May 2019, Vol. 246, No. 5


Marcellus, Utica Plays Offer Unlimited Promise, Nagging Questions

At the end of 2018, when the U.S. Energy Information Administration (EIA) released its latest (2017) statistics on proved oil and natural gas reserves, the United States producers were leading the world, and the Marcellus Shale play in Pennsylvania was leading the nation.

Both Marcellus and Utica shale, which combined comprise the Appalachian Basin, have been producing some astonishing statistics since they burst on the domestic U.S. energy scene early in this decade.

EIA analysts estimate what they designate as “East” gas production will lead the nation for the next 30 years. However, they cannot clearly predict how unpredictable political, regulatory and economic shifts might affect their projections going forward.

In a swing state like West Virginia, which includes parts of both the Utica and Marcellus, sticky issues in February of this year included deep well spacing and abandoned or orphaned wells. Eventually, they could greatly affect production growth and operator costs. The West Virginia Oil and Natural Gas Association has been advocating legislative proposals designed to free up the industry by eliminating outdated restrictions.

A testament to the robust production activity in this region is the presence of strong industry organizations like the West Virginia contingent, including the Ohio Oil and Gas Association, the Northeast Gas Association, and the ever-vigilant Marcellus Shale Coalition.

This presence was never more relevant, with the almost daily challenges and obstacles to address as the midstream struggles to build enough infrastructure to keep up with the record-breaking production.

An example, in February, was the rejection from the 4th U.S. Circuit Court of Appeals of a joint request from Dominion Energy and the U.S. Forest Service (USFS), regarding Dominion’s Atlantic Coast pipeline. The USFS was chewed out by the court for “abdicating its responsibility” to preserve national forest resources.

At the outset of spring this year, there were 25 active FERC-regulated gas pipeline projects, involving 14 separate companies or consortiums. With a couple of other projects added, there are 27 projects valued at $32.6 billion, representing potentially 3,500 miles of new pipe in the ground.

“We expect to see increasing investment discipline and
returns across the value chain as we move out of the
early stage ‘dot-com phase’ of the shale revolution.”

— Christopher Wright, CEO,
Liberty Oilfield Services  

Collectively, these represent 124,000 jobs, with gas capacity of 22.7 Bcf/d and 445,000 bpd of natural gas liquids (NGL), according to a tally by Energy In Depth (EID), an oil industry research, education and public outreach organization.

In a February blog, BTU Analytics analyst Andrew Bradford predicted Appalachia was turning the corner and could be looking at excess pipeline capacity in the early 2020s. Bradford estimated a total of 30.4 Bcf/d as an average collective pipeline capacity in 2020.

“In the long-term, our numbers are pretty flat,” he said. “There are others out there with much more bullish views [Antero, 37 Bcf/d by 2023; Energy Transfer Partners, 42.5 Bcf/d by 2025; Kinder Morgan, 41.5 Bcf/d by 2027; and TransCanada, 44 Bcf/d by 2027].

“We see Appalachia going from being pipeline constrained for a long, long time to going to a macro-market where we are demand constrained. We don’t see enough basin demand in Appalachia or enough demand growth in adjacent regions.”

As EIA and other energy data gathering organizations know, the latest reserve records have been established amid U.S. crude oil productions levels not seen since the early 1970s.

The experts suggest stronger oil and gas prices globally, combined with the continuing development of shales and low-permeability formations, propelled the record proved reserve levels. The new natural gas numbers are what EIA called “an extension of a longer-term development trend” centered in the Marcellus/Utica shale plays.

“Both U.S. proved reserves of crude oil and natural gas are approximately double their levels from a decade ago,” EIA noted in its latest report. “Prior to 1997, gas and oil reserves had been declining since the 1970s.”

Like the other prominent U.S. shale basins, Marcellus and Utica are populated by efficiency and technology driven operators who have taken ever-longer laterals and turned them into successes through precision targeting, high-density stimulations, and cost savings. Lateral lengths have long ago passed the seemingly very long two-mile distance, now regularly exceeding three miles.

In 2017, proved gas reserves increased in each of the top eight U.S. natural gas reserves states, in which the three “East” Appalachians (Pennsylvania, West Virginia and Ohio) were ranked Nos. 2, 5, and 7, respectively.

Pennsylvania had the largest one-year net increase in proved reserves of 28.1 Tcf in the Marcellus and Utica plays, and in early March, the state Independent Fiscal Office reported overall gas production last year exceeded 6 Tcf, a 14.2% year-over-year increase. At the end of 2017, EQT Corp. successfully completed the longest lateral by any operator to date – the H18 well in Washington County at 17,400 feet, or more than three miles. In 2018, EQT’s goal was to drill 27 wells in Pennsylvania, all more than three miles long.

“Total U.S. gas production across most cases is driven by continued development of the Marcellus and Utica shale plays in the East,” said Stephen Leahy of the Northeast Gas Association (NEGA), citing U.S. EIA.

