September 2020

Shaletech: Marcellus-Utica Shales

Gas Prospects Rise in Concert with Oil Woes
Jim Redden / Contributing Editor
Marcellus-Utica drilling has remained steady, with 31 active rigs through August.  Image: CNX Resources Corp.
Marcellus-Utica drilling has remained steady, with 31 active rigs through August. Image: CNX Resources Corp.

While Appalachian gas producers may wish no ill will to their oily counterparts, the sharp decline in associated gas is more than welcome, as they prepare for the winter heating season and beyond.

Long accustomed to battling low prices, operators in the rich dry and wet gas windows of the Marcellus and Utica shales of Pennsylvania, West Virginia and Ohio can be forgiven for seeing any supply disruption as a net positive. Amid the overall demand destruction of the Covid-19 pandemic, the average, monthly, Henry Hub spot gas price over the first half of 2020 tumbled to $1.81/MMBtu, dropping to a 25-year low of $1.63/MMBtu in June, before rebounding to $2.18/MMBtu on Aug. 10.

“Looking into 2021, we see considerable improvements for the natural gas and NGL (natural gas liquids) macro as a result of activity-driven supply declines, particularly in shale oil basins, and strengthening global demand for natural gas and NGLs,” Range Resources Corp. CEO Jeff Ventura said in an Aug. 4 call, echoing many of his peers. “For this reason, many reputable analysts are now predicting $3 natural gas or higher in 2021.”

Appalachian producers, likewise, are curtailing sales volumes or maintaining relatively flat production profiles in the nation’s largest gas play, in hopes the thermometer and stockpiles cooperate in the coming months. The Appalachia basin is projected to deliver 32,413 MMcfd of gas in September (Fig. 1), a mere 202-Mcfd increase over September 2019’s level, according to a U.S. Energy Information Administration (EIA) estimate. That trend is borne out in the Marcellus Pennsylvania core, where the latest data available from the state’s Department of Environmental Protection (DEP) shows a cumulative 554,523,922 Mcf of dry gas produced in June, compared to 550,175,879 Mcf in June 2019.

Fig. 1. August-to-September gas production in the Appalachia region is projected to drop by 210 MMcfd.
Fig. 1. August-to-September gas production in the Appalachia region is projected to drop by 210 MMcfd.

As for drilling, it’s been steady as you go, with a consistent average of 31 active rigs since July 24, all but five of which are Marcellus-directed, according to Baker Hughes.

Meanwhile, in what could be considered blasphemy elsewhere, operators met the cancellation of an in-basin pipeline with shrugs or outright cheers. Citing nagging delays and increasing cost uncertainty, utilities Dominion Energy and Duke Energy, on July 5, pulled the plug on the 600-mi. Atlantic Coast Pipeline (ACP) that would have carried gas from West Virginia to eastern North Carolina. 

“Near term, we don’t really expect that much of an impact,” says Jason Kurtz, V.P. of Marketing and Transportation for Southwestern Energy Co. “There’s open capacity out of the basin.”

EQT Corp, a driving force and the largest signed shipper of the Mountain Valley Pipeline (MVP), is shedding no tears over the competing pipeline’s fate. Equitrans Midstream’s 303-mi Corp. MVP network is expected to start-up in the first quarter of 2021, running from northwestern West Virginia to southern Virginia. “With ACP being cancelled, that was about 1.5 Bcf a day of capacity that was going down at the southeastern market, which is competing with MVP capacity that is going to deliver gas there. So, not having that project online makes MVP more desirable,” says EQT President and CEO Toby Rice.

The APC cancellation preceded rock star investor Warren Buffett’s $9.7-billion acquisition of Dominion’s gas midstream infrastructure. The July 16 deal includes 7,700 mi. of natural gas pipelines, 900 Bcf of storage and a 25% stake in the Cove Point liquefied natural gas (LNG) export terminal in Lusby, MD.


