As natural gas production in the Permian Basin surges to levels that could essentially tap out the physical capabilities of existing infrastructure in and around the supply region by 2019, the horse race is on for companies to build pipelines that could connect these supplies to new demand markets not too far from home.
Indeed, nearly 4 Bcf/d of export capacity is being developed in South Texas over the next few years in the form of liquefied natural gas (LNG) export facilities and cross-border pipeline projects to Mexico.
Meanwhile, natural gas production in the Permian, currently around 6.6 Bcf/d, is expected to grow to between 9 Bcf/d and 10 Bcf/d by the end of 2019 as associated gas growth surges, thanks to rapid oil drilling in the basin. With oil prices hovering in the mid-$40s to low $50s/bbl, drilling in the basin shows no signs of slowing. The rig count in the Permian, which extends across West Texas and into southeastern New Mexico, has grown by a whopping 92% in the last year, up to 386 as of Sept. 22, according to Baker Hughes Inc.
The surge in activity is not without justification. Energy researchers at IHS Markit have completed the first, three-year phase of a massive Permian Basin research project that models and interprets key geologic characteristics to better estimate its remaining hydrocarbon potential, with initial results indicating the ancient basin still holds an estimated 60-70 billion bbl of technically recoverable resources.
The problem with the associated gas growth in the Permian is that the massive supply hub sits among a group of gas sources all competing to flow gas to market, effectively causing a displacement issue among competing gas plays, including Oklahoma’s stacked reservoirs, the resurgent Rockies and the Haynesville Shale.
Some pipelines already have been announced to help alleviate the abundant supply. Cheniere Energy Inc.-backed Midship Pipeline Co. LLC is developing a 1.4 Bcf/d pipeline connecting gas production from the Anadarko Basin in Oklahoma to growing Gulf Coast and Southeast markets via deliveries to existing pipelines.
The proposed project would consist of 199.4 miles of 36-inch diameter newbuild pipeline beginning in Kingfisher County, OK, and terminating at interconnects with existing interstate natural gas pipeline near Bennington, OK. Midship filed an application for a certificate of public convenience and necessity with the Federal Energy Regulatory Commission (FERC) in May and expects to begin construction in the second quarter 2018, with in-service by early 2019.
Meanwhile, there is more than 2 Bcf/d of pipeline capacity from Waha to Mexico that is barely flowing today as the market is awaiting pipelines farther downstream in Mexico to come online, according to Genscape Inc.’s Eric Fell, senior natural gas analyst.
Once a pipeline like the 1.2 Bcf/d La Laguna-Aguascalientes comes online, “you could effectively flip the switch and get that Permian gas to Mexico,” Fell said. In doing so, though, basis differentials at Waha and South Texas would be impacted as displacement occurs.
Still, severe constraints in the Permian are likely to show up beginning in 2019 as the amount of physical capacity to move gas nears exhaustion.
“The market is starting to recognize the fact that there is a gas takeaway problem,” said BTU Analytics’ Erika Coombs, senior energy analyst. “We’ve already started to see Waha showing the impending constraints.”
Waha cash basis prices have widened substantially since the beginning of the year, falling from a 12-cent discount to the Henry Hub to a 37-cent discount as of Monday (Sept. 25), according to NGI’s Daily Price Index.
Forward prices also reflect the trapped supply issue surrounding the Permian as prices on Monday for the coming winter averaged about 42 cents below the Henry Hub, while summer 2018 prices averaged 55 cents below the benchmark. For the summer of 2019, Waha basis sat at minus 54 cents, according to NGI Forward Look.
BTU is projecting 367 MMcf/d of incremental gas growth in the Permian by the end of 2017. The Lakewood, CO-based company expects 3.3 Bcf/d of incremental gas growth by the end of 2019. “That’s why we need pipes,” Coombs said.
Stronger Waha prices begin to appear in the winter 2019-2020 strip as forward basis prices on Sept. 22 sat at minus 41.5 cents, while the summer 2020 strip was at minus 40 cents, Forward Look data show.
The improved pricing structure further out the Waha forward curve aligns with the in-service dates for two major pipeline projects that have been proposed to take burgeoning Permian gas production to demand markets in South Texas.
NAmerico, a joint venture partnership with Cresta Energy and backed by privately held NAmerico Energy Holdings LLC, began marketing their proposed Pecos Trail pipeline on Feb. 1. Rather than hold a formal open season, NAmerico opted to hold bilateral discussions with prospective shippers to gauge interest in the proposed 461-mile, 1.85 Bcf/d pipeline.
NAmerico President Jeff Welch said the company has been “quite successful in garnering letters of intent” (LOI) and is working to convert those into definitive documents. While Welch could not say how many shippers have expressed interest, nor how much capacity shippers have committed to, he did say the majority of capacity on the now 2 Bcf/d Pecos Trail is under LOIs. The key going forward, he said, is to help shippers understand how the market is evolving and decide to be a part of a solution that’s effective.
