February 2023

ShaleTech: Marcellus-Utica Shales

Price volatility, pipeline scarcity help corral production
Jim Redden / Contributing Editor

Thawing prices from a fickle winter heating season and largely politically-induced takeaway restrictions have combined to rein in gas production from the premier Appalachian basin, situated on the doorstep of half of the nation's population cluster.  

Amid seesawing gas prices, operators across the basin's dry and wet gas Marcellus and Utica shales of Pennsylvania, West Virginia and Ohio are expected to produce 35,372 MMcfd in February (Fig. 1), guesstimates the U.S. Energy Information Administration (EIA), a number which would be some 4,625 MMcfd less, year-over-year. 

Fig. 1. January to February Appalachian gas production is forecast to rise by 93 MMcfd, but remains below February 2022 production. Source: U.S. Energy Information Administration (EIA)
Fig. 1. January to February Appalachian gas production is forecast to rise by 93 MMcfd, but remains below February 2022 production. Source: U.S. Energy Information Administration (EIA)

Gas prices vacillated for much of last year and continued into 2023, where futures for February delivery dropped to $4.172/MMBtu on Jan. 4, as a deadly arctic blast in late December gave way to unseasonably warm weather to greet the new year. The EIA projects spot gas prices on the Henry Hub benchmark will average less than $5.00/MMBtu this year. Prices hit a 2022 high of $9.85/MMBtu on Aug. 22.  

"I remain bullish on the outlook for natural gas, but there's no doubt we see some volatility in the near-term," Chesapeake Energy Corp. EVP and COO Josh Viets told the Bank of America Securities Global Energy Conference last November. Chesapeake is returning to its gassy roots following the $1.425 billion sale of around 377,000 net acres and 27,000 boed of oil production in its Eagle Ford Brazos Valley asset on Jan. 18. 

Headwinds aside, Appalachian drilling activity remained relatively steady throughout 2022 and entered 2023 with a combined 52 rigs active in January (Fig.2), according to Baker Hughes. Of those, 38 active rigs targeted the Marcellus in January—two active rigs off from the 2022 high of 40 in October—mainly in the Pennsylvania fairway, where operators are increasing focus on the Upper Marcellus horizon. 

Fig. 2. Cumulative Appalachian drilling activity was relatively steady last summer, averaging around 48 active rigs. Image: Southwestern Energy Co.
Fig. 2. Cumulative Appalachian drilling activity was relatively steady last summer, averaging around 48 active rigs. Image: Southwestern Energy Co.

Leading gas producer EQT Corp. operated up to three of those rigs last year, along with one to two top hole rigs and two to three frac spreads. In September, EQT spent $5.2 billion to acquire privately held Tug Hill Operating and XCL Midstream, adding 800 MMcfed of production and around 90,000 net acres to their possession, which now comprises 1.1 million net acres across the tri-state operating area.  

Full-year 2022 net production was projected to reach roughly 6.1 Bcfed, with 64 to 79 net wells turned-in-line—some 30% fewer than previously guided. President and CEO Toby Rice said wells have pushed back to this year, largely in hopes that the 10% to 20% inflation rate the industry has faced will ease. "One of the benefits of moving wells back in 2023, I guess, is that we do hope service costs will abate a bit," he said. "But we'd like to have those volumes today with the current price backwardations."   

With operators reporting record cash flows, further production growth, they say, is being hampered by difficulties in moving more gas out of the basin. The lingering dearth of pipeline capacity, which shows no sign of easing anytime soon, is driven largely by backlash from non-producing states, particularly in the Upper Northeast.  


"We continue to see policymakers in New York and elsewhere pushing the narrative that growth in wind and solar, alone, can meet the needs of a fully electric world, including for winter heating in cold climates, like Buffalo (N.Y.), without sacrificing affordability and reliability, " says David Bauer, president and CEO of diversified National Fuel Gas Co. of Williamsville, N.Y. "The gap between aspirations and reality is remarkable." 

Over the past six years, no less than five major pipeline projects designed to move Appalachian gas to East Coast markets have been abandoned, primarily over regulatory squabbles. Chief among those was Williams' 124-mi Constitution pipeline that had been designed to transport 650 MMcfd of Pennsylvania gas to northeastern consumers. 

"An area of uncertainty that played really prominently during the third quarter is the continued inability of our elected representatives to achieve consensus on interstate pipeline permitting reform, which is hard to believe," says Nicholas DeIuliis, president and CEO of CNX Resources Corp. "So, Appalachia awaits future pipelines to be built." 

