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Last Updated: July 17, 2017
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*This article was first published on 16 March 2017 by Moji Karimi and is reprinted here with full permission.

“We are a late adopter of technology.” Said no one ever!

Often the biggest dream of an oil and gas startup is to have ExxonMobil (or any of the other majors) as their first customer. However, not understanding an operator’s culture of technology reception could be a deadly first step for early-stage startups.

Startups should know the target operator’s risk tolerance, and the best time to approach the company. You would never hear the manager of an oil company say that they are a late adopter of technology but, in reality, many companies prefer to wait and see the outcome of tests done with early adopters. Here are some suggestions for both startups and operators that could help optimize technology adoption.

For Startups

Do your homework. Learn all the critical information about your target operators and prioritize against your product development timeline. A mistimed pitch could either burn your chance or throw you into a yearlong back and forth with no light at the end of the tunnel. Here are a few suggestions.

  • First things first, you should understand the problem the operator is trying to solve as well as they do. Be prepared to explain why your product and team are the best choice to solve that problem. If you aren’t solving a problem, you will be a “nice to have” and therefore won’t get much attention.
  • For your market segmentation, categorize operators into majors, independents, and small companies. Usually it is best to start with smaller companies. This may seem counter-intuitive to what will impress your stakeholders, but you are likely to become equipped with case studies and move up the ranks faster by beginning with smaller firms.
  • For each given operator, research the comparable technologies being deployed. Also, find out the development stage at which the operator has historically agreed to field trial new technologies.
  • Find out if the operator has an internal technology team and, more specifically, if that group is housed inside each business unit or functions independently. Determine what their budget for field trials is and, if there is none, then your best chance will be to find a champion of your technology within a business unit.
  • In general, it is best to begin this search within business units, which may lead to referrals to other stakeholders. Think of who could benefit from your technology the most, and also who is the one paying for it.  
  • If the operator has a venture capital arm and you are looking for investments, proceed with this group. Even if you move forward with a business unit instead, ensure that the venture capital arm of the company knows about your field trial. This is a relationship worth nurturing since it may help raise capital for your company and, from an investment perspective, there is no better due diligence than an actual field trial with the same company.
  • Spend 80% of your time finding the right entry point and then become laser-focused on that specific company. Remember, until you have a commercial product, your success depends on successfully executing one field trial at a time.  

As you get exposure with more operators, identify the trends that show where you are gaining traction and have the clearest path to commercial and repeatable applications.

For Operators

Regardless of your role, ask how your company perceives technology. Is some level of early-technology risk accepted? One good reality check is to see how the previous failures have been treated. That will indicate what stage of technology maturity works better for your company. Here are a few other suggestions for dealing with startups:

  • Any given technology has a competing status quo. In early meetings with a developer, ensure that you give proper assessment to the technology and the value it could bring to the table.
  • There are many reasons why a technology will not work, but start with why it could work. Assuming it indeed delivers on the promise. The next step is to quantify the short-term cost it incurs to replace the status quo and the long-term value it offers. This step alone cancels out many of the technologies that are “cool” but don’t really add value.
  • For technologies that compete with in-house initiatives, think of any “1+1=3” scenarios that could accelerate or augment internal development. In some cases, an emerging technology could supplant the internal initiative. This is not always a bad thing as it would free up your experts’ time to do something else.
  • Early in the process, identify any possible show stoppers that would preclude you from working with the startup and make sure they know your key concerns such as intellectual property requirements, data sharing, specific conflicts of interest, etc.
  • Keep an open mind about the presented value proposition since sometimes startups have the right technology but the wrong message. As the problem owner, educate them on how their technology could be applied to solve problems they may have not even thought about.

Next time an early stage startup approaches your company, give them guidance on what milestones they must achieve before they should come back. If maturity level is indeed the issue, make clear that you are not saying their technology does not work—it is just not developed enough for a field trial with your company.

All of this highlights that the relationship between startups and operators needs to be collaborative to accelerate technology uptake. The aim of course is to help both sides of the table win; an operator gets a new value-generating technology and the startup gains momentum.

