Energy News Beat

(Bloomberg) – Shell Plc is preparing to cut staff from its offshore wind business as Chief Executive Officer Wael Sawan moves the company away from the capital-intensive renewable energy sector.

The British oil major is set to begin the layoffs within months, mainly in Europe, according to people familiar with the matter who requested not to be identified because the information is private.

“We are concentrating on select markets and segments to deliver the most value for our investors and customers,” a Shell spokesperson said. “Shell is looking how it can continue to compete for offshore wind projects in priority markets while maintaining our focus on performance, discipline and simplification.”

Shell had been spending heavily in offshore wind, aiming to leverage its experience extracting oil and gas at sea to become a leader in the technology. But soaring costs in the sector and a renewed focus on driving returns for shareholders under Sawan has led the company to back away from the green-energy source.

Since Sawan took on the CEO role at the beginning of last year, he’s put pressure on business divisions to improve performance and profitability. In June 2023, he laid out a plan to reduce “structural costs” by as much as $3 billion by the end of 2025. The cuts to offshore wind follow layoffs that started in the low-carbon solutions unit earlier this year.

Shell has built up a team, focused in the Netherlands to develop and build offshore wind farms. But the company limits on spending left a large team with less to do than previously expected.

The staff cuts follow departures of a number of key executives in the offshore wind business, including Thomas Brostrom, the head of its European renewable power division and Melissa Read, the head of its UK offshore wind unit.

Source: Worldoil.com

Take the Survey at https://survey.energynewsbeat.com/

1031 Exchange E-Book

ENB Top News 
ENB
Energy Dashboard
ENB Podcast
ENB Substack

The post Shell plans job cuts in offshore wind business as CEO refocuses on oil and gas appeared first on Energy News Beat.

 

Energy News Beat
The US is working to build its own rare earth element supply chain to reduce dependence on China.
China currently dominates the market due to decades of investment and lax environmental regulations.
Researchers are exploring ways to extract rare earths from existing US coal mines as a potential shortcut.

Huge upticks in renewable energy capacity installations around the world are causing demand for key rare earth elements to skyrocket. While these materials aren’t as geologically rare as their name might suggest, their production is limited as a finite number of already developed supply chains struggle to keep up with demand. As a result, prices are skyrocketing. Not only is there therefore a huge economic opportunity in establishing new supply chains for rare earths, there are also major risks to allowing current market entities to continue consolidating influence over these essential clean energy building blocks.

Currently, China dominates rare earth element supply chains. According to the Oxford Institute of Energy Studies, Beijing alone is responsible for 70% of the world’s rare earth ore extraction and 90% of rare earth ore processing. Moreover, China is still the only large-scale producer of heavy rare earth ores on the planet. This isn’t just because of China’s own rich natural deposits of these ores. “This dominance has been achieved through decades of state investment, export controls, cheap labour and low environmental standards,” reports Oxford. The country has spent decades building up supply chains around the world, expanding its energy and industrial influence into emerging markets spread across Asia, Africa, and Latin America.

Now, the United States is making concerted efforts to build up its own homegrown rare earth supply chains for its own renewable energy needs, as well as considerable demand from the military. The Department of Defense has awarded more than $439 million to establish domestic rare earth element supply chains since 2020, and the Department of Energy has also been throwing billions of dollars into kickstarting the country’s lithium industry.

The United States has been scouting out supply chains for key rare earth elements around the globe, intensifying efforts to secure its own supply in recent years by turning to nations including Mongolia, South Africa, and Mexico for potential trade deals. However establishing trade agreements that China hasn’t already gotten to first has proven difficult. China has been busily expanding a green energy empire in lithium-rich Latin America, for example, but the United States has had a comparatively difficult time entering into the same market.

Luckily, the United States is also geologically rich in many rare earth elements – it will just require building an entire extraction and processing industry from the ground up. Considering the huge and rapidly growing demand for these elements, as well as the geopolitical risk associated with a one-nation monopoly on their supply chains, that kind of a timeline is less than ideal.

But researchers at the University of Utah may have found a shortcut. Ironically enough, the key to powering the U.S. renewable energy industry may require partnering with the U.S. coal industry for quicker and more cost-efficient ore extraction. The research team has found ‘elevated concentrations’ of rare earth elements in currently operational mines on the Uinta coal belt of Colorado and Utah. In theory, this could allow already active mines to extract rare earths along with the ore they’re already extracting with little additional overhead.

“The model is if you’re already moving rock, could you move a little more rock for resources towards energy transition?” said study co-author Lauren Birgenheier, an associate professor of geology and geophysics. “In those areas, we’re finding that the rare earth elements are concentrated in fine-grain shale units, the muddy shales that are above and below the coal seams.”

While the United States is making a major place to become competitive in the rare earth element market, however, it’s still many years and billions of dollars behind China in terms of industrial development as well as deal-making diplomacy with ore-rich nations. Plus, it can’t compete with the low labor costs, unilateral decision-making power, and lax environmental oversight that gives Beijing an edge on the market. But innovative approaches like the ones being tested by the University of Utah could open a potential avenue for regaining some of that ground.

Source: Oilprice.com

Take the Survey at https://survey.energynewsbeat.com/

1031 Exchange E-Book

ENB Top News 
ENB
Energy Dashboard
ENB Podcast
ENB Substack

The post Active Coal Mines Might Be Key to the Renewable Revolution appeared first on Energy News Beat.

 

Energy News Beat

Humanity is almost a quarter of the way through the 21st century and Virginia — home to 70% of the world’s data centers — is on the frontlines of the latest emerging technology: artificial intelligence, or AI.

The prevalence of data centers and the rising role of AI don’t equate to a dystopian battle between humans and machine control, though (at least at the moment). Rather, these issues are at the center of a debate over localities’ authority and revenue benefits, historic preservation, environmental considerations, and electricity demand and utility rate projections, all shaped by ever-increasing internet use.

The state is studying data center development

Northern Virginia, the densely populated suburbs and exurbs located just outside the nation’s capital, is home to 70% of the world’s data centers, the huge warehouses that store computers’ processing equipment, internet network servers and data drives. With people increasingly using web-based programs on an average of 22 internet-connected devices in homes, data centers are seen to be needed more than ever.

While data centers are proposed as potential drivers of economic benefits for localities, a number of Virginians have expressed concerns about the proliferation of the warehouses in the state and their effect on communities where they’re located.

“Is it worth losing all your water, and having noise pollution and everything else to get revenue for some of the things you need?” said Mary Damone, 67, who moved to the Orange County area a few years ago, where a 732-acre data center park development has been proposed.

Fairfax County resident Chris Ambrose, 63, who, like Damone, was also at a recent press conference raising concerns over data center development, said the development of thousands of homes in the proposal is bad enough.

“Then you add the data centers to it, and the transmission lines, the impact on the battlefields,” Ambrose said. “If they need more revenue, you would think it would be something more measured. The magnitude is just crazy. It’s off the charts.”

Josh Levi, president of the Data Center Coalition, said the industry looks forward to supporting JLARC and discussing the findings when the study is done.

“Virginia continues to distinguish itself as one of the most dynamic and important markets for the digital infrastructure that enables our innovation economy and meets the growing, collective computing demands of individuals and organizations of all size,” Levi said.

 

This past legislative session, lawmakers introduced over a dozen bills to address some of the public’s concerns over how data centers could impact water demand, power delivery costs and more, but they were all sent to the Joint Legislative Audit Review Commission, the state’s policy research arm, to develop policy proposal recommendations.

“We have a number of research activities planned or underway for this study,” said Mark Gribbin, the JLARC project lead for the data center study, at a meeting last week outlining the study’s goals.

“Foremost, we’ll have a high level of engagement with local communities and data center companies,” said Gribbin. “We’re also working closely with utilities, local governments and state regulators, especially on questions related to development, water, air and energy,”

In the few months since those legislative deferrals, a battlefield in Orange County has been listed as one of the 11 most endangered sites in the country because of data center development, and Google announced a $1 billion investment to expand their data center campus in Reston.

Both events have re-upped the conversation over how to provide data centers their needed electrons, which could be delivered through an improved transmission system, after a recent regulatory overhaul of how such systems are planned.

“If the generation isn’t there to meet a proposed data center’s needs, the data center doesn’t [need to] locate in Virginia or anywhere else that can’t meet its load,” said Walton Shepherd, Virginia Policy Director with the Natural Resources Defense Council. “Virginia is not responsible for the running of the internet, the data center operators largely are. The solution we need to solve is a cleaner grid.  We have the tools to do so, and that’s with or without data centers.”

Local, historic concerns

In Orange County, Wilderness Crossing data center received national attention for its proposed development near a Civil War-era battlefield, fueled by concerns after data centers were built near other historic sites in Loudoun and Prince William counties in addition to other parts of the state.

The proposed Wilderness Crossing site near  Wilderness Battlefield sprawls across 2,600 acres, 732 of which  would accommodate data centers — which can typically have a footprint of over 100,000 square feet each and reach 90 feet tall —  and distribution warehouses. The site plan also envisions over 5,000 residential units and 200,000 square feet of mixed commercial use buildings, and a realigning of Route 20.

“If this development goes forward as approved, there will be intense pressure on the existing road network,” said Bob Lookabill, president of the Friends of the Wilderness Battlefield, at the press conference announcing concerns over the Wilderness Crossing proposal.

The development would also obstruct the views of Virginia’s hillside, take up forested land, sit on abandoned gold mines and draw on water from the Rapidan River, which experienced drought-like conditions last year. Concerns about data centers’ impact on local waterways have been echoed around the state.

The area’s water is served by the Rapidan Service Authority. According to its recently approved water permit, obtained by the Virginia Mercury, the Department of Environmental Quality rejected an initial request finalized after the Wilderness Crossing rezoning that sought to pull more water for projected demand increase.

“What if there is a drought?” said Tim Cywinksi, communications director for the Virginia chapter of the Sierra Club, while speaking about another data center proposal in Caroline County during a webinar. “Are we going to continue to supply what becomes a diminishing resource to an industry that’s powering AI? Or are we going to give it to families to make sure they need it? … This is why protective policy is so important.”

Other data center proposals appear to show that the developments would encroach on historic sites statewide, such as Manassas National Battlefield Park, Culpeper National Cemetery, Brandy Station, Sweet Run State Park and Savage Station Battlefield.

Two historic Black graveyards belonging to the Gaskins family in the Brentsville area of Prince William County are alleged to have been damaged from the construction of a data center and a nearby power substation.

“Without comprehensive action from our elected leaders, countless historic sites [and] national parks may continue to fall victim to this unchecked and unregulated data center growth,” said Kyle Hart, mid-atlantic field representative at the National Park Conservation Service during the May 1 press conference.

The pressure to these sites has already been largely seen in Loudoun and Prince William counties, which have been dubbed Data Center Alley, and recently approved a Digital Gateway rezoning in their respective jurisdictions.

“We have to have a better way [to] think it through and it needs to be transparent,” said Chris Miller, president of the Piedmont Environmental Council, a conservation organization focused on preserving central Virginia’s countryside. The group won a lawsuit against Orange County that forced the release of previously withheld information on the Wilderness Crossing proposal. “I think everyone wants a continued investment in the economy and [to be] prosperous, but you want it done in a way that doesn’t destroy the underlying quality of life.”

Data center developments have been continually proposed throughout Virginia and are welcomed by some communities. A 1,200-acre data center site was recently approved in Hanover County. The Delta Lab, an energy innovation initiative focused on Southwest Virginia, has studied locating one in that region that could use water from mines for cooling.

Del. Mark Sickles, D-Fairfax County, said at the recent JLARC meeting, two vacant buildings along the beltway in his district are being converted into an Amazon Web Services data center, without controversy.

“It was a perfect place for it, actually,” Sickles said. “We need to find more perfect places in Virginia that are close to power, and can be shielded from the public. It’s going to be a challenge for everybody because I don’t think we want to give up on this industry.”

$1 billion investment

Just days before the concern over Wilderness Crossing became public, Gov. Glenn Youngkin announced that Google, one of the biggest companies in the world, would expand its data center campuses from two facilities to three.

“We’re super excited about it,” said Ruth Porat, president, chief financial officer and chief investment officer of both Google and its parent company Alphabet, of the expansion. “The investments we’ve made today are not only important investments in infrastructure, but they’ve also added 3,500 jobs in Virginia, and they supported a billion dollars of economic activity.”

Google completed the first phase of construction on the first two data centers in 2019 with a $1.2 billion investment in the state.

The third center’s creation will usher in an AI Opportunity Fund seeded with $75 million from the company’s philanthropic arm, Google.org. The fund will help people around the county earn online training certifications. The program joins a separate Grow with Google program, already underway, that teamed with Northern Virginia Community College to offer a new free cyber security career certificate.

“Since 2019, this innovative public-private partnership has increased opportunities for students to join the technology workforce,” said Anne M. Kress, president of NOVA, in a statement. Kress added that the partnership  “helps close the skills gap and greatly expands the region’s talent pool.”

A driving force for the online certifications through the opportunity fund, would be leveraging AI. The governor leaned into the “accelerator” allegory during the announcement, highlighting AI’s ability to hasten the pace for certifications to be awarded.

“What’s been so exciting is that this parallel path, this moment of accelerator and brakes, is enabling confidence as we move forward to move forward with an expedited pace,” Youngkin said. “That is where breakthroughs can occur.”

Data centers in Virginia have provided $2.2 billion in wages for citizens, and 25% of revenue to Loudoun County have gone into “essential services” like schools, social services and other public programs, Youngkin added.

Impact on power demand

Increased internet usage, including AI, requires data centers to use more electricity. Computing for AI is measured by an entirely new computing graphic processing unit, or GPU.

“Historically, a single data center typically had a demand of 30 megawatts or greater,” Dominion Energy Virginia President Bob Blue said in the utility’s first quarter earnings call. “However, we’re now receiving individual requests for demand of 60 megawatts to 90 megawatts or greater, and it hasn’t stopped there.”

Larger data center campuses with multiple buildings can “require total capacity ranging from 300 megawatts to as many as several gigawatts,” Blue added.

The utility has connected 94 data centers to date and expects to connect another 15 this year, Blue also told investors. Power Engineering reported on a Securities Exchange Commision annual filing that in 2023 and 2022, 24% and 21% of electricity sales from Dominion were to data centers, respectively.

“The concentration of data centers primarily in Loudoun County, Virginia represents a unique challenge and requires significant investments in electric transmission facilities to meet the growing demand,” the SEC filing states.

While the data center computers have become more efficient through a power usage effectiveness score — a rate that determines how efficiently energy is processed for the web-based service to reach internet users — a study from McKinsey & Company found that data center power demand is expected to more than double across the country from from 17 GW to 35 GW. Some of that power could come from Dominion’s 176-turbine  offshore wind project,  expected to generate 2.6 GW of electricity, or enough to power 660,000 homes.

“The point is that they’re packing more and more into less space,” Miller said. “How are we going to meet that load?”

Dominion projects its load growth, which includes data centers and vehicle electrification, to increase from 17 gigawatts in 2023 to 33 gigawatt in 2048, though environmental groups are skeptical of growth proposals being modeled accurately.