CNX points out that insufficient takeaway prevents access to 50% of the U.S. population that lies within a day's drive of the producing region. This rich consumer base is augmented with a sizeable regional industrial complex, bolstered in November with the long-awaited start-up of the Shell

polyethylene manufacturing complex in Beaver County, Pa., Fig. 3. Earlier estimates had the facility consuming up to 95,000 bpd of Appalachia-produced ethane. A long-shot proposal is also on the table to build a liquefied natural gas (LNG) export facility along the Delaware River in Chester, Pa. With a processing capacity of 1.8 MMcfd, the Cove Point facility on Chesapeake Bay, in Lusby, Md., is the region's lone LNG export terminal.  

Fig. 3. The Shell Polymers Monaca (SPM) manufacturing facility in Pennsylvania, which became operational on Nov. 15, is the first major polyethylene manufacturing complex in the Northeast with a designed output of 1.6 MTPA. Image: Shell
Fig. 3. The Shell Polymers Monaca (SPM) manufacturing facility in Pennsylvania, which became operational on Nov. 15, is the first major polyethylene manufacturing complex in the Northeast with a designed output of 1.6 MTPA. Image: Shell

CNX, for its part, produced 1,590.9 MMcfed in the third quarter, up modestly from the 1,564.1 MMcfed in the quarter prior but down by around 77.8 MMcfed, year-over year. Fourth-quarter production is expected to remain flat.  

The pure play operator drilled four wells, fraced 11 and hooked five up to production during the quarter on a mainly Pennsylvania leasehold that encompassed more than 1 million net acres. CNX has since dropped one rig and will resume a one rig, one frac spread program, Fig.4. "I think having this very consistent one-rig, one-frac crew plan makes us operate at a very high level of efficiency. It allows us to secure the right service partners on a long-term basis and develop very healthy relationships," DeIuliis said.  

Fig. 4. An Evolution Well Services electric frac spread on location at a CNX well site. Image: CNX Resources Corp.
Fig. 4. An Evolution Well Services electric frac spread on location at a CNX well site. Image: CNX Resources Corp.

Despite the basin-wide takeaway restrictions, Seneca Resources Co. LLC, National Fuel's E&P arm, increased FY 2022 fourth-quarter production, year-over-year, by 10% to 87.9 Bcfe. The upstream entity has targeted total FY 2023 production at between 370 and 390 Bcfe.  

Seneca, which operates exclusively in a 1.2-million-net-acre Appalachian leasehold, plans to further accelerate production, with 17 new wells coming online in the first quarter, says President Justin Loweth. With 88% of production under firm takeaway and sales agreements, Loweth said Seneca has managed to mitigate the widening price differentials seen throughout the Appalachia basin.  

Challenging "permitting delays and cancellations of critical infrastructure projects," likewise, have not prevented pioneer Appalachian producer Range Resources Corp. from increasing production, albeit modestly. Third-quarter production of 2.13 Bcfed was up 3% over the quarter prior, with a similar growth rate envisioned for the final quarter of 2022.  

Range expected to put 63 wells on production in 2022 within a legacy 460,000-net-acre position, primarily in southwestern Pennsylvania. "Approximately half of the wells are located on pads with existing production, supporting Range's cost-efficient development plans," says Sr. VP of Reservoir Engineering and Economics Alan Farquharson. 

Running a single rig, the company drilled seven wells in the third quarter and completed 22 wells. Range plans to continue with one rig and one frac crew this year. "It would be reasonable to expect us to see an increase in drilling activity in Q1 to then properly shape our program for 2023," said COO Dennis Degner. 


Going against the historical grain, Chesapeake and others are now looking closely at the Upper Marcellus as a standalone or co-developed zone. "We're moving to a co-development of the Upper Marcellus in the core of the basin, to optimize development of all zones of inventory. We expect the 2023 program to be about 50% Upper Marcellus and Lower Marcellus," says President and CEO Domenic Dell'Osso. 

Specifically, Viets said the operator has already acquired "a number of data points," given that some 100 Upper Marcellus wells are online and producing. This year, Chesapeake plans to develop the upper zone with its average 12,500-ft horizontal reaches, compared to the average 11,000-ft laterals in the lower horizon. Average 12-month cumulative flow from the Upper Marcellus is guided at around 450 MMcf/ft, compared to an estimated 580 MMcf/ft for the lower horizon. 

"Of course, as we develop the Lower Marcellus, we've drilled through it so that's allowed us to characterize it from a subsurface standpoint and have an understanding where it's prospective and where it's not," Viets said. "One of the really important components of the upper versus the lower is how much of a barrier do I have between the two zones. That barrier thins as we move out into the western part of the acreage, so that's where we start talking about co-development of the Lower with the Upper Marcellus."  

