Published on Dec 19, 2022
Coterra Energy (CTRA) appears to be running out of Tier One inventory in the Marcellus, Upstream suggests, while its regional production during the first three quarters of 2022 has dipped to the company’s lowest levels since 2018. A surge in production in the second half of the year predicted by the company failed to emerge in the third quarter, Upstream shows.
Already, Coterra’s operations in the region are characterized by sharper-than-average declines, Upstream shows, while management has begun discussing drilling constraints and preparing investors to see declining capital efficiencies.
As stakeholders closely monitor shale basins for signs that companies or certain regions are running out of Tier One acreage, Coterra’s results appear to confirm that the company has begun shifting to its Tier Two Marcellus locations, which includes infill wells and other less-promising targets.
Coterra’s Tier Two drilling offers less of a production boost at higher costs while output from its aging Tier One wells declines faster than similarly situated peers.
Coterra’s Marcellus operations are confined to Pennsylvania’s Susquehanna County, once known as the “core of the core” of the dry gas window — a strategic advantage for Coterra’s Marcellus predecessor, Cabot Oil and Gas.
But as the county is increasingly drilled, Coterra lacks acreage to fall back on in other parts of Appalachia – transforming the company’s concentration in the core into something of a double-edged sword.
As some shine comes off Susquehanna County, the company’s average output per well has been falling, Upstream shows. Coterra also announced a major reserves revision in early November, reducing their proved reserves in the Marcellus by 32 to 36 percent.
Coterra did not respond to requests for comment.
“As I have said, flexibility is the coin of the realm in the commodity business,” CEO Tom Jorden said in November earnings. While Coterra retains the ability to shift between the Permian, Anadarko and the Marcellus, within Pennsylvania, the company appears increasingly hemmed in.
Coterra shifts to less-attractive targets earlier than anticipated, where wells cost more, produce less. Coterra’s Pennsylvania operations target two distinct intervals in the Marcellus: the Lower Marcellus which is hydrocarbon-rich and the focal point of the majority of Coterra’s legacy wells and the Upper Marcellus, which is less rich in natural gas deposits and has been less explored by the company.
In a 4Q 2020 earnings call, then-CEO of Coterra’s predecessor Cabot, Dan Dinges predicted that a shift to the Upper Marcellus wouldn’t arrive until “towards the end of this decade.”
But with its Tier One inventory becoming exhausted, Coterra has moved its timeline up and started to explore the Upper Marcellus more concertedly, with now-CEO Jorden saying those wells will represent 30 to 40 percent of their portfolio going forward.
Although Coterra’s management celebrated results from recent tests in the Upper Marcellus, those results reflect lower production and higher expenses than their recently drilled wells in the more-explored Lower Marcellus, company disclosures analyzed by The Capitol Forum show.
First, projected costs show future Upper Marcellus wells appear more expensive to drill. That might surprise anyone who only glanced at Coterra’s announcement, which highlighted lower per-foot costs in the Upper Marcellus — but in the accompanying earnings presentation, Coterra showed its Upper Marcellus wells also have longer average laterals, leading to higher total per-well costs.
Future Upper Marcellus wells will cost $1,000 per lateral foot with a 10,000 foot lateral length, Coterra projected in its recent earnings presentation – translating to $10 million per well.In comparison, the company’s most recently drilled Lower Marcellus wells (those with a “2021-2022 vintage”) cost $1,150 per lateral foot with lengths about 7,300 feet – or about $8.4 million per well.
Second, its Upper Marcellus test wells also produce less. Coterra reported that its seven recently drilled ~8,100 foot Upper Marcellus wells produced an average 324 Mcf per lateral foot during their first six months, or 2.6 Bcf per well.
Coterra compares that to its 140 most recently drilled Lower Marcellus wells’ six-month average of 406 Mcf per lateral foot (2.96 Bcf per well) – suggesting a per-well output that’s roughly twelve percent lower in the newer Upper Marcellus locations than in the legacy play of the Lower Marcellus.
