Category Archives: Bakken Shale

The Bakken Boom Goes Bust With No Money to Clean up the Mess

Desmog, by Justin Mikulka, August 8, 2020
Northwestern ND Aerial Photos  Credit: NDDOT Photos, CC PDM 1.0

More than a decade ago, fracking took off in the Bakken shale of North Dakota and Montana, but the oil rush that followed has resulted in major environmental damage, risky oil transportation without regulation, pipeline permitting issues, and failure to produce profits.

Now, after all of that, the Bakken oil field appears moving toward terminal decline, with the public poised to cover the bill to clean up the mess caused by its ill-fated boom.
Historical Bakken oil production. Energy Information Administration

In 2008, the U.S. Geological Service (USGS) estimated that the Bakken region held between 3 and 4.3 billion barrels of “undiscovered, technically recoverable oil,” starting a modern-day oil rush.

This oil was technically recoverable due to the recent success with horizontal drilling and hydraulic fracturing (fracking) of oil and gas-rich shale, which allowed hydrocarbons trapped in the rock to be pumped out of reservoirs previously unreachable by conventional oil drilling technology.

The industry celebrated the discovery of oil in the middle of North America but realized it also posed a problem. A major oil boom requires infrastructure — such as housing for workers, facilities to process the oil and natural gas, and pipelines to carry the products to market — and the Bakken simply didn’t have such infrastructure. North Dakota is a long way from most U.S. refineries and deepwater ports. Its shale definitely held oil and gas, but the area was not prepared to deal with these hydrocarbons once they came out of the ground.

Most of the supporting infrastructure was never built — or was built haphazardly — resulting in risks to the public that include industry spills, air and water pollution, and dangerous trains carrying volatile oil out of the Bakken and through their communities. With industry insiders recently commenting that the Bakken region is likely past peak oil production, that infrastructure probably never will be built.

Embed from Getty Images

Meanwhile, the petro-friendly government of North Dakota has failed to regulate the industry when money was plentiful during the boom, leaving the state with a financial and environmental mess and no way to fund its cleanup during the bust.

Haste Makes Waste: Booms Move Faster Than Regulations

After the USGS announced the discovery of oil in the Bakken, the oil and gas industry moved fast, with both the industry and state and federal regulators ignoring whether what amounted to essentially new methods of extracting and transporting large amounts of oil called for new rules and protections.

The Bakken’s big increase in oil production quickly exceeded its existing pipeline capacity, leading producers to turn to trucks to move their oil out of the fields. But as the Globe and Mail reported in 2013, this stop-gap solution wasn’t working well: “The trucking frenzy was chewing up roads, driving accident rates to record highs and infuriating local residents.”

The industry could have restricted production until new pipelines and processing equipment were built but instead moved to rail as the next transportation option. High oil prices motivated drillers to get the oil out of the ground and to customers as fast as possible. Moving oil by rail was essentially unregulated and would not require the permits, large investment, or lead times required for pipelines, leading to the Bakken oil-by-rail boom.

Moving large amounts of this light volatile oil on trains had never been done before — but there was no new regulatory oversight of the process. Without proper oversight, the industry loaded the Bakken’s volatile oil into rail tank cars originally designed to carry products like corn oil. That’s despite the National Transportation Safety Board warning that these tank cars were not safe to move flammable liquids like Bakken crude oil.

The industry waved away these warnings. July 6, 2013 marked the first major derailment of a Bakken oil train, resulting in a massive explosion, 47 deaths, and the destruction of much of downtown Lac-Mégantic, Quebec. Bakken “bomb trains” (as train operators called them) continued to derail, creating large oil spills and often catching fire and burning for days. Regulators have still failed to address the known risks for oil trains in the U.S. and Canada. 

