February 2020

ShaleTech: Marcellus-Utica shales

Capital discipline reining in rigs, production
Jim Redden / Contributing Editor

Fists have tightened throughout the Appalachia basin, as gas producers finally come to grips with market realities.

With the U.S. Energy Information Administration (EIA) forecasting gas prices to average no more than $2.33/MMBtu this year, capital constraint outranks production growth across the dry and wet gas Marcellus-Utica play of Pennsylvania, West Virginia and Ohio. While production remains at historical highs, the rate of growth has begun to decline, with the EIA estimating February production to rise just under 6%, to 33,346 MMcfd, from 31,292 MMcfd produced in February 2019.

The combined Marcellus-Utica rig count, likewise, has gone from relatively steady to steadily declining, with operators laying down some 33 rigs since the 2019 high of 83 active rigs in early April, according to Baker Hughes, which reported an average 50 rigs active in January. 

“We believe the basin needs around 50 rigs to hold production flat,” said EQT Corp. interim CFO Kyle Derham. “Given a recent commentary from most Appalachia producers regarding capital discipline, we would anticipate rigs falling below maintenance levels in the coming months. We expect these rig count reductions to begin showing up in supply in the back half of 2020 and could lead to exit-to-exit production declines.”

Any drop would be welcomed, as even the height of the winter heating season has failed to significantly draw down bloated storage levels. “I think what’s happening in Appalachia is a little bit of a microcosm of what’s happening more nationally, where storage is getting full. We’re getting up towards the upper end of what the storage levels are. We’re getting past the five-year average storage levels,” said Nick DeIuliis, CEO of CNX Resources Corp.


With little price relief expected this year, operators are confident that supply and demand will begin to balance next year, with an associated uptick in prices. Budding non-weather-related in-basin power and petrochemical demand will get a 1.6-Mtpa boost later this year or in early 2021, with the start-up of Shell’s polyethane cracker in Beaver County, Pa.

Producers also scored a victory of sorts in early September, when the Federal Energy Regulatory Commission (FERC) ruled that New York did not have the right to block the stalled Constitution pipeline, designed to transport Appalachia gas to the consumer-rich upper Northeast. New York naturally appealed the decision, denying it the authority to withhold the necessary water quality certification for the in-state segment of the 124-mi network. “It’s a small win, but there’s still a lot of work to be done,” said Jeffrey Hutton, senior V.P. of marketing for Cabot Oil & Gas Corp., which holds an equity stake in the project. 

Cabot remains committed to a modest 5% production growth target this year and will cut capital expenditures by more than $100 million. Cabot closed out 2019 expecting to spend between $800 million and $820 million to drill and complete around 90 wells in a 179,000-net-acre position concentrated in Susquehanna County, Pa. Preliminary 2020 guidance estimates capital expenditures of no more than $700 million to $725 million. 

President and CEO Dan Dinges said Cabot is continuing to “try to squeeze what we can in [lowering] cycle times” and rationalize the rig and frac fleet in a largely maintenance program in 2020. “For the maintenance program, we don’t need three full rigs throughout the year, and we don’t need two full frac crews for the year,” he said.

Cabot is not alone, as operators in the mature play, which features some of the longest laterals in the unconventional community, are slashing budgets and seeking all opportunities to lower expenses, from bromidic service cost re-negotiations to more avant-garde measures like water-sharing, combo development and electric frac spreads


In updated guidance, premier leaseholder CNX Resources expects 2020 production to drop by 17.5 Bcfe, as it reduces combined 2019-2020 capital spend by around $80 million. For now, CNX plans to run two rigs and one frac crew this year, after operating a trio of rigs and three frac spreads in the third quarter to drill 15 and complete 20 wells. Over the first nine months of the year, CNX drilled 54 wells, with 43 completions and 46 wells put online.

Seven of the new producing wells were on two dry Utica pads that went online in the third quarter as part of CNX’s distinctive wet Marcellus blending strategy in the stacked pay, Southwest Pennsylvania asset. By avoiding processing costs, CNX says mixing damp Marcellus gas with dry Utica gas can generate up to a 30% uplift in asset value. One dry Utica well can blend three to four damp Marcellus wells, according to CNX. 

CNX also credits the first-ever use of gas-powered electric frac spreads as saving around $250,000/well on diesel costs. Evolution Well Services introduced the all-electric pressure pumping technology to the Appalachia basin in second-quarter 2019 after signing a long-term agreement with CNX. 

CNX controls nearly 1.2 million net acres across Pennsylvania, West Virginia and Ohio, with most activity focused on the core Southwest Pennsylvania properties.

Despite the lowest quarterly spend since going public in 2013, Antero Resources Corp. averaged third-quarter production of 3,367 MMcfed, a 24% year-over-year increase. Antero spent $290 million to drill 23 Marcellus wells at average lateral lengths of 11,500 ft and put 33 wells on production. Antero expected to exit 2019 with a cumulative 120–130 wells drilled and 110-120 completions.

Antero tentatively plans to reduce this year’s drilling and completion budget from a high of $1.3 billion in 2019 to $1.15 billion-$1.20 billion. Nevertheless, annual production is targeted to grow 8% to 10% in 2020.

The pure-play operator holds more than 612,000 net Marcellus and Utica acres in West Virginia and Ohio, respectively, where it was averaging four rigs and three to four completion crews at year-end.

