I used to be a pure red blooded driller. Red, the colour of fire and blood, associated with energy, war, danger, strength, power, determination as well as passion, desire, and love. And all of that hot emotions was for my passion to drill. I did not care about anything else other than well length, cost, time, and how great I was at selecting the right tool, using it and of course telling people about my accomplishments. And in Feb 2004, I reached the very pinnacle of being a drilling engineer. I drilled, single handedly (that shall go in my future memoirs), the longest well in Malaysia. At 6313mMD, I, the lead drilling engineer, held the Malaysian record for longest well ever drilled.
Unfortunately that intense self admiration and jubilation was short lived, when in a few weeks that record was broken by another operator. My ego deflated, my self worth diminishing by every mention of the other well's length, I banged my forehead whenever I thought of them who beat my record by a measly 50m. And of course, being a red blooded driller, the only lesson I learned was to just to drill longer next time. If I ever drilled another record breaking well, I will make sure I just put in some contingency shale drilling of about ~60m, so that I never get beaten again -_-
Sadly, I have never had a chance again, because since 2004, there have only been a handful of ultra ERD wells drilled. To put this into perspective, the longest well currently in Malaysia was drilled in 2014 to ~6700m, which is a laudable achievement, but exemplifies a slow progression over 10 years. As a driller, I feel that it is my responsibility to revive the interest in ERD and invigorate the passion for world class records which has since waned in the Malay Basin.
But now I've since gone to the Dark Side (Star Wars trademark), the side that bleeds hydrocarbon, I realise that my previous infatuation with drilling KPIs just seems so irrelevant in the grand scheme of things, when the oil business bottom line are production and profits, and doesn't really give a hoot on how long a well is. To stay profitable, and as reserves become even smaller and difficult to access, it has becomes an ever-more important to focus on looking at several concepts with enabling techniques, to be able to select the right solution to exploit hydrocarbons. As a driller, nothing is sexier and more elegant than suggesting extended reach drilling. While its the most straightforward option which allows the ability to explore and produce further and deeper, and minimise facilities installation, it does come with added risk and possibility of failure.
Any solution proposed requires capital expenditure. And capital expenditure proposals must be sufficiently specific to permit their technical and commercial justification, with sufficient risk assessment, for exploration and production operations, not just for the immediate fiscal year, but the life of the production sharing contract or field. In the economic phase of evaluation, oil management may find that it has more investment opportunities than capital to invest, or more capital to invest than investment opportunities. Whichever situation exists, oil management needs to resort to some economic criteria for selecting or rejecting investment proposals. Management’s decision in either case is likely to be based largely on the measures of financial return on the investment. In the current depressed oil price climate, how do we make extended reach drilling a viable option?
I won’t pretend that I’m an expert at economics like Wally in the Dilbert strip above, but let’s try to simplify the concept for the purpose of this article. Lets just say, all of the KPIs of a well, production, cost, schedule, IRR, ROI, terms of PSC, can all be rolled into a variable limit, the economic threshold of the project.
This chart represents the likelihood of costs in a normal Monte Carlo S-curve spread, where the cost of a project is typically quoted as the P50, with a range given for sensitivities. In layman's terms, the mid case is the P50 (50% chance having costs below that threshold) and P10 and P90 is the low and high side respectively. The range of costs are given so that the project can be carefully evaluated against the returns for any given scenario.
However, most projects focus on the most straightforward approach, which is trying to reduce base cost ('What we plan for' curve), in an attempt to get closer to the low side, and hope that nothing goes wrong to upset the cart and skew to the upside. To shift the whole S-curve downwards, the team will negotiate contracts, purchase cheaper tangibles/consumables, reduce the technology, and try to get the work done with a lean operation. However, as we lower down our price point, we will inevitably be introducing creep, compromising quality and safety. Post experiencing a trainwreck, the looming result is cost inadvertently passing the economic threshold ('What will actually happen' curve).
A prudent project manager should try to visualise, manage and contain all of the outcomes, trying to put a cap on the risk and exposure of the upside, while making the likelihood of meeting the P50 expectation more likely, even if it means increasing the mid-case, and forgoing a more aggressive P10 ('What we actually need' Green curve). To put it simply, don't lose the farm while trying to save every single dollar.
