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

Recent Financial and Operational Highlights

Delivered Permian Resources’ best quarter to-date:

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

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

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

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

Management Commentary

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

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

Operational and Financial Results

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

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

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

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

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

Earthstone Integration Update

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

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

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

Recent Acquisitions

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

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

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

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

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

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

2024 Operational Plan and Target Update

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

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

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

Shareholder Returns

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

Quarterly Report on Form 10-Q

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

Conference Call and Webcast

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

About Permian Resources

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

Cautionary Note Regarding Forward-Looking Statements

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

Forward-looking statements may include statements about:

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

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

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

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

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

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

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

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

2024 FY Guidance (Updated)

Net average daily production (Boe/d)

310,000

–

330,000

Net average daily oil production (Bbls/d)

148,000

–

152,000

Production costs

Lease operating expenses ($/Boe)

$5.50

–

$6.00

Gathering, processing and transportation expenses ($/Boe)

$1.00

–

$1.50

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

$0.90

–

$1.10

Severance and ad valorem taxes (% of revenue)

6.5%

–

8.5%

Total cash capital expenditure program ($MM)

$1,900

–

$2,100

Operated drilling program

TILs (gross)

~250

Average working interest

~75%

Average lateral length (feet)

~9,300

(1)

Excludes stock-based compensation.

Permian Resources Corporation
Operating Highlights

Three Months Ended March 31,

2024

2023

Net revenues (in thousands):

Oil sales

$

1,051,642

$

524,386

Natural gas sales(1)

38,767

32,122

NGL sales(2)

152,590

59,760

Oil and gas sales

$

1,242,999

$

616,268

Average sales prices:

Oil (per Bbl)

$

76.13

$

74.38

Effect of derivative settlements on average price (per Bbl)

(0.12

)

3.65

Oil including the effects of hedging (per Bbl)

$

76.01

$

78.03

Average NYMEX WTI price for oil (per Bbl)

$

76.96

$

76.13

Oil differential from NYMEX

(0.83

)

(1.75

)

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

$

1.24

$

1.81

Effect of derivative settlements on average price (per Mcf)

0.17

0.58

Natural gas including the effects of hedging (per Mcf)

$

1.41

$

2.39

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

$

2.41

$

2.67

Natural gas differential from NYMEX

(1.17

)

(0.86

)

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

$

26.47

$

27.12

Net production:

Oil (MBbls)

13,813

7,050

Natural gas (MMcf)

51,802

23,974

NGL (MBbls)

6,629

2,798

Total (MBoe)(3)

29,076

13,844

Average daily net production:

Oil (Bbls/d)

151,794

78,332

Natural gas (Mcf/d)

569,249

266,374

NGL (Bbls/d)

72,846

31,094

Total (Boe/d)(3)

319,514

153,822

_______________________________________

(1)

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

(2)

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

(3)

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

Permian Resources Corporation
Operating Expenses

Three Months Ended March 31,

2024

2023

Operating costs (in thousands):

Lease operating expenses

$

168,671

$

74,532

Severance and ad valorem taxes

96,166

48,509

Gathering, processing and transportation expenses

39,055

15,482

Operating cost metrics:

Lease operating expenses (per Boe)

$

5.80

$

5.38

Severance and ad valorem taxes (% of revenue)

7.7

%

7.9

%

Gathering, processing and transportation expenses (per Boe)

$

1.34

$

1.12

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

Three Months Ended March 31,

2024

2023

Operating revenues

Oil and gas sales

$

1,242,999

$

616,268

Operating expenses

Lease operating expenses

168,671

74,532

Severance and ad valorem taxes

96,166

48,509

Gathering, processing and transportation expenses

39,055

15,482

Depreciation, depletion and amortization

410,179

188,219

General and administrative expenses

37,373

35,474

Merger and integration expense

11,123

13,299

Impairment and abandonment expense

20

245

Exploration and other expenses

11,488

4,374

Total operating expenses

774,075

380,134

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

112

66

Income from operations

469,036

236,200

Other income (expense)

Interest expense

(72,587

)

(36,777

)

Net gain (loss) on derivative instruments

(121,129

)

54,512

Other income (expense)

3,232

120

Total other income (expense)

(190,484

)

17,855

Income before income taxes

278,552

254,055

Income tax expense

(48,957

)

(34,254

)

Net income

229,595

219,801

Less: Net income attributable to noncontrolling interest

(83,020

)

(117,681

)

Net income attributable to Class A Common Stock

$

146,575

$

102,120

Income per share of Class A Common Stock:

Basic

$

0.27

$

0.35

Diluted

$

0.25

$

0.31

Weighted average Class A Common Stock outstanding:

Basic

552,472

295,913

Diluted

595,352

335,848

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

March 31, 2024

December 31, 2023

ASSETS

Current assets

Cash and cash equivalents

$

12,692

$

73,290

Accounts receivable, net

557,243

481,060

Derivative instruments

5,000

70,591

Prepaid and other current assets

32,442

25,451

Total current assets

607,377

650,392

Property and Equipment

Oil and natural gas properties, successful efforts method

Unproved properties

2,476,541

2,401,317

Proved properties

15,492,619

15,036,687

Accumulated depreciation, depletion and amortization

(3,808,590

)

(3,401,895

)

Total oil and natural gas properties, net

14,160,570

14,036,109

Other property and equipment, net

45,007

43,647

Total property and equipment, net

14,205,577

14,079,756

Noncurrent assets

Operating lease right-of-use assets

123,147

59,359

Other noncurrent assets

145,208

176,071

TOTAL ASSETS

$

15,081,309

$

14,965,578

LIABILITIES AND EQUITY

Current liabilities

Accounts payable and accrued expenses

$

977,114

$

1,167,525

Operating lease liabilities

53,172

33,006

Derivative instruments

33,687

2,725

Other current liabilities

48,059

38,297

Total current liabilities

1,112,032

1,241,553

Noncurrent liabilities

Long-term debt, net

3,909,418

3,848,781

Asset retirement obligations

128,160

121,417

Deferred income taxes

441,839

422,627

Operating lease liabilities

71,898

28,302

Other noncurrent liabilities

69,766

73,150

Total liabilities

5,733,113

5,735,830

Commitments and contingencies (Note 12)