All told, it appears Coterra’s recent wells in its legacy Lower Marcellus play outperform wells in the Upper Marcellus by roughly eight percent on a cost-per-mcf basis (based on Coterra’s cost figures for a 10,000-foot Upper Marcellus well and the production results from its test wells).
Coterra’s costs for both its Lower and Upper Marcellus wells run significantly higher than other operators in Northeastern Pennsylvania’s dry gas window on a per-foot basis.
Chesapeake Energy, whose operations in the region are focused in neighboring Bradford County, reported an average per-foot costs of $785 on lateral lengths averaging 9,900 feet year-to-date 2022 in its Aug. 2, 2022 earnings deck. Southwestern Energy reported average “dry gas Marcellus” costs of $518 per lateral foot for 2021.
Legacy wells dogged by outsized decline rates, red flags for parent-child issues. In the Lower Marcellus, Coterra has been drilling mostly infill wells for a number of years – and while infill wells look less expensive than Upper Marcellus wells, not only do they tend to underperform Tier One wells drilled early on, they also risk damaging those older wells, driving legacy production down.
First, navigating between existing wells limits drillers’ options for new wells, which can drive efficiencies down. In the November call, Jorden signaled that Coterra is running into “constraints” with its Lower Marcellus laterals.
Second, one side-effect of infill drilling can often be increased declines amongst legacy assets in the portfolio, often referred to as “parent-child interference,” which occurs when newly drilled wells (called “child wells” or “infill wells”) exacerbate decreasing production rates of older (parent) wells nearby as core drilling fields become filled in and crowded.
So more Lower Marcellus drilling risks snowballing Coterra’s already significant decline rates by, for example, adding to parent-child interference issues.
While outsized decline rates can have any number of causes, Coterra has admitted experiencing parent-child problems in the Marcellus and Coterra’s decline rates outpace local and regional peers, according to Upstream.
For example, Coterra’s operations reflect an overall decline rate of 25 percent in 2021 compared to its peers’ Appalachian operations like Southwestern Energy (SWN), the second-largest operator in Susquehanna County, or Chesapeake Energy (CHK) which reflect 10 and 7 percent decline rates respectively, Upstream shows, based on prior 13-month production.
Coterra’s 25 percent decline rate is also far higher than the 13.7 percent for all operators in Appalachia and 11.4 percent for all operators in Pennsylvania, according to Upstream.
A significant proportion of the company’s legacy wells have seen significant recent production declines. Over 12 percent of Coterra’s 961 active horizontal gas wells in Pennsylvania saw production levels fall at least 50 percent comparing the first half of 2022 to the first half of the prior year. Over one third saw production drop by more than 30 percent.
More notably, those sharp drops weren’t isolated to newly drilled wells. Although shale wells commonly have high initial production followed by sharp decline rates, rates tend to level off over time.
But a significant number of Coterra’s older horizontal wells can be found among those with higher decline rates comparing the first half of 2022 to the first half of 2021, including wells with spud dates dating back as far as mid-2009.
Number of wells (y-axis) showing production drops in given ranges (x-axis) from the first half of 2021 to the first half of 2022 among Coterra’s active Pennsylvania horizontal gas wells spud in given year (color coded). Wells spud in 2012 were far more likely to see declines above 50 percent, including three wells with declines between 70 and 80 percent. Wells spud five years earlier exhibited significantly slower declines, including with the largest number (19) showing declines below 30 percent. Wells with no reported production and any wells that saw production growth not depicted. Data source: Upstream.
The faster-than-expected shift towards the Upper Marcellus could suggest Coterra views the risks posed by Lower Marcellus infill drilling as significant.
During November earnings, Jorden was asked if Coterra’s just-announced one-third Marcellus reserves write-down was tied to problems with well spacing issues and if “parent wells are being more impacted as you do more in-field activity drilling?”
“I mean, a lot of it is, of course, driven by the behavior of infill wells,” Jorden responded.
As Tier One Locations Dry Up, Coterra’s average well productivity has been falling. Other operators have begun eyeing what’s happening in Susquehanna County, noting its dwindling remaining Tier One locations.
