[Editor's note: This story is the second installment of a three-part outlook series which appears in the December 2018 edition of Oil and Gas Investor. Subscribe to the magazine here.]

People like to be in control, and certainly that’s the case with a producer group like OPEC. But it takes time to turn a proverbial battleship—or crude tanker—around. What if measures intended to balance the market, once implemented, exceed their goal? What if measures are so effective that they need to be reversed, shifting to slower production after earlier running with spigots wide open?

Such a scenario formed part of a conundrum facing the oil market two months ago, when supplies were tightening ahead of the Nov. 6 deadline for sanctions to go into effect against entities purchasing crude oil from Iran. Initially, prices ran higher, with West Texas Intermediate (WTI) and Brent prices settling at $76.41 per barrel (bbl) and $86.47/bbl, respectively, on Oct. 3.

Some 19 trading days later, the two benchmarks had shed just over 13% and 12%, respectively, settling at $66.18/bbl and $75.91/bbl. (Editor’s note: This is likely to update for what ends up being trough price.)

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Undoubtedly, the U.S. move to target minimal exports from Iran—following its withdrawal from the Iran nuclear deal—has created multiple issues.

Gulf producers, led by Saudi Arabia, plus Kuwait and the United Arab Emirates (UAE), have made up for a good portion of Iran’s loss of market share. In doing so, they have relied on “strategic ambiguity” in raising output levels at the expense of Iran and various OPEC producers that have fallen short of their production quotas. Chief among the latter, of course, is Venezuela and its collapsing economy.

The “Runner,” a Suezmax-class crude oil vessel, docks at the newly opened NuStar Oil Dock 15 at the Port of Corpus Christi. The POCC is positioning itself to be a leading exporter of burgeoning U.S. crude supply.

But still facing uncertainty of supply, senior executives at trading houses have raised the alarm about possible price spikes. A Trafigura Group executive, speaking at the Asia Pacific Petroleum Conference in late September, forecast Brent prices of $90/bbl by Christmas and $100/bbl in early 2019. A Mercuria Energy Group executive said it is “conceivable to see a price spike north of $100 per barrel.”

Saudi Arabia

Saudi Arabia oil minister Khalid A. Al-Falih has offered a less dramatic prediction for future crude oil supplies. “We are doing everything we can and then some,” he said, speaking at the Russian Energy Week forum in October in Moscow. “It’s not going to be popular for me to say this, but the market is well-supplied. Some would say oversupplied.”

It’s clear that much market uncertainty still surrounds the supply of crude oil in the wake of the U.S. withdrawal from the Iran nuclear deal.

For some, recent market tightness is likely to continue, in part due to market anticipation of new International Maritime Organization (IMO) regulations coming into effect in 2020. For others, it’s just a matter of time before rising supply outpaces demand, as crude demand growth is dented by trade tensions and tariffs, slowing GDP and currency effects of a strong dollar on emerging market demand.

But all parties point to the existence of geopolitical risks that may create outages in crude supplies. As one market observer noted, “global oil market shock absorbers are very thin right now.”

October Crude Market

Ed Morse, global head of commodity research at Citi, described the early October crude market as “finely balanced,” but had at hand a host of figures showing how lost supply from Iran and Venezuela is likely to be made up by Saudi Arabia, Kuwait, the UAE and a handful of non-OPEC producers. Notably, Russia is also playing a key role, as it has transitioned “from a price taker to price maker,” he said.

Under its base-case assumptions, Citi forecasts Brent prices to slide from $79/bbl in the fourth quarter of this year to $62 in the final quarter of 2019. The average for 2019 is about $69.75/bbl, as non-OPEC supply growth is expected to dampen prices through next year. Citi’s 2019 bull-and-bear cases reflect a wide range of outcomes: Brent and WTI averaging $85.75 and $53.25, respectively.

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For the near-term, investor attention is focused on the opposing dynamics of declining exports from Iran and Venezuela countered to some extent—no one knows for sure—by moves to stabilize the market by Saudi Arabia, in its traditional role, and other producers with excess capacity.

As of August, effective spare capacity—meaning barrels that can be brought on production quickly without incremental investment—stood at a little over 1 million barrels per day (MMbbl/d) worldwide, excluding Iran, according to Morse. This was comprised of 500,000 to 600,000 bbl/d of spare capacity in Saudi Arabia, roughly 250,000 bbl/d in Russia and much of the balance in Kuwait and the UAE.

