Natural gas is on the up following a turbulent decade. After booming in the early days of the shale revolution, it largely fell out of favor as gas prices collapsed in the early 2010s, and many shale drillers turned their focus to oil, which was more profitable at the time. Both oil and gas have subsequently gone through price downturns, the latest of which was brought on by the arrival of the COVID-19 pandemic in 2020.
Now, while the pandemic continues to affect how trends are playing out, demand is on the upswing as economic activity picks up again amid global supply chain challenges brought about by the disruptions seen since early 2020.
“It’s been interesting if you’ve been watching natural gas for the last decade,” said Campbell Faulkner, a senior vice president and chief data analyst with commodity broker OTC Global Holdings. “It was very hot 15 years ago, particularly in East Texas and onshore, then it kind of fell into irrelevance due to associated dry gas production. And then you have the pandemic disrupt a pretty finely tuned system, and that’s where we are.”
Further uncertainty lies ahead as winter begins, bringing with it the prospects of cold weather and spikes in heating demand.
“The winter story is the same as ever for U.S. gas markets—prices will depend on winter weather,” said Jen Snyder, Enverus’ managing director of intelligence. “In 2021, though, it’s not just weather in the [United] States but also weather in Europe and Asia that will drive prices.”
This was echoed by Faulkner. “This winter, the interesting thing is, we're not just talking about North America, and we're not just talking about the Netherlands like we typically would have been even 18 months ago—gas has gone global,” he said.
This increased interconnectedness of gas markets, along with rising demand, bodes well for U.S. LNG exporters and the gas producers—largely shale—that supply them with feedstock.
“Without a doubt, the demonstrated resilience of the global gas market has been a catalyst for long-term commitments to U.S. LNG development, and we expect additional FIDs [final investment decisions] in the years ahead,” Snyder said. “We look to the Haynesville and gassier Eagle Ford areas to feed new trains.”
Feed gas could also come from the prolific Permian Basin, but as the majority of the gas output there is a byproduct of drilling for oil, it has different drivers behind it.
“In the Permian, development will depend on oil prices, but savvy operators will position to sell into the global market,” Snyder added.
Certain shale producers are keen to capitalize on this boom in demand from LNG terminals and other gas users on the Gulf Coast. This can be illustrated by some major recent deals focused on the nearby Haynesville Shale play spanning Louisiana and East Texas. In early November 2021, Chesapeake Energy completed its acquisition of Haynesville player Vine Energy in a deal valued at about $2.2 billion. Days later, Southwestern Energy announced it had agreed to buy GEP Haynesville for roughly $1.85 billion. Southwestern said the transaction would make it the largest Haynesville producer, in addition to the major presence it already has in Appalachia.
“We knew the Utica play was underappreciated, but it has turned out better than we expected, so far. With the right people, capital and strategy, we’ve effectively turned this asset around.” —Hardy Murchison, Encino
The deal came as Appalachia-focused companies continued to struggle to get new pipelines built. In September 2021, PennEast Pipeline became the latest natural gas pipeline project in the region to be abandoned amid ongoing legal and regulatory challenges. Against this backdrop, Southwestern has been building up its position in the Haynesville, having also acquired Indigo Natural Resources in September for $2.7 billion, before announcing its latest deal to buy GEP Haynesville.
“The deal indicates the overall view of the Haynesville as a superior investment for dry gas,” said Faulkner of the latest transaction. “The Marcellus has been consistently stymied by the lack of investment in takeaway capacity along with a negative regulatory environment.”
He continued, “Natural gas basis prices in the Haynesville also indicate the current view of sufficient future pipeline takeaway capacity. The Haynesville has superior unit economics for dry gas with great existing infrastructure for takeaway. Additionally, the overall location is positioned well for LNG offtake as well as export to the East Coast via existing/older gas pipelines.”
Snyder said Enverus had been expecting consolidation in the Haynesville and that Southwestern was “definitely leading the pack” among buyers.
“Haynesville is well positioned because of the play’s location close to the coast and in a state friendly to pipelines, and deep quality inventory,” she said. “For now, the consolidation is a headwind to activity, but the mid to long term should bring stability to the play.”
Even as some operators expand in the Haynesville, though, others continue to maintain a focus elsewhere, including Appalachia and the Permian. Not all players wish to focus on dry gas, and some will be content with associated gas production, or a balanced portfolio of oil, gas and NGL that enables them to pivot depending on which commodity is more profitable.