“Technology advancements and improvements in industry practices lower production costs in [EIA’s] Reference case and increase the volume of oil and natural gas recovery per-well. These advancements have a significant cumulative effect in plays that extend over wide areas that have large undeveloped resources [Marcellus, Utica and Haynesville plays],” EIA’s late 2018 outlook stated.

BTU Analytics’ Bradford thinks it is “dangerous to bet against technology,” noting recent years in the U.S. shale boom have proved how true that is. “Are we at the point of diminishing returns? Have we squeezed 80% of the juice out of the orange? Or 50%?” he asks rhetorically. “We’ve come a long way, and at some point, you would expect some diminishing returns on technology, but that is a dangerous step to take.”

Besides its steady growth over the past 10 years, a fact that stands out for EIA’s East,” or Appalachia, is the consistent praise it receives from analysts, researchers and consultants alike who also are smitten with the Permian and the Bakken. Nevertheless, they seem to swoon even more over the three-state Marcellus-Utica shales that have been given the nickname of “Crescent USA.” Referring to the moon-like curved shape that represents how the gas play sweeps from Pennsylvania to Ohio.

The Potential Gas Committee (PGC) at Colorado School of the Mines in Golden, Colo., in its latest fully vetted report dubbed the Atlantic as North America’s “richest resource area,” barreling ahead of the Gulf Coast, Rockies and Mid-Continent areas with 39% of the resources compared to 20%, 17% and 14%, respectively, for the other three, any one of which would normally be thought of as the oil and gas centers.

“The largest volumetric gains (214 TC or 26%) were reported in the Atlantic area,” PGC stated. “The major reason for the increase is new drilling and production results from Marcellus, Utica and Rogersville shale plays in the Appalachian Basin.”

On a year-end earnings conference call in February, Houston-based Cabot Oil & Gas Corp.’s CEO Dan Dinges was comparing the lower- and upper-Marcellus reservoirs, he said the upper-area “remains one of the most economic reservoirs in North America.” Dinges has openly revealed said at Cabot – one of the largest producers in the Marcellus – plans to continue drilling the upper-Marcellus well samples to build an “ever-larger population” of wells there.

Cabot’s tests, he said, have shown there to be “multi-decades” of inventory life from what Dinges called a world-class asset. Elsewhere in the region, the same success has eluded Cabot as in north-central Ohio where in February the E&P stopped unconventional drilling based on what it called poor results, leaving the company with its Marcellus focus in Pennsylvania.

Speaking to the ever-problematic issue of takeaway pipeline capacity in Appalachia, Dinges said much of Cabot’s recent financial success has been tied to what he calls “long-awaited new capacity in the basin, demand projects that we have been working on for literally years.”

Looking at respected analytical shops, such as RBN Energy LLC and BTU Analytics, the story is much the same. While those analyses can call out volatility, takeaway capacity and local political challenges, for example, they cannot get away from being bullish about Appalachian resource base.

RBN Energy, which comments on the Marcellus-Utica regularly, covered the extreme price and production volatility in the fall last year, encouraging its analysts to publish a 26-page report on the evolving Northeast gas takeaway capacity use and additions, noting the price impacts. In that report, RBN noted the Northeast gas gyrations have had a “domino effect” on the larger U.S. natural gas market. It has turned what they call a “traditional demand-driven market” into a net U.S. gas supplier.

Marcellus-Utica blogging from analysts tends to inspire more than dry analytics, who often show that there can be a poetic element in the usually arcane geological and oil and gas writing market.

As RBN’s Sheetal Nasta explained in October last year: “The Northeast’s role in the gas market is again on the cusp of a profound shift, led by the latest round of Marcellus/Utica takeaway expansions,” continuing to explain that after constant construction and regulatory delays, the sun was shining again, and several large-capacity expansion pipeline projects “turned up the spigot” before the end of last year.

Since the final quarter of 2018 there has been more bullishness expressed by pundits because key projects such as part of the Williams Companies’ Atlantic Sunrise gas pipeline project opened in October bringing another 1.15 Bcf/d of capacity out of the Marcellus to the Northeast.

“Several of the largest shippers on Atlantic Sunrise indicated that they will initially fill their commitments with a combination of new [Appalachian] and redirected gas, and in the first few days, gas in Susquehanna County [Pa.] has been redirected primarily from [Kinder Morgan’s] Tennessee Pipeline to help fill Atlantic’s Central Penn North pipeline,” said a report from Colorado-based BTU Analytics, which in its October blog was declaring “a new day in Pennsylvania.”

Over the recent years, analysts like BTU Analytics have carefully followed the progress, and often lack thereof, of key projects besides Atlantic Sunrise, such as Rover, Nexus, Gulf Xpress and others, that they and others have touted as influencing production and pricing over the next four or five years.

“While Atlantic Sunrise increases the gas supply in southern Pennsylvania and southern New Jersey (Transco Zone 6, south), there are other system bottlenecks to consider,” said BTU’s analysts.

The Marcellus-Utica petroleum product history is thick in recent years, and although it was composed nearly six quarters ago, a Moody’s Investors Service report, “Even in the Most Prolific Basins, Earning Healthy Returns Is a Challenge,” offers some cogent points that rating agencies like to focus on – costs and product mix, particularly when natural gas liquids (NGL) are involved. Back in September 2017, Moody’s Sajjad Alam, vice president and senior analyst, touted the Marcellus as the fastest growing U.S. gas-producing basin.