Northern Virginia Electric Cooperative expects to increase its peak electric load by more than 12% per year over the next 15 years, “driven almost exclusively by data centers.”

“NOVEC works one-on-one with each new data center, as each new high-load customer presents unique issues to NOVEC and its distribution facilities,” said Jim East, communications manager at electric cooperative. “Part of this includes meeting the special energy supply and construction schedule needs, while always maintaining the high degree of reliability and affordability for all remaining customers.”

To meet the demand for data centers, Dominion has included renewable energy technology in its long-term, non-binding integrated resource plan, but is also proposing a natural gas plant, which environmental groups continue to oppose, including protests at a Richmond outdoor festival the utility sponsored.

Teresa Hall, a spokeswoman for Appalachian Power Company, Virginia’s second largest utility that serves Southwest Virginia, noted that “annual power generation over the last 20 years has stayed relatively flat until now.” The uptick, she said, is thanks to data centers.

“With data centers/increased internet use and AI, the landscape is changing quickly,” Hall said, adding that data centers present a unique challenge because they “require a lot of power – commonly 300 MW or more, which is enough to power all of the homes in a medium-size city.”

The company is facing the challenge head-on, Hall said.

“To date, we’ve been able to accommodate almost any size customer that has expressed an interest in our service territory. As we go forward, we know we will need additional cooperation.”

Virginia’s leaders have increasingly expressed the need for new technologies such as small modular reactors, tinier versions of traditional nuclear plants that could power a small city like Roanoke with a population of 100,000. Proponents say SMRs could provide baseload, around-the-clock power when renewable technology can’t produce it. The SMRs are intended to provide between 300 to 500 megawatts of power, but none have been turned on in the United States since NuScale pulled the plug on its effort to build one in Idaho due to cost concerns.

Shepherd, with the NRDC, said that if SMRs are built, “they’re so far off. I don’t think those are going to implicate the data center’s decision on where and when it builds in a place where it is able to get power.”

Another part of the dialogue focuses on technologies like battery storage and a recently announced 1920 rule from the Federal Energy Regulatory Commission, or FERC, to increase planning for transmission lines across state lines. FERC’s new guidance includes transmission lines that may need to be upgraded from a traditional 110 kilovolt to up to 500 kilovolt capacity, in order to supply data centers.

“Transmission developers can now plan projects that address a multitude of needs that are anticipated to develop over a long-term horizon more efficiently and cost-effectively for customers,” stated Ben Fowke, president and CEO of American Electric Power, the parent company of Appalachian Power Company, in U.S. Senate committee testimony this week.

The regional rule will also help areas pull on generation sources that may be located in other areas of the PJM Interconnection regional grid that Virginia is a member of.

“Every resource backs up every other, but only if you have the transmission required,” said Gamlich.

In 2023, Virginia’s legislature passed a bill to truncate a State Corporation Commission review of a transmission line proposal from PJM Interconnection. The line is needed to deliver power for data center development in Virginia and the $670 million project cost is recovered from ratepayers in Virginia.

There’s also an opportunity to strengthen existing transmission lines through grid enhancing technologies, or GETs, and separate ways to utilize a demand side management and energy efficiency programs to reduce the amount of strain on the grid. It can also help get around the 26 gigawatts of electricity stuck in a queue awaiting approval from PJM, 23% of which is from Virginia, said Kim Jemaine, director at Advanced Energy United.

“In the states where they have been adopted at a medium level, GETs have unlocked 30% additional capacity from existing infrastructure and have allowed twice as many new energy projects to be integrated,” said Kim Jemaine, director at Advanced Energy United. Jermaine said GETs “can be installed with little to no downtime and at a fraction of the cost of new infrastructure.

Utilities have said they can’t rely on energy efficiency efforts, like homeowners using smart thermostats to control consumption, because the end use may not keep up with those behaviors. But that dismissal is a “red herring,” Shepherd said. Measuring the load reductions delivered through energy efficiency programs and making actionable plans based on those measurements is not impossible, Shepherd added.

“I think folks need to chill out and recognize the regular nature of grid planning. It’s just a matter of rolling up our sleeves a little further to make sure it’s done correctly.”

Perhaps ironically, as manufacturing and society in general electrifies more, AI might be able to help with those demand side management programs, as noted by the U.S. Department of Energy.

“AI has the potential to significantly improve all these areas of grid management,” the report stated, and can be a tool that models for capacity and transmission studies, compliance and review for federal permitting, forecasting renewable energy production and creating applications to enhance resilience.

Levi, with the Data Center Coalition, said the “industry is committed to leaning in as an engaged partner at this pivotal time. Collectively, we can meet the moment and ensure a clean, reliable, affordable, and resilient electric system that supports the digitization of our economy, widespread vehicle and building electrification, the onshoring of advanced manufacturing, growth in controlled environment agriculture, and other 21st-century economic drivers.”

Local Revenue

But the money.

The local revenue generated by data centers supports Loudoun and Prince William counties — the latter of which could add $54 million in revenue, with $19 million going toward schools and $21 million offsetting a real estate tax increase — as a result of increasing its data center tax from $2.15 to $3.70 per $100 assessed value.

Henrico County created a $60 million affordable housing fund with revenue from data centers in order to waive water and sewer connection fees and building permit fees.

“We’re doing something different,” Board Chairman Tyrone Nelson said, according to Richmond BizSense. “We may be the only locality in the commonwealth, maybe in the country, dedicating a single revenue source to address a crisis like this in our community.”

Even property owners that sell their land for development of a data center can reap benefits. But, as evidenced by a Prince William County lawsuit,  the spoils don’t always go to the seller  if a legal challenge over the rezoning holds up their profits as the property value and tax increase remains.

The report on Project Oasis proposal in Southwest Virginia said development of a 250,000 square foot “hyperscale” data center with 36 MW of demand could generate an estimated $464 million in capital investment and 40 indirect jobs.

Another report by the Virginia Economic Development Partnership found that 35 data centers, which are cited as the largest industry in the state, invested $23 billion into the economy while getting almost $1 billion in tax relief in exchange for its economic inputs. The report found a 14% average annual return on incentive for the years 2022 through 2027.

“JLARC estimated [in 2019] that 90 percent of the data center investment made by the companies that benefit from the DCRSUT exemption would not have occurred in Virginia without the exemption,” the report stated.

Although localities may be raking in local revenue benefits, those tax incentives for data centers cancel out cash that could be padding state coffers, which similarly could go toward education and other services.

“There’s different layers to look at,” said Jackson Miller, director of state power sector policy, also at the NRDC. “We just think that if you’re going to give away that revenue, which is taxpayer public money, then it needs to be conditioned with requirements to maximize energy efficiency, with requirements to maximize and ensure that that facility is bearing its costs and paying for it on the grid so ratepayers don’t get a double- whammy.”

Along with a bill to study if data centers or ratepayers foot the bill for transmission upgrades, a separate bill sent to JLARC this session came from Del. Rip Sullivan, D-Fairfax, and Sen. Suhas Subramanyam, D-Loudoun, that would’ve required data centers to achieve a certain computing efficiency score, known as a PUE, in order to receive state tax breaks.

The data center companies have climate improving commitments, but local permitting pushback to renewable energy sources, including solar, present challenges.

The centers should “ be required to be 100% renewable before they turn the lights on if they’re serious about their publicly stated comments,” said Hart, with the National Park Conservation Service.

The data center industry’s benefits to Virginia’s economy include the creation of 12,140 direct jobs, including engineers, building control specialists, security, server technicians, logistics professionals, construction management, health and safety specialists, and food services. The future benefits — and challenges — of data center development in the state remain to be seen.

Source: Yahoo.com

Take the Survey at https://survey.energynewsbeat.com/

1031 Exchange E-Book

ENB Top News 
ENB
Energy Dashboard
ENB Podcast
ENB Substack

The post Virginia Explained: Data center expansion, with all its challenges and benefits appeared first on Energy News Beat.

 

Energy News Beat
The acquisition of Marathon Oil will extend ConocoPhillips’ reach across shale fields in Texas, New Mexico and North Dakota, adding 2 billion barrels of resources to its portfolio.
ConocoPhillips expects share buybacks worth $7 billion in the first year after the deal is completed and $20 billion after the first three years.
ConocoPhillips is the last major U.S. oil company to pull the trigger on a big acquisition as the industry undergoes a wave of consolidation.

ConocoPhillips agreed on Wednesday to buy Marathon Oil in an all-stock transaction worth $17 billion that would bolster the company’s shale assets as the broader oil and gas industry undergoes a major wave of consolidation.

The deal will add 2 billion barrels of resources to ConocoPhillips’ inventory in the U.S., extending the company’s reach across shale fields in Texas, New Mexico and North Dakota.

Lance said the transaction would grow ConocoPhillips’ earnings, cash flow and shareholder returns after the deal closes in the fourth quarter. ConocoPhillips expects share buybacks worth $7 billion in the first year after the deal is completed and $20 billion in the first three years.

The merger is expected to generate $500 million in savings in the first year through reduced administrative and operating costs because the companies’ assets are adjacent to each other.

ConocoPhillips’ stock was down 3.3% in early trading following the announcement as Marathon Oil shares surged 7.3%. ConocoPhillips is the third-largest U.S. oil company with a market capitalization of $137 billion, while Marathon Oil has a market cap of $14.4 billion.

ConocoPhillips is the last of the top three U.S. oil companies to pull the trigger on a big acquisition as the industry undergoes a transformational wave of consolidation.

Exxon Mobil’s acquisition of Pioneer Natural Resources for $60 billion recently received the greenlight from the Federal Trade Commission. Hess Corporation shareholders voted on Tuesday to advance the company’s $53 billion merger with Chevron

Source: CNBC

Take the Survey at https://survey.energynewsbeat.com/

1031 Exchange E-Book

ENB Top News 
ENB
Energy Dashboard
ENB Podcast
ENB Substack

The post ConocoPhillips to buy Marathon Oil in $17 billion all-stock deal that bolsters shale assets appeared first on Energy News Beat.

 

Energy News Beat

Floating LNG player Golar LNG is working to sign definitive agreements for an up to 20-year FLNG deployment.

In February, the LNG firm led by Tor Olav Trøim said in its 2023 results report that it had signed a framework agreement with a “potential customer” for a long-term opportunity that could utilize either the 2.4 mtpa FLNG Hilli or a 3.5 mtpa FLNG.

Golar said on Tuesday in its first quarter report that the framework agreement has now “progressed to detailed contract negotiations for an up to 20-year FLNG deployment”.

The next steps of the project development include signing of definitive detailed agreements, obtaining necessary third-party approvals including governmental and environmental, amongst others, and a mutual final investment decision (FID), the company said.

According to Golar, the FLNG development has a planned start-up during 2027.

The company’s CEO Karl Staubo said during the earnings call later on Tuesday that the development could include more than one FLNG over time.

Golar is working with the client whether Hilli or the MKII 3.5 mtpa FLNG should be the first one, Staubo said.

Golar said it focus is on redeployment of its FLNG Hilli following the end of the FLNG’s current charter in July 2026, and thereafter ordering and securing commercial terms for a contemplated MKII FLNG.

Last year, FLNG Hilli, located offshore Cameroon’s Kribi, offloaded its 100th cargo of liquefied natural gas since it started operations in 2018.

Hilli produced 1.46 million tonnes in 2023.

Golar said in the first quarter presentation that the FLNG has offloaded 112 cargoes up to date and produced more than 7 million tonnes of LNG.

Beside the mentioned project, Golar said it continues to advance additional FLNG developments and the company sees “increased prospective client interaction for our FLNG offering”.

“Geographically, most of the activity remains in West Africa and South America, however we are pleased to see other regions with proven stranded and associated gas reserves seek FLNG development,” the firm said.

As per the MKII 3.5 mtpa FLNG project, Golar exercised its option last year to acquire the 148,000-cbm Moss-type carrier, Fuji LNG, which it aims to convert to a floating LNG producer.

Golar said the MKII FLNG project development continues, with previously ordered long lead items now 58 percent complete.

The company took delivery of Fuji LNG on March 4, 2024.

Golar said Fuji LNG will trade on a multi-month charter ahead of its expected transfer to the yard for FLNG conversion.

“Work between the topside manufacturer, shipyard and Golar continues to move the project towards a FID. Detailed negotiation for a debt financing facility to be available during the construction period of the contemplated MKII FLNG also continues with prospective lenders and made solid progress during the quarter,” the company said.

The quarterly presentation shows that total spend as of March 31, 2024, including Fuji LNG, is about $270 million. Golar committed more than $400 million for the development.

Golar said that an all-in FLNG price had been reconfirmed as an “industry-leading” with about $600 million/mtpa, and the yard slot was confirmed for H2 2027 sailaway if the conversion is ordered in 2024.

In November last year, Golar’s converted floating LNG producer, Gimi, left Seatrium’s yard in Singapore.

Golar announced in January this year the arrival of the FLNG at the site of BP’s Greater Tortue Ahmeyim project offshore Mauritania and Senegal.

However, the FLNG then proceeded to moor offshore Tenerife and BP said the unit arrived at the GTA hub in February.

Golar said in the quarterly report that the FLNG is “ready to commence operations”, while the project’s FPSO has now arrived at the project site.

“Hookup and commissioning of the FPSO are on the critical path to first gas and are expected to complete in the third quarter of 2024,” Golar said.

Commissioning of FLNG Gimi can start thereafter. FLNG Gimi’s commissioning period is expected to be about six months, concluding with the commercial operations date (COD), it said.

“Together with the client we are making positive progress in exploring options to bring forward parts of the commissioning process that could shorten this six-month commissioning period,” it said.

During April, Golar received its first standby day rate cash payment from March 13, 2024 onwards, paid monthly in arrears, it said.

Also, pre-commercial operations date contractual cash flows are expected to be deferred on the balance sheet and released over the contract term from COD, it said.

The operators, BP and Kosmos, and Golar have reached an agreement in principle to resolve the disputed amounts for pre-COD cash flows from January 10, 2024, subject to final documentation and stakeholder approval, it said.

If made effective this agreement will provide Golar with progressive stage payments from January 10, 2024 until COD.

COD triggers the start of the 20-year lease and operate agreement that unlocks the equivalent of around $3 billion of Adjusted Ebitda backlog to Golar.

Golar reported net income of $55 million, inclusive of $6 million of non-cash items, and Adjusted Ebitda of $64 million in the first quarter of this year.

Source: Lngprime.com

Take the Survey at https://survey.energynewsbeat.com/

1031 Exchange E-Book

ENB Top News 
ENB
Energy Dashboard
ENB Podcast
ENB Substack

The post Golar says progress made on new FLNG deal appeared first on Energy News Beat.

 

Energy News Beat

Energy trader Vitol has extended its existing liquefied natural gas (LNG) supply deal with Korea Middle Power (Komipo).

The original SPA was signed in 2011. Deliveries started in 2015, with Vitol supplying Komipo with over 4 million tons of LNG over 10 years.

Under this extension agreement, Vitol will continue to supply Komipo with LNG from 2025 to 2028, the Geneva-based trader said in a statement on Tuesday.

