June 2020, Vol. 247, No. 6


Midstream Making Sense of Ongoing Coronavirus Shockwaves

By Richard Nemec, Contributing Editor

On Easter Sunday when all of America’s churches were silent, President Trump, who earlier had wished they could be filled with worshipers, was helping broker a final oil production agreement among nearly two dozen producing nations as a way of easing the global glut of crude at a time when the coronavirus (COVID-19) had eliminated millions of barrels of daily demand. 

For the American leader it was a significant move globally and domestically to help heal a U.S. economy that had been brought to a standstill by COVID-19 mitigation measures.

If there was ever a clear intersection between COVID-19 and a shocked oil and natural gas sector, it was this unexpected milestone that ended an oil price war between Russia and Saudi Arabia. 

How far that will go toward easing the malaise in the U.S. oil patch was not clear in April when this report was being put together, and national, state and local government and public health professionals were trying to reign in the virus.

Later in the spring, Trump’s administration and U.S. Senate Republicans were working on some sorts of relief for the oil and gas operators in the form of loans, tariffs on foreign imports or buying more supplies for the strategic oil reserve.

The Washington, D.C.-based American Petroleum Institute (API) published an “early glimpse” of COVID-19’s impact on energy markets in February ahead of the nation’s lockdown response. API’s numbers crunchers foresaw lower jet fuel and diesel deliveries in February, slow supply growth, a final month of strong U.S. crude exports, and a convergence of U.S. and global prices.

There were few redemptive indicators at that time with exploration and production (E&P) companies of all sizes leading the way in slashing capital expenditures (capex), laying off workers, shutting in wells and pulling rigs from the major producing basins.

El Dorado, Ark.-based independent Murphy Oil Corp.’s CEO Roger Jenkins contracted the virus, took medical leave and returned to his job in mid-April to find a sea of cutbacks and a continuing hunkering down by the industry. 

One of the nation’s largest oilfield service operators, Houston-based Baker Hughes cut its capex 20% from the $1.24 billion level in 2019, and it took a $15 billion impairment charge in 1Q2020 after writing down the value of its oilfield services and equipment due to low commodity prices.

On a first-quarter earnings conference call in April, the CEO of multibillion-dollar global oilfield services giant Schlumberger indicated that getting through and learning about the second quarter this year is essential to longer term viability in the industry. Schlumberger’s CEO Olivier Le Peuch called this financial quarter “likely to be the most uncertain and disruptive the industry has ever seen.” 

Le Peuch reported declines in revenues in each of its business segments and in all of the areas of the world where it operates. He reported a “sequential international revenue decline” sparked by lower winter activity in many areas and COVID-19.

While investment bank analysts were speculating that the OPEC+ agreement was “too little, too late,” Schlumberger and others were bracing for a second quarter in which U.S. oil prices fall faster than global Brent-priced production. When Le Peuch gave his first-quarter earnings report, West Texas Intermediate (WTI) prices hit $18/bbl during a week in which the U.S. rig count fell from 602 to 529 before crashing below zero on May futures contracts April 20.

“A mind-blowing carnage” is how the historic event seemed to Jim Krane, the Wallace S. Wilson Fellow for Energy Studies at Rice University’s Baker Institute for Public Policy. “U.S. oil prices make little sense in physical terms. Is anyone actually going to pay $30 or $40/bbl to get rid of a barrel of crude oil? I doubt it. But with storage full, there’s no way to take delivery of these end-of-period physical shipments,” he said.

In a blog in April, API CEO Mike Sommers argued for a U.S. policy that doesn’t make the situation worse, following OPEC+ and the virus. Sommers thinks more U.S. cutbacks and/or tariffs to protect domestic gas and oil would be counterproductive. “Tariffs hamstring U.S. energy projects by increasing the costs of imported production materials.”

Given the global cutbacks now in place, associated gas supplies also have to be expected to go down accordingly. A rough measure is that for every 500,000 bpd of oil production, associated gas equals about 1 Bcf/d (28 MMcm/d). “Considering the depth and duration of the global oil situation, we could see an 8-Bcf/d [227-MMcm] reduction in associated gas,” said IHS Markit’s Narmadha Navaneethan, director for North American upstream research, adding that associated gas represents a third of the U.S. production at 31 Bcf/d (878 MMcm).

Before Easter, IHS Markit’s Yergin had labeled the global pullback the “Big Cut,” putting a $24.4 billion price tag on it for all of 2020 compared to the previous year. Yergin emphasized that the collapse in world oil demand and low prices are driving large spending cuts among companies worldwide. North American E&Ps, he notes, are making the largest cuts as a percentage of their overall capex budgets, slashing spending overall by 36%. 

As the debate and analysis widened, it became clear that the pullback should cover all of North America, including previous robust investments in Mexico that will dry up.

North American oil and natural gas producers quickly stomped hard on the brakes in the face of the combined global effect of the COVID-19 pandemic and the first-quarter global oil price war. 

Before Easter, industry estimates were putting the horizontal oil rig count, an important measuring stick for investment interest, on track to fall by about 65% from mid-March levels. Rig counts also are considered a key metric to consumer confidence in the oil patch. And, from the mid-March total of 620 rigs, the count was projected to fall to about 200.