*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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Latest NrgBuzz

Financial Review: 2019

Key findings

  • Brent crude oil daily average prices were $64.16 per barrel in 2019—11% lower than 2018 levels
  • The 102 companies analyzed in this study increased their combined liquids and natural gas production 2% from 2018 to 2019
  • Proved reserves additions in 2019 were about the same as the 2010–18 annual average
  • Finding plus lifting costs increased 13% from 2018 to 2019
  • Occidental Petroleum’s acquisition of Anadarko Petroleum contributed to the largest reserve acquisition costs incurred for the group of companies since 2016
  • Refiners’ earnings per barrel declined slightly from 2018 to 2019

See entire annual review

May, 26 2020
From Certain Doom To Cautious Optimism

A month ago, the world witnessed something never thought possible – negative oil prices. A perfect storm of events – the Covid-19 lockdowns, the resulting effect on demand, an ongoing oil supply glut, a worrying shortage of storage space and (crucially) the expiry of the NYMEX WTI benchmark contract for May, resulted in US crude oil prices falling as low as -US$37/b. Dragging other North American crude markers like Louisiana Light and Western Canadian Select along with it, the unique situation meant that crude sellers were paying buyers to take the crude off their hands before the May contract expired, or risk being stuck with crude and nowhere to store it. This was seen as an emblem of the dire circumstances the oil industry was in, and although prices did recover to a more normal US$10-15/b level after the benchmark contract switched over to June, there was immense worry that the situation would repeat itself.

Thankfully, it has not.

On May 19, trade in the NYMEX WTI contract for June delivery was retired and ticked over into a new benchmark for July delivery. Instead of a repeat of the meltdown, the WTI contract rose by US$1.53 to reach US$33.49/b, closing the gap with Brent that traded at US$35.75b. In the space of a month, US crude prices essentially swung up by US$70/b. What happened?

The first reason is that the market has learnt its lesson. The meltdown in April came because of an overleveraged market tempted by low crude oil prices in hope of selling those cargoes on later at a profit. That sort of strategic trading works fine in a normal situation, but against an abnormal situation of rapidly-shrinking storage space saw contract holders hold out until the last minute then frantically dumping their contracts to avoid having to take physical delivery. Bruised by this – and probably embarrassed as well – it seems the market has taken precautions to avoid a recurrence. Settling contracts early was one mechanism. Funds and institutions have also reduced their positions, diminishing the amount of contracts that need to be settled. The structural bottleneck that precipitated the crash was largely eliminated.

The second is that the US oil complex has adjusted itself quickly. Some 2 mmb/d of crude production has been (temporarily) idled, reducing supply. The gradual removal of lockdowns in some US states, despite medical advisories, has also recovered some demand. This week, crude draws in Cushing, Oklahoma rose for the second consecutive week, reaching a record figure of 5.6 million barrels. That increase in demand and the parallel easing of constrained storage space meant that last month’s panic was not repeated. The situation is also similar worldwide. With China now almost at full capacity again and lockdowns gradually removed in other parts of the world, the global crude marker Brent also rose to a 2-month high. The new OPEC+ supply deal seems to be working, especially with Saudi Arabia making an additional voluntary cut of 1 mmb/d. The oil world is now moving rapidly towards a new normal.

How long will this last? Assuming that the Covid-19 pandemic is contained by Q3 2020, then oil prices could conceivably return to their previous support level of US$50/b. That is a big assumption, however. The Covid-19 situation is still fragile, with major risks of additional waves. In China and South Korea, where the pandemic had largely been contained, recent detection of isolated new clusters prompted strict localised lockdowns. There is also worry that the US is jumping the gun in easing restrictions. In Russia and Brazil – countries where the advice to enforce strict lockdowns was ignored as early warning signs crept in – the number of cases and deaths is still rising rapidly. Brazil is a particular worry, as President Jair Bolosnaro is a Covid-19 skeptic and is still encouraging normal behaviour in spite of the accelerating health crisis there. On the flip side, crude output may not respond to the increase in demand as easily, as many clusters of Covid-19 outbreaks have been detected in key crude producing facilities worldwide. Despite this, some US shale producers have already restarted their rigs, spurred on by a need to service their high levels of debt. US pipeline giant Energy Transfer LP has already reported that many drillers in the Permian have resumed production, citing prices in the high-US$20/b level as sufficient to cover its costs.