Vitol will supply three LNG cargoes per year.

“The extension confirms the trust and strength of the relationship developed over years of reliable LNG deliveries,” Vitol said.

Vitol, which entered the LNG market in 2006, said it is expanding its LNG presence globally and last year traded over 17 million tonnes of LNG worldwide.

The firm revealed in its full-year report in March that its natural gas and LNG volumes grew by 19 percent and 24 percent respectively, but it did not reveal the quantities.

In 2022, Vitol’s traded LNG volumes increased to about 17.6 million tonnes of oil equivalent, or some 14 million tonnes of LNG, as the company’s portfolio responded to increased demand from Europe.

This means that Vitol’s LNG volumes in 2023 reached some 17.3 million tonnes of LNG.

The firm reported LNG volumes of 12.9 million tonnes in 2021, 10 million tonnes in 2020, and 10.5 million tonnes in 2019.

Vitol has a global LNG portfolio with long-term LNG supply from North America, Africa, Middle East, and Asia, and charters a fleet of LNG carriers.

In February, Vitol signed a long-term deal to buy natural gas from US oil and gas producer EOG.

It also signed a deal with India’s GAIL to deliver 1 mtpa of LNG to the latter for a period of about 10 years starting in 2026.

Source: Lngprime.com

Take the Survey at https://survey.energynewsbeat.com/

1031 Exchange E-Book

ENB Top News 
ENB
Energy Dashboard
ENB Podcast
ENB Substack

The post Vitol extends LNG supply deal with South Korea’s Komipo appeared first on Energy News Beat.

 

Energy News Beat

DALLAS, May 07 /BusinessWire/ — Kosmos Energy Ltd. (“Kosmos” or the “Company”) (NYSE/LSE: KOS) announced today its financial and operating results for the first quarter of 2024. For the quarter, the Company generated a net income of $92 million, or $0.19 per diluted share. When adjusted for certain items that impact the comparability of results, the Company generated an adjusted net income(1) of $99 million, or $0.21 per diluted share for the first quarter of 2024.

FIRST QUARTER 2024 HIGHLIGHTS

Net Production(2): ~66,700 barrels of oil equivalent per day (boepd), representing ~13% growth year over year, with sales of ~62,600 boepd
Revenues: $419 million, or $73.52 per boe (excluding the impact of derivative cash settlements)
Production expense: $94 million, or $16.42 per boe
Capital expenditures: $286 million
Successfully completed convertible bond issuance, enhancing liquidity and paying down higher interest floating rate debt
Post quarter end, successfully refinanced the Company’s reserve-based lending (RBL) facility, extending maturity to year-end 2029
Post quarter end, contracted a drilling rig for the Equatorial Guinea 2024 infill and infrastructure-led exploration (ILX) campaign

Commenting on the Company’s first quarter 2024 performance, Chairman and Chief Executive Officer Andrew G. Inglis said: “Kosmos has had an active start to the year, continuing the operational and financial momentum we saw in 2023. Operationally, we’ve brought four new wells online at Jubilee and first oil at Winterfell is expected shortly, both important milestones for the Company as we target 50% production growth from the second half of 2022 to year-end 2024. We’ve also seen significant progress at Tortue with the FLNG arriving on location, completion of the deepwater pipelay and the FPSO en route to the project site. In Equatorial Guinea, we’re pleased to have secured a high quality rig for the infill and ILX campaign later this year. We are also advancing our next set of growth projects, securing long lead items for Tiberius and a two-year license extension granted for Yakaar-Teranga.

Financially, we enhanced the resilience of the Company with a successful convertible bond offering and the re-financing of the RBL. Both transactions were important steps to proactively increase liquidity and extend our near-term debt maturities.

Our strategy remains on track with a busy year of catalysts ahead across all of our business units in Ghana, Equatorial Guinea, the U.S. Gulf of Mexico and Mauritania and Senegal.”

FINANCIAL UPDATE

Net capital expenditure for the first quarter of 2024 was $286 million, in line with guidance. Full-year capital expenditures are expected to be weighted to the first half of the year as the Ghana drilling program concludes and the Winterfell and Tortue Phase 1 projects progress to start-up.

Kosmos exited the first quarter of 2024 with approximately $2.7 billion of total long-term debt and approximately $2.4 billion of net debt(1) and available liquidity of approximately $954 million. Post quarter-end, the Company successfully refinanced the RBL facility, which now matures at the end of 2029. The facility size increased to $1.35 billion (from $1.25 billion) with current commitments as of April 26, 2024 of approximately $1.2 billion. The RBL facility is secured against the Company’s production assets in Ghana and Equatorial Guinea. The Company’s assets in the US Gulf of Mexico and Mauritania and Senegal remain unencumbered.

The Company generated net cash provided by operating activities of approximately $273 million and free cash flow(1) of approximately $(42) million in the first quarter.

OPERATIONAL UPDATE

Production

Total net production(2) in the first quarter of 2024 averaged approximately 66,700 boepd, in line with guidance, representing a ~13% increase compared to the first quarter of 2023. This growth largely reflects higher production in Ghana arising from the start-up of the Jubilee South East project and the ongoing infill drilling campaign. The Company exited the quarter in a net underlift position of approximately 0.2 million barrels.

Ghana

Production in Ghana averaged approximately 43,800 boepd net in the first quarter of 2024. Kosmos lifted three cargos from Ghana during the quarter, in line with guidance.

At Jubilee (38.6% working interest), oil production in the first quarter averaged approximately 92,900 bopd gross with one water injector well brought on in January and two producer wells brought online in February. In the second quarter, one new producer well was brought online in April with one additional water injector well expected online by quarter end.

Following the completion of the additional water injector well, the planned drilling campaign will conclude approximately six months ahead of schedule as a result of efficiencies in the drilling operations.

Jubilee FPSO reliability continues to remain high at approximately 99% uptime for the first quarter. Voidage replacement for the first quarter was ~110% as a result of the elevated levels of water and gas injection.

In the first quarter, Jubilee gas production net to Kosmos was approximately 6,100 boepd. The interim gas sales agreement that is currently in place for Jubilee associated gas was extended for 18 months at a price of ~$3/mmbtu. In the second quarter, the onshore gas plant that receives Jubilee gas is expected to be offline for approximately two weeks for planned routine maintenance, with the impact included in second quarter guidance.

At TEN (20.4% working interest), production averaged approximately 18,600 bopd gross for the first quarter, in line with expectations. TEN FPSO reliability was consistent with Jubilee at approximately 99% uptime for the first quarter.

U.S. Gulf of Mexico

Production in the U.S. Gulf of Mexico averaged approximately 14,500 boepd net (~81% oil) during the first quarter, in line with guidance.

The first two wells at the Winterfell project (25% working interest) are expected online shortly. A third well is expected online in the second half of 2024. Gross production from the first phase of the Winterfell project is expected to be around 20,000 boepd when the initial three wells are online. Total gross resource at Greater Winterfell is estimated to be up to 200 million boe.

The Company’s production enhancement activities for 2024 continue to make good progress with the Odd Job subsea pump project, which is planned to sustain long-term production from the field, expected online in mid-2024. At Kodiak, workover plans for the Kodiak 3 well have progressed with operations expected to commence in mid-2024. Year-end 2024 exit production from these enhancement activities is expected to be around 5,000 boepd net. The Tornado field is expected to be offline for most of the second quarter for the scheduled routine maintenance of the HP-1 floating production unit with the impact included in second quarter guidance.

The Tiberius ILX project, (50% working interest and operator) continues to progress as a phased development, with project sanction expected later this year. Certain long lead items are being secured to optimize the development timeline and project costs. During the first quarter, Kosmos acquired part of Equinor’s stake in the project to maintain an aligned partnership and now holds 50%, which is already included in the 2024 capital guidance. Around the time of project sanction, Kosmos plans to farm down to optimize its working interest to fit within the targeted 2025+ capital program. Estimated gross resource at Tiberius is approximately 100 million boe.

Equatorial Guinea

Production in Equatorial Guinea averaged approximately 24,400 bopd gross and 8,400 bopd net in the first quarter. Kosmos lifted one cargo from Equatorial Guinea during the quarter, in line with guidance.

The Ceiba Field and Okume Complex workover and infill drilling campaign commenced in the fourth quarter of 2023, completing one production well workover. However, as a result of previously communicated safety issues with the drilling rig, the operator terminated the rig contract in early February 2024.

The partnership has now secured the Noble Venturer rig to resume the drilling campaign following the conclusion of its previous program in Ghana. The rig is expected on location around mid-year 2024 to drill and complete two infill wells in Block G and the Akeng Deep ILX prospect in Block S. Year-end 2024 exit production from the new infill wells is expected to be around 3,000 bopd net. The Akeng Deep well result is expected around the end of the year.

Mauritania & Senegal

The Greater Tortue Ahmeyim liquefied natural gas (LNG) project continues to make good progress. The following milestones have been achieved:

Drilling: The operator has successfully drilled and completed all four wells with expected production capacity significantly higher than what is required for first gas.

Hub Terminal: Construction work is complete and Hub Terminal handed over to operations.

FLNG: The vessel arrived on location offshore Mauritania/Senegal during the first quarter of 2024 and is now moored to the Hub Terminal. The partnership is continuing to work with the vessel operator to accelerate commissioning work.

Subsea: The subsea workscope is progressing in line with expectations with the flowline installation now complete and final connection work ongoing.

FPSO: Inspection and repair of the vessel’s fairleads is complete with the vessel now en route to the project site with mooring work to commence thereafter. Hookup and commissioning of the FPSO remain on the critical path to first gas, expected in the third quarter of 2024 with first LNG expected in the fourth quarter of 2024.

The Greater Tortue Ahmeyim cargo optimization arbitration ruling is expected mid 2024.

In Senegal, on Yakaar-Teranga, Kosmos continues to work closely with Senegal’s national oil company (PETROSEN) on pre-FEED work that prioritizes cost-competitive gas for the rapidly growing economy, combined with an offshore LNG facility targeting exports into international LNG markets. Kosmos plans to farm down its working interest to approximately 25% – 33% while retaining operatorship of the project.

In Mauritania, the BirAllah license expired at the end of April 2024. Kosmos continues to work closely with Mauritania’s national oil company (SMH) and the Government of Mauritania to advance attractive gas opportunities in the country.

(1) A Non-GAAP measure, see attached reconciliation of non-GAAP measure.

(2) Production means net entitlement volumes. In Ghana and Equatorial Guinea, this means those volumes net to Kosmos’ working interest or participating interest and net of royalty or production sharing contract effect. In the U.S. Gulf of Mexico, this means those volumes net to Kosmos’ working interest and net of royalty.

Conference Call and Webcast Information

Kosmos will host a conference call and webcast to discuss first quarter 2024 financial and operating results today, May 7, 2024, at 10:00 a.m. Central time (11:00 a.m. Eastern time). The live webcast of the event can be accessed on the Investors page of Kosmos’ website at http://investors.kosmosenergy.com/investor-events. The dial-in telephone number for the call is +1-877-407-0784. Callers in the United Kingdom should call 0800 756 3429. Callers outside the United States should dial +1-201-689-8560. A replay of the webcast will be available on the Investors page of Kosmos’ website for approximately 90 days following the event.

About Kosmos Energy

Kosmos is a full-cycle, deepwater, independent oil and gas exploration and production company focused along the offshore Atlantic Margins. Our key assets include production offshore Ghana, Equatorial Guinea and the U.S. Gulf of Mexico, as well as world-class gas projects offshore Mauritania and Senegal. We also pursue a proven basin exploration program in Equatorial Guinea and the U.S. Gulf of Mexico. Kosmos is listed on the New York Stock Exchange and London Stock Exchange and is traded under the ticker symbol KOS. As an ethical and transparent company, Kosmos is committed to doing things the right way. The Company’s Business Principles articulate our commitment to transparency, ethics, human rights, safety and the environment. Read more about this commitment in the Kosmos Sustainability Report. For additional information, visit www.kosmosenergy.com.

Non-GAAP Financial Measures

EBITDAX, Adjusted net income (loss), Adjusted net income (loss) per share, free cash flow, and net debt are supplemental non-GAAP financial measures used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines EBITDAX as Net income (loss) plus (i) exploration expense, (ii) depletion, depreciation and amortization expense, (iii) equity based compensation expense, (iv) unrealized (gain) loss on commodity derivatives (realized losses are deducted and realized gains are added back), (v) (gain) loss on sale of oil and gas properties, (vi) interest (income) expense, (vii) income taxes, (viii) loss on extinguishment of debt, (ix) doubtful accounts expense and (x) similar other material items which management believes affect the comparability of operating results. The Company defines Adjusted net income (loss) as Net income (loss) adjusted for certain items that impact the comparability of results. The Company defines free cash flow as net cash provided by operating activities less Oil and gas assets, Other property, and certain other items that may affect the comparability of results and excludes non-recurring activity such as acquisitions, divestitures and National Oil Company (“NOC”) financing. NOC financing refers to the amounts funded by Kosmos under the Carry Advance Agreements that the Company has in place with the national oil companies of each of Mauritania and Senegal related to the financing of the respective national oil companies’ share of certain development costs at Greater Tortue Ahmeyim. The Company defines net debt as total long-term debt less cash and cash equivalents and total restricted cash.

We believe that EBITDAX, Adjusted net income (loss), Adjusted net income (loss) per share, free cash flow, Net debt and other similar measures are useful to investors because they are frequently used by securities analysts, investors and other interested parties in the evaluation of companies in the oil and gas sector and will provide investors with a useful tool for assessing the comparability between periods, among securities analysts, as well as company by company. EBITDAX, Adjusted net income (loss), Adjusted net income (loss) per share, free cash flow, and net debt as presented by us may not be comparable to similarly titled measures of other companies.

This release also contains certain forward-looking non-GAAP financial measures, including free cash flow. Due to the forward-looking nature of the aforementioned non-GAAP financial measures, management cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as future impairments and future changes in working capital. Accordingly, we are unable to present a quantitative reconciliation of such forward-looking non-GAAP financial measures to their most directly comparable forward-looking GAAP financial measures. Amounts excluded from these non-GAAP measures in future periods could be significant.

Forward-Looking Statements

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that Kosmos expects, believes or anticipates will or may occur in the future are forward-looking statements. Kosmos’ estimates and forward-looking statements are mainly based on its current expectations and estimates of future events and trends, which affect or may affect its businesses and operations. Although Kosmos believes that these estimates and forward-looking statements are based upon reasonable assumptions, they are subject to several risks and uncertainties and are made in light of information currently available to Kosmos. When used in this press release, the words “anticipate,” “believe,” “intend,” “expect,” “plan,” “will” or other similar words are intended to identify forward-looking statements. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of Kosmos, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. Further information on such assumptions, risks and uncertainties is available in Kosmos’ Securities and Exchange Commission (“SEC”) filings. Kosmos undertakes no obligation and does not intend to update or correct these forward-looking statements to reflect events or circumstances occurring after the date of this press release, except as required by applicable law. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this press release. All forward-looking statements are qualified in their entirety by this cautionary statement.

###

Kosmos Energy Ltd.

