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Germany’s government approved on Wednesday a draft law to enable faster development of hydrogen projects and infrastructure by fast-tracking permitting and environmental checks for hydrogen production, storage, and transportation, government sources told Reuters.

The so-called Hydrogen Acceleration Law will give hydrogen projects priority in approvals, simplify permitting, and fast-track environmental impact assessments.

Germany, which aims to become a carbon-neutral economy by 2045 – five years ahead of the EU and other major developed economies – already has a National Hydrogen Strategy in place. The strategy will help create a domestic market as a first step in market ramp-up by building appropriate hydrogen production capacity and developing technologies for the use of hydrogen on the demand side. Germany also plans to implement a regulatory framework for the development and expansion of the necessary hydrogen transport and distribution infrastructure.

In a 2023 update of the National Hydrogen Strategy, Germany raised the target for hydrogen electrolysis capacities from 5 gigawatts (GW) to 10 GW by 2030, assuming that hydrogen demand in Germany will increase to 95-130 terawatt hours (TWh) by 2030, from around 55 TWh per year in 2023. The Strategy also sets out how hydrogen demand is to become even greater between 2030 and 2045.

Germany, Europe’s largest economy, bets big on hydrogen to decarbonize hard-to-abate industrial sectors including steelmaking and cement making.

Last year, the European Commission approved under the EU state aid rules two German measures to support ThyssenKrupp Steel Europe in decarbonizing its steel production processes and accelerating its uptake of renewable hydrogen. Germany plans a $597 million (550 million euros) direct grant and conditional payment mechanism of up to $1.57 billion (1.45 billion euros) to support ThyssenKrupp Steel Europe.

Separately, Germany’s state-controlled firm Securing Energy for Europe (Sefe) plans to invest around $543 million (500 million euros) in repurposing some of its underground gas storage sites and gas pipelines into infrastructure fit for storing and transporting green hydrogen, Sefe’s CEO Egbert Laege told Reuters in an interview earlier this year.

Source: Oilprice.com

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America produces more energy than any other country in the world, has more energy reserves than any other country, and pioneered clean, inexpensive, and virtually unlimited nuclear energy. So why does even the Washington Post admit that “America is running out of power?”

The answer is simple. Take a look at your smartphone. Binge-watch the new season of Bridgerton on Netflix. Ask ChatGPT to produce an outline for your marketing plan.

“For years tech giants have been helping climate catastrophists shut down reliable fossil fuel electricity, falsely claiming they can be replaced by solar/wind,” Alex Epstein — energy expert and author of “Fossil Future” — reported on X a few days ago. “Now the grid they’ve helped gut can’t supply their growing AI needs.”

There are few things more destructive than a major corporation with lots of money to throw around making themselves look good on trendy social concerns.

“Tech giants have propagandized against reliable fossil fuel power plants by falsely claiming to be ‘100% renewable’ and implying everyone could do it, Epstein continued. “In fact, they have just paid utilities to credit them for others’ solar and wind use and blame others for their coal and gas use.”

Apple CEO Tim Cook got bragging rights. California got brownouts. Even Texas, one of the better-run states in the union, has made itself overreliant on unreliable energy sources like wind and solar.

Would it surprise you to learn that Apple’s vice president in charge of Environment, Policy and Social Initiatives is Lisa Jackson, who served as Barack Obama’s EPA chief?

Now there is good news buried deep inside all the doom and gloom. Nobody, not even the wishful-thinking experts in Washington or America’s C-suites, can keep power-hungry data centers running on windmills and unicorn farts. From Netflix to your cloud photo library to the latest AI chatbot, more and more of everything we do relies on data centers.

There’s simply too much money to be made from Big Data to make them rely on unreliable power sources.

The Biden administration is making useless (but expensive) pledges to “modernize America’s electrical grid, paving the way for clean energy and fewer outages” that fail to address the issue. A better grid would be nice. A harder grid would be better. But what we really need is more cheap and reliable power — and lots more of it.

Enter, at long last, the small modular reactor (SMR). “Due to their small size and modular nature,” Carbon Credits reported last week, “SMRs can be factory-assembled and transported to sites unsuitable for larger reactors, making them more affordable and quicker to construct.”

Those same Big Tech firms that have been loudly trumpeting how “green” they are have been quietly “shopping for nuclear power to run new data centers.” Plans are already being drawn up to build new data centers around SMRs.

The hypocrisy is stunning. But if the rest of us end up getting plentiful and reliable nuclear energy out of it, I suppose it might have been worth having to listen to Cook and Jackson’s little lectures.

Maybe.

Source: Pjmedia.com

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(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

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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

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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

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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

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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

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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

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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

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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

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