Hui Shan

Job Steward at NrgEdge. If you are an Energy Professional (Oil, Gas, Energy) contact me for opportunities
Last Updated: August 18, 2018
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Human Resources
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‘Nine to five plus a single employer’ is no longer an equation that the current workforce operates on. This traditional marketplace has been disrupted with the advent of new technology that has heralded gig or on-demand economy. Players like Uber, Airbnb, & Deliveroo offer a classic example of how these innovators have leveraged on this concept of gig economy and have shaken up the traditional setup. Millions of people today, prefer flexible work timings, multiple employers, interest-based projects and multiple revenue streams, the working style we commonly refer to as gig economy.

CIPD describes the gig economy as a new way of working that is based on the temporary jobs or projects, which is paid on the project or hourly basis. It is also referred to as the ‘sharing economy’ or ‘collaborative economy’

The gig economy: pros and cons in the context of the Oil & Gas Industry        

The Oil and Gas industry is considered traditional when it comes to adapting to new technology or concepts. However, the notion is changing now with 30% of its workforce comprising of gig workers and the trend is expected to rise in coming years. Instead of depending on the recruitment agencies, companies are now focussing on targeted industry digital platforms to search, shortlist, verify and hire the gig contractors or freelancers. However, like everything else, there are pros and cons of hiring freelancers or gig employees:

Pros:

Reduced Overhead cost

The cost of hiring an in-house employee is immense because apart from salary it also includes costs of insurance, perks, benefits, training, leaves, and cost associated with providing the facilities like internet, sitting arrangements, refreshments, canteen, electricity, and so on. All the extra cost apart from salary gets waived off when it comes to hiring gig employees or also known as “freelancers” in the market. Thus reducing the huge chunk of overhead cost for the employing company.

Low Financial Risk

 In the case of full-time employees, the company needs to pay even during “down-times” when the work is low, or the productivity standards are not met. However, in the case of temporary staff or freelancers, the company only pays for the work accomplished as per the specified standard. Thereby lowering the financial risk.

Bigger and better pool of talent

The energy sector is a highly specialized sector and hence requires employees with a specific skill set. Specially for an on-site project, location is the biggest constraint. What if you do not find the right talent at your location? Then you are left with two options: either to hire a new employee and provide training or offload and distribute the work to the current employees. Both this scenario is risky. That’s when the gig employees are a real life-saver. The boundaries are no barrier, you can gain access to any person sitting in any part of the world. You do not even have to compromise on the skills and invest in training.

Innovation and knowledge-sharing

The company spends a substantial amount on strategizing and talent development. However, when you opt for a freelancer, you gain access to knowledge that the employee brings in by working with other organizations. So, in the oil and gas sector, a new employee can bring an innovation in the process or methodology by his experience and observation with different clients.

Round the clock functioning

Sometimes, the gig employee operates from different time zone which means that you can get your work running even while you have closed down at your part of the world. Additionally, you can reach out to freelancers for revisions, urgent works, even after the fixed working hours and during weekends, which is a great relief during tight-deadline projects.

Cons

Lack of supervision and discipline

Most gig workers operate remotely, and you cannot monitor their work physically which means that you can never be sure whether the hourly rates that the employee billed you for, is actually spent on work or for leisure. However, now there are numerous monitoring sites like Hubstaff that tracks the productivity level of the employee. Also, working in oil and gas sector involves potential hazards that can lead to serious injuries and even death. In case of remote workers, managing and monitoring all safety measures pertaining to explosions and fires, equipment safety, machine hazards and so on is a daunting task.

Unpredictable work 

Until you gain mutual trust, there is a lot at the stake. For example: if you hire a temporary staff or freelancer to work on a project, you cannot be certain if the person will be able to deliver his/her duties. The risk of losing time, money, and energy is high. If all turns well, you can enjoy the perks however if it didn’t go your way then you suffer a loss on multiple levels. To avoid this scenario, it is advisable to ask for previous work references and keep reviewing the work periodically so that you are aware of the direction things are shaping in.