Betting on the Utica
Appalachia remains the single largest U.S. gas-producing region, despite some of the challenges it has experienced recently, such as building significant new takeaway capacity. Much of the focus among Appalachian producers has centered on the Pennsylvania portion of the Marcellus Shale. However, this is not the only part of the basin that is considered to have potential.
Other operators have been targeting the Utica Shale play, which also spans several Northeastern states, but it is not renowned for its gas content alone. One of the operators in the Utica—privately owned Encino Energy— is banking on the play’s mix of gas, oil and NGL to help offset the risks of future commodity price volatility.
Encino, which is backed by CPP Investments (CPPIB), was founded in 2011. In 2017 Encino and CPPIB jointly formed an acquisition company, Encino Acquisition Partners.
The partnership was aimed at building “a sustainably profitable, large-scale gas, oil and liquids production company,” according to Encino President and CEO Hardy Murchison.
In 2018 Encino closed a $2 billion acquisition of Chesapeake Energy’s Utica assets in Ohio, consisting of 1 million net acres and holding an estimated 29 Tcfe of recoverable reserves.
“Given the improvements we’ve seen since we bought the assets and the running room the properties still have, we’re extraordinarily pleased with the acquisition,” Murchison said. “We knew the Utica play was underappreciated, but it has turned out better than we expected, so far. With the right people, capital and strategy, we’ve effectively turned this asset around.”
It has not all been positive, with Murchison pointing to the pandemic and the brief oil price war between Russia and Saudi Arabia in 2020 as particularly notable setbacks to the company’s plans. However, he said the asset quality, people and technology had allowed Encino to weather the commodity price volatility that played out.
“The diversity of our reserves—about 70% natural gas along with roughly half a billion barrels of oil and nearly a billion barrels of NGL—allows us to develop and produce profitably in a variety of commodity price environments,” Murchison said. “We’ve driven down well costs per lateral foot by about 50% since 2018 and doubled productivity per foot. With what we think are now the lowest costs per foot in the basin, combined with the oil and liquids revenues, our margins are approaching best in class.” As of mid-November, the company had been producing almost 1 Bcfe/d in 2021, including roughly 15,000 bbl/d of oil.
“We added a third drilling rig [in October], which brings our undeveloped inventory life down to about 30 years and allows us to start growing oil production much faster,” Murchison said.
This growth in oil output is a key component of Encino’s strategy as it targets an oil and gas production mix that balances higher margins with lower greenhouse-gas emissions.
“We’ve had a constructive view on natural gas for years, and we think current market events worldwide are demonstrating the value of gas for many years to come,” Murchison said. “However, margins are still higher in many oil and liquids plays.”
The company’s commodity mix in the Utica “drives our cash margins much higher than most gas producers and our emissions intensity far lower than most oil producers,” he added. “That optionality across all three phase windows of hydrocarbon development—part of what initially attracted us to the Utica—has proven important over the past three years. We think the high margins and depth and diversity of inventory will be key drivers of Encino’s success going forward.”
Murchison said the ability to choose between natural gas and oil wells within the same field is a critical differentiator for Encino. “The ability to pivot allows us to be nimble with capital allocation and maintain high cash margins in the face of commodity price volatility,” he added.
Encino is bullish on the Utica’s prospects, with Murchison saying the formation is reemerging as one of the best gas plays on the continent.
“High-rate dry gas wells with lower costs and lower decline rates compare favorably with the Haynesville,” he said. “Our oil and liquids are big differentiators compared with most of the Marcellus. I think the Utica will probably ‘re-rate’ as a play, much as the Haynesville has in recent years. Given the liquids component, it may compare more closely with the Eagle Ford and parts of the Permian.”
Those other regions could also potentially be of interest to Encino if it finds the right asset at the right valuation.
“Encino is built to do more, and consolidation is clearly picking up steam in the oil patch,” Murchison said. “We’re looking actively at multiple transactions, and I expect we’ll continue growing both with the drill bit and through acquisitions.”
A Different Approach
A decade into the shale boom, unconventional plays are maturing, and with this, questions are increasingly arising over what to do with older, unwanted wells. Such questions become all the more pressing when such wells could be leaking methane, given that new U.S. methane regulations are being brought in and ESG issues are increasingly being treated as a priority.
It is some of these trends that Diversified Energy, which is headquartered in Alabama and listed in the U.K., is tapping into. The company’s business model involves buying aging, producing gas wells and continuing to operate them until the end of their economic life, at which point the wells are retired. It does no exploration of its own, but rather targets already producing wells that are no longer wanted by their previous operators.