Alam highlighted the fact that across the Marcellus, firm transportation costs were somewhat the same, but price realizations by producers varied widely. A key was product mixes.

“Marcellus yields more liquids in less thermally mature areas in southern Pennsylvania and northwest West Virginia offering 10%-35% more NGLs by volume, which provides significant price benefits,” Alam wrote. At the time, he noted more than two-thirds of the Marcellus rig activity was concentrated in the lucrative NGL areas.

Alam goes on to identify the prime areas as ones where producers “have a robust gathering and processing network, and midstream companies have more willingly invested in long-haul pipelines to market gas and NGLs outside the basin. Price realizations and cash margins are significantly lower despite a 20-30-cent cost advantage in northeastern Pennsylvania, which is mostly dry gas and less developed midstream infrastructure.”

In early March, Nicole Jacobs and Dan Alfaro, with EID, deconstructed more than $32 billion in Appalachian Basin pipelines, noting that the region was becoming the one to watch for “increased NGL production, particularly when it comes to ethane, the building block of petrochemical feedstocks and plastics manufacturing.” They credited Department of Energy Secretary Rick Perry for calling this out.

In Ohio, the oil and gas industry historically has been “more welcomed,” according to Mike Chadsey, of the Ohio Oil and Gas Association, who said the Utica and Marcellus have continued to draw increased investment, particularly from its biggest producers (Ascent Resources LLC, Encino Energy LLC, Gulfport Energy Corp., Antero Resources Corp., and EQT Corp.). State officials have estimated that the oil and gas sector has invested $70 billion in the state since the start of the shale boom.

In late February, the Ohio Department of Natural Resources indicated there were 17 rigs in the Utica and one in the state’s portion of the Marcellus operating, with more than 2,500 horizontal wells and 3,000 permits generated in the New Year in the Utica.

In 2018, Ohio’s Utica Shale accounted for almost all the rapid increase in gas production in the state, which was 21 times greater in 2017 than 2012, according to U.S. EIA. Ohio is the nation’s eighth-largest ethanol producer and sixth-largest in crude oil refining capacity.

In the northeast portion of the Appalachian Basin and the greater Northeast region, including New England, NEGA, the electric generation sector, and gas industry promoters indicate there are both good and bad stories to tell in seeking to map out the future for the dominant shale plays.

Earlier this year, giant New York City utility Consolidated Edison (ConEd) shook up NEGA officials by declaring a moratorium on new gas service connections in the burgeoning, affluent Westchester County area of its service territory. NEGA’s Leahy called ConEd’s move and other small utility moratoria “troublesome,” noting the lack of adequate midstream infrastructure capacity is the common stated reason for these actions by the distribution companies.

In talking about the broad region, Leahy acknowledged that beyond the Appalachian Basin, there are pockets of strong local resistance to gas pipelines centered on what he calls “a strong environmental awareness around energy production and its role in society. It is challenging to get things built.” Leahy calls the hookup moratoria “a new trend that hopefully won’t expand. The moratorium in Westchester County has caused a lot of concerns in the business community.”

While the roadblocks come mostly from the regulatory and political sectors, the power sector’s increasing needs and willingness to sign on for long-term gas contracts has been very helpful to prospective pipeline projects, Leahy said. Gas has become the predominant fuel for making electricity in the East. In New England, 49% of the power comes from gas-fired generation, and that percentage is 58% in New York state.

This winter, the head of the New England Independent System Operator, Gordon van Welie, talked about the challenges of obtaining more gas for power generation on the regional grid.

For the regional electric industry stakeholders, Van Welie described the current state of New England’s grid as “holding steady on a strong foundation, but the power system is changing, and vulnerabilities are growing.”

Van Welie emphasizes how this raises the energy security risk, and pipeline capacity expansion troubles underscore this greater risk, he thinks.

“With an evolving resource mix and inadequate fuel delivery infrastructure, there may not be enough energy to satisfy electricity demand during extended cold weather and, increasingly, year-round competitive markets are under stress, said the ISO-NE CEO.

“Public policy initiatives provide financial support to renewables and distributed resources, artificially suppressing prices for all resources. [As a result,] ISO-NE continues to adapt market rules and planning and operational procedures to ensure continued reliability and fair competition for all resource types,” Van Welie noted.

Leahy said the regional grid operator doesn’t see any major pipeline expansions coming into New England because of the political and regulatory climate, and for him, “that contributes to the angst in the power sector. We have small, incremental projects, but that is it.”

There is nothing small or incremental about Appalachian natural gas production, or the its long-standing need for midstream infrastructure. The focus of the U.S. gas industry surely will continue to shine brightly on “Crescent USA.” But while the future holds plenty of action, the ride promises to be bumpy at times. Buckle up! P&GJ

Richard Nemec is P&GJ’s Los Angeles-based correspondent. He can be reached at

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