Loyalty and company ethics 

Because, each company has its own set of principles and working guidelines which forms the culture of the company, it is challenging for the freelancer to operate as per the company’s code of conduct or policies. Furthermore, they work for multiple clients at a time, their loyalty may be questionable.

Training and development issue

Every company works and operates differently though key process remains the same. The complete onboarding of the remote worker is not possible as in the case of a full-time employee where the company’s working style becomes their second nature. Additionally, the effort to organize a training program for the gig worker is tricky because of the location and time bound issues.

Thus, for a dynamic industry like oil and gas, gig employees can be an asset if they can bring in the required expertise, skill set and attitude to outperform your expectation. You can find the right talent by using dedicated oil & gas professional networking platforms that bring talents and employers together. Use it to your advantage and you are good to go.

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This Week in Petroleum
Despite crude oil production cuts, Saudi Arabian crude oil exports to some Asian countries have increased

The U.S. Energy Information Administration (EIA) estimates that during May 2019, Saudi Arabia’s crude oil production approached a four-year low, averaging an estimated 9.9 million barrels per day (b/d). Production declined more than 1 million b/d since its estimated all-time high production levels in October and November 2018 (Figure 1). Although the country’s total crude oil exports are also lower than recent highs, its crude oil exports to some Asia Pacific countries actually increased during the period of declining production. China in particular has increased its crude oil imports from Saudi Arabia, which is partially a result of new Chinese refining capacity. In contrast, U.S. crude oil imports from Saudi Arabia reached a 31-year low in February, with weekly estimates for April, May, and June suggesting even further declines.

Figure 1. Monthly Saudi Arabia crude oil production and exportsMonthly Saudi Arabia crude oil production and exports

Four Asia Pacific countries that publish crude oil imports by country of origin—China, Japan, South Korea, and Taiwan—collectively imported an average of 3.5 million b/d of crude oil from Saudi Arabia in 2018 (Figure 2). Chinese and Japanese 2019 year-to-date crude oil imports from Saudi Arabia are higher than their 2018 annual averages, whereas Taiwan’s are flat and South Korea’s have declined slightly. China’s crude oil imports from Saudi Arabia, in particular, have increased by 0.4 million b/d year-to-date through April compared with the 2018 annual average, significantly higher than Japan’s increase of less than 0.1 million b/d.

Monthly crude oil imports from Saudi Arabia for select Asia Pacific countries

In contrast, U.S. crude oil imports from Saudi Arabia have declined year-to-date through March 2019 compared with the 2018 average by more than 0.2 million b/d, averaging 0.6 million b/d for the first quarter of 2019. Weekly estimates through June 14 of this year show continued declines, indicating that imports from Saudi Arabia averaged less than 0.5 million b/d in May and the first half of June. As a result of these shifts in crude oil flows, the U.S. share of total Saudi Arabian crude oil exports fell to 9% in March, and China’s share increased to 24% (Figure 3). Collectively, the United States, China, Japan, Taiwan, and South Korea historically accounted for about 60%–65% of total Saudi Arabian crude oil exports.

Figure 3.Monthly share of Saudi Arabian crude oil exports

These recent changes in crude oil trade patterns are partially because of long-term structural trends within China and the United States, but they are also a result of recent oil market dynamics. From 2010 through 2018, EIA estimates total Chinese petroleum consumption has increased from 9.3 million b/d to 13.9 million b/d, whereas Chinese domestic production has increased from 4.6 million b/d to 4.8 million b/d. As a result, China’s need to meet incremental oil consumption has come primarily from imports. China’s crude oil imports from Saudi Arabia have gradually increased in recent years, and in March 2019 reached the highest level for any month since at least 2004, at 1.7 million b/d. Other countries, including Russia and Brazil, have had larger increases in crude oil export growth to China, however, with Russia overtaking Saudi Arabia as the largest source of crude oil on an annual average basis in 2016.