“People used to ask Wayne Gretzky why he’s such a great hockey player,” Welch said. “And he would tell them, ”I don’t skate where the puck was. I skate where the puck is going to be.’ That’s been the biggest challenge…getting people to understand where the puck is going to be. The more significant players do recognize that now.”
NAmerico hopes to have a final investment decision made by the end of Q3 or early Q4, with plans to bring Pecos Trail online 22 months later in the late second quarter or early third quarter of 2019.
Meanwhile, Kinder Morgan Texas Pipeline LLC (KMTP), a subsidiary of Kinder Morgan Inc. (KMI), held an open season in the spring for its proposed Gulf Coast Express Pipeline, a 430-mile, 42-inch pipeline running from near Waha to Agua Dulce in South Texas near Corpus Christi.
Given the level of interest by shippers, the company is now considering adding about 15% more capacity than the 1.7 Bcf/d that was offered in the open season, according to KMTP spokeswoman Melissa Ruiz.
As designed, natural gas supply would be sourced from multiple locations, including existing receipt points along KMI’s KMTP and El Paso Natural Gas pipeline systems in the Permian, a proposed interconnection with the Trans-Pecos Pipeline and additional interconnections to intrastate and interstate pipeline systems in the Waha area.
Deliveries of natural gas into the Agua Dulce area will include points into KMTP’s existing Gulf Coast network, KMI-owned intrastate affiliates (KM Tejas and KM Border pipelines), the Spectra Valley Crossing pipeline, the NET Mexico header and multiple other intrastate and interstate natural gas pipelines. Like NAmerico’s Pecos Trail, Gulf Coast Express has a proposed in-service date for the second half of 2019.
Meanwhile, Sempra Energy and Boardwalk Pipeline Partners LP joined the competition and launched a nonbinding, open season through Sept. 14 to solicit interest in a 470-mile pipeline. The proposed 42-inch diameter Permian-Katy Pipeline (P2K) as initially designed would transport up to 2 Bcf/d from the Waha, which could begin phased-in service in late 2019.
While no one can dispute the rapidly growing gas production coming from the Permian, the fact that growth comes from associated gas that is tied to oil drilling has to beg the question whether potentially lower oil prices could throw a wrench into any of the newbuild plans. But both NAmerico’s Welch and KMTP’s Ruiz believe Permian producers have a strong interest in ensuring they have a market for the associated gas.
“At the end of the day, the high demand for natural gas is not changing,” Ruiz said. “And producers want a cost-effective takeaway solution that provides optionality and reliability.”
Welch agreed. The Permian, he said, “is going to be so prolific you have to take control of your future with respect to takeaway capacity. If you’re not engaged in that, you run the risk of subpar returns and not having flow assurance on your natural gas production.”
Meanwhile, Genscape’s Ben Chu, manager of equity products, said the basin is well fragmented in that different drilling zones offer better economics where oil prices can run as low as the high $20s/bbl and still garner attractive netbacks. Genscape sees associated gas in the Permian growing 1.2 Bcf/d over 2017 levels in 2018, and another 1.1 Bcf/d in 2019.
While a big Waha discount can impact cash flow, a lot of producers don’t care because they are making money on oil, BTU’s Coombs said. In addition, a lot of the acreage in the Permian is held by production (HBP). With the cost of land considered a sunk cost, producers in plays like the Haynesville and the Permian have continued to drill even when prices have dropped, Chu said. The industry is maturing in its HBP drilling, with producers putting in as many wells as they can. “All of that creates momentum.”
NAmerico’s Welch agreed, noting the Permian was an active space where a lot of the private equity-backed producers have to exploit their interests in a certain amount of time. There are also big players like ExxonMobil Corp. and Chevron Corp. that hold big blocks of acreage, in addition to a plethora of acquisitions and divestitures taking place.
Problems could arise, however, as the rig count in the Permian has increased so quickly that the number of drilled but uncompleted wells (DUC) has risen as well. “Those DUCs will need completion, but completion costs have gone up higher than operators have expected,” Genscape’s Fell said.
With nearly 6 Bcf/d of capacity being proposed to take Permian gas to the Gulf Coast, the challenge now becomes getting the 10-15 large producers that can be anchor shippers on board with only one or two of these projects as only about 3 Bcf/d of capacity is needed, Coombs said.
“This is a really competitive process. It’s all about who can build the pipe for the lowest cost and offer the best rates. We see getting everyone on board with the same projects as a challenge that could push the in-service into 2020 rather than 2019,” she said.
That delay then could impact how quickly the Permian is able to grow oil because if producers can’t move their gas, they can’t drill for oil. Flaring the gas isn’t a viable option because in existing production areas, flare permits are for a period of only 45 days, 180 days maximum, according to the Railroad Commission of Texas.
“The pace of completions is something that is definitely at risk,” Coombs said.
With a nearly two-year lag between making an FID and pipeline in-service, and the impending pipeline constraints that are expected to arise in the Permian beginning in 2019, the race is on to get the regulatory process underway.
“It’s a competitive market for sure,” Ruiz said. “Time will tell. But it’s quite possible for more than pipeline to be built.”
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