Shareholders’ equity

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

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

59

54

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

19

23

Additional paid-in capital

6,331,073

5,766,881

Retained earnings (accumulated deficit)

626,930

569,139

Total shareholders’ equity

6,958,081

6,336,097

Noncontrolling interest

2,390,115

2,893,651

Total equity

9,348,196

9,229,748

TOTAL LIABILITIES AND EQUITY

$

15,081,309

$

14,965,578

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

Three Months Ended March 31,

2024

2023

Cash flows from operating activities:

Net income

$

229,595

$

219,801

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

Depreciation, depletion and amortization

410,179

188,219

Stock-based compensation expense

9,631

17,871

Impairment and abandonment expense

20

245

Deferred tax expense

46,979

33,454

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

(112

)

(66

)

Non-cash portion of derivative (gain) loss

128,474

(14,777

)

Amortization of debt issuance costs, discount and premium

1,531

2,796

Changes in operating assets and liabilities:

(Increase) decrease in accounts receivable

(85,138

)

(1,503

)

(Increase) decrease in prepaid and other assets

5,350

(1,016

)

Increase (decrease) in accounts payable and other liabilities

(98,911

)

(6,811

)

Net cash provided by operating activities

647,598

438,213

Cash flows from investing activities:

Acquisition of oil and natural gas properties, net

(97,019

)

(100,755

)

Drilling and development capital expenditures

(519,623

)

(315,285

)

Purchases of other property and equipment

(2,772

)

(1,204

)

Contingent considerations received related to divestiture

–

60,000

Proceeds from sales of oil and natural gas properties

66

65,116

Net cash used in investing activities

(619,348

)

(292,128

)

Cash flows from financing activities:

Proceeds from borrowings under revolving credit facility

220,000

160,000

Repayment of borrowings under revolving credit facility

(160,000

)

(260,000

)

Debt issuance costs

(1,880

)

–

Proceeds from exercise of stock options

58

231

Share repurchases

(31,492

)

(61,578

)

Dividends paid

(87,194

)

(15,192

)

Distributions paid to noncontrolling interest owners

(28,327

)

(13,324

)

Net cash provided by (used in) financing activities

(88,835

)

(189,863

)

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

(60,585

)

(43,778

)

Cash, cash equivalents and restricted cash, beginning of period

73,864

69,932

Cash, cash equivalents and restricted cash, end of period

$

13,279

$

26,154

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

Three Months Ended March 31,

2024

2023

Cash and cash equivalents

$

12,692

$

25,593

Restricted cash

587

561

Total cash, cash equivalents and restricted cash

$

13,279

$

26,154

Non-GAAP Financial Measures

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

Adjusted EBITDAX

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

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

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

Three Months Ended

(in thousands)

3/31/2024

12/31/2023

9/30/2023

6/30/2023

3/31/2023

Adjusted EBITDAX reconciliation to net income:

Net income attributable to Class A Common Stock

$

146,575

$

255,354

$

45,433

$

73,399

$

102,120

Net income attributable to noncontrolling interest

83,020

157,265

52,896

75,555

117,681

Interest expense

72,587

63,024

40,582

36,826

36,777

Income tax expense

48,957

78,889

16,254

26,548

34,254

Depreciation, depletion and amortization

410,179

367,427

236,204

215,726

188,219

Impairment and abandonment expense

20

5,947

245

244

245

Non-cash derivative (gain) loss

128,474

(180,179

)

161,672

18,678

(14,777

)

Stock-based compensation expense(1)

9,094

8,495

15,633

35,042

16,707

Exploration and other expenses

11,488

4,669

5,031

5,263

4,374

Merger and integration expense

11,123

97,260

10,422

4,350

13,299

(Gain) loss on sale of long-lived assets

(112

)

(82

)

(63

)

–

(66

)

Adjusted EBITDAX

$

921,405

$

858,069

$

584,309

$

491,631

$

498,833

_______________________________________

(1)

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

Net Debt-to-LQA EBITDAX

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

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

(in thousands)

March 31, 2024

Long-term debt, net

3,909,418

Unamortized debt discount, premium and issuance costs on senior notes

16,381

Long-term debt

3,925,799

Less: cash and cash equivalents

(12,692

)

Net debt (Non-GAAP)

3,913,107

LQA EBITDAX(1)

3,685,620

Net debt-to-LQA EBITDAX

1

_______________________________________

(1)

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

Adjusted Shares

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

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

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

Three Months Ended March 31,

(in thousands)

2024

2023

Basic weighted average shares of Class A Common Stock outstanding

552,472

295,913

Weighted average shares of Class C Common Stock

218,811

263,369

Adjusted basic weighted average shares outstanding

771,283

559,282

Basic weighted average shares of Class A Common Stock outstanding

552,472

295,913

Add: Dilutive effects of Convertible Senior Notes

28,355

27,314

Add: Dilutive effects of equity awards

14,525

12,621

Diluted weighted average shares of Class A Common Stock outstanding

595,352

335,848

Weighted average shares of Class C Common Stock

218,811

263,369

Adjusted diluted weighted average shares outstanding

814,163

599,217

Adjusted Operating Cash Flow and Adjusted Free Cash Flow

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

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

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

Three Months Ended March 31,

(in thousands, except per share data)

2024

2023

Net cash provided by operating activities

$

647,598

$

438,213

Changes in working capital:

Accounts receivable

85,138

1,503

Prepaid and other assets

(5,350

)

