Source: Energy Intelligence April 27, 2020
A years-long effort to build gas takeaway capacity out of the Permian Basin could leave the region “massively long” on pipelines by 2021 in an ironic twist that would leave producers holding a very expensive bag.
In just over a year if pipeline in-service schedules are met, Permian oil producers — which are laying down rigs at a record pace — could be on the hook for 2 billion-3 billion cubic feet per day of unfilled take-or-pay gas pipeline capacity as their associated gas volumes plummet.
Midstream operators, led by Kinder Morgan, have been installing pipeline infrastructure meant to ferry an expected explosion of gas out of the basin — a bounty that is off the table now that Permian oil producers are laying down rigs at a record pace. Instead, there will be a dearth of gas available to fill ever-increasing capacity, analysts say.
Kinder Morgan has sanctioned a pair of 2 Bcf/d pipelines to handle the expected excess — Gulf Coast Express, which went into operation in October, and the Permian Highway Pipeline (PHP), which is set to begin operations later this year. The latter’s fate is uncertain as it has become mired in lawsuits challenging its federal permit from the US Army Corps of Engineers (p6).
In addition to the Kinder Morgan projects, the 2 Bcf/d Whistler Pipeline has been sanctioned with more than 95% of its capacity under firm contract. Another 1 Bcf/d of Permian gas could also be moving into Mexico in a year or so as export projects wrap up.
This 7 Bcf/d of aggregate capacity was a tad more than the basin actually needed before the oil price collapse, Matthew Lewis, a senior director at East Daley Capital, told Energy Intelligence. “By our math, we’ll be massively long capacity,” he said — and that is not good for producers’ bottom line, as gas drillers discovered in Appalachia (NGW Jun.3’19).
Lewis said physical prices for Midland crude, now well below $20 or $25 per barrel, will continue to cause a significant reduction in Permian drilling and completions, not to mention shut-ins of producing wells. The oil sector is struggling with the double whammy of the Saudi-Russian price war and demand loss created by the coronavirus pandemic.
The trend is already evident. Rystad Energy reported last week that hydraulic fracturing activity in the US saw its largest drop ever in March, with about 200 fracking operations getting under way in the massive Permian.
As a result of that pullback, associated gas production in the Permian could fall by around 2 Bcf/d over the course of this year alone, with 0.7 Bcf/d-0.8 Bcf/d just from reducing flared volumes, according to the Energy Intelligence Research & Advisory (R&A) unit.
A number of dry gas producers in the Marcellus Shale found themselves in a similar fix by backing takeaway pipes from the region, only to fall short in producing the volumes to fill it. However, the Permian is an oily play so the consequences of excess gas capacity are less pronounced, Lewis said, although recouping losses by selling unused capacity could prove difficult.
Why? Because gas prices are likely to rise in the Permian once greater takeaway capacity and falling production relieves the supply glut, Lewis explained. The 2021 forward curve, now reflecting gas prices 45¢-90¢ per million Btu below Henry Hub, would make paying the 50¢-55¢ tariff on the new takeaway capacity worthwhile.
But it’s likely that the Waha/Henry Hub differential will tighten significantly, to 30¢-40¢, at which point shippers would be under water paying the full tariff.
Last week’s price action showed just how volatile Waha prices can be when it comes to pipeline constraints, trading as low as negative $10/MMBtu on Monday, only to test 11-week highs at $1.30/MMBtu by the end of the week, according to Energy Intelligence data.
While acknowledging the expected plunge in gas output and the suits against PHP, Kinder Morgan CEO Stephen Kean made clear on the company’s first-quarter earnings call last week that “it’s not stopping us from continuing our construction at this point” — at least on rights-of-way not impacted by the dispute. And he was equally unconcerned about revenues if the pipeline were to run light.
“The good thing for Kinder Morgan is both of its pipelines are underpinned by 10-year take-or-pay contracts, so they are covered provided no one goes bankrupt,” Lewis said.
Even if Permian oil drillers are forced by the Texas Railroad Commission to shut in production, the loss of associated gas volumes on its pipes would not hurt Kinder Morgan’s bottom line, Kean said on the call.
“Force majeure events do not excuse obligation to pay,” Kean said, “at least when it comes to our transportation tariffs, we
think we’re fairly well insulated there.”
However, Kinder Morgan’s planned 2 Bcf/d Permian Pass Pipeline, which has few if any shippers on board, will likely never be sanctioned, an eventuality the firm hinted at in its fourth-quarter earnings call (NGW Mar.9’20). Permian Pass wasn’t even mentioned in last week’s call.
Where financial stress for Kinder Morgan on the gas side may come with the loss of gathering and processing (G&P) fees that are paid as they are incurred. And with uncertainty how this and other factors might play out, founder and executive board chairman Richard Kinder said the firm is increasing its dividend by 5% to $1.05 a share rather than the planned 25% increase “to preserve flexibility and balance sheet capacity.”
Kinder Morgan is also reducing its capital budget by $460 million, with much of the reduction in “either removed or deferred G&P investments,” Kean said, indicating the firm is bracing for reduced volumes of gas and other product.
However, declining gas revenues can be met by a “pivot to dry gas plays,” Kean said. “We do have that ability. If you think about our assets, our natural gas assets, we serve dry gas plays like the Marcellus/Utica from a transmission standpoint and storage standpoint with our Tennessee Gas Pipeline system. We serve the Haynesville.”
“And we’ve got plenty of room to grow to the extent the dry gas market — or to the extent that the gas market comes back into balance with the reliance less on associated gas volumes and more on dry gas volume.”