Will the Omicron Variant Lead to the Collapse of Oil Prices?

With the Omicron variant continuing to spread around the world, will a drop in oil prices follow? Maybe, but probably short term.

Equity markets tanked last Friday, Nov. 26, on fears that the Omicron variant would sharply impact worldwide economic output. The nearly 1,000-point loss in the Dow wiped nearly $90 billion of value in Dow equities. Oil prices were particularly hit hard, dropping nearly 10% from Thursday’s close.

That drop, however, is minor compared to what happened to prices in early 2020 when at the end of April oil prices had dropped nearly 70% in value. This was frightening and was a combined pessimistic response to fears of demand destruction due to coronavirus and the price war initiated by OPEC and Russia to counter rising production from U.S. shale oil producers.

As a world economy, we had not faced a major health crisis since 2014 when Ebola fears gripped the world and, according to the Centers for Disease Control and Prevention (CDC), the 2009 H1N1 flu sickened 60.8 million and killed 12,469 in the U.S.

If we go back to the 1918 Spanish flu, the graph below shows the gross U.S. demographic impact of these pandemics.

The 1918 Spanish flu infected about 28% of the U.S. population but didn’t impact oil prices to any great degree. COVID-19 has infected about 15% of our fellow citizens but has caused nearly 125,000 more deaths because our population is about three times larger than it was in 1918.

In our current COVID-19 pandemic, images of first responders desperately improvising to save lives, and stories of grief-stricken children and partners forced to provide remote comfort to isolated and suffering elders tested our confidence that there would ever be a “normal” American life in the future.

How did oil markets react?

The pre-COVID price of oil (CLF) in late 2019 dropped by 73% to its low in April 2020. Fears of demand destruction due to COVID dropped the price from $63/bbl to around $40/bbl — a 36% drop.

Price pressure was further exacerbated by OPEC’s price war with Russia, with OPEC increasing their output by a factor of four during a short window going into and lasting through April 2020. This dropped the price of oil another 40-50%.

Once OPEC ended its price war, the baseline price of oil was around $40/bbl.

When Moderna and Pfizer announced their vaccines, and the CDC authorized their emergency use, prices recovered until late July 2021 when the U.S. entered its third wave of increasing case counts and rising death counts.

Prices dropped about 16% before staging an astounding recovery to a four-year high of nearly $84/bbl in mid-October.

Now we have the Omicron variant. We do not have enough information yet about its transmissibility or lethality, but the market’s virus fears resulted in a drop from $74/bbl on its Nov. 26 opening to midday pricing of $65/bbl on Nov. 30 — a three-trading day drop of about 12%.

Our first pandemic oil price drop occurred when nothing about the potential impact of COVID, or treatments for it, was known. If we were in the same state of unpreparedness now, we could see the previous pandemic fear factor of 36% drop the price from here to the low $50/bbl, high $40/bbl range.

However, given that we have vaccines, monoclonal antibodies, new therapies and better testing, my guess is that our original fear discount won’t apply now, and that we would see some, but not a lot, of price weakness from here.

The bigger fear would be that planned incremental OPEC production increases would increase supply and range bind prices. Given that the recent OPEC-Russia price war dropped prices about 50%, supply increases do more to depress prices than virus fears.

As is always the case with oil prices, tomorrow always delivers surprises.

Supermajors Pile Into Low-Carbon GOM Acreage

Offshore Gulf of Mexico (GOM) is becoming the destination of choice for international oil companies seeking new, low-carbon acreage to explore and develop. Lease Sale 257 on Nov. 17 garnered $192 million in winning bids, about double the average of the previous seven auctions, across 170 deep- and 140 shallow-water blocks. The sale went ahead after a court blocked the Biden administration’s lease moratorium imposed early this year. The moratorium was to allow the U.S. Department of the Interior to review the environmental impacts associated with oil and gas activities on public lands and in offshore waters.

Unsurprisingly, the sale drew criticism from environmentalists despite the basin offering the lowest Scope 1 greenhouse gas emissions intensity in the U.S. at 8 kg CO₂e/boe (Figure 1). The GOM’s Scope 1 emissions are even competitive on a global scale. The Oil and Gas Climate Initiative (OGCI), whose members include the so-called supermajors responsible for 30% of total world oil production, has a 2025 emissions target of 17 kg CO₂e/boe from its members’ operated upstream assets, more than double the GOM average.

