In good times, the instinct of any company is to expand. In bad times, that instinct reverses to consolidation. This cycle is no more apparent anywhere else than in the oil and gas sector, where periodic boom-bust periods have been a regular feature since David Beaty drilled the first modern oilfield back in 1875 in Pennsylvania. The year 2020 is proving to be a year of reckoning for the entire industry, for obvious reasons, with all firms of all sizes announcing or preparing to announce major impairments. What follows is usually a swathe of divestments.
Two major sales by supermajors have captured the headlines recently: BP’s exit from the petrochemicals sector through a sale to INEOS, and Shell reaffirming its desire to sell its 35% stake in the Abadi LNG project in Indonesia. Both deals paint a picture of companies retreating from peripheral, though still profitable activities, in order to focus on core activities.
In BP’s case, it will be selling its last remaining petrochemical sites to INEOS, owned by UK billionaire Jim Ratcliffe. The sale encompasses 15 sites in the Americas, Europe and Asia focused on aromatics, acetyls and related businesses for US$5 billion, to be paid in US$1 billion instalments after an initial US$400 million deposit. Charmingly, it brings the INEOS story full circle: INEOS was first formed in 1998 to buy out a BP petrochemicals business in Belgium, and in 2005, paid US$9 billion to purchase Innovene, another BP subsidiary that made up a large proportion of BP’s then-existing chemicals assets.
For INEOS, it’s a great win as it adds aromatics and acetyl capacity where it is lacking, and significantly boosts presence in Asia, described as ‘two big pieces of chemistry in (that) portfolio that (INEOS) didn’t have before, completing the set’. From BP’s perspective, however, the sale runs counter to the prevailing trend in the energy sector where firms are actively expanding their petrochemicals presence, from China to the US Gulf Coast, seeing it as a stable and lower-carbon alternative to complement zero-carbon operational transformations. But BP’s footprint in the petrochemicals business has been shrinking over the past two decades, ceding ground to Shell, ExxonMobil, Total and other national players. It might prove to be a canny move, there has been a massive surge in capacity for petrochemicals recently, with huge oversupply in certain grades that has placed major pressure on petchems profit margins. Global campaigns to reduce single-use plastics also blunted growth prospects. A global pandemic further tarnished the lustre of the sector. For BP, it would have been easy to say yes to pocketing a pretty penny from Jim Ratcliffe, which would allow it to, in the words of CEO Bernard Looney – ‘build a more focused, more integrated BP, (with) other opportunities that are more aligned with our future direction’.
Unlike BP, Shell has announced no intention to reduce its presence in petrochemicals. But it is looking to divest its stake in the Abadi LNG project in Indonesia led by Japan’s Inpex. Why it wants to do that might throw up some questioning looks. Shell through its takeover of natural gas giant BG Group is the world’s largest LNG trader by far. Surely, then, retaining a 35% stake in a large natural gas project would be a good thing. Right?
Perhaps not. Reports that Shell has been wanting to sell its 35% stake in the Abadi LNG project surfaced in 2019. The Abadi LNG project centred on the Masela gas block deep in the Arafura Sea has had a particularly chequered past. Debates between Japan’s Inpex and the Indonesian government over the direction and location of the project has plagued it with delays. Inpex and Shell had favoured floating LNG plant but Joko Widodo’s government was pushing for an onshore plant, tempted by better local employment prospects. The government won out in the end, finally confirming in 2019 an offshore production facility and a 9.5 mtpa onshore plant that would be operational in 2028, extending the Masela PSC by 20 years. Negotiations, it was reported, were particularly strenuous. And perhaps Shell lost patience.
Shell could sell its stake, valued at up to U$2 billion to Inpex, which owns the remaining 65%, or to other players. But few players have the appetite to navigate Indonesia’s complicated upstream sector. For Shell, the exit may be a relief. Particularly since it already has other, equally gigantic LNG assets nearby in Australia. Those LNG assets are expected to take a US$8-9 billion hit as part of a potential US$15-22 billion impairment charge for Q2 2020 on low gas prices. Shell’s view on long-term gas prices is alreadt on the bleaker side. So why not divest now for ready cash, instead of waiting 8 more years for an asset that might be worth even less then?
BP and Shell have offered up an intriguing preview of where the industry could go in these trying times, exits and consolidations, and we expect that there will be a lot more similar divestment announcements to roll out over the remainder of 2020 and in 2021.
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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.