A cooperative thermometer has lost favor as the primary gauge for measuring the economic winds of the gas-rich Appalachian basin.
To point, the debuts of long-awaited pipeline networks, in-basin power and petrochemical demand, and regional exportation of liquefied natural gas (LNG) and natural gas liquids (NGLs) combine to provide seasonally independent markets that overshadow the yearly price bumps that accompany falling temperatures and rising consumption.
The chief of Cabot Oil & Gas Corp., for one, counts some 26 midstream and downstream projects in various stages of development within the Pennsylvania and Ohio swaths of the tri-state Marcellus and Utica shale plays, which feature some of the nation’s longest lateral wells. “If you look at all of those 26 projects, and you get them up to speed and commission them along the levels and size that are forecast up there, that’s greater than 3.5 Bcf of in-basin demand that I don’t think a lot of people talk about,” says President and CEO Dan Dinges.
West Virginia rounds out the triumvirate that has transformed this once coal-dominant basin into one of the world’s premier gas production provinces. Taking in both the dry and wet gas windows of the Marcellus and the Ohio-centric Utica, which is often linked with the underlying Point Pleasant shale, the Appalachian basin is expected to deliver a record 31.569 Bcfgd in February (Fig. 1), according to the U.S. Energy Information Administration (EIA). Moreover, once-widening price differentials are largely in the rear-view mirror, thanks to the basin’s neoteric midstream build-up, highlighted by the Oct. 6 start-up of the Atlantic Sunrise interstate pipeline network.
Marcellus-Utica drilling activity remained steady throughout 2018, a pace that is continuing into 2019, with an average 78 active rigs at work in January, compared to 75 at the beginning of last year, according to Baker Hughes, a GE Company. All but 18 of the rigs at work last month targeted the Marcellus, primarily in Pennsylvania, which also cradles the emerging deep Utica dry gas play.
With a backlog of 55 drilled-but-uncompleted (DUC) wells at year’s end, Gulfport Energy Corp. is the outlier, putting the kibosh on further drilling within its 215,000-net-acre Utica-focused asset. “When you have 55 DUCs in inventory, to continue to drill and add to that inventory for us in this quarter just really didn’t make sense,” interim CEO Donnie Moore said on Nov. 2.
Before suspending drilling in the fourth quarter, Gulfport operated two rigs and spudded 23 gross wells, with average laterals of 10,350 ft. Leaving open the possibility of bringing back one or two rigs early this year, Gulfport produced 294,741 MMcfe over the first three quarters, up from 236,383 MMcfe in the like 2017 period.
POTENTIAL PETROCHEMICAL HUB
Meanwhile, a late-arriving, yet brutal, winter heating season pushed U.S. gas price futures to a two-month high of $3.5910/MMBtu on the New York Mercantile Exchange (NYMEX). However, it is the rich concentration of higher-priced NGL encased within much of the basin that drives a good portion of the drilling activity and brightens the regional supply-demand equation.
Since late last year, Cabot, alone, is flowing nearly 1.05 Bcfd of Marcellus gas “with significantly better pricing realizations” to new markets, which include two new gas-fired power plants in Pennsylvania. The Atlantic Sunrise connection to Maryland’s Cove Point LNG export facility (Fig. 2) also provides Cabot a clear path to capitalize on a 20-year, 350-MMcfd supply contract with Pacific Summit Energy.
Cabot estimated that production in fourth-quarter 2018 will range from 2,225 to 2,275 MMcfed, up from 1,884 MMcfed in the first three months. The company averaged three rigs and two completion crews last year, with an estimated 80 net wells put into production within the tightly concentrated 172,000 net acres it holds, primarily in prolific Susquehanna County, Pa.
Further bolstering the regional outlook, the U.S. Department of Energy (DOE) in December said it expected Appalachian NGL production, particularly ethane, to increase 20-fold between 2013 and 2025, a projection that the agency used to justify a proposed federal ethane storage and distribution hub. Pointing specifically to the basin’s abundant ethane concentration, the results of a commissioned IHS-Markit study released last March concluded that any petrochemical project in Appalachia would be “four times more profitable” than similar ventures along the U.S. Gulf Cost, where the key feedstock is not readily available in sufficient volumes.
