Oil and gas drilling in Colorado hit a historic low in May with only six drill rigs operating and an average for the month of seven drilling platforms – the fewest in the 28 years that oil field services company Baker Hughes has kept monthly records by state.
In the Denver-Julesburg/Niobrara Basin, which extends along the Front Range into southern Wyoming, seven rigs were operating mid-May the lowest level in Baker Hughes’ basin database since it began in February 2011.
The combination of plunging oil prices – set-off in part by a brief price war between Saudi Arabia and Russia – and a collapse in demand due to the novel coronavirus pandemic shutting down economies has roiled the industry worldwide and led to an oil glut.
In addition, in Colorado the industry is facing a sweeping revision of oil and gas and air emission regulations, required by laws passed in 2019.
“Those three things have been devastating for the state,” said Lynn Granger, executive director of the Colorado Petroleum Council, a trade group. “It happened so quickly it took the market some time to react.”
Additional pressure has been put on many operators who ran up heavy debts and even before the crash were struggling to post positive cash flow – a situation worrying to investors.
The combination of horizontal drilling – with lateral wells as much as 3-miles long – and hydrofracturing, or fracking, freed oil and gas from tight shale deposits and set-off the shale boom and a frenzy in both investing and drilling. In 2019, the U.S. was the world’s largest oil producing country, with an output of 12 million barrels per day.
“You had some companies that had several years of poor capital allocation and diminishing liquidity and lack of access to capital markets, before this hit,” said Tyler Hoge, a financial analyst with Enverus, an industry analytics firm.
Colorado is not alone. The Baker Hughes rig count for the U.S. plunged to 339 in May, also a historic low, having dropped from 779 rigs on March 15. In Texas’ Permian Basin, the country’s largest oil producing region, 243 rigs have been shut since March – 57% of all the rigs in the 86,000 square-mile basin.
As recently as March 20, there were 21 rigs operating in Colorado, according to Baker Hughes. In May of 2019, there were 33.
Boom, bust cycle is familiar
The oil and gas industry is used to boom and bust cycles – adding rigs when oil prices are high and shutting them down when they are low. The lowest monthly average for Colorado rigs before this month was 11 in September 1995.
Colorado hit a low of 16 rigs when the price for West Texas Intermediate (WTI) crude oil, the U.S. benchmark, dropped to $29.13 a barrel in January 2016, down from $107 a barrel in June 2014.
The NYMEX spot price for a barrel of WTI crude was $31.91 on May 29, a roughly 40% drop in 14 weeks – prices had plummeted to as low as $11.26 a barrel in April.
There is, however, a big difference between the last downturn and this one, industry analysts say. First, the 2014-16 price decline was gradual – spread over about 18 months, and, second, these exploration and production companies (E&Ps) were financially healthier.
In 2016, “E&Ps had the ability to raise capital or take on debt. That ability is gone now,” said Matt Hagerty, an analyst with BTU Analytics. “The situation was bad before everything that has happened this year.”
Absent an infusion of cash and faced with debt, drillers are cutting operations and expenditures, shutting in wells and trying to avoid running in the red, while posting positive cash flow through existing wells. This is what is leading to the low level for activity in the state.
“Cash flow is number one,” Hoge said. “Operators want to come out of this, despite everything that happened in 2020, saying we came out with cash flow positive.”
The major companies operating in the state did not respond to a Colorado Sun request for comment, but the publicly traded ones made their plans clear in May earnings calls.
Houston-based Occidental Petroleum Co. was the largest oil producer in the state in 2019, according to Colorado Oil and Gas Conservation Commission data, primarily as a result of its $55 billion acquisition, including debt, of the Anadarko Petroleum Corp.
That merger, however, left Occidental shouldering an estimated $31 billion in debt, according to Enverus. This has led to slashing employee salaries, including top executives’, cutting dividends and selling assets.
Occidental cut its capital budget for the Rockies, which includes drilling and project development, to $300 million from $900 million.
The company is halting exploration and development of new wells and plans to shut-in 9% of its producing wells, with about a third of those in Colorado. Occidental has about 4,700 wells in the state, according to a federal filing.