We mostly attribute the low emissions profile to a well-developed gas offtake infrastructure and market that reduces the need for flaring. In addition, the GOM has strict ESG regulations, relatively young infrastructure and significant discovered but undeveloped hydrocarbon resources. The continued investment by supermajors confirms the basin’s global top-tier status despite their commitment to reduce oil production and emissions. Chevron, Shell and BP accounted for half of money spent at Sale 257, strengthening their positions in the basin. Other U.S. operators are following suit, with Occidental spending 33% more this year than its total spending in the region for all sales since 2019.

With global demand for oil and gas still increasing, the GOM looks set to attract a growing proportion of the supermajors’ development capital spending, allowing them to produce more oil and gas but still improve their overall carbon intensity scores. Using our PRISM data platform, Enverus clients are readily able to benchmark U.S. ESG metrics at a basin, play, operator or asset level, helping them make smarter and faster investment decisions during the energy transition.

Figure 1 | U.S. GHG Emission Intensity by Basin

Source | Enverus

Attacking Methane Emissions Beyond Oil and Gas

A recent Associated Press article titled “Biden’s climate plan aims to reduce methane emissions” states, “The centerpiece of U.S. actions is a long-awaited rule from the Environmental Protection Agency to tighten methane regulations for the oil and gas sector.”

It also says, “The oil and natural gas industry is the nation’s largest industrial source of methane.”

The logic seems straightforward, that drilling for hydrocarbons produces methane, the infrastructure for moving that product stream around the country will naturally have less than perfect containment, ergo, regulate.

In 2020, the U.S. produced 8,288,717 metric tons of methane. The sum of all the categories in Enverus’ greenhouse gas data set that represent both upstream oil and gas and midstream — production, pipelines, compression gathering and boosting, for example — accounts for about 37% of total 2020 methane. That’s a significant source of methane, to be sure, and one that operators in oil and gas must work harder to minimize.

But the data show underground coal mines are responsible for nearly 14% of methane production in the U.S., and municipal landfills account for nearly 41% of our methane emissions footprint. Together, coal and landfills are responsible for 55% of our methane problem, and are a bigger source of methane pollution than oil and gas.

To get a sense of the scope of the problem, it’s important to realize there are 1,121 municipal landfills in the EPA data set. The screenshot below shows methane points of emission in North Carolina binned and colored by total emitted volume. The most burdensome emitters are the dark red dots, and they are all municipal landfills.

Source: Enverus coded EPA data; screenshot of Enverus PRISM GHG data.

The screenshot below of southwest Pennsylvania shows a concentration of coal mines, two onshore production emitters and power plants.

The mines in the screenshot accounted for more 2020 methane emissions than all U.S. offshore oil and gas methane generation or natural gas processing emissions.

Source: Enverus coded EPA data; screenshot of Enverus PRISM GHG data.

Setting aside the costs to reduce emissions in mines for a moment, coal mines will be a difficult problem to tackle, because unlike other sources of methane emissions, there is a higher percentage of problem mines than in other sectors.

On the plus side, however, there are only 62 mine facilities, and 10 of those are responsible for over half the sector’s emissions. If we look at other sectors, it’s clear that their problematic emission impacts are concentrated in relatively few places.

Focusing remediation on the top 20 problem sites within a sector will have major impacts without being too disruptive.

Assuming the EPA writes smart guidance, focusing methane remediation efforts in areas that also have CO2 problems would be an efficient way to deploy administrative and technical resources to execute on this plan.

Remediation in upstream oil and gas should be relatively straightforward — find the well with the leaking casing, or the gas compressor with a bad seal, or the pipeline that drones have identified as leaking, and go fix the emitting infrastructure. It’s easily identifiable and mostly mechanical in nature. Upstream and midstream operators should embrace leak detection and quickly eliminate those leaks. It’s good politics and ultimately improves the bottom line.

I don’t know what the process would be for capturing leaking methane from a coal mine or a landfill. My guess is that it’s much more complicated and probably expensive.

Perhaps the best course of action for the Biden administration — especially post-Virginia election — would be to broaden their focus from just oil and gas and tackle a couple of smaller landfill and coal mine projects.

Project costs would be smaller and climbing the learning curve will be quicker. Deploy those lessons learned to larger emitters and get a bigger impact, quickly.

Instead of using a federal sledgehammer, limited but targeted interventions by regional federal teams using both carrots and sticks could go a long way toward reducing the U.S. warming curve. Judiciously applied funds from the Build Back Better bill, when passed, could help the administration truthfully claim it is staying true to its climate policies by using smart money to make a noticeable difference in our national methane footprint.