1,016

Accounts payable and other liabilities

98,911

6,811

Merger and integration expense & other

17,612

13,299

Estimated tax distribution to noncontrolling interest owners(1)

(335

)

–

Adjusted operating cash flow

843,574

460,842

Less: total cash capital expenditures

(519,623

)

(315,285

)

Adjusted free cash flow

$

323,951

$

145,557

Adjusted basic weighted average shares outstanding

771,283

559,282

Adjusted operating cash flow per adjusted basic share

$

1.09

$

0.82

Adjusted free cash flow per adjusted basic share

$

0.42

$

0.26

_______________________________________

(1)

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

Adjusted Net Income

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

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

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

Three Months Ended March 31,

(in thousands, except per share data)

2024

2023

Net income attributable to Class A Common Stock

$

146,575

$

102,120

Net income attributable to noncontrolling interest

83,020

117,681

Non-cash derivative (gain) loss

128,474

(14,777

)

Merger and integration expense & other

17,612

13,299

Impairment and abandonment expense

20

245

(Gain) loss on sale of long-lived assets

(112

)

(66

)

Adjusted net income excluding above items

375,589

218,502

Income tax expense attributable to the above items(1)

(51,528

)

(26,186

)

Adjusted Net Income

$

324,061

$

192,316

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

771,283

559,282

Adjusted net income per adjusted basic share

$

0.42

$

0.34

_______________________________________

(1)

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

(2)

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

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

Period

Volume (Bbls)

Volume (Bbls/d)

Wtd. Avg. Crude

Price

($/Bbl)(1)

Crude oil swaps

April 2024 – June 2024

3,612,500

39,698

$77.27

July 2024 – September 2024

3,634,000

39,500

76.08

October 2024 – December 2024

3,634,000

39,500

74.94

January 2025 – March 2025

2,250,000

25,000

74.30

April 2025 – June 2025

2,275,000

25,000

73.05

July 2025 – September 2025

2,300,000

25,000

71.88

October 2025 – December 2025

2,300,000

25,000

70.88

January 2026 – March 2026

405,000

4,500

71.74

April 2026 – June 2026

409,500

4,500

70.75

July 2026 – September 2026

414,000

4,500

69.80

October 2026 – December 2026

414,000

4,500

69.00

Period

Volume (Bbls)

Volume (Bbls/d)

Wtd. Avg. Collar

Price Ranges

($/Bbl)(2)

Crude oil collars

April 2024 – June 2024

182,000

2,000

$60.00

–

$76.01

July 2024 – September 2024

184,000

2,000

60.00

–

76.01

October 2024 – December 2024

184,000

2,000

60.00

–

76.01

Period

Volume (Bbls)

Volume (Bbls/d)

Wtd. Avg. Put Price

($/Bbl)(3)

Deferred

Premium

($/Bbl)(3)

Deferred premium puts

April 2024 – June 2024

227,500

2,500

$65.00

$4.96

July 2024 – September 2024

230,000

2,500

65.00

4.96

October 2024 – December 2024

230,000

2,500

65.00

4.96

Period

Volume (Bbls)

Volume (Bbls/d)

Wtd. Avg.

Differential

($/Bbl)(4)

Crude oil basis differential swaps

April 2024 – June 2024

3,841,018

42,209

$0.97

July 2024 – September 2024

4,048,000

44,000

0.98

October 2024 – December 2024

4,048,000

44,000

0.98

January 2025 – March 2025

2,250,000

25,000

1.10

April 2025 – June 2025

2,275,000

25,000

1.10

July 2025 – September 2025

2,300,000

25,000

1.10

October 2025 – December 2025

2,300,000

25,000

1.10

January 2026 – March 2026

405,000

4,500

1.12

April 2026 – June 2026

409,500

4,500

1.12

July 2026 – September 2026

414,000

4,500

1.12

October 2026 – December 2026

414,000

4,500

1.12

Period

Volume (Bbls)

Volume (Bbls/d)

Wtd. Avg.

Differential

($/Bbl)(5)

Crude oil roll differential swaps

April 2024 – June 2024

3,842,018

42,220

$0.51

July 2024 – September 2024

4,048,000

44,000

0.53

October 2024 – December 2024

4,048,000

44,000

0.53

January 2025 – March 2025

2,250,000

25,000

0.43

April 2025 – June 2025

2,275,000

25,000

0.43

July 2025 – September 2025

2,300,000

25,000

0.43

October 2025 – December 2025

2,300,000

25,000

0.43

January 2026 – March 2026

405,000

4,500

0.37

April 2026 – June 2026

409,500

4,500

0.37

July 2026 – September 2026

414,000

4,500

0.37

October 2026 – December 2026

414,000

4,500

0.37

_______________________________________

(1)

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

(2)

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

(3)

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

(4)

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

(5)

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

Period

Volume (MMBtu)

Volume (MMBtu/d)

Wtd. Avg. Gas Price

($/MMBtu)(1)

Natural gas swaps

April 2024 – June 2024

5,906,321

64,905

$3.29

July 2024 – September 2024

5,949,388

64,667

3.43

October 2024 – December 2024

5,933,899

64,499

3.86

January 2025 – March 2025

3,600,000

40,000

4.32

April 2025 – June 2025

3,640,000

40,000

3.65

July 2025 – September 2025

3,680,000

40,000

3.83

October 2025 – December 2025

3,680,000

40,000

4.20

Period

Volume (MMBtu)

Volume (MMBtu/d)

Wtd. Avg.

