Facts & Rumors # 543
February 17, 2024
Latest facts and rumors from the Marcellus, Utica, and Permian, Eagle Ford Plays
Diamondack to Merge with Endeavor. Diamondback to merge with Endeavor in blockbuster $26 billion private buyout. Houston Chronicle. Diamondback Energy said Monday it would acquire Endeavor Energy Resources in a transaction valued at $26 billion, a blockbuster deal that would create the largest pure-play in the Permian Basin of West Texas and New Mexico. The large publicly owned oil company based in Midland said it would buy Endeavor, a private company also based in Midland, for $8 billion in cash and 117.3 million of its shares. Existing Diamondback shareholders are expected to own 60.5% of the combined company. The deal continues a consolidation trend that is rippling across Texas as publicly held oil companies seek to expand their inventories through acquisition. Expected to close during the fourth quarter, the deal would create the largest company dedicated solely to the basin, and the new company would trail only Exxon and Chevron in terms of total oil production in the Permian, said Alex Beeker, research director at Wood Mackenzie. Financial Times and WSJ also report.
Possible Merger. Devon Energy and Enerplus. The merger and acquisition deals are coming in the shale patch, at a rate almost too fast to document. Last week news broke about Devon Energy, and Canadian-based producer, Enerplus, opening merger talks. Enerplus has some choice acreage in the Bakken play that would be very attractive to Devon as it fills in a lot of gaps in its own prime Bakken acreage. They also hold some non-operated acreage in the Marcellus, that would likely be sold off as Devon has no other operation in that basin. The Bakken is home to some of the longest shale laterals, and the ERF “jigsaw puzzle” pieces would assist DVN greatly in maximizing the production from the play.
Details are sketchy at this point, and I wouldn’t be surprised if ERF isn’t holding out for a cash premium given the liquids-rich “dirt”- 68%, they own. That would be the smart play for their shareholders. DVN has reached for its checkbook in its last couple of deals, for RimRock, and Validus. The stocks of both companies are off from peaks set in Q-3 of last year, DVN about 30% and ERF about 15%. This is the time to be merging with companies that can contribute immediately to the bottom line, and synergistically make Newco potentially a better entity than the two were separately. That’s what’s supposed to happen anyway.
Occidental Pumping More with CO2. Occidental to pump more Permian oil using captured CO2. E&E News. Occidental Petroleum plans to ramp up its use of captured carbon dioxide to pump more oil out of the Permian Basin, harnessing the company’s growing network of direct air capture projects. The company announced the plan Thursday afternoon during a fourth-quarter earnings call. Officials said they plan to bring online about 60 wells, where operators will pump carbon dioxide underground to squeeze more oil out of the earth in a process known as enhanced oil recovery (EOR).
Occidental – CrownRock Deal Delayed. Occidental hits speedbump in $12 billion Permian acquisition. Upstream. The completion of Occidental Petroleum’s $12 billion acquisition of shale oil and gas company CrownRock has been delayed after the US competition watchdog requested more information from the pair. Occidental said in its third quarter conference call on Thursday that the Federal Trade Commission (FTC) wanted more information related to the acquisition, which will give Oxy a major boost to its portfolio of assets in the Permian basin, the most prolific shale producing play in the US.
FERC Approve NatGas Projects. FERC greenlights projects that could unleash gas exports. E&E News. The Federal Energy Regulatory Commission approved two natural gas projects Thursday that seek to boost gas exports as a rift widens between the fossil fuel industry and environmental critics. FERC approved the Saguaro Connector pipeline — proposed by Oneok — that would run about 500 miles and transport 2.8 billion cubic feet of gas per day from Texas to the coast of Mexico.
