Category: Oil and Gas

CALGARY, Alberta (Oct. 24, 2023) — Enverus Intelligence Research (EIR), a subsidiary of Enverus, the most trusted energy-dedicated SaaS platform, is releasing its summary of 3Q23 upstream merger and acquisition (M&A) activity.

In Q3, U.S. upstream M&A cruised along with $14 billion transacted in 25 deals. A liftoff in corporate consolidation picked up the slack of declining opportunities to buy private assets with two-thirds of deal value last quarter coming from combinations between public companies. That accelerated to historic levels in October with ExxonMobil’s $65 billion acquisition of Pioneer Natural Resources in the third-largest upstream deal ever by enterprise value, and Chevron purchasing Hess for $60 billion.

“As anticipated, the pace of consolidation slowed for private E&Ps as the cream of the crop in terms of scale and quality has largely, but not entirely, been bought out,” said Andrew Dittmar, senior vice president at EIR. “The next logical step in consolidation is more tie-ups between public producers. That could have slowly built toward a historic deal like ExxonMobil’s purchase of Pioneer but instead that happened right out of the gate and could well be the largest deal of the shale era.”

Prior to its expansion in the Permian with the purchase of Pioneer, ExxonMobil placed a smaller bet on carbon capture utilization and storage (CCUS) during 3Q23 with its acquisition of Denbury for $4.9 billion. While Denbury did bring to the table legacy oil production, the core driver of the acquisition is likely the infrastructure the company has in place, specifically CO2 pipelines that support ExxonMobil’s plan to build a carbon sequestration hub along the Texas-Louisiana Gulf Coast.

“ExxonMobil is committing to its traditional energy business, which has become extremely profitable for the major, while working to decarbonize operations to meet its emissions targets,” Dittmar said. “This is coming from a combination of reducing upstream emissions and building its carbon sequestration business.”

“By acquiring Pioneer, ExxonMobil is not only expanding its Permian portfolio, but also speeding up the Permian’s transition to a low-carbon future. ExxonMobil has set an ambitious goal of achieving net-zero emissions by 2030 for its existing Permian assets and by 2035 for the newly acquired Pioneer asset, which is 15 years ahead of Pioneer’s original plan,” said John Gutentag, product owner at Enverus.

While emission intensity matters as companies set their net zero goals, it doesn’t appear to be playing a major role in how they screen targets for acquisitions.

“Despite seeing more airtime of the environmental, social and governance justification of deals, we have seen no clear evidence of the U.S. upstream market valuing assets based on their emission intensity,” added Gutentag. “However, the new emissions reporting rules proposed by the Environmental Protection Agency (EPA), the methane fee introduced in the Inflation Reduction Act, and the EPA’s regulatory agenda are influencing the asset selection process, as some assets will experience disproportionately high fees and retrofitting costs while others will be minimally affected.”

Emissions intensity didn’t deter Chevron in October’s other historic deal, the $60 billion purchase of Hess. Hess’ Bakken operations screen near the highest emissions intensity among public Bakken operators at just under 20 kg CO2e/boe. However, Chevron, like Exxon, will look to rapidly improve those metrics. From the standpoint of overall emission from oil and gas operations, acquisitions by majors are very bullish for the industry improving its environmental footprint.

The Bakken overall appears to play a minimal supporting role in a deal where Enverus anticipates 80% of the value is weighted toward Hess’ interest in Guyana assets though. Chevron’s focus on international assets in the acquisition of Hess leaves the door open for more shale deals down the road while keeping a balanced portfolio. However, with $60 billion spent on Hess those shale deals are likely to be smaller like its $7.6 billion purchase of PDC Energy in Colorado’s DJ Basin.

“There are certain parallels between the moves by ExxonMobil and Hess as the majors are looking to refill their pipelines to maintain production against a declining asset base. That indicates they view their legacy businesses staying profitable into the 2030s,” said Dittmar. “After 10 years of slashing spending on exploration and focusing on getting capital back to shareholders it’s time to look at growth again for oil and gas production.”

The moves by ExxonMobil and Chevron are likely to ignite further consolidation among smaller oil and gas companies as they scramble to remain competitive and secure remaining drilling opportunities. Already, reports have emerged of merger talks between large-cap independents including a potential combination between oil producers Devon Energy and Marathon Oil and gas-focused producers Chesapeake Energy and Southwestern Energy.

The large independents are also likely to go on shopping spree targeting smaller and midsize producers. The stocks of these smaller companies almost all trade at meaningful discounts to the larger E&Ps, raising the opportunity for deals that create value for both buyers and sellers. That was the case in 3Q23’s other corporate deal, the purchase of Earthstone Energy by Permian Resources. Because Earthstone’s stock was being undervalued by the market relative to the quality of its asset base, Permian Resources was able to pay a premium on the share price while keeping the deal very attractive to its own financial an inventory metrics.

“Within U.S. shale, the most attractive acquisition targets are going to be companies with exposure to the Permian Basin,” concluded Dittmar. “The Permian is uniquely positioned among U.S. shale plays as having both the most remaining high-quality inventory and the greatest opportunity for resource expansion. That expansion will keep shale production humming into the 2030s, albeit at a higher cost of supply. The outlook for shale is bright from here and M&A will be robust as companies want to secure their piece of that future.”

Members of the media should contact Jon Haubert to request a copy of the full report or to schedule an interview with one of Enverus’ expert analysts.

About Enverus Intelligence Research
Enverus Intelligence ® | Research, Inc. (EIR) is a subsidiary of Enverus that publishes energy-sector research focused on the oil, natural gas, power and renewable industries. EIR publishes reports including asset and company valuations, resource assessments, technical evaluations and macro-economic forecasts; and helps make intelligent connections for energy industry participants, service companies and capital providers worldwide. EIR is registered with the U.S. Securities and Exchange Commission as a foreign investment adviser. Enverus is the most trusted, energy-dedicated SaaS platform, offering real-time access to analytics, insights and benchmark cost and revenue data sourced from our partnerships to 98% of U.S. energy producers, and more than 35,000 suppliers. Learn more at Enverus.com.

