March 14, 2018 | Rishi Iyengar
The Permian Basin is a significant part of the large natural gas production growth expectations for 2018 and beyond. IHS Markit expects that out of the 4.7 Bcf/d of U.S. Lower 48 natural gas production growth expected in 2018, more than 1 Bcf/d will come from the Permian. However, unlike the Marcellus and Utica, gas from the Permian is associated with oil production. So forecasting gas production in the Permian requires looking at oil economics and the logistical and capacity challenges that the oil sector faces. That is the subject of this issue of "Get the Point."
The Permian has undoubtedly the best economics of any play in the Lower 48, with over half of the wells breaking even below $45/bbl. WTI spot price has been around or above $60/bbl since New Year’s Day, and forwards through 2018 are in the $57/bbl-$60/bbl range. Evidence that Permian operators are responding to the new price signal came in a big way over the last two months, with Baker Hughes data showing that 28 new oil-directed rigs have been added across the Texas and New Mexico areas of the Permian since mid-January.
Even before the recent price run-up, the Permian drilling machine was already marching forward at a strong pace, with rig counts seeing significant increases over 2017. However, according to IHS Markit analysis of Permian oilfield services and logistics, the ability of producers to complete wells has been severely constrained by limitations in the service sector, in water infrastructure, and in proppant logistics, leading to a buildup of a significant inventory of drilled but uncompleted (DUC) wells.
Below, OPIS takes a closer look at the factors that could limit the pace of Permian production growth and evaluate operator expectations for 2018.
Permian oil drilling activity on the rise
Permian Basin drilling activity saw significant increases in 2017, with total Permian drilling rigs growing in number from 269 to 400 by Jan. 1, 2018. This was primarily driven by increases in the Delaware Basin during the first half of 2017, and in New Mexico in the second half, even as WTI prices stayed in the $50-$55/bbl range for the majority of the year. Recent months have seen WTI prices rise up to above $60/bbl, and forwards for 2018 are well above $55/bbl.
Permian production growth, while not insignificant, has not occurred at the same ferocious pace as the growth in rig count. Total gas output increased by 1 Bcf/d from 5.1 Bcf/d in January 2017 to 6.1 Bcf/d in January 2018, with the vast majority of this growth occurring in the Midland and Delaware Basins. It is important to note that January 2018 production in the Permian was hampered by substantial freeze-off events, which stalled growth out of the basin that month. Additionally, according to IHS Markit, there also were some temporary rail bottlenecks into the Permian in Q1 2018, which affected proppant deliverability and potentially reduced completions early in the year. Overall, were it not for these production losses, it is very likely that we would have seen a higher January average for Permian gas output.
According to IHS Markit upstream analysis of the Permian, other types of service sector and logistical bottlenecks constrained Permian production growth in 2017, especially during the second half of the year.
One important driver has been that well characteristics have changed – namely that newer wells have longer laterals, increased proppant use, more frac stages, and are in relatively underdeveloped areas of the play. Well-level data from IHS Markit Performance Evaluator shows that from July 2016 to July 2017, the average lateral length of Permian horizontal wells increased from 7,000 to 7,900 feet, and proppant use per lateral foot increased from 1,763 pounds to 2,047 pounds. But this raised demand for proppant, which then led to constraints in frac sand deliverability. Furthermore, complex wells in newer and more remote areas of the Delaware Basin and New Mexico challenged the capacity of labor, infrastructure and logistics. Together, these trends have hampered completion rates and driven a large buildup of DUC wells.
The outlook for 2018, according to a recent IHS Markit upstream analysis report, is much improved – service sector firms have been making investments and developing solutions to Permian logistical constraints. The fruits of these efforts are expected to materialize in 2018, especially towards the second half of the year.
IHS Markit’s analysis of Permian oilfield services sees the following developments in proppant use and labor availability.
Proppant use. The significant increases in proppant demand seen in 2017 have spurred the development of frac sand mines within the Permian Basin. IHS Markit estimates that around 40 million tons of new frac sand capacity will be built in Texas in 2018, representing roughly the total expected proppant demand of the Permian and the Eagle Ford in 2018.
Labor trends. Producers, especially in newer areas in the Delaware Basin and New Mexico, were plagued by labor shortages and a lack of labor-related infrastructure (camps, etc.) during 2017, and responded with a surge of hiring. Frac crew employment more than doubled in the Permian from 4Q16 to 4Q17. For 2018, IHS Markit’s analysis is that much of the needed labor increase has already occurred, and that during this year employment increases will be much more moderate.
Given these developments, IHS Markit expects the significant easing of well completion constraints through 2018 and 2019, with increasing completion rates reining back and then reversing the growth in the DUC inventory.
Improved expectations for well completion and production growth are corroborated by the forward looking-statements released by the top four gas producers in the Permian:
OXY: According to OXY’s Q4 earnings presentation, the firm has been engaging in acreage trading for consolidation to allow for longer laterals, development of logistics hubs in New Mexico and Delaware Basin, and expansion of produced water recycling capacity. OXY expects 45% overall production growth from 4Q17 to 4Q18 on a barrels of oil-equivalent (Boe) basis.
