate electricity, both for individual and industrial uses, hydrocarbons will continue to have an important role in creating energy, in the short to medium term.

“If you look at the energy density constraints, clearly electricity is gaining share but electricity is not the source of energy; it is a conduit of energy. The energy has to come from somewhere and that can be hydrocarbons, or nuclear, or renewables.” he said.

Nevertheless, he added, the greater use of renewables to generate electricity offers oil and gas companies the option of integrating a higher share of renewables into power management processes to create efficiencies, sustainability and affordability when modernising equipment, or planning new CAPEX projects.

The ADIPEC Energy Dialogue is a series of online thought leadership events created by dmg events, organisers of the annual Abu Dhabi International Exhibition and Conference. Featuring key stakeholders and decision-makers in the oil and gas industry, the dialogues focus on how the industry is evolving and transforming in response to the rapidly changing energy market.

With this year’s in person ADIPEC exhibition and conference postponed to November 2021, the ADIPEC Energy Dialogue, along with insightful webinars, podcasts and on line panels continue to connect the oil and gas industry, with the challenges and opportunities shaping energy markets in the run up to, and following, a planned three-day live stream virtual ADIPEC conference taking place from November 9-11.

An industry first of its kind, the online conference will bring together energy leaders, ministers and global oil and gas CEOs to assess the collective measures the industry needs to put in place to fast-track recovery, post COVID-19.

To watch the full ADIPEC Energy Dialogue series go to: https://www.youtube.com/watch?v=QZzUd32n3_s&t=6s