Risk to TX Oil Companies from Middle East. What Texas oil companies have at risk as Middle East tensions rise. Houston Chronicle. Just 15 miles off the Israeli coast, Chevron operates a natural gas field that has already had to be shut in once over fear of a missile attack. Approximately 1,200 miles to the east, along the Persian Gulf, ConocoPhillips, Exxon Mobil and Shell are drilling for oil and gas through joint ventures with state-owned oil companies that have previously been targeted by terrorists. And 1,400 miles to the south, BP has had to divert tankers from passing through the 20-mile-wide Bab el Mandeb Strait, where Iran-backed Houthi militants are firing missiles at passing ships. Four months after Hamas fighters swarmed across the Israeli border, killing more than 1,100 people and kidnapping over 200 more, many of the oil and natural gas companies that operate in and around Houston have much at stake as tensions in the Middle East build.
LNG Projects in Rio Grande Valley Not Affected by Biden Pause. LNG projects in the Valley not affected by federal pause on new export terminals. 5News KRGV, The two companies given the green light to operate liquefied natural gas export terminals in the Rio Grande Valley continue being built. Last month, the Biden administration announced a pause on applications for new LNG export terminals. Rio Grande LNG and Texas LNG received permits prior to that announcement, and experts say that could be a good thing for the local companies. “LNG is a very competitive landscape, and so if the door is closed on a whole group of projects, arguably, the ones that are already permitted may have an advantage,” Rapidan Energy Director of gas research Alex Munton said. Both companies aren’t completely in the clear just yet. They will need to start the seven-year renewal process in a few years.
2024 and 2025 NatGas Spot Price Outlook. What is the outlook for the natural gas spot price in 2024 and 2025? EIA. In 2022 and 2023, increases in natural gas supply (domestic natural gas production and imports) exceeded the increases in natural gas demand (domestic consumption and exports). In 2024, we expect the reverse will be true: demand increases by 2.3 billion cubic feet per day (Bcf/d) in our forecast, and supply remains relatively flat. In 2025, we expect supply and demand to grow at similar rates, although inventories will build because supply will still slightly exceed demand in our forecast.
NatGas Production Drop Continues. Thanks, MDN. EIA Feb DPR: Production drop continues in M-U, but slows. Marcellus Drilling News. The latest monthly U.S. Energy Information Administration (EIA) Drilling Productivity Report (DPR) for February, issued yesterday (below), shows EIA believes shale gas production across the seven major plays tracked in the monthly DPR for March will decrease production from the prior month of February. This is the eighth month in a row that EIA has predicted shale gas production will decrease for the combined seven plays. However, the decrease is less than in previous months, meaning the rate of decrease is slowing. EIA says combined NatGas production will slide by a cumulative 25 MMcf/d (million cubic feet per day). The Marcellus/Utica, called “Appalachia” in the report, is predicted to decrease by 76 MMcf/d in March compared with February.
NatGas Producers Making Cuts. U.S. NatGas drillers cut spending, reduce activity amid price crash. Reuters. U.S. natural gas producers are slashing spending and reducing drilling activity following a sharp decline in prices, companies said this week during earnings presentations and analyst calls. For months of relatively low gas prices, many producers kept output mostly steady on expectations that demand would rise in 2024 and 2025 when several liquefied natural gas (LNG) export plants enter service.
LNG to Surge by 50% by 2040 – Shell. LNG demand to surge 50% by 2040 in clean-fuel transition, forecasts Shell. Financial Times. Global liquefied natural gas demand is forecast to surge 50 per cent by 2040 as the world transitions to cleaner fuel, Shell said in its latest annual LNG outlook. Demand for natural gas globally will then peak after 2040, although appetite for LNG will continue growing as China and developing Asian nations switch from dirtier coal to the comparatively cleaner fuel. The growth forecast is slightly lower than predictions last year, but energy majors still expect a strong rise in LNG demand as the world’s economies target net zero carbon emissions by 2050.
MVP Keeps Progressing. Mountain Valley pipeline escapes suit by Virginia landowners. Bloomberg Law. Mountain Valley Pipeline LLC won its bid Tuesday to continue construction of a more-than-300-mile-long natural gas pipeline through Virginia despite a protest from affected property owners. The US Court of Appeals for the D.C. Circuit, after remand from the US Supreme Court, affirmed the district court’s decision to dismiss for lack of jurisdiction a lawsuit brought by landowners whose properties were in the path of the pipeline and were seized by eminent domain.
