Outlook America

Editor’s Note: An industry that has seen its fair share of times of trial and tribulation is coming off what by any and all measures may have been the most trying time of all. But this has never been a business for the faint of heart. Untamed cyclicality is the nature of the oil and gas beast, and in 2020 it was unleashed by an extraordinary set of circumstances.

Operators were pressed into retreating and retrenching. But to borrow from an old adage about warfare, while there is no shame in a tactical retreat, there is no victory in it either. The industry enters 2021 hungry for even small victories and hoping for a big swing in market fundamentals. To what degree will pent-up economic activity spur recovery in domestic and global markets? Are crude prices poised to bounce higher? Has a new era already begun to dawn for U.S. natural gas? And might the twin impacts of demand recovery and production depletion transform oil and gas inventory surpluses into shortages in the months ahead?

Since shifting oil and gas supply and demand fundamentals will dictate U.S. producers’ ability to call rigs and frac crews back into action, AOGR presented a series of questions to J. Marshall Adkins, Raymond James & Associates Inc., and Andrew D. Weissman, EBW Analytics Group LLC.

Questions are in italics, followed by the market experts’ responses. The editors acknowledge Eli Rubin, research director at EBW Analytics, for his contributions to the discussion on natural gas markets.

Jump to: U.S. Natural Gas Market -- MAJOR PRICE UPSURGE AHEAD?

Q: Let’s start with the mile high view and break the fundamentals down from there. You suggest the outlook for oil is much more bullish than the NYMEX strip indicates. Recognizing there are a lot of moving parts, please summarize the main tenants behind your thesis. How do you see the macro supply/demand balance shaping up as the year progresses?

J. MARSHALL ADKINS: It’s actually simple. Forward oil supply/demand fundamentals are very strong, given the effects of extremely low oil prices in 2020. Point one is that the U.S. oil and gas industry is nine months into the sharpest and deepest activity decline ever experienced. The amount of damage inflicted over the past year does not come without consequences.

We clearly are seeing U.S. production fall off hard as a result of taking activity levels from 800 active rigs at the beginning of 2020 to below 250 at the low point in late summer. The lack of spending–mostly in U.S. shale plays, but also internationally–means lower global oil supplies in 2021. If oil prices were to stay below $50/bbl, U.S. oil production would drift lower. Simply put, production is not sustainable at WTI strip prices in the mid- to upper $40s.

Point two is that the impetus for the pullback in activity was massive demand destruction. But the demand destruction was not as bad as predicted. While global oil demand was still hammered by coronavirus shutdowns and travel restrictions, it is important to note that oil demand has recovered sharply off the lows seen last April. More importantly, the broader markets are telling us that the global economy is going to come roaring back once vaccines are widely distributed, leading to a strong rebound in global oil demand as we go through 2021.

Finally, the combination of recovering demand and lower available supply has already led to an undersupplied oil market and sharply falling global oil inventories. Our models show global oil inventories crossing the historical “normal” level to the below-normal range by mid-2021. The bottom line is that all these factors–constrained supply, recovering demand and falling inventories–should drive prices sharply higher over the next 18 months, perhaps doubling current strip prices.

I think we are going to get to the point where, even with OPEC+ producing all out, the world will be short of crude oil by the back half of 2021.

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Q: Speaking of OPEC+, in January, the group began adding incremental production. But Saudi Arabia announced a surprise cut to its production. How do you foresee OPEC+’s strategy to manage supply evolving as demand recovers?

ADKINS: Relative to its output at the beginning of 2020, OPEC+ is currently producing about 3.5 MMbbl/d less oil per day. Of that 3.5 MMbbl/d total, nearly 3 MMbbl/d is split evenly between Saudi Arabia and Russia. Pretty much everyone else accounts for the other 0.5-1.0 MMbbl/d. Going forward, the key question is, “What are the Saudis and Russians going to do?”

It’s nice to have other nations contribute; it certainly was crucial initially when OPEC+ reduced production by 7.5 MMbbl/d last May/June. The reality is, Saudi Arabia and Russia are the ones who have done the managing of global supply, and so far, they are on the same page regarding managing supply to drive higher short-term oil prices.

Holding around 3.5 MMbbl/d off the market is extraordinarily helpful to rebalancing the supply/demand equation. I think they are going to continue to act deliberately to tighten inventories as long as oil prices are not well above $50/bbl. However, I suspect that as the demand recovery starts to manifest this year, Saudi Arabia, Russia and every other OPEC+ member will be forced to increase production well above their stated goals. My math suggests the world will need that OPEC+ oil in the back half of 2021 to avoid a severe shortage of crude.

In fact, by the end of the year, our models indicate the market is going to be calling on every bit of the volumes OPEC+ was producing at the start of 2020, and then some. Specifically, I think that by year-end 2021 every OPEC+ member will need to produce all out everything it can, with the exception of Iran and Venezuela, which are stymied by other issues.

In the situation we foresee, OPEC+ will be irrelevant by the end of next year. Why? The impetus of the unusual cooperation among producing countries was historically low oil prices. It was borne out of necessity. For the next few years, I think OPEC+ will be irrelevant because production quotas are irrelevant in a market short on supply. When all the members are producing all out, there is no need to cooperate on quotas.

There is one caveat: If the Biden administration elects to allow Iranian supplies to come back into the market, then Saudi Arabia will still need to hold off maybe 1 MMbbl/d from producing at maximum capacity.