August, 12 2020
SHORT-TERM ENERGY OUTLOOK

Forecast Highlights

  • The August Short-Term Energy Outlook (STEO) remains subject to heightened levels of uncertainty because mitigation and reopening efforts related to the 2019 novel coronavirus disease (COVID-19) continue to evolve. Reduced economic activity related to the COVID-19 pandemic has caused changes in energy demand and supply patterns in 2020. Uncertainties persist across the U.S. Energy Information Administration’s (EIA) outlook for all energy sources, including liquid fuels, natural gas, electricity, coal, and renewables. The STEO is based on U.S. macroeconomic forecasts by IHS Markit, which assume U.S. gross domestic product declined by 5.2% in the first half of 2020 from the same period a year ago and will rise from the third quarter of 2020 through 2021.
  • Daily Brent crude oil spot prices averaged $43 per barrel (b) in July, up $3/b from the average in June and up $25/b from the multiyear low monthly average price in April. EIA expects monthly Brent spot prices will average $43/b during the second half of 2020 and rise to an average of $50/b in 2021.
  • U.S. regular gasoline retail prices averaged $2.18 per gallon (gal) in July, an increase of 10 cents/gal from the average in June but 56 cents/gal lower than at the same time last year. EIA expects that gasoline prices will gradually decrease through the rest of the summer to reach an average of $2.04/gal in September before falling to an average of $1.99/gal in the fourth quarter. Forecast U.S. regular gasoline retail prices will average $2.23/gal in 2021, compared with an average of $2.12/gal in 2020.
  • EIA expects high inventory levels and surplus crude oil production capacity will limit upward price pressures in the coming months, but as inventories decline into 2021, those upward price pressures will increase. EIA estimates global liquid fuels inventories rose at a rate of 6.4 million barrels per day (b/d) in the first half of 2020 and expects they will decline at a rate of 4.2 million b/d in the second half of 2020 and then decline by 0.8 million b/d in 2021.
  • EIA estimates that demand for global petroleum and liquid fuels averaged 93.4 million b/d in July. Demand was down 9.1 million b/d from July 2019, but it was up from an average of 85.0 million b/d during the second quarter of 2020, which was down 15.8 million b/d from year-ago levels. EIA forecasts that consumption of petroleum and liquid fuels globally will average 93.1 million b/d for all of 2020, down 8.1 million b/d from 2019, before increasing by 7.0 million b/d in 2021. Reduced economic activity related to the COVID-19 pandemic has caused changes in energy supply and demand patterns in 2020.
  • EIA estimates that global liquid fuels production averaged 91.8 million b/d in the second quarter of 2020, down 8.6 million b/d year over year. The decline reflects voluntary production cuts by the Organization of the Petroleum Exporting Countries (OPEC) and partner countries (OPEC+), and reductions in drilling activity and production curtailments in the United States because of low oil prices. In the forecast, the global supply of oil continues to decline to 90.4 million b/d in the third quarter of 2020 before rising to an annual average of 99.4 million b/d in 2021.
  • EIA estimates that U.S. liquid fuels consumption averaged 16.2 million b/d in the second quarter of 2020, down 4.1 million b/d (20%) from the same period in 2019. The decline reflects travel restrictions and reduced economic activity related to COVID-19 mitigation efforts. EIA expects U.S. oil consumption will generally rise through the end of 2021. EIA forecasts U.S. liquid fuels consumption will average 18.9 million b/d in the third quarter of 2020 (down 1.8 million b/d year over year) before rising to an average of 20.0 million b/d in 2021. Although the 2021 forecast level is 1.6 million b/d more than EIA’s forecast 2020 consumption, it is 0.4 million b/d less than the 2019 average.
  • EIA has lowered U.S. crude oil production estimates for 2020 by 370,000 b/d from the previous STEO. EIA expects crude production to average 11.3 million b/d in 2020 and 11.1 million b/d in 2021, down from 12.2 million b/d in 2019. Recently released EIA data show that average monthly U.S. oil production for May was 1.2 million b/d lower than the July STEO forecast, indicating more extensive production curtailments than previously estimated. Also, EIA’s August STEO assumes that the Dakota Access Pipeline will remain operational. A U.S. District Court ordered on July 6 the temporary closure of the Dakota Access Pipeline beginning in early August. A U.S. appeals court has overturned the lower court decision, allowing the pipeline to remain running while further litigation proceedings continue.
  • In July, the Henry Hub natural gas spot price averaged $1.77 per million British thermal units (MMBtu). EIA expects natural gas prices will generally rise through the end of 2021 but the sharpest increases will be during this fall and winter when they rise from an average of $2.11/MMBtu in September to $3.14/MMBtu in February. EIA expects that rising demand heading into winter, combined with reduced production, will cause upward price pressures. EIA forecasts that Henry Hub natural gas spot prices will average $2.03/MMBtu in 2020 and $3.14/MMBtu in 2021.
  • EIA estimates that total U.S. working natural gas in storage ended July at about 3.3 trillion cubic feet (Tcf), 15% more than the five-year (2015–19) average. In the forecast, inventories rise by 2.0 Tcf during the April-through-October injection season to reach nearly 4.0 Tcf on October 31.
  • EIA expects that total U.S. consumption of natural gas will average 82.4 billion cubic feet per day (Bcf/d) in 2020, down 3.0% from 2019. The largest decline in consumption occurs in the industrial sector, which EIA forecasts will average 22.0 Bcf/d in 2020, down 1.0 Bcf/d from 2019, as a result of reduced manufacturing activity. The decline in total U.S. consumption also reflects lower heating demand in early 2020, contributing to residential and commercial demand in 2020 averaging 12.8 Bcf/d (down 0.9 Bcf/d from 2019) and 8.8 Bcf/d (down 0.8 Bcf/d from 2019), respectively.
  • U.S. dry natural gas production set an annual record in 2019, averaging 92.2 Bcf/d. EIA forecasts dry natural gas production will average 88.7 Bcf/d in 2020, with monthly production falling from its monthly average peak of 96.2 Bcf/d in November 2019 to 82.7 Bcf/d by April 2021, before increasing slightly. Natural gas production declines the most in the Permian region, where EIA expects low crude oil prices will reduce associated natural gas output from oil-directed rigs. EIA’s forecast of dry natural gas production in the United States averages 84.0 Bcf/d in 2021. EIA expects production to begin rising in the second quarter of 2021 in response to higher natural gas and crude oil prices.
  • EIA estimates that U.S. liquefied natural gas (LNG) exports will average 5.5 Bcf/d in 2020 and will average 7.3 Bcf/d in 2021. EIA expects that U.S. LNG exports will decline through the end of the summer as a result of reduced global demand for natural gas. U.S. exports of LNG in July 2020 averaged 3.1 Bcf/d, which is about the same as in May 2018, when the available liquefaction capacity was about one-third of the current capacity. Declines in global natural gas demand associated with COVID-19 mitigation efforts, high natural gas storage inventories in Europe and Asia, and an on-going expansion in LNG liquefaction capacity have contributed to natural gas and LNG prices reaching all-time historical lows. Low international prices have affected the economic competitiveness of U.S. LNG exports and have led to numerous cargo cancellations, particularly at the Sabine Pass, Corpus Christi, and Freeport LNG export terminals. EIA expects LNG exports from the United States to remain low in the next few months. Based on numerous trade press reports, EIA estimates about 45 cargoes have been canceled for upcoming August shipments and about 30 cargoes have been canceled for September shipments.
  • EIA forecasts 3.6% less electricity consumption in the United States in 2020 compared with 2019. The largest decline on a percentage basis is in the commercial sector, where EIA expects retail sales of electricity to fall by 7.4% this year. Forecast industrial retail electricity sales fall by 5.8%. EIA forecasts residential sector retail sales will increase by 2.0% in 2020. Milder winter temperatures earlier in the year led to lower consumption for space heating, but that factor is offset by increased summer cooling demand and an assumed increase in electricity use by more people working from home. In 2021, EIA forecasts total U.S. electricity consumption will rise by 0.8%.
  • EIA expects the share of U.S. electric power sector generation from natural gas-fired power plants will increase from 37% in 2019 to 40% this year. In 2021, the forecast natural gas share declines to 35% in response to higher natural gas prices. Coal’s forecast share of electricity generation falls from 24% in 2019 to 18% in 2020 and then increases to 22% in 2021. Electricity generation from renewable energy sources rises from 17% in 2019 to 20% in 2020 and to 22% in 2021. The increase in the share from renewables is the result of expected additions to wind and solar generating capacity. EIA expects a decline in nuclear generation in both 2020 and 2021, reflecting recent and upcoming retirements of nuclear generating capacity.
  • EIA forecasts that renewable energy will be the fastest-growing source of electricity generation in 2020. EIA expects the electric power sector will add 23.2 gigawatts (GW) of new wind capacity and 12.9 GW of utility-scale solar capacity in 2020. However, these future capacity additions are subject to a high degree of uncertainty, and EIA continues to monitor reported planned capacity builds.
  • U.S. coal consumption, which dropped to its lowest point since April, totaled 95 MMst in the second quarter of 2020. EIA expects coal consumption to rise to a seasonal peak of 127 MMst in the third quarter but remain lower than 2019 levels through the end of 2020. EIA estimates that U.S. coal consumption will decrease by 26% in 2020 and increase by 20% in 2021. EIA estimates that total U.S. coal production in 2020 will decrease by 29% from 2019 levels to 502 MMst. In 2021, EIA expects higher demand and rising natural gas prices to a lead to a recovery in coal production of 12%, with a total annual production level of 564 MMst.
  • EIA forecasts that U.S. energy-related carbon dioxide (CO2) emissions, after decreasing by 2.8% in 2019, will decrease by 11.5% (588 million metric tons) in 2020. This record decline is the result of less energy consumption related to restrictions on business and travel activity and slowing economic growth related to COVID-19 mitigation efforts. CO2 emissions decline with reduced consumption of all fossil fuels, particularly coal (24.9%) and petroleum (11.6%). In 2021, EIA forecasts that energy-related CO2 emissions will increase by 5.6%, as the economy recovers and stay-at-home orders are lifted. Energy-related CO2 emissions are sensitive to changes in weather, economic growth, energy prices, and fuel mix.
August, 12 2020
Utility-scale battery storage capacity continued its upward trend in 2018