Media Contact: Jon Haubert | 303.396.5996

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My mom could always leap into the coldest water. Every summer when we visited my grandma in upstate New York, my mom dove straight into the freezing lake, even when the temperature outdoors hit the 50s. The dogs, who usually trailed her everywhere, would whine in protest before paddling after her, and the iciness left her breathless when she surfaced. “Just jump, Lil,” she’d yell to me, laughing, before swimming off to vanish into the distance.

But I never could. I didn’t think much about that difference between us, until I flew north to be with her on the day she’d chosen to die.

When my mom found out in May last year that she had pancreatic cancer, the surgeon and the oncologist explained to our family that cutting out her tumor might extend her prognosis by about a year; chemotherapy could tack on another six months. A few days later, my mom asked if we could spend time together in Seattle over the summer, if we could get lemonade at the coffee shop while I was there, if I wanted to play Scrabble before I left. “Yeah, of course,” I said. “But—” She interrupted me: “I’m not getting surgery.”

After a decade of Parkinson’s disease, my mom already experienced frequent periods of uncontrolled writhing and many hours spent nearly paralyzed in bed. That illness wounded her the way losing vision might pain a photographer: Throughout her life, she had reveled in physicality, working as a park caretaker, ship builder, and costume designer. Now, plagued by a neurological disorder that would only worsen, she didn’t want to also endure postoperative wounds, vomiting from chemo, and the gloved hands of strangers hefting her onto a bedpan after surgery. Nor did she want to wait for the pain cancer could inflict. Instead, my mom said, she planned to request a prescription under Washington’s Death With Dignity Act, which allows doctors, physician assistants, and nurse practitioners to provide lethal drugs for self-administration to competent adult residents with six months or less to live.

As a doctor myself, I’ve confronted plenty of death, yet I still found myself at a loss over how to react to my mom’s choice. I know that the American tropes of illness—“battling to the end,” “hoping for a miracle,” being “a fighter”—often do harm. In clinical training, none of us wanted to unleash the fury of modern medicine upon a 98-year-old with cancer who’d just lost his pulse, but we all inflicted some version of it: ramming his purpled breastbone against his stilled heart, sending electricity jagging through his chest, and breaching his throat, blood vessels, and penis with tubes, only to watch him die days later. I didn’t want that for my mom; I had no desire for her to cling futilely to life.

And yet, even though it shamed me, I couldn’t deny feeling unnerved by my mom’s choice. I understood why she’d made it, but I still ruminated over alternate scenarios in which she gave chemo a shot or tried out home hospice. Though her certainty was comforting, I was also devastated about losing her, and uneasy about how soon after a new diagnosis she might die.

My mom had made her end-of-life wishes known by the time I was in fifth grade. Our rental home still held the owners’ books, among them Final Exit, a 1991 guide for dying people to end their lives. The author dispensed step-by-step advice on how to carry out your own death, at a time when nothing like the Death With Dignity Act existed in any state. When I found the book, my mom snatched it away. But months later, after her best friend died of brain cancer, she asked if I remembered it.

“If I ever get really sick, Lil,” she said, “I don’t plan to suffer for a long time just to die in the end anyhow. I would take my life before it gets to that point, like in that book. Just so you know.”

After her Parkinson’s diagnosis, my mom moved across the country to Washington, mostly to be near my sister, but also because in 2008, it became only the second state to approve lethal prescriptions for the terminally ill. Since then, despite much contention, the District of Columbia and eight more states have followed—including California, where I live and practice medicine. No dying patient of mine had ever requested the drugs, so I didn’t think much about the laws. Then my mom got cancer, and suddenly, the controversies ceased to be abstract.

Proponents of aid-in-dying laws tend to say that helping very sick patients die when they want to is compassionate and justified, because people of sound mind should be free to decide when their illnesses have become unbearable. Access to lethal medications (which many recipients never end up using) lets them concentrate on their remaining life. I sympathize: I’ve seen patients who, despite palliative care, suffered irremediable existential or physical pain that they could escape only with sedating doses of narcotics.

But I grasped the other side of the argument as well: that self-determination has limits. Aid-in-dying opponents have said that doctors who hasten death violate the Hippocratic Oath. Although I disagree with these moral objections, I do share some of the antagonists’ policy concerns. Many worry that state laws will expand to encompass children and the mentally ill, as they do in countries such as Belgium and the Netherlands. They argue that a nation that still devalues disabled people needs to invest in care, rather than permit death and open up the risk of coercion. So far, Americans who have used these laws have been overwhelmingly white and college-educated. But I could imagine patients of mine requesting death for suffering that’s been amplified by their poverty or uninsurance.

These policies are so polarizing that people can’t even agree on language. Detractors refer to “assisted suicide,” or even murder, while supporters prefer medical “aid-in-dying,” which I’ll use, because it’s less charged. But I don’t much like either term, and neither did my mom. She was already dying, so she didn’t think of her death as suicide. Nor would she accept a passive term such as aid-in-dying, when she was the one taking action. Lacking any suitable word, she settled on a phrase that felt stark but honest. “When I kill myself,” she’d say. When she killed herself, we should give her spice rack to a friend. When she killed herself, we shouldn’t hold a funeral, because that would be depressing. Her tone was always matter-of-fact. My stomach always somersaulted.

That summer, I read constantly about aid-in-dying—accounts of its use in Switzerland, essays in American medical journals, articles written by people who’d lost a loved one that way. I was the exception in our family. My mom was concerned with bigger issues, like whether the ice-cream shop would restock the lemon flavor before she died. My sister thought I was overintellectualizing things—and she was right. Sometimes we do the only thing we know how to, to keep from falling apart.

So I kept looking for the solace of stories that felt as complicated as my own thoughts. They were remarkably rare. To me, loving my mom meant acknowledging my own hesitation yet still respecting her measure of the unendurable. Juggling these emotions felt nuanced, but most of what I read didn’t. So many narratives cast aid-in-dying as either an abomination or the epitome of virtue, in which a dying person could be rewarded for courageous serenity with a perfect death.

Another daughter whose mother pursued aid-in-dying spoke in a TED Talk of the “design challenge” to “rebrand” death as “honest, noble, and brave.” But however tantalizing the prospect, the promise that we can scrub death of ugliness felt dangerously dishonest. Death can be wrenching and awful no matter where and how it happens: on a ventilator in an intensive-care unit, on morphine in hospice, or with a lethal prescription at home, surrounded by family. Being able to control death doesn’t mean we can perfect it.