Differential

($/MMBtu)(2)

Natural gas basis differential swaps

April 2024 – June 2024

10,920,000

120,000

$(0.99)

July 2024 – September 2024

11,040,000

120,000

(0.99)

October 2024 – December 2024

11,040,000

120,000

(0.98)

January 2025 – March 2025

3,600,000

40,000

(0.74)

April 2025 – June 2025

3,640,000

40,000

(0.74)

July 2025 – September 2025

3,680,000

40,000

(0.74)

October 2025 – December 2025

3,680,000

40,000

(0.74)

Period

Volume (MMBtu)

Volume (MMBtu/d)

Wtd. Avg. Collar

Price Ranges

($/MMBtu)(3)

Natural gas collars

April 2024 – June 2024

5,013,679

55,095

$2.68

–

$5.04

July 2024 – September 2024

5,090,612

55,333

2.68

–

5.06

October 2024 – December 2024

5,106,101

55,501

2.75

–

5.29

_______________________________________

(1)

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

(2)

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

(3)

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

Source: Rbcrichardsonbarr.com

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

 

Energy News Beat

OKLAHOMA CITY, Okla., May 7, 2024 /PRNewswire/ — SandRidge Energy, Inc. (the “Company” or “SandRidge”) (NYSE: SD) today announced financial and operational results for the three-month period ended March 31, 2024.

Recent Highlights

On May 2, 2024, the Board of Directors declared a $0.11 per share cash dividend payable on May 31, 2024 to shareholders of record on May 17, 2024. The Company has paid $141.2 million in cash dividends since May 2023
First quarter net income was $11.1 million, or $0.30 per basic share. Adjusted net income(1) was $8.4 million, or $0.23 per basic share
Adjusted EBITDA(1) of $14.7 million for the three-month period ended March 31, 2024
Adjusted G&A(1) was $2.8 million, or $2.03 per Boe for the three-month period ended March 31, 2024
Net cash provided by operating activities of $15.7 million for the three-month period ended March 31, 2024
Generated $14.5 million of free cash flow(1) for the three-month period ended March 31, 2024, which represents a conversion rate of approximately 99% relative to adjusted EBITDA(1)
As of March 31, 2024, the Company had $208.5 million of cash and cash equivalents, including restricted cash
Approximately $2.7 million in interest income for the quarter ended March 31, 2024

Financial Results & Update

Profitability & Realized Pricing

For the three months ended March 31, 2024, the Company reported net income of $11.1 million, or $0.30 per basic share, and net cash provided by operating activities of $15.7 million. After adjusting for certain items, the Company’s adjusted net income(1) amounted to $8.4 million, or $0.23 per basic share, adjusted operating cash flow(1) totaled $17.5 million and adjusted EBITDA(1) was $14.7 million for the quarter. The Company defines and reconciles adjusted net income, adjusted operating cash flow, adjusted EBITDA, and other non-GAAP financial measures to the most directly comparable Generally Accepted Accounting Principles in the United States (“GAAP”) measure in supporting tables at the conclusion of this press release.

For the three months ended March 31, 2024, the Company generated approximately $14.5 million of free cash flow(1). This represents a conversion rate of approximately 99% relative to adjusted EBITDA for the three months ended March 31, 2024.

First quarter realized oil, natural gas, and natural gas liquids prices were $75.08 per Bbl, $1.25 per Mcf and $23.65 per Bbl, respectively.

Operating Costs

During the first quarter of 2024, lease operating expense (“LOE”) was $10.9 million or $7.92 per Boe. The Company continues to focus on its operating costs and safely maximizing the value of its asset base through prudent expenditure programs, cost management efforts, and continuous pursuit of initiatives that safely drive cost efficiency in the field. The Company successfully managed the operational impacts of seasonal cold weather throughout the first quarter of 2024, which impacted the timing of expense workover activities, but were not outside of the Company’s range expectations for this time of year.

For the three months ended March 31, 2024, general and administrative expense (“G&A”) was $3.3 million, or $2.42 per Boe.

Liquidity & Capital Structure

As of March 31, 2024, the Company had $208.5 million of cash and cash equivalents, including restricted cash, diversified across multiple significant, well-capitalized financial institutions. The Company has no outstanding term or revolving debt obligations.

Dividend Program

In January 2024, the Board of Directors approved a one-time cash dividend of $1.50 per share of the Company’s common stock, which was paid on February 20, 2024 to shareholders of record as of the close of business on February 5, 2024. The aggregate total payout was approximately $55.6 million. Additionally, in March 2024, the Board of Directors increased the Company’s on-going quarterly dividend to $0.11 per share which was first paid on March 29, 2024, to shareholders of record as of the close of business on March 15, 2024. The aggregate total payout was $4.1 million. The $0.11 per share dividend is subject to quarterly approval by the Board of Directors. Dividend payments for the three-month period ended March 31, 2024 totaled $59.7 million, which included $0.1 million of dividends on vested stock awards.

On May 2, 2024, the Board of Directors declared a $0.11 per share cash dividend payable on May 31, 2024 to shareholders of record on May 17, 2024.

Operational Results & Update

Production & Revenue

Production totaled 1,376 MBoe (15.1 MBoed, 15% oil, 58% natural gas and 27% NGLs) for the three months ended March 31, 2024. Revenues totaled $30.3 million (51% oil, 20% natural gas and 29% NGLs) for the first quarter of 2024. While production in the first quarter of 2024 was impacted by seasonal cold weather, our projected long-term decline rates remain stable due to the nature of the Company’s asset base and the continued focus on production optimization efforts.

Production Optimization Program

The Company continues to optimize its stable, low-decline production base, which has an estimated single-digit annual PDP decline rate over the next ten years. The Company continuously evaluates the potential for high-return projects that further enhance its asset base. Such projects include, but are not limited to, workovers, artificial lift improvements and conversions from less efficient systems, recompletions of “behind pipe” pay in vertical section of existing wells, and the restimulation of existing intervals and previously bypassed unstimulated intervals in existing wells. When evaluating these and other options, the Company continues to ensure that all projects meet high rate of return thresholds and remains capital disciplined as the commodity price landscape changes.