Google Wants to Be “Big Brother” for Methane Leaks. Google to share oil and gas methane leaks spotted from space. Reuters. Google and environmental group Environmental Defense Fund on Wednesday unveiled a partnership to expose sources of climate-warming emissions from oil and gas operations that will be detected from space by a new satellite. MethaneSAT will launch next month, one of several satellites that are being deployed to monitor methane emissions across the globe to pinpoint major sources of the invisible but potent greenhouse gas. It is a partnership led by EDF, the New Zealand Space Agency, Harvard University and others.
Will NatGas Prices Stay Down? Thank You, Natural Gas Intelligence (NGI) U.S. natural gas markets are looking dire for sellers, with futures diving near depths last seen during the Covid-19 pandemic. Several catalysts lie ahead, though, that could create a floor and set the stage for a rebound, according to analysts.
The March New York Mercantile Exchange (Nymex) contract fell below the $2.000/MMBtu level on Feb. 7 and hasn’t looked back, dropping in seven straight sessions, the latest on Wednesday, down 8.0 cents to $1.609. The contract traded as low as $1.590, within 11 cents of the lowest prompt-month close in the post-shale era of $1.482 in June 2020.
Meanwhile, NGI’s Henry Hub spot prices fell 15.5 cents day/day to average $1.510 on Wednesday. The benchmark cash price last touched this level in July 2020.
Prices have sunk under the weight of near-record Lower 48 production and Old Man Winter whiffing for a second year in a row. Forecasts for late February were turning warmer, dashing hopes of a last gasp of cold to reduce the surplus of gas in working storage.
The next wave of added LNG export capacity arriving in 2025 should act as major price support, but all of 2024 lies between the market and that goalpost. In the meantime, one inflection point for prices could come if exploration and production (E&P) companies were to react to the selloff and take steps to reduce gas volumes, several analysts said in recent updates.
A second support could come from a strong summer burn — a possibility, according to bulls, if coal retirements and rising demand outpace the wave of renewable builds.
“It’s a bloodbath out there,” East Daley Analytics analyst Jack Weixel told NGI. “The market is trying really hard to signal to producers to pump the brakes. Is it working? Not yet as daily production estimates are still plus-105 Bcf/d. But it will work.”
The East Daley forecast sees Henry Hub cash prices bottoming out in May and ramping from July and faster in July and August as gas inventories fall to a deficit to the five-year average, finishing the year closing in on $3.50, Weixel said in a recent webinar.
That’s not without pain first. Given weak fundamentals “we believe there is risk to inventories finishing above 1,900 Bcf and further suppressing prices through the 2024 shoulder season,” Weixel said Tuesday.
Similarly, EBW Analytics Group analyst Eli Rubin said Wednesday recent losses in Nymex futures are justified by the deteriorating chances of late winter cold. “In the unlikely event producers fail to trim production in response to lower prices, 2024 injection season prices may drop to average $1.88,” or another 10% of downside from current levels, Rubin said.
EBW Analytics on Wednesday predicted the Nymex April contracts could range between $1.48 to $1.92, while further out to 90 days the June contract could stage a rebound with a range of $1.91 to $2.38.
A relief rally is likely at some point over the next 30-45 days, while over the next 90 days “producers cutting their production guidance could help rebalance the market,” Rubin said.
However, if more aggressive output cuts are needed to rebalance the market, the price signal required could be well below current levels.
“Producers will likely start curtailing in earnest if spot market prices fall below cash or pure variable costs of production, but I think we’ll need Nymex prices to approach $1 to see that,” according to NGI’s Patrick Rau, director of Strategy & Research. “In that case, you’ll see more cutbacks in the gassier regions than the oilier ones, such as the Permian Basin and Eagle Ford, especially with West Texas Intermediate prices firming up here in recent weeks.”