U.S. crude oil imports, on the other hand, have steadily decreased during this period as domestic crude oil production has increased. In addition, U.S. crude oil imports from members of the Organization of the Petroleum Exporting Countries (OPEC) have declined, in particular, following increases from other countries such as Canada. Canadian crude oil can substitute for certain OPEC grades and have lower transportation costs when shipped by available pipeline capacity.

Saudi Arabian crude oil exports to China increased recently at least in part as a result of the startup of a new 0.4 million b/d refinery in Dalian, Liaoning Province, which has a supply agreement with Saudi Aramco, Saudi Arabia’s national oil company. Saudi Aramco also has a supply agreement with another 0.4 million b/d refining and petrochemical complex in Zhejiang Province, which started trial operations this year.

Other near-term developments, however, could reduce the volume of Saudi Arabian crude oil headed to China for May, June, and through the summer. Saudi Arabia typically increases domestic crude oil consumption in the summer months because the country directly burns the fuel for power generation. Although Saudi Arabia has gradually been increasing the use of fuel oil and natural gas instead of crude oil for power generation, the seasonal increase is dependent on the weather and can still amount to several hundred thousand barrels per day in additional domestic consumption during summer months. The five-year (2014–18) average crude oil burn for electric power generation peaks in July at 0.7 million b/d, an increase of 0.3 million b/d from the April average. In addition, Chinese crude oil refinery demand could be lower in the second quarter of 2019 than in the first quarter of 2019. Bloomberg data suggest that Chinese refinery outages in May and June month-to-date were 2.1 million b/d and 1.7 million b/d, respectively, 0.5 million b/d and 0.6 million b/d higher than their respective five-year averages for those months.

Recent global oil supply issues could keep Saudi Arabian crude oil exports to China, Japan, South Korea, and Taiwan relatively high in the coming months, however, in spite of the previously mentioned seasonal factors. These four countries were all initially granted Iranian sanctions waivers through May 2019. However, because waivers were not renewed, each country will likely need an alternative to Iranian crude oil. This development could keep their crude oil imports from Saudi Arabia near first-quarter 2019 levels for the coming months as a partial substitute for Iranian barrels. Saudi Arabia’s support of maintaining current OPEC production cuts or increasing output levels in the upcoming late-June or early-July OPEC meeting will be a critical determinant for future export flows.

U.S. average regular gasoline and diesel prices fall

The U.S. average regular gasoline retail price fell more than 6 cents from the previous week to $2.67 per gallon on June 17, 21 cents lower than the same time last year. The Midwest price fell nearly 8 cents to $2.54 per gallon, the West Coast price fell nearly 7 cents to $3.45 per gallon, the East Coast price fell more than 6 cents to $2.56 per gallon, the Rocky Mountain price fell nearly 4 cents to $2.91 per gallon, and the Gulf Coast price fell nearly 3 cents to $2.34 per gallon.

The U.S. average diesel fuel price fell nearly 4 cents to $3.07 per gallon on June 17, more than 17 cents lower than a year ago. The West Coast and Midwest prices each fell nearly 5 cents to $3.67 per gallon and $2.96 per gallon, respectively, the Rocky Mountain price fell more than 4 cents to $3.07 per gallon, the East Coast price fell nearly 3 cents to $3.10 per gallon, and the Gulf Coast price fell more than 2 cents to $2.82 per gallon.

Propane/propylene inventories rise

U.S. propane/propylene stocks increased by 3.3 million barrels last week to 74.5 million barrels as of June 14, 2019, 10.7 million barrels (16.8%) greater than the five-year (2014-2018) average inventory levels for this same time of year. East Coast, Midwest, and Gulf Coast inventories each increased by 1.1 million barrels. Rocky Mountain/West Coast inventories fell slightly, remaining virtually unchanged. Propylene non-fuel-use inventories represented 6.6% of total propane/propylene inventories.