Outlook

SandRidge will continue to focus on growing the cash value and generation capability of its asset base in a safe, responsible and efficient manner, while exercising prudent capital allocations to projects it believes provide high rates of returns in the current commodity price outlook. These near-term projects will be focused on artificial lift conversions to more efficient and cost-effective systems and other capital-efficient workovers while preserving future development and expanded well reactivations, benefited by our 99% held by production acreage position that extends the option value to initiate projects in favorable commodity price environments, to achieve high rates of return. The Company will continue to monitor forward-looking commodity prices, results, costs and other factors that could influence returns on investments, which will continue to shape its disciplined development decisions in 2024 and beyond.

SandRidge will also continue to maintain the optionality to execute on value accretive merger and acquisition opportunities that could bring synergies, leverage the Company’s core competencies, complement its portfolio of assets, seek to further utilize its approximately $1.6 billion of net operating losses (“NOLs”), or otherwise yield attractive returns for its shareholders.

Environmental, Social, & Governance (“ESG”)

SandRidge maintains its Environmental, Social, and Governance (“ESG”) commitment, to include no routine flaring of produced natural gas and transporting over 95% of its produced water via pipeline instead of truck. Additionally, SandRidge maintains an emphasis on the safety and training of our workforce. We have personnel dedicated to the close monitoring of our safety standards and daily operations.

Conference Call Information

The Company will host a conference call to discuss these results on Wednesday, May 8, 2024 at 10:00 am CT. The conference call can be accessed by registering online in advance at https://registrations.events/direct/Q4I231505 at which time registrants will receive dial-in information as well as a conference ID. At the time of the call, participants will dial in using the participant number and conference ID provided upon registration. The Company’s latest presentation is available on the Company’s website at investors.sandridgeenergy.com.

A live audio webcast of the conference call will also be available via SandRidge’s website, investors.sandridgeenergy.com, under Presentation & Events. The webcast will be archived for replay on the Company’s website for at least 30 days.

Contact Information
Investor Relations
SandRidge Energy, Inc.
1 E. Sheridan Ave. Suite 500
Oklahoma City, OK 73104
[email protected]

About SandRidge Energy, Inc.

SandRidge Energy, Inc. (NYSE: SD) is an independent oil and gas company engaged in the development, acquisition, and production of oil and gas assets. Its primary area of operations is the Mid-Continent region in Oklahoma and Kansas. Further information can be found at sandridgeenergy.com.

-Tables to Follow-

 

Operational and Financial Statistics
Information regarding the Company’s production, pricing, costs and earnings is presented below (unaudited):

 

Capital Expenditures

The table below presents actual results of the Company’s capital expenditures for the three months ended March 31, 2024 (unaudited):

Capitalization

The Company’s capital structure as of March 31, 2024 and December 31, 2023 is presented below:

 

 

 

Non-GAAP Financial Measures

This press release includes non-GAAP financial measures. These non-GAAP measures are not alternatives to GAAP measures, and you should not consider these non-GAAP measures in isolation or as a substitute for analysis of our results as reported under GAAP. Below is additional disclosure regarding each of the non-GAAP measures used in this press release, including reconciliations to their most directly comparable GAAP measure.

Reconciliation of Net Cash Provided by Operating Activities to Adjusted Operating Cash Flow

The Company defines Adjusted operating cash flow as net cash provided by operating activities before changes in operating assets and liabilities as shown in the following table. Adjusted Operating cash flow is a supplemental financial measure used by the Company’s management and by securities analysts, investors, lenders, rating agencies and others who follow the industry as an indicator of the Company’s ability to internally fund exploration and development activities or incur new debt. The Company also uses this measure because operating cash flow relates to the timing of cash receipts and disbursements that the Company may not control and may not relate to the period in which the operating activities occurred. Further, Adjusted operating cash flow allows the Company to compare its operating performance and return on capital with those of other companies without regard to financing methods and capital structure. This measure should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with GAAP.

Reconciliation of Free Cash Flow

The Company defines free cash flow as net cash provided by operating activities plus net cash (used in) provided by investing activities less the cash flow impact of acquisitions and divestitures. Free cash flow is a supplemental financial measure used by the Company’s management and by securities analysts, investors, lenders, rating agencies and others who follow the industry as an indicator of the Company’s ability to internally fund exploration and development activities or incur new debt. This measure should not be considered in isolation or as a substitute for net cash provided by operating or investing activities prepared in accordance with GAAP.

Reconciliation of Net Income to EBITDA and Adjusted EBITDA

The Company defines EBITDA as net income before income tax (benefit) expense, interest expense, depreciation and amortization – other and depreciation and depletion – oil and natural gas. Adjusted EBITDA, as presented herein, is EBITDA excluding items that management believes affect the comparability of operating results such as items whose timing and/or amount cannot be reasonably estimated or are non-recurring, as shown in the following tables.

Adjusted EBITDA is presented because management believes it provides useful additional information used by the Company’s management and by securities analysts, investors, lenders, ratings agencies and others who follow the industry for analysis of the Company’s financial and operating performance on a recurring basis and the Company’s ability to internally fund exploration and development activities or incur new debt. In addition, management believes that adjusted EBITDA is widely used by professional research analysts and others in the valuation, comparison and investment recommendations of companies in the oil and gas industry. The Company’s adjusted EBITDA may not be comparable to similarly titled measures used by other companies.

Reconciliation of Net Cash Provided by Operating Activities to Adjusted EBITDA

Reconciliation of Net Income Available to Common Stockholders to Adjusted Net Income Available to Common Stockholders

The Company defines adjusted net income as net income excluding items that management believes affect the comparability of operating results and are typically excluded from published estimates by the investment community, including items whose timing and/or amount cannot be reasonably estimated or are non-recurring, as shown in the following tables.