Consolidated Statements of Operations

(In thousands, except per share amounts, unaudited)

Three Months Ended

March 31,

2024

2023

Revenues and other income:

Oil and gas revenue

$

419,103

$

394,240

Other income, net

36

(373

)

Total revenues and other income

419,139

393,867

Costs and expenses:

Oil and gas production

93,618

83,936

Exploration expenses

12,060

12,000

General and administrative

28,265

29,167

Depletion, depreciation and amortization

100,928

109,374

Interest and other financing costs, net

16,448

24,568

Derivatives, net

23,822

(6,840

)

Other expenses, net

2,029

2,030

Total costs and expenses

277,170

254,235

Income before income taxes

141,969

139,632

Income tax expense

50,283

56,323

Net income

$

91,686

$

83,309

Net income per share:

Basic

$

0.20

$

0.18

Diluted

$

0.19

$

0.17

Weighted average number of shares used to compute net income per share:

Basic

468,042

458,318

Diluted

482,096

479,326

Kosmos Energy Ltd.

Condensed Consolidated Balance Sheets

(In thousands, unaudited)

March 31,

December 31,

2024

2023

Assets

Current assets:

Cash and cash equivalents

$

254,323

$

95,345

Receivables, net

121,777

120,733

Other current assets

226,786

206,635

Total current assets

602,886

422,713

Property and equipment, net

4,389,404

4,160,229

Other non-current assets

357,841

355,192

Total assets

$

5,350,131

$

4,938,134

Liabilities and stockholders’ equity

Current liabilities:

Accounts payable

$

372,449

$

248,912

Accrued liabilities

278,891

302,815

Other current liabilities

14,073

3,103

Total current liabilities

665,413

554,830

Long-term liabilities:

Long-term debt, net

2,655,052

2,390,914

Deferred tax liabilities

358,377

363,918

Other non-current liabilities

599,654

596,135

Total long-term liabilities

3,613,083

3,350,967

Total stockholders’ equity

1,071,635

1,032,337

Total liabilities and stockholders’ equity

$

5,350,131

$

4,938,134

Kosmos Energy Ltd.

Condensed Consolidated Statements of Cash Flow

(In thousands, unaudited)

Three Months Ended

March 31,

2024

2023

Operating activities:

Net income

$

91,686

$

83,309

Adjustments to reconcile net income to net cash provided by operating activities:

Depletion, depreciation and amortization (including deferred financing costs)

103,327

111,925

Deferred income taxes

(7,316

)

(8,032

)

Unsuccessful well costs and leasehold impairments

466

1,304

Change in fair value of derivatives

27,010

(2,338

)

Cash settlements on derivatives, net(1)

(6,194

)

(11,357

)

Equity-based compensation

7,328

10,093

Other

(5,708

)

(2,273

)

Changes in assets and liabilities:

Net changes in working capital

61,964

21,222

Net cash provided by operating activities

272,563

203,853

Investing activities

Oil and gas assets

(314,822

)

(223,685

)

Notes receivable from partners

(2,528

)

(15,671

)

Net cash used in investing activities

(317,350

)

(239,356

)

Financing activities:

Borrowings under long-term debt

175,000

–

Payments on long-term debt

(300,000

)

(7,500

)

Net proceeds from issuance of senior notes

390,430

–

Purchase of capped call transactions

(49,800

)

–

Dividends

–

(165

)

Other financing costs

(11,691

)

(11,810

)

Net cash provided by (used in) financing activities

203,939

(19,475

)

Net increase (decrease) in cash, cash equivalents and restricted cash

159,152

(54,978

)

Cash, cash equivalents and restricted cash at beginning of period

98,761

186,821

Cash, cash equivalents and restricted cash at end of period

$

257,913

$

131,843

(1)

Cash settlements on commodity hedges were $(2.9) million and $(4.2) million for the three months ended March 31, 2024 and 2023, respectively.

Kosmos Energy Ltd.

EBITDAX

(In thousands, unaudited)

Three Months Ended

Twelve Months Ended

March 31, 2024

March 31, 2023

March 31, 2024

Net income

$

91,686

$

83,309

$

221,897

Exploration expenses

12,060

12,000

42,338

Depletion, depreciation and amortization

100,928

109,374

436,481

Impairment of long-lived assets

–

–

222,278

Equity-based compensation

7,328

10,093

39,928

Derivatives, net

23,822

(6,840

)

41,790

Cash settlements on commodity derivatives

(2,934

)

(4,182

)

(15,200

)

Other expenses, net(1)

2,029

2,030

23,655

Interest and other financing costs, net

16,448

24,568

87,784

Income tax expense

50,283

56,323

152,175

EBITDAX

$

301,650

$

286,675

$

1,253,126

(1)

Commencing in the first quarter of 2023, the Company combined the lines for “Restructuring and other” and “Other, net” in its presentation of EBITDAX into a single line titled “Other expenses, net.”

The following table presents our net debt as of March 31, 2024 and December 31, 2023:

March 31,

December 31,

2024

2023

Total long-term debt

$

2,700,000

$

2,425,000

Cash and cash equivalents

254,323

95,345

Total restricted cash

3,590

3,416

Net debt

$

2,442,087

$

2,326,239

Kosmos Energy Ltd.

Adjusted Net Income (Loss)

(In thousands, except per share amounts, unaudited)

Three Months Ended

March 31,

2024

2023

Net income

$

91,686

$

83,309

Derivatives, net

23,822

(6,840

)

Cash settlements on commodity derivatives

(2,934

)

(4,182

)

Other, net(2)

1,797

1,899

Total selected items before tax

22,685

(9,123

)

Income tax (expense) benefit on adjustments(1)

(7,311

)

3,508

Impact of valuation adjustments and other tax items

(7,963

)

–

Adjusted net income (loss)

$

99,097

77,694

Net income per diluted share

$

0.19

$

0.17

Derivatives, net

0.05

(0.01

)

Cash settlements on commodity derivatives

(0.01

)

(0.01

)

Total selected items before tax

0.04

(0.02

)

Income tax (expense) benefit on adjustments(1)

(0.01

)

0.01

Impact of valuation adjustments and other tax items

(0.01

)

–

Adjusted net income (loss) per diluted share

$

0.21

$

0.16

Weighted average number of diluted shares

482,096

479,326

(1)

Income tax expense is calculated at the statutory rate in which such item(s) reside. Statutory rates for the U.S. and Ghana/Equatorial Guinea are 21% and 35%, respectively.

(2)

Commencing in the first quarter of 2023, the Company combined the lines for “Restructuring and other” and “Other, net” in its presentation of Adjusted net income into a single line titled “Other, net.”

Kosmos Energy Ltd.

Free Cash Flow

(In thousands, unaudited)

Three Months Ended

March 31,

2024

2023

Reconciliation of free cash flow:

Net cash provided by operating activities

$

272,563

$

203,853

Net cash used for oil and gas assets – base business

(156,131

)

(97,174

)

Base business free cash flow

116,432

106,679

Net cash used for oil and gas assets – Mauritania/Senegal

(158,691

)

(126,511

)

Free cash flow

$

(42,259

)

$

(19,832

)

Kosmos Energy Ltd.

Operational Summary

(In thousands, except barrel and per barrel data, unaudited)

Three Months Ended

March 31,

2024

2023

Net Volume Sold

Oil (MMBbl)

4.890

4.945

Gas (MMcf)

4.336

2.761

NGL (MMBbl)

0.088

0.096

Total (MMBoe)

5.701

5.501

Total (Mboepd)

62.645

61.124

Revenue

Oil sales

$

402,117

$

388,099

Gas sales

15,138

3,866

NGL sales

1,848

2,275

Total oil and gas revenue

419,103

394,240

Cash settlements on commodity derivatives

(2,934

)

(4,182

)

Realized revenue

$

416,169

$

390,058

Oil and Gas Production Costs

$

93,618

$

83,936

Sales per Bbl/Mcf/Boe

Average oil sales price per Bbl

$

82.23

$

78.48

Average gas sales price per Mcf

3.49

1.40

Average NGL sales price per Bbl

21.00

23.70

Average total sales price per Boe

73.52

71.67

Cash settlements on commodity derivatives per Boe

(0.51

)

(0.76

)

Realized revenue per Boe

73.00

70.90

Oil and gas production costs per Boe

$

16.42

$

15.26

(1)

Cash settlements on commodity derivatives are only related to Kosmos and are calculated on a per barrel basis using Kosmos’ Net Oil Volumes Sold.

Kosmos was underlifted by approximately 0.2 million barrels as of March 31 2024.

Kosmos Energy Ltd.

Hedging Summary

As of March 31, 2024(1)

(Unaudited)

Weighted Average Price per Bbl

Index

MBbl

Floor(2)

Sold Put

Ceiling

2024:

Three-way collars

Dated Brent

3,000

$

70.00

$

45.00

$

96.25

Three-way collars

Dated Brent

2,000

70.00

45.00

90.00

Two-way collars

Dated Brent

1,000

65.00

–

85.00

Two-way collars

Dated Brent

1,500

70.00

–

100.00

(1)

Please see the Company’s filed 10-Q for additional disclosure on hedging material. Includes hedging position as of March 31, 2024 and hedges put in place through filing date.

(2)

“Floor” represents floor price for collars and strike price for purchased puts.

2024 Guidance

2Q 2024

FY 2024 Guidance

Production(1,2)

62,000 – 66,000 boe per day

71,000 – 77,000 boe per day

Opex(3)

$23 – $25 per boe

~$15 – $17 per boe

DD&A

$14.50 – $16.50 per boe

$18 – $20 per boe

G&A(~60% cash)

$25 – $30 million

$100 – $120 million

Exploration Expense(4)

$10 – $15 million

$40 – $60 million

Net Interest Expense(5,6)

$35 – $40 million

~$140 million

Tax

$10 – $12 per boe

$10 – $12 per boe

Capital Expenditure

$225 – $275 million

$700 – $750 million

Note: Ghana / Equatorial Guinea revenue calculated by number of cargos.

(1)

2Q 2024 cargo forecast – Ghana: 4 cargos / Equatorial Guinea 0.5 cargo. FY 2024 Ghana: 15 cargos / Equatorial Guinea 3 cargos. Average cargo sizes 950,000 barrels of oil.

(2)

U.S. Gulf of Mexico Production: 2Q 2024 forecast 12,500-13,500 boe per day. FY2024: 15,500-17,000 boe per day. Oil/Gas/NGL split for 2024: ~82%/~12%/~6%.

(3)

FY24 opex excludes operating costs associated with Greater Tortue Ahmeyim, which are expected to total approximately $115-130 million ($15 million in 2Q24)

(4)

Excludes leasehold impairments and dry hole costs

(5)

Includes impact of capitalized interest in 1H24 relating to Greater Tortue Ahmeyim development expenditure until first gas; 2H24 interest expense expected to be ~$45 million / quarter

(6)

Includes one-off loss on extinguishment of debt of approximately $22 million in the second quarter 2024 associated with the amendment and restatement of the RBL

Source: Rbcrichardsonbarr.com

Take the Survey at https://survey.energynewsbeat.com/

1031 Exchange E-Book

ENB Top News 
ENB
Energy Dashboard
ENB Podcast
ENB Substack

The post Kosmos Energy Announces First Quarter 2024 Results appeared first on Energy News Beat.

 

Energy News Beat

HOUSTON, May 07 /BusinessWire/ — Magnolia Oil & Gas Corporation (“Magnolia,” “we,” “our,” or the “Company”) (NYSE:MGY) today announced its financial and operational results for the first quarter of 2024.

First Quarter 2024 Highlights:

(In millions, except per share data)

For the

Quarter Ended

March 31, 2024

For the

Quarter Ended

March 31, 2023

Percentage increase

(decrease)

Net income

$

97.6

$

106.7

(9

)%

Adjusted net income(1)

$

101.0

$

119.3

(15

)%

Earnings per share – diluted

$

0.46

$

0.50

(8

)%

Adjusted EBITDAX(1)

$

227.8

$

216.9

5

%

Capital expenditures – D&C

$

119.0

$

139.7

(15

)%

Average daily production (Mboe/d)

84.8

79.3

7

%

Cash balance as of period end

$

399.3

$

667.3

(40

)%

Diluted weighted average total shares outstanding(2)

204.3

213.9

(5

)%

First Quarter 2024 Highlights:

Magnolia reported first quarter 2024 net income attributable to Class A Common Stock of $85.1 million, or $0.46 per diluted share. First quarter 2024 total net income was $97.6 million and total adjusted net income(1) was $101.0 million. Diluted weighted average total shares outstanding decreased by 5% to 204.3 million(2) compared to first quarter 2023.

Adjusted EBITDAX(1) was $227.8 million during the first quarter of 2024. Total drilling and completions (“D&C”) capital was $119.0 million and below our earlier guidance. First quarter D&C capital represented approximately 52% of adjusted EBITDAX and was 15% lower than the prior-year’s first quarter.

Net cash provided by operating activities was $210.9 million during the first quarter of 2024 and the Company generated free cash flow(1) of $117.1 million. Magnolia generated adjusted operating income(1) as a percentage of revenue of 39% during the quarter.

The Company has embarked on a field-level optimization and cost reduction program across our assets that is expected to deliver a 5 to 10% reduction in cash operating costs (LOE) per boe during the second half of the year compared to the first quarter 2024.

Total production in the first quarter of 2024 grew 7% on a year-over-year basis to 84.8 thousand barrels of oil equivalent per day (“Mboe/d”) including 37.5 thousand barrels per day of oil. Production at Giddings and Other was 61.4 Mboe/d, providing overall growth of 17% compared to last year’s first quarter, including oil production growth of 16%.

On April 30, 2024, Magnolia acquired oil and gas properties in Giddings from a private operator encompassing roughly 27,000 net acres for approximately $125 million. These assets included total production of approximately 1,000 Mboe/d (~35% oil), in addition to leasehold and royalty acres. The acquisition significantly increases Magnolia’s working interest in future high-return development areas and adds new acreage which further expands the Company’s leading position in the Giddings area.

The Company repurchased 2.4 million of its Class A Common Stock during the first quarter for $52.4 million. Magnolia has 6.9 million Class A Common shares remaining under its current repurchase authorization, which are specifically allocated toward open market share repurchases.

As previously announced, the Board of Directors declared a cash dividend of $0.13 per share of Class A common stock, and a cash distribution of $0.13 per Class B unit, payable on June 3, 2024 to shareholders of record as of May 13, 2024.

Magnolia returned $79.2 million(3), or 68% of the Company’s free cash flow(1), to shareholders during the first quarter through a combination of share repurchases and dividends while ending the period with $399.3 million of cash on the balance sheet. The Company remains undrawn on its $450.0 million revolving credit facility, has no debt maturities until 2026 and does not currently plan to increase its bonded indebtedness.

(1)

Adjusted net income, adjusted EBITDAX, free cash flow, and adjusted operating income are non-GAAP financial measures. For reconciliations to the most comparable GAAP measures, please see “Non-GAAP Financial Measures” at the end of this press release.