After delivering 1.99 Bcfd in the third quarter, Chesapeake planned to hold full-year 2022 Appalachia production at between 1.8 Bcfd and 1.9 Bcfd. The operator projected that 75 to 85 Marcellus wells will have been drilled last year, with 85 to 95 put online. "We do expect the Marcellus to be somewhat constrained for the foreseeable future," he said. "Our expectation for that asset is to run roughly five rigs. We think that holds us flat at around the 1.9 (Bcfd) range, and until something changes from an export standpoint in the basin, that's where we're going to be."  

With the addition of 113,000 net acres, acquired in the $2.6-billion acquisition of Chief E&D Holdings LP in January 2022, Chesapeake controls around 650,00 net Marcellus acres in Pennsylvania. With a year under its belt, the acquisition has given Chesapeake ample leeway for further development of the Marcellus, given the location of the acquired asset and the common gathering system, Viets says. 

"If you think about maximizing return on a well, if I drill into a spot in the field where it's pressured up because an offset operator has also been drilling, I now control that, and that allows us to really be methodical about how we plan our development," he said.   

Coterra Energy Inc. said recent flowback data from a Pennsylvania pad, comprising seven Upper and two Lower Marcellus wells, has confirmed an in-situ barrier between the two zones that effectively heads off inter-well communication. The project also contained three fully bound infill wells drilled at 800-ft spacing, while 11 existing Lower Marcellus wells offset the new upper-zone wells with cumulative production of around 127 Bcf.  

"This has allowed us to study well-to-well interference and communication between the Upper and Lower Marcellus," says President and CEO Tom Jorden. "We see little communication between the Upper and Lower Marcellus wells, confirming our thesis that the Purcell limestone that separates them serves as an effective frac barrier. This will be very important to our future development of the Upper Marcellus."  

Coterra says the 10% to 15% lower development costs/ft and the capacity to drill longer laterals in the upper horizon help compensate for the lower absolute flow volumes, compared to the Lower Marcellus. The Upper Marcellus wells, thus far, are averaging an aggregate 324 Mcf/lateral ft, compared to the average 406 Mcf/lateral ft of the company’s Lower Marcellus wells turned-in-line during the 2021-2022 period. 

Marking its first full year as a new company, Coterra closed out the third quarter of 2022 with net production of 2.2 Bcfd, with 24 new drills, 18 completions and 25 wells out online, along with 23 wells remaining to be completed in the fourth quarter and 32 wells expected to go into production. As of Nov. 3, the company was running three rigs and one completion crew on a tightly concentrated 173,000-net-acre position in the Marcellus core of Susquehanna County, Pa. At year-end 2022, Coterra expected to have put 75 to 84 Marcellus wells online, with laterals averaging 7,350 ft.  

Coterra is the offshoot of the surprising $17-billion merger of Cabot Oil & Gas Corp. and West Texas and Oklahoma producer Cimarex Energy that occurred on Oct. 1, 2021. 


Over the last couple of years, activity has gradually increased in the wetter Utica, which extends from its Ohio fairway into Pennsylvania, where it underlies the Marcellus. According to Baker Hughes, 14 rigs were active, on average, in the Utica during January, eclipsing the 2022 high of 13 active rigs in November. Operators are continuing to fully delineate the play while modifying completion designs.  

After widening its traditional 1,000-ft well spacing and adding "right-sized" completions and longer laterals, Gulfport Energy Corp has managed to nearly double recoveries within its Utica-focused Ohio leasehold. Compared to its traditional completions design, the Oklahoma City, Okla., operator has seen average recoveries of 2.2 Bcfe/1,000 ft in 2022, compared to a medium recovery rate of 1.4 Bcfe/1,000 ft in wells last completed with the legacy design in 2021. Gulfport emerged from bankruptcy in May of that year. 

Third-quarter net production averaged approximately 615 MMcfed. The full-year 2022 program was to include 20 gross (17.9 net) wells drilled with 15 gross (13.2 net) wells completed and turned-in-line.  

"We turned-in-line seven wells in the third quarter, with five additional (producing) wells planned in the fourth quarter," said Executive VP and CFO William Buese. "We executed our wider spacing development plan, utilizing right-sized completions, and showed increased recovery factors, compared to the 1,000-ft spaced wells. The results include our four-well Extreme pad brought online in late September." 

Gulfport added a top hole rig, which it plans to run for around six months before resuming a single-rig drilling program. "The top hole rig allows us to drill seven additional wells in the Utica before year-end," Buese told analysts on Nov. 1. "We plan to continue with this top hole for roughly half of 2023 before continuing with one continuous rig for the balance of the year. This level of activity should allow us to execute a continuous eight-month frac program, eliminating the risk of releasing crews in this tight service market." 

Gulfport holds some 193,000 net acres in a four-county eastern Ohio area, where the Utica ranges in thickness from 600 ft to more than 750 ft.  