If you are planning to justify a new technology, a new technique, or a risky proposition such as extended reach drilling, there are 5 key elements that you need in your proposal, to emulate the 'What we actually need' green curve:
Key 1: Collaborate and Build the knowledge of your team: Collaborate as much as possible internally, and externally with partners, host government, increase data trade transactions, and engage professional networks in order to learn as much as you can on the venture you are undertaking. In this environment, you will be pleasantly surprised that others might actually be interested to learn from you to. In my previous life, I was part of an assurance team, called upon by our partner in Western Australia to look at their concept work. They were down to two options, where they were weighing a 10km ERD well versus a subsea development, where the costs of subsea were 50% higher. The upside costs presented by the drilling team for the ERD looked reasonable, with their P90 costs about a wash with the subsea well. So on paper, ERD looked to be the right selection. However, the Drilling Manager confessed that despite the economics and his attempt to show the risks, he believes that his team does not have the capability to carry out the work, in other words the drillability due to the capability was questionable. The ERD well was dropped in favor of the subsea well, and everybody agreed that was the right call, because regardless what the evaluation on paper shows, there was no confidence in the team that was to carry the work out. Pity.
Key 2: Cap your upside costs: Gone are the days when people say, "A well is going to cost what its going to cost". Have savvier contracts, such as with lump sum capped, performance incentivised, meterage measured or even turnkeyed contract. We should no longer be dependent on time based contracts, just because the supplier says so. Determine the cost structure which fits your project and design your contracts to meet what is required
Key 3: Increase your execution reliability: This doesn't mean not having problems. What it means is being able to deliver what you promised. So if the design is complex, and on average non productive time is high, design the lower complexity aspects of the project to absorb the possible problems that you will eventually have. Sometimes you have to accept that your planned costs would have to be higher to increase reliability. Justify the increase and plan for success, but be ready for failure.
Key 4: Have contingency plans for everything, even failure of your base plan: It goes without saying that risk assessments are the support system for a project, but without closing out and implementing any of the mitigation plans, the risk assessment are just a waste of time. An always think of what would happen if the primary plan fails? Do you have a fall back plan to still retain value or limit exposure? An alternative target, perhaps? A ready for deployment sidetrack assembly?
Key 5: Increase the value statement of your design: During detailed design, a D&C team often gets carried away on focusing too much on 'getting the job' done versus remembering why the job was done in the first place. Reaching an objective is just the means to extract the value from the project. Design the well in order to increase the returns on the project, and increase the economic threshold. Drill better wells, which doesn't necessarily mean drilling longer or more wells.
Hopefully the keys above will assist the reader in creating more palatable ERD proposals. Every single project, every single team, and every single company will have a different approach in creating value, but I do hope that maybe in some minute way, I managed to jog some life back into excitement about drilling and ERD in Malaysia. Stay savvy, people.
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Throughout much of its history, the United States has imported more petroleum (which includes crude oil, refined petroleum products, and other liquids) than it has exported. That status changed in 2020. The U.S. Energy Information Administration’s (EIA) February 2021 Short-Term Energy Outlook (STEO) estimates that 2020 marked the first year that the United States exported more petroleum than it imported on an annual basis. However, largely because of declines in domestic crude oil production and corresponding increases in crude oil imports, EIA expects the United States to return to being a net petroleum importer on an annual basis in both 2021 and 2022.
EIA expects that increasing crude oil imports will drive the growth in net petroleum imports in 2021 and 2022 and more than offset changes in refined product net trade. EIA forecasts that net imports of crude oil will increase from its 2020 average of 2.7 million barrels per day (b/d) to 3.7 million b/d in 2021 and 4.4 million b/d in 2022.
Compared with crude oil trade, net exports of refined petroleum products did not change as much during 2020. On an annual average basis, U.S. net petroleum product exports—distillate fuel oil, hydrocarbon gas liquids, and motor gasoline, among others—averaged 3.2 million b/d in 2019 and 3.4 million b/d in 2020. EIA forecasts that net petroleum product exports will average 3.5 million b/d in 2021 and 3.9 million b/d in 2022 as global demand for petroleum products continues to increase from its recent low point in the first half of 2020.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), February 2021
EIA expects that the United States will import more crude oil to fill the widening gap between refinery inputs of crude oil and domestic crude oil production in 2021 and 2022. U.S. crude oil production declined by an estimated 0.9 million b/d (8%) to 11.3 million b/d in 2020 because of well curtailment and a drop in drilling activity related to low crude oil prices.
EIA expects the rising price of crude oil, which started in the fourth quarter of 2020, will contribute to more U.S. crude oil production later this year. EIA forecasts monthly domestic crude oil production will reach 11.3 million b/d by the end of 2021 and 11.9 million b/d by the end of 2022. These values are increases from the most recent monthly average of 11.1 million b/d in November 2020 (based on data in EIA’s Petroleum Supply Monthly) but still lower than the previous peak of 12.9 million b/d in November 2019.