The myth of the “good death”—graceful and unsullied, beatific even—has infiltrated the human subconscious since at least the 15th century, when the Ars Moriendi, Christian treatises on the art of dying, proliferated in Europe. A translation of one version counsels the sick on how to die “gladly.” The moral in these texts bludgeons you: How you die is a referendum on how you lived, with only a picturesque exit guaranteeing repose for the soul.

The notion has seeped through generations. “I hope if I’m ever in that situation, I’d have the bravery to do that,” one friend said about my mom’s choice. “It’s good she’ll die with her dignity intact,” said another. My mom’s physicians, kind and smart people, seemed so eager to validate her decision that the aid-in-dying criteria distilled to a checklist rather than unfurling into conversation. Even the name of the law my mom intended to use, Death With Dignity, implies that planned death succeeds where other ways of dying don’t. More than half a millennium after the Ars Moriendi, we still seem to believe that you can fail at death itself.

One doctor told us of a landscape architect who drank the fatal cocktail while exulting in her garden in full bloom. It sounded perfect—except that in all my years as a doctor, I’ve never seen a perfect death. Every time, there’s some flaw: physical discomfort, conversations left unfinished, terror, family conflict, a loved one who didn’t get there in time. Still, my sister and I tried to stage-manage a beautiful death. We booked a cabin in Olympic National Park for my mom’s exit. We would bake her famous olive bread and cook bouillabaisse. We’d wheel her to the beach, then to the towering cedar forest, then massage her feet with almond oil while we talked in front of a woodstove. The fireside conversation would be our parting exchange of gifts, full of meaning, remembrance, and closure.

As our family waited for that day to come, we kept thinking we should be tearing through a bucket list. Instead, we did what we always had—cooked, played games, read. We just did it with an ever-present sense of countdown, in an apartment where nearly everything would outlive my mom: the succulent on the windowsill, the lasagna in the freezer she made us promise to eat when she was gone.

My mom did have the lemon ice cream again, but our family never made it to the cabin in the forest. A month before the planned trip—10 weeks after my mom’s diagnosis—the pharmacy compounded the drugs: a mixture of morphine and three others. The bottle was amber, filled with dissolvable powder and labeled with the words No Refills. (“Now that would be a dark Saturday Night Live skit,” my mom told me.) The next morning, a Thursday, she called, dizzy and miserable. She wanted to die ahead of schedule, on Saturday. I got on a plane.

My mom, my sister’s family, and I spent Friday grilling chicken and drinking good wine. After my older niece painted my mom’s nails lavender with polka dots, the kids and my brother-in-law said their goodbyes and left. The next morning, my sister and I laid out the backyard like a set: a couch swathed in blankets. Tables with plants and photos and huge candlesticks. A stereo to play the music of our childhood and her motherhood.

But our revised choreography couldn’t erase how horrible my mom felt that morning, dispirited by her disease and deeply exhausted. We had to cajole her not to die in bed. Eventually, she came outside, where we drank peppermint tea and talked about nothing memorable. When the moment came to gulp the bottle’s contents, mixed into lemonade, she didn’t hesitate.

“You would make the same choice if you were me, right?” she said, setting down the empty bottle. I knew she wasn’t second-guessing. She was ending her time as our mother not out of lack of devotion, but because all other options felt untenable, and she needed confirmation that we knew this.

“Yes,” my sister said, “I would.”

“Me too,” I said—but in truth, I didn’t know. Maybe I would have dwindled over months of chemo as I learned to reshape my life in the face of imminent death. Maybe I would have died in hospice, surrendering myself to the fog and mercy of morphine. Maybe I would have stowed the drugs in a cupboard, cradling them occasionally and then, unable to reconcile the simplicity and complexity of that ending, replacing them. Each of these paths would have demanded its own form of courage—just not my mom’s type.

“I’ll just go to sleep now, right?” she asked.

“Yeah, Mom, you’ll just go to sleep,” I said. “I love you.”

My sister and I kissed her forehead, her cheeks, her collarbone. We avoided the poisonous sheen on her lips, where our tears had wet the residue of white powder.

The aspens rustled, confetti of silver. My mom didn’t cry, and the slightest trace of a smile alighted on her face.

“Bye,” she said. “You’ve been awesome.”

And then she dove off the dock. Her lips blued, and when she tried to speak more, the words never surfaced.

It took her five and a half hours to disappear completely, while my sister and I tamped down growing worries that the drugs hadn’t worked. My mom felt no pain—she couldn’t have, after all that morphine—but her passing wasn’t a fairy tale. Her suffering wasn’t embossed in meaning; she didn’t tile over her bitterness with saintly forbearance. My mom died on the day she was ready and by the means she chose. All of that matters, immensely so. She also died precipitously, far from the forest she’d dreamed of, while my sister and I were left with little closure and a prolonged, confusing death.

Usually, I write when I’m most upset, but my mom’s death catapulted me into a frightening depth of wordlessness. Weeks passed before I realized that my problem was not that I couldn’t find words at all. It was that I couldn’t tell the tale I felt I was supposed to. In that myth, death has a metric of success, and that metric is beauty. The trouble is that you can’t grieve over a version of events that never happened. You can only grieve over the story you lived, with all of its ambiguities.

My mom’s death was beautiful. It was also terrible, and fraught. That is to say, it was human.

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Argentina will hold its first round of presidential elections on October 22, posing potential headwinds to the local hydrocarbon industry.

The country has struggled to balance its need to attract foreign investment into its energy sector with its domestic economic turmoil for some time. However, with activity picking up in Namibia and South Africa’s west coast, companies are turning their attention to the other side of the Atlantic.

Politics

One of the key areas of concern is political. La Libertad Avanza’s Javier Milei took a surprise lead in the primary election in August, with 30% of the vote. Following the vote on Sunday, there could be a run-off one month later.

Unidos por la Patria, the ruling party, has been unable to tame inflation, which is projected to pass 120% by the end of the year. The party came third in the August vote, with 27%.

It is the economy minister, Sergio Massa, who aims to win over voters as he runs for the position of president.

Turmoil

The country’s economy is “increasingly fragile with episodes of heightened market volatility”, the International Monetary Fund (IMF) said in August.

