Shaletech: Marcellus-Utica shales

This is not what a “no-growth environment” is supposed to look like.

To point, Appalachia basin gas producers are poised to break the monthly production records set over the first six months of 2021, testing commitments to put fiscal temperance above unconstrained growth. With prices on a continual upswing, some question whether said discipline can be maintained or, in the vernacular of the country folks, will operators in the Marcellus and Utica shales choose to “make hay while the sun shines?”

Southwestern Energy is running five self-owned rigs in the Appalachia basin, including this one at work in West Virginia. Photo: Southwestern Energy Co

“It’s easy to stay disciplined in a $2.70 strip. It’s another proposition, when you’re looking at a $3 strip,” EQT Corp. President and CEO Toby Rice said on July 29, eight days after closing the $2.90-billion acquisition of Alta Resources, LLC. “I think that people know how that plays out, when you chase shorter-term price signals.”

The spot gas price on the Henry Hub benchmark hit an eight-month high of $5.60/MMBtu on Sept. 15, with the winter heating season still developing.

Fig. 1. September-to-October gas production in the Appalachian region is expected to increase by 74 MMcfd. Source: U.S. Energy Information Administration (EIA)

The nation’s largest dry and wet gas play, and also one of the most tightly regulated with states imposing strict emissions control standards, the Marcellus and underlying Utica shales stretch across Pennsylvania, West Virginia and Ohio. There, the U.S. Energy Information Administration (EIA) guesstimates that October gas production will reach 34,857 MMcfd (Fig. 1), eclipsing the monthly average of 31,900 MMcfd over the first six months of 2021. Appalachian production was 33,795 MMcfd in October 2020.

On a national perspective, the dramatic swing in Appalachian production can be a bit deceiving, as U.S. gas stockpiles totaling 3,006 Bcf on Sept. 10 were 17% lower, year-over-year, and 7% below the five-year average, according to EIA. Reduced working gas in storage can partly be traced to the decline in associated gas production and growing international thirst for U.S. liquefied natural gas (LNG) exports.

Growing Appalachian production is already straining existing takeaway capacity and widening pricing differentials. “When overall production exceeds the takeaway capacity, the basis (price differential) blows out. Looking at last year, that basis has been very volatile, even in this no-growth environment,” says Paul Rady, President and CEO of pure play Antero Resources Corp.

Illustrating the takeaway issues, Equitrans Midstream blamed extended federal and state regulatory reviews for pushing the start-up of the long-awaited Mountain Valley pipeline from the end of 2021 to sometime next summer. The 303-mi network is designed to move 2 Bcfd of gas from northwestern West Virginia to southern Virginia.

Some relief is expected to arrive in the fourth quarter, with the start-up of Williams Companies’ Leidy South expansion, with designed capacity of 582.4 MMcfd. The takeaway and gas gathering project expands the company’s existing Pennsylvania infrastructure to connect with the consumer-rich Atlantic Seaboard.

FORECAST SUNNY

Fig.2. A cumulative 39 rigs were active in the Marcellus and Utica play through September. Image: CNX Resources Corp.

Meanwhile, drilling activity in the Marcellus has remained steady with an average 27 active rigs throughout October, down one rig from the monthly six-month average. Owing largely to appreciably higher natural gas liquids (NGL) prices, an average 11 rigs were actively targeting the wetter Utica in September and October, up by seven rigs from the six-month average, Fig. 2.

Antero, the nation’s second largest NGL producer, said C3 +NGL prices averaged $40.32/bbl in the second quarter, up 159% year-over-year. Owing to a “firm transportation portfolio,” Rady said the company expects to realize a $0.15-$0.25/Mcf premium to the benchmark price.

The company is running three rigs and two completion crews in the 542,000 net acres under control in the southwestern core of the Marcellus and Utica in West Virginia and Ohio. Antero put 22 Marcellus wells online during the second quarter, with average lateral lengths of 11,740 ft. New drills included a Marcellus record well, with an 18,858-ft lateral reach.