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Q: Before we look at where demand may be headed, let’s take a look at where it’s been. How much actual year-over-year demand was lost during the depths of the COVID-19 lockdowns? What does the demand picture look like as 2021 begins?

ADKINS: In March, most people thought we would see a 30% reduction in global oil demand in the April-May time frame as all the lockdowns went into place around the world. However, if you look at the actual global oil inventory numbers during that timeframe, demand destruction at the peak in April 2020 was not nearly as bad as feared. The best I can tell, the destruction actually was about half of that 30% expectation.

That said, a demand loss of 15%-16% is still really ugly. It is very rare to see a decline of even a few percentage points, but a double-digit decline was unprecedented. So, while there was still significant demand destruction, it was not as ugly as everyone thought it would be. More importantly, the April demand destruction was not nearly as bad as most analysts are still assuming in their models.

Moreover, the recovery off of that lower bottom has been extremely robust. By the start of December, demand had recovered from being down from 15+ MMbbl/d at the low point last spring to down less than 5 MMbbl/d. That’s a pretty stout rebound.

Even though demand has improved significantly from April lows, there will be some element of permanent demand destruction that precipitated from the coronavirus pandemic related to work-from-home, international business travel, etc. Specifically, I am assuming a few percentage point reset, and oil demand should then grow off the lower base going forward.

I think the die is cast for that growth, especially with pent-up demand from people that were cooped up for the better part of a year. The market is indicating in a range of stocks that it is expecting a very robust global economic recovery once the vaccine is implemented on scale. Accordingly, I think people will be surprised to the upside as to how quickly oil demand recovers as we move through 2021.

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Q: Assuming the distribution of multiple vaccines, how soon do you see total global demand being restored to prepandemic levels? Could permanent post-pandemic behavioral changes impact demand, particularly for travel?

ADKINS: Our modeling shows global demand returning to early 2020 levels of around 100 MMbbl/d in the back half of 2022. That said, I think we could see oil demand surge back to reach 100 MMbbl/day as soon as late 2021. This view is based on the optimism I’m seeing from other industries and other economists regarding the pent-up demand. While possible, I don’t think it is safe to put a sharp demand rebound pace in the model quite yet. Put another way, I am not predicting early 2020 oil demand levels by late 2021, but it is an upside possibility in our modeling.

Let’s talk about demand specifics. Over-the-road vehicle traffic is actually up year-over-year in many cases around the world, so there are encouraging signs. At the peak of the lockdowns, air travel was down 70% from the start of 2020. It was only down 40% in early December, which was a surprisingly healthy recovery given the circumstances. Again, it is still ugly, but it indicates the degree of recovery that has taken place already in the sector hardest hit by demand destruction.

There are a lot of swirling issues that will impact jet fuel demand. The biggest positive is the pent-up demand for vacation travel, summer cruises, etc., as the vaccine takes effect. There are a lot of grandmas who are going to want to go see their grandkids. Also, as economic activity and global trade ramps up, air transport of cargoes and goods will pick up as well.

The one main negative I see is business travel. People have discovered that they can accomplish virtually a lot of what they used to do in person. There likely will be some level of permanent jet fuel demand destruction, particularly for international business travel. With people learning how to communicate effectively using virtual platforms, companies have a substitute for physical travel and can eliminate the expense of having employees on the road all the time. Will the positives of pent-up demand for air travel be enough to offset the loss of business travel? Probably not, but we will see.

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Q: The market had a supply overhang even before COVID and the ballooning of storage inventories last spring. How do you characterize the status of global inventories at the start of 2021? When do you expect inventories to normalize within the five-year average?

ADKINS: The inventory picture is what the market consensus misses most right now. If you look at pretty much any oil model forecast, you will see it keys off the International Energy Agency’s historical demand data, which had much greater implied oil demand destruction estimates than what we believe actually occurred last spring and summer. Specifically, the IEA data indicates that inventories built globally by 1.5 billion barrels from the beginning of 2020 through May 2020. I challenge anyone to find those oil and/or oil product inventory builds. It simply didn’t happen and none of the global inventory data supports it.

So, although most oil models suggest global inventories built 1.5 billion barrels in early 2020, if you look at the different places crude oil and products can be stored, you will find that only about half of that–750 million barrels–actually showed up in global inventories.

While a 750 MMbbl surplus in May 2020 is still very large, it also means that actual inventory levels that need to be worked off are only half as big as most forecasts currently assume. That is huge! One might say, “So what, that’s history. Who cares about the past?” It is important because it is the starting point to determine when global oil inventories might return to normal levels. More specifically, it impacts both the timing and pace of the recovery in oil prices.

Think of the surplus inventory as a hole we dug last spring by putting too much oil in the system. That market has to climb out of that hole by working though that surplus. I believe the hole is only half as deep as the IEA data and most models suggest. If the hole is only half as deep, then we are working through the excess much more quickly than most understand. In fact, I believe the world has already worked down about 50% of the 750 MMbbl of surplus built up in the first half of 2020.

Think about this . . . Globally, “oil on the water” floating inventories grew by 225 MMbbl between March and May. From May to December, those same inventories had already fallen by 320 MMbbl. Put simply, the path to getting back to normalized oil and oil product inventories, is much shorter than most think.