EQT will maintain flat production in 2020, while cutting year-over-year capital spending by around $525 million, to $1.3 billion to $1.4 billion. With 720,000 net acres traversing the tri-state area, EQT’s 2020 guidance estimates total year-end production of 1.45 Bcfe to 1.5 Bcfe.

After averaging five to seven rigs and three to five frac spreads last year, EQT will run three to four rigs in 2020, along with three to four frac crews. EQT drilled 20 Marcellus and eight Utica wells in the third quarter, with an additional 23 Marcellus wells on tap for the fourth quarter.

This year, 80% of the wells drilled and 50% of those put into production will adhere to EQT’s combo development scheme which, according to CEO Toby Rice, consists of “properly spaced, large-scale projects to develop 10 to 25 wells for multiple pads simultaneously.”

EQT claims combo development has thus far increased daily footage drilled by 50% and reduced per-foot costs some 40%. 

Holding around 210,000 net acres in Ohio, Utica-centered Gulfport Energy Corp. averaged production of 1.2 Bcfed in the third quarter, up 9% year-over-year. Running a single rig, the company closed out 2019 with an aggregate 15.3 net wells drilled with average lateral lengths of approximately 12,200 ft and 44.3 wells put online. During the third quarter, Gulfport drilled its longest Utica well to date, with a lateral length exceeding 16,000 ft at a measured depth of nearly 27,000 ft.

Pure-play Southwestern Energy Co. drilled 14 and completed 16 wells in the third quarter, with cumulative production dropping to 202 Bcfe from 252 Bcfe in the same year-ago quarter. After idling two rigs early in the fourth quarter, Southwestern was running a single rig and two frac crews in late 2019.

Southwestern holds 184,024 net acres in the dry gas-dominant portion of Pennsylvania, where aggregate production for the first nine months of 2019 came in at 343 Bcf, up from 341 Bcf produced in the first three quarters of 2018. During the third quarter, the operator beat its company horizontal length record by nearly 2,400 ft with two wells drilled in Pennsylvania and West Virginia, with average lateral reaches of 18,300 ft.

Chesapeake Energy Corp. wrapped up 2019, averaging two rigs and one frac spread with an aggregate 44 wells expected to be put online. Third-quarter Marcellus production from the roughly 540,000 net acres that Chesapeake controls in Pennsylvania jumped to 928 MMcfd, compared to 812 MMcfd in the same year-ago quarter. 

While planned 2020 activity levels had not been finalized as of Nov. 5, Chesapeake says it will limit investment in the Marcellus asset, with most capital re-directed to higher-margin oil properties. The company, nevertheless, will average between two to three rigs this year.                        

Nascent Montage Resources Corp. delivered higher-than-expected production of 621.7 MMcfed in the third quarter, but in keeping with a priority of free cash flow over growth, will continue to run a single gross rig in the early going of 2020.

Montage drilled four gross wells in the third quarter, while completing four Utica dry gas and three Marcellus wells. The Marcellus wells were drilled on existing Utica pads, “which further improves our cost structure and rates of returns,” said President and CEO John Reinhart.

Created with the all-stock merger of Eclipse Resources Corp. and Blue Ridge Mountain Resources, Inc., Montage is celebrating its one-year anniversary this month. The company holds 218,000 net acres in southeastern Ohio, West Virginia and North Central Pennsylvania.

Equinor ASA, which holds 247,000 net acres, increased cumulative third-quarter production to 208,400 boe from 168,700 boe produced in the same prior-year quarter. No additional information was made available, pending an operational update in February.


Meanwhile, with injection wells few and far between outside of Ohio, managing flowback and produced water is a critical operational component in the environmentally sensitive Appalachia basin. Getting it right can add appreciably to asset value.

Antero, for one, credits the wholesale blending of flowback and produced water as largely responsible for reducing lease operating expenses (LOE)/Mcfe by 21% in the third quarter, compared to the first half of the year, with a further 15% decline expected this year. Consequently, the fate of the shuttered Clearwater water treatment facility in West Virginia remains in doubt. The nearly $300-million, two-year-old facility was shut down in September for a cost-benefit analysis, and it would appear Antero has no plans for it to resume operations anytime soon. “The closure of the Antero Clearwater facility accelerated well cost-savings, as we increased blending, in order to minimize the high wastewater injection fees and trucking costs associated with it,” CEO Paul Rady said on Oct. 29, also citing “drier completions” as a contributor to lower LOE.    

Range Resources Corp. says a water-sharing program with contiguous operators saved roughly $2 million in aggregate completion costs in the third quarter, alone. “Utilizing other producers’ water in the third quarter totaled 750,000 bbl and represents an over 80% increase, compared to the same time period a year ago,” said Senior V.P. and COO Dennis Degner.

The savings come just as Range reduces 2020 capital spending to 29% less than the $728 million shelled out last year, which was below the original budget. Range operated a reduced two-rig program in the third quarter, but increased daily footage by approximately 35%, compared to the first half of 2019.

Range holds around 875,000 net acres in Pennsylvania, where third-quarter production averaged 2,042 MMcfed, representing a 3% increase over the prior-year third quarter. A cumulative 88 Appalachian wells were expected to be put into production during 2019.

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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