June, 20 2019
Indonesia’s Abadi LNG Project Sees Movement

It has been 21 years since Japanese upstream firm Inpex signed on to explore the Masela block in Indonesia in 1998 and 19 years since the discovery of the giant Abadi natural gas field in 2000. In that time, Inpex’s Ichthys field in Australia was discovered, exploited and started LNG production last year, delivering its first commercial cargo just a few months ago. Meanwhile, the abundant gas in the Abadi field close to the Australia-Indonesia border has remained under the waves. Until recently, that is, when Inpex had finally reached a new deal with the Indonesian government to revive the stalled project and move ahead with a development plan.

This could have come much earlier. Much, much earlier. Inpex had submitted its first development plan for Abadi in 2010, encompassing a Floating LNG project with an initial capacity of 2.5 million tons per annum. As the size of recoverable reserves at Abadi increased, the development plan was revised upwards – tripling the planned capacity of the FLNG project to be located in the Arafura Sea to 7.5 million tons per annum. But at that point, Indonesia had just undergone a crucial election and moods had changed. In April 2016, the Indonesian government essentially told Inpex to go back to the drawing board to develop Abadi, directing them to shift from a floating processing solution to an onshore one, which would provide more employment opportunities. The onshore option had been rejected initially by Inpex in 2010, given that the nearest Indonesian land is almost 100km north of the field. But with Indonesia keen to boost activity in its upstream sector, the onshore mandate arrived firmly. And now, after 3 years of extended evaluation, Inpex has delivered its new development plan.

The new plan encompasses an onshore LNG plant with a total production capacity of 9.5 million tons per annum. With an estimated cost of US$18-20 billion, it will be the single largest investment in Indonesia and one of the largest LNG plants operated by a Japanese firm. FID is expected within 3 years, with a tentative target operational timeline of the late 2020s. LNG output will be targeted at Japan’s massive market, but also growing demand centres such as China. But Abadi will be entering into a far more crowded field that it would have if initial plans had gone ahead in 2010; with US Gulf Coast LNG producers furiously constructing at the moment and mega-LNG projects in Australia, Canada and Russia beating Abadi’s current timeline, Abadi will have a tougher fight for market share when it starts operations. The demand will be there, but the huge rise in the level of supplies will dilute potential profits.

It is a risk worth taking, at least according to Inpex and its partner Shell, which owns the remaining 35% of the Abadi gas field. But development of Abadi will be more important to Indonesia. Faced with a challenging natural gas environment – output from the Bontang, Tangguh and Badak LNG plants will soon begin their decline phase, while the huge potential of the East Natuna gas field is complicated by its composition of sour gas – Indonesia sees Abadi as a way of getting its gas ship back on track. Abadi is one of Indonesia’s few remaining large natural gas discoveries with a high potential commercialisation opportunities. The new agreement with Inpex extends the firm’s licence to operate the Masela field by 27 years to 2055 with the 150 mscf pipeline and the onshore plant expected to be completed by 2027. It might be too late by then to reverse Indonesia’s chronic natural gas and LNG production decline, but to Indonesia, at least some progress is better than none.

The Abadi LNG Project:

  • Reserves: 10 tcf of natural gas
  • Field: Estimated production of 1.2 bcf/d gas and 24,000 b/d condensate for 24 years
  • Operations: Inpex (65%), Royal Dutch Shell (35%)
  • LNG Plant: 9.5 mtpa capacity, estimated start date in 2027
June, 18 2019
Your Weekly Update: 10 - 14 June 2019

Market Watch

Headline crude prices for the week beginning 10 June 2019 – Brent: US$62/b; WTI: US$53/b