Specifically, our model shows global inventories returning to the “normal” range in the second quarter of 2021. At that point, the consequences of degraded supply capacity and rising demand in a post-COVID global economy are going to lead to an increasingly undersupplied market in the back half of 2021. We could, in fact, end up with desperately low levels of inventories by the fourth quarter of 2021 if oil prices stay anywhere near current levels.

So, in less than one calendar year, we could go from the highest levels of oil surplus in history to normal inventories in the second quarter of 2021 and then to well below-normal levels by the end of the year. The way to mitigate this, of course, is to have oil prices go up enough to prompt increased production. Even if OPEC+ starts producing all out after inventories normalize in the March-April timeframe, I think we are still going to see well below-normal inventory levels for both crude oil and refined products by the time we exit 2021.

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Q: In its latest projections, the U.S. Energy Information Administration sees rising global demand and upward pricing pressures in 2021, and expects WTI to average $44.24/bbl next year, up $6/bbl from 2020’s average. What do you expect as a price range for WTI in 2021?

ADKINS: The problem with crude markets is that if something gets out of whack even a little, it can have severe consequences. For full-year 2020, we think demand was down about 7.5% year-over-year, which led to an oversupply situation that caused oil prices to crash below $10/bbl and reduced drilling activity to its lowest levels in modern history. Likewise, to assume oil prices will increase only a few dollars in a severely undersupplied situation ignores the way commodities markets work.

If we are indeed as short crude supply as my models suggest for 2021, oil prices won’t go from $45 to $50 and stay there. They will go from $45 to $50, and then keep going to $60, $65 or maybe $70 and even higher. Put simply, it takes a meaningful price response to generate meaningful responses from OPEC+ and U.S. producers, as well as to alter consumer behavior. Throughout history, oil prices have never risen or fallen to exactly the right point and stopped. They always overshoot both on the upside and the downside. Prices clearly overshot on the downside last April, and I suspect they will overshoot on the upside sometime in 2021.

I think WTI prices could go well north of $70/bbl this year. I would not be shocked to see prices roughly double from where they averaged in 2020 to reach $80-$90 by the end of 2021. It is not out of the question.

People ask how that can be possible. I like to remind them that it wasn’t that long ago when WTI was trading well above $100/bbl, and almost every forecast had prices staying above $100/bbl indefinitely. We all know what happened next. Therefore, an increase to $70/bbl seems very reasonable in the supply/demand scenario my model suggests is moving into place. In other words, based on the fundamentals, I don’t think $80+ is extremely far-fetched.

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Q: COVID was the ultimate wild card that no one could have anticipated. It’s impossible to predict the unpredictable, but as you analyze all the various data points, do you see anything the market may be overlooking that unexpectedly can influence pricing in 2021? Is there more potential for an upside or a downside surprise?

ADKINS: Let’s look at wild cards from two perspectives: bearish and bullish. Assuming COVID vaccines are distributed as planned, the big bearish wild card in my mind, obviously, is Iran, which theoretically has reduced production by 1.75 MMbbl/d. However, I am not sure anyone has a good handle on how much oil Iran is really sneaking out of the country. Its actual production is probably significantly less than 1.75 MMbbl/d. Furthermore, Iran has not been putting capital into infrastructure. So, what can Iran really bring back on line if the Biden regime decides to allow it to resume oil exports? The answer is probably somewhere between 1.0 MMbbl/d and 1.5 MMbbl/d of incremental oil brought into global oil markets.

If that were to happen in a vacuum, where Saudi Arabia was producing everything it had all out, it could be a definite negative. However, I suspect OPEC+ would make room for Iranian supply as prices dictate. If the Saudis simply returned their production output to where it was at the start of 2020, it would still leave room for Iran to come back in the second half of this year.

Keep in mind, Iranian sanctions will not exactly be the first item on Biden’s agenda. If a removal of Iranian sanctions happens, it will take time. Using my numbers, Iran could come back on line in the second half of 2021 and the oil market still would be undersupplied at year’s end.

As far as wild cards that could be bullish for prices, the market continues to almost entirely dismiss geopolitical events and unrest in the Middle East. In November, Houthi forces hit a Saudi Aramco oil facility with a missile. In separate events in December, tankers were hit with mines and boats loaded with explosives in Saudi ports. Iran recently seized a South Korean tanker.

In the past, these types of events were major price catalysts because they were seen as potential supply disruptions. In today’s oversupplied market, they hardly even register. One could speculate on 20 things that could go wrong in the region, but if any supplies from the Middle East get disrupted in the undersupplied market environment I am describing for 2021, it won’t be nearly so easy for the market to ignore.

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Q: The material effects of depressed commodity prices are impossible to miss in onshore tight oil plays. How much has U.S. oil production dropped since March? This leads to the million-dollar question: How low could oil output go before it stabilizes? What will it take to resume production growth?

ADKINS: The answer to that depends partially on whether you are including natural gas liquids in the U.S. oil supply number. That noted, U.S. crude oil-only supply is down about 2 MMbbl/d since the beginning of 2020. Monthly EIA-914 data (which combines crude oil and lease condensate) shows production down from just under 13 MMbbl/d last spring to just under 11 MMbbl/d exiting the year. If you include NGLs, the number is higher. There has recently been some slowing of the U.S. supply drop-off as the frac count picked up and operators completed a bunch of drilled but uncompleted wells, but that will only provide a temporary respite at sub-$50/bbl oil prices.