Fracking for oil also resulted in large volumes of natural gas coming out of the same wells as the oil, further contributing to the financial troubles of shale producers. However, with no infrastructure in place to process or carry away that gas, the industry chose to either leave it mixed in with the oil loaded onto trains (making it more volatile and dangerous) or simply burn (flare) or release (vent) the potent greenhouse gas into the atmosphere.

More than a decade after the Bakken boom started, North Dakota was flaring 23 percent of the gas produced via fracking — making a mockery of the state’s flaring regulations. In July, The New York Times detailed the environmental devastation caused by flaring in the oil fields of Iraq, where they flare about half of the gas as opposed to the quarter of the gas that North Dakota has flared.

Also in July, researchers at the University of California, Los Angeles and University of Southern California published research that found pregnant women exposed to high levels of flaring at oil and gas production sites in Texas have 50 percent higher odds of premature birth when compared to mothers with no exposure to flaring.

Flare from an oil well in the Permian region of Texas. Credit: © 2020 Justin Hamel

Another major blindspot for the industry and regulators has been the radioactive waste produced during fracking. When the industry did finally acknowledge this issue in North Dakota, its first move was to try to relax regulations to make it easier to dump radioactive waste in landfills — a practice that is contaminating communities across the country.

In 2016, a study from Duke University found “thousands of oil and gas industry wastewater spills in North Dakota have caused ‘widespread’ contamination from radioactive materials…”

The fracking boom in North Dakota has resulted in widespread environmental damage and is worsening the climate crisis, given its high flaring levels, methane emissions, and, of course, production of oil and gas. As major Bakken producers go bankrupt and continue to lose money while the oil field goes bust, who will pay to clean up the mess?

Like most oil-producing states, North Dakota had the opportunity to require oil and gas producers to put up money in the form of bonding which would be designated to properly clean up and cap oil and gas wells once they were finished producing. Unfortunately, the state didn’t put that precaution in place, and now bankrupt companies are starting to walk away from their wells.

It’s starting to become out of control, and we want to rein this in,” Bruce Hicks, Assistant Director of the North Dakota Oil and Gas Division, said last year about companies abandoning oil and gas wells.

The state recently decided to use $66 million in federal funds designated for coronavirus relief to begin cleaning up wells the oil industry has abandoned — costs that the industry should be covering, according to the law, but that are now shifted to the public.

The Bakken boom made a lot of money for a select few oil and gas executives and Wall Street financiers. But as the boom fades, taxpayers and nearby residents have to deal with the financial and environmental damage the industry will leave behind.

Bakken’s Best Days Are a Thing of the Past

As DeSmog reporting has revealed, shale producers have not been profitable for the past decade, even though they have drilled and fracked most of the best available shale oil deposits. While the prolific Permian region in Texas and New Mexico still has some of the best “tier one” core acreage for oil production left, that isn’t the case in the Bakken.

In June, oil and gas industry analysts at Wood MacKenzie highlighted this discrepancy in remaining core acreage between the Permian and the Bakken. According to Wood MacKenzie, the top quarter of remaining oil well inventory in the Permian would result in over 8,000 new wells. For the Bakken, however, the analysts put that number at 333 wells.

This difference is why John Hess, CEO of major Bakken producer Hess Corporation, predicted in January that Bakken production would soon peak.

The drop in oil demand due to the pandemic has hit the industry as a whole, but the Bakken was already in decline, with the best producing wells a thing of the past well before the novel coronavirus reached U.S. shores.

In September 2019, The Wall Street Journal reported on the dismal outlook for Hess Corporation’s oil wells, noting last year: “This year’s wells generated an average of about 82,000 barrels of oil in their first five months, 12 percent below wells that began producing in 2018 and 16 percent below 2017 wells.”

Legal Reviews of Pipelines Potentially Causing Shutdowns

Even when the industry did try to construct oilfield infrastructure in the Bakken, its rush to build and manage pipelines hasn’t always worked out well. Legal challenges to two major Bakken pipelines, one old, one new, may shut down both of them soon.