Pioneer Resources: According to Pioneer’s February 2018 investor presentation, the firm has allocated $2.65 billion for drilling and completion (D&C) investment, and $260 million for investment in water infrastructure, field facilities and integration. It expects 22% production growth in 2018 compared to 2017 levels.
Cimarex: According to Cimarex’s Q4 corporate presentation, the firm plans to invest $945 million on D&C, and $90 millionfor midstream and infrastructure in 2018. Cimarex expects 32% growth in oil production from 4Q17 to 4Q18.
Concho: According to Concho’s Q4 earnings presentation, the firm has allocated $2 billion for D&C investment, and $140 million for other infrastructure. Concho plans to operate a 16-rig drilling program in the Delaware Basin, where 65% of its capital budget for 2018 is allocated. The firm states that it has improved available sand volumes and last-mile logistics, and expects 50% of 2018 sand volumes to be sourced from local Permian mines. Concho’s 2018 production guidance states expectations of 28% production growth from 4Q17 to 4Q18.
Overall, the strategy of major Permian operators looks to be focused on scaling development to maximize recoveries in 2018.
Takeaway Capacity: Oil and Gas
If labor, proppant and logistics challenges are less significant in 2018 than they were in 2017, the next potential constraint is in takeaway capacity.
According to IHS Markit, total crude pipeline capacity out of the Permian is currently neck-and-neck with production levels. Several smaller takeaway projects are slated to come online in 2018, with larger capacity additions expected to arrive in early 2019. If the in-service dates and timelines for ramp-up to full capacity of these crude pipeline projects go exactly according to their announced schedules, then capacity would just keep pace with expected crude production growth. But there is, of course, the very real possibility that one or more of these projects is delayed -- in which case it is likely that crude production will exceed pipeline capacity until larger projects and expansions come online in 2019. In short, crude pipeline capacity remains a potential risk to Permian oil output, and therefore to associated gas production.
The next question for Permian associated gas is whether there is adequate gas takeaway capacity to handle the expected additional output. While it is difficult to gauge exactly how much capacity remains on existing Permian pipelines, given that a significant amount of Permian gas flows onto Texas intrastates, a number of new projects have been announced to take growing gas production from the Permian-Delaware Basin to the Waha hub, and from the Waha to Gulf Coast markets:
Permian-Delaware Basin to Waha:
Waha to Gulf Coast:
IHS Markit and OPIS expect that at this point, out of the four announced Waha-to-Gulf Coast pipelines, Gulf Coast Express and Permian 2 Katy seem the most likely to move forward to commercial operations. In this scenario, and assuming both the Northern Natural and NGPL expansion projects come online, by the end of 2019 the Permian could see just under 2 Bcf/d of new capacity from the Delaware Basin into Waha, and 4 Bcf/d of new capacity out of Waha to Gulf Coast markets.
Based on these projects, there appears to be sufficient gas takeaway capacity to accommodate the expected increases in gas output. From the Gulf Coast, Permian gas would have the ability to seek out growing markets for LNG exports and pipeline exports into Mexico.
Further, there is the potential for additional Permian gas to flow into Mexico over the next few years. Three pipelines out of Waha went in-service in 2017: Comanche Trail, Roadrunner Phase 2 and TransPecos. Collectively, they added 3 Bcf/d of capacity from West Texas to the Mexican border.
However, the corresponding pipeline buildout in Mexico has been fraught with project delays, and capacity connecting West Texas border crossings to Mexican markets is lagging behind. Eventually, the infrastructure will be in place to connect West Texas to demand centers in central Mexico and new power demand in northwestern Mexico that is being driven by fuel oil-to-natural gas retrofitting, Permian gas flowing south from West Texas should be a very attractive source of gas for Mexican customers based on price/basis. According to project tracking by OPIS, several of these projects have expected in-service dates in the second half of 2018.
However, if any of these projects is delayed, or if downstream demand such as Gulf Coast LNG exports or Mexico power demand do not materialize in a timely manner, producers may resort to flaring gas that doesn’t yet have a destination. The U.S. Bureau of Land Management recently loosened federal regulations on flaring, reverting a significant amount of control to state regulatory bodies, and the Texas Railroad Commission (TRRC) is relatively generous as to how much flaring is permitted. TRRC flaring rules state that gas from newly completed wells can be flared up to 10 days, after which operators can apply for permits allowing continued flaring if a lack of pipeline capacity is demonstrated. The TRRC's Administrative Code states that it can “allow additional releases of gas if the operator of a well or production facility presents information to show the necessity for the release,” and that “necessity” includes “the unavailability of a gas pipeline or other marketing facility.” Permits are granted and re-evaluated for 180-day periods.
Overall, it is clear that the Permian Basin is ripe for increased production of oil and associated gas in 2018, but many pieces need to fall into place in order for the productive capacity of the play to be realized. With many of the service sector, frac sand and water infrastructure issues expected to be significantly alleviated, the biggest risks to associated gas production growth will likely be the timely addition of takeaway capacity for both oil and gas, and the ability of Permian gas to find markets.