Based on updated guidance from E&P companies, most of the anticipated decline was expected by the end of April. The horizontal rig count so far had dropped to roughly 500 in early April, falling by 19% in three weeks. The oil drilling crash in April was on track to result in the largest monthly decline in completions activity ever recorded in the U.S. oil patch, as the amount of hydraulic fracturing (fracking) dipped below 300 wells nationally. Estimates called for 200 wells being impacted by the decline in the Permian Basin, along with less than 50 wells each in the Bakken and Eagle Ford shales.

In North Dakota where rig counts plummeted in March and April, state officials rushed to establish waivers to the requirements that wells will be completed within a 12-month period. Knowing that they were facing a rash of shut-ins and inactive wells as the number of uncompleted wells climbed, a statewide industrial commission headed by the governor established one-year, renewable waivers for new wells that, under normal conditions, are required to be operated or abandoned within one year. 

Within a few weeks of that action, the state was pursuing a large build-out in oil storage to help prop up the Bakken Shale production that was nearing 1.5 MMbpd before the virus and global market woes hit.

“Companies are looking at building large tank farms made up of mostly off-the-shelf 400-barrel tanks,” said Lynn Helms, director of the State Department of Mineral Resources. “The companies have a series of permits they have to go through, along with construction and commissioning.” 

Helms indicated at least two developers were eyeing up to 300,000- to 500,000-bbl capacity tank farms, and they anticipated erecting them within weeks once they had permits. 

Later in April when the oil future’s market prices dipped below zero, the administration directed the Departments of Energy and Treasury to develop a program that will make federal funds available to struggling oil and gas companies. Production state congressional representatives also were engaged in talks related to the issue of aide to energy companies.

On the distribution (retail) side of the natural gas business that touches most U.S. consumers, the American Gas Association (AGA) has been tracking its member utilities’ response to COVID-19. Delivering gas to homes and businesses, of course, is designated “essential,” so field and office employees alike have carried on in the face of COVID-19’s scourge. 

“Gas utilities always do everything necessary to deliver essential energy to homes and critical businesses, such as hospitals, senior centers and food distributors, but as we experience today’s pandemic, it is even more apparent how important this is,” said AGA’s spokesman Jake Rubin.

Before entering a home, field service workers ask if anyone in the household has COVID-19 or has symptoms for the virus. This probing is needed in these times to keep utility employees, their coworkers, families and the community at large safe, Rubin noted. “Our industry never expected to be operating in this type of global pandemic, but we have seen over the past month that many of the lessons we learned working through other challenges and holding regular crisis drills have served us well,” he said.

An industry best practice relied on heavily in the lockdown is the establishment of incident command structures to put in place a “standardized hierarchical system,” encouraging cooperative responses across a utility’s various departments, Rubin said. In theory, it helps organize and coordinate response activities and streamline decision-making, a model created way before anyone knew about COVID-19.

Research/analytics firms such as Wood Mackenzie (WoodMac) and Tudor, Pickering, Holt & Co. (TPH) were calling out many of the endangered E&Ps that put U.S. crude production at risk, given the numbers of distressed companies tied to the bulk of the nation’s reserves. 

They cited excessive debt, tightened capital markets and even tighter bank lending standards as an unhealthy stew for the E&P sector. TPH analysts estimate 2.3 MMbpd of supply is held by distressed producers, accounting for a “notable 22% of total onshore U.S. production.”

Not all of the distressed E&Ps are expected to go into decline, but “We’re likely to see meaningful output decline ... in 2020-21.” In TPH’s update in December covering a group of 50 E&Ps, the biggest contributors at risk were listed as California Resources Corp., Chesapeake Energy, Oasis Petroleum and Whiting Petroleum. Subsequently, the analyses added another half-dozen major shale gas producers, among others.

In its Short-Term Outlook in April, the U.S. Energy Information Administration (EIA) openly talked about “heightened levels of uncertainty” surrounding any energy industry projections this year, given COVID-19’s unrelenting impact on energy markets. On April 7, EIA analysts saw that impact as “still evolving.” According to EIA, the virus has changed energy supply/demand patterns, and crude prices have crashed from the loss of demand to the virus at the same time a global glut of supply was worsening.

EIA’s outlook came before the OPEC+ agreement, so the uncertainty was still particularly acute. The agreement will now be factored in as part of the next short-term projections. “EIA forecasts that the United States will return to being a net importer of crude oil and petroleum products in the third quarter of 2020 and remain a net importer in most months through the end of the forecast period. This is a result of higher net imports of crude oil and lower net exports of petroleum products,” EIA’s outlook notes. 

As May neared, the same crash in global oil demand enveloped natural gas with EIA noting a 43-Bcf (1.2-Bcm) storage injection for a week in mid-April, which was more than half the 92-Bcf (2.6-Bcm) injection for the same week in 2019. May and June Nymex gas futures contracts shrank below $2/Mcf, and spot prices were even lower in the $1.70/Mcf range. 

Richard Nemec is P&GJ’s correspondent based in Los Angeles. He can be reached at rnemec@ca.rr.com

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