04 Jan 2022 spglobal.com
Houston Ship Channel Jan-22 basis falls 60 cents
Permian output nears prior record at 14.1 Bcf/d
Rigs, drilling, completions highest since Q1 2020
Recent growth in Permian Basin gas production appears to be keeping downward pressure on the East Texas market, helping to reset the outlook for balance-of-winter gas prices at key Gulf Coast area hubs.
In recent trading, cash basis at locations like Houston Ship Channel, Katy Hub and Transco Zone 1 have fallen to a more-than-40 cents discount to the Henry Hub, down from year-ago levels at just 4 to 5 cents behind the benchmark, S&P Global Platts data shows.
While the trend isn't new, steeper discounts in East Texas are now becoming more frequent.
After trading at less than 10 cents discount to the Henry Hub for much of this past summer, East Texas gas prices came under increased pressure this fall. From Oct. 1 to date, cash basis at Houston Ship Channel has averaged minus 21 cents. Over the same period last year, the East Texas hub traded more than 25 cents higher, or about 5 cents premium to the US benchmark.
Faltering prices in the spot market are now quickly reshaping the outlook for this winter.
On Jan. 3, the Houston Ship Channel balance-of-month contract settled at just a penny premium to Henry Hub. Just days prior, the full calendar-month January 2022 contract expired at more than 60 cents premium to the benchmark. Over the same one-week period, the February 2022 contract also lost almost 30 cents, settling Jan. 3 at just 14 cents premium to Henry Hub.
From October to late December, both winter contracts traded at nearly 40 cents premium to Henry Hub – likely in anticipation of strong winter-season demand for LNG exports from the Texas Gulf Coast.
Weakening basis prices in the East Texas market come amid rising production in the Permian Basin.
Modeled data from S&P Global Platts Analytics suggest that the uptick in output is likely pushing more supply eastbound on major intrastate transport corridors like Kinder Morgan's Gulf Coast Express and Permian Highway Pipelines and the more recent, Whistler Pipeline.
Twice last month, Permian gas production was estimated at over 14 Bcf/d, falling just shy of its prior record high at 14.1 Bcf/d in June 2021, Platts Analytics data shows.
This year's pre-winter production push in the Permian, which is not atypical for West Texas or other US shale basins, was further fueled by a recent acceleration in drilling and completion activity there.
Since the start of the fourth quarter, Permian operators have added some 34 rigs to the basin, bringing the total to an estimated 300 in the week ended Dec. 29, data published by Enverus shows.
Drillers are wasting no time putting recently added rigs to work. In November, the number of wells drilled surged to a 19-month high at 300. From August to November, well completions averaged over 400 per month – also the highest since first-quarter 2020, data from the US Energy Information Administration shows.
As the upstream activity continues, the outlook for production growth has become increasingly bullish. According to a recent forecast from Platts Analytics, output from the Permian is likely to hit sustained levels at over 14 Bcf/d by sometime in the first-quarter 2022.
Would you say it is healthy for the Permian to add supply to keep the price of NG moderate, instead of allowing a sharp peak? I know my biggest concern has always been that the NG from the Permian was going to create such a glut that the bottom would fall out of the price.
The impact of accelerating Permian production on price is greater now after a number of years of constrained take away capacity. The days of extremely discounted prices at the WaHa Hub are history. Now associated gas has several options for reaching markets where it gets better pricing. Natural gas focused operators have a reason to balance supply and demand for gas, oil focused operators much less so. So far many operators have heeded Wall Street and the Banks and not created a supply glut but that could change quickly with a spike in oil prices. There is a sweet spot or range for natural gas prices that provides acceptable rates of return while still incentivizing increased use of natural gas. The view from my back yard (Haynesville operators) looks like $3.35 to $3.75 based on most recent break even statements. I think increasing Permian production could easily put prices back in the $2.70 to $3.00 range. As operating costs go up, that puts most gas focused players in peril especially those with a lot of debt to service.
Midcontinent producing hubs trade into $4.30s/MMBtu
Permian flows to Midcontinent up 70 MMcf/d in January
Midcontinent, Gulf Coast hubs compete for Permian gas
Strong natural gas demand across the central US this month is pulling more supply northbound from the Permian Basin as Midcontinent hub prices hit steep premiums to Waha. With colder weather forecast across the Upper Midwest over the coming week, a likely continuation of the trend could cut Permian deliveries to the Gulf Coast and other destination markets.
Since the start of January, gas demand across the Upper Midwest has seen its strongest start to a new year since 2018. Frigid temperatures in the region have fueled an uptick in deliveries from the Midcontinent producing region, encompassing Oklahoma, Kansas and Missouri, where gas prices have strengthened as a result.
At hubs across the Midcontinent, spot gas prices traded into the $4.30s/MMBtu on Jan. 13, hitting their highest since late November, preliminary settlement data from S&P Global Platts showed.