We have run a number of “What if?” scenarios, and a WTI price of $45/bbl simply cannot economically support enough drilling and completion activity to offset structural declines. If oil prices would stay range-bound at around $45/bbl, U.S. operator cash flows would only support a rig count averaging fewer than 400 rigs (and around 150 frac crews), and we would continue to see lumpy but continued degradation in U.S. production capacity. At $45/bbl, I would suggest we would lose up to another 1 MMbbl/d of domestic oil production by the end of 2021. That would mean U.S. crude production would exit 2020 down 2 MMbbl/d, and then exit 2021 down a total of 3 MMbbl/d.

Growth can be achieved only by taking up the rig count (and associated completion crews) with higher oil prices. Rig counts are in the mid-300s now. Assuming the industry can put rigs and fracturing crews back to work quickly after such a severe downturn, which will require lots of people, capital and everything else, and if we could get to 600 rigs by the end of 2021 and add another 200 rigs to get to 800 by the end of 2022, we would start to post growth again and might be able to get close to start-of-2020 production volumes.

But as noted, it would require a huge increase in spending, a dramatically improved oil field services business environment, a lot of new employees, and a ton of new investment capital. The cannot realistically happen unless oil prices increase to $70 or higher.

If oil prices do surge in 2021 as we expect, U.S. production could get close to 13 MMbbl/d again by the end of 2023, but that assumes U.S. well productivities do not deteriorate as drilling activity ramps up in noncore areas. What if productivities turn negative, which is very possible? In that case, achieving growing production would require that many more rigs, frac crews, and investment dollars. Let me put it this way: no matter what, it is going to take a heroic effort to get crude oil production back to 13 MMbbl/d, where we started 2020.

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Q: After last spring’s collapse in drilling and completion activity, operators concentrated on their Tier 1 acreage with the greatest production potential and lowest break-even costs. What have we learned about productivity trends and decline curves? What are the “magic numbers” of rigs and frac spreads needed to hold production steady?

ADKINS: There have not been any really huge surprises with decline trends or well productivities. If someone would have asked me at the beginning of 2020 what would happen if the rig count dropped from 800 to 250, I would have said U.S. well productivities would go up and overall oil production would go down. This is because operators would be expected to drill and complete longer laterals on their very best and most contiguous acreage. That is what happened, and it allowed mid-single digit growth in U.S. per-well productivity in 2020. Again, that is a function of the lowest rig counts in history targeting a small universe of high-graded, longer lateral wells.

Likewise, in the higher-price environment that I foresee coming in 2021-22, well productivities will be challenged to stay flat as the industry drills and completes more lower-tier wells with shorter laterals on less-contiguous acreage.

So, how many rigs do we need to keep U.S. oil supply flat? We have run iterations that suggest U.S. oil production could be kept flat at a rig count of 450-500 rigs and a frac spread count of 175-ish. Keep in mind that coming into 2020 the required rig count to stay flat was closer to 800 average U.S. rigs. As we get further out on the decline curve with lower U.S. production, the number of rigs (and frac crews) needed to stay flat falls significantly.

Exactly how activity will respond to the higher price signals as 2021 unfolds depends on the pace of recovery in the general global economy, but let’s assume a linear oil price increase starting the year at around $50 and exiting 2021 at $80/bbl. I think the pace of recovery in drilling and completion activity will be subdued over the first half of the year as public companies operate out of cash flow, prioritize returns to investors, and repair their balance sheets. However, once WTI increases to $60/bbl, there would be enough cash coming through the door that they could start spending more on activity and still be able to return value to shareholders and service debt.

Accordingly, I think the rig and frac counts will accelerate in the back of the year as the public companies enter the mix again. Early on, activity will be driven by private companies taking advantage of low service costs to put rigs and frac crews to work. By the back half of 2021, everyone will be back in the game putting money to work.

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Q: If your forecast holds true, operators and service and supply companies will be scrambling to transition from cost-cutting survival tactics to increased spending and opportunity-capture modes. What factors could pose challenges to ramping activity? Two potential obstacles immediately come to mind: recapitalizing given existing debt obligations and replenishing the workforce.

ADKINS: To answer this question, we must bring natural gas fundamentals into the mix. We haven’t really spoken about natural gas, but lower oil production also means lower associated gas production. The gas market looks pretty solid. The fundamentals at the start of winter supported $3.50 or higher prices throughout 2021, but extremely warm weather so far this winter has taken away some of the upside. Absent warm weather during the rest of winter and normal weather patterns in summer and fall, the fundamental support is still in place for relatively strong U.S. natural gas prices, and eventually, increased gas-directed drilling activity.

The oil and gas business is one that requires a lot of capital, so capital access is potentially a big impediment. A growing number of investors really do not like putting money into anything related to oil and gas. That is partly ESG, partly past performance on investments and partly social activism, but the lack of incremental investment capital available to the oil and gas industry is as bad as we have ever seen it.

If capital access continues to be constrained, we will be in an unprecedented time as oil and gas prices recover. To say the least, it will be interesting to see how it plays out. I know this much: Whenever an industry is starved of capital, its product tends to become scarcer, and by definition, returns tend to go up. The tobacco industry is an example of this.

