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Career Development
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By Moji Karimi


Here are some of the repeated discussion topics that seem to be common and specific to O&G.

Before I get to that, and as one of the general discussion points let me clarify the startup concept (my definition of it anyways) in contrast with a small business or consulting.

“Startup is a company based on a somewhat risky (unproven) idea that solves a pain-point in an innovative way. A startup should definitely have intellectual property and could be acquired in a relatively short amount of time”. Therefore, small “me too” businesses or consulting firms don’t fit here. Nothing wrong with those but they follow a different growth path and have unlike business models and priorities. By the short time I mean 7-10 years (for Tech startups that more like 3-5 years, O&G product/market fit takes longer for several reasons). Also have to mention, by O&G startup I’m not referring to a new E&P company (though that is also a very interesting concept. See UpCurve Energy as a good example).

For O&G folks who have lost their job it’s very tempting to immediately think about applying the same skill-set they have learnt to:

- provide somewhat the same service as bigger companies with a twist. Actually down market is the worst time to start a “me too” business. Same services take you to price war with bigger companies and you are certain to lose. Where you could shine is if you compete on “value” and have a clear differentiation.

- become a consultant. Even though this is a nice and quick way to make up for some of the lost income, it’s not a sustainable source and you are going against several other experts who are thinking about doing the same. You are also banking on a shrinking market.

Here are some ideas to consider before starting your business:

  • Read your non-compete agreement with your ex-employer line by line. It’s very common for entrepreneurs to have worked at a big corporation and while there learned the skill-set that’s enabling them to develop original ideas. This is a risky area and you should definitely consult with a lawyer.
  • Before spending any time or money on building or coding anything, find out if this is a problem worth solving. As engineers, we love to jump into building things but, in case of building a company, you have to control the urge and spend proper time researching the market and speaking with future clients to reality-check and refine your idea. That doesn’t mean fully disclosing how the idea works, but what problem you are targeting to solve, and how you compare to the incumbent methods.
  • Think about the company not about the product. People think products define companies, it’s actually not true, business models create companies and your solution/product is only a part of it. A quick way to build one is the business model canvas with the integral part of it being the value proposition. Here is a quick Udemy course on Lean Canvas which I think is better refined than the business model canvas.
  • Think about the milestones for your company, for O&G these could be 1- research 2- business model 3- prototype 4- field trial 5- commercialization. Or you can follow a more general flow-work like the lean startup model. In either case think about what resources you need for each phase.
  • For each petroleum engineer out there with a novel idea there is also a business development manager who is looking for an idea to execute upon. So no matter what side you are on, start networking with the mindset beyond looking for a job, but to find a business partner with skill-set complementary to yours.

Initially the purpose of this post was for those who have lost their job recently; but some aspects also apply to the ones currently employed and want to have a plan B. Working full time and trying to develop an idea at nights and weekends has its own very interesting challenges.

At the end, starting a new venture isn’t easy, if it was everyone would be doing it. However, there is nothing more satisfying that controlling your own destiny.


*This article was first published on 4 February 2016 by Moji Karimi and is reprinted here with full permission.

**About the Writer:

Moji Karimi is an oil and gas entrepreneur who has helped ideate, develop, and commercialize technology for big companies such as Weatherford and has now begun focusing on startups. Currently, Karimi is the business development manager at Biota Technology, a startup that is commercializing DNA Sequencing in the oil and gas industry. He is also a cofounder of SPE Gulf Coast Section Entrepreneurship Cell which is an initiative to educate and connect entrepreneurs, decision makers, and investors. Karimi holds BS and MS degrees in drilling and petroleum engineering, respectively.

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Your Weekly Update: 12 - 16 August 2019

Market Watch 

Headline crude prices for the week beginning 12 August 2019 – Brent: US$58/b; WTI: US$54/b

  • Saudi Arabia’s overtures to further stabilise prices was met with a largely positive response by the market, allowing crude prices to claw back some ground after being hammered by demand concerns
  • Saudi officials reportedly called other members in the OPEC and OPEC+ producer clubs to discuss options on how to stem the recent rout in prices, with an anonymous official quoted as saying that it ‘would not tolerate continued price weakness’
  • Reports suggest that Saudi Arabia plans to keep its oil exports at below 7 mmb/d in September according to sales allocations, which was seen as a stabilising factor in crude price trends
  • This came after crude prices fell as the US-China trade war entered a new front, causing weakness in the Chinese Yuan, although President Trump has floated the idea of delaying the new round of tariffs beyond the current implementation timeline of September 1
  • Crude had also fallen in response to a slide in American crude oil stockpiles and a receding level of tensions in the Persian Gulf
  • In a new report, the International Energy Agency said that the outlook for global oil demand is ‘fragile’ on signs of an economic slowdown; there is also concern that China will target US crude if the US moves ahead with its tariff plan
  • The US active rig count lost another 8 rigs – 6 oil and 2 gas – the sixth consecutive weekly loss that brought the total number of active rigs to 934
  • Demand fears will continue to haunt the market, which will not be offset so easily of Saudi-led efforts to limit production; as a result, crude prices will trade rangebound with a negative slant in the US$56-58/b range for Brent and US$52-54/b for WTI