Attractive E&P Yields Are Becoming Difficult for Investors To Ignore

Finding high-yield investments has become more difficult in recent years. One reason why E&P stocks have outperformed all sectors year-to-date (XOP up 88% versus S&P up 23%) is because of attractive free cash flow (FCF) yields, even after the sector has rallied. Nearly all E&P stocks continue to offer double-digit FCF yields — based on our estimates in 2022 — and screen attractive versus stocks in other sectors.

2022E FCF Yields (Assuming Strip Commodity Prices)

Source: Enverus Valuation Analytics. “FCF Yield” is calculated as 2022E Free Cash Flow/Market Cap. Commodity-price assumptions and market caps are based on market values as of Oct. 28, 2021.

Even in lower price scenarios that are more representative of the market’s long-term expectations, E&Ps’ FCF yields still screen attractive.

2022E FCF Yields at Lower Price Scenarios

Source: Enverus Valuation Analytics. Each data point represents a company’s annualized FCF yield in each quarter during 2022. WTI/HH price scenarios include $50/$2.50, $60/$3, $70/$3.50 and Base Case (Strip).

But short-term FCF yields can only reveal so much about a sector’s overall value. The market is ascribing value to potential growth — or long-term yield sustainability — as indicated by a positive correlation between higher valuation multiples and our estimates for high-quality well inventory lives.

However, accurately estimating inventory remains difficult for investors. We see significant dislocations between market value and intrinsic value at the individual stock level. Attractive relative-valuation opportunities exist for investors willing to invest the time and effort.

Valuation Multiples Versus High-Quality Inventory Life by Basin Peer Group

Source: Enverus Valuation Analytics. Basin peer groups represent groups of E&Ps tagged to a primary basin. “Inventory Life” is calculated as inventory of un-completed wells with a sub-$45 WTI (or sub-$2.25 Henry Hub) half-cycle breakeven/wells completed in next 12 months. “EV / CPV” is calculated as (market enterprise value/current production valuation).

COP26 and the Long Road to Decarbonization

We were curious to see what would happen during this week’s 2021 United Nations Climate Change Conference, or COP26. After all, commitments to net zero emissions need to be coupled with realistic pathways for their delivery, and so far, they have not been.

Previous pledges on climate action have gone unfulfilled and governments have struggled to agree on joint rules for carbon markets. Meanwhile, financial contributions to allow developing countries to move away from carbon-intensive industry have fallen short, prompting deadlines to be extended.

The absence of key heads of state at the conference has caused the prospect of a comprehensive new plan to fizzle. Heads of state from Russia, China and Saudi Arabia have stayed away, aware that in nearly any outcome they will be painted as the villains of the piece. The U.S., the world’s biggest greenhouse gas emitter, is struggling to get key climate measures through congress, undermining President Biden’s capacity to encourage joint action on the international stage.

However, there are reasons for climate campaigners to be hopeful. Net-zero commitments may be distant, but they provide investors with a framework to work with. European commitments to phase out the sales of new internal combustion engine vehicles has prompted the auto industry to reconfigure manufacturing in favor of electric vehicles, and sales have outstripped forecasts, including our own. Europe’s shift to green power generation has produced the same trend, although country by country, the results are uneven.

The shift to decarbonize industrial activity is a rocky road, but the first steps are being taken. Watch how public policy translates into investor behavior because this will be the real test of COP26 in the months and years ahead.

What Drives Exploration Acreage Bid Valuations at Lease Sales?

Accurately understanding bid prices at lease sales is an arduous task for exploration teams. Several variables contribute to a block’s risk and cost, such as the presence of de-risked play concepts, an operator’s confidence in prospect interpretation, proximity to infrastructure, macro environment and political landscape, among others. While some of those factors are subjective and non-disclosed, Enverus analysts explore the objective data points to identify areas and scenarios in which operators are more likely to pay a premium.

As an example, in the Gulf of Mexico 70% of all blocks won at lease sales since 2016 have been within 20 miles of existing production hubs, placing a premium on acreage exposed to the infrastructure-led exploration strategy. Additionally, we estimate tieback acreage is more than two times likely to have multiple bids per block and garners an average of 1.3 times higher bonuses paid than non-tieback acreage. Using Enverus’ GOM lease, geologic, production and economic data sets, we help clients navigate lease sales.

Gulf of Mexico Lease Sale 257 will take place Nov. 17, 2021, the first since the temporary federal lease moratorium was lifted earlier this year.

