When it was first announced in 2012, there was scepticism about whether or not Petronas’ RAPID refinery in Johor was destined for reality or cancellation. It came at a time when the refining industry saw multiple ambitious, sometimes unpractical, projects announced. At that point, Petronas – though one of the most respected state oil firms – was still seen as more of an upstream player internationally. Its downstream forays were largely confined to its home base Malaysia and specialty chemicals, as well as a surprising venture into South African through Engen. Its refineries, too, were relatively small. So the announcement that Petronas was planning essentially, its own Jamnagar, promoted some pessimism. Could it succeed?
It has. The RAPID refinery – part of a larger plan to turn the Pengerang district in southern Johor into an oil refining and storage hub capitalising on linkages with Singapore – received its first cargo of crude oil for testing in September 2018. Mechanical completion was achieved on November 29 and all critical units have begun commissioning ahead of the expected firing up of RAPID’s 300 kb/d CDU later this month. A second cargo of 2 million barrels of Saudi crude arrived at RAPID last week. It seems like it’s all systems go for RAPID. But it wasn’t always so clear cut. Financing difficulties – and the 2015 crude oil price crash – put the US$27 billion project on shaky ground for a while, and it was only when Saudi Aramco swooped in to purchase a US$7 billion stake in the project that it started coalescing. Petronas had been courting Aramco since the start of the project, mainly as a crude provider, but having the Saudi giant on board was the final step towards FID. It guaranteed a stable supply of crude for Petronas; and for Aramco, RAPID gave it a foothold in a major global refining hub area as part of its strategy to expand downstream.
But RAPID will be entering into a market quite different than when it was first announced. In 2012, demand for fuel products was concentrated on light distillates; in 2019, that focus has changed. Impending new International Maritime Organisation (IMO) regulations are requiring shippers to switch from burning cheap (and dirty) fuel oil to using cleaner middle distillate gasoils. This plays well into complex refineries like RAPID, specialising in cracking heavy and medium Arabian crude into valuable products. But the issue is that Asia and the rest of the world is currently swamped with gasoline. A whole host of new Asian refineries – the latest being the 200 kb/d Nghi Son in Vietnam – have contributed to growing volumes of gasoline with no home in Asia. Gasoline refining margins in Singapore have taken a hit, falling into negative territory for the first time in seven years. Adding RAPID to the equation places more pressure on gasoline margins, even though margins for middle distillates are still very healthy. And with three other large Asian refinery projects scheduled to come online in 2019 – one in Brunei and two in China – that glut will only grow.
The safety valve for RAPID (and indeed the other refineries due this year) is that they have been planned with deep petrochemicals integration, using naphtha produced from the refinery portion. RAPID itself is planned to have capacity of 3 million tpa of ethylene, propylene and other olefins – still a lucrative market that justifies the mega-investment. But it will be at least two years before RAPID’s petrochemicals portion will be ready to start up, and when it does, it’ll face the same set of challenging circumstances as refineries like Hengli’s 400 kb/d Dalian Changxing plant also bring online their petchem operations. But that is a problem for the future and for now, RAPID is first out of the gate into reality. It won’t be entering in a bonanza fuels market as predicted in 2012, but there is still space in the market for RAPID – and a few other like in – at least for now.
RAPID Refinery Factsheet:
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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.
It is, obviously, unsurprising that the recently released Q2 financials for the oil & gas supermajors contained distressed numbers as the first full quarter of Covid-19 impact washed over the entire industry. It is, however, surprising how the various behemoths of the energy world are choosing to respond to the new normal, and how past strategies have exposed either inherent strengths or weakness in their operational strategy.
Let’s begin with BP. With roots that stretch back to 1908 with the discovery of commercial oil in Persia, now Iran – BP arguably coined the phrase supermajor in the late 1990s, when acquisition of Amoco, Arco and Burmah Castrol married BP’s own substantial holdings in Europe and the Middle East to create a transatlantic oil and gas giant. It was a trend mirrored across the industry, with the Seven Sisters of the 1970s becoming ExxonMobil (Esso and Mobil), Chevron (Gulf Oil, Socal and Texaco) and modern day Royal Dutch Shell. Joining them were ConocoPhillips (Conoco and Phillips) and Total (Petrofina and Elf Aquitaine). As the world’s appetite for oil and gas increased at an accelerating pace, the supermajors became among the world’s largest and highest valued companies across the next two decades.
That is now poised for a major change. With fossil fuels waning in demand and renewables becoming more investable, BP is now declaring that it will no longer be a supermajor. CEO Bernard Looney made the announcement ahead of the release of the company’s Q2 financials, seeking to reinvent the firm as ‘integrated energy company’ rather than an ‘integrated oil company’. To make this change, Looney is looking to shrink BP’s oil and gas output by 40% through 2030 and invest heavily to become the world’s largest renewable energy businesses, putting climate change firmly on the agenda and getting ahead of the curve in meeting European directives for a low-carbon future. This was, perhaps, already on the cards. But the Covid-19 effect has hastened it. With a second quarter loss of US$6.7 billion, BP is choosing this time to rebrand itself for long-term transformation rather than maximise current shareholder value; indeed, it will slash dividends in half in order to invest cash for the future.
On the European side of the Atlantic, that trend is accelerating. Shell and Total are also aiming to be carbon neutral by 2050, alongside other European majors such as Eni and Equinor. That isn’t to say that oil or gas will no longer play a huge role in their operations – indeed Total and Eni in particular have made many recent and potentially lucrative finds in Egypt, South Africa and Suriname – just that oil and gas will become a smaller percentage of a diversified business. Both Shell and Total have also displayed how past strategic decisions have paid dividends in uncertain times. Both supermajors declared profits for the quarter, escaping the trend of underlying losses with net profits of US$638 million and US$126 million respectively when a deep red colour to the numbers was expected. The saving grace in a dramatic quarter was their trading activities, where the trading divisions of Shell and Total (as well as BP) took advantage of chaos in the market to deliver strong results. But even with this silver lining, Shell and Total are scaling back on dividends, as they join BP in a drive to diversify in the age of climate change, which has strong political backing in Europe where they are based.
On the other side of the pond, the mood surrounding climate change is decidedly different. ExxonMobil and Chevron aren’t exactly ignoring a low-carbon future but they aren’t exactly embracing it wholeheartedly either. Instead, both supermajors look to be focusing on maximising shareholder value by focusing on producing oil as profitably as possible. It explains why Chevron moved to acquire Noble Energy recently after failing to buy Anadarko last year, and why ExxonMobil is still gung-ho over American shale and its new found black gold assets in Guyana. The Permian remains on their focus; with economic pressure on, there are rich pickings in the shale patch that could turn American shale from a patchwork of ragtag independent drillers to big boy-dominated. In the short-term, that promises quick returns after the panic – especially with ExxonMobil and Chevron declaring net losses of US$1.08 billion and US$8.3 billion for Q2, respectively – but the underlying assumption to that is that the energy industry will recover and continue as it is for the foreseeable future, rather than the major upheaval predicted by their European counterparts.
For shareholders, and the companies themselves, the expectation is what the future will hold once the worse is over. That Q2 2020 financials dismal performance was never in doubt. What is more revealing is where the supermajors will go from here. Will BP’s attempt to end the supermajor era pay off? Or will American optimism return us back to business as usual? It’s two different visions of the future that will either way spell a sea change for the industry.
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