For decades natural gas was more of a nuisance than a blessing in the Permian Basin, where oil, specifically, was the economic engine of the region. Oil still is king, but natural gas is starting to flex some serious economic muscle these days, due to ripple effects from world events. This competition is creating its own set of issues to be dealt with.
Prices at the Henry Hub, the main pricing point for gas from the Permian, reached $8.81/MMBtu in late September, according to the U.S. Energy Information Administration (EIA). During the Pandemic those prices had dived to just $1.63/MMBtu in June of 2020, due to lost demand from worldwide shut-ins of travel and industry.
By September of 2022, as concerns about an economic slowdown grew, ycharts.com reports Henry Hub prices dropping to $6.83/MMBtu.
While $8.81 and even $6.83 are several times the 2020 numbers, it is important to note that they are nowhere near the all-time highs of October 2005, when prices reached $13.42/MMBtu, or of June 2008 at $12.69/MMBtu. The shale revolution beginning in 2010, which exponentially increased gas production, mainly in the gas-rich Marcellus of Pennsylvania and New York, drove the price drops of succeeding years.
But now, world events, including boycotts of Russian crude and natural gas, have created shortages in Europe that are being met, in part, by liquefied natural gas (LNG) coming from the Texas Gulf Coast and elsewhere in the United States. Much of the gas going to those Gulf shore plants comes by pipeline from the Permian Basin. More recently, explosions on the Nordstream pipelines from Russia to Europe have made investors more jittery and prices less stable, even though neither line was active at the time of the damage.
Basin producers have responded to the opportunities. Gas production in the Permian, the nation’s second most prolific gas producer after the Marcellus, reached an annual high in 2021, says the EIA. That year production averaged 16.7 billion cubic feet per day (Bcf/d). Projections are that this growth will grow by 2.1 Bcf/d in 2022 and by an additional 1.7 Bcf/d in 2023.
Nationally, according to several sources, natural gas production reached 100Bcf/d for the first time ever in 2021.
That all sounds great, but there is a caveat—getting it out of the ground is one thing, but getting it processed and to market is something else. A recent Bloomberg story questioned whether takeaway capacity can keep up with demand. It postulated that by early 2023 current gas pipelines would reach capacity, much as they did in 2018. If there is nowhere for the gas to go, it could cause wells to be shut in, affecting oil production as well.
There are three main pipelines under construction, but their full takeaway capacity is not expected to be available until 2024. Those projects are as follows, according to this EIA list:
Kinder Morgan Energy Partners, WhiteWater, and Summit Midstream Partners have announced expansion projects on their respective 2021 pipeline projects, collectively totaling 1.8 Bcf/d of additional capacity.
Kinder Morgan plans to expand the Gulf Coast Express Pipeline, adding 0.6 Bcf/d of capacity by the end of 2023.
EnLink Midstream reached a final investment decision to construct the Matterhorn Express Pipeline, which would add 2.5 Bcf/d of takeaway capacity by the fourth quarter of 2024.
Processing capacity must also expand, required for the removal of impurities. In this case also, much construction is expected. In fact, says GlobalData, the United States “is set to have a planned gas processing capacity of 3,881 mmcfd (million cubic feet per day) and an announced gas processing capacity of 3,340 mmcfd by 2026.” This will account for 69 percent of North American added capacity during that time frame.
In the past, such production increases would have signaled a price crash due to oversupply. But with Europe scrambling to replace embargoed Russian supplies, the United States has stepped up its LNG game, with the EIA reporting that, “In 2021, total annual U.S. natural gas exports were 6.65 Tcf—the highest on record, and the United States has been an annual net exporter of natural gas since 2017.” The United States still imports some natural gas, mostly from its northern neighbor, to fill regional supply gaps. Demand growth, therefore, is outstripping supply growth, which sustains higher prices.
Flaring excess gas used to be an option. During the time of 2017 through early 2020, the night sky over the Basin flickered bright yellow from flares. When production dropped in 2020, the need for flaring evaporated. In the climate of 2022 flaring is much less accepted due to its release of CO2 without any benefit. Suzie Boyd, founder and president of Caballo Loco Midstream, a Midland-based consulting firm, said in an email interview that she believes a return to flaring would be more acceptable to independents than to ESG-minded majors. At today’s prices, however, flaring could be economically harmful—forcing a decision that was not necessary at previous pricing levels.
Since the summer, exports from the Texas Gulf Coast have been reduced by the explosion at the Freeport LNG plant, whose full capacity is not expected to be restored until March. At the time of the explosion, Henry Hub prices dropped temporarily due to the expected drop in demand.
Another wrinkle in this story is the fact that the increased exports have reduced the amount of gas put into U.S. storage during the summer stockpiling season. As of the end of September, the approximate end of the season when more gas comes into storage than goes out, the EIA reported underground stockpiles in the “Lower 48” at 2,977 Bcf. This is 5.7 percent lower than last year’s comparable reporting period, when the level was 3,157 Bcf. It is 9.3 percent lower than the five-year average of 3,283 Bcf.
Excepting an extraordinarily cold U.S. winter, this should be plenty. But the hope of being able to grow supply to meet demand faces pushback on several levels. Permian rig growth rates have slowed in recent months, after ramping up quickly after the removal of COVID-19 restrictions. Many experts point out that rig counts are no longer an accurate predictor of growth due to the fact that a single rig can drill longer laterals and multiple wells from one location. Nonetheless, a drop in rig counts could be a sign of slower growth.
Increasing environmental pressure against new pipelines—which has manifested more in non-Texas regions including the Marcellus—could reduce transportation options in the future.
Environmentally, natural gas is cleaner for electricity generation than the coal it replaces in many locations, but many groups consider anything other than purely renewable generation to be anathema. Natural gas is also the feedstock for 95 percent of hydrogen production, which becomes fertilizer after being turned into ammonia. There are few immediate prospects for making “green” hydrogen from any other sources on a large scale.
Natural gas is, therefore, an important part of home comfort, transportation, food, and even medicine, among a long list of other things that have become necessities. That’s a position it should continue to hold well past the 2035 green energy goals set by many governments.
As Permian gas production increases, especially from older wells, the Basin finds itself in a position of relevance on the gas side, almost to the level it has long enjoyed with crude oil. Natural gas is therefore no longer a nuisance, instead becoming a challenge for the midstream sector to keep up with. And it has the potential to make a big difference in world markets and human comfort.
Paul Wiseman is a freelance writer in the energy sector. His email address is email@example.com.