The shortfall in associated production has particularly lifted prospects for the copious wet zones of the Marcellus and the Ohio core of the Utica shale. Since January, an estimated 1.3 MMbpd of NGLs have been taken off the market (Fig. 2), with resultant prices, as a percentage of the West Texas Intermediate (WTI) and Brent oil benchmarks, strengthening accordingly. Some estimates have NGL trading at nearly 45% of WTI, well above the pre-pandemic average.

Fig. 2. The oil price decline is having a profound effect on NGL, where two-thirds of the supply comes from shale oil plays. Source: Antero Resources Corp.
Fig. 2. The oil price decline is having a profound effect on NGL, where two-thirds of the supply comes from shale oil plays. Source: Antero Resources Corp.

Complementing improving in-basin demand from petrochemicals, power generation and the like, Appalachian producers also envision price uplifts, from increased takeaway capacity of the still-developing Mariner pipeline network and the Marcus Hook NGL hub along the Delaware River in Pennsylvania. To meet increased demand expectations, Energy Transfer LP, which operates both Mariner and Marcus Hook, says a 50,000-bpd expansion of the Marcus Hook terminal will be in service by the first quarter of 2021. 

Pure-play Antero Resources, for one, says it may take “several years” for U.S. NGL production to return to pre-Covid-19 levels. “We can see that the strength of NGL markets, relative to WTI and Brent, has continued to stay elevated as a result of more resilient petrochemical and residential commercial markets during this pandemic,” says David A. Cannelongo, V.P. of Liquids Marketing and Transportation.

Despite the lowest quarterly spend since going public in 2013, Antero produced 3,521 MMcfed in the second quarter—a 9% year-over-year increase. The company spent $180 million in drilling and completions capital during the quarter, including one well that Antero claims established a U.S. record with 11,253 lateral ft drilled in a 24-hr period. The company put 44 wells on production during the quarter, at average lateral lengths of 10,757 ft.

After laying down three rigs and two completion crews in the second quarter, Antero is running a single rig and completion crew in a 542,000-net-acre leasehold, primarily spanning northern West Virginia and eastern Ohio.


Utica-focused Gulfport Energy Corp. has been squirreling away new production, while keeping a wary eye on oil-weighted peers. “As a result of the commodity price environment, during the second quarter, we made the strategic decision to defer a near-term production to later periods in the year and early 2021, when natural gas prices are expected to be higher,” CEO David Wood said in an abbreviated Aug. 5 call.

For the year, Gulfport plans to drill 15 wells, with 25 new producers put on-line within its 205,000-net-acre Utica asset in Ohio. After completing 22 wells over the first half of 2020, the company plans to complete seven additional seven Utica wells over the second half. Production averaged 800,313 Mcfed over the first six months, compared to 1,022,341 Mcfed for the same 2019 timeframe.

Wood says the supply picture could hit a bump, with activity starting to crawl back in oil basins. “With oil now having just crossed near $40 a barrel, we have started to see some activity return and with it, the associated gas production come back to market,” he said.

CNX Resources Corp. will begin restoring just over 500 MMcfed of shut-in production around Nov. 1. “Gas markets were already strained, when Covid-19 had a dramatic impact on the entire global economy,” says Executive V.P. and COO Chad Griffith. “Summer 2020 gas prices plummeted, but the huge reduction in rig activity created some real bullishness for supply reductions and for improved prices this coming winter and beyond.”

Since the end of June, CNX has gone from two rigs to one, and one all-electric frac spread. During the quarter, the company drilled eight wells and completed 11 s on a more than 1-million-net-acre leasehold, where a recently completed central Pennsylvania deep Utica well was trending estimated ultimate recoveries (EUR) between 4.5 to 5.0 Bcf/1,000 ft.

For its part, EQT has begun a “moderated” restoration of the 1.4 Bcfed of shut-in gas, representing some 25% of its production base. “I think that a lot of other operators are seeing the same thing we’re seeing and making a statement that this product is undervalued at these prices,” Rice said. “And there is conviction that prices will be higher in the future.”