Second quarter production of 3,324 MMcfed (173,000 bpd of liquids) was down slightly from 3,521 MMcfed during the same period last year.

Elsewhere, EQT produced an average 5.6 Bcfed in the second quarter on capital expenditures of $246 million, or $19 million below the low end of its guidance. The Pittsburgh-based operator projects cumulative third-quarter sales volumes of 470-500 Bcfe, with year-end production expected to range between 1,800 and 1,875 Bcfe.

With the 300,000 net acres included in the Alta acquisition, EQT controls around 880,000 net acres across Pennsylvania, West Virginia and Ohio. The company, which has established targets to achieve net zero Scope One and Scope Two greenhouse gas emissions by or before 2025, will operate two to three rigs and three to four frac spreads for the remainder of the year.

Increased in-basin production notwithstanding, the head of Range Resources Corp believes operators overall have remained disciplined to the so-called Shale 3.0 model—a term coined by the investment community to characterize the current state of the industry, in which operating within cash flow is the overriding tenet. As such, “I think we’re setting up for strong natural gas prices for this year, as well as into next year,” says President and CEO Jeffrey Ventura.

Range averaged production of 2.10 Bcfed over the second quarter, at an unhedged realized price of approximately $3.25/Mcfe, $0.41/Mcfe above the NYMEX and Henry Hub benchmark price of $2.84/Mcfe. In keeping with its moderation strategy, Range projects 2021 production to average around 2.15 Bcfed.

Running two dual-fuel rigs, split equally between its dry and wet southwestern Pennsylvania leasehold, Range brought 25 wells to production in the second quarter, just under half of the 59 new producers on tap for this year. To cut costs, nearly 75% of the new drills were completed on pads with existing production, with lateral reaches from 12,000 ft to longer than 16,500 ft.

Range controls some 470,000 net Marcellus acres, with stacked upside potential in the Upper Devonian and lower Utica/Point Pleasant horizons.

GOING FULL-BORE

Conversely, after increasing production nearly 50% in the third quarter, Seneca Resources Co., LLC is ramping up completion activity for the reminder of FY 2021, given the “near-term run-up in winter natural gas prices” and the impending start-up of the Leidy South expansion. “We have begun the process of accelerating our completion phase, and now have two active completion crews,” said President Justin Loweth on Aug. 6.

During the quarter, Seneca operated two rigs and drilled 12 wells, including the commencement of drilling on the first pad in Tioga County, PA on acreage acquired in last summer’s $504-million acquisition of Shell’s Appalachian assets. The E&P subsidiary of diversified National Fuel Gas Co. of New York averaged combined dry gas production of around 1,030 MMcfd from the Eastern and Western Development areas. With the 450,000 net acres in the Shell acquisition, the company holds a commanding 1.2 million net acres in Pennsylvania.

Seneca’s current activity level will increase capital expenditures by some $45 million throughout FY 2022. “Looking beyond next year, we expect capital to trend downward, as we decrease our activity levels and move to a maintenance and low-growth mode,” says Loweth.

Southwestern Energy Co closed out the first half of 2021 with aggregate production of 545 Bcfe, up sharply from the 402 Bcfe produced in the first six months of last year.

Southwestern averaged five self-owned rigs and two frac crews in the second quarter, split evenly between dry gas and liquids-rich properties, with two each in Pennsylvania and West Virginia and one in Ohio, where the company drilled and completed its first Utica dry gas well. A cumulative 23 wells were drilled across the southwestern and northeastern Appalachian assets, with a total of 19 wells completed and 31 wells put in production.

During the second quarter, Southwestern also reached an agreement with multi-disciplinary Project Canary, a public benefit corporation, to conduct emissions monitoring and certification of Appalachian wells. “The basin-wide well certification process and site monitoring has begun, and we have already installed continuous monitors at several operating sites across our Pennsylvania acreage enabling our operating teams to immediately address potential emissions should they occur,” President and CEO Bill Way said on July 30.