Looking at Saudi Arabia alone, a decision to utilize its effective spare capacity would bring its production level up to about 11 MMbbl/d, said Morse. (Oil minister Al-Falih has moved in this direction, announcing an increase to 10.7 MMbbl/d.) Assuming investments to deploy rigs, build separation facilities, etc., a further 800,000 bbl/d of capacity could be added within 90 days or so, he said.

Neutral Zone Capacity

In addition, latent capacity exists in the so-called Neutral Zone, shared by Saudi Arabia and Kuwait. Plans call for reactivating production, shuttered from 2013 to 2014, involving both an offshore and onshore stage with 525,000 bbl/d of combined capacity. The initial, 250,000-bbl/d offshore stage is scheduled to be completed by the end of first-quarter 2019. The second stage is due for completion later this year.

(In October, Saudi Arabia and Kuwait had yet to reach agreement on final terms on the Neutral zone reactivation, according to S&P Global Platts.)

Saudi Arabia also has significant redundancy in its export system, according to Morse, with some 240 MMbbl in inventory. Even assuming some days when exports peak at over 12 MMbbl/d, but average closer to 7.5 MMbbl/d, its inventory represents well over 20 days of cover, he noted. Exports could rise by 500,000 bbl/d for 200 days, and the drawdown would still leave 140 MMbbl in inventory.

Addressing the issue of lost Iranian exports—and the ability of Saudi Arabia and other producers to plug the gap—Morse noted that Iranian exports in the first half of this year averaged about 2.2 MMbbl/d. By August, Iran’s exports had fallen to 1.5 MMbbl/d, a decline of 700,000 bbl/d, and tanker tracking firms estimated exports were down to 1.2 MMbbl/d, a drop of 1 MMbbl/d, by early October, he said.

“The market has already absorbed a good 1-million-barrels-per- day drop in its production,” Morse commented. “The issues in the market relate to how much China and India will import, how much southern European countries might import and how many barrels might be smuggled one way or another, or be disguised in other countries’ exports.”

China’s Continued Appetite

Among importers of Iranian oil, China is likely to continue importing “at least 500,000 to 550,000 bbl/d,” said Morse. India could still import 200,000 bbl/d and southern Europe maybe 100,000 bbl/d, he estimated. “The likely highest figure for smuggling—either by turning off transponders so tankers can’t be tracked, or by smuggling through Iraq—would be around 200,000 bbl/d.”

If correct, by Nov. 4, the date for sanctions to be imposed, the numbers estimated above would leave Iran with exports totaling somewhat less than 1 MMbbl/d, or about 300,000 bbl/d below the 1.2 MMbbl/d of exports being shipped in early October, according to Morse.

Away from the Iran sanctions, there is plenty of risk of unrest flaring up in other OPEC countries. For example, Libya—producing over 1 MMbbl/d as of press time—is capable of losing 500,000 to 700,000 bbl/d at “any given moment,” said Morse. Libya is due to hold elections this winter, as is Nigeria in February. On average, loss of production during a Nigerian election has been “on the order of 500,000 bbl/d.”

In Venezuela, in addition to a lack of investment and spare parts, the number of rigs working is “too few to be capable of keeping production at current levels. The only question about Venezuela is how rapid the decline will continue to be,” said Morse. An early October report by the International Energy Agency indicated another 300,000 bbl/d was at risk through the end of this year, he noted.

Coupled with potential risks to output in Iraq, if geopolitical risks disrupted production all at once in the above countries—a theoretical “simultaneous accidental disruption”—the combined impact would come to “about a 2 MMbbl/d hit,” including lost Iranian supplies, said Morse. A further 1 MMbbl/d loss of this kind, while unlikely, would drive Brent prices “over $90/bbl for all the fourth quarter,” he predicted.

Russia Now A ‘Price Maker’

Amidst this reduced certainty of supply, Russia has been able to exercise greater influence in the Middle East, with “ambitions, led by the head of state, to be a market maker in the oil market,” commented Morse. Prior to 2017, Russia was mainly a “European player, not a global player” in oil, he recalled. Now it has transitioned “from a price taker to a price maker.”

Morse attributed the more expansionary stance of Russia to two main factors. One was a change in the Russian tax system, which encouraged more investment in production growth. The other was a 50% depreciation of the ruble, coupled with an ascendant U.S. dollar, which meant dollar-based oil revenues were increasing, while ruble-denominated cost of investments in Russia were decreasing.