The controversial Dakota Access pipeline (DAPL) is facing a potential shutdown after a judge ruled that the Army Corps of Engineers did not properly address oil spill risks and now must complete a full environmental review, which could result in a long-term shutdown of the pipeline while the Corps completes the study. Energy Transfer, DAPL‘s owner, appealed that ruling, and a subsequent court decision has allowed the pipeline to remain in operation while the legal battle over the environmental impact study continues.

At the same time, the Tesoro High Plains pipeline — in operation since 1953 — is facing a shutdown because it failed to renew an agreement with Mandan, Hidatsa, and Arikara Nation landowners on the Fort Berthold Indian Reservation, meaning the pipeline’s owner, Marathon, now is trespassing on that land.

These pipelines together ship more than one-third of the oil out of the Bakken, and if they are shut down, Bakken oil producers likely would turn to rail again to move their oil. However, rail is significantly more expensive than pipelines and not economically viable at current low oil prices.

However, at current production levels, existing pipelines (other than the two in question) and current long-term rail contracts can likely handle most of the Bakken’s oil production, especially as the region becomes less attractive to investors.

Energy consulting group ESAI Energy recently released a new report on U.S. pipelines, with analyst Elisabeth Murphy concluding, “An uncertain outcome for Dakota Access will have knock-on effects for the Bakken, such as capital being diverted to other basins that have better access to markets.”

The ESAI analysis also concludes that the Bakken will decline by approximately 270,000 barrels per day on an annual basis in 2020 and by a further 65,000 barrels per day in 2021.

With declining total production and new wells producing less than the past, Bakken producers are facing rising debts without the means to pay them back.

End of the Unconventional Bakken Boom

Oil produced by fracking is called “unconventional oil” due to the new technologies used to extract it from shale. However, it is unconventional in other ways as well. One, it has never been profitable. Another is a change in the boom-and-bust cycle, which has been a part of the oil industry since its inception in the U.S. in the 1850s.

Traditionally the boom-and-bust cycle for conventional oil production was tied to the price of oil. Low prices caused busts. This was true of the shale oil industry in 2014 when oil prices crashed. However, the industry returned to record production after that.

Williston "Rockin' the Bakken" marketing slogan
Screen shot of a marketing slogan for Bakken oil and gas development. Source: https://willistondevelopment.com

But it’s different this time. Unlike conventional oil fields, shale field production declines much more quickly. While shale producers could retreat to the top-producing acreage during the 2014 bust, most of that acreage is now gone.

The shale industry is faced with trying to come back from a historic downturn in which even the companies that don’t go bankrupt are saddled with crippling debts. That’s because for most of the past decade, shale companies borrowed more money than they made producing fracked oil and gas, to the tune of hundreds of billions of dollars.

All of the evidence strongly suggest that the Bakken is an oil field on the decline. Its best acreage has been depleted and the economics of the remaining acreage don’t pan out these days.

Reviewing the economics of the Bakken, investment site Seeking Alpha recently concluded that the “Bakken Will Never Be The Same Again.”

Seeking Alpha was purely commenting on the economics of oil production in the Bakken. However, the same could be said about the water, air, and land in the Bakken. Shale companies polluted the environment and are now walking away from the damage — leaving the cleanup bill to the public. It is a tried-and-true approach for industries in resource extraction. Privatize the profits and socialize the losses.

Hess Corporation CEO John Hess knows more about the economics of the Bakken than most people. In February Reuters reported, “Hess plans to use cash flow from the Bakken to invest in longer-term offshore investments.” A major Bakken producer is apparently no longer viewing the region as a good long-term investment.

From here, the outlook only gets worse for the Bakken.

Main Image: Northwestern ND Aerial Photos  Credit: NDDOT PhotosCC PDM 1.0 

Hard times ahead for Bakken oil industry – maybe the end?