Will E&Ps Cut Output?
Much hinges on how fast gas producers would respond to the downturn in prices by cutting output.
“The market is quickly pricing to send a strong signal to the producing community, “analysts at Mobius Risk Group said. “In fact, it is more or less begging them to turn off the spigot.”
Already, two of the largest gas producers in North America have signaled slowing activity. Haynesville Shale pure play Comstock Resources Inc. said it would suspend quarterly dividend payments and reduce the number of operating drilling rigs from seven to five.
The Haynesville, the third largest gas producing region in the Lower 48 with about 12 Bcf/d output, has higher relative drilling costs than other basins, and E&Ps are more vulnerable to price downturns.
EQT Corp., the nation’s largest natural gas producer, indicated on Wednesday that it wasn’t ready to reduce production further. If anything, production volumes have been overstated, management said in a conference call. If Lower 48 production were to hold flat, storage levels could finish the injection season in line with five-year averages, CFO Jeremy Knop said.
Tudor, Pickering, Holt & Co. (TPH) analyst Matt Portillo said the “gas market will likely try and wrangle down high year-end storage with additional price-driven production cuts.” TPH is forecasting Haynesville rolling 900 MMcf/d from peak to trough in the third quarter. The firm’s channel checks suggest the basin could fall to around 40 rigs by mid-year versus around 46 in early February.
“That said, the negative shift in inventory balances suggests the market needs to lose another 0.5 Bcf/d of supply to bring down October storage” estimates,” Portillo said. That could lead to, reductions in the Eagle Ford Shale, Haynesville, Midcontinent and in Appalachia
Analysts at Siebert Williams Shank & Co. provided a similar assessment. “At current strip prices, we expect more activity reductions (particularly in Haynesville) and greater risk of curtailments/shut-ins during seasonally weak periods,” the analysts said. The firm lowered its 2024 Henry Hub price estimate by more than 10% to $2.50/Mcf.
Gas producers have three levers to pull to reduce output — drilling rates, completions and shut-ins — with the latter the quickest way to bring down gas flows. EBW’s Rubin said “simply slowing new completions could balance the natural gas market,” with well declines eroding close to 3.3 Bcf/d of monthly production.
“We believe extreme price weakness may force producers’ hands, weakening supply in low-demand shoulder seasons,” Rubin said. Gas oversupply suggests “prices may soon revert lower unless producers announce downward capital expenditure revisions or colder weather arrives.”
Oil-heavy production regions like the Permian, with a lot of associated gas, could prove resistant to gas price signals with oil prices still profitable. The U.S. Energy Information Administration (EIA) in its most recent update said production declines during March in gassier Appalachia and in the Haynesville would be offset by growth in the Permian, which would keep Lower 48 gas production steady.
Private E&Ps, which do not have to report publicly, are also a factor for cuts, accounting for about one-third of U.S. gas production, according to Rau.
“Private producers tend to drop rigs and lower activity sooner than public companies,” he said. “Publics typically aren’t as quick to pare back, and many of those have a dividend to fund.” In addition, public E&Ps “don’t necessarily want to release top tier super-spec rigs either if they can avoid it.”
Could Summer Save Again?
Last year, the industry faced a similar surplus of gas in storage after a mild winter. However, a record summer burn halved a storage surplus and averted an end-of-October finish above 4 Tcf of gas in working storage.
Earlier this year, some E&Ps still held the expectation that this summer could prove a repeat. That outcome could support markets, though the expectation could weigh if it tempts E&Ps to not reduce gas production.
East Daley is projecting gas-fired demand could exceed last summer’s average by upwards of 0.3 Bcf/d. “Summer power burn levels comparable to summer ’23 should lift cash prices as they work off the surplus in storage from June to August,” East Daley’s Weixel said.