The result, according to Morse, was Russian energy companies “engaged in a record level of drilling activities that created a record level of discoveries.” Moreover, the industry’s support from currency moves has in large part not reversed. Even as oil prices have risen, the once tight correlation between the ruble and oil prices has weakened due to U.S. sanctions, which have held the ruble down.

Russia’s production has recently been running at 400,000 bbl/d over year-ago levels, and the industry is said to have a further 250,000 bbl/d of spare capacity, even after the recent expansion, according to Morse. Further significant additions to capacity are also on the way. As much as 1.1 MMbbl/d of new production is set to come online, generally by 2022, according to Citi forecasts.

Russian Inventory Of Discoveries

Importantly, the capacity growth projected by Citi comes from greenfield projects and not idled older fields. Some 700,000 bbl/d is from new fields already launched, but still ramping up. Another 350,000 bbl/d or so is from fields currently under development but yet to be turned on. “We think they have a big enough inventory of discoveries to add 300,000 bbl/d per year for the next four years,” said Morse.

As for the Americas, Morse forecast U.S. production growth of around 1.2 MMbbl/d, with potentially another 200,000 bbl/d of NGL output, destined for the export pool. Brazil and Canada are expected to add another 500,000 bbl/d of production. “With a couple of years of this supply growth,” he said, “It’s likely to cover our projected global demand growth and any supply disruptions.”

“Every quarter that we look at, the U.S. is going to be producing a good 300,000 bbl/d more than the quarter before,” he continued. “We think all incremental U.S. crude growth goes into the export pool, and that helps keep global markets either well-balanced or oversupplied in the long run. We project U.S. crude production growth of 1 MMbbl/d or more for at least the next seven years.”

High Prices Measured In Months

For Morse, this supply outlook argues in favor of any price spikes lasting in terms of months, not years.

“Any event that gives rise to a high price is not likely to last very long,” he said. “I put at most two years on it rather than four, and it’s more likely to be six to nine months rather than even two years. That’s where the question comes in as to whether we have disruptions in Venezuela, Libya and Nigeria, Iraq and Iran at the same time.”

Barclays’ 2019 outlook is “for a continued downward trend in prices, based on a view that Brent shouldn’t have been as high as it was—in the low $80s—at the beginning of October,” according to Michael Cohen, the firm’s head of energy markets research. For 2019, Barclays’ base case calls for Brent and WTI to average $72/bbl and $65/bbl, respectively.

“As we move lower, we believe there is still fundamental justification for a $70 to $80/bbl range for Brent,” he said. “It’s just that the bias continues to be skewed to the upside, given the extent of the geopolitical outages that could emerge, as well as the impending International Maritime Organization 2020 regulations [IMO 2020] that come into play at the end of 2019.”

Recent market conditions have been particularly hazardous to interpret, since defining what constitutes a balanced market lies largely “in the eye of the beholder,” observed Cohen.

“More than I can ever remember, it’s a completely subjective judgment call as to what is the market balance,” he said. “It’s a judgment call as to what level of production the Saudis need to supply the market. It’s a judgment call about how strictly sanctions are implemented. It’s a judgment call by the Trump administration as to whether the market price is too high.”

Too Many Cooks

Accordingly, an old analogy, “too many cooks spoil the broth,” may be applicable to the current mix of oil policy. “All those entities—whether it’s the Saudis, the U.S. State Department or the While House, or the OPEC Secretariat—they’re all going to have their own view as to how much supply needs to be added to the market,” he said. “With so many cooks in the oil price kitchen, the broth is bound to spoil.”

As regards U.S. sanctions on Iranian oil, “the policy to reduce Iran’s revenues doesn’t work if prices stay high,” said Cohen. “The best way for U.S. policymakers to reduce Iranian export revenues is to allow prices to fall to $70 to $80, and let Iran export about 1.4 MMbbl/d, slightly below current [October] levels.”

Although Barclays can see Iranian exports possibly falling as low as 1 MMbbl/d, “we don’t think it will be sustained at that level,” said Cohen. “The Russians are going to help them, in my view, and the Chinese are going to keep their purchases stable, at least for now. Turkey is going to continue to take oil, and the state-owned Indian refineries are going to keep taking their oil.”

While supply issues may arise from disruptions in Iran, Venezuela, Nigeria, Libya, etc., the demand size of the oil equation may get a lift in the latter part of next year as markets anticipate the IMO 2020 regulations coming into force. Although not its base case, Barclays sees the global demand growth likely spiking to 1.8 MMbbl/d in 2020, up from growth of 1.4 MMbbl/d in 2019.

