CSIS conference examines US shale oil’s short-term pluses, minuses

Speakers at a day-long conference examining US shale oil’s short-term prospects repeatedly turned to Permian basin operations as examples of progress despite lower crude oil prices as operators reduced costs. But those same producers could face problems if transportation capacity doesn’t increase and local opposition mounts, other speakers said during the Feb. 27 event at the Center for Strategic & International Studies.

Speakers at a day-long conference examining US shale oil’s short-term prospects repeatedly turned to Permian basin operations as examples of progress despite lower crude oil prices as operators reduced costs. But those same producers could face problems if transportation capacity doesn’t increase and local opposition mounts, other speakers said during the Feb. 27 event at the Center for Strategic & International Studies.

“The key issue here is that the market has shifted from resource shortages where oil prices would be higher in the future to a view where there ultimately is no resource limitation because producers can recover as much as they want with shale technology,” said Paul B. Sankey, a managing director and senior oil and gas analyst at Wolfe Research LLC. “That ultimately has led to the view that they no longer look at the finding portion of finding and development costs. That’s huge.”

Recognition that higher crude prices are no longer inevitable has led Pioneer Natural Resources, Devon Energy Corp., and other independents to abandon their previous growth-for-growth’s-sake strategies and pursue approaches that provide a 10% return to shareholders in the next 3 years, Sankey said. “Many will need to change their pay structures,” he said. “The oil sector sell-down has raised the cost of capital and led shareholders to demand this. As they do, there will be more cash returned, which will be a strong positive for the sector.”

Jan Stuart, who leads the energy macro team at Cornerstone Research Macro LLC, said underlying fundamentals are tightening. “Supply growth needs to catch up with demand, which continues to grow,” he said. “We think we’ll end 2018 in a deficit, with prices around $60/bbl, which we consider normal. So there is room to grow for US shale. If these companies can make money at $50/bbl and are now beginning to consolidate, US crude oil production could go to the moon, through the roof, or whatever expression you prefer. We have growth targets of 2 million b/d this year and next, and some significant amounts of natural gas liquids growth as well.”

Stuart said US production at $60/bbl could get crude oil from shale above 8 million b/d by yearend 2019. “Give me a $65/bbl price, and it could be close to 10 million b/d,” he said. “We are in a growth-plus phase that the equity markets may be lively to reward. I would posit that E&P companies in the Permian basin are going to benefit.” Of the 17 US upstream independents that Cornerstone believes are poised to grow, 12 are in the Permian, he noted.

Distributing returns on capital

“These companies are about to become very profitable, reinvesting dollars into a very large resource base. From a big picture standpoint, this industry has begun to consolidate,” said Stuart. “Companies are moving beyond merely doing asset deals but haven’t started to do corporate takeovers. But the majors are moving in, and companies are starting to sing from a hymn sheet that advocates returns on capital being distributed rather than plowed into the ground.”

Roger Diwan, vice-president for financial services at IHS Markit, said, “Money has played an incredible role in allowing this boom in shale production. If you had been here a year ago and I’d told you that [West Texas Intermediate, the US benchmark crude] was going to average $51/bbl in 2017 and had been asked how much shale production was going to grow in the US during that period, the consensus was 300,000-400,000 b/d. It actually grew about 1.2 million b/d.”

Diwan said, “This has to do less with oil prices than finance. The US shale resource endowment really is one of the worst you can think of. What made it possible to produce was the availability of money for risk that made people willing to try things to make it happen. It was the merger of 2 industries: oil, which was resource-poor in the US, and capital.”

Credit, equity, and private equity markets fund different parts of US upstream independents, and have different dynamics and returns, Diwan said. Linkage between a very sophisticated financial sector and a very large and entrepreneurial energy sector means that shale resources will continue to be funded as long as returns remain positive with prices close to $45-50/bbl, he said.

Diwan said that capital is abundantly available, and the two key metrics are oil prices and cost. “The amount that remains on the sidelines from nontraditional sources, primarily nonbank institutions such as private lenders and private equity, and Chevron, ExxonMobil, and other global producers’ increasing willingness to inject capital from overseas into US onshore operations means that the US oil patch now is much more efficient as well as very well capitalized to achieve several years of production growth, provided prices sustainably remain above $45/bbl,” he said.

