In the oil and gas
industry, we have long known that the right people, with the right skills and
tools, will bring about the highest return on investment in any critical
project. But what happens when you don’t have those people with the right
skills to helm those projects?
The oil price fell below $30 in January and this was followed by an almost continuous stream of news relating to job losses, decreasing profits and cost cutting at every corner. The International Energy Agency reported that any recovery in the oil and gas industry will be short lived, and the recent “rise in prices was a ‘false dawn’”.
One key consequence of this continued downturn has been significant cuts of “non-regulatory” or “non-essential’ training by many oil companies. Ironically these “non-essential’ training do play a pivotal role in the continued survival of the industry, and vital for its safe operations. So what happens to an industry that neglects vital skills development? This is hidden element of the current cost cutting campaigns.
Back in 2011 Schlumberger Business Consulting conducted a survey exploring future skills shortages in the hydrocarbon industry. It found that “22,000 senior petrochemical professionals would quit the industry by 2015” and that the recruitment of graduates may offset staff levels but would not fill the experience gap. It later then noted that by 2016 the absence of experienced professionals within the oil industry would reach 20% of the talent pool.
These finding are four years old, and the downturn wasn’t even considered as a mitigating factor in the study. Since then, not only have thousands of jobs been cut, but recruitment budgets have also been slashed and the extended downturn has put graduates off this struggling industry, only worsening the problem.
When the inevitable upturn in the oil price and wider sector does take place, oil companies will find themselves with a potentially vast skills gap. Desperate to increase production with higher prices to make up for lost revenue, many firms are likely to push ahead with under-skilled staff. In doing so, these firms will not just face inefficiencies but potentially catastrophic safety and environmental incidents affecting profits and lives.
The industry has a long history of overlooking issues related to its talent management. Long-term skills development planning has never really been adhered to when oil prices collapse. Most oil companies have been short sighted, pleasing only their masters in the stock market.
Oil company bosses need to focus on talent as much as they did when the price of oil was over $70 – 80per barrel. Granted that we may not see another $100per barrel days in the near future however when oil prices return to its “normal” trajectory, the problem will only worsen. This careless neglect of sustained skills development, will lead to significant shortages, inflated salaries, the overuse of third-party contractors and widespread poaching. Current evidence also suggests that talents that have left the oil sector may not necessary return, unless the price is right. And it will be a high price to pay.
But is this all the responsibility of the oil companies or is there more that could be done by regulators, interest groups, long term oil investors or even the employee unions?
The UK’s North Sea oil and gas fields are feeling the full weight of the crisis due to their high staff and production costs. An estimated 65,000 jobs have been lost across the UK oil industry and further 10,000 are at risk compounded by the recent Brexit mess.
What is a probable
Consider this. The Engineering Construction Industry Training Board legally requires that companies on their register pay a mandatory levy at the start of each year. The levy can only be claimed back through training, forcing firms to conduct training or lose their levy.
this might not be enough to solve the problem entirely but they are certainly
in the right direction towards a more sustainable and competent workforce in
the long run. Be it companies themselves or by regulating bodies, it is vital
that the oil industry understands that by equipping staff with the knowledge and
practical skills, it will keep their business on track in the long term. It can
quite literally save companies millions from overspend, inefficiencies and
What are your thoughts about probable solutions that can resolve the continuing decline of skills and experience in the current oil crisis?
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Headline crude prices for the week beginning 12 August 2019 – Brent: US$58/b; WTI: US$54/b
Headlines of the week
The momentum for crude prices abated in the second quarter of 2019, providing less cushion for the financial results of the world’s oil companies. But while still profitable, the less-than-ideal crude prices led to mixed results across the boards – exposing gaps and pressure points for individual firms masked by stronger prices in Q119.
In a preview of general performance in the industry, Total – traditionally the first of the supermajors to release its earnings – announced results that fell short of expectations. Net profits for the French firm fell to US$2.89 billion from US$3.55 billion, below analyst predictions. This was despite a 9% increase in oil and gas production – in particularly increases in LNG sales – and a softer 2.5% drop in revenue. Total also announced that it would be selling off US$5 billion in assets through 2020 to keep a lid on debt after agreeing to purchase Anadarko Petroleum’s African assets for US$8.8 billion through Occidental.
As with Total, weaker crude prices were the common factor in Q219 results in the industry, though the exact extent differed. Russia’s Gazprom posted higher revenue and higher net profits, while Norway’s Equinor reported falls in both revenue and net profits – leading it to slash investment plans for the year. American producer ConocoPhillips’ quarterly profits and revenue were flat year-on-year, while Italy’s Eni – which has seen major success in Africa – reported flat revenue but lower profits.