“If you look up in Northeast PA, you look at Susquehanna County, you look at Cabot [now Coterra], Chesapeake, up in that area, they’re drilling their inventory quite quickly,” Dave Boyer, director of Geology and Development Planning at Arsenal Resources, told The Capitol Forum’s Energy and the Regulated State conference on Nov. 1.
“And if you want to call that the only Tier One gas in Marcellus, because I mean they’re getting three and four Bcf per thousand feet – well, yes, we’re running out of that.”
Compared to Chesapeake or Southwestern, Coterra’s Marcellus operations are uniquely confined to Susquehanna County, where it holds roughly 177,000 net acres, making Coterra more exposed than its peers to the impacts of intensive drilling there.
The company’s average productivity per-well – historically one of Coterra’s strengths – has fallen off in recent years and at a rate faster than peers, Upstream data shows. The downward trend appears likely to continue in 2022 based on the company’s reported production so far this year and its disclosed drilling plans in the region.
Operators’ average annual output (MMcfe) per producing Pennsylvania well. 2022 annual figures shown based on production data and well count from Jan-Sept. 2022, if all operators were to remain on the trajectory seen during first 3 quarters of 2022 to end of final quarter. Data Source: Upstream.
Coterra’s Marcellus output has trended down in 2022, but company predicts final quarter upturn. To be sure, Coterra’s older wells have further to fall than many of their peers in absolute terms simply because so many early Susquehanna County wells were highly productive. But rapid declines impact the company’s prospects in significant ways, undermining any notion that relatively steady production from older wells could buoy overall output and ease the shift towards Tier Two acreage.
Over the first three quarters of 2022 Coterra’s Pennsylvania gas production has tracked lower than it reported at the same point for the past three years, dropping from over 750 million mcf from Jan. to Sept. 2019 to 715 million mcf in 2022.
Monthly production in Mcfe. First 9 months 2022 shown in orange. Data Source: Upstream.
The company has been warning since the start of this year that its Marcellus production would start out low – but predicted an upwards trend towards year-end, with output weighted towards the third and fourth quarters.
That predicted second-half surge had yet to emerge in the third quarter, with Coterra’s reported 3Q production just two percent higher than Q2 levels – and slightly below Q1.
To reach 2021 levels, Coterra’s average monthly Marcellus output in 4Q would have to rise roughly 20 percent, compared to the company’s January through September averages. Coterra generally tends to report higher production in the fourth quarter, Upstream shows, with an average 9 percent uptick over the past decade, including a high of 19.2 percent in 2018.
While that surge could still happen in the fourth quarter, Coterra plans to bring on the same number of wells in Q4 as it did in Q3. And its seven expected new 4Q wells will target the Upper Marcellus (where the company has noted “we expect absolute volumes to be lower than Lower Marcellus”).
Coterra projected limited near-term impacts from “systemic” reserves revision. In its Nov. 3 release, Coterra announced a 32 to 36 percent downward proved reserves revision for its Marcellus holdings – an unusual move, given that oil and gas companies more commonly update reserves figures at the end of the year.
In an earnings call the next day, Coterra management said the revision – which Jorden dubbed “kind of the systemic issue of the reserves” following the merger between Cabot Oil and Gas and Cimarex Energy last year — would have diluted near-term impacts because the company will spread effects over a 50-year projected well lifespan.
In late September, Fitch had affirmed Coterra’s BBB long-term issuer default rating with a stable outlook, citing Coterra’s “low decline Marcellus shale production” and Coterra’s “significant footprint in the thickest producing interval in the Marcellus, the Upper and Lower Marcellus of Susquehanna County,” and Coterra’s Delaware Basin holdings.” Fitch listed “Lower netback Marcellus production becoming a materially larger portion of production mix… or a sustained decline in overall in production” among factors that could lead to a downgrade.
In May 2021, as Cabot and Cimarex announced they would merge to form Coterra, The Capitol Forum reported that despite company claims to hold “best-in-class” assets, Cabot’s portfolio already showed “decreased production and assets with high decline rates” and that Susquehanna County, where Cabot’s acreage is concentrated, showed the sharpest declines among top-producing Pennsylvania counties.