When Will the Pipeline Relief Come?
Will There Ever Be Enough Truckers?
How Much Can You Expect From Rail?
The next year could spell trouble for operators producing oil in West Texas and southeastern New Mexico.
The Permian Basin currently has more crude than it can handle, and production there continues to grow at a steady rate month-over-month after surpassing 3 million B/D earlier this year, according to data from US Energy Information Administration (EIA).
Pipeline takeaway capacity isn’t sufficient and won’t be until the second half of 2019. There aren’t nearly enough trucks or truck drivers to make up the difference, and any meaningful expansion of crude-by-rail transport is restricted by infrastructure and business-related constraints.
Both options are already competing with movement of equipment and supplies such as sand and water, demand of which has also grown—along with their costs—to support the continued production growth. Many operators in the basin struggled to generate positive cash flow even before the bottlenecks became an issue. Now, the price of the crude they’re producing is trading at a big discount vs. spot prices in Houston, near the Gulf Coast refining and export center; and Cushing, Oklahoma, the crude trading hub from which the West Texas Intermediate (WTI) price is derived.
The spread between Midland crude and WTI grew to double digits in May, spiking from roughly $1 a couple months earlier. If WTI prices were closer to where they were a year ago, the impact of the spread immediately “would have been significant for almost every operator,” noted R.T. Dukes, Wood Mackenzie US Lower 48 upstream research director. Fortunately for Permian operators, WTI prices have been much higher than the range of prices for which they budgeted coming into the year, minimizing the impact of the spread thus far.
But WTI prices aren’t guaranteed to remain that high, and differentials could grow—just look at the Western Canada Select heavy crude price, which has traded at up to a $30/bbl discount to WTI this year due in large part to transportation constraints. The spread forced operators such as Cenovus, Husky Energy, and Canadian Natural Resources to slow their oil sands production during the first quarter.
Permian operators are similarly being forced to examine whether continued growth over the next year is sustainable or even worthwhile. Their exposure to Midland spot prices varies, ranging anywhere from less than 5% to 50–60% of Permian production, said John Coleman, Wood Mackenzie senior analyst, North American crude oil markets. Most operators are in the 20–30% range, meaning there already has been a modest hit to cash flow, he said.
Consultancy Rystad Energy believes the Midland vs. Cushing spread will “stay very much depressed” into mid-2019 and “won’t be surprised” if it moves into the low $20s/bbl, said Artem Abramov, Rystad vice president, shale analysis. “Everything points to the situation getting worse and worse going forward.”
Abramov has heard from crude gatherers in the basin that already “several smaller operators plan to push completion work further into the future until wellhead prices improve a bit.” The differentials will potentially impact small operators the most because they typically sell their crude at the wellhead and don’t have long-term agreements with pipeline owners. Also exposed are new entrants of varying sizes that only recently initiated their drilling programs and lack firm takeaway agreements.
Among pressure pumpers in the basin, C&J Energy Services said it will delay redeploying three of its frac fleets comprising 120,000 hp due in large part to takeaway concerns. Operator Halcon Resources planned to reduce its rig count in the Delaware Basin from four to three in July primarily due to lower Midland prices. “With widening [Midland-Cushing] differentials, we have seen our recent oil price realizations decline significantly,” commented Floyd C. Wilson, Halcon chairman and chief executive officer.
Dedicated pure-play operators such as Diamondback Energy, Parsley Energy, Resolute Energy, and Centennial Resource Development “have some commitments and firm agreements, but they are a bit more exposed on average,” Abramov said. “Some operators tried to hedge basis [differential], but given a very illiquid nature of these contracts, they did not manage to achieve significant protection relative to their production levels.”
The largest operators such as Pioneer Natural Resources, Concho Resources, and EOG Resources are less exposed, having a high share of firm agreements. “At least for 2018, they secured adequate differentials not only on their base production but also on expected growth toward year end,” he said.
Coleman said, “If you don’t have pipelines, rail, or trucking available to move your crude to market—if you physically cannot move your crude to market—pricing in the basin needs to move to incentivize producers to shut in that marginal well so that additional crude is not being produced at that point.”
Given WTI prices around $70/bbl, the “doomsday scenario” in which numerous operators shut in wells or delay completions, Coleman said, is a Midland vs. Houston differential in the $25–30/bbl range. Along the way, there may be revised production or lifting strategies with lower peak rates. “I think we’ll see probably in the second half of the year some companies make some difficult decisions,” said Dukes.