Diversified was initially focused on conventional operations, but now its portfolio comprises 67,000 wells—both conventional, vertical wells and unconventional, horizontal ones. Its core operating area is Appalachia, which is a region renowned for shale gas production. The company is interested in taking on more unconventional wells as shale plays mature. It is also expanding its operations in the Central Region, comprising Texas, Louisiana and Oklahoma, having made several acquisitions there.
According to Diversified CEO Rusty Hutson Jr., the company chooses what wells to acquire based on a “disciplined evaluation process.” This includes considering the emissions related to new acquisitions and assessing the impact they could have on the company’s overall emissions profile.
“From the beginning, we set out to establish Diversified as an owner-operator model, focused on optimizing mature assets, being good stewards of those assets, and responsibly retiring them when the wells run dry,” Hutson said. “There’s steady, long-term value in the natural gas that many of these conventional and unconventional assets produce, and we believe our approach, in which a well-capitalized, disciplined operator manages the wells, creates environmentally responsible energy production and delivers long-term value to our stakeholders.”
At its first capital markets day, held in mid-November 2021, the company talked up its environmental credentials, including the fact that it had moved its deadline for net-zero greenhouse-gas emissions to 2040, from 2050 previously. Diversified executives said the company had zero tolerance for gas leaks from its wells, planning not only to identify them but also to eliminate them. They also noted that Diversified plugs more wells in Appalachia than any other operator—and said it does this more cheaply than other companies.
Diversified expects natural gas to play a key role in the energy transition, in which it is planning to play a part. According to comments made by company executives at its capital markets day, Diversified will consider accelerating its well plugging program to generate carbon offsets. It will also evaluate the potential of repurposing its assets for carbon capture and for advancing the growth of the nascent clean hydrogen industry.
Diversified has already bought wells from some leading Appalachian Shale producers, and over time more sellers are expected to emerge as they figure out what to do with their unwanted wells. Given the sheer number of shale wells that have been drilled over the past decade, the need for plugging and abandonment is set to grow, and it would not be surprising if producers are keen to offload their older assets in anticipation of this.
As demand for natural gas, including from liquefaction plants, on the U.S. Gulf Coast grows, producers in the Haynesville Shale play are hoping to benefit from their proximity to the region.
The Haynesville had been in large part neglected after natural gas prices collapsed in the early 2010s, causing many shale producers to pivot to crude oil. For those Haynesville producers that stayed, however, prospects continue to improve. Indeed, recent consolidation in the play, with independents Chesapeake and Southwestern making major acquisitions, illustrates the desire by gas-focused producers to increase their exposure to the region. On the sellers’ side, strengthening gas prices appear to have bolstered private investors’ appetites for exiting the play.
“It is now becoming well understood that the Haynesville Shale is very strategically located close to the Texas and Louisiana Gulf Coasts, which are the best natural gas markets in the United States.” —Alan Smith, Rockcliff
Some private operators remain, however, including Rockcliff Energy II, which is focused on developing the East Texas portion of the Haynesville.
“Rockcliff is an active operator, running four Haynesville rigs and two frac spreads, and has achieved significant size and scale over the past four years through the drilling and completion of over 160 Haynesville wells achieving current net production of over 1 Bcfe/d,” said Alan Smith, Rockcliff’s co-founder, president and CEO. “Rockcliff’s acreage is located near the highly strategic Gulf Coast markets, which provides direct access to multiple natural gas buyers, including LNG buyers.”
Smith sees the Haynesville as being increasingly at an advantage given the trends that are playing out on the Gulf Coast, and some of the challenges that other gas-producing regions, such as Appalachia, are facing.
“It is now becoming well understood that the Haynesville Shale is very strategically located close to the Texas and Louisiana Gulf Coasts, which are the best natural gas markets in the United States,” he said. “The largest natural gas producing area today, which is the Marcellus/Utica up in Appalachia, is takeaway constrained. This means that companies located in the Appalachia area with significant inventory can only drill with a limited number of rigs due to pipeline constraints out of the area. Some companies have secured more takeaway capacity than others, but this generally limits the growth potential for these companies.
“The Haynesville, on the other hand, is not takeaway constrained and is located in a more friendly regulatory environment when additional takeaway capacity construction is necessary,” Smith continued. “Gulf Coast demand continues to increase due to new plants, manufacturing and, of course, LNG exports. Operators in the Haynesville generate outstanding returns, very strong operating margins (lower differentials and no/ lower minimum volume commitment costs, which enhance Haynesville margins) and have great flexibility in their desired development plans, which is a huge advantage for the Haynesville Shale.”