In November, pure play Antero Resources Corp. delivered an initial shipment of 337,000 bbl of ethane as part of an 11,500-bpd 10-year export agreement with major Austrian polyethylene and polypropylene producer Borealis AG. The first load was delivered through the Mariner East 1 pipeline to the Marcus Hook, Pa., terminal for export to a Borealis steam cracker in Sweden. The December start-up of the Mariner East 2 also cleared the way for Antero to export up to 50,000 bpd of propane and butane.
Antero plans to average five rigs and four completion crews this year and complete between 115 to 125 wells, with average lateral lengths of 10,200 ft, and another 120 to 130 wells with average 11,900-ft reaches. Production from Antero’s 621,000 net acres in 2019 is expected to jump up to 20%, year-over-year, to a projected high of 3,250 MMcfed. In the third quarter, Antero put a quarterly record 73 wells online, including an eight-well Marcellus pad with 60-day average production of more than 23 MMcfed/well, including 25% ethane recovery.
The opening of new markets, likewise, has some players jockeying for position, though not on the scale seen in other shale basins.
ASSETS CHANGE HANDS
It was generally believed that EQT Corp.’s $6.7-billion acquisition of Rice Energy Inc. in late 2017 would set off a wave of regional consolidations, especially as operators look to block up acreage to accommodate ever-increasing laterals. While deals of that magnitude have yet to materialize, 2018 saw a number of smaller transactions unfold.
Among the “not-so-small” deals, Chesapeake Energy Corp. in late October finalized the sale of its entire Ohio Utica holdings to Encino Acquisition Partners for $2 billion. The deal gives Encino 900,000 net acres, 900 producing wells and some 119,00 boed of production.
A Utica early mover, Chesapeake retains approximately 547,000 net Marcellus acres in Pennsylvania, which produced 135,000 boed in the third quarter. Chesapeake, which tentatively plans to add a third rig this year, expects the Marcellus asset to deliver $350 million in free cash flow in 2018.
Deals completed in 2018 also included the all-stock merger of Pennsylvania’s Eclipse Resources Corp and Irving, Texas-based Blue Ridge Mountain Resources, Inc., which was to close in the fourth quarter. The combined company plans to run a two to three-rig development program this year across its 227,000 net effective undeveloped acres. In late 2017, Eclipse drilled a Utica well in southeastern Ohio with a then-record 20,800-ft lateral reach.
Eclipse spudded nine gross operated Utica wells, and connected 13 wells to production pre-closing, including the first Utica well in the Flat Castle development in northern Pennsylvania. Completed with a lateral reach of around 13,800 ft, the well flowed at a better-than expected 35-day rate of 32 MMcfgd. Eclipse expected post-closing fourth-quarter production to reach 500-560 Mcfed, including an estimated 187-to-212-MMcfed contribution from Blue Ridge.
An approximately $1.5-billion buying spree last year netted privately held Ascent Resources-Utica, LLC an additional 113,400 net acres, which included 93 operated wells, with production of approximately 216 MMcfed. Sellers included joint venture partners Hess Corp. and CNX Resources Corp, which received $400 million for the jointly operated 39,000 net Utica acres and some 14,000 boed of production in eastern Ohio.
Just over a year removed from splitting with its former coal producer parent, CNX exited 2018 with projected Marcellus and Utica production of between 497.5 and 507.5 Bcfe. Following accelerated completion activity late in the year, 35 Marcellus-Utica wells were put online in the third quarter, setting the stage for a significant production ramp over the final three months of 2018. The third-quarter production mix included a 17% year-over year increase in Marcellus production to 70.6 Bcfe, while the deep dry gas play in Pennsylvania contributed to the 67% hike in Utica production to 33.6 Bcfe.