Gas-fired generation met more than one-half of U.S. power demand last summer. EIA said this record share of the power mix would likely continue through 2024. However, with 36 GW of solar and 30 billion kWh of wind generation expected to be added in 2024, renewables could eat into gas power’s share of the energy stack, EIA said.
“I’m not worried about solar/wind penetration into the gas stack, not with all the coal that is coming offline at the same time,” Weixel told NGI. “Now, summer ’23 was a slightly low wind year, at least in places like Texas. So, there is some of that to be concerned with, but load is growing as well.”
Demand is growing from data centers, electric vehicles and even consumption from the field with electric fracking, production plants and compression, Weixel said. “We’re going to strain the grid this summer, there is almost no question, and gas is going to serve a lot of that load.”
Rau said 2024 is likely to be another year in which demand for gas-fired generation will play a large role in balancing the market. “It will likely take another hot summer to help keep the market more in balance,” he said.
JAN DUC Report. A 244-well drop-in drilled, but uncompleted wells in the Permian Basin during January led to a 17% overall drop in DUCs year-over-year in four of the U.S.’s most prolific shale plays.
The Energy Information Administration just reported that on Jan. 31, 2024, the total number of DUCs in the Permian, Bakken, Eagle Ford and Appalachia (including the Marcellus and Utica Shale plays) fell 457 wells, or 16.6%, from January 2023, to 2,290. The latest total was up four wells from December 2023’s 2,286-well total.
Three of the four plays recorded a large year-over-year drop in DUCs. In addition to the Permian, which dropped to 839 DUCs last month, from 1,083, the Bakken’s total DUCs fell 232 wells, or 42%, from January, 2023, to 553 from 321.
The Permian lost three wells from December 2023.
Also, the total number of DUCs in the Eagle Ford on Jan 31, 2024, was 350, down 128 wells, or 26.8%, from the year-ago total of 478. From December 2023, to last month, the Eagle Ford actually picked up two additional DUCs.
The story was much different in Appalachia, as January 2024’s total of 780 was up 147 wells, or 23.2%, from last year’s 633 total. The latest total was up eight wells from December 2023’s 772 total.
Big Takeover Targets Remain in the Permian. Thanks, Forbes. Monday’s announced $26 billion buyout of privately held Endeavor Energy Resources by Diamondback Energy FANG +1.9% is the latest in a long series of mergers and acquisitions that have rapidly consolidated most Permian Basin oil and gas production into the hands of a handful of very large firms.
One question that always arises in the wake of one of these huge deals is, who is left to be bought? In Monday’s piece I wrote at Forbes on the Diamondback deal, I quote Enverus SVP Andrew Dittmar as pointing to venerable privately held Texas firm Mewbourne Oil as the next likely candidate with a big Permian asset base, along with smaller holdings in the Anadarko Basin. Mewbourne controls more than 360,000 barrels of oil equivalent per day in Permian production, ranking it well among the 10 largest producers in the region. For companies looking for a Permian-centric deal, Mewbourne now stands out as ripe for the picking, assuming its owners want to sell.
Another possible plum is Coterra Energy, with an asset base in the Permian almost as large as Mewbourne’s. Coterra was formed in 2021 through the merger of corporate producers Cimarex and Cabot Oil & Gas +2.7% Co. The company owns a more diversified asset base with major holdings in the Marcellus Shale and Anadarko Basin in addition to its Permian assets. So, a buyout by a larger company like, say, ChevronCVX +0.1% or ConocoPhillipsCOP +0.4%, would be a more complex and gas-heavy deal than, for example, ExxonMobil’sXOM -0.8% acquisition of pure Permian play Pioneer Natural ResourcesPXD -0.6% and could involve a sizable post-close program to divest a wealth of non-core assets.
PROMOTED
OvintivOVV +0.7%OVV +0.7% is the company we formerly knew as Encana, one that has undergone a series of radical transformations over the last 10-12 years. Ovintiv is another corporate operator with a diverse set of assets in both the US and Canada and would present more complexities than a pure Permian deal. Still, it controls over 200,000 boe/day in the Permian, so would be an attractive target for many buyers.