In the past, the biggest challenge coming out of downturns was always manpower. I don’t think labor will be as big a problem as it has been in the past simply because there have not been a ton of other industries hiring. In the past, the oil business would cycle down and people would get a job outside the industry. The alternative job options haven’t been there this time. COVID has hit almost everyone hard. My guess is that people will be much less of an issue than capital in getting this industry back to work in 2021.

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Q: Natural gas fundamentals always seem to come down to a simple, inescapable truth: “It all depends on the weather.” That certainly has been the case so far this winter. Unseasonable warmth through early January weakened demand and undercut prices. You have been very bullish on natural gas in 2021. How has lackluster winter demand altered your market forecast?

ANDREW D. WEISSMAN: The mild weather has affected pricing significantly heading into 2021, but our core view of the market has not changed. The thesis we offered last spring was that there was significant risk that prices would come under intense downward pressure during the summer and fall, reaching a low point in early fall. That is exactly what happened. Henry Hub spot prices bottomed on Oct. 2 at a $1.41/MMBtu. The dynamics that drove that price behavior were as we anticipated, with COVID-related lockdowns reducing demand and adding to the oversupply that had persisted in the market for several years prior to the pandemic.

But our thesis last spring went on to suggest that a major structural market deficit would develop in late 2020 and become severe in 2021, putting upward pressure on prices into 2022 and possibly beyond. From our standpoint, there’s no question that is exactly where we are today.

We believe there is a high probability for a steep rise in prices this year. It would be occurring already except for two main factors that intervened to delay what we see as an inevitable price run-up: multiple hurricanes striking LNG export infrastructure in late summer, and unusually warm temperatures in the first half of winter.

Let’s back up to late August when the first of two major hurricanes–Laura and Delta–directly hit the Cameron LNG terminal near Lake Charles, La. The significance of this extraordinary act-of-God event on the market is underappreciated. The damage Laura caused to the local electric grid knocked the Cameron facility completely out of commission for six weeks. It was down the entire month of September, when global LNG demand was roaring back.

Just as Cameron was restarting, Delta made landfall at almost exactly the same location and delayed Cameron’s return to full capacity by another five-six weeks. Laura and Delta had the cumulative effect of blocking a substantial amount of LNG demand that would have left less supply available for injection into storage. Less gas in storage, in turn, would have mitigated downward pressure on prices in November and December, even though weather in November was among the warmest on record for the month. The combination of lost LNG demand due to Laura and Delta and very mild weather kept prices under downward pressure.

During the remainder of the winter, weather will still matter in part because many analysts focus heavily on end-of-winter storage projections as the basis for gas pricing. In our judgment, this near-exclusive focus on end-of-winter storage is a myopic view that misses clear market signals about what, at this point, appears nearly certain to happen during 2021. Supply and demand are going to be extremely tight all year long. If prices stay near current levels, during this year’s injection season, the amount of gas injected into storage could fall to an all-time low, leaving the market with a huge storage deficit heading into next winter. To prevent this from occurring, prices will need to rise sharply over the next 12 months, potentially reaching multi-year highs next winter.

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Q: The sentiment for some time has been that the gas market is chronically oversupplied. The vision you are describing represents a dramatic departure from that line of thinking. Are you ready to declare that 2021 will be the year in which the market shifts away from an excess-supply mentality and adopts new perceptions about supply and demand?

WEISSMAN:Yes. And I will do one better: The era of chronic oversupply is already history. We have moved into a new period with a significant structural deficit that is unlikely to turn around any time soon.

We believe the market is severely undersupplied today. This reality has been masked by hurricane-related loss of LNG demand last fall and warm early winter weather. Although very mild weather over the remainder of this winter could keep storage high enough that it might take that much longer for the deficit to become readily apparent, the new era is already here and it is going to persist for some time.

As we move farther into 2021, we think it’s going to become unmistakably clear that a new day has dawned. The market is going to face a severe supply deficit if Henry Hub prices remain anywhere close to recent levels. Prices will need to move considerably higher to balance supply and demand.

NYMEX prices slipped below $2.40 immediately after Christmas when forecasts showed continued mild weather across most of the country for the first two weeks of January. If the rest of the winter turns out to be warmer than normal, prices could remain soft and delay the price run-up a bit longer. It would be temporary, however.

Even in a warmer-than-normal January-to-March scenario, the storage surplus would continue to erode, albeit at a slower pace. The way we see it, the structural deficit is so severe that the likelihood of prices increasing this year is very high regardless of weather over the remainder of winter.

But traders continue to focus exclusively on the near-term picture, with gas trading based on current storage volumes versus historical averages. If that were the only criterion, one would see that December inventories remained comfortably above both the year-ago level and the five-year average and conclude that the market remains oversupplied.

It is a big mistake to conclude too much from the weekly storage numbers, however. The fundamentals indicate storage will be driven to well below the five-year average by the end of March. By late spring/early summer–depending on weather over the rest of the winter–expect the trend of eroding supply to become unmistakable, leading to an increasing price environment for injection season and winter 2021-22 heating season contracts.

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Q: The disconnect is startling between prevailing perceptions of the state of the U.S. gas market and the structural realities as you describe them. Can you think of a corollary to the situation you envision unfolding in 2021?

WEISSMAN: It has been a long time, but in the early 2000s when I first became active in the natural gas market, I was one of the first to predict a doubling or tripling of prices because of the same kind of disconnect between market perceptions and fundamentals. Prices did, in fact, triple, catching many by surprise.