Inspiring Our Oil and Gas Workforce

We all understand the motivations that drive folks who hunt for treasures. Whether it’s buying extra Powerball tickets, trying to pick the next crypto or biotech winner in the stock market, or even using a metal detector at the beach to find a lost Rolex, we understand.

It’s the allure of making a risk pay off in a big way.

The careers of many oil and gas geoscientists have been made on the foundation of the inherent risk in conventional resource exploration.

Work up a hunch in an area no one’s worked before. Try to confirm it by pulling a bunch of logs and mapping out reservoir thickness and trap structure.  Assess that source, reservoir, seal and trap conditions are satisfied, and then lease the acreage. Confirm it with seismic if need be. Sell it to management or your investment group and then line up a rig.

Get your morning reports on drilling rates, samples and tops, and as you get close to your target pay zone, start looking for reports of oil and gas shows.

Finally, when the well reaches total depth, head out to the location and watch in anxious anticipation as the logging company shows the down log and you get your first look at the log response of the thing you’ve been chasing for months — or maybe even years.

Experience elation. You’ve found producible hydrocarbons that will make money greater — maybe much greater — than your workup, lease and drilling costs.

Or, experience dejection. You, your company or your investment groups risked a bunch of money and came up with nada.

In a weird way, the process was the perfect expression of the digital age — ones and zeroes — before the digital revolution even occurred.

The experience of exploring for oil and gas was both brutal and immensely satisfying. Brutal in the sense that there were no shades of gray. You either made tons money or you lost a lot of money.

But we kept doing it because we were totally captivated and enthralled by the idea of thinking in four dimensions and putting our minds deep in the earth to ferret out where Mother Nature had hidden and locked up hydrocarbons.

And the fundamental assumption that kept prospect generators engaged in the world’s greatest treasure hunt was that our societies always needed more oil and gas.

Fast forward to 2021. Unconventional reservoir development has become firmly entrenched as the dominant method of producing oil and gas in the U.S. Instead of discrete traps of various sizes ranging up to hundreds or even a few thousand acres requiring careful research to identify, unconventional plays like the Eagle Ford in South Texas are prospective over nearly 4 million acres.

And unlike conventional exploration, there are many shades of gray in these plays, ranging from wells with modest returns on investments to money-making superstar wells.

By now, we’re probably all familiar with the current mantra imposed on the industry by the investment community — deliver free cash flow, reduce your debt and live within your means.

So, my question is this: How can that possibly be inspirational for the exploration-minded geoscientists in the upstream workforce that have traditionally been guided to find more?

Maybe they can find inspiration in developing really detailed reservoir models that guide development plans. Perhaps this kind of incremental advancement of reservoir petrophysics and facies developments synchs up with the younger generation’s reported aversion to risk.

Or maybe the fact that they are getting great paychecks to support their future plans is enough.

But from my limited perspective, I always wanted to be inspired to do great things, to work against long odds and succeed. And it’s hard to see how management and C-suites can be truly inspirational for their workforce if they’re messaging management rather than risk taking.

Maybe we can close the circle by inspiring this upstream geoscience workforce to come full circle to identify the best places to store, rather than extract, the fluids and gases that we recognize as harmful to our planet’s climate.

Perhaps creation of true free cash flow will allow some companies to start adding incremental risk to their strategy portfolios by stepping back into conventional exploration to find exceptional fields like Utah’s Covenant Field — nearly 38 million barrels estimated ultimate recovery (EUR) with a median measured depth of 7,150 feet, most of it produced from just over 700 acres.

However accomplished, it’s essential for company leadership to clearly define inspirational goals to keep their workforce engaged, because without an engaged workforce a company can only look forward to long term decline.

Oil Price: What Goes Up …

Low inventories, recovering demand and a muted supply response are behind surging energy prices and rising stock values of producers. Today’s picture looks similar to late 2018, when Brent spiked to ~$85/bbl and prompted bullish calls for $100/bbl oil. But that year, a wave of OPEC and U.S. supply growth hit and U.S./China trade tensions undercut demand expectations. Stock markets sold off heavily and oil prices collapsed into the $50s (Figure 1).

Are high oil prices sustainable this time around? We don’t think so for several reasons. First, OPEC still has plenty of spare production capacity to bring back. Sanctioned Iran has spare capacity in spades. Iraq and the UAE are still pursuing upstream growth plans. Whether through consumer pressure or self-interest, high oil prices will mean more OPEC supply at some point. Second, while the post-COVID-19 recovery is well underway, it’s a bumpy affair. Roughly 70% of populations in emerging economies remain unvaccinated, meaning the pandemic remains a threat to demand recovery. A new wave of infection looks more probable than a colder-than-normal winter. Last, high oil prices will accelerate the transition away from oil to alternatives such as electric vehicles.