Utility-scale battery storage systems are increasingly being installed in the United States. In 2010, the United States had seven operational battery storage systems, which accounted for 59 megawatts (MW) of power capacity (the maximum amount of power output a battery can provide in any instant) and 21 megawatthours (MWh) of energy capacity (the total amount of energy that can be stored or discharged by a battery). By the end of 2018, the United States had 125 operational battery storage systems, providing a total of 869 MW of installed power capacity and 1,236 MWh of energy capacity.

Battery storage systems store electricity produced by generators or pulled directly from the electrical grid, and they redistribute the power later as needed. These systems have a wide variety of applications, including integrating renewables into the grid, peak shaving, frequency regulation, and providing backup power.

annual utility-scale battery storage capacity additions by region

Source: U.S. Energy Information Administration, Preliminary Monthly Electric Generator Inventory and Annual Electric Generator Report

Most utility-scale battery storage capacity is installed in regions covered by independent system operators (ISOs) or regional transmission organizations (RTOs). Historically, most battery systems are in the PJM Interconnection (PJM), which manages the power grid in 13 eastern and Midwestern states as well as the District of Columbia, and in the California Independent System Operator (CAISO). Together, PJM and CAISO accounted for 55% of the total battery storage power capacity built between 2010 and 2018. However, in 2018, more than 58% (130 MW) of new storage power capacity additions, representing 69% (337 MWh) of energy capacity additions, were installed in states outside of those areas.

In 2018, many regions outside of CAISO and PJM began adding greater amounts of battery storage capacity to their power grids, including Alaska and Hawaii, the Electric Reliability Council of Texas (ERCOT), and the Midcontinent Independent System Operator (MISO). Many of the additions were the result of procurement requirements, financial incentives, and long-term planning mechanisms that promote the use of energy storage in the respective states. Alaska and Hawaii, which have isolated power grids, are expanding battery storage capacity to increase grid reliability and reduce dependence on expensive fossil fuel imports.

total installed cost of utility-scale battery systems by year

Source: U.S. Energy Information Administration, Form EIA-860, Annual Electric Generator Report
Note: The cost range represents cost data elements from the 25th to 75th percentiles for each year of reported cost data.

Average costs per unit of energy capacity decreased 61% between 2015 and 2017, dropping from $2,153 per kilowatthour (kWh) to $834 per kWh. The large decrease in cost makes battery storage more economical, helping accelerate capacity growth. Affordable battery storage also plays an important role in the continued integration of storage with intermittent renewable electricity sources such as wind and solar.

Additional information on these topics is available in the U.S. Energy Information Administration’s (EIA) recently updated Battery Storage in the United States: An Update on Market Trends. This report explores trends in battery storage capacity additions and describes the current state of the market, including information on applications, cost, market and policy drivers, and future project developments.

August, 11 2020