In the past week, crude oil prices have surged to levels last seen over a year ago. The global Brent benchmark hit US$63/b, while its American counterpart WTI crested over the US$60/b mark. The more optimistic in the market see these gains as a start of a commodity supercycle stemming from market forces pent-up over the long Covid-19 pandemic. The more cynical see it as a short-term spike from a perfect winter storm and constrained supply. So, which is it?
To get to that point, let’s examine how crude oil prices have evolved since the start of the year. On the consumption side, the market is vacillating between hopeful recovery and jittery reactions as Covid-19 outbreaks and vaccinations lent a start-stop rhythm to consumption trends. Yes, vaccination programmes were developed at lightning speed; and even plenty of bureaucratic hiccoughs have not hampered a steady rollout across the globe. In the UK, more than 20% of adults have received at least one dose of the vaccines, with the USA not too far behind. Israel has vaccinated more than 75% of its population, and most countries should be well into their own programmes by the end of March. That acceleration of vaccinations has underpinned expectations of higher oil demand, with hopes that people will begin to drive again, fly again and buy again. But those hopes have been occasionally interrupted by new Covid-19 clusters detected and, more worryingly, new mutations of the virus.
Against this hopeful demand picture, supply has been managed. Squabbling among the OPEC+ club has prevented a more aggressive approach to managing supply than kingpin Saudi Arabia would like, but OPEC+ has still managed to hold itself together to placate the market that crude spigots will remain restrained. And while the UAE has successfully shifted OPEC+ quota plan for 2021 from quarterly adjustments to monthly, Saudi Arabia stepped into the vacuum to stamp its authority with a voluntary 1 million barrels per day cut. The market was impressed.
That combination of events over January was enough to move Brent prices from the low US$50/b level to the upper US$50/b range. However, US$60/b remained seemingly out of reach. It took a heavy dusting of snow across Texas to achieve that.
Winter weather across the northern hemisphere seemed harsher than usual this year. Europe was hit by two large continent-wide storms, while the American Northeast and Pacific Northwest were buffeted with quite a few snowstorms. Temperatures in East Asia were fairly cold too, which led to strong prices for natural gas and LNG to keep the population warm. But it was a major snowstorm that swept through the southern United States – including Texas – that had the largest effect on prices. Some areas of Texas saw temperatures as low as -18 degrees Celsius, while electricity demand surged to the point where grids failed, leaving 4.3 million people without power. A national emergency was declared, with over 150 million Americans under winter storm warning conditions.
For the global oil complex, the effects of the storm were also direct. Some of the largest oil refineries in the world were forced to shut down due to the Arctic conditions, further disrupting power and fuel supplies. All in all, over 3 mmb/d of oil processing capacity had to be idled in the wake of the storm, including Motiva’s Port Arthur, ExxonMobil’s Baytown and Marathon’s Galveston Bay refineries. And even if the sites were still running, they would have to contend to upstream disruptions: estimates suggest that crude oil production in the prolific Permian Basin dropped by over a million barrels per day due to power outages, while several key pipelines connecting Cushing, Oklahoma to the Texas Gulf Coast were also forced to shutter.
That perfect storm was enough to send crude prices above the US$60/b level. But will it last? The damage from the Texan snowstorm has already begun to abate, and even then crude prices did not seem to have the appetite to push higher than US$63/b for Brent and US$60/b for WTI.
Instead, the key development that should determine the future range for crude prices going into the second quarter of 2021 will be in early March, when the OPEC+ club meets once again to decide the level of its supply quotas for April and perhaps beyond. The conundrum facing the various factions within the club is this: at US$60/b, crude oil prices are not low enough to scare all members in voting for unanimous stricter quotas and also not high enough to rescind controlled supply. Instead, prices are at a fragile level where arguments can be made both ways. Russia is already claiming that global oil markets are ‘balanced’, while Saudi Arabia is emphasising the need for caution in public messaging ahead of the meeting. Saudi Arabia’s voluntary supply cut will also expire in March, setting up the stage for yet another fractious meeting. If a snow overrun Texans was a perfect storm to push crude prices to a 13-month high, then the upcoming OPEC+ meeting faces another perfect storm that could negate confidence. Which will it be? The answer lies on the other side of the storm.