EQT's Rice echoed Gulfport's commentary on the advantages of wider spacing in the Utica. "Over in the Utica, some of the science work that we've done, primarily widening spacing, has shown increased recoveries per foot, which makes those returns more attractive."  

The Utica also figures heavily in the production stream of pure play operator Antero Resources Corp., which forecasts net liquids production of 175,000 to 185,000 bpd at year-end 2022. Total 2022 production from a 501,000-net-acre position in the southwestern core of the Marcellus-Utica is expected to range from 3.2 Bcfed to 3.3 Bcfed. 

Operating three rigs and two completion crews, Antero planned to drill 70 to 80 wells in 2022, with 70 to 75 wells completed at average laterals of 13,800 ft. With firm transportation commitments on two southbound pipeline networks and a connection to the Cove Point facility, more than 1 Bcfd of Antero's total dry gas production is funneled to LNG export terminals.  

Dual-basin operator Southwestern Energy Co. expected to close out 2022 with Marcellus and Utica production of 2.8 Bcfed to 2.9 Bcfed, down slightly from the roughly 3.0 Bcfed produced in 2021. Appalachian wells account for 61% of total gas and NGL production of the company, which also operates in the Louisiana Haynesville play. 

Southwestern turned 14 Marcellus and Utica wells online in the third quarter, which recorded a cumulative production mix of 267 Bcfe, including 84,000 bpd of NGLs and 13,000 bpd of oil. The Appalachian wells were put on production at average lateral lengths of 15,629 ft.  

The company controls 768,000 net acres across Pennsylvania, West Virginia and Ohio. Of the wells put onstream in the third quarter, eight were in Southwestern's super-rich West Virginia asset. "In the fourth quarter, based on our super-rich activity and the timing of completions, we anticipate holding oil volumes flat," said COO Clay Carrell.  

After being forced to P&A a recent Pennsylvania Utica well, CNX will concentrate on the Marcellus for the time being. While drilling the vertical section of the well, the formation directly overlying the Utica became unstable, with various mitigation strategies proving unsuccessful, said COO Chad Griffin. 

"We already had a handful of Marcellus wells on this pad, and we plan to get those wells online early next year (2023). We'll let those Marcellus wells produce for a few years before we come back to this pad to access those same Utica reserves," he said on an Oct. 27 call. "I think this actually derisks our Utica program moving forward. We still believe very strongly in the reservoir." 

It ain't all about drilling 

Archaea Energy Inc. sees one person's trash as another person's warmth, while EQT Corp. is betting hydrogen has a place in the gas-rich Appalachia basin energy mix.  

Just over a year ago, Archaea began funneling as much as 12,700 MMBtu/d of pipeline-quality renewable natural gas (RNG) from decaying trash emissions at a Pennsylvania landfill and into the local power grid. Two months ago, BP forked over $4.1 billion to acquire the five-year-old Houston RNG company. "We see enormous opportunity to grow our bioenergy business by bringing Archaea fully into BP,” BP American President Dave Lawler said of the Dec. 28 acquisition. 

The rubbish-fed Project Assai, at the Keystone Sanitary Landfill in Dunmore, Pa., is the largest of Archaea's national RNG portfolio. The proprietary combination of compressors, membranes and pipes separates carbon dioxide (CO2) from the methane (CH4), which is processed into commercial-grade gas, while the CO2 is sequestered. Archaea says the project is designed to reduce CO2 emissions by more than 200,000 metric tons per year. 

Meanwhile, in West Virginia, EQT joined a public-private coalition in the third quarter of 2022 that aims to establish the Appalachian Regional Clean Hydrogen Hub (ARCH2). Battelle, GTI Energy and Allegheny Science & Technology (AST) joined EQT and the State of West Virginia in the partnership, which is seeking a share of the $8 billion the U.S. Department of Energy (DOE) has committed for such projects, under last year's Infrastructure Investment and Jobs Act.  

"Appalachia is ideally suited to lead the charge in clean hydrogen production in the United States, given abundant low cost, low emissions natural gas, interconnected infrastructure and storage, existing transportation networks and proximity to major end use markets," says EQT President and CEO Toby Rice.  

The coalition intends to submit a full DOE application by this spring, with a final decision on the hub expected in the fall.  

Lead Photo: Autumn foliage surrounds a Chesapeake-operated rig at work in Pennsylvania. Image: Chesapeake Energy Corp. 

About the Authors
Jim Redden
Contributing Editor
Jim Redden is a Houston-based consultant and a journalism graduate of Marshall University, has more than 40 years of experience as a writer, editor and corporate communicator, primarily on the upstream oil and gas industry.
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