With the 325,000 Marcellus and Utica acres acquired in the November 2020 all-stock purchase of Montage Resources, Southwestern holds more than 786,000 net acres.

PRODUCTION DILEMMA

For CNX Resources Corp., higher dry gas and NGL prices present an attractive dilemma when it comes to maximizing the value of its flowing production. Through the wholly owned midstream subsidiary, CNX has the option of mixing wet Marcellus volumes with Utica gas and selling as blended dry gas or rerouting damp Marcellus production and extracting the NGL component. “Certainly NGL prices are up, but so are gas prices. And so, to us, it’s really about the relative spread between NGL and gas,” says COO Chad Griffith.

Both were in play over the second quarter with cumulative production increasing year-over-year from 114.5 Bcf to 137.9 Bcf. Second-quarter NGL production, however, more than doubled to 9.5 Bcf from 4.7 Bcfe put in the sales lines in the same period last year.

Fig. 3. In an effort to reduce basin emissions, CNX is employing Evolution Well Services’ all-electric frac spread. Image: CNX Resources Corp

Running one rig and a companion frac spread (Fig. 3), CNX drilled seven wells in the second quarter, with 13 wells completed and 14 turned-in-line. The company controls more than 1 million acres across southwest Pennsylvania and West Virginia where it boasts to having the basin’s lowest production costs of $0.73/Mcfe.

Elsewhere, newly reorganized Chesapeake Energy Corp also will significantly reduce hedges going into 2022. In the next fiscal year, 45% of the company’s gas production volumes will be hedged, dropping from 75% in FY 2021. “As much as the basis (differential) has been wide, the realized price that we’re seeing in the field, especially this month, is very, very strong,” CFO Nick Dell’Osso said in an Aug. 11 call.

Chesapeake holds a 540,000-net-acre position in Pennsylvania, where second-quarter production averaged 1,279 MMcfd. Eight months after exiting bankruptcy court, Chesapeake is operating a three-rig fleet, which drilled around 65 Marcellus wells in the second quarter.

After exiting bankruptcy court in May, Utica-focused Gulfport Energy Corp. has laid out a 2021 development plan that includes 19.8 net (21 gross) new drills at average lateral reaches of 15,000 ft, along with 17 wells completed and turned to sales. Second-quarter production from its 193,000 net Ohio acres averaged 744 MMcfed, with average full-year production estimated to range from 975 to 1,000 MMcfed. Running a single rig, Gulfport spudded one well in the second quarter.

For now, the company is employing simul-frac technology to complete the six-well Angelo pad in Jefferson County at lateral reaches averaging 17,220 ft. When it comes online in the fourth quarter, the pad is forecast to deliver combined production of more than 200,000 Mcfd. Angelo joins the earlier completed four-well Shannon pad and three-well Hendershot pad, to the south in Belomont County, and the more recently completed two-well Morris pad in Monroe County.

Owing to reduced pressure decline, the Shannon and Hendershot pads are expected to remain on plateau for up to 10 months, surpassing the historic six-month average for production to drop. The Morris pad is exhibiting similar trends, Gulfport says. “We believe this performance is a direct result of moving to wider spacing and slightly larger fracs,” interim CEO Timothy Cutt said on Aug. 6 during the company’s first earnings call post-bankruptcy.

Typically, Utica wells are developed on 1,000-ft spacing, often combined with smaller and more economical completions, which Cutt said has led to faster and steeper decline rates. Along with longer laterals, Gulfport’s development strategy includes 1,250-ft spacing and higher-intensity completions, featuring 50 bbl/ft fluid and proppant loading of 2,250 lb-ft at a normalized cost of $150/ft.

“The cost to develop a four-well and wider space pad versus a five-well tighter space pad is similar, but we believe that Gulfport’s performance will demonstrate longer plateaus and higher cumulative production during the first few years online,” Cutt said.

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.