Averaging four rigs and three frac crews in the third quarter, CNX drilled 23 wells, including 15 Marcellus wells in Greene County, Pa., and completed 27 Marcellus and Utica wells. CNX expected to wrap up 2018 with the drilling of 64 Marcellus and 15 Utica wells, including stacked-pay prospects on two multi-well Marcellus-Utica pads in southwestern Pennsylvania.
An independent operator since spinning off from CONSOL Energy Inc. on Nov. 29, 2017, CNX controls some 1 million net acres.
On Aug. 30, privately held PennEnergy Resources, LLC paid $600.5 million to acquire Rex Energy Corp, then under bankruptcy protection, expanding its property base to 203,500 gross acres, primarily in southwestern Pennsylvania. The combined assets give PennEnergy net production of 450 MMcfed.
PUSHING THE ENVELOPE
Meanwhile, Pittsburgh’s EQT has been forced to dial back efforts to quickly, and literally, extend its reach across an estimated 1.2-million-net-acre leasehold. With much of the largely contiguous properties concentrated in a 680,000-net-acre Marcellus core, EQT in 2018 went full-bore in pushing lateral lengths well beyond the 14,000-to-15,000-ft “sweet spot,” a move the company now concedes was premature.
“With the Rice acquisition, we found ourselves with a land position that gave us the opportunity to go from an average of 8,000-ft laterals to almost 14,000 ft,” said Senior V.P. and CFO Rob McNally. “But, mixed in there were quite a number of laterals that were between 15,000 ft and 20,000 ft, and many in the kind of 18,500-ft range, which present a whole new set of challenges, stretching rigs to the limits of their capabilities.”
EQT was expected to wrap up 2018 with the drilling of 115 to 120 Marcellus wells in Pennsylvania and West Virginia, and 34 gross Utica wells in Ohio. The company plans to stabilize at around 10 rigs and six to eight frac crews this year, after fluctuating between nine and 11 rigs (Fig. 3) and six to eight frac crews in 2018.
For now, a horde of ultra-long reaches is not on the board. “In hindsight, we probably tried to drill too many of those ultra-long laterals in 2018. I think that there is potential upside in drilling those longer-than-15,000-ft laterals, but we need to do it at a more measured pace, so that we can incorporate the learnings into the next well as opposed to having multiple ultra-long laterals going at once,” McNally said.
With the late 2018 drilling of a southwestern Pennsylvania well with an 18,566-ft reach, first-mover Range Resources Corp., for now, can lay claim to the longest Marcellus well to date. Results also were pending at year-end on two newly completed 18,000-ft lateral wells drilled within a Pennsylvania footprint comprising roughly 875,000 net acres, most of which offers stacked pay potential, combining the Marcellus, Utica and Upper Devonian shales. Range expected to put 92 wells on production in 2018 at completed well costs ranging from $6.5 million to $9.2 million. Third-quarter net production averaged around 1,988 MMcfed, a 24% year-over-year quarterly increase.
Southwestern Energy Co., for another, established company records in the third quarter with the 16,272-ft and 15,559-ft laterals of two wells drilled in Pennsylvania and West Virginia, respectively. The duo was among the aggregate 22 wells that the company drilled in the third quarter across its 500,000 net acres in southwestern and northeastern Appalachia, which produced 535 Bcfe over the first nine months of 2018. Staking a claim as one of the basin’s largest NGL producers, Southwestern estimates 2018 production of 707 to 731 Bcfe.
Southwestern ended the year averaging three wholly-owned rigs and two frac crews, and the firm may run up to six rigs in 2019. Company-owned rigs and self-sourced sand have helped enable Southwestern to “mitigate increases in cost quite well,” says President and CEO Bill Way. ‘We’re actually seeing a deflationary effect on the balance of items we use.” Completed Marcellus wells, with 6,960-ft to 6,994-ft average horizontal reaches, currently cost between $7.0 million and $8.6 million/well.
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