Argentina has a tumultuous relationship with the IMF – in addition to other sources of international capital. Massa blamed inflation on the IMF, despite the agency providing a $7.5 billion fillip in August.

IMF managing director Kristalina Georgieva, said political support is “critical in the near and medium term” for the reform plans. Tackling “the country’s deep challenges will require continued efforts by future administrations”.

Massa responded to the August vote by devaluing the peso by around 18% and increasing interest rates, in an attempt to reassure investors.

Milei has talked of dollarising the economy, of spending cuts, of shutting down the central bank and also of selling off state-owned YPF (NYSE: YPF). He has also argued against a link between human action and climate change.

Argentina’s turmoil has had a notable impact on investors. Verisk Maplecroft senior Americas analyst Mariano Machado said the government’s “price, capital, and exchange-rate controls, and the levy of export taxes” have acted to “reduce the profitability and competitiveness of energy companies”.

Somewhat offsetting federal instability, though, is the resilience of the local private sector and provincial leadership, Machado said.

Seeking advantage

“As political and policy volatility becomes a feature of the operating landscape, even private companies with a high risk appetite could be facing binding constraints when seeking to invest in Vaca Muerta and offshore plays,” the analyst said.

High wages and inflation have pushed up costs, making local operations less cost effective. “In the long run, these persistent patterns impair relationships with energy majors and creditors and affect access to financing and technology for the sector.”

AIM-listed Molecular Energies’ (LON: MEN) decision to sell off its Argentine business to its chairman, Peter Levine, seems to play to this trend. The deal, agreed in September, saw Levine take over debt payments from Molecular’s local unit in addition to a commitment on free cash flow.

Company officials said the market was “not appreciative” of the value of the Argentina assets. The company has shifted its hydrocarbon hopes to Paraguay and is also working on energy transition investments.

“Energy players with robust political acumen and established relationships have a vital edge over newcomers. Navigating the intricate regulatory web and building ties with government officials unlocks strategic advantages by enabling decision-makers to learn from previous state interventions in the market,” said Machado.

In addition to the financial and policy challenges, transportation capacity is a “major bottleneck”. This is, of course, more of a challenge for onshore operations than offshore.

Offshore options

Wintershall Dea took the final investment decision (FID) on the Fénix offshore gas project in Argentina in 2022. The company intends to start this up in 2025, with expected peak production of around 65,000 barrels of oil equivalent per day.

The plan will involve three horizontal wells, producing to a new unmanned platform. The gas will be transported 35 km to TotalEnergies (PARIS: TTE) operated Véga Pleyade platform. The French company put the project cost at $706 million. Pipelay work began in July.

Noble (NYSE: NE) has agreed to provide its Noble Regina Allen for the Fénix plan, starting in the first half of 2024.

Frontier tests

Beyond Fénix though, there is scope for frontier exploration. Equinor (OSLO: EQNR), and Shell (LON: SHEL), are due to spud an exploration well in the CAN 100 licence in December. The Argerich-1 exploration will test a new frontier, involving Valaris’ DS-17 rig.

S&P Global said the high hopes around Argerich were “founded largely on the recent deepwater exploration success in Namibia’s Orange” Basin. The analysts said the well was targeting an estimated resource of 1.1 billion boe.

It is seeking Cretaceous basin floor fan sandstones, “similar to those found in the Namibian discoveries, that remains untested in the Latin American Atlantic margin”.

TotalEnergies drilled a well in 2016 in Uruguay’s Pelotas Basin. The Raya-1 well was disappointing, though, and was plugged and abandoned. “Argerich-1 results will likely shape exploration in the region for the foreseeable future,” S&P said.

CGG’s Will Jeffery noted some positive signs of seeps offshore Argentina. Speaking to Energy Voice, he said finding seeps in the water removed one of the major exploration risks.

“There is source rock along that coastline,” he said. “The appearance of the slicks and the geospatial size compares with producing basins, such as Angola and the Gulf of Mexico, the seeps have the same characteristics.”

The seeps suggest high evaporation rates, which points to high quality light oil, Jeffery said.

Risks remain, though. While seeps show the presence of source rock they do not determine how thick they may be or the structure’s formation.

While the Raya well was disappointing for Total at the time, CGG’s Jeffery noted that the company had acquired blocks around the region. The company drilled Raya in 3,400 metres of water, which was at the time a world record.

Uruguay

Total drilled the Raya well offshore Uruguay. The disappointing result triggered an exit from the country’s offshore.

Uruguay held a licensing round to flag up its opportunities in early 2020. Given the timing, turn out for the round was poor – although one UK-listed company Challenger Energy (LON: CEG) did take part.

“We were the only bidder,” Challenger CEO Eytan Uliel told Energy Voice. The company won Block 1 in the offshore round but everything was put on pause owing to the pandemic. Challenger was formally awarded its licence in May 2022.

“In the meantime, two discoveries were made offshore Namibia, in early 2022, by Shell and Total,” Uliel said. “Everyone then took a second look at Uruguay, as it looks like the mirror of the Orange Basin.”

Shell and APA Corp. (NYSE: APA) took part in the next round, paying out hundreds of millions of dollars to acquire blocks. By December 2022, all but one block was licensed – with Challenger ultimately acquiring it. “Within 15 months, every offshore Uruguay licence had been taken out,” the CEO said.

Challenger accelerated its work under the first phase to complete its requirements, mostly around reprocessing, and sees “lots of potential”.

Partner plans

“The Venus structure [off Namibia] is most analogous to the structures we, Shell and APA are seeing on the margin boundary off Blocks 1 and 4,” Uliel said. “We see the same Aptian source rock.”

Challenger does not have the funds to shoot 3D seismic on its own. As such, it intends to farm-down its interest to a partner, aiming to close a deal by the end of 2023.

There has been talk of a major seismic company coming in to cover the entire offshore area in one campaign. This may take place in 2024, Uliel said.

Equinor’s Argerich well is sufficiently far from Uruguay that success – or failure – would have little impact, the CEO said. “In a technical sense, there are licences in Argentina that could be of interest, but in an operational sense it’s a completely different kettle of fish.”

The Challenger executive noted the legal travails around activities offshore Argentina as one instance of the problems in the country. “Uruguay has a clear energy policy, the government has been totally supportive of us and the industry.”