No Pipeline Relief Until 2019
“Right now we are in a situation where we are very close to 100% utilization of outbound pipelines,” which Rystad estimates is 3.1 million B/D, said Abramov. While there is some spare capacity, much of it is held by larger operators such as Pioneer. Rystad forecasts Permian production to continue growing to 3.6–3.7 million B/D by year end.
Operators’ past aversions to making long-term takeaway commitments could be hurting them in this instance, said Taylor Robinson, president of PLG Consulting. Those that made longer-term commitments months ago or a year ago are “going to be at an advantage.” Meanwhile, many other operators “are just trying to figure things out.”
PLG estimates that, if the Permian’s current monthly oil production growth rate as forecast by EIA continues into next year, up to 740,000 B/D of crude will be bottlenecked—or left in the ground—by September 2019, which is around the time the major pipeline projects are slated to begin operating. A common thread for those projects: connecting the basin with the growing Corpus Christi, Texas, export hub.
The private-equity-backed 590,000‑B/D EPIC crude pipeline extending from Orla, Texas, to Corpus Christi is expected to start up in second-half 2019, anchored by Apache and Noble Energy. During next year’s third quarter, Plains’ Cactus II pipeline, also linking Orla to the Corpus Christi area, will provide 585,000 B/D of capacity to shippers. Phillips 66 Partners’ and Andeavor’s Gray Oak pipeline system connecting West Texas with Corpus Christi and Sweeny and Freeport, Texas, is expected to be placed in service by the end of 2019. It could move up to 700,000 B/D.
After the new capacity comes on line in 2019, “we think production will explode upward in the Permian” given the high count of drilled-but-uncompleted wells, said Abramov.
In the meantime, modest expansions will help some operators move more barrels to market. Enterprise Products Partners in May added 35,000 B/D of capacity to its Midland-to-Sealy, Texas, pipeline. Volumes continue to ramp up on Phase 1 of Energy Transfer Partners’ Permian Express III pipeline, and the company is looking to fill the remaining 50,000 B/D of volume commitments. Owned by Magellan Midstream Partners and Plains All American, the BridgeTex pipeline is set to have another 40,000 B/D operational early next year.
Analytics firm RBN Energy notes that the Midland-to-Sealy and BridgeTex pipelines will benefit from drag-reducing agents, additives that cut turbulence—an issue for pipelines moving lighter crudes—allowing for better flow and thus increased capacity.
Will There Ever Be Enough Truckers?
An alternative to pipeline for moving some of the excess crude out of the Permian is trucking, but the seemingly flexible mode of transport is becoming more expensive and difficult to secure. Wood Mackenzie estimates that trucking crude from the Permian to the Gulf Coast costs $12–14/bbl, which is reflected in the recent differentials. What’s more, there’s a dearth of readily available truck drivers not only in the basin but nationwide, as booming industrial and consumer economies have created demand far exceeding national capacity.
The American Trucking Association in late 2017 projected a national driver shortage of 50,000 by the end of that year, a trend that it believed could balloon by about 250% by 2026. As a result, companies serving the oil and gas industry are competing with companies such as Kellogg’s and General Mills for drivers.
“Driver demand across the US is at an all-time high regardless of industry, and convincing guys to come back to the oil patch is an issue,” said John Zanner, fundamental energy analyst at RBN Energy. Within the Permian, there aren’t nearly enough trucks or drivers for intra-basin movement of crude, water, sand, and equipment.
Rystad estimates that the number of trucks involved in in-basin crude disposition—trips that typically take no more than 20–25 miles—has surpassed the 2014 all-time high, totaling more than 1 million B/D of capacity. In the lesser-developed Delaware Basin, 80% of crude is trucked in Winkler and Pecos counties in lieu of limited gathering infrastructure. Sending those trucks on long-haul deliveries to Cushing or the Gulf Coast only serves to reduce in-basin capacity.
Abramov said Rystad has heard of at least two operators in the Midland Basin exploring trucking crude to Wichita Falls, Texas—where crude would then be routed toward Cushing—or to an Eagle Ford gathering system linked to the Gulf Coast. But Rystad believes long-haul trucking “will hardly become significant volume-wise,” he said.
Zanner noted that operators need a reliable fleet of trucks each day at the wellsite to support production for flexible storage and takeaway. “When an operator mistimes a new well or has one come on that is producing way higher than expected, it needs to be able to call for more trucks literally that same day,” he said. “That’s where operators are going to be running into big issues. Just logistically, there’s just not enough bodies, there’s not enough trucks. It’s going to be a mess for some guys if they don’t really plan carefully for what’s going to happen.”