Why The Bakken May Not Come Back

OilPrice.com, by Nick Cunningham, Jul 07, 2020

The Bakken shale is already declining because of financial struggles and the oil market downturn, but the potential shuttering of the Dakota Access pipeline could close off the possibility of a rebound.

The 570,000-barrel-per-day oil pipeline carries Bakken oil to the Midwest. On Monday, a federal judge ordered the pipeline to shut down within 30 days after vacating authorization for the project. Energy Transfer immediately appealed for a “provisional stay,” but on Tuesday, U.S. District Court Judge James Boasberg shot down that request.

Energy Transfer will still file a conventional appeal to stay the judge’s order, and surely the company will follow through on that as quick as possible. But it’s not clear how quickly the judge will respond to that; meanwhile he ordered Dakota Access to be drained by August 5.

Even if a stay is granted, the pause could be “short-lived,” ClearView Energy Partners wrote in a note to clients. The firm cited a separate case involving an electric transmission line that resulted in the Army Corps of Engineers being forced to undertake an environmental impact statement after the project was completed.

“Put another way, even conservative jurists can back a court ruling that finds agency environmental reviews flawed and should be suspended while redone,” ClearView Energy Partners wrote. “[T]he horizon for Dakota Access may be darkening,” the firm added.

Assuming that Dakota Access goes offline and undergoes an environmental assessment, which could take the better part of a year, the process will drag on into a potential Joe Biden administration. At that point, the Army Corps, under a new direction, may change its stance, killing off the pipeline.

Time will tell, but in the interim, the temporary closure is an enormous victory for the Standing Rock Sioux Tribe. “This pipeline should have never been built here. We told them that from the beginning,” the Tribe’s Chairperson Mike Faith said.Related: China Inks Military Deal With Iran Under Secretive 25-Year Plan

If Dakota Access is forced to shut down for good, it could head off any hopes on the part of the oil industry to revive production in the Bakken. Without the pipeline, a large portion of Bakken production would need to return to the practice of moving large volumes by rail.

“I think everybody is forming their game plan now, and if they have tank cars, they’re probably thanking their lucky stars,” one source familiar with Bakken rail operations told Reuters.

However, a sudden rush of shipping oil-by-rail will increase the risk of derailments and explosions. Early on in the Bakken shale boom, it was all too common for oil trains to derail and explode, earning them the nickname of “bomb trains.” A return of oil train shipments would increase safety risks.

Meanwhile, because putting oil on rail is more costly, Bakken crude would need to be discounted for the process to make sense.

Already, the region is seeing a larger discount. Shortly after the court decision ordering Dakota Access to shut down, the price of Bakken oil at the hub of Clearbrook, Minnesota declined. Relative to WTI, the discount widened from $1.15 per barrel to $2.75 per barrel, according to Bloomberg, which was the largest markdown since May.Related: The Death Of The $2 Trillion Auto Industry Will Come Sooner Than Expected

The Bakken was already slowing down before the pandemic. Years of red ink from shale drillers soured investors on the whole fracking enterprise, but that is particularly true in the Bakken. For example, Continental Resources, which has a prominent presence in the Bakken, saw its stock price fall in half between late 2018 and late 2019.

Bakken production hit a peak in October and November of last year at just over 1.5 million barrels per day (mb/d), before declining to 1.43 mb/d in February, just before the global pandemic rocked the market.

Because the North Dakota region has much less storage capacity than Texas and Oklahoma, Bakken drillers were immediately squeezed when the market went into a tailspin, forcing them to shut in thousands of wells. The EIA expects production from the Bakken to dip below 1 mb/d in July.

A source at one unnamed Bakken oil producer said that the region’s total production will need to decline to 950,000 bpd in August if Dakota Access shuts down. At the start of this week, Continental’s share price is off by more than 15 percent, a reflection of the negative impact of the DAPL shutdown.

“Production of crude oil is going to be landlocked in North Dakota,” Sandy Fielden, director of oil and products research at Morningstar, told Reuters. “It’s going to be congested and that’s going to cause discounts in the price of Bakken crude to WTI.”