Environmental groups, including Greenpeace, have taken action against offshore plans in Argentina. Greenpeace lost its court battle earlier this year to prevent exploration but has continued to object to the plans.

Falklands

One seemingly intractable problem for Argentina has been the Falkland Islands. A number of small companies made discoveries offshore the Falklands around 10 years ago, but progress has been painfully slow.

Argentina’s protests have been a major factor in slowing development. The United Nations heard a debate on the topic earlier this year, with a number of South American countries voicing support for Argentina’s sovereignty.

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Representatives from the Falklands reminded those participating that a referendum had given 99% support to remaining in the UK.

However, such is the enmity no companies involved in the Falklands were willing to talk on the record.

JHI Associates struck a deal to acquire PL001 in the North Falklands Basin in September. The licence is west of the Sea Lion find.

Navitas Petroleum and Rockhopper Exploration (LON: RKH) hold the Sea Lion find, with a potential aim of reaching an FID in 2024. Meanwhile, Borders & Southern has the Darwin condensate discovery.

SP Angel analyst David Mirzai noted the “problem has always been politics”, in addition to the commodity price swings.

This time, it may be different. In 2023, companies have returned to exploration projects. “That is what we hope to see with the Falklands, with more free cash flow redeployed into higher risk exploration and appraisal.”

Argentina may or may not be on course for a new president, but success in the offshore will require bold steps from industry. Whether they are willing to look beyond the political challenges will be a topic of keen consideration as the votes come rolling in on Sunday.

Advisors

National Bank Financial Inc. and RBC Capital Markets are acting as financial advisors to Tamarack with respect to the Transaction. Stikeman Elliott LLP is acting as legal counsel to Tamarack with respect to the Transaction.

Executive Leadership

Tamarack is pleased to announce the appointment of Mr. Kevin Johnston as Vice President, Finance. Mr. Johnston will join the Tamarack finance team, which is led by Steve Buytels, Chief Financial Officer, as the Company continues to focus on strategic execution of its long-term development plan. Mr. Johnston brings 20 years of industry experience in accounting and finance. Most recently, he held the role of Vice President, Finance & Controller at ATCO’s Energy Infrastructure business unit and was previously the Vice President, Finance & Controller at Seven Generations Energy. Mr. Johnston is a Chartered Professional Accountant and holds a master’s degree in professional accounting. The Company is excited to add the skills and perspectives that Mr. Johnston brings to the strong existing leadership team.

About Tamarack Valley Energy Ltd.

Tamarack is an oil and gas exploration and production company committed to creating long-term value for its shareholders through sustainable free funds flow generation, financial stability and the return of capital. The Company has an extensive inventory of low-risk, oil development drilling locations focused primarily on Charlie Lake, Clearwater plays in Alberta while also pursuing EOR upside in these core areas. Operating as a responsible corporate citizen is a key focus to ensure we deliver on our environmental, social and governance (ESG) commitments and goals. For more information, please visit the Company’s website at www.tamarackvalley.ca.

Abbreviations

Reader Advisories

Notes to Press Release

(1)   Production of approximately 70,000 boe/d comprised of 17,070 bbl/d light and medium oil, 36,700 bbl/d heavy oil, 3,960 bbl/d NGL and 73,640 mcf/d natural gas.

(2)   See “Specified Financial Measures”.

(3)   As per the AER May OneStop data.

(4)   Production impacts of approximately 7,000 boe/d comprised of 1,749 bbl/d light and medium oil, 1,113 bbl/d NGL and 24,833 mcf/d natural gas.

(5)   Production impacts of approximately 4,500 boe/d comprised of 1,098 bbl/d light and medium oil, 922 bbl/d NGL and 14,880 mcf/d natural gas.

(6)   Production impacts of approximately 1,200 boe/d comprised of 293 bbl/d light and medium oil, 246 bbl/d NGL and 3,968 mcf/d natural gas.

(7)   Production impacts of approximately 6,000 boe/d comprised of 1,464 bbl/d light and medium oil, 1,229 bbl/d NGL and 19,841 mcf/d natural gas.

Forward Looking Information

This press release contains certain forward-looking information (collectively referred to herein as “forward-looking statements”) within the meaning of applicable Canadian securities laws. Forward-looking statements are often, but not always, identified by the use of words such as “guidance”, “outlook”, “anticipate”, “target”, “plan”, “continue”, “intend”, “consider”, “estimate”, “expect”, “may”, “will”, “should”, “could” or similar words suggesting future outcomes. More particularly, this press release contains statements concerning: Tamarack’s business strategy, objectives, strength and focus; the completion of the Transaction, including the terms and timing thereof; the anticipated benefits of the Transaction; future streamlining of holdings, high grading of development inventory and enhanced operational efficiencies; future intentions with respect to debt repayment and reduction and return of capital; oil and natural gas production levels, free funds flow; anticipated operational results for the remainder of 2023 including, but not limited to, estimated or anticipated production levels, capital expenditures, drilling plans and infrastructure initiatives; enhanced recovery; exploration activities; continued integration of the recently acquired assets; the ability of the Company to achieve drilling success consistent with management’s expectations; Tamarack’s commitment to ESG principles and sustainability; and the source of funding for the Company’s activities including development costs.

The forward-looking statements contained in this document are based on certain key expectations and assumptions made by Tamarack, including those relating to: the business plan of Tamarack; the satisfaction of all conditions to the completion of the Transaction; the timing of and success of future drilling, development and completion activities; the geological characteristics of Tamarack’s properties; the characteristics of recently acquired assets; the continued integration of recently acquired assets into Tamarack’s operations; prevailing commodity prices, price volatility, price differentials and the actual prices received for the Company’s products (including expectations concerning narrowing WCS differentials); the availability and performance of drilling rigs, facilities, pipelines and other oilfield services; the timing of past operations and activities in the planned areas of focus; the drilling, completion and tie-in of wells being completed as planned; the performance of new and existing wells; the application of existing drilling and fracturing techniques; prevailing weather and break-up conditions; royalty regimes and exchange rates; impact of inflation on costs; the application of regulatory and licensing requirements; the continued availability of capital and skilled personnel; the ability to maintain or grow the banking facilities; the accuracy of Tamarack’s geological interpretation of its drilling and land opportunities, including the ability of seismic activity to enhance such interpretation; and Tamarack’s ability to execute its plans and strategies.