Refineries At High Rates

Given increased demand anticipated for middle distillates due to IMO 2020 regulations, “the second half of 2019 is going to be characterized by possible increased refinery purchasing of a variety of crude grades,” said Cohen. “Refineries are generally likely to be running at quite high-capacity utilization rates, and that could create an upside price spike as well.”

“The IMO 2020 regulatory change is a much bigger deal for the global oil market than most people understand,” said Marshall Adkins, director of energy research at Raymond James & Associates. “Our oil model is meaningfully more bullish today than it was a year ago, because of our understanding of IMO 2020 as well as the effect of the sanctions on Iranian oil.”

Coming into 2018, Raymond James held one of the most bullish stances on oil, projecting an average WTI price of $65/bbl. For 2019, the firm recently raised its forecasts for both WTI and Brent by $10/bbl to $77.50/bbl and $90/bbl, respectively. Citing the impact of IMO 2020, its projections call for 2020 to be a “cyclical peak year,” with prices moving higher to $92.50/bbl and $100/bbl.

Starting Jan. 1, 2020, the new IMO 2020 regulation will come into effect, lowering the “open water” sulfur cap on marine fuels to below 0.5% vs. the prior 3.5%. Coming hard on the heels of the Iranian oil sanctions, the rule outlawing the use of high sulfur bunker fuel will “make some portion of the 4 MMbbl/d ‘bottom of the barrel’ oil supply essentially useless,” according to Raymond James.

Identifying how much of the 4 MMbbl/d bunker fuel may survive or be converted to new uses offers a mean of backing into how much new oil supply will be needed as a replacement. Of the 4 MMbbl/d, Adkins estimated 500,000 to 1 MMbbl/d could survive by ships installing scrubbers, 500,000 to 1 MMbbl/d could be upgraded with cokers and 500,000 to 1 MMbbl/d could survive via cheating. Aggregating these, this leaves 1- to 2.5 MMbbl/d of outlawed high sulfur marine fuel having to be replaced.

Possible Supply Loss

“IMO 2020 could result in the loss of 1 to 2 MMbbl/d of supply that we’re currently consuming that will not be usable oil in 13 months. That’s a big deal,” said Adkins. In its place, shipping companies will have to switch to a higher-quality refined product, typically a middle distillate. The net result: a drop in crude supply as high sulfur bunker fuel is deemed unusable, and a jump in middle distillate demand.

While still somewhat below the radar, the IMO 2020 issue “is shaping up to be a true game-changer for oil prices,” said Raymond James in raising its crude price forecasts in late October.

“Simply put, there is not enough available supply to compensate fully for the loss of 1.5 MMbbl/d from the market. Our $100-Brent cyclical peak forecast for 2020 represents a price that is high enough to begin seriously reducing global demand, a necessary step in balancing the market.”

From a refinery perspective, the global middle distillate market is estimated to be about 35 MMbbl/d. This means that a 2 MMbbl/d jump in middle distillate consumption would represent a 7% increase in global market demand in 2020. Refineries are expected to price at wider discounts the heavier, sour crudes (Canadian heavy grades and some OPEC crudes) relative to light, sweet crudes (WTI, Brent).

In Russia, where the frequently used Urals feedstock has a 1.35% sulfur component, “people are likely to be also underestimating the impact of IMO 2020 on the refining sector,” according to Adkins. Russian refineries have historically processed much of the Urals crude into high sulfur bunker fuel, and thus they have not invested in equipment (cokers or hydrotreaters) to produce light or low sulfur distillates.

Urals Discount To Widen

As refineries worldwide increasingly favor lower sulfur crudes for their feedstock, “demand for Urals can be expected to diminish, resulting in a deeper discount vs. Brent,” according to a September Raymond James report examining Russia. “All else being equal, this means reduced price realizations—and thus reduced cash flow—for Rosneft as well as the smaller Russian producers.”

In terms of Russian producers accelerating the pace of production, Adkins expected to see an increase of 300,000 bbl/d by the end of this year, with growth then returning to historical trend lines. Increasing demands from the Russian treasury, in the form of mandatory dividends, could pose a challenge in terms of generating cash flow to reinvest in drilling activity, he noted.

Expressing confidence on the commodity outlook for the coming year, Adkins said he gave odds of “better than 50% that we trade above $90 Brent for a period in 2019.” Depending on the nature of a catalyst, likely resulting from a potential interruption of production, such a price spike could “translate into a sustained price above $90, and be above there for a while,” he predicted.

Chris Sheehan can be reached at csheehan@hartenergy.com.

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