One big independent producer with a huge Permian footprint that seldom gets mentioned in these discussions is EOG. Again, the company’s complexity in terms of assets has made it a less attractive target in the past few years, as acquiring companies have focused on deals that enhance or create big positions in the Permian, and to a lesser extent, the Marcellus, Haynesville, and DJ Basins.
EOG has assets seemingly everywhere. In addition to its massive Permian position (over 660k boe/d), EOG operates in the Bakken Shale, the DJ Basin, the Powder River Basin in Wyoming, the Anadarko Basin, the Barnett Shale, the Eagle Ford Shale, the Utica Basin in the Northeast, and even has international assets.
While these are all attractive play areas when considered in a vacuum, taken together they create complexities in deal valuations and absorption, along with a wealth of follow-on actions like divestitures of non-core assets for which the acquiring company would need to plan and execute.
Oklahoma City-based Devon EnergyDVN -0.5%DVN -0.5% is, like EOG, a longtime growth independent whose name seldom gets mentioned in these discussions. But, with 478,000 boe/d in equity Permian production, it would present a very big prize for a bigger company looking to enhance its Permian position.
Like EOG, Devon operates in several other US shale basins, but would present a good deal less complexity as a takeover target than its Houston-based peer. But Devon was mentioned in recent stories regarding rumors that it is in talks to acquire EnerPlus in a deal that would further diversify its asset holdings into the Marcellus shale, while also enhancing its position in the Bakken.
In addition to the complexity of their asset holdings, one of the main reasons why these two long-existing growth independents seldom are mentioned as takeover targets is that they don’t appear to have any desire to be considered as such.
The Bottom Line
Many deals that have happened in the rapid shale-centric consolidation movement of the past several years have been fairly simple deals involving buyout targets with assets in a single basin. The deals have been even more attractive when the selling company’s assets are highly contiguous to the acquirer’s pre-existing assets in the same region, as was the case for ExxonMobil and Pioneer.
This is the deal model that is easiest to absorb, creates the highest degree of economies of scale, and involves the least need for follow-on activities like divestitures of non-core assets. As we can see, there aren’t a lot of such deals involving sizable companies left to be made as it relates to the Permian Basin.
When you start to see companies like EOG and Devon Energy selling out of some of their operational areas in order to high-grade their asset bases, that’s when you can imply their management teams may be working to make their companies more attractive to potential buyers.
All of which boils down to the expectation that, while some attractive deals remain out there to be made, upstream M&A action for 2024 will likely pale in comparison to 2023.
Here’s a handy list, compiled by energy analytics and data consultancy Enverus, of the 10 top producers in the Permian once the DiamondBack/Endeavor deal closes:
PA Permits February 5, to February 15, 2024
County Township E&P Companies
1. Allegheny Fawn Range
2. Allegheny Fawn Range
3. Allegheny Fawn Range
4. Beaver Independence Range
5. Beaver Independence Range
6. Bradford Tuscarora Chesapeake
7. Bradford Tuscarora Chesapeake
8. Bradford Tuscarora Chesapeake
9. Bradford Tuscarora Chesapeake
10. Elk St. Mary’s Seneca
11. Elk St. Mary’s Seneca
12. Elk St. Mary’s Seneca
13. Elk St. Mary’s Seneca
14. Elk St. Mary’s Seneca
OH Permits February 4, to February 15, 2024
County Township E&P Companies
1. Guernsey Center EAP Ohio
2. Guernsey Center EAP Ohio
3. Guernsey Center EAP Ohio
4. Guernsey Center EAP Ohio
WV Permits February 5, February 9, 2024
1. Doddridge Antero
2. Doddridge Antero
3. Doddridge Antero
4. Harrison Diversified Prod.
5. Harrison Diversified Prod
6. Tyler EQT
7. Tyler EQT
8. Tyler EQT
9. Tyler EQT