(2)

Weighted average total shares outstanding include diluted weighted average shares of Class A Common Stock outstanding during the period and shares of Class B Common Stock, which are anti-dilutive in the calculation of weighted average number of common shares outstanding.

(3)

Includes $2.9 million of share repurchases incurred during the first quarter, but settled during the second quarter of 2024, and excludes $1.7 million of share repurchases incurred during the fourth quarter of 2023, but settled during the first quarter of 2024.

“Magnolia’s first quarter performance delivered a solid start to 2024, continuing our strategy of disciplined capital spending, while delivering steady production growth with strong pre-tax margins and consistent free cash flow,” said President and CEO Chris Stavros. “Our growing production and continued low reinvestment rate provided free cash flow generation of roughly $117 million. We returned 68 percent of our free cash flow to our shareholders through our recently increased dividend and share repurchase program. Higher oil production of 37.5 thousand barrels per day during the quarter was driven by strong well performance and additional volumes from assets acquired last year.

“A key objective of Magnolia’s business plan and strategy is to utilize some of the excess cash generated by the business to pursue attractive bolt-on oil and gas property acquisitions. Properties are targeted not to simply replace the oil and gas that has already been produced but importantly, to improve the future opportunity set of our overall business and enhance the sustainability of our high returns. The latest example is an acquisition from a private operator that we closed at the end of April for $125 million which includes approximately 27,000 net acres in Giddings and leverages the significant knowledge we have gained through operating in the field. While these properties come with a relatively small amount of current production, they have similar attractive operational characteristics to our core acreage position in Giddings. The acquisition further lengthens our already deep inventory of high return locations in Giddings while adding duration to our overall portfolio as well as significantly increasing our working interest in some of our existing inventory. We continue to look for bolt-on oil and gas property acquisitions utilizing our technical expertise and where we have a competitive advantage in the development of the Austin Chalk and Eagle Ford formations in South Texas.

“While I am proud of our teams’ accomplishments, we continue to seek out areas where we can improve. Our field operations team recently initiated a field-level optimization and cost reduction program throughout our assets. Part of these efforts will employ improved field management systems that will increase efficiencies and optimize processes across the field while capturing synergies from acquired assets. These and other initiatives are expected to deliver a 5 to 10 percent reduction in cash operating costs (LOE) per boe during the second half of the year compared to the first quarter. Our goal is to improve on our track record for generating high operating margins while providing additional free cash flow to either return to our shareholders or reinvest in the business.”

Operational Update

First quarter 2024 total company production volumes averaged 84.8 Mboe/d including oil production of 37.5 Mbbls/d. Production from Giddings and Other increased by 17% compared to last year’s first quarter to 61.4 Mboe/d with oil production growing 15% over the same period. Total Company production volumes benefited from continued strong well performance, in addition to some production from assets acquired last year, as well as a slightly oilier development program. First quarter 2024 capital spending on drilling, completions, and associated facilities was $119.0 million.

Magnolia continues to operate two drilling rigs and one completion crew and expects to maintain this level of activity throughout the year. While this activity level is similar to the 2023 operating plan, lower well costs combined with improved operating efficiencies allow for more wells to be drilled, completed and turned in line during 2024 and help to support Magnolia’s overall high-margin growth. Most of this year’s development activity will consist of multi-well development pads in the Giddings area, with a proportionally smaller amount of development planned in the Karnes area, in addition to some appraisal wells on our assets. For Giddings development activity in 2024, we currently expect to drill multi-well pads with somewhat longer lateral lengths of approximately 8,500 feet as compared to last year.

On April 30, 2024, Magnolia acquired approximately 27,000 net acres in Giddings for approximately $125 million. These oil and gas properties include both leasehold and royalty interests, as well as approximately 1,000 Mboe/d of total production (~35% oil and ~68% liquids). The acquisition covers over 80,000 gross acres, a portion of which Magnolia currently operates. The incremental acreage offers both new operated development locations in addition to increasing the working interest in many existing high-return development locations.

Additional Guidance

We are reiterating the Company’s full-year 2024 capital spending and production guidance, with D&C capital expected to be in the range of $450 to $480 million. We estimate this should deliver high single digit total production growth during this year as compared to 2023, and with oil production growing at a similar rate. We expect second quarter D&C capital expenditures to be between $120 to $125 million and total production for the second quarter to be approximately 89 Mboe/d.

Magnolia plans to apply the Company’s operating expertise to its newly acquired assets which should lead to improved field operations and efficiencies allowing for lower unit operating costs that we expect to be reflected in the second half of 2024. Our lengthy experience and knowledge acquired while operating in the Giddings area gives us confidence that these initiatives should lead to higher margins on these assets and increased free cash flow for the Company.

Oil price differentials are anticipated to be approximately a $3.00 per barrel discount to Magellan East Houston and Magnolia remains completely unhedged for all its oil and natural gas production. The fully diluted share count for the second quarter of 2024 is expected to be approximately 203 million shares, which is approximately 4% lower than second quarter 2023 levels.

Quarterly Report on Form 10-Q

Magnolia’s financial statements and related footnotes will be available in its Quarterly Report on Form 10-Q for the three months ended March 31, 2024, which is expected to be filed with the U.S. Securities and Exchange Commission (“SEC”) on May 8, 2024.

Conference Call and Webcast

Magnolia will host an investor conference call on Wednesday, May 8, 2024 at 10:00 a.m. Central (11:00 a.m. Eastern) to discuss these operating and financial results. Interested parties may join the webcast by visiting Magnolia’s website at www.magnoliaoilgas.com/investors/events-and-presentations and clicking on the webcast link or by dialing 1-844-701-1059. A replay of the webcast will be posted on Magnolia’s website following completion of the call.

About Magnolia Oil & Gas Corporation

Magnolia (MGY) is a publicly traded oil and gas exploration and production company with operations primarily in South Texas in the core of the Eagle Ford Shale and Austin Chalk formations. Magnolia focuses on generating value for shareholders by delivering steady, moderate annual production growth resulting from its disciplined and efficient philosophy toward capital spending. The Company strives to generate high pre-tax margins and consistent free cash flow allowing for strong cash returns to our shareholders. For more information, visit www.magnoliaoilgas.com.

Cautionary Note Regarding Forward-Looking Statements

The information in this press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of present or historical fact included in this press release, regarding Magnolia’s strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward looking statements. When used in this press release, the words could, should, will, may, believe, anticipate, intend, estimate, expect, project, the negative of such terms and other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events. Except as otherwise required by applicable law, Magnolia disclaims any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this press release. Magnolia cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the control of Magnolia, incident to the development, production, gathering and sale of oil, natural gas and natural gas liquids. In addition, Magnolia cautions you that the forward looking statements contained in this press release are subject to the following factors: (i) the supply and demand for oil, natural gas, NGLs, and other products or services, including impacts of actions taken by OPEC and other state-controlled oil companies; (ii) the outcome of any legal proceedings that may be instituted against Magnolia; (iii) Magnolia’s ability to realize the anticipated benefits of its acquisitions, which may be affected by, among other things, competition and the ability of Magnolia to grow and manage growth profitably; (iv) changes in applicable laws or regulations; (v) geopolitical and business conditions in key regions of the world; and (vi) the possibility that Magnolia may be adversely affected by other economic, business, and/or competitive factors, including inflation. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, actual results and plans could differ materially from those expressed in any forward-looking statements. Additional information concerning these and other factors that may impact the operations and projections discussed herein can be found in Magnolia’s filings with the SEC, including its Annual Report on Form 10-K for the fiscal year ended December 31, 2023. Magnolia’s SEC filings are available publicly on the SEC’s website at www.sec.gov.

Magnolia Oil & Gas Corporation

Operating Highlights

For the Quarters Ended

March 31, 2024

March 31, 2023

Production:

Oil (MBbls)

3,415

3,221

Natural gas (MMcf)

13,749

12,650

Natural gas liquids (MBbls)

2,009

1,812

Total (Mboe)

7,715

7,141

Average daily production:

Oil (Bbls/d)

37,531

35,788

Natural gas (Mcf/d)

151,086

140,552

Natural gas liquids (Bbls/d)

22,072

20,129

Total (boe/d)

84,784

79,342

Revenues (in thousands):

Oil revenues

$

259,182

$

239,122

Natural gas revenues

21,095

27,771

Natural gas liquids revenues

39,140

41,489

Total Revenues

$

319,417

$

308,382

Average sales price:

Oil (per Bbl)

$

75.89

$

74.24

Natural gas (per Mcf)

1.53

2.20

Natural gas liquids (per Bbl)

19.49

22.90

Total (per boe)

$

41.40

$

43.18

NYMEX WTI (per Bbl)

$

76.97

$

76.11

NYMEX Henry Hub (per MMBtu)

$

2.24

$

3.45

Realization to benchmark:

Oil (% of WTI)

99

%

98

%

Natural Gas (% of Henry Hub)

68

%

64

%

Operating expenses (in thousands):

Lease operating expenses

$

46,150

$

42,371

Gathering, transportation and processing

8,537

12,732

Taxes other than income

17,898

19,292

Depreciation, depletion and amortization

97,076

70,701

Operating costs per boe:

Lease operating expenses

$

5.98

$

5.93

Gathering, transportation and processing

1.11

1.78

Taxes other than income

2.32

2.70

Depreciation, depletion and amortization

12.58

9.90

Magnolia Oil & Gas Corporation

Consolidated Statements of Operations

(In thousands, except per share data)

For the Quarters Ended

March 31, 2024

March 31, 2023

REVENUES

Oil revenues

$

259,182

$

239,122

Natural gas revenues

21,095

27,771

Natural gas liquids revenues

39,140

41,489

Total revenues

319,417

308,382

OPERATING EXPENSES

Lease operating expenses

46,150

42,371

Gathering, transportation and processing

8,537

12,732

Taxes other than income

17,898

19,292

Exploration expenses

25

11

Asset retirement obligations accretion

1,618

841

Depreciation, depletion and amortization

97,076

70,701

Impairment of oil and natural gas properties

–

15,735

General and administrative expenses

23,555

19,766

Total operating expenses

194,859

181,449

OPERATING INCOME

124,558

126,933

OTHER INCOME (EXPENSE)

Interest income (expense), net

(2,312

)

487

Other expense, net

(4,313

)

(1,138

)

Total other expense, net

(6,625

)

(651

)

INCOME BEFORE INCOME TAXES

117,933

126,282

Current income tax expense

11,628

4,202

Deferred income tax expense

8,708

15,403

Total income tax expense

20,336

19,605

NET INCOME

97,597

106,677

LESS: Net income attributable to noncontrolling interest

12,511

10,342

NET INCOME ATTRIBUTABLE TO CLASS A COMMON STOCK

$

85,086

$

96,335

NET INCOME PER COMMON SHARE

Basic

$

0.46

$

0.50

Diluted

$

0.46

$

0.50

WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING

Basic

182,368

191,780

Diluted

182,424

192,054

WEIGHTED AVERAGE NUMBER OF CLASS B SHARES OUTSTANDING (1)

21,827

21,827

DILUTED WEIGHTED AVERAGE TOTAL SHARES OUTSTANDING (1)

204,251

213,881

(1)

Shares of Class B Common Stock, and corresponding Magnolia LLC Units, are anti-dilutive in the calculation of weighted average number of common shares outstanding.

Magnolia Oil & Gas Corporation

Summary Cash Flow Data

(In thousands)

For the Quarters Ended

March 31, 2024

March 31, 2023

CASH FLOWS FROM OPERATING ACTIVITIES

NET INCOME

$

97,597

$

106,677

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation, depletion and amortization

97,076

70,701

Exploration expenses, non-cash

1

5

Impairment of oil and natural gas properties

–

15,735

Asset retirement obligations accretion

1,618

841

Amortization of deferred financing costs

1,089

1,042

Deferred income tax expense

8,708

15,403

Loss on revaluation of contingent consideration

4,205

–

Stock based compensation

4,658

3,772

Other

2,921

–

Net change in operating assets and liabilities

(6,941

)

5,647

Net cash provided by operating activities

210,932

219,823

CASH FLOWS FROM INVESTING ACTIVITIES

Acquisitions

(13,359

)

3,691

Deposits for acquisitions of oil and natural gas properties (1)

(13,150

)

–

Additions to oil and natural gas properties

(120,986

)

(138,645

)

Changes in working capital associated with additions to oil and natural gas properties

20,244

(14,977

)

Other investing

(57

)

(284

)

Net cash used in investing activities

(127,308

)

(150,215

)

CASH FLOW FROM FINANCING ACTIVITIES

Class A Common Stock repurchases

(51,201

)

(45,844

)

Dividends paid

(24,010

)

(22,578

)

Distributions to noncontrolling interest owners

(2,837

)

(2,510

)

Other financing activities

(7,380

)

(6,833

)

Net cash used in financing activities

(85,428

)

(77,765

)

NET CHANGE IN CASH AND CASH EQUIVALENTS

(1,804

)

(8,157

)

Cash and cash equivalents – Beginning of period

401,121

675,441

Cash and cash equivalents – End of period

$

399,317

$

667,284

(1)

Associated with the acquisitions of certain oil and gas producing properties including leasehold and mineral interests in the Giddings area, that closed in the second quarter of 2024.

Magnolia Oil & Gas Corporation

Summary Balance Sheet Data

(In thousands)

March 31, 2024

December 31, 2023

Cash and cash equivalents

$

399,317

$

401,121

Other current assets

198,218

190,152

Property, plant and equipment, net

2,093,942

2,052,021

Other assets

116,465

112,922

Total assets

$

2,807,942

$

2,756,216

Current liabilities

$

350,011

$

314,887

Long-term debt, net

393,480

392,839

Other long-term liabilities

166,667

165,822

Common stock

24

23

Additional paid in capital

1,745,157

1,743,930

Treasury stock

(591,175

)

(538,445

)

Retained earnings

547,261

486,162

Noncontrolling interest

196,517

190,998

Total liabilities and equity

$

2,807,942

$

2,756,216

Magnolia Oil & Gas Corporation

Non-GAAP Financial Measures

Reconciliation of net income to adjusted EBITDAX

In this press release, we refer to adjusted EBITDAX, a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders, and rating agencies. We define adjusted EBITDAX as net income before interest (income) expense, income taxes, depreciation, depletion and amortization, exploration expenses, and accretion of asset retirement obligations, adjusted to exclude the effect of certain items included in net income. Adjusted EBITDAX is not a measure of net income in accordance with GAAP.

Our management believes that adjusted EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We also believe that securities analysts, investors, and other interested parties may use adjusted EBITDAX in the evaluation of our Company. We exclude the items listed above from net income in arriving at adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of adjusted EBITDAX. Our presentation of adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.