The drivers were different then, but the general setup was similar to what we see happening today. To put it simply, the market potentially is between an immovable rock on the supply side and impenetrable hard place on the demand side. Something has to give, and as in the early 2000s, that something will be prices.

Global natural gas prices are surging already. In mid-December, Korean LNG spot prices hit $12.20/MMBtu equivalent, the highest since November 2014. That is a bullish indicator that demand for U.S. LNG exports will be strong.

Domestic consumption held up remarkably well during the pandemic, and with several new LNG liquefaction trains added in 2020 and COVID vaccines now available, core demand for natural gas in 2021 is in a position to grow significantly. But demand growth requires supply growth, and U.S. gas production is moving in the opposite direction. Reversing the decline trend will prove more challenging and take longer than many think.

If there were a better understanding of the growing structural deficit, the market would appreciate that end-of-winter storage needs to be very high to get through 2021 and prices would be higher. Even assuming the market performs perfectly efficiently, the current storage trajectory for this winter–while high enough to avoid a near-term crisis–is still far below where it needs to be to avoid a severe shortage in the second half of the year.

The market could turn quickly once participants begin to fully recognize the gravity of the structural deficit and its implications for prices. The hit last autumn on Gulf Coast LNG demand and the exceptionally mild start to winter have clouded near-term market signals and delayed the upward surge in prices, but it’s coming. It is only a question of when and how high prices will go.

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Q: Let’s look at supply. How much permanent decline do you see in year-over-year U.S. gas production? How much of that lost output is associated gas? With WTI prices strengthening, will associated gas production start to stabilize? How soon could it start growing again in the Permian Basin with its pipeline capacity additions?

WEISSMAN: Our models indicate total U.S. gas production exited 2020 roughly 4 billion cubic feet a day-4.5 Bcf/d lower than at the start of the year. Should prices stay at current levels, the amount of gas that would be injected into storage during the 2021 injection season would be an all-time low, and would leave start-of-winter storage next November close to 1.0 trillion cubic feet short.

But even with higher prices, we expect associated gas production to continue falling in oily plays such as the Eagle Ford, Bakken, Niobrara and SCOOP/STACK. Permian gas production declines seem to be leveling and could increase marginally later in 2021, but it’s very unlikely that for the year as a whole Permian associated gas volumes will significantly exceed 2020 levels.

Associated gas production trends are driven by global oil market conditions and capital constraints. Global oil prices should continue to strengthen as COVID vaccines are distributed. Asian oil demand is very strong already, and vaccines will help demand rebound virtually everywhere else. By midyear, we should see a strong recovery in both the U.S. and European economies.

However, OPEC+ has a lot of production capacity sitting on the sidelines that can be brought back quickly as demand warrants. There is also the possibility that Iranian production will rise sharply at some point, and there is quite a bit of Canadian oil sands production yet to be restarted.

So, while we see oil prices improving dramatically later this year, the upside for U.S. oil producers is going to be tempered by OPEC+’s ability to restore idled supply. That will create a situation in which, while on paper U.S. producers may be justified in ramping up production in the Permian and other oil basins, the practical economics are not going to be overwhelming.

Politically, the Biden administration intends to restrict fracturing on federal lands, and that could have an impact in the Delaware Basin. Operationally, capital availability is a huge constraint. There was a lot of industry consolidation in the Permian, in particular, during 2020. That typically involved taking on more debt, and in almost every case, resulted in the producers publicly committing to restraining 2021 CAPEX, funding maintenance-level operations with cash flows and returning value to shareholders.

Consider ExxonMobil, the largest U.S. gas producer and one of the most active operators in the Permian. Its management recognizes the importance of maintaining dividends to shareholders. But to do so, ExxonMobil has indicated that it does not expect to have enough cash flow to fund even the maintenance-level drilling program it had initially planned for 2021. ExxonMobil’s situation is relevant in two ways. First, if the largest producer has to keep CAPEX below maintenance-level spending, it is hard to imagine associated gas production growing in the Permian or any other oil basin.

Second, ExxonMobil has signaled its interest in selling its U.S. dry gas business. Therefore, it can be assumed the company will not be pouring capital into assets in the Haynesville, Marcellus or other gas basins that otherwise might be very attractive to develop. Again, if the largest producers are in that position, it is going to materially impact what happens with U.S. dry gas production, even if smaller private companies increase their activity.

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Q: After bottoming in early October, by late October, Henry Hub spot prices had climbed to above $3.00 and January futures were trading above $3.50. Then came the start of a no-show winter that bled market momentum in November and December. To what degree might the late-year price erosion impact supply expectations in 2021?

WEISSMAN: It was very deflating for gas producers, who had been hit hard by extremely low prices during the first three quarters. As a group, they found themselves entering the third quarter with diminished cash flows, historically low prices for their product and large amounts of debt, and their banks weren’t interested in extending credit. But the market rallied in a big way in October, and by the start of November, futures prices had more than doubled. But even then, publicly held gas producers were reiterating their commitment to be disciplined and restrain CAPEX.

Understandably, even if they were not capital constrained, and even if they are 100% certain prices will move higher in 2021, it is very rational business judgment to be extremely cautious. Producers have heard a clear message from investors that their highest priority must be repairing balance sheets and paying dividends. Wall Street will look favorably at companies that show a high level of capital spending discipline, and will punish those that are overly aggressive. That is a powerful dynamic regulating operator behavior, and it has to be part of the calculus in predicting the supply-side response to higher prices as 2021 progresses.