Much like the year itself, the final quarter of 2020 proved to be full of shocks and surprises… at least in terms of financial results from oil and gas giants. With crude oil prices recovering on the back of a concerted effort by OPEC+ to keep a lid on supply, even at the detriment of their market share, the fourth quarter of 2020 was supposed to be smooth sailing. The tailwind of stronger crude and commodity prices, alongside gradual demand recovery, was expected to have smoothen out the revenue and profit curves for the supermajors.
That didn’t happen.
Instead, losses were declared where they were not expected. And where profits were to be had, they were meagre in volume. And crucially, a deeper dive into the financial results revealed worrying trends in the cash flow of several supermajors, calling into question the ability of these giants to continue on their capital expenditure and dividend plans, and the risks of resorting to debt financing in order to appease investors and yet also continue expanding.
Let’s start with the least surprising result of all. For months, ExxonMobil had been signalling that it would be taking a massive writedown on its upstream assets in Q4 2020, which could lead to a net loss for the quarter and the year. Unlike its peers, ExxonMobil had resisted making writedowns on the value of its crude-producing assets earlier in 2020. At the time, it stated that it had already built caution in the value assessments of those assets, reflecting ‘fair value’; not so long after that bold statement, ExxonMobil has been forced to backtrack and make a US$20.2 billion downward adjustment. Unusually, that meant that non-cash impairments aside, ExxonMobil actually eked out a tiny profit of US$110 million for the quarter on the strength of margins in the chemicals segment, but a full year loss of US$22.4 billion: the first ever annual loss since Exxon and Mobil merged in 1998. This was better than expected by Wall Street analysts, who would also be cheering the formation of ExxonMobil Low Carbon Solutions, in which the group would pump some US$3 billion through 2025 to reduce its greenhouse gas emissions by 20% from 2016 levels. That acknowledgement of a carbon neutral future is still far less ambitious than its European counterparts, but is a clear sign that ExxonMobil is starting to take the climate change element of its business more seriously.
If ExxonMobil managed to surprise in a good way, then its closest American rival did the opposite. Chevron had been outperforming ExxonMobil in quarterly results for a while now, but in Q4 2020 retreated with a net loss of US$665 million. That was narrower than the US$6.6 billion loss declared in Q4 2019, but still a shock since analysts were expecting a narrow profit. Calling 2020 ‘a year like no other’, the headwinds facing Chevron in Q4 2020 were the same facing all majors and supermajors, despite gains in crude prices, refining margins and fuel sales were still soft. Chevron’s cash flow was also a concern – as was ExxonMobil’s – which prompted chatter that the two direct descendants of JD Rockefeller’s Standard Oil were considering a merger. If so, then there is at least alignment on the climate topic: Chevron is also following the trail blazed by European supermajors in embracing a carbon neutral future, with CEO Michael Wirth conceding that Chevron may ‘not be an oil-first company in 2040’.
On the European side of the pond, that same theme of lowered downstream performance dragging down overall performance continued. But unlike the US supermajors, the likes of Shell, BP and Total were somewhat insulated from the Covid-19 blows at the peak of the pandemic as their opportunistic trading divisions capitalised on the wild swings in crude and fuel prices. That factor is now absent, with crude prices taking on a steady upward curve. That’s good for the rest of their businesses, but bad for trading, which thrives on uncertainty and volatility. And so BP reported a Q4 net profit of US$115 million, Shell followed with a Q4 net profit of US$393 million and Total closed out the earning season with industry-beating Q4 net profit of US$1.3 billion, above market expectations.
The softness of the financials hasn’t stopped dividend payouts, but has also been used by Europe’s Big Oil to set the tone for the next few decades of their existence. Total and BP paid a hefty premium to secure rights to build the next generation of UK wind farms; Total joined the Maersk-McKinney Moller Center for Zero Carbon Shipping to develop carbon neutral shipping solutions and splashed out on acquiring 2.2 GW of solar power projects in Texas; BP signed a strategic collaboration agreement with Russia’s Rosneft to develop new low carbon solutions; and aircraft carrier KLM took off with the first flight powered by synthetic kerosene that was developed by Shell through carbon dioxide, water and renewables. That’s a lot of a groundwork laid for the future where these giants can be carbon neutral by 2050.
The message from Q4 seems clear. Big Oil has barely begun its recovery from the Covid-19 maelstrom, and the road to a new normal remains long and painful. But this is also an opportunity to pivot; to set a new destination that is no longer business-as-usual, but embraces zero carbon ambitions. Even the American supermajors are slowly coming around, while the European continues to lead. Will majors in Asia, Latin America and Africa/Middle East follow? Let’s see what that attitude will bring over this new decade.
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