Although management considers these assumptions to be reasonable based on information currently available, undue reliance should not be placed on the forward-looking statements because Tamarack can give no assurances that they may prove to be correct. By their very nature, forward-looking statements are subject to certain risks and uncertainties (both general and specific) that could cause actual events or outcomes to differ materially from those anticipated or implied by such forward-looking statements. These risks and uncertainties include, but are not limited to: risks with respect to unplanned third party pipeline outages and risks relating to inclement and severe weather events and natural disasters, such as fire, drought and flooding, including in respect of safety, asset integrity and shutting-in production, maintaining 2023 guidance and resumption of operations; risks with respect to unplanned third-party pipeline outages; unforeseen difficulties in integrating of recently acquired assets into Tamarack’s operations, including the Deltastream assets; incorrect assessments of the value of benefits to be obtained from acquisitions and exploration and development programs; risks associated with the oil and gas industry in general (e.g. operational risks in development, exploration and production; and delays or changes in plans with respect to exploration or development projects or capital expenditures); commodity prices; the uncertainty of estimates and projections relating to production, cash generation, costs and expenses, including increased operating and capital costs due to inflationary pressures; volatility in the stock market and financial system; health, safety, litigation and environmental risks; access to capital; pandemics; Russia’s military actions in Ukraine; and the Israel-Palestinian conflict. Due to the nature of the oil and natural gas industry, drilling plans and operational activities may be delayed or modified to respond to market conditions, results of past operations, regulatory approvals or availability of services causing results to be delayed. Please refer to the Company’s AIF for the period ended December 31, 2022 and the MD&A for the period ended June 30, 2023 for additional risk factors relating to Tamarack, which can be accessed either on Tamarack’s website at www.tamarackvalley.ca or under the Company’s profile on www.sedarplus.ca.The forward-looking statements contained in this press release are made as of the date hereof and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, except as required by applicable law. The forward-looking statements contained herein are expressly qualified by this cautionary statement.

This press release contains future-oriented financial information and financial outlook information (collectively, “FOFI”) about generating sustainable long-term growth in free funds flow, prospective results of operations and production, weightings, operating costs, 2023 capital budget and expenditures, balance sheet strength, realized pricing, corporate operating field netback, free funds flow, net debt, material debt reduction (including achieving the first net debt threshold of its enhanced return of capital framework), total returns and components thereof, including pro forma the completion of the Transaction, all of which are subject to the same assumptions, risk factors, limitations and qualifications as set forth in the above paragraphs. FOFI contained in this document was approved by management as of the date of this document and was provided for the purpose of providing further information about Tamarack’s future business operations. Tamarack and its management believe that FOFI has been prepared on a reasonable basis, reflecting management’s best estimates and judgments, and represent, to the best of management’s knowledge and opinion, the Company’s expected course of action. However, because this information is highly subjective, it should not be relied on as necessarily indicative of future results. Tamarack disclaims any intention or obligation to update or revise any FOFI contained in this document, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law. Readers are cautioned that the FOFI contained in this document should not be used for purposes other than for which it is disclosed herein. Changes in forecast commodity prices, differences in the timing of capital expenditures, and variances in average production estimates can have a significant impact on the key performance measures included in Tamarack’s guidance. The Company’s actual results may differ materially from these estimates.

Specified Financial Measures

This press release includes various specified financial measures, including non-IFRS financial measures, non-IFRS financial ratios, capital management measures and supplemental financial measures as further described herein. These measures do not have a standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and, therefore, may not be comparable with the calculation of similar measures by other companies.

“Adjusted Funds Flow (Capital Management Measures)” is calculated by taking cash-flow from operating activities, on a periodic basis and adding back changes in non-cash working capital.

“Excess Funds Flow (Capital Management Measures)” is calculated by taking free funds flow on a periodic basis subtracting cash taxes and expected ARO spending.

“Free Funds Flow and Capital Expenditures (Capital Management Measures)” is calculated by taking adjusted funds flow and subtracting capital expenditures, excluding acquisitions and dispositions. Capital expenditures is calculated as property, plant and equipment additions (net of government assistance) plus exploration and evaluation additions. Management believes that free funds flow provides a useful measure to determine Tamarack’s ability to improve returns and to manage the long-term value of the business.

“Net Debt (Capital Management Measures)” is calculated as credit facilities plus senior unsecured notes, plus deferred acquisition payment notes, plus working capital surplus or deficiency, plus other liability, including the fair value of cross-currency swaps, plus government loans, plus facilities acquisition payments, less notes receivable and excluding the current portion of fair value of financial instruments, decommissioning obligations, lease liabilities and the cash award incentive plan liability.

Net Production Expenses, Revenue, net of blending expense, Operating Netback and Operating Field Netback (Non-IFRS Financial Measures, and Non-IFRS Financial Ratios if calculated on a per boe basis) – Management uses certain industry benchmarks, such as net production expenses, revenue, net of blending expense, operating netback and operating field netback, to analyze financial and operating performance. Net production expenses are determined by deducting processing income primarily generated by processing third party volumes at processing facilities where the Company has an ownership interest.  Under IFRS this source of funds is required to be reported as income.  Where the Company has excess capacity at one of its facilities, it will process third party volumes as a means to reduce the cost of operating/owning the facility, and as such third-party processing revenue is netted against production expenses in the MD&A. Blending expense includes the cost of blending diluent purchased to reduce the viscosity of our heavy oil transported through pipelines to meet pipeline specifications. The blending expense represents the difference between the cost of purchasing and transporting the diluent and the realized price of the blended product sold. In this MD&A, blending expense is recognized as a reduction to heavy oil revenues, whereas blending expense is reported as an expense in the financial statements. Operating netback equals total petroleum and natural gas sales (net of blending), including realized gains and losses on commodity and foreign exchange derivative contracts, less royalties, net production expenses and transportation expense. Operating field netback equals total petroleum and natural gas sales, less royalties, net production expenses and transportation expense. These metrics can also be calculated on a per boe basis, which results in them being considered a non-IFRS financial ratio. Management considers operating netback and operating field netback important measures to evaluate Tamarack’s operational performance, as it demonstrates field level profitability relative to current commodity prices.

SOURCE Tamarack Valley Energy Ltd.