The recovery is ongoing. But what is likely to happen is an erratic recovery, with intermittent bouts of mini-booms and mini-busts. Consultancy IHS Markit Energy Advisory envisions a choppy recovery with ‘stop-and-go rallies’ over 2020 – particularly in the winter flu season – heading towards a normalisation only in 2021. It predicts that the market will only recover to pre-Covid 19 levels in the second half of 2021, and a smooth path towards that only after a vaccine is developed and made available, which will be late 2020 at the earliest. The oil market has moved from certain doom to cautious optimism in the space of a month. But it will take far longer for the entire industry to regain its verve without any caveats.

Market Outlook:

  • Crude price trading range: Brent – US$33-37/b, WTI – US$30-33/b
  • Demand recovery has underpinned a rally in oil prices, on hopes that the worst of the demand destruction is over
  • Chinese oil demand is back to the 13 mmb/d level, almost on par year-on-year
  • News that development of potential Covid-19 vaccines are reaching testing phase also cheered the market
  • The US active oil and gas rig count lost another 35 rigs to 339, down 648 sites y-o-y


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May, 23 2020
EIA expects record liquid fuels inventory builds in early 2020, followed by draws

quarterly global liquid fuels productionand consumption balance

Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), May 2020

As mitigation efforts to contain the 2019 novel coronavirus disease (COVID-19) pandemic continue to lead to rapid declines in petroleum consumption around the world, the production of liquid fuels globally has changed more slowly, leading to record increases in the amount of crude oil and other petroleum liquids placed into storage in recent months. In its May Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) expects global inventory builds will be largest in the first half of 2020. EIA estimates that inventory builds rose at a rate of 6.6 million barrels per day (b/d) in the first quarter and will increase by 11.5 million b/d in the second quarter because of widespread travel limitations and sharp reductions in economic activity.

After the first half of 2020, EIA expects global liquid fuels consumption to increase, leading to inventory draws for at least six consecutive quarters and ultimately putting upward pressure on crude oil prices that are currently at their lowest levels in 20 years.

As with the March and April STEO, EIA’s forecast reductions in global oil demand arise from three main drivers: lower economic growth, less air travel, and other declines in demand not captured by these two categories, largely related to reductions in travel because of stay-at-home orders. Based on incoming economic data and updated assessments of lockdowns and stay-at-home orders across dozens of countries, EIA has further lowered its forecasts for global oil demand in 2020 in the May STEO. The STEO is based on macroeconomic projections by Oxford Economics (for countries other than the United States) and by IHS Markit (for the United States).

changes in quarterly global petroleum liquids consumption

Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), May 2020

In the May STEO, EIA forecasts global liquid fuels consumption will average 92.6 million b/d in 2020, down 8.1 million b/d from 2019. EIA forecasts both economic growth and global consumption of liquid fuels to increase in 2021 but remain lower than 2019 levels. Any lasting behavioral changes to patterns in transportation and other forms of oil consumption once COVID-19 mitigation efforts end, however, present considerable uncertainty to the increase in consumption of liquid fuels, even if gross domestic product (GDP) growth increases.

Members of the Organization of the Petroleum Exporting Countries (OPEC) and partner countries (OPEC+) agreed to new production cuts in early April that will remain in place throughout the STEO forecast period ending in 2021. EIA assumes OPEC members will mostly adhere to announced cuts during the first two months of the agreement (May and June) and that production compliance will relax later in the forecast period as stated production cuts are reduced and global oil demand begins growing.

EIA forecasts OPEC crude oil production will fall to less than 24.1 million b/d in June, a 6.3 million b/d decline from April, when OPEC production increased following an inconclusive meeting in March. If OPEC production declines to less than 24.1 million b/d, it would be the group’s lowest level of production since March 1995. The forecast for June OPEC production does not account for the additional voluntary cuts announced by Saudi Arabia’s Energy Ministry on May 11.

EIA expects OPEC production will begin increasing in July 2020 in response to rising global oil demand and prices. From that point, EIA expects a gradual increase in OPEC crude oil production through the remainder of the forecast and for production to rise to an average of 28.5 million b/d during the second half of 2021.

changes in quarterly global petroleum liquids production

Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), May 2020

EIA forecasts the supply of non-OPEC petroleum and other liquid fuels will decline by 2.4 million b/d in 2020 compared with 2019. The steep decline reflects lower forecast oil prices in the second quarter as well as the newly implemented production cuts from non-OPEC participants in the OPEC+ agreement. EIA expects the largest non-OPEC production declines in 2020 to occur in Russia, the United States, and Canada.

May, 20 2020