Management uses the supplemental measure of adjusted net income as an indicator of the Company’s operational trends and performance relative to other oil and natural gas companies and believes it is more comparable to earnings estimates provided by securities analysts. Adjusted net income is not a measure of financial performance under GAAP and should not be considered a substitute for net income available to common stockholders.

Reconciliation of General and Administrative to Adjusted G&A

The Company reports and provides guidance on Adjusted G&A per Boe because it believes this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period and to compare and make investment recommendations of companies in the oil and gas industry. This non-GAAP measure allows for the analysis of general and administrative spend without regard to stock-based compensation programs and other non-recurring cash items, if any, which can vary significantly between companies. Adjusted G&A per Boe is not a measure of financial performance under GAAP and should not be considered a substitute for general and administrative expense per Boe. Therefore, the Company’s Adjusted G&A per Boe may not be comparable to other companies’ similarly titled measures.

The Company defines adjusted G&A as general and administrative expense adjusted for certain non-cash stock-based compensation and other non-recurring items, if any, as shown in the following tables:

Cautionary Note to Investors – 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. These forward-looking statements are neither historical facts nor assurances of future performance and reflect SandRidge’s current beliefs and expectations regarding future events and operating performance. The forward-looking statements include projections and estimates of the Company’s corporate strategies, future operations, development plans and appraisal programs, drilling inventory and locations, estimated oil, natural gas and natural gas liquids production, price realizations and differentials, hedging program, projected operating, general and administrative and other costs, projected capital expenditures, tax rates, efficiency and cost reduction initiative outcomes, liquidity and capital structure and the Company’s unaudited proved developed PV-10 reserve value of its Mid-Continent assets. We have based these forward-looking statements on our current expectations and assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including the volatility of oil and natural gas prices, our success in discovering, estimating, developing and replacing oil and natural gas reserves, actual decline curves and the actual effect of adding compression to natural gas wells, the availability and terms of capital, the ability of counterparties to transactions with us to meet their obligations, our timely execution of hedge transactions, credit conditions of global capital markets, changes in economic conditions, the amount and timing of future development costs, the availability and demand for alternative energy sources, regulatory changes, including those related to carbon dioxide and greenhouse gas emissions, and other factors, many of which are beyond our control. We refer you to the discussion of risk factors in Part I, Item 1A – “Risk Factors” of our Annual Report on Form 10-K and in comparable “Risk Factor” sections of our Quarterly Reports on Form 10-Q filed after such form 10-K. All of the forward-looking statements made in this press release are qualified by these cautionary statements. The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on our Company or our business or operations. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements. We undertake no obligation to update or revise any forward-looking statements.

SandRidge Energy, Inc. (NYSE: SD) is an independent oil and gas company engaged in the development, acquisition and production of oil and gas properties. Its primary area of operations is the Mid-Continent region in Oklahoma and Kansas. Further information can be found at www.sandridgeenergy.com.

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SOURCE SANDRIDGE ENERGY, INC.

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The post SANDRIDGE ENERGY, INC. ANNOUNCES FINANCIAL AND OPERATING RESULTS FOR THE THREE-MONTH PERIOD ENDED MARCH 31, 2024 AND DECLARES $0.11 PER SHARE CASH DIVIDEND appeared first on Energy News Beat.

 

Energy News Beat

LONG BEACH, Calif., May 07 /BusinessWire/ — California Resources Corporation (NYSE:CRC) today reported financial and operating results for the first quarter 2024. The Company plans to host a conference call and webcast on Wednesday, May 8th at 1:00 p.m. Eastern Time (10:00 a.m. Pacific Time). Participation details can be found within this release. In addition, supplemental slides are posted to CRC’s website at www.crc.com.

First Quarter 2024 Highlights:

Returned $79 million to shareholders through share repurchases and dividends
Reported $87 million of net cash from operating activities
Net cash provided by operating activities before changes in operating assets and liabilities, net1 of $92 million includes $25 million of costs related to the Aera transaction and incremental energy costs due to scheduled power plant major maintenance
Reported net loss of $10 million, or $0.14 per diluted share. When adjusted for items analysts typically exclude from estimates (including mark-to-market adjustments of $59 million, one-time costs for Aera Merger of $13 million and increased power and fuel costs due to power plant shutdown of $21 million all of which is before taxes), the Company’s adjusted net income1 was $54 million, or $0.75 per diluted share
Generated an adjusted EBITDAX1 of $149 million and $33 million of free cash flow1
Flat entry to exit gross production of 94 thousand barrels of oil equivalent per day (MBoe/d) after investing drilling and workover capital of $22 million
Delivered average quarterly net production of 76 MBoe/d and net oil production of 48 thousand barrels of oil per day (MBo/d)
The Carbon TerraVault JV achieved the milestone for the second installment related to “CTV I – 26R” reservoir pore space contribution in the amount of $46 million. See CTV’s First Quarter 2024 Update press release for additional information
Announced the expiration of the required waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 with respect to the pending combination upon the completion of which Aera Energy, LLC (Aera) and its operating affiliate Aera Energy Services Company will be indirect wholly-owned subsidiaries of CRC (Aera Merger)
Received “Grade A” certification through MiQ’s Methane Emissions Performance Standard for CRC’s operating assets in Los Angeles and Orange Counties

“Our solid first quarter performance adds to CRC’s historical track record of unwavering commitment to shareholder returns and effective cost management,” said Francisco Leon, CRC’s President and Chief Executive Officer. “CRC’s improved cost structure demonstrates the fundamental improvements we’ve made to our business, reflecting our readiness to combine with Aera while driving a higher level of efficiency and effectiveness throughout the organization. I want to thank all of our employees as the foundation of CRC’s continued success comes from their ongoing diligent efforts and hard work”

“With company’s operations successfully scaled to generate free cash flow, our advantaged balance sheet position has allowed us to accelerate the return of capital to shareholders and return more than double of our quarterly free cash flow1 back to investors,” continued Leon. “Looking ahead to the remainder of the year, we remain focused on closing the Aera Merger, further expanding our carbon management business and continuing to provide innovative energy solutions to meet California’s energy needs.”