Headlines of the week

Upstream

  • Nearly all Anadarko shareholders have approved the Occidental Petroleum deal, completing the controversial takeover bid despite investor Carl Icahn’s attempts to derail the purchase
  • Crude oil inventories in Western Canada have fallen by 2.75 million barrels m-o-m to its lowest level since November 2017, as the production limits in Alberta appear to be doing their job in limiting a supply glut while output curbs are slowly being loosened on the arrival of more rail and pipeline capacity
  • Mid-sized Colorado players PDC Energy and SRC Energy – both active in the Denver-Julesburg Basin – are reportedly in discussion to merge their operations
  • Pemex has been granted approval by the National Hydrocarbon Commission to invest US$10 billion over 25 years to develop onshore and offshore exploration opportunities in Mexico
  • Qatar Investment Authority has acquired a ‘significant stake’ in major Permian player Oryx Midstream Services from Stonepeak Infrastructure Partners for some US$550 million, as foreign investment in the basin increases
  • PDVSA and CNPC’s Venezuelan joint venture Sinovensa has announced plans to expand blending capacity – lightening up extra-heavy Orinoco crude to medium-grade Merey – from a current 110,000 b/d to 165,000 b/d
  • BHP has approved an additional US$283 million in funding for the Ruby oil and gas project in Trinidad and Tobago, with first production expected in 2021
  • CNPC, ONGC Videsh and Petronas have reportedly walked away from their onshore acreage in Sudan, blaming unpaid oil dues on production from onshore Blocks 2A and 4 that have already reached more than US$500 million

Midstream/Downstream

  • Expected completion of Nigeria’s huge planned 650 kb/d Dangote refinery has been delayed to the end of 2020, with issues importing steel and equipment cited
  • Saudi Aramco’s US refining arm Motiva announced plans to shut several key units at its 607 kb/d Port Arthur facility in Texas for a 2-month planned maintenance, affecting its 325 kb/d CDU and the naphtha processing plant
  • ADNOC has purchased a 10% stake in global terminal operator VTTI, expanding its terminalling capacity in Asia, Africa and Europe
  • A little-known Chinese contractor Wison Engineering Services has reportedly agreed to refurbish Venezuela’s main refineries in a barter deal for oil produced, in a bid for Venezuela to evade the current US sanctions on its crude exports
  • Swiss downstream player Varo Energy will increase its stake in the 229 kb/d Bayernoil complex in Germany to 55% after purchasing BP’s 10% stake
  • India has raised the projected cost estimate of its giant planned refinery in Maharashtra – a joint venture between Indian state oil firms with Saudi Aramco and ADNOC – to US$60 billion, after farmer protests forced a relocation

Natural Gas/LNG

  • The government of Australia’s New South Wales has given its backing to South Korea’s Epik and its plan to build a new LNG import terminal in Newcastle
  • Kosmos Energy is proposing to build two new LNG facilities to tap into deepwater gas resources offshore Mauritania and Senegal under development
  • In the middle of the Pacific, the French territory of New Caledonia has started work on its Centrale Pays Project, a floating LNG terminal with an accompanying 200-megawatt power plant, with Nouvelle-Caledonia Energie seeking a 15-year LNG sales contract for roughly 200,000 tons per year
August, 16 2019
The State of the Industry: Q2 2019

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

  • ExxonMobil – Revenue (US$69.1 billion, down 6% y-o-y), Net profit (US$3.1 billion, down 22.5% y-o-y)
  • Shell - Revenue (US$90.5 billion, down 6.5% y-o-y), Net profit (US$3 billion, down 50% y-o-y)
  • Chevron – Revenue (US$36.3 billion, down 10.4% y-o-y), Net profit (US$4.3 billion, up 26% y-o-y)
  • BP - Revenue (US$73.7 billion, down 4.11% y-o-y), Net profit (US$2.8 billion, flat y-o-y)
  • Total - Revenue (US$51.2 billion, down 2.5% y-o-y), Net profit (US$2.89 billion, down 18.6% y-o-y)
August, 14 2019
TODAY IN ENERGY: Australia is on track to become world’s largest LNG exporter

LNG exports from selected countries

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.

Australia LNG export capacity

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.

Australia LNG projects

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.

Australia LNG exports by destination country

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.

August, 14 2019