In addition to capital constraints, there are growing ESG challenges in virtually every basin and a pipeline takeaway capacity bottleneck in the region with arguably the greatest ability to respond to higher gas prices: Appalachia. Marcellus operators are up against a proverbial brick wall in takeaway capacity that prevents them from expanding exports. Put all these things together and it creates a unique set of circumstances that is going to limit the ability to significantly increase natural gas production in two or three years, let alone in 2021.

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Q: As you noted, operators in the Marcellus, in particular, have stated their intention to take a measured and deliberate approach, focusing on maintaining production and returning value to shareholders. Assuming higher prices in 2021, what exactly do you project for activity levels in shale gas plays?

WEISSMAN: We do expect increased drilling in the second half of the year in response to higher prices, but it will have only a modest impact on total annual production in 2021 in a market massively short on supply. The Haynesville is among the dry gas plays best positioned to benefit, but the play’s two largest producers are Chesapeake and XTO. The former is in bankruptcy and the latter is for sale. While smaller private producers are starting to ramp up drilling, as is publicly traded Comstock Resources, Haynesville production is equally likely to see a net decline as a net increase over the next six months.

We anticipate total gas production in the Eagle Ford falling significantly in the second half of the year. However, EOG’s Dorado play in South Texas, which includes the Austin Chalk and Eagle Ford, looks very attractive. It may help stabilize output from the region later in the year. As noted, the Marcellus and Utica have distinct challenges that will make it difficult to grow production beyond current levels.

That is broadly the case in every play. Operators are going to be hard-pressed to do more than bring back a small number of rigs to maintain production at current levels. There will be activity in a few bright spots, but generally, the supply response will take time to materialize. The market is going to have to balance more on the demand side than on the supply side this year.

In other words, prices will have to rise high enough to drive significant amounts of demand out of the market. That will trigger fuel switching to coal in the power sector, and potentially even disrupt LNG exports to conserve natural gas supplies for domestic consumption.

If everything bears out as we envision, domestic prices will not only rise enough in 2021 to displace gas in power generation, but could have to rise significantly enough to back U.S. LNG exports out of overseas markets. Should that occur, opportunities will emerge for producers to hedge their production and begin to grow supply, with the caveat that adding rigs in the back half of this year will not impact production until sometime in 2022.

A best guess estimate for an average rig count in the fourth quarter is between 100 and 125, or a 25%-50% increase over the current count. But again, a lot will depend on all the factors we have identified, not the least of which is capital constraints and producers’ ability to ramp production even with the strong price incentives in place.

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Q: Let’s look closer at how demand may respond in the higher-price environment. This is the part of the forecast that is hardest to fathom — and to stomach. Gas demand for both power burn and LNG exports hit record highs in 2021. How do you see demand in those sectors reversing course?

WEISSMAN: Demand has to be viewed in the context of price, and it is not always pretty. The short answer is that with supply unable to grow, demand growth must be curtailed. If demand were at the levels one would expect at the current forward price curve, storage would fall to catastrophic levels. At today’s strip prices, our models show storage potentially going negative next winter if weather resembles anything close to normal. Obviously, that will not happen. Instead, prices will rise as much as needed to bring the market into balance.

Most of the rebalancing will occur initially through fuel switching in the power sector. In fact, we think one of the main stories of 2021 will be gas displacement in power burn. The magnitude of the price increase to accomplish this could be very large, and the amount of demand displacement could be severe: easily 4 Bcf/d-5 Bcf/d.

One likely result of consuming less gas and more coal in power generation will be increased carbon dioxide emissions. Ironically, that may be the price of canceling and delaying the Atlantic Coast and other pipelines that could have allowed additional gas supplies to reach the market.

What if fuel switching in power generation is not enough balance demand with available supply? Global LNG demand is strong this winter and is expected to remain so for the next couple years. LNG demand is weather-sensitive, so there is always uncertainty in the range of potential outcomes. That said, given forward price curves and severe weather in Asia this winter, which has drawn a large number of LNG cargoes to Asia and depleted European storage, U.S. liquefaction plants likely will run near maximum capacity for much of this year.

What happens next with LNG exports will depend, in part, on how much gas is left in storage at the end of March. With demand for space heating and LNG exports tapering off, will there be a sufficient buffer at winter’s end to allow the market to balance during the injection season solely through prices rising sufficiently to compel generators to dispatch coal-fired capacity?

If the answer to that question is yes and there is enough gas left to allow storage to be replenished adequately during the injection season by switching power generation to coal, then U.S. prices may top out in the upper-$3.00 to low-$4.00 range and LNG exports would be unaffected.

But if the answer is no and the market cannot be balanced by fuel switching alone, then Henry Hub prices will need to rise high enough to curtail U.S. LNG exports to keep more gas in the United States. If the global LNG demand remains tight, prices at Henry Hub might need to go much higher than $4.00/MMBtu to keep U.S. gas at home.

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Q: Let’s reflect on that. The situation you are describing is the opposite of what has occurred since the introduction of U.S. LNG exports. Low-priced domestic gas production allowed the United States to export low-cost LNG supplies, in effect, forcing LNG supplies in other parts of the world to compete on a price basis with the U.S. market. In your scenario, global LNG markets would force the U.S. market to compete on a price basis for domestic production. And removing U.S. LNG for any length of time should theoretically increase global LNG prices, right?

