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.
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.
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
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
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
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
"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.
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.
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.
TARGET: UPPER MARCELLUS
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
"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
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.
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
"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.
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." WO
Photo: Autumn foliage surrounds a Chesapeake-operated rig at work in
Pennsylvania. Image: Chesapeake Energy Corp.