Crude transport by truck is chiefly competing with increasing movement of sand on the roadways, with regional sand mines now fulfilling 25% of the basin’s proppant demand, Rystad data indicate. Keeping up with demand will require almost tripling the number of trucks carrying sand to 3,600 trucks/day by yearend 2018 from 1,250 trucks/day in 2016.
Exacerbating the issue is a lack of roads to accommodate the rising traffic, meaning the trucks will be making markedly fewer round trips per day compared with 2 years ago. It doesn’t help that many in-basin sand mines are close geographically, collectively serving as an inbound and outbound traffic bottleneck.
During his time in the Permian recently, Benjamin Stewart, Rystad vice president, shale research, observed “traffic jams lined up for a mile-plus with semis just sitting bumper to bumper.” And when the light turns green or it’s their turn to proceed at a stop sign, it takes a while for those heavy trucks to get moving again, he added. The inefficiency is unappealing to drivers, most of whom are paid on a per-mile basis.
A planning lead for a Permian operator recently told Rystad that he believes the region could “see similar problems as to what happened in the Eagle Ford years back—roads get chewed up, and no one wants to have them shut down for repairs.” While possible solutions are sparse, Stewart has heard that some of the larger operators have started to explore forming a consortium and working alongside the US Department of Transportation to jointly build out infrastructure.
Those work conditions provide a challenge for the operators, midstream companies, services companies, and trucking companies of all sizes hoping to attract drivers to the region. Job postings in the Permian region for heavy and tractor-trailer truck drivers far outnumbered those of other occupations in May, according to statistics from the Texas Workforce Commission. In 2016, they were already leading regional employment by more than 1,800 workers.
The existing high density of drivers and the inability to bring in many more has resulted in high in-basin turnover. “I hear rumblings on the ground there from a trucking company friend of mine that the turnover is getting untenable, an indicator that there’s going to be more challenges down the road—because turnover is driven by [companies’] desperation for drivers and offering bonuses and higher wages, so people are jumping more than ever,” Robinson said.
“It’s difficult to make that investment in someone when they’re really kind of mercenaries,” Zanner said. “There are some trucking companies that got burned in the past for growing really big in times like these.” While some companies may “go for broke,” others are content just staying at their current capacity and making money.
Don't Expect Too Much From Rail
When the Permian last experienced crude bottlenecks in 2014, many operators turned to rail to move their crude out of the basin. “It was a similar situation, but the volumes were significantly lower and the [basin’s production] growth rate was significantly slower,” Robinson said. Production in the basin was almost a third of what it is now, and it didn’t have to compete with the currently large volumes of sand moving on the rails.
“But very few people kept those crude-by-rail facilities going” because additional pipeline capacity came on line, “and it just made no sense for [operators] to double, triple, or quadruple their takeaway costs” by using rail instead of pipeline, he explained. Many of those facilities in turn became overloaded with imported sand, while others were never completed.
“Right now, there are a number of folks looking at restarting a facility or adding tanks to a facility that never got completed” for crude export, thinking they’ll see a return on their investment within the next year before pipeline capacity is scheduled to ramp up, Robinson said.
Coleman said efforts to bolster export capacity, including by Plains All American, are expected to wrap up in this year’s third and fourth quarters, and the impact will be in the tens of thousands of barrels, which will only modestly help the glut. Rystad estimates Permian rail capacity is around 150,000 B/D, but “actual crude-by-rail volumes are below this level and fairly noisy from day to day in our view,” Abramov said.
Scheduled for completion in this year’s third quarter, Murex and Cetane Energy are doubling the capacity of their crude transloading facility in Carlsbad, New Mexico. While the facility “accommodates substantial transloading of sand,” the companies said, “segregated entry and exit lanes for oil will alleviate any congestion between commodities.”
“Crude-by-rail, when it works well, it works really well,” Zanner said. But there are logistical challenges as well because the operator has to line up crude production plans, trucks, locomotive power, and rail cars. Abramov noted that major rail companies are asking for multiyear transport agreements that extend well-beyond the pipeline capacity boost anticipated in 2019, which is an unappealing proposition for operators.
“Adding new, greenfield crude-by-rail capacity in the basin is unlikely,” Zanner said. “Previous crude-by-rail providers have been burned by adding facilities when spreads widen, only to mothball those when market conditions improve—see the Powder River [Basin] and Bakken terminals that no longer move anything,” he said. “Given that crude-by-rail folks know that a ton of pipeline capacity is coming on line at the end of 2019, they would be hard-pressed to build something new.”