We will take the liberty of adapting Henry Ford’s famous quote to say: “Whether you think you are a bull or whether you think you are bear, you are right!” Either side of the divide could marshal enough arguments to support its case this week, though clearly the bulls were louder as Brent attempted to brush up against the $60 mark for the first time since July 2015. The futures market is notoriously given to short-termism when establishing prices, and it was understandably hard to look beyond one’s nose as crude rallied beyond the year’s previous peak. So, we took it upon ourselves to bring the bearish factors in clear view, including the fact that the worst fears of supply disruption as result of the Kurdish independence referendum were not realized, and remain a tail risk at best in an otherwise comfortably oversupplied world. OPEC basked in reflected glory, but it would be premature to declare its strategy a clear win. Demand growth projections could yet leave the optimists in the lurch. Meanwhile, away from Brent’s backwardation is the continuing WTI contango, which is giving US producers an opportunity to hedge and lock in prices above $50 for output a year from now.
“Is Brent in a bubble waiting to burst?” we asked in last Friday’s Viewsletter. It didn’t burst (which to us meant giving up most of its premium above $52) and a few oil experts we hold in high regard argued with us this week that it wasn't a bubble, either.
Some of the oil trading and analyst heavyweights gathered in Singapore for the 33rd Asia Pacific Petroleum Conference over September 25-27 were sanguinely bullish. Speaker Ben Luckock, co-head of group market risk at Swiss trader Trafigura, grabbed imaginations and headlines by suggesting that 2018 could mark the end of “lower-for-longer” oil prices.
As front-month ICE Brent futures rallied to a high not seen in two years above $59/barrel Monday amid tensions over the Kurdish independence referendum and flirted with the $60 high-water mark in subsequent trading sessions, being a bull was de rigueur. Cautioning the industry to not forget the bearish factors still looming in the background risked making you a party pooper.
The prospect of a new wave of demand destruction advancing towards the oil industry in the shape of electric vehicles and the sharing economy got the cursory nod in conference presentations and networking chatter at the seemingly endless cocktail receptions, but wasn’t spoiling the mood for most.
Giddy talk of this year’s “surprisingly strong demand growth” and how it would rid the world of oversupply, helped by the OPEC/non-OPEC cuts (which were hastily declared an unmitigated success) and speculation over the declining fortunes of the US shale industry dominated groupthink.
Coincidentally, as the parties petered out, Brent had corrected down to the $57/barrel level. WTI, which had rallied only to sevenmonth highs, was holding just over $51 Friday. If there is a bull run, be ready to run fast and change course swiftly. The underlying fundamentals of oversupply, we believe, remain firmly in place.
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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
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.
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.
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.