More Top Reads From Oilprice.com:

UPDATE: Latest on West Virginia derailment, explosion

Two recent stories in the media:

1.  WEST VIRGINIA METRO NEWS: No change for CSX, Bakkan oil will continue to roll through area where derailment took place
By Chris Lawrence, February 27, 2015 at 2:47PM

MOUNT CARBON, W.Va. — There will be another CSX train carrying Bakkan oil going through eastern Kanawha and Fayette counties soon now that the track has been repaired following the Feb. 19 derailment of an oil train near Mount Carbon.

“It’s part of the freight that goes over that line,” CSX Spokesman Gary Sease told MetroNews Friday. “Those shipments, along with all the other freight we haul, have resumed.”

The rebuilt line, just a few miles from Montgomery, reopened Thursday afternoon following a week long cleanup.  [CONTINUED]


2.  PBS NEWSHOUR: Fiery train wrecks put pressure on safety standards for oil transport
February 27, 2015 – 8:43am
A combination photo shows a sequence of an explosion erupting from a CSX Corp train derailment in Mount Carbon, West Virginia pictured across the Kanawha River in Boomer, West Virginia February 16, 2015. Photo by Steve Keenan/Reuters

WASHINGTON — Fiery wrecks of trains hauling crude oil have intensified pressure on the Obama administration to approve tougher standards for railroads and tank cars despite industry complaints that it could cost billions and slow freight deliveries.

On Feb. 5, the Transportation Department sent the White House draft rules that would require oil trains to use stronger tank cars and make other safety improvements.

Nine days later a 100-car train hauling crude oil and petroleum distillates derailed and caught fire in a remote part of Ontario, Canada. Less than 48 hours later, a 109-car oil train derailed and caught fire in West Virginia, leaking oil into a Kanawha River tributary and burning a house to its foundation. As the fire spread across 19 of the cars, a nearby resident said the explosions sounded like an “atomic bomb.” Both fires burned for nearly a week.  [CONTINUED]


Wall Street Journal: Big Oil Feels the Need to Get Smaller

Repost from The Wall Street Journal

Big Oil Feels the Need to Get Smaller

Exxon, Shell, Chevron Pare Back as Rising Production Costs Squeeze Earnings
By Daniel Gilbert and Justin Scheck, Nov. 2, 2014
Shell_Ft.McMurrayAlberta_Bbrg500
Extracting oil from Western Canada’s oil sands, such as at this Shell facility near Fort McMurray, Alberta, is a particularly expensive proposition. Bloomberg News

As crude prices tumble, big oil companies are confronting what once would have been heresy: They need to shrink.

Even before U.S. oil prices began their summer drop toward $80 a barrel, the three biggest Western oil companies had lower profit margins than a decade ago, when they sold oil and gas for half the price, according to a Wall Street Journal analysis.

Despite collectively earning $18.9 billion in the third quarter, the three companies— Exxon Mobil Corp. , Royal Dutch Shell PLC and Chevron Corp. —are now shelving expansion plans and shedding operations with particularly tight profit margins.

The reason for the shift lies in the rising cost of extracting oil and gas. Exxon, Chevron, Shell, as well as BP PLC, each make less money tapping fuels than they did 10 years ago. Combined, the four companies averaged a 26% profit margin on their oil and gas sales in the past 12 months, compared with 35% a decade ago, according to the analysis.

Shell last week reported that its oil-and-gas production was lower than it was a decade ago and warned it is likely to keep falling for the next two years. Exxon’s output sank to a five-year low after the company disposed of less-profitable barrels in the Middle East. U.S.-based Chevron, for which production has been flat for the past year, is delaying major investments because of cost concerns.

BP has pared back the most sharply, selling $40 billion in assets since 2010, largely to pay for legal and cleanup costs stemming from the Deepwater Horizon oil spill in the Gulf of Mexico that year.

