Limited gas takeaway is bringing punishing differentials to the Permian Basin
The rise of the Permian has powered the recent resurgence of the American oil and gas industry.
Drawn by thousands of feet of stacked pay, oil companies have poured into the basin. With Concho’s (ticker: CXO) announcement of a massive $9.5 billion deal in the Permian last week, the largest in the Permian’s unconventional history, the play continues to surprise to the upside, establishing itself as the most desirable shale basin in the country.
The EIA estimates the Permian will produce 4.86 MMBOEPD in April, enough to make it the largest shale basin in the U.S., surpassing even the massive Appalachian shale region which holds the Marcellus and Utica gas plays. Permian production has surged since January 2017, rising by 1.5 MMBOEPD in only 16 months.
Already at service company capacity, water takeaway maxed out for some operators, gas takeaway full
This growth has not been without difficulties, with growing pains in multiple areas. One of the first problems to crop up was service company capacity, which was severely lacking after the lean years of the downturn. There simply were not enough frac crews to meet demand, and new crews generally had limited experience. As recently as November, major Permian players were reporting the frac market was so tight that spot crews had incremental costs beyond contract crews of nearly $1 million per well. While the service market has gradually grown to meet demand, this is hardly the only constraint the basin faces.
The problem of water takeaway was brought into focus during Q4 conference calls. Notable was when Carrizo (ticker: CRZO) illustrated just how important sufficient water takeaway can be.
The company reported its newest wells were producing at higher rates than expected. While this is normally a blessing for companies, in this case it was something of a curse, because in addition to increased oil and gas output, these wells were producing at higher water-oil ratios than expected. This meant Carrizo’s water production actually exceeded its takeaway capacity, forcing the company to constrain production and delay its development plan by a quarter. While most companies have not experienced water difficulties this severe, handling produced water from the Permian is a major consideration throughout the basin.
Permian: second only to the Marcellus in natural gas production
The latest constraint to rear its ugly head involves dealing with Permian gas production.
While the basin is commonly regarded as an oil play, the Permian is producing an estimated 10.25 Bcf/d, making it the second-largest gas producer, behind only the Marcellus itself. There are limited pipelines to transport this gas, which is eating into producers’ margins.
Source: EnerCom Analytics
Differentials are the highest in the U.S.
The Waha gas hub, located in southwest Texas, for example, now has the highest differentials of any major U.S. gas hub, averaging nearly $0.80/MMBTU below Henry Hub in March. Differentials in the Permian have even surpassed those of the Marcellus, where the reports of limited pipeline capacity creating crippling differentials for operators has become a broken record.
Source: EnerCom Analytics
Permian producers received an average of less than $1.90/MMBTU in March, the lowest monthly average since May 2016. While the spread has improved somewhat in the past few days, this may not bring relief for Permian companies.
With the basin showing no signs of slowing its current drilling and production growth, associated natural gas is likely to continue to flood onto the market.
Source: EnerCom Analytics
$0 gas possible: analysts
This flood of new gas will exacerbate the standard seasonal weakening in the gas markets, as spring often brings a drop in gas demand when the weather moves out of the hard winter freeze into moderate and warm spring temperatures. Tudor Pickering analysts estimate Permian gas could average $1.85/MMBTU over the year, compared to an average of $2.69/MMBTU in 2017. Some analysts are even more pessimistic, predicting that on some days Permian gas could reach zero—$0.00. While this would be unusual, extremely low gas prices have been seen before. Appalachian gas spot prices, for example, reached $0.20/MMBTU in late 2016.
Pipelines are years out, ethane may be the solution
Midstream companies are responding to this gas growth with new pipeline plans, but this will not bring relief in the short term. The Kinder Morgan Gulf Coast Express, for example, plans to connect Permian gas to East Texas, but is not scheduled to begin operations until October 2019.
To get around the pipeline problem, Permian producers may take a play from the playbook of Marcellus companies. Natural gas liquids like ethane can be separated from the gas and transported on different pipelines. NGL lines in the Permian are not experiencing the capacity squeeze seen in gas, so splitting out ethane would both reduce the volumes of gas being transported and allow companies to sell at less unfriendly differentials.
Mexican pipeline delays are partly to blame
Part of this differential cannot be remedied by U.S. companies. Some of the blame lies south of the border. There are extensive systems for transporting natural gas from the Permian to Mexico’s markets, and the country already consumes a large volume of U.S. produced gas. However, these exports have been constrained by Mexican infrastructure, as the Mexican pipelines connected to American systems are not extensively connected in the Mexican market.
Numerous Mexican pipelines are in the works, but the lines planned to begin operations in the past six months have been delayed, meaning new demand from the country is minimal.
