Appalachian restraint [NGW Magazine]
Gas producers in the Appalachian Basin, home to the Marcellus and Utica shale plays, are adapting to the new era of restraint in shale drilling. However, this does not mean that the region’s output will stop growing, even though some leading producers plan to keep their volumes flat this year compared with 2020 levels.
Overall, Appalachian producers are expected to raise their output in 2021 even as they cut back spending or keep it unchanged from last year, showing that there is still potential for further productivity gains.
Like other shale producers across the US, Appalachian drillers were already under mounting pressure to demonstrate fiscal discipline and prioritise returns before Covid-19 hit energy demand last year. Prior to the pandemic, US natural gas prices were languishing at lows not seen since 2016, causing producers to proceed with caution. Once Covid-19 was declared to be a pandemic and lockdowns began globally, these trends were exacerbated, with demand and prices briefly collapsing.
While a gradual recovery has been underway recently, bolstered by a demand spike on extreme winter weather over the past couple of months, shale producers in Appalachia and elsewhere appear to be in no hurry to abandon the cautious approach.
Capital expenditure guidance for 2021 illustrates this focus on restraint in the near term. EQT Corp., the US’ largest natural gas producer, announced that it spent $1.079bn in 2020, marking a decrease of $694mn on 2019. In 2021, the company anticipates spending $1.1-1.2bn, while also keeping its volumes roughly flat compared with 2020, after output was already unchanged compared with 2019.
It is worth noting that EQT has been engaged in a major review and overhaul of its operations since mid-2019, when activist investor brothers Toby and Derek Rice won control of the company’s board. EQT scaled back its production targets at the time, in order to spend some time reviewing its operations to become more efficient, and this process was subsequently complicated by the pandemic.
Another major player in Appalachia, Southwestern Energy, has said it intends to spend $850-925mn in 2021 and produce 3.05bn ft3/day of gas equivalent, in line with production volumes in the fourth quarter of 2020. The company spent $899mn over the whole of 2020.
Cabot Oil & Gas, for its part, anticipates producing 2.35bn ft3/day equivalent in 2021, with a capex budget of $535mn. This represents a 6% spending reduction year on year even as Cabot’s production rises from 2.34bn ft3/day equivalent in 2020, when it spent $569.8mn.
And Range Resources said it had spent $411mn over the course of 2020 – roughly $109mn less than it had originally budgeted – and announced capex guidance of $425mn for 2021. The company anticipates producing 2.15bn ft3/day equivalent over the course of 2021, up slightly from an average of 2.09bn ft3/day equivalent in the fourth quarter of 2020.
Antero Resources, meanwhile, has announced a significant spending cut. The company unveiled a capex budget of $635mn for 2021, of which drilling and completion will account for $590mn, down 21% from 2020. Antero has described this as being at the maintenance capital level. It is nevertheless targeting production of 3.3-3.4bn ft3/day equivalent over the course of 2021, barely down from 3.65bn ft3/day equivalent in the Q4 2020.
Consultancy Energy Aspects estimates that output from the eight largest publicly traded gas producers in Appalachia will rise by 700mn ft3/day year on year, or 4%, notwithstanding a $650mn decline in capex year on year, or 10%. These eight producers account for 55% of regional output.
The consultancy expects total Appalachia production to rise by 600mn ft3/day in 2021 compared with last year. This is attributed to efficiency gains and producers tapping their drilled but uncompleted (DUC) well inventories, an Energy Aspects senior associate, Ashwin Ravichandran, told NGW.
“Appalachia operators have been heavily relying on DUCs to keep production flat for the last 12 months and we expect them to tap on to these inventories for next two quarters,” he said.
Ravichandran noted, however, that takeaway capacity constrains continue to limit Appalachian growth despite favourable in-basin economics. Energy Aspects expects the northeast Pennsylvania region to drive Appalachian growth in 2021, thanks to both in-basin economics and takeaway capacity additions, but warns that its full potential is also set to be curtailed by takeaway limitations.
The scrapping of the Atlantic Coast pipeline last year came as a blow to Appalachia’s takeaway capacity expansion plans. Construction is still underway on the Mountain Valley pipeline but this work has been marked by delays. Energy Aspects believes this pipeline will ultimately be completed, but not until the second half of 2022.
Appalachian operators are trying to adapt to their operating environment in various ways. One trend, which has played out across other US shale plays too, is the recent uptick in consolidation.
Indeed, Southwestern completed its acquisition of Montage Resources in November 2020, saying the transaction had made it into the third largest Appalachian producer. And in October, EQT struck a deal to buy Chevron’s Appalachia assets for $735mn. Such acquisitions are seen as helping producers pursue scale once they are no longer in growth mode.
“I think producers who have recently consolidated their acreage through either acquisitions or divestiture could be able to optimise their well costs by drilling longer laterals,” said Ravichandran, citing EQT’s ability to tap into Chevron’s acreage by drilling longer laterals from their existing drilling pads. “I think most of the consolidation is largely done, but still there is some more room for consolidation, which could help these producers reduce their well costs by optimising well spacing and lateral lengths.”
Another development for EQT is a growing focus on West Virginia, even though Southwest Pennsylvania continues to account for 65% of the company’s capex this year. Nonetheless, EQT has said that around 40% of its core leasehold is in West Virginia and the state’s share of capex is set to grow from 7% in 2020 to 30% in 2021.
Other notable moves being made by Appalachian drillers include Antero’s decision to partner with a private equity player – QL Capital Energy Partners, which is an affiliate of Quantum Energy Partners – to fund part of its drilling plans. The partnership is worth $500-550mn and will see QL fund 20% of Antero’s development capex in 2021 and 15-20% annually between 2022 and 2024.
Antero said in its fourth-quarter earnings that it was “uniquely positioned” to take on a drilling partner owing to underused firm transportation, a deep liquids-rich drilling inventory and already established gathering incentive programme with Antero Midstream.
Viewed on an annual basis, this funding is comparatively modest, but nonetheless is set to help Antero drill 60 incremental wells over 2021-24. It also illustrates that even with sources of capital having dried up compared to the early days of shale drilling, some avenues remain open to producers, including private equity.
Ravichandran said that in an environment where raising new debt had fallen out of favour – and indeed access was limited – partnering with private equity could be a good way to raise capital.
“At the same time [private equity players] can invest directly gas producers if they wish to ride the commodity upcycle and it could be a win-win situation for both,” he said. “I won’t be surprised if in future more such deals are made in the US shale patch.”