Capital budgets slashed by half
Houston-based Noble Energy, the state’s second biggest oil producer, has slashed its overall capital budget, which includes drilling, by $900 million – a 50% cut.
“All completion activity has been suspended, and drilling activity has been reduced to one rig in the DJ Basin,” Brent Smolik, Noble’s chief operating officer, told analysts in a May 8 conference call. “The plan includes $75 million to $100 million for the option to complete DJ wells in the fourth quarter.”
The first set of wells Nobel plans to shut in will be lower-productivity wells that don’t cover the cost of operating them. In addition some more productive wells also will be closed “for better value in future high-price environments,” Smolik said.
Shale wells produced the majority of their oil in the first two years of operation. “Anybody who is producing a solid amount of oil in their wells, they are almost taking a loss at these prices in April and May,” Hagerty said.
Denver-based PDC Energy was the state’s third largest oil producer in 2019. In its first-quarter earnings call with analysts, CEO Barton Brookman Jr. said the capital budget has been cut 50% to between $500 and $600 million.
“This is the slowest capital pace for the company in many, many years,” Brookman said. PDC Energy will operate one rig in Colorado this year and no fracking crews.
The company also expects to shut-in 20% to 30% of its wells over the next few months – at least until prices improve later in the year.
“We look forward to getting back to the new normal one of these days,” Brookman told analysts.
Among the other operators active on the Front Range, Extraction Oil and Gas Inc. CEO Matt Owens, in a first-quarter earnings call, said that the company is releasing its drilling and fracking crews, and completing just one well in Greeley.
Scot Woodall, CEO of Denver-based HighPoint Resources, said his company was deferring all capital and completion activities until prices improve and preparing for the possibility of shut-ins. Denver-based Bonanza Creek Energy said in its first quarter earnings release this month that all drilling and completion activity had stopped.
Denver-based Whiting Petroleum filed for bankruptcy protection and reorganization on April 1. It is one of 17 shale drillers nationally that have filed for bankruptcy so far this year and the number could reach more than 70 if WTI prices linger around $30 a barrel, according to Oslo-based industry analyst Rystad Energy.
“Bonanza, HighPoint and Extraction are struggling because of the liquidity issue,” Hoge said.
In its May 4 earnings call, HighPoint Resources said it was still awaiting negotiations with its bank lenders on its credit status but expected its borrowing base to be reduced by about 40%.
In April, Extraction Oil and Gas lenders cut the company’s borrowing base by 32% to $650 million, Marianella Foschi, the company’s vice president of finance, told analysts. Extraction is carrying about $2.8 billion in debt according to Enverus.
“The biggest question isn’t whether you will hit free cash flow, but how will you survive?” Hoge said.
To some extent, operators are protected from the low prices by hedges, a kind of insurance policy that makes up the difference between the market price and a target price. Many of the Colorado producers have at least part of their oil hedged at $50 a barrel or more.
Many of those hedges, however, run out in 2021, and if market oil prices remain low, the impacts could be severe. “Producers are a lot less protected in 2021 than they are today, Hagerty said. “That could hit cash flow and speed up the process for a lot of losers … Everything could really accelerate.”
While oil prices and balance sheets will have the final say in how companies fare, Colorado industry advocates contend this is the wrong time to undertake massive rulemakings.
“It’s one uncertainty we face in Colorado that a lot of the other regions don’t have,” Hagerty said.
The COGCC has delayed its overhaul of nine sections of its rules until late summer and early fall, while the Colorado Air Quality Control Commission has already adopted regulations on oil and gas emissions and greenhouse gas emissions.
“What we need is a moment to catch our breath,” said Dan Haley, president of the Colorado Oil and Gas Association, a trade group. “There are now, quite literally, more rulemakings taking place in Denver, during a pandemic, than there are rigs operating in the state.”
CORRECTION: This story was updated June 1, 2020, at 9:35 a.m. to correctly identify Noble Energy’s chief operating officer Brent Smolik, and to properly attribute the company’s capital investment plans in Colorado.
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