Rising gas prices in the Midcontinent this month have lifted locations across the region to steep premiums over Waha, incentivizing an uptick in northbound flows from the Permian Basin. Month-to-date, Permian deliveries into the Midcontinent have averaged over 720 MMcf/d, or about 70 MMcf/d stronger than in December, data compiled by S&P Global Platts Analytics shows.
Over at least the next week, colder weather across the Upper Midwest promises to keep Midcontinent gas demand and prices strong, potentially diverting more Permian Basin supply northbound – away from the basin's other destination markets like the Gulf Coast.
Current forecast data shows population-weighted temperatures across the Midwest averaging a frigid 21 degrees Fahrenheit over the next week, roughly in line with the month-to-date average at 19.7 degrees.
Over coming weekend, Midwest gas demand is forecast to reach its highest yet this season at over 29.3 Bcf/d as temperatures in the region dip into the upper teens. With gas prices in both the Midwest and the Midcontinent likely to surge, Permian shippers could divert additional supply away from the Gulf or West Coast markets to meet stronger demand in the central US.
Already this month, stronger gas demand in both the Midcontinent and the Midwest, and in the local area around the Permian Basin, appears to have weakened eastbound gas transmissions.
According to modeled data from Platts Analytics, eastbound transmissions from the Permian are down about 600 MMcf/d so this month, compared to last. Permian flows westbound, and southbound to Mexico have thus far seen little change compared to December.
With Permian eastbound transmissions potentially facing downward pressure in the days ahead, Gulf Coast hubs like Houston Ship Channel and Katy could be forced to compete for Permian supply.
Over the past three weeks, NGPL Midcontinent has priced at an average 24 cents premium to Waha, compared with an average 22 cents premium at Houston Ship Channel. Amid strengthening demand in the Midwest and Midcontinent gas markets, both hub's premium to Waha has moved more in tandem recently as the two destination markets are increasingly forced to compete for Permian supply.
At market close Jan. 13, the balance-of-month forward contract at Eastern Gas South settled at an average 54 cents discount to the Henry Hub while the February 2022 contract ending trading at an even steeper discount of 65 cents, S&P Global Platts most recently published M2MS forwards data shows.
Compared with January's cash basis average at minus 44 cents month-to-date, weaker forward basis for the balmo and February 2022 contracts likely reflects trader's anticipation of a coming gain in gas production.
Over the past two winter seasons, January production declines in Appalachia were followed by sustained lower output levels over a period of six months or more, Platts Analytics data shows.
This year, though, the market could be anticipating a quicker rebound following the recent startup of Transcontinental Gas Pipe Line's Leidy South project – an interstate pipeline expansion that entered full service in December offering producers an incremental 580 MMcf/d in transmission capacity out of the Appalachia Basin.
Record-production levels last month, which came after the Leidy South project entered service, also followed the announcement of new production guidance from at least two Appalachian producers – National Fuel Gas Company and Coterra Energy – both of whom said on third-quarter earnings calls that they intended to grow output this winter to fill newly leased capacities on Leidy South.
Combined, the late-2021 developments are a bullish indicator for Appalachian production growth this year. Over the past month, the shifting outlook for Marcellus and Utica production could be a contributing factor for recent weakening in Eastern Gas' 2022 forward curve. At market settlement Jan. 13, nearly all the hubs' 2022 calendar-month contracts were priced below prior valuations recorded just one-month ago. On average, the 2022 forward curve is now priced at 83 cents below Henry Hub, down from an 80 cents discount to the benchmark in mid-December, Platts data shows.
Just out of curiousity, when they say 70 million cubic feet of NG, is that at atmospheric pressure?
Hard to know. Each state has regulations regarding how tests are done. Chesapeake uses the Oklahoma standards for pressure and temperature for its internal data but uses the Louisiana standards for production reports for their Haynesville wells. I'm not up on the differences for other states as that is above my pay grade. I am only aware of the Chesapeake discrepancy because of work that I performed for a client. The volume difference between what was reported on their royalty statement was always different than the volume reported to the state but the difference was quite small.
May have been quite small, but a penny over hundreds of millions of units is a good chunk of change.
Yes but that begs the question, to whose advantage? Whatever the chunk of change, I suspect that it pales in comparison to the pencil whipping that the industry puts on its mineral lessors, un-leased mineral owners and Working Interests. The sale of operators gathering and treating systems in the early years of the Haynesville Shale Play that were structured to yield the most up front cash for the companies at the long term expense of the underlying mineral interests continues to disadvantage royalty revenues to this day. In one particular field, one operator has a G&T cost of $0.20/mcf while the immediately adjacent operator has a G&T cost of $1.20/mcf. When companies structure G&T system sales with exorbitant charges per mcf, minimum volume commitments and guaranteed rates of return, the damage to mineral interests is significant and sustained.
I'm sure they skim it wherever they can. I just try to remind myself occasionally that I could be getting nothing. It's funny to me that this last months royalty check was made by the operator going through a bunch of past payments and adjusting whatever costs they figured were wrong\ inaccurate, and managed a few hundred dollars to carry through this first month that there was zero production since they've had that workover rig on it.