After several quarters of disappointing analysts, ExxonMobil managed to beat expectations in Q219 – recording better-than-expected net profits of US$3.1 billion. In comparison, Shell – which has outperformed ExxonMobil over the past few reporting periods – disappointed the market with net profits halving to US$3 billion from US$6 billion in Q218. The weak performance was attributed (once again) to lower crude prices, as well as lower refining margins. BP, however, managed to beat expectations with net profits of US$2.8 billion, on par with its performance in Q218. But the supermajor king of the quarter was Chevron, with net profits of US$4.3 billion from gains in Permian production, as well as the termination fee from Anadarko after the latter walked away from a buyout deal in favour of Occidental.
And then, there was a surprise. In a rare move, Saudi Aramco – long reputed to be the world’s largest and most profitable energy firm – published its earnings report for 1H19, which is its first ever. The results confirmed what the industry had long accepted as fact: net profit was US$46.9 billion. If split evenly, Aramco’s net profits would be more than the five supermajors combined in Q219. Interestingly, Aramco also divulged that it had paid out US$46.4 billion in dividends, or 99% of its net profit. US$20 billion of that dividend was paid to its principle shareholder – the government of Saudi Arabia – up from US$6 billion in 1H18, which makes for interesting reading to potential investors as Aramco makes a second push for an IPO. With Saudi Aramco CFO Khalid al-Dabbagh announcing that the company was ‘ready for the IPO’ during its first ever earnings call, this reporting paves the way to the behemoth opening up its shares to the public. But all the deep reservoirs in the world did not shield Aramco from market forces. As it led the way in adhering to the OPEC+ club’s current supply restrictions, weaker crude prices saw net profit fall by 11.5% from US$53 billion a year earlier.
So, it’s been a mixed bunch of results this quarter – which perhaps showcases the differences in operational strategies of the world’s oil and gas companies. There is no danger of financials heading into the red any time soon, but without a rising tide of crude prices, Q219 simply shows that though the challenges facing the industry are the same, their approaches to the solutions still differ.
Supermajor Financials: Q2 2019
Source: U.S. Energy Information Administration, CEDIGAZ, Global Trade Tracker
Australia is on track to surpass Qatar as the world’s largest liquefied natural gas (LNG) exporter, according to Australia’s Department of Industry, Innovation, and Science (DIIS). Australia already surpasses Qatar in LNG export capacity and exported more LNG than Qatar in November 2018 and April 2019. Within the next year, as Australia’s newly commissioned projects ramp up and operate at full capacity, EIA expects Australia to consistently export more LNG than Qatar.
Australia’s LNG export capacity increased from 2.6 billion cubic feet per day (Bcf/d) in 2011 to more than 11.4 Bcf/d in 2019. Australia’s DIIS forecasts that Australian LNG exports will grow to 10.8 Bcf/d by 2020–21 once the recently commissioned Wheatstone, Ichthys, and Prelude floating LNG (FLNG) projects ramp up to full production. Prelude FLNG, a barge located offshore in northwestern Australia, was the last of the eight new LNG export projects that came online in Australia in 2012 through 2018 as part of a major LNG capacity buildout.
Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL), trade press
Note: Project’s online date reflects shipment of the first LNG cargo. North West Shelf Trains 1–2 have been in operation since 1989, Train 3 since 1992, Train 4 since 2004, and Train 5 since 2008.
Starting in 2012, five LNG export projects were developed in northwestern Australia: onshore projects Pluto, Gorgon, Wheatstone, and Ichthys, and the offshore Prelude FLNG. The total LNG export capacity in northwestern Australia is now 8.1 Bcf/d. In eastern Australia, three LNG export projects were completed in 2015 and 2016 on Curtis Island in Queensland—Queensland Curtis, Gladstone, and Australia Pacific—with a combined nameplate capacity of 3.4 Bcf/d. All three projects in eastern Australia use natural gas from coalbed methane as a feedstock to produce LNG.
Source: U.S. Energy Information Administration
Most of Australia’s LNG is exported under long-term contracts to three countries: Japan, China, and South Korea. An increasing share of Australia’s LNG exports in recent years has been sent to China to serve its growing natural gas demand. The remaining volumes were almost entirely exported to other countries in Asia, with occasional small volumes exported to destinations outside of Asia.
Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL)
For several years, Australia’s natural gas markets in eastern states have been experiencing natural gas shortages and increasing prices because coal-bed methane production at some LNG export facilities in Queensland has not been meeting LNG export commitments. During these shortfalls, project developers have been supplementing their own production with natural gas purchased from the domestic market. The Australian government implemented several initiatives to address domestic natural gas production shortages in eastern states.
Several private companies proposed to develop LNG import terminals in southeastern Australia. Of the five proposed LNG import projects, Port Kembla LNG (proposed import capacity of 0.3 Bcf/d) is in the most advanced stage, having secured the necessary siting permits and an offtake contract with Australian customers. If built, the Port Kembla project will use the floating storage and regasification unit (FSRU) Höegh Galleon starting in January 2021.