SqueezePlaysWSJ.500

To be sure, the companies, at least eventually, aim to pump more oil and gas. Exxon and Chevron last week reaffirmed plans to boost output by 2017.

“If we went back a decade ago, the thought of curtailing spending because crude was $80 a barrel would blow people’s minds,” said Dan Pickering, co-president of investment bank Tudor, Pickering, Holt & Co. “The inherent profitability of the business has come down.”

It isn’t only major oil companies that are pulling back. Oil companies world-wide have canceled or delayed more than $200 billion in projects since the start of last year, according to an estimate by research firm Sanford C. Bernstein.

In the past, the priority for big oil companies was to find and develop new oil and gas fields as fast as possible, partly to replace exhausted reserves and partly to show investors that the companies still could grow.

But the companies’ sheer size has meant that only huge, complex—and expensive—projects are big enough to make a difference to the companies’ reserves and revenues.

As a result, Exxon, Shell and Chevron have chased large energy deposits from the oil sands of Western Canada to the frigid Central Asian steppes. They also are drilling to greater depths in the Gulf of Mexico and building plants to liquefy natural gas on a remote Australian island. The three companies shelled out a combined $500 billion between 2009 and last year. They also spend three times more per barrel than smaller rivals that focus on U.S. shale, which is easier to extract.

The production from some of the largest endeavors has yet to materialize. While investment on projects to tap oil and gas rose by 80% from 2007 to 2013 for the six biggest oil companies, according to JBC Energy Markets, their collective oil and gas output fell 6.5%.

Several major ventures are scheduled to begin operations within a year, however, which some analysts have said could improve cash flow and earnings.

For decades, the oil industry relied on what Shell Chief Financial Officer Simon Henry calls its “colonial past” to gain access to low-cost, high-volume oil reserves in places such as the Middle East. In the 1970s, though, governments began driving harder bargains with companies.

Oil companies still kept trying to produce more oil, however. In the late 1990s, “it would have been unacceptable to say the production will go down,” Mr. Henry said.

Oil companies were trying to appease investors by promising to boost production and cut investment.

“We promised everything,” Mr. Henry said. Now, “those chickens did come home to roost.”

Shell has “about a third of our balance sheet in these assets making a return of 0%,” Shell Chief Executive Ben van Beurden said in a recent interview. Shell projects should have a profit margin of at least 10%, he said. “If that means a significantly smaller business, then I’m prepared to do that.”

Shell late last year canceled a $20 billion project to convert natural gas to diesel in Louisiana and this year halted a Saudi gas project where the company had spent millions of dollars.

The Anglo-Dutch company also has dialed back on shale drilling in the U.S. and Canada and abandoned its production targets.

U.S.-based Exxon earlier this year allowed a license to expire in Abu Dhabi, where the company had pumped oil for 75 years, and sold a stake in an oil field in southern Iraq because they didn’t offer sufficiently high returns.

Exxon is investing “not for the sake of growing volume but for the sake of capturing value,” Jeff Woodbury, the head of investor relations, said Friday.

Even Chevron, which said it planned to increase output by 2017, has lowered its projections. The company has postponed plans to develop a large gas field in the U.K. to help bring down costs. The company also recently delayed an offshore drilling project in Indonesia.

The re-evaluation has also come because the companies have been spending more than the cash they bring in. In nine of the past 10 quarters, Exxon, for example, has spent more on dividends, share buybacks and capital and exploration costs than it has generated from operations and by selling assets.

Though refining operations have cushioned the blow of lower oil prices, the companies indicated that they might take on more debt if crude gets even cheaper. U.S. crude closed Friday at $80.54 a barrel.

Chevron finance chief Patricia Yarrington said the company planned to move forward with its marquee projects and is willing to draw on its $14.2 billion in cash to pay dividends and repurchase shares.

“We are not bothered in a temporary sense,” she said. “We obviously can’t do that for a long period of time.”