First Quarter 2024 Financial and Operating Summary

Net loss for the period was $10 million, or $0.14 per diluted share of common stock, and adjusted net income1 was $54 million, or $0.75 per diluted share. The Company reported first quarter net cash from operating activities of $87 million. Adjusted EBITDAX1 was $149 million. Net cash provided by operating activities before changes in operating assets and liabilities, net1, of $92 million includes Aera Merger expenses of $13 million and incremental energy costs due to the scheduled Elk Hills power plant major maintenance of $12 million. CRC generated $33 million of free cash flow1 during the quarter.

CRC’s gross production in the first quarter averaged 94 MBoe/d. Net production averaged 76 MBoe/d, including net oil production of 48 MBo/d. A longer than expected Elk Hills power plant major maintenance, challenging weather conditions and PSC effects adversely affected net production in the first quarter of 2024 by 1.5 MBoe/d from previously issued guidance. Average realized oil prices during the quarter were 98% of Brent.

Operating costs in the first quarter of 2024 were $176 million compared to $186 million in the fourth quarter of 2023 primarily due to lower electricity and natural gas prices.

Capital in the first quarter of 2024 was lower than previously issued guidance due to anticipated facility and workover spend, and totaled $54 million. CRC ran a one-rig program in the San Joaquin basin during the period.

First Quarter 2024 Financial Results

Certain prior period balances related to NGL marketing activities have been reclassified to conform to CRC’s 2024 presentation. For the three months ended December 31, 2023, CRC reclassified $4 million related to NGL storage activities from other revenue to revenue from marketing of purchased commodities on the condensed consolidated statement of operations. CRC also reclassified $3 million of NGL processing fees from other operating expenses, net to costs related to marketing of purchased commodities.

Selected Production, Price Information and Results of Operations

1st Quarter

4th Quarter

($ in millions)

2024

2023

Average net oil production per day (MBbl/d)

48

50

Realized oil price with derivative settlements ($ per Bbl)

$

77.17

$

71.34

Average net NGL production per day (MBbl/d)

11

11

Realized NGL price ($ per Bbl)

$

50.50

$

49.08

Average net natural gas production per day (Mmcf/d)

105

130

Realized natural gas price with derivative settlements ($ per Mcf)

$

3.90

$

4.66

Average net total production per day (MBoe/d)

76

83

Margin from marketing of purchased commodities ($ millions)

$

20

$

29

Margin from electricity sales ($ millions)

$

7

$

24

Net gain (loss) from oil commodity derivatives ($ millions)

$

(71

)

$

119

Selected Financial Statement Data and non-GAAP measures:

1st Quarter

4th Quarter

($ and shares in millions, except per share amounts)

2024

2023

Statements of Operations:

Revenues

Total operating revenues

$

454

$

726

Selected Expenses

Operating costs

$

176

$

186

General and administrative expenses

$

57

$

66

Adjusted general and administrative expenses1

$

49

$

55

Taxes other than on income

$

38

$

33

Transportation costs

$

20

$

18

Operating Income (loss)

$

(4

)

$

283

Interest and debt expense

$

(13

)

$

(13

)

Income tax benefit (provision)

$

9

$

(79

)

Net (loss) Income

$

(10

)

$

188

EPS, Non-GAAP Measures and Select Balance Sheet Data

Adjusted net income1

$

54

$

67

Weighted-average common shares outstanding – diluted

69.0

72.3

Net loss (income) per share – diluted

$

(0.14

)

$

2.60

Adjusted net income1 per share – diluted

$

0.75

$

0.93

Adjusted EBITDAX1

$

149

$

179

Net cash provided by operating activities

$

87

$

131

Net cash provided by operating activities before changes in operating assets and liabilities, net1

$

92

$

104

Capital investments

$

54

$

66

Free cash flow1

$

33

$

65

Cash and cash equivalents

$

403

$

496

Pending Aera Merger

On February 7, 2024, CRC entered into a definitive agreement and plan of merger (Merger Agreement) to combine with Aera in an all-stock transaction with an effective date of January 1, 2024. Aera is a leading operator of mature fields in California, primarily in the San Joaquin and Ventura basins, with high oil-weighted production. At closing, Aera’s owners will receive 21.2 million shares of CRC’s common stock plus an additional number of shares determined by reference to the dividends declared by CRC having a record date between the effective date and closing. CRC also agreed to assume Aera’s outstanding long-term indebtedness of $950 million. CRC expects to repay a significant portion of this indebtedness with cash on hand and borrowings under its revolving credit facility. CRC expects to refinance the balance through one or more debt capital markets transactions and, only to the extent necessary, borrowings under a bridge loan facility.

On March 26, 2024, CRC announced the expiration of the required waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 with respect to the pending Aera Merger.

On May 7, 2024, CRC filed the definitive proxy statement for the Aera Merger with the SEC. Closing of the Aera Merger is subject to certain closing conditions, including among others, regulatory approvals and CRC shareholder approval, and is expected to close around mid-year 2024.

For more information about this transaction please visit: https://www.crc.com/news/news-details/2024/California-Resources-Corporation-to-Combine-with-Aera-Energy/default.aspx

2024 Capital Outlook, Second Quarter 2024 Guidance and Capital Program2

CRC’s 2024 guidance estimates exclude the pending Aera Merger. The Company intends to update guidance after the transaction closes.

Following the March 2024 Court of Appeals decision in the Kern County Environmental Impact Report matter, CRC expects its 2024 capital program to range between $200 million and $240 million under current permitting conditions. Of this amount, $165 million to $185 million is related to oil and natural gas development (including $20 million to $25 million for maintenance at CRC’s Elk Hills gas processing plant), $20 million to $25 million is for carbon management projects and $15 million to $30 million is for corporate and other (including $10 million to $15 million related to maintenance at CRC’s Elk Hills power plant). In 2024, CRC expects to run a one rig program while executing projects using existing permits.