Running an average two to three rigs and an equal number of frac fleets, EOG expects to drill and complete a total of 82 Marcellus wells this year, with 15 Utica completions on tap. The company controls 630,000 net acres of Marcellus play in Pennsylvania and West Virginia, with an additional 60,000 net Utica acres in Ohio.

Since buying Shell’s 450,000 net acres and some 220 MMcfd of production on July 31, National Fuel Gas Co. has curtailed 13 Bcf of production. “Moving forward, we expect prices to remain low over the next couple of months and, therefore, we are now forecasting to curtail our remaining spot volumes for the rest of this fiscal year,” COO John R. Pustulka said in an Aug. 7 call.

The company’s drilling and production entity, Seneca Resources Company, LLC, will operate one rig and one completion crew through FY2021, Pustulka said. A total of 32 new producing wells are planned in the upcoming fiscal year, equally split between the Marcellus and Utica.

In what it describes as the largest acquisition in the company’s 118-year history, National Fuel paid nearly $504 million for Shell’s entire Appalachia assets in Tioga County, Pa. National Fuel now controls around 1.2 million net acres.


Nomenclature aside, Cabot Oil & Gas Corp. has shifted to the latter, focusing solely on the dry gas window of a tightly concentrated, 173,000-net-acre leasehold in prolific Susquehanna County, Pa. After producing 2,229 MMcfed in the second quarter, Cabot expects 2020 production to come in flat, relative to 2019 at a range of 2,350 to 2,375 MMcfed. Full-year guidance calls for 60 to 70 wells to be drilled, completed and put online.

Owing to cross-unit drilling legislation that Pennsylvania enacted last December, clearing the way for longer laterals, Cabot is looking at increasing Upper Marcellus development with around 12,000-ft horizontal reaches. “It is our intent to lay out the sticks for the Upper Marcellus, with longer laterals on average than we’ve been able to drill in the Lower Marcellus program,” says President and CEO Dan Dinges.

Dinges sees the year-over-year “potential” for a more-than-6-Bcfd production shortfall as winter approaches, driven by activity cuts in both gas and oil basins over the second half of the year. After a “disappointing summer,” he also expects LNG exports to improve by the end of the third quarter. “Our base case expectation is that as we move into the winter, higher global gas prices will put U.S. LNG back in the money, leading to significant improvements in utilization rates and a corresponding increase in export-related demand for natural gas,” he said.

Fig. 3. A Southwestern Energy rig at work in West Virginia. Image: Southwestern Energy Co.
Fig. 3. A Southwestern Energy rig at work in West Virginia. Image: Southwestern Energy Co.

Among the most active Appalachian operators, Southwestern Energy averaged five rigs and four frac spreads in the second quarter (Fig. 3), with the drilling of 30 wells, and 31 wells completed and put online. The company plans to exit the third quarter with two rigs and one frac fleet active across the 460,000 net acres under control in Pennsylvania and northern West Virginia.

Most of the quarterly activity was focused on the northeastern Appalachia dry gas assets in Pennsylvania, where Southwestern drilled 21 wells with 14 completed and 11 put to sales. In the wetter West Virginia acreage, the company drilled and completed nine and 17 wells, respectively, with 20 wells turned-in-line.

Range Resources, for another, became a pure play operator after unloading its North Louisiana shale assets in August, with activity now concentrated entirely on some 833,000 net acres in southwestern Pennsylvania with stacked pay potential for the Marcellus, UItica and Upper Devonian shales.

Range, which plans to put 67 wells into production this year, dropped from four rigs to one, and from three frac crews to one at mid-year.

Dry gas comprised 83% of the 551.7 MMcfed that Montage Resources Corp. produced in the second quarter, and will continue to make up a higher percentage of production going forward, the company said. During the quarter, the company drilled five and completed seven gross Utica dry gas wells in the Monroe County, Ohio, stacked pay area, where four Marcellus and three Utica wells were also turned in line. “We anticipate the production mix continuing to reflect a more meaningful percentage of dry gas over the next few quarters and into the full-year 2021,” says President and CEO John Reinhart.

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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