The following table presents a reconciliation of net income to adjusted EBITDAX, our most directly comparable financial measure, calculated and presented in accordance with GAAP:

For the Quarters Ended

(In thousands)

March 31, 2024

March 31, 2023

NET INCOME

$

97,597

$

106,677

Interest (income) expense, net

2,312

(487

)

Income tax expense

20,336

19,605

EBIT

120,245

125,795

Depreciation, depletion and amortization

97,076

70,701

Asset retirement obligations accretion

1,618

841

EBITDA

218,939

197,337

Exploration expenses

25

11

EBITDAX

218,964

197,348

Impairment of oil and natural gas properties

–

15,735

Non-cash stock based compensation expense

4,658

3,772

Loss on revaluation of contingent consideration

4,205

–

Adjusted EBITDAX

$

227,827

$

216,855

Magnolia Oil & Gas Corporation

Non-GAAP Financial Measures

Reconciliation of net income to adjusted net income

Our presentation of adjusted net income is a non-GAAP measures because it excludes the effect of certain items included in net income. Management uses adjusted net income to evaluate our operating and financial performance because it eliminates the impact of certain items that management does not consider to be representative of the Company’s on-going business operations. As a performance measure, adjusted net income may be useful to investors in facilitating comparisons to others in the Company’s industry because certain items can vary substantially in the oil and gas industry from company to company depending upon accounting methods, book value of assets, and capital structure, among other factors. Management believes adjusting these items facilitates investors and analysts in evaluating and comparing the underlying operating and financial performance of our business from period to period by eliminating differences caused by the existence and timing of certain expense and income items that would not otherwise be apparent on a GAAP basis. However, our presentation of adjusted net income may not be comparable to similar measures of other companies in our industry.

For the Quarters Ended

(In thousands)

March 31, 2024

March 31, 2023

NET INCOME

$

97,597

$

106,677

Adjustments:

Loss on revaluation of contingent consideration

4,205

–

Impairment of oil and natural gas properties

–

15,735

Change in estimated income tax (1)

(795

)

(3,089

)

ADJUSTED NET INCOME

$

101,007

$

119,323

Diluted weighted average shares of Class A Common Stock outstanding during the period

182,424

192,054

Weighted average shares of Class B Common Stock outstanding during the period (2)

21,827

21,827

Total weighted average shares of Class A and B Common Stock, including dilutive impact of other securities (2)

204,251

213,881

(1)

Represents corporate income taxes at an assumed annual effective tax rate of 18.9% and 19.6% for the quarters ended March 31, 2024 and 2023, respectively.

(2)

Shares of Class B Common Stock, and corresponding Magnolia LLC Units, are anti-dilutive in the calculation of weighted average number of common shares outstanding.

Magnolia Oil & Gas Corporation

Non-GAAP Financial Measures

Reconciliation of revenue to adjusted cash operating margin and operating income margin

Our presentation of adjusted cash operating margin and total adjusted cash operating costs are supplemental non-GAAP financial measures that are used by management. Total adjusted cash operating costs exclude the impact of non-cash activity. We define adjusted cash operating margin per boe as total revenues per boe less cash operating costs per boe. Management believes that total adjusted cash operating costs per boe and adjusted cash operating margin per boe provide relevant and useful information, which is used by our management in assessing the Company’s profitability and comparability of results to our peers.

As a performance measure, total adjusted cash operating costs and adjusted cash operating margin may be useful to investors in facilitating comparisons to others in the Company’s industry because certain items can vary substantially in the oil and gas industry from company to company depending upon accounting methods, book value of assets, and capital structure, among other factors. Management believes excluding these items facilitates investors and analysts in evaluating and comparing the underlying operating and financial performance of our business from period to period by eliminating differences caused by the existence and timing of certain expense and income items that would not otherwise be apparent on a GAAP basis. However, our presentation of adjusted cash operating margin may not be comparable to similar measures of other companies in our industry.

For the Quarters Ended

(in $/boe)

March 31, 2024

March 31, 2023

Revenue

$

41.40

$

43.18

Total cash operating costs:

Lease operating expenses (1)

(5.91

)

(5.87

)

Gathering, transportation and processing

(1.11

)

(1.78

)

Taxes other than income

(2.32

)

(2.70

)

Exploration expenses

–

–

General and administrative expenses (2)

(2.52

)

(2.30

)

Total adjusted cash operating costs

(11.86

)

(12.65

)

Adjusted cash operating margin

$

29.54

$

30.53

Margin (%)

71

%

71

%

Non-cash costs:

Depreciation, depletion and amortization

$

(12.58

)

$

(9.90

)

Impairment of oil and natural gas properties

–

(2.20

)

Asset retirement obligations accretion

(0.21

)

(0.12

)

Non-cash stock based compensation

(0.60

)

(0.53

)

Total non-cash costs

(13.39

)

(12.75

)

Operating income margin

$

16.15

$

17.78

Add back: Impairment of oil and natural gas properties

–

2.20

Adjusted operating income margin

$

16.15

$

19.98

Margin (%)

39

%

46

%

(1)

Lease operating expenses exclude non-cash stock based compensation of $0.6 million, or $0.07 per boe, and $0.4 million, or $0.06 per boe, for the quarters ended March 31, 2024 and 2023, respectively.

(2)

General and administrative expenses exclude non-cash stock based compensation of $4.1 million, or $0.53 per boe, and $3.4 million, or $0.47 per boe, for the quarters ended March 31, 2024 and 2023, respectively.

Magnolia Oil & Gas Corporation

Non-GAAP Financial Measures

Reconciliation of net cash provided by operating activities to free cash flow

Free cash flow is a non-GAAP financial measure. Free cash flow is defined as cash flows from operations before net change in operating assets and liabilities less additions to oil and natural gas properties and changes in working capital associated with additions to oil and natural gas properties. Management believes free cash flow is useful for investors and widely accepted by those following the oil and gas industry as financial indicators of a company’s ability to generate cash to internally fund drilling and completion activities, fund acquisitions, and service debt. It is also used by research analysts to value and compare oil and gas exploration and production companies and are frequently included in published research when providing investment recommendations. Free cash flow is used by management as an additional measure of liquidity. Free cash flow is not a measure of financial performance under GAAP and should not be considered an alternative to cash flows from operating, investing, or financing activities.

For the Quarters Ended

(In thousands)

March 31, 2024

March 31, 2023

Net cash provided by operating activities

$

210,932

$

219,823

Add back: net change in operating assets and liabilities

6,941

(5,647

)

Cash flows from operations before net change in operating assets and liabilities

217,873

214,176

Additions to oil and natural gas properties

(120,986

)

(138,645

)

Changes in working capital associated with additions to oil and natural gas properties

20,244

(14,977

)

Free cash flow

$

117,131

$

60,554

Source: Rbcrichardsonbarr.com

Take the Survey at https://survey.energynewsbeat.com/

1031 Exchange E-Book

ENB Top News 
ENB
Energy Dashboard
ENB Podcast
ENB Substack

The post Magnolia Oil & Gas Corporation Announces First Quarter 2024 Results appeared first on Energy News Beat.

 

Energy News Beat

The post European Oil Giants Consider Shifting Their Listings to the U.S. appeared first on Energy News Beat.

 

Energy News Beat

MIDLAND, Texas, May 07 /BusinessWire/ — Permian Resources Corporation (“Permian Resources” or the “Company”) (NYSE:PR) today announced its first quarter 2024 financial and operational results and revised 2024 guidance.

Recent Financial and Operational Highlights

Delivered Permian Resources’ best quarter to-date:

Production outperformance due to accelerated Earthstone efficiencies and continued strong well results
Robust free cash flow driven by operational execution and realization of cost synergies
Earthstone integration completed ahead of schedule
Earthstone annual synergy target increased by $50 million to $225 million
Executed ~$270 million of additional bolt-on acquisitions in core operating areas

Reported crude oil and total average production of 151.8 MBbls/d and 319.5 MBoe/d (~48% oil) during the quarter
Announced cash capital expenditures of $520 million, net cash provided by operating activities of $648 million and adjusted free cash flow1 of $324 million ($0.42 per adjusted basic share)
Reported total return of capital of $185 million, or $0.24 per share, implying a total annualized return yield of ~5.7%2:

Quarterly base dividend of $0.06 per share
Variable dividend of $0.14 per share
Repurchased 2.0 million shares for $31 million

Added ~11,200 net acres and ~110 locations in the Delaware Basin through recent transactions
Increased mid-point of full year oil and total production guidance by 2% to 150 MBbls/d and 320 MBoe/d

Management Commentary

“In our first full quarter post closing Earthstone, Permian Resources delivered strong operational and financial results, building upon our operational momentum from last year,” said Will Hickey, Co-CEO of Permian Resources. “Outstanding well results and higher operational efficiencies across both legacy Permian Resources and Earthstone assets drove robust production during the quarter. This outperformance provided us with the confidence to increase standalone production guidance and represents a solid start to the year.”

“This quarter’s strong results allowed us to generate $324 million of adjusted free cash flow, or $0.42 per share,” said James Walter, Co-CEO of Permian Resources. “Additionally, we continue to enhance our position through strategic leasehold and bolt-on acquisitions, adding high-quality inventory directly offset our most capital efficient asset that immediately competes for capital. We believe Permian Resources’ leading cost structure, basin knowledge and balance sheet strength will continue to drive attractive opportunities to grow our already deep inventory position in an accretive manner.”

Operational and Financial Results

Permian Resources continued the efficient development of its core Delaware Basin acreage position in the first quarter, delivering excellent well results while successfully integrating the Earthstone acquisition. During the quarter, average daily crude oil production was 151,794 barrels of oil per day (“Bbls/d”), an 11% increase compared to the prior quarter. First quarter total production averaged 319,514 barrels of oil equivalent per day (“Boe/d”). “Our strong first quarter production results were primarily driven by better than expected well performance, strong production runtimes and acceleration from continued operational efficiencies,” said Will Hickey, Co-CEO.

The Company was able to accelerate activity due to strong drilling and completion (“D&C”) synergy capture, driving increased D&C efficiencies program-wide. As of May 1, the Company is no longer utilizing any Earthstone drilling rigs or completion crews, and the Earthstone assets are fully integrated from a D&C perspective. Total cash capital expenditures (“capex”) for the first quarter was $520 million.

Realized prices for the quarter were $76.13 per barrel of oil, $1.24 per Mcf of natural gas and $26.47 per barrel of natural gas liquids (“NGLs”), excluding the effects of hedges and GP&T costs. First quarter total controllable cash costs (LOE, GP&T and cash G&A) were $8.11 per Boe. LOE was $5.80 per Boe, GP&T was $1.34 per Boe and Cash G&A was $0.97 per Boe.

For the first quarter, Permian Resources generated net cash provided by operating activities of $648 million, adjusted operating cash flow1 of $844 million ($1.09 per adjusted basic share) and adjusted free cash flow1 of $324 million ($0.42 per adjusted basic share).

Permian Resources continues to maintain a strong financial position and low leverage profile. At March 31, 2024, the Company had $13 million in cash on hand and $60 million drawn under its revolving credit facility. Net debt-to-LQA EBITDAX1 at March 31, 2024 was approximately 1x. Permian Resources recently completed its spring borrowing base redetermination process, whereby elected commitments increased to $2.5 billion from $2.0 billion, providing an additional $500 million of liquidity. The borrowing base remains unchanged at $4.0 billion. Also subsequent to quarter-end, the Company redeemed the $356 million aggregate principal amount of 6.875% Senior Notes due 2027.

Earthstone Integration Update

The integration of Earthstone is complete, and synergy capture is meaningfully ahead of schedule. Overall, the Company’s success in both the acceleration and magnitude of synergies captured to-date has resulted in an increase of $50 million to the previously stated annual synergy target of $175 million, bringing the updated synergy target to $225 million per year.

As a result of the successful integration and synergy realization, during the quarter the Company reduced average spud-to-rig release days by 18% per well and average completion days by 50% per well on legacy Earthstone acreage compared to Earthstone’s results from the first half of 2023. Additionally, Permian Resources has improved legacy Earthstone runtimes, benefiting overall production volumes, and realized approximately $1 per Boe of LOE and margin synergies through workover, compressor and midstream optimization initiatives.

“We are pleased to have achieved our original synergy target ahead of schedule and excited to increase our annual target to $225 million,” said James Walter, Co-CEO. “I’m incredibly proud of both legacy companies’ employees for ensuring such a smooth integration. Their hard work and dedication were key to such an efficient synergy capture.”

Recent Acquisitions

Permian Resources continues to strengthen its acreage position in the core of the Delaware Basin, announcing two bolt-on acquisitions and additional properties acquired through its ongoing grassroots program.

The Company recently executed two separate bolt-on transactions located in Eddy County, New Mexico from undisclosed third-parties. The acquired properties consist of predominantly undeveloped acreage offset Permian Resources’ highly capital efficient Parkway asset. Inventory on the acquired acreage comprises two-mile locations with high NRIs which immediately compete for capital. The Company closed upon the first transaction during the first quarter, and the second transaction is currently pending with closing expected to occur late in the second quarter.

“The acquired acreage is analogous to our high-quality Parkway position. This area represents one of the highest returning assets within our portfolio, with returns driven by reduced D&C costs and strong oil cuts. We are excited to begin development on the acquired acreage later this year,” said Will Hickey, Co-CEO.

Additionally, Permian Resources continues to be highly successful executing upon its ground game, consisting of smaller grassroots acquisitions and leasehold transactions. During the first quarter of 2024, the Company completed approximately 150 grassroots leasing and working interest acquisitions. The majority of these acquisitions are slated for near-term development, making them highly accretive.

Combined, the Company added approximately 11,200 net leasehold acres and 4,500 net royalty acres for total consideration of approximately $270 million, reflecting an acquisition value of approximately $9,500 per net leasehold acre and approximately $5,000 per net royalty acre after adjusting for production value. Permian Resources has identified approximately 110 gross operated locations on the acquired properties. In total, these acquisitions contributed less than 100 Boe/d of total production in the first quarter.

(The transactions referenced in this press release are additive to the Company’s Portfolio Optimization Transactions which were announced on January 30, 2024. For maps and further details summarizing Permian Resources’ recent transactions, please see the presentation materials on its website under the Investor Relations tab.)

2024 Operational Plan and Target Update

Based on recent operational results, Permian Resources increased its 2024 standalone oil and total production targets by approximately 2% to 148-152 MBbls/d and 310-330 MBoe/d, respectively, based on the mid-point of guidance. There are no other changes to the Company’s standalone guidance ranges.

The recent acquisitions noted above are expected to add approximately 3,500 Boe/d (~45% oil) of total production during the second half of 2024. The Company expects approximately $50 million of incremental capital expenditures associated with wells spud on the newly acquired acreage during the second half of 2024. Notably, the potential impact of the recently announced acquisitions is not included in the revised standalone guidance.

(For a detailed table summarizing Permian Resources’ revised 2024 standalone operational and financial guidance, please see the Appendix of this press release.)

Shareholder Returns

Permian Resources announced today that its Board of Directors (the “Board”) declared a quarterly base cash dividend of $0.06 per share of Class A common stock, or $0.24 per share on an annualized basis. This represents a 20% increase in the Company’s base cash dividend compared to the prior quarter. Additionally, based upon first quarter financial results, the Board has declared a quarterly variable cash dividend of $0.14 per share of Class A common stock. Combined, the base and variable dividends represent a total cash return of $0.20 per share. The base and variable dividends are payable on May 29, 2024 to shareholders of record as of May 21, 2024. Permian Resources returned additional capital to shareholders in the first quarter by repurchasing 2.0 million shares of common stock for $31 million. The Company’s first quarter total return of capital, inclusive of the base dividend, variable dividend and share repurchases, was $0.24 per share.