  • With US’s trade and tariff assault abating for the moment, crude oil prices have consolidated their trends to steady up as OPEC+ nations signal their desire to continue stabilising the oil market ahead of a June 25 meeting in Vienna
  • Despite some background squabbles between Russia and Saudi Arabia – with Russia at pains to emphasise its position regarding lower oil prices – the group has seemingly come together
  • Saudi Arabia has reportedly corralled the OPEC group to agreeing to extending the current supply deal to December, even Iran, but convincing Russia has been a harder task and adherence may continue to be an issue
  • Meanwhile, the US continues to tighten the screws on Venezuela and Iran, announcing sanctions on Iranian petrochemicals exports and targeting Venezuela’s trade in diluents that are used to blend heavy crude down
  • With reports that Iranian crude exports were down to an estimated 400 kb/d in May, tensions in the Persian Gulf continue with the latest incident being attacks on tankers; this risk factor will lift the floor for oil prices for now
  • After a brief rise last week, American drillers dropped 11 oil rigs but added 2 gas rigs according to Baker Hughes for a net loss of 9 active sites, bringing the total active rig count down to 975
  • As OPEC prepares to meet, the market has seemingly locked in an extension of the supply deal into projections, which will leave little room for gains; expect Brent to fall to the US$60-62/b range and WTI to trade at US$51-53/b

Headlines of the week

Upstream

  • BP is selling its stakes in its Egyptian concessions in the Gulf of Suez to Dubai-based Dragon Oil (a subsidiary of ENOC), which do not include BP’s core production assets in the West Nile Delta production area
  • Eni’s African streak continues with its fifth oil discovery in Angola’s Block 15/06 at the Agidigbo prospect, bringing total resources to 1.8 billion barrels
  • Also in Angola, ExxonMobil and its partners are looking to invest further in offshore Block 15 that will see Sonangol take a 10% interest in the PSA
  • Russia’s Lukoil has inked a deal with New Age M12 Holding to acquire a 25% interest in the offshore Marine XII licence in the Republic of Congo for US$800 million, covering the producing Nene and Litchendjili fields
  • Buoyed by recent discoveries in the Caribbean, the Dominican Republic is launching its first licensing round in July, offering 14 blocks in the onshore Cibao, Enriquillo and Azua basins and the offshore San Pedro basin
  • W&T Offshore and Kosmos Energy have struck oil in the Gladden Deep well in the US Gulf of Mexico, the first of a four-well programme that includes the Moneypenny, Oldfield and Resolution prospects with estimates of 7 mmboe

Midstream & Downstream

  • Shell is increasing storage capacity at its Pulau Bukom refinery in Singapore, adding two new crude oil tanks to increase capacity by nearly 1.3 million barrels
  • A new swathe of American sanctions against Iran is now targeting Iranian petrochemical exports, clipping a major regional revenue source for Iran
  • Angola is looking overhaul its refining sector, by attracting investment o overhaul facilities and building a new refinery in Soyo that will be the third ongoing refining project after the 200 kb/d Lobito and Cabinda plants
  • BP and Mexico’s IEnova have signed a deal allowing BP to use IEnova’s new gasoline and diesel storage and distribution facilities in Manzanillo and Guadalajara, allowing access to over 1 million barrels of storage
  • British petrochemicals firm INEOS has announced plans to invest US$2 billion in building three new petchem plants in Saudi Arabia that would form part of the wider Saudi Aramco-Total Project Amiral petrochemicals complex
  • The saga of Russia’s bankrupt 180 kb/d Antipinsky refinery continues, with SOCAR Energoresurs (a JV including Sberbank) acquiring an 80% stake in the refinery with the aim of restarting operations
  • Mexico has kicked off construction of its US$7.7 billion oil refinery, aimed to overhauling the Mexican refining industry after years of underperformance

Natural Gas/LNG

  • Toshiba is exiting the Freeport LNG project in Texas, paying Total US$815 million and handing over its 20-year liquefaction rights by March 2020
  • China’s CNOOC has officially acquired a 10% stake in the Arctic LNG 2 project by Novatek, solidifying natural gas ties between Russia and China
  • Cheniere has taken FID to add a sixth liquefaction train to its Sabine Pass export project in Lousiaina, which would add 4.5 mtpa of capacity to the plant
  • Novatek, Sinopec and Gazprombank have created a China-focused joint venture to market LNG and natural gas from Novatek’s Arctic projects in China
June, 17 2019