So, where are oil prices headed? Forecasting is as much art as science, but we don’t believe $100/bbl is attainable, let alone sustainable. The combination of OPEC+’s effective management of supply and a more disciplined U.S. producing sector suggests a supply-driven collapse that mimics 2018 is unlikely. In conclusion, we think this time around is different. Oil will fall, but barring catastrophic COVID-19 news, the decline should be a soft landing rather than a belly flop.

Learn more about Enverus’ Intelligence solutions here.

FIGURE 1 | Oil Prices in 2018 Versus 2021

Exploring the CCUS Opportunity Set

Over the past few quarters, interest has surged in carbon capture, utilization and storage (CCUS) technology. Policy enhancements are providing a pathway to viable carbon capture business models and have spurred a string of announced projects across the value chain. As companies begin screening for the most compelling opportunities for carbon capture, offtake and storage operations, we believe it is critical to understand emission profiles. This information helps locate and quantify cheap-to-abate emission volumes and identify profitable CO2 reduction opportunities using CCUS.

FIGURE 1 | Carbon Capture Headline Mentions by Quarter

OK, wait … what is CCUS?

CCUS, or carbon capture, utilization and storage, is the process of capturing CO2 from industrial point sources and either sequestering it permanently underground or using it for EOR or the production of other materials, fuels or chemicals. The value chain can be thought of in three segments: carbon capture, transportation and storage in an appropriate sink. Today, CCUS technology is used to capture CO2 emissions from industries such as power generation, natural gas processing, fertilizer production and oil refining.

FIGURE 2 | CCUS Value Chain

 How do we characterize emission profiles?

 The following factors allow us to grade point sources to identify attractive CCUS opportunities:

• Location of point sources.
• Density of point sources.
• Point source CO2 volumes.
• Purity and concentration of CO2 in gas streams.

Why is understanding emission profiles important to CCUS deployment?

At the sector and projects levels, significant deviation in capture cost estimates reflect the varied concentration and purity of CO2 in the processed gas stream. Natural gas processing and ammonia production screen, on average, as some of the lowest capture cost subsectors because CO2 is inherently produced in the process. Iron and steel, power generation and cement manufacturing, on the other hand, are typically the hardest to abate due to the lower concentration of CO2 in the gas streams.

The size and density of stationary sources are also important considerations. CCUS typically favors facilities with higher emissions as economies of scale are more easily reached through lower per-unit transportation and storage costs.

How do these projects actually make money?

Earlier this year, the U.S. federal government expanded and extended its 45Q tax credit to provide increased stability and certainty for CCUS developers and investors alike, and to enhance the economics for both CO2-EOR and permanent sequestration. The tax credit flatlines in 2026 at $35/tonne for CO2-EOR applications and $50/tonne for permanent sequestration. The credit value must be shared across the capture, transportation and storage entities.

FIGURE 3 | Summary of the Internal Revenue Code Section 45Q Credit

In Canada, the carbon tax provides a strong incentive for emission reduction. The regulated price is C$40/tonne CO2 in 2021 and escalates towards C$170/tonne CO2 in 2030.

What’s the size of the prize?

 In 2019, the U.S. and Canada combined emitted nearly 3 billion tonnes of CO2 from stationary sources, about 9% of the global total. As of September 2021, operational CCUS projects capture roughly 23 million tonnes per year (Mtpa) of CO2 across both countries, or less than 1% of 2019 emissions. We believe significant opportunities exist to scale the technology to meet emission reduction objectives.

FIGURE 4 | 2019 CO2₂ Point Source Emissions by Country

Got it! So how do we locate these opportunities?

Through the combined efforts of Enverus ESG Analytics and Enverus Intelligence, we analyzed emission profiles across more than 9,000 facilities to identify top opportunities for CCUS deployment. Factors such as facility location, CO2 volumes and sector were all key considerations leveraged in our analysis. This information is invaluable for infrastructure players, operators and low-carbon investors interested in understanding the CCUS landscape and seeking out the most compelling projects in the space.

We hope that we can show you how our analytics and insights will benefit your workflows. You can book a preview of our solutions with us here. Or fill out the form below and an Enverus Expert will reach out to you!