Possible constraints

A second group of speakers warned that insufficient pipeline capacity and growing community protests could restrain short-term US shale oil production growth. “Sometime in the next few months, gas production is going to exceed takeaway capacity out of the Permian basin,” said RBN Energy LLC Pres. Rusty Braziel. “Will the Texas Railroad Commission allow extensive flaring to occur? That’s not clear. It’s also not certain how it would handle pipeline capacity constraints on production.”

Four pipelines have been proposed, but the situation will not improve until at least one of them is built, Braziel said. “If it’s the Kinder Morgan project, the problem will be solved sometime in 2019. But if it isn’t, it will be around much longer,” he said. “That’s not the Permian producers’ only problem. Older wells produce 10-13 bbl of water for every barrel of crude. But production from an unconventional formation can’t be put back into the ground because these are low-permeability formations. It has to be trucked away to disposal sites, often some distance away.”

Braziel said about half of the water produced in the Permian comes from unconventional formations, and the volume should hit the low 30 million bbl range in the next 3 years. Companies are springing up to handle it, but infrastructure will be needed, he said.

“It’s a very interesting world where the market seems to be in the front of crude oil capacity, but a lot of infrastructure will be needed to handle the gas liquids and water that comes with that crude,” Braziel said. “It can always be put on trucks and hauled a long way away. That’s not true with gas, and trucks can only handle a limited amount of water. There aren’t a lot of trucks, and not a lot of truck drivers.”

Inadequate pipeline capacity is having its most dramatic gas price consequences in the Permian, but Braziel said it’s also affecting producers in other parts of the country. “There’s strong increase in gasified power generation, but it’s hardly having an impact. The gas that’s being produced out of the Bakken and Marcellus shales has to compete with what’s being produced on the Gulf Coast if it’s going to generate electricity there or be exported,” he said.

Risks throughout development

“There are social and other components that can affect projects,” noted Tricia Schuller, the principal at Adamantine Energy LLC in Boulder, Colo. “It wasn’t that long ago that a limited number of risks existed. Now, they occur in every stage of development from conception to construction. It’s more than siting. I don’t think social risk can derail projects, but it can cause years and millions—if not billions—of dollars in lost time and, ultimately, causing projects to be shelved.”

Schuller noted that while many people expected the Trump administration to make the atmosphere more friendly, this actually has made local protests grow. “On the state regulatory front, local activists are turning out. In Colorado, they had to limit protests to get work done. When you have 300 people lining up, it starts to have an impact. In many parts of Colorado, it’s harder than ever to get a disposal well permit. There’s a local community organization in every town with which to engage,” she said.

It’s critical for company leaders to identify where a permit or regulatory decision could be a factor because they all can create delays, Schuller said. Every component in the review process is an opportunity to build relationships, and management should be ready to talk directly and candidly to people, local governments, and regulators, she said.

Amit Naresh, an analyst at ESAI Energy LLC in Wakefield, Mass., said that US shale oil development has pushed out a substantial amount of US light crude imports. Most of what remains is bound for refiners on the East and West coasts, he told the CSIS gathering. “East Coast refiners will continue to import light crude from Africa because they don’t have a way to get what’s produced domestically to their facilities. But US light oil is replacing imports at Louisiana and Texas refineries,” he said.

“One of the biggest reasons to be bullish about US crude export opportunities are the International Maritime Organization sulfur requirements that are due to change by Jan. 1, 2020, boosting demand for sweeter crude and benefiting refiners who are configured to take it as well as those with equipment to remove more sulfur,” Naresh said. “There could be as much as a 1 million b/d shift away from high-sulfur bunker fuel to lower-sulfur gas oil. Refiners don’t know how ship owners will respond. They will need to adjust their crude slate to lighter and sweeter grades or invest in more residual capacity and processing units.”

Contact Nick Snow at nicks@pennwell.com.

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