WEISSMAN: That is exactly right. The global natural gas market is already very tight. Spot prices at virtually every major hub are at their highest levels in years and the forward curves for 2021 have moved up significantly this winter. The United States actually is the only major hub in the world in which prices have remained weak.

The United States has brought on a tremendous amount of liquefaction capacity, and that has been a great thing for both the domestic industry and consumers worldwide. Initially, though, it created excess supply in the global market, which was just starting to be worked through when the pandemic hit. There is every reason to be hopeful that the pandemic will be under control by next summer, and on a weather-neutral basis, LNG demand is forecast to grow in 2021 and 2022. It is not uncommon for spot market LNG prices to exceed $10/MMBtu to $12.00/MMBtu during periods of high seasonal demand, and even higher prices are possible.

If the United States needs to retain gas that otherwise would be exported as LNG in order to keep storage at adequate levels next winter, that probably means Henry Hub prices might need to go to the $8/MMBtu-$10/MMBtu range, if not higher, to back off LNG exports. Gas prices are very seasonal, but prices in Europe and Asia are at the highest levels they have been in a long time, and conditions next winter could be even tighter.

In the past, any potential developing supply shortage led to higher prices, which prompted fuel switching in regional power markets, rebalancing local supply and demand relatively quickly. That is possible because generators can switch fuels in relatively short order. In the Midwest and Mid-Atlantic states, for example, if a cold snap increases local gas prices, generators can switch to coal-fired plants within a matter of a few days or in some cases even hours.

LNG liquefaction, loading and shipping have much longer lead times. If we get to the point where U.S. LNG exports have to be halted, those decisions will have to be made on a time frame of months rather than days.

Imagine that at this time next year, the power sector has switched everything it can to coal and the market is still short on supply. At that point, U.S. LNG exports will have to start shutting down, but LNG still will be in demand in Asia and Europe. It is not hard to conceive of an extremely bullish price scenario next winter where prices skyrocket for a brief period. I am not predicting this, but I do think there is a much greater possibility of that occurring than is generally understood.

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Q: In late December, environmental activists in Aspen, Co., vandalized the local gas distribution system, apparently intentionally rendering segments of the city’s infrastructure inoperable. This was done on a day when local temperatures fell to 2 degrees Fahrenheit, and punctuates the “anti-industry at any cost” irrationality that often confronts natural gas development. How could opposition to the industry weigh on gas supply? Are there other wild card issues that could influence the market in 2021 and beyond?

WEISSMAN: Last year at this time, the Atlantic Coast Pipeline was expected to begin shipping gas out of Appalachia by early 2022, just when increased supplies could be sorely needed. But after years of legal battles and delays, the developers canceled the project last summer. Anyone involved in the industry understands how critical pipeline capacity is to the Marcellus Shale. To achieve its potential, this prolific supply resource must have access to markets. Atlantic Coast is a huge setback. It is gone and will never be revived.

Mountain Valley from northwestern West Virginia into southern Virginia is now the only option left for increasing transportation capacity out of Appalachia. Given what happened with Atlantic Coast and Biden’s election, it’s hard to fathom anyone stepping up to propose building another pipeline in the region. Mountain Valley is close to being completed, but the startup date already has been pushed back to late 2021. Time is running out to cross the finish line, and it is not entirely clear what may happen if the project does not get final permitting approval before Biden is sworn into office.

We hope Mountain Valley gets completed, but if it also gets blocked, it effectively would mean Marcellus production is maxed out. Without new pipelines, the lack of takeaway capacity will create a permanent barrier to increasing Marcellus output. There are real consequences to imposing limits on supply by preventing infrastructure development, and consumers will suffer those consequences in the long term.

And that ties back to the point about how important it is for those in the industry to see beyond the here and now. Many assume the warm weather of November and December completely negated the supply reductions that occurred after the pandemic began. That is simply not the case.

The good news is that a growing number of market participants are thinking contrary to the predominant short-term view to focus on the bigger market picture. We are not the only ones recognizing the structural deficit and coming to terms with the idea that higher prices are in store.

As always, there will be surprises, but they are far more likely to surprise to the upside than the downside. I will conclude with an example of a phenomenon that could be an upside surprise in the making: the effect of remote working and schooling on overall gas demand. Because the winter has been so mild, it’s been hard to get an accurate read on this. I have talked with local distribution companies, and interestingly, they don’t seem to have a handle on it yet.

We know there is a lot more residential space than commercial space. While commercial demand has been reduced, most commercial space continues to be heated regardless of whether it is occupied. In contrast, on the residential side, a lot of homeowners who would be turning the heat down when they left for work or school in the morning and turning it up on returning in the evening are leaving the thermostat up around the clock.

That could add as much as 200 Bcf-400 Bcf of demand over the winter. With end-of-winter storage expected to be close to 1.4 Tcf, that degree of unanticipated demand could be a catalyst for shifting the psychology of the market and prompting the run-up in prices that we think will characterize 2021.

This is a huge open question, and it is just one possibility that could add a new layer onto the structural deficit that is already in place. Yet, at this point, there does not seem to be a recognition by either the market or policymakers regarding the severity of the risk we are about to encounter.