As the U.S. oil and gas industry has evolved, so too have the operators. In Rockcliff’s case, the company said its team has built nine companies across various basins, commodities and economic cycles over time.
“While each company, business environment and commodity cycle is different, the core ingredients that have contributed to the success of Rockcliff are the people and the application of the best technologies available,” Smith said. “The difference when compared to our past endeavors is that our current company is a shale company instead of a conventional assets com pany. We did not do this with the conventional team from the past—instead, it required recruiting the leadership and technical expertise to be able to locate and access the best shale assets we could get our hands on.”
Some consistencies have remained across the previous conventional-focused companies and Rockcliff in its current, unconventional-focused, form, however. Smith described all of these companies as “big hedgers,” consistently opting to hedge a high percentage of future output to mitigate against the risks of significant commodity price fluctuations.
“During the life of Rockcliff II, which began in 2016, we have already experienced a massive commodity cycle, with natural gas prices ranging from $1.33 per MMBtu to $6.37 per MMBtu,” he said.
The company’s strategy of hedging some of its production up to three years into the future paid off during the 2020 price downturn amid the pandemic-driven collapse in demand and prices.
“In 2020 when natural gas was hovering in the $1.50/ MMBtu range, we never laid down a rig or reduced our workforce thanks to our hedge program,” Smith said.
While gas prices are stronger now, publicly listed companies remain under pressure to generate returns for their investors, meaning that they continue to act with caution when it comes to new capex and drilling. Private operators such as Rockcliff, meanwhile, do not have to contend with such constraints.
“The private equity-backed companies continue to be focused on value creation and cash-on-cash returns over the four- to seven-year life spans of most of these companies,” Smith said. “The big question for the public companies is for them to continue to have ample inventory and the growing concern of viability for decades to come—can they achieve this if they are not reinvesting in their respective businesses? In other words, if they pay out all their free cash flow to their investors, how do they discover new reserves and inventory to propel them into the future?”
Despite such questions, the expectation is that new discoveries will be needed as far as natural gas is concerned. Smith sees gas as “a key transition fuel in power generation going forward,” as efforts are made to balance decarbonization with reliability and affordability.
“We don’t disagree that wind and solar should absolutely be part of the equation, but until battery technology can improve to the point that wind and solar are reliable, then it will continue to be a supplement to the reliable power provided by natural gas, and to some extent coal and nuclear,” Smith said.
In the short term, cold winter temperatures can be expected to bolster gas demand. In the longer term, there is some uncertainty over how the energy transition will play out and what that means for natural gas. However, there are reasons for the gas industry to be confident that it could have a role to play.
“We can’t get rid of the thermal fraction. It's not something that’s just going to magically be replaced,” said Faulkner of power generation against the backdrop of the energy transition. “At the end of the day, we need thermal energy sources, so I actually think it bodes very well, particularly for the domestic shale-producing, gas-focused folks.
“I think it’s going to continue to drive domestic production, both from an LNG export standpoint, and just the domestic consumption. We’ve been killing the coal fleet, we’re retiring a large number of nuclear plants, [and] it’s going to put more demand on gas.”
While natural gas continues to make up a part of the energy mix, however, the operators responsible for its production from shale plays, which is where the majority of new U.S. gas output is expected to come from, may evolve further. Public companies, which were instrumental in kicking off the shale boom a decade ago, have stepped back and are continuing to prioritize returns to investors at the expense of new capital spending, even as the gas price environment has improved. And while private companies have played a significant role in keeping production going as their public counterparts started holding back in recent years, a number of them are now taking advantage of improved prices to exit their shale investments.
“There’s not a lot of private equity-backed cash floating around anymore. A lot of the smaller players have exited,” Faulkner said. “What we’re going to see is a continuation of small public companies. Those are going to be who really flourish.”
Enverus also expects public companies to remain comparatively significant producers of shale gas even as larger players maintain restraint.
“We do expect most public companies to grow at low rates, but with solid production bases in place, the volumes are nonetheless significant,” Snyder said. “Some earlier-stage publics will differentiate with growth.”
Different operators will have different strategies, depending on whether they are public or private, and focused on a single basin or multiple ones. However, there are plenty of trends for gas producers to take advantage of currently, whatever their particular circumstances are.
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