Quarterly Report on Form 10-Q

Permian Resources’ financial statements and related footnotes will be available in its Quarterly Report on Form 10-Q for the quarter ended March 31, 2024, which is expected to be filed with the Securities and Exchange Commission (“SEC”) on May 8, 2024.

Conference Call and Webcast

Permian Resources will host an investor conference call on Wednesday, May 8, 2024 at 9:00 a.m. Central (10:00 a.m. Eastern) to discuss first quarter 2024 operating and financial results. Interested parties may join the call by visiting Permian Resources’ website at www.permianres.com and clicking on the webcast link or by dialing (800) 225-9448 (Conference ID: PRCQ124) at least 15 minutes prior to the start of the call. A replay of the call will be available on the Company’s website or by phone at (800) 938-2488 (Passcode: 24995) for a 14-day period following the call.

About Permian Resources

Headquartered in Midland, Texas, Permian Resources is an independent oil and natural gas company focused on the responsible acquisition, optimization and development of high-return oil and natural gas properties. The Company’s assets and operations are concentrated in the core of the Delaware Basin, making it the second largest Permian Basin pure-play E&P. For more information, please visit www.permianres.com.

Cautionary Note Regarding Forward-Looking Statements

The information in this press release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact included in this press release, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this press release, the words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “goal,” “plan,” “target” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.

Forward-looking statements may include statements about:

volatility of oil, natural gas and NGL prices or a prolonged period of low oil, natural gas or NGL prices and the effects of actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries (“OPEC”), such as Saudi Arabia, and other oil and natural gas producing countries, such as Russia, with respect to production levels or other matters related to the price of oil, natural gas and NGLs;
political and economic conditions and events in or affecting other producing regions or countries, including the Middle East, Russia, Eastern Europe, Africa and South America;
our business strategy and future drilling plans;
our reserves and our ability to replace the reserves we produce through drilling and property acquisitions;
our drilling prospects, inventories, projects and programs;
our financial strategy, return of capital program, leverage, liquidity and capital required for our development program;
the timing and amount of our future production of oil, natural gas and NGLs;
our ability to identify, complete and effectively integrate acquisitions of properties, assets or businesses;
our ability to realize the anticipated benefits and synergies from the Earthstone merger and effectively integrate the assets acquired in such transaction;
our hedging strategy and results;
our competition;
our ability to obtain permits and governmental approvals;
our compliance with government regulations, including those related to climate change as well as environmental, health and safety regulations and liabilities thereunder;
our pending legal matters;
the marketing and transportation of our oil, natural gas and NGLs;
our leasehold or business acquisitions;
cost of developing or operating our properties;
our anticipated rate of return;
general economic conditions;
weather conditions in the areas where we operate;
credit markets;
our ability to make dividends, distributions and share repurchases;
uncertainty regarding our future operating results;
our plans, objectives, expectations and intentions contained in this press release that are not historical; and
the other factors described in our most recent Annual Report on Form 10-K, and any updates to those factors set forth in our subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of oil, natural gas and NGLs. Factors which could cause our actual results to differ materially from the results contemplated by forward-looking statements include, but are not limited to, commodity price volatility (including regional basis differentials), uncertainty inherent in estimating oil, natural gas and NGL reserves and in projecting future rates of production, geographic concentration of our operations, lack of availability of drilling and production equipment and services, lack of transportation and storage capacity as a result of oversupply, government regulations or other factors, risks relating to the Earthstone Merger, competition in the oil and natural gas industry for assets, materials, qualified personnel and capital, drilling and other operating risks, environmental and climate related risks, regulatory changes, restrictions on the use of water, availability to cash flow and access to capital, inflation, changes in our credit ratings or adverse changes in interest rates, changes in the financial strength of counterparties to our credit agreement and hedging contracts, the timing of development expenditures, political and economic conditions and events in foreign oil and natural gas producing countries, changes in local, regional, national, and international economic conditions, security threats and the other risks described in our filings with the SEC.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data, and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

Should one or more of the risks or uncertainties described in this press release occur, or should any underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this press release are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this press release.

1) Adjusted Operating Cash Flow, Adjusted Free Cash Flow and Net Debt-to-LQA EBITDAX are non-GAAP financial measures. See “Non-GAAP Financial Measures” included within the Appendix of this press release for related disclosures and reconciliations to the most directly comparable financial measures calculated and presented in accordance with GAAP.

2) Based on closing share price as of May 3, 2024.

Details of our revised 2024 operational and financial guidance are presented below:

2024 FY Guidance (Updated)

Net average daily production (Boe/d)

310,000

–

330,000

Net average daily oil production (Bbls/d)

148,000

–

152,000

Production costs

Lease operating expenses ($/Boe)

$5.50

–

$6.00

Gathering, processing and transportation expenses ($/Boe)

$1.00

–

$1.50

Cash general and administrative ($/Boe)(1)

$0.90

–

$1.10

Severance and ad valorem taxes (% of revenue)

6.5%

–

8.5%

Total cash capital expenditure program ($MM)

$1,900

–

$2,100

Operated drilling program

TILs (gross)

~250

Average working interest

~75%

Average lateral length (feet)

~9,300

(1)

Excludes stock-based compensation.

Permian Resources Corporation
Operating Highlights

Three Months Ended March 31,

2024

2023

Net revenues (in thousands):

Oil sales

$

1,051,642

$

524,386

Natural gas sales(1)

38,767

32,122

NGL sales(2)

152,590

59,760

Oil and gas sales

$

1,242,999

$

616,268

Average sales prices:

Oil (per Bbl)

$

76.13

$

74.38

Effect of derivative settlements on average price (per Bbl)

(0.12

)

3.65

Oil including the effects of hedging (per Bbl)

$

76.01

$

78.03

Average NYMEX WTI price for oil (per Bbl)

$

76.96

$

76.13

Oil differential from NYMEX

(0.83

)

(1.75

)

Natural gas price excluding the effects of GP&T (per Mcf)(1)

$

1.24

$

1.81

Effect of derivative settlements on average price (per Mcf)

0.17

0.58

Natural gas including the effects of hedging (per Mcf)

$

1.41

$

2.39

Average NYMEX Henry Hub price for natural gas (per MMBtu)

$

2.41

$

2.67

Natural gas differential from NYMEX

(1.17

)

(0.86

)

NGL price excluding the effects of GP&T (per Bbl)(2)

$

26.47

$

27.12

Net production:

Oil (MBbls)

13,813

7,050

Natural gas (MMcf)

51,802

23,974

NGL (MBbls)

6,629

2,798

Total (MBoe)(3)

29,076

13,844

Average daily net production:

Oil (Bbls/d)

151,794

78,332

Natural gas (Mcf/d)

569,249

266,374

NGL (Bbls/d)

72,846

31,094

Total (Boe/d)(3)

319,514

153,822

_______________________________________

(1)

Natural gas sales for the three months ended March 31, 2024 include $25.3 million of gathering, processing and transportation costs (“GP&T”) that are reflected as a reduction to natural gas sales and $11.3 million for the three months ended March 31, 2023. Natural gas average sales prices, however, exclude $0.49 per Mcf of such GP&T charges for the three months ended March 31, 2024 and $0.47 per Mcf for the three months ended March 31, 2023.

(2)

NGL sales for the three months ended March 31, 2024 include $22.9 million of GP&T that are reflected as a reduction to NGL sales and $16.1 million for the three months ended March 31, 2023. NGL average sales prices, however, exclude $3.45 per Bbl of such GP&T charges for the three months ended March 31, 2024 and $5.77 per Bbl for the three months ended March 31, 2023.

(3)

Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.

Permian Resources Corporation
Operating Expenses

Three Months Ended March 31,

2024

2023

Operating costs (in thousands):

Lease operating expenses

$

168,671

$

74,532

Severance and ad valorem taxes

96,166

48,509

Gathering, processing and transportation expenses

39,055

15,482

Operating cost metrics:

Lease operating expenses (per Boe)

$

5.80

$

5.38

Severance and ad valorem taxes (% of revenue)

7.7

%

7.9

%

Gathering, processing and transportation expenses (per Boe)

$

1.34

$

1.12

Permian Resources Corporation
Consolidated Statements of Operations (unaudited)
(in thousands, except per share data)

Three Months Ended March 31,

2024

2023

Operating revenues

Oil and gas sales

$

1,242,999

$

616,268

Operating expenses

Lease operating expenses

168,671

74,532

Severance and ad valorem taxes

96,166

48,509

Gathering, processing and transportation expenses

39,055

15,482

Depreciation, depletion and amortization

410,179

188,219

General and administrative expenses

37,373

35,474

Merger and integration expense

11,123

13,299

Impairment and abandonment expense

20

245

Exploration and other expenses

11,488

4,374

Total operating expenses

774,075

380,134

Net gain (loss) on sale of long-lived assets

112

66

Income from operations

469,036

236,200

Other income (expense)

Interest expense

(72,587

)

(36,777

)

Net gain (loss) on derivative instruments

(121,129

)

54,512

Other income (expense)

3,232

120

Total other income (expense)

(190,484

)

17,855

Income before income taxes

278,552

254,055

Income tax expense

(48,957

)

(34,254

)

Net income

229,595

219,801

Less: Net income attributable to noncontrolling interest

(83,020

)

(117,681

)

Net income attributable to Class A Common Stock

$

146,575

$

102,120

Income per share of Class A Common Stock:

Basic

$

0.27

$

0.35

Diluted

$

0.25

$

0.31

Weighted average Class A Common Stock outstanding:

Basic

552,472

295,913

Diluted

595,352

335,848

Permian Resources Corporation
Consolidated Balance Sheets (unaudited)
(in thousands, except share and per share amounts)

March 31, 2024

December 31, 2023

ASSETS

Current assets

Cash and cash equivalents

$

12,692

$

73,290

Accounts receivable, net

557,243

481,060

Derivative instruments

5,000

70,591

Prepaid and other current assets

32,442

25,451

Total current assets

607,377

650,392

Property and Equipment

Oil and natural gas properties, successful efforts method

Unproved properties

2,476,541

2,401,317

Proved properties

15,492,619

15,036,687

Accumulated depreciation, depletion and amortization

(3,808,590

)

(3,401,895

)

Total oil and natural gas properties, net

14,160,570

14,036,109

Other property and equipment, net

45,007

43,647

Total property and equipment, net

14,205,577

14,079,756

Noncurrent assets

Operating lease right-of-use assets

123,147

59,359

Other noncurrent assets

145,208

176,071

TOTAL ASSETS

$

15,081,309

$

14,965,578

LIABILITIES AND EQUITY

Current liabilities

Accounts payable and accrued expenses

$

977,114

$

1,167,525

Operating lease liabilities

53,172

33,006

Derivative instruments

33,687

2,725

Other current liabilities

48,059

38,297

Total current liabilities

1,112,032

1,241,553

Noncurrent liabilities

Long-term debt, net

3,909,418

3,848,781

Asset retirement obligations

128,160

121,417

Deferred income taxes

441,839

422,627

Operating lease liabilities

71,898

28,302

Other noncurrent liabilities

69,766

73,150

Total liabilities

5,733,113

5,735,830

Commitments and contingencies (Note 12)

Shareholders’ equity

Common stock, $0.0001 par value, 1,500,000,000 shares authorized:

Class A: 587,622,487 shares issued and 582,262,542 shares outstanding at March 31, 2024 and 544,610,984 shares issued and 540,789,758 shares outstanding at December 31, 2023

59

54

Class C: 187,607,059 shares issued and outstanding at March 31, 2024 and 230,962,833 shares issued and outstanding at December 31, 2023

19

23

Additional paid-in capital

6,331,073

5,766,881

Retained earnings (accumulated deficit)

626,930

569,139

Total shareholders’ equity

6,958,081

6,336,097

Noncontrolling interest

2,390,115

2,893,651

Total equity

9,348,196

9,229,748

TOTAL LIABILITIES AND EQUITY

$

15,081,309

$

14,965,578

Permian Resources Corporation
Consolidated Statements of Cash Flows (unaudited)
(in thousands)

Three Months Ended March 31,

2024

2023

Cash flows from operating activities:

Net income

$

229,595

$

219,801

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation, depletion and amortization

410,179

188,219

Stock-based compensation expense

9,631

17,871

Impairment and abandonment expense

20

245

Deferred tax expense

46,979

33,454

Net (gain) loss on sale of long-lived assets

(112

)

(66

)

Non-cash portion of derivative (gain) loss

128,474

(14,777

)

Amortization of debt issuance costs, discount and premium

1,531

2,796

Changes in operating assets and liabilities:

(Increase) decrease in accounts receivable

(85,138

)

(1,503

)

(Increase) decrease in prepaid and other assets

5,350

(1,016

)

Increase (decrease) in accounts payable and other liabilities

(98,911

)

(6,811

)

Net cash provided by operating activities

647,598

438,213

Cash flows from investing activities:

Acquisition of oil and natural gas properties, net

(97,019

)

(100,755

)

Drilling and development capital expenditures

(519,623

)

(315,285

)

Purchases of other property and equipment

(2,772

)

(1,204

)

Contingent considerations received related to divestiture

–

60,000

Proceeds from sales of oil and natural gas properties

66

65,116

Net cash used in investing activities

(619,348

)

(292,128

)

Cash flows from financing activities:

Proceeds from borrowings under revolving credit facility

220,000

160,000

Repayment of borrowings under revolving credit facility

(160,000

)

(260,000

)

Debt issuance costs

(1,880

)

–

Proceeds from exercise of stock options

58

231

Share repurchases

(31,492

)

(61,578

)

Dividends paid

(87,194

)

(15,192

)

Distributions paid to noncontrolling interest owners

(28,327

)

(13,324

)

Net cash provided by (used in) financing activities

(88,835

)

(189,863

)

Net increase (decrease) in cash, cash equivalents and restricted cash

(60,585

)

(43,778

)

Cash, cash equivalents and restricted cash, beginning of period

73,864

69,932

Cash, cash equivalents and restricted cash, end of period

$

13,279

$

26,154

Reconciliation of cash, cash equivalents and restricted cash presented on the Consolidated Statements of Cash Flows for the periods presented:

Three Months Ended March 31,

2024

2023

Cash and cash equivalents

$

12,692

$

25,593

Restricted cash

587

561

Total cash, cash equivalents and restricted cash

$

13,279

$

26,154

Non-GAAP Financial Measures

In addition to disclosing financial results calculated in accordance with U.S. generally accepted accounting principles (“GAAP”), our earnings release contains non-GAAP financial measures as described below.

Adjusted EBITDAX

Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income attributable to Class A Common Stock before net income attributable to noncontrolling interest, interest expense, income taxes, depreciation, depletion and amortization, impairment and abandonment expense, non-cash gains or losses on derivatives, stock-based compensation (not cash-settled), exploration and other expenses, merger and integration expense, gain/loss from the sale of long-lived assets and other non-recurring items. Adjusted EBITDAX is not a measure of net income as determined by GAAP.