 

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Oil Price

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Mergers in the U.S. shale patch have continued through the course of 2023 as companies jockey for assets that will fill in gaps in their acreage base. Two key basins have been the focus of much of this activity. I refer to the Permian Basin and the Eagle Ford, each of which has attributes that draw the interested eyes of companies with strong balance sheets and cash to spend.

This article continues a series I started back in August, with this OilPrice article where the recent activity by Devon Energy (NYSE: DVN) in the Eagle Ford snapping up Validus Energy was discussed, among others. The theme of that article was “Big fish, eating little fish.” What we didn’t get into then in any detail, and will do in this article, is look at one of the primary metrics now driving this merger mania in the shale patch.

Reserve replacement

It shouldn’t come as any surprise to anyone that oil and gas companies need to make new discoveries at a rate greater than they are producing reserves as daily production. We call this Reserve Replacement-RR, and it is one of the primary drivers causing big operators to use some of their cash hoard in M&A activity. The challenge before these companies is it is becoming more difficult to replace production-which has been increasing monthly, as the most recent EIA-Drilling Productivity report notes, through new drilling alone.

One of the key problems inherent in this effort has been the shift producers have made in reallocating cash flow from new drilling to shareholder returns. These returns have been very popular with investors but have come at a price for reserves replacement even as Finding and Development-F&D costs for a broad cohort of shale E&Ps, have declined as the blue bars in the RBN Energy graph reveal. The sharp bump higher in RR from 2020-2021 came in part from companies reappraising reserves that had been previously written down in the oil price collapse. Once this was complete, we see the line flattening into 2022 as new drilling shoulders the burden for many operators.

One of the things that comes into focus is how some companies have done a better job than others at RR. We can start with Pioneer Natural Resources (NYSE:PXD), a company soon to be merged into ExxonMobil (NYSE:XOM). There are many reasons why XOM was determined to pay up for PXD, and we discussed some of them in an OilPrice article last April. There are other reasons, and we plan to detail them in a future article. That said, PXD’s success in replacing its reserves can’t have escaped XOM’s careful eye, at better than 300% over the three-year period,

as this RBN Energy graphic notes.

For reference, XOM hasn’t been doing nearly as well on this metric, as this graphic from Energy Intelligence reveals. To be fair we must acknowledge the Law of Large numbers hobbles XOM in this regard. Even with the massive discoveries the last few years in Guyana XOM’s reserves are falling year over year. The purchase of PXD will buy XOM some time with its 2.2 bn barrels of P-2 reserves, and we should see a bump higher over the next couple of years.

It is worth noting that Pioneer is in the position it is precisely from this sort of M&A activity over several years. The company was one of the first movers in the shale M&A space with its purchase of Parsley Energy in early 2021 for $7 bn. That was followed a few months later with the acquisition of privately held Double Point Energy for $6.4 bn. Pioneer management is to be congratulated for having the vision to spend the money they did, at a time when the oilfield’s recovery from Covid lows was still nascent. It set the stage for them to become the leading Permian producer they became and ultimately draw ExxonMobil’s buyout offer at a 20% premium to recent share prices.

What’s next?

Pioneer wasn’t alone in building a shale empire to bolster reserve replacement rates on Wall Street when they couldn’t through drilling. Devon Energy (NYSE:DVN) is another price example of a company that has transformed itself through acquisitions and divestitures over the last few years.

Devon made its first big splash in the M&A theatre with its $5.3 bn takeout of Ocean Energy in 2003, gaining a significant shale footprint along with deepwater blocks in the Gulf of Mexico and international interests in a number of West African countries, Indonesia and Russia. In 2015, Devon bought the Anadarko assets of Felix Energy for $1.9 bn. The next big buy was Permian-Delaware-focused WPX Energy in 2021 for $5.8 bn. WPX brought acreage that now forms the cornerstone of much of DVN’s development plans in the Delaware. It followed up WPX with Parsley Energy later that year for another $4.5 bn. Devon has continued this torrid pace with bolt-on purchases of Validus Energy in 2022 for $1.9 bn, enhancing its Eagle Ford oil-weighted acreage in the process. Then came the Williston basin assets of Rimrock Oil and Gas in the sweet spot of the Bakken play.

All of that M&A activity builds a company with a portfolio that is top-tier in every shale play in which it participates. Devon itself is a powerhouse with nearly 700K BOEPD output that will generate nearly $12 bn of EBITDA in the full year 2024. It trades currently at 3X EV/EBITDA and $59K per flowing barrel. For reference, ExxonMobil just paid $66 bn or $254 per share for PXD, which prior to the deal, was trading at 5-6X EV/EBITDA and $88K per flowing barrel.

I think it’s just a matter of time before a Super Major like Chevron (NYSE:CVX)-which has the same reserves replacement problem that XOM does, does the math and puts an offer on the table for Devon.

An alternative scenario might be where Devon makes a merger deal with another shale operator that would give them the critical mass to stay independent. Marathon Oil (NYSE:MRO) has a similar acreage footprint to DVN’s and trades in the 3-4X EV/EBITDA sweet spot and at a very low-for these days, $40K per flowing barrel. Whether it’s Devon or someone else, MRO’s days as an independent operator are likely numbered.

Your takeaway

Shale drilling has been refined to a high art since the mid-teens. Longer wells and increased efficiencies in fracturing treatments have enabled operators to grow production with fewer assets. This has resulted in helping to keep costs in line and for companies to grow production year over year and pad the coffers with record cash flows.

Shrewd operators have used their cash flow to fund aggressive acquisition campaigns that have enhanced their reserve replacement rates. In the case of PXD, this put a target squarely on the back, and in my view, an offer like the one XOM made was inevitable.

As I’ve discussed, there are other companies performing at a high level in terms of reserve replacements, and I think it is very likely we will see more M&A activity in the shale patch as we head into 2024.

 

 

By David Messler for Oilprice.com

 

In the first nine months of 2023, U.S. LNG developers signed 14 long-term sales and purchase agreements totaling 19.65 mtpa. The pace is far slower than in 2022 when Russia’s invasion of Ukraine led European countries to scramble for future supplies not shipped from Moscow. The first nine months of 2022 saw 30 SPAs totaling 35.0-35.5 mtpa, and the full year brought 38 agreements totaling 48.53-49.03 mtpa. Q3 of this year was particularly slow, with only two SPAs signed.