2024 PRELIMINARY OUTLOOK2

TOTAL 2024E

Net Production (MBoe/d)

75 – 79

Oil Production (%)

~61%

Capital ($ millions)

$200 – $240

Drilling & completions, workover ($ millions)

$100 – $110

Facilities ($ millions)

$45 – $50

Maintenance of gas processing and power plants at Elk Hills ($ millions)

$30 – $40

Carbon management business ($ millions)

$20- $25

Corporate & other ($ millions)

$5 – $15

CRC expects its second quarter capital program to range between $50 million to $57 million. The program includes capital of $45 million to $49 million related to oil and natural gas development (including $4 million to $8 million related to maintenance at CRC’s Elk Hills gas processing plant), $3 million to $5 million related to carbon management projects and $2 million to $3 million related to corporate and other activities.

CRC expects to produce 74 to 78 MBoe/d (~61% oil) in the second quarter of 2024. The table below provides highlights of the Company’s second quarter 2024 guidance. See Attachment 2 for complete information on CRC’s second quarter 2024 guidance.

CRC GUIDANCE2

Total

2Q24E

CMB

2Q24E

E&P, Corp. & Other 2Q24E

Net Production (MBoe/d)

74 – 78

74 – 78

CMB Expenses and Operating Costs ($ millions)

$170 – $183

$10 – $13

$160 – $170

General and Administrative Expenses ($ millions)

$56 – $64

$1 – $3

$55 – $61

Adjusted General and Administrative Expenses1 ($ millions)

$49 – $57

$1 – $3

$48 – $54

Capital ($ millions)

$50 – $57

$3 – $5

$47 – $52

Margin from Marketing of Purchased Commodities ($ millions) 3

$5 – $15

$5 – $15

Electricity Margin ($ millions)4

$34 – $42

$34 – $42

Shareholder Return

CRC is committed to returning significant cash to shareholders through dividends and repurchases of its common stock.

During the first quarter of 2024, CRC repurchased 1.1 million shares for $58 million or an average price of $53.26 per share. Post quarter end and through May 3, 2024, CRC repurchased an additional 0.3 million shares for $15 million or an average price of $54.80. Since the inception of the Share Repurchase Program in May 2021 through May 3, 2024, 16.2 million shares have been repurchased for $675 million at an average price of $41.61 per share. These total repurchases represent 19% of CRC’s shares outstanding at its bankruptcy emergence in October 2020.

In February 2024, CRC’s Board of Directors approved a $250 million increase of the Share Repurchase Program, bringing the aggregate program to $1.35 billion, and extended the program through December 31, 2025. Adjusting for this increase, CRC has approximately $675 million of capacity remaining under the repurchase program as of May 7, 2024.

On May 7, 2024, CRC’s Board of Directors declared a quarterly cash dividend of $0.31 per share of common stock. The dividend is payable to shareholders of record on May 31, 2024 and will be paid on June 14, 2024. Post closing of the Aera Merger, and subject to Board approval, CRC expects to increase its quarterly dividend.

From October 2020 through May 7, 2024, CRC has returned $905 million of cash to its stakeholders, including $675 million in share repurchases, $175 million of dividends and $55 million in principal of its Senior Notes repurchases.

Balance Sheet and Liquidity Update

In connection with the Merger Agreement, on February 9, 2024, CRC entered into a second amendment to its Revolving Credit Facility to permit CRC to incur debt under a bridge loan facility that may be used in connection with closing the Aera Merger.

In March 2024, CRC entered into a third amendment to its Revolving Credit Facility. The amendment facilitated certain matters with respect to the Aera Merger, including the postponement of the regular spring borrowing base redetermination until the fall of 2024 and certain other amendments.

Additionally, CRC obtained commitments from its existing lenders and certain new lenders to amend CRC’s Revolving Credit Facility upon closing of the Aera Merger. These commitments include increasing its borrowing base from $1.2 billion to $1.5 billion, increasing the aggregate commitment amount from $630 million to $1.1 billion, and other matters.

As of March 31, 2024, CRC had liquidity of $880 million, which consisted of $403 million in cash and cash equivalents plus $477 million of available borrowing capacity under its Revolving Credit Facility (which is after $153 million of outstanding letters of credit).

Acquisitions and Divestitures

In March 2024, CRC sold its 0.9-acre Fort Apache real estate property in Huntington Beach, California for a purchase price of $10 million and recognized a $6 million gain.

Sustainability

In April, 2024, CRC received a “Grade A” certification through MiQ’s Methane Emissions Performance Standard for CRC’s operating assets in Los Angeles and Orange Counties. MiQ is an independent not-for-profit established to facilitate a rapid reduction in methane emissions from the oil and gas sector. This certification is the first “Grade A” independently certified gas (ICG) designation that MiQ has presented to oil and natural gas operating assets in California and the Rocky Mountain region. The achievement further demonstrates CRC’s dedication to its ESG goals and sustainability platform. CRC plans to continue to work with MiQ to expand its ICG certifications to operations in the San Joaquin and Sacramento basins.

Board Changes

On May 3, 2024, CRC’s shareholders elected one new Board member, Christian S. Kendall.

Mr. Kendall is the former President and Chief Executive Officer of Denbury. Prior to joining Denbury in 2015, Mr. Kendall worked at Noble Energy, Inc., where he served as a member of Noble’s executive management and operations leadership team as Senior Vice President, Global Operations Services. Prior to that, Mr. Kendall served in several other executive and management roles of increasing responsibility with Noble beginning in 2001. Mr. Kendall’s career in the oil and natural gas industry began in 1989 at Mobil Oil Corporation. Mr. Kendall has served as the Chairman of