Our management believes Adjusted EBITDAX is useful as it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers, without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or nonrecurring items. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.

The following table presents a reconciliation of Adjusted EBITDAX to net income, which is the most directly comparable financial measure calculated and presented in accordance with GAAP:

Three Months Ended

(in thousands)

3/31/2024

12/31/2023

9/30/2023

6/30/2023

3/31/2023

Adjusted EBITDAX reconciliation to net income:

Net income attributable to Class A Common Stock

$

146,575

$

255,354

$

45,433

$

73,399

$

102,120

Net income attributable to noncontrolling interest

83,020

157,265

52,896

75,555

117,681

Interest expense

72,587

63,024

40,582

36,826

36,777

Income tax expense

48,957

78,889

16,254

26,548

34,254

Depreciation, depletion and amortization

410,179

367,427

236,204

215,726

188,219

Impairment and abandonment expense

20

5,947

245

244

245

Non-cash derivative (gain) loss

128,474

(180,179

)

161,672

18,678

(14,777

)

Stock-based compensation expense(1)

9,094

8,495

15,633

35,042

16,707

Exploration and other expenses

11,488

4,669

5,031

5,263

4,374

Merger and integration expense

11,123

97,260

10,422

4,350

13,299

(Gain) loss on sale of long-lived assets

(112

)

(82

)

(63

)

–

(66

)

Adjusted EBITDAX

$

921,405

$

858,069

$

584,309

$

491,631

$

498,833

_______________________________________

(1)

Includes stock-based compensation expense for equity awards related to general and administrative employees only. Stock-based compensation amounts for geographical and geophysical personnel are included within the Exploration and other expenses line item.

Net Debt-to-LQA EBITDAX

Net debt-to-LQA EBITDAX is a non-GAAP financial measure. We define net debt as long-term debt, net, plus unamortized debt discount, premium and debt issuance costs on our senior notes minus cash and cash equivalents.

We define net debt-to-LQA EBITDAX as net debt (defined above) divided by Adjusted EBITDAX (defined and reconciled in the section above) for the three months ended March 31, 2024, on an annualized basis. We refer to this metric to show trends that investors may find useful in understanding our ability to service our debt. This metric is widely used by professional research analysts, including credit analysts, in the valuation and comparison of companies in the oil and gas exploration and production industry. The following table presents a reconciliation of net debt to long-term debt, net and the calculation of net debt-to-LQA EBITDAX for the period presented:

(in thousands)

March 31, 2024

Long-term debt, net

3,909,418

Unamortized debt discount, premium and issuance costs on senior notes

16,381

Long-term debt

3,925,799

Less: cash and cash equivalents

(12,692

)

Net debt (Non-GAAP)

3,913,107

LQA EBITDAX(1)

3,685,620

Net debt-to-LQA EBITDAX

1

_______________________________________

(1)

Represents adjusted EBITDAX (defined and reconciled in the section above) for the three months ended March 31, 2024, on an annualized basis.

Adjusted Shares

Adjusted basic and diluted weighted average shares outstanding (“Adjusted Basic and Diluted Shares”) are non-GAAP financial measures defined as basic and diluted weighted average shares outstanding adjusted to reflect the weighted average shares of our Class C Common Stock outstanding during the period.

Our Adjusted Basic and Diluted Shares provide a comparable per share measurement when presenting results such as adjusted free cash flow and adjusted net income that include the interests of both net income attributable to Class A Common Stock and the net income attributable to our noncontrolling interest. Adjusted Basic and Diluted Shares are used in calculating several metrics that we use as supplemental financial measurements in the evaluation of our business.

The following table presents a reconciliation of Adjusted Basic and Diluted Shares to basic and diluted weighted average shares outstanding, which are the most directly comparable financial measure calculated and presented in accordance with GAAP:

Three Months Ended March 31,

(in thousands)

2024

2023

Basic weighted average shares of Class A Common Stock outstanding

552,472

295,913

Weighted average shares of Class C Common Stock

218,811

263,369

Adjusted basic weighted average shares outstanding

771,283

559,282

Basic weighted average shares of Class A Common Stock outstanding

552,472

295,913

Add: Dilutive effects of Convertible Senior Notes

28,355

27,314

Add: Dilutive effects of equity awards

14,525

12,621

Diluted weighted average shares of Class A Common Stock outstanding

595,352

335,848

Weighted average shares of Class C Common Stock

218,811

263,369

Adjusted diluted weighted average shares outstanding

814,163

599,217

Adjusted Operating Cash Flow and Adjusted Free Cash Flow

Adjusted operating cash flow and adjusted free cash flow are supplemental non-GAAP financial measures used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define adjusted operating cash flow as net cash provided by operating activities adjusted to remove changes in working capital, merger and integration and other non-recurring charges, and estimated tax distributions to our non-controlling interest owners. Adjusted operating cash flows is reduced by total cash capital expenditures to arrive at adjusted free cash flows.

Our management believes adjusted operating cash flow and adjusted free cash flow are useful indicators of the Company’s ability to internally fund its future exploration and development activities, to service its existing level of indebtedness or incur additional debt, without regard to the timing of settlement of either operating assets and liabilities, its merger and integration and other non-recurring costs or estimated tax distributions to noncontrolling interest owners after funding its capital expenditures paid for the period. The Company believes that these measures, as so adjusted, present meaningful indicators of the Company’s actual sources and uses of capital associated with its operations conducted during the applicable period. Our computation of adjusted operating cash flow and adjusted free cash flow may not be comparable to other similarly titled measures of other companies. Adjusted operating cash flow and adjusted free cash flow should not be considered as alternatives to, or more meaningful than, net cash provided by operating activities as determined in accordance with GAAP or as indicators of our operating performance or liquidity.

Adjusted operating cash flow and adjusted free cash flow are not financial measures that are determined in accordance with GAAP. Accordingly, the following table presents a reconciliation of adjusted operating cash flow and adjusted free cash flow to net cash provided by operating activities, which is the most directly comparable financial measure calculated and presented in accordance with GAAP:

Three Months Ended March 31,

(in thousands, except per share data)

2024

2023

Net cash provided by operating activities

$

647,598

$

438,213

Changes in working capital:

Accounts receivable

85,138

1,503

Prepaid and other assets

(5,350

)

1,016

Accounts payable and other liabilities

98,911

6,811

Merger and integration expense & other

17,612

13,299

Estimated tax distribution to noncontrolling interest owners(1)

(335

)

–

Adjusted operating cash flow

843,574

460,842

Less: total cash capital expenditures

(519,623

)

(315,285

)

Adjusted free cash flow

$

323,951

$

145,557

Adjusted basic weighted average shares outstanding

771,283

559,282

Adjusted operating cash flow per adjusted basic share

$

1.09

$

0.82

Adjusted free cash flow per adjusted basic share

$

0.42

$

0.26

_______________________________________

(1)

Reflects estimated future distributions to noncontrolling interest owners based upon current federal and state income tax expense recognized during the period and expected to be paid by the partnership. Such estimates are based upon the noncontrolling interest ownership percentage as of three months ended March 31, 2024.

Adjusted Net Income

Adjusted net income is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define adjusted net income as net income attributable to Class A Common Stock plus net income attributable to noncontrolling interest adjusted for non-cash gains or losses on derivatives, merger and integration expense, other nonrecurring charges, impairment and abandonment expense, gain/loss from the sale of long-lived assets and the related income tax adjustments for these items. Adjusted net income is not a measure of net income as determined by GAAP.

Our management believes adjusted net income is useful as it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers by excluding certain non-cash items that can vary significantly. Adjusted net income should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Our presentation of adjusted net income should not be construed as an inference that our results will be unaffected by unusual or nonrecurring items. Our computations of adjusted net income may not be comparable to other similarly titled measures of other companies.

Adjusted net income is not a financial measure that is determined in accordance with GAAP. Accordingly, the following table presents a reconciliation of adjusted net income to net income, which is the most directly comparable financial measure calculated and presented in accordance with GAAP:

Three Months Ended March 31,

(in thousands, except per share data)

2024

2023

Net income attributable to Class A Common Stock

$

146,575

$

102,120

Net income attributable to noncontrolling interest

83,020

117,681

Non-cash derivative (gain) loss

128,474

(14,777

)

Merger and integration expense & other

17,612

13,299

Impairment and abandonment expense

20

245

(Gain) loss on sale of long-lived assets

(112

)

(66

)

Adjusted net income excluding above items

375,589

218,502

Income tax expense attributable to the above items(1)

(51,528

)

(26,186

)

Adjusted Net Income

$

324,061

$

192,316

Adjusted basic weighted average shares outstanding (Non-GAAP)(2)

771,283

559,282

Adjusted net income per adjusted basic share

$

0.42

$

0.34

_______________________________________

(1)

Income tax (expense) benefit for adjustments made to adjusted net income is calculated using PR’s federal and state-apportioned statutory tax rate of 22.5%.

(2)

Adjusted basic weighted average shares outstanding is a Non-GAAP measure that has been computed and reconciled to the nearest GAAP metric in the preceding table above.

The following table summarizes the approximate volumes and average contract prices of the hedge contracts the Company had in place as of April 30, 2024. There were no additional contracts entered into through the date of this filing:

Period

Volume (Bbls)

Volume (Bbls/d)

Wtd. Avg. Crude

Price

($/Bbl)(1)

Crude oil swaps

April 2024 – June 2024

3,612,500

39,698

$77.27

July 2024 – September 2024

3,634,000

39,500

76.08

October 2024 – December 2024

3,634,000

39,500

74.94

January 2025 – March 2025

2,250,000

25,000

74.30

April 2025 – June 2025

2,275,000

25,000

73.05

July 2025 – September 2025

2,300,000

25,000

71.88

October 2025 – December 2025

2,300,000

25,000

70.88

January 2026 – March 2026

405,000

4,500

71.74

April 2026 – June 2026

409,500

4,500

70.75

July 2026 – September 2026

414,000

4,500

69.80

October 2026 – December 2026

414,000

4,500

69.00

Period

Volume (Bbls)

Volume (Bbls/d)

Wtd. Avg. Collar

Price Ranges

($/Bbl)(2)

Crude oil collars

April 2024 – June 2024

182,000

2,000

$60.00

–

$76.01

July 2024 – September 2024

184,000

2,000

60.00

–

76.01

October 2024 – December 2024

184,000

2,000

60.00

–

76.01

Period

Volume (Bbls)

Volume (Bbls/d)

Wtd. Avg. Put Price

($/Bbl)(3)

Deferred

Premium

($/Bbl)(3)

Deferred premium puts

April 2024 – June 2024

227,500

2,500

$65.00

$4.96

July 2024 – September 2024

230,000

2,500

65.00

4.96

October 2024 – December 2024

230,000

2,500

65.00

4.96

Period

Volume (Bbls)

Volume (Bbls/d)

Wtd. Avg.

Differential

($/Bbl)(4)

Crude oil basis differential swaps

April 2024 – June 2024

3,841,018

42,209

$0.97

July 2024 – September 2024

4,048,000

44,000

0.98

October 2024 – December 2024

4,048,000

44,000

0.98

January 2025 – March 2025

2,250,000

25,000

1.10

April 2025 – June 2025

2,275,000

25,000

1.10

July 2025 – September 2025

2,300,000

25,000

1.10

October 2025 – December 2025

2,300,000

25,000

1.10

January 2026 – March 2026

405,000

4,500

1.12

April 2026 – June 2026

409,500

4,500

1.12

July 2026 – September 2026

414,000

4,500

1.12

October 2026 – December 2026

414,000

4,500

1.12

Period

Volume (Bbls)

Volume (Bbls/d)

Wtd. Avg.

Differential

($/Bbl)(5)

Crude oil roll differential swaps

April 2024 – June 2024

3,842,018

42,220

$0.51

July 2024 – September 2024

4,048,000

44,000

0.53

October 2024 – December 2024

4,048,000

44,000

0.53

January 2025 – March 2025

2,250,000

25,000

0.43

April 2025 – June 2025

2,275,000

25,000

0.43

July 2025 – September 2025

2,300,000

25,000

0.43

October 2025 – December 2025

2,300,000

25,000

0.43

January 2026 – March 2026

405,000

4,500

0.37

April 2026 – June 2026

409,500

4,500

0.37

July 2026 – September 2026

414,000

4,500

0.37

October 2026 – December 2026

414,000

4,500

0.37

_______________________________________

(1)

These crude oil swap transactions are settled based on the NYMEX WTI index price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.

(2)

These crude oil collars are settled based on the NYMEX WTI index price on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.

(3)

These crude oil deferred premium puts are settled based on the NYMEX WTI index price on each trading day within the specified monthly settlement period versus the contractual put prices for the volumes stipulated.

(4)

These crude oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each applicable monthly settlement period.

(5)

These crude oil roll swap transactions are settled based on the difference between the arithmetic average of NYMEX WTI calendar month prices and the physical crude oil delivery month price.

Period

Volume (MMBtu)

Volume (MMBtu/d)

Wtd. Avg. Gas Price

($/MMBtu)(1)

Natural gas swaps

April 2024 – June 2024

5,906,321

64,905

$3.29

July 2024 – September 2024

5,949,388

64,667

3.43

October 2024 – December 2024

5,933,899

64,499

3.86

January 2025 – March 2025

3,600,000

40,000

4.32

April 2025 – June 2025

3,640,000

40,000

3.65

July 2025 – September 2025

3,680,000

40,000

3.83

October 2025 – December 2025

3,680,000

40,000

4.20

Period

Volume (MMBtu)

Volume (MMBtu/d)

Wtd. Avg.

Differential

($/MMBtu)(2)

Natural gas basis differential swaps

April 2024 – June 2024

10,920,000

120,000

$(0.99)

July 2024 – September 2024

11,040,000

120,000

(0.99)

October 2024 – December 2024

11,040,000

120,000

(0.98)

January 2025 – March 2025

3,600,000

40,000

(0.74)

April 2025 – June 2025

3,640,000

40,000

(0.74)

July 2025 – September 2025

3,680,000

40,000

(0.74)

October 2025 – December 2025

3,680,000

40,000

(0.74)

Period

Volume (MMBtu)

Volume (MMBtu/d)

Wtd. Avg. Collar

Price Ranges

($/MMBtu)(3)

Natural gas collars

April 2024 – June 2024

5,013,679

55,095

$2.68

–

$5.04

July 2024 – September 2024

5,090,612

55,333

2.68

–

5.06

October 2024 – December 2024

5,106,101

55,501

2.75

–

5.29

_______________________________________

(1)

These natural gas swap contracts are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.

(2)

These natural gas basis swap contracts are settled based on the difference between the Inside FERC’s West Texas WAHA price and the NYMEX price of natural gas, during each applicable monthly settlement period.

(3)

These natural gas collars are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.

Source: Rbcrichardsonbarr.com

Take the Survey at https://survey.energynewsbeat.com/

1031 Exchange E-Book

ENB Top News 
ENB
Energy Dashboard
ENB Podcast
ENB Substack

The post Permian Resources Announces Strong First Quarter 2024 Results and Increases Full Year Guidance appeared first on Energy News Beat.