Q1-Q3 SPA tally is down 53% by number of contracts, 44% by volume YOY.

European buyers contracted 35% of the 1Q23-3Q23 long-term SPA volumes. Asian buyers came in second at 31%, while supermajors and majors snagged 27% and merchants and traders locked in 7%. This compared to a 2022 breakdown of 38% supermajor/major, 32% Asian, 21% European and 9% merchant/trader.

Venture Global LNG has signed the most long-term SPAs in the first nine months of 2023 at five, totaling 5.95 mtpa – two SPAs covering 1.7 mpta for Plaquemines LNG and three SPAs covering 4.25 mtpa. Counterparties are Germany’s state-owned Securing Energy for Europe, The Woodlands-based global LNG shipper Exelerate Energy, and Asian firms JERA and China Gas. These deals follow a banner 2022 when the company signed 13 SPAs totaling 12 mtpa.

Venture Global’s Plaquemines LNG facility will be capable of exporting up to 20 mtpa produced by 36 trains. An FID for the 13.3 mtpa Phase 1 was made in May 2022, and Phase 2 sanction followed this March. FERC issued the final EIS for the 20 mtpa CP2 facility in late July and could authorize the project before year’s end. CP2 will have 18 modular trains, twice as many as the operational 10 mtpa Calcasieu Pass LNG facility Venture Global built next door. Calcasieu Pass is still in the commissioning phase despite exporting 90 cargos in the first seven months of 2023, according to Department of Energy data.

Venture Global signed most SPAs YTD; NextDecade locked in most volumes.

Four of the 2023 agreements were secured by Cheniere Energy, totaling 4.7 mtpa. Signed with European firms BASF and Equinor and Asian firms ENN and Korea Southern Power, the agreements support expansions of the company’s existing Corpus Christi and Sabine Pass facilities. Cheniere pre-filed with FERC in February for Sabine Pass Stage 5, which will add up to three trains totaling up to about 20 mtpa. Sabine Pass currently has 30 mtpa of capacity from six trains.

At Corpus Christi, Stage 3 project is under construction after Cheniere made an FID in June 2022 for the seven-train, over 10 mtpa expansion. The capacity, expected in 2025, will add to the original three trains’ 15 mtpa. But that’s not all. Cheniere filed an application with FERC in March to add two more trains, CCL Midscale Trains 8 and 9, with 3 mtpa of capacity. In 2022, Cheniere signed five SPAs totaling 7.85 mtpa.

Despite only signing two SPAs through Q3 this year, NextDecade’s tally of 6.4 mtpa is volumetrically more than its competitors’ tally and follows six SPAs totaling 7.75 mtpa in 2022. TotalEnergies signed up for the bulk of the 2023 SPA volumes, at 5.4 mtpa, while Japan’s Itochu signed for the rest. NextDecade will supply the volumes from its 27 mtpa Rio Grande LNG project in Brownsville, Texas. The company made an FID for the project’s three-train 17.6 mtpa Phase 1 in July, and the first train should be substantially complete in 2027.

So far this year Delfin Midstream also signed two SPAs, one with European firm Centrica and one with commodities firm Hartree Partners, with the contracts covering 1.6 mtpa and adding to one SPA covering 0.5 mtpa signed in 2022. Unlike the other projects with offtake agreements, which are land-based, Delfin is developing a floating LNG seaport project. If fully developed, Delfin LNG is designed to accommodate up to four FLNG facilities to produce up to 13.3 mtpa. The company said it is in the final phase ahead of an FID for the first two FLNG vessels and is accelerating the development of the remaining FLNG slots in light of a strong market outlook for cleaner-burning fuels in Asia and continuing strong demand in Europe. First LNG is targeted for 2027.

FIDs YTD are Venture’s Plaquemines Ph. 2 & NextDecade’s Rio Grande Ph. 1.

Sempra Infrastructure may have only signed one SPA for 1 mtpa this year, with PKN Orlen, but the company had already locked in three long-term agreements totaling 8.28 mtpa in 2022 for its Port Arthur LNG project in Jefferson County, Texas. It made a positive FID in March for the two-train, 13 mtpa Phase 1, whose first train is set to come online in 2027. A two-train Phase 2 is currently being marketed and was recently authorized by FERC.

Despite a lack of sales and purchase agreements signed this year, Commonwealth LNG and Lake Charles LNG have made notable progress. The proposed six-train, 9.3 mtpa Commonwealth project in Cameron, Louisiana, was authorized by FERC in November 2022. At that time, the company had already signed SPAs covering up to 2.5 mtpa over 20 years with Woodside Energy. So far in 2023, Commonwealth has entered heads of agreements for 4 mtpa of long-term supply, one for 1 mtpa for 20 years with MET Group, one with Kimmeridge Energy Management for 2 mtpa over 20 years, and one with EQT Corp. for 1 mtpa over 15 years. The latter two agreements include feedgas supply to the project. Kimmeridge is also providing development capital and Commonwealth says it now has sufficient financial commitment to reach FID. That’s targeted for 1Q24, with startup anticipated in 2027.

Lake Charles and Commonwealth LNG have made notable progress this year.

The situation surrounding Lake Charles LNG is a bit more complicated. The U.S. Department of Energy denied Energy Transfer’s application for a three-year extension of its existing license to export to countries that don’t have free trade agreements with the U.S., leaving the startup requirement at Dec. 16, 2025. ET anticipates that startup will occur in 2028, so that deadline is not feasible, and the company in August filed for an expedited non-FTA export license, to be issued by February.

Despite the regulatory uncertainty, ET signed HOAs covering tolling agreements with EQT and Chesapeake Energy that envision each E&P company providing 135 MMcf/d of feedgas supplied to Lake Charles and offtaking 1 mtpa for 15 years, or 2 mtpa combined. Further HOAs cover 1.6 mtpa over 20 years to a Japanese consortium and 1 mtpa for 15 years to an unnamed U.S. firm. In 2022, six SPAs covering 7.9 mtpa were signed for Lake Charles. If the HOAs are all converted to SPAs, ET will have 12.5 mtpa in long-term offtake lined up for the project. When fully developed, Lake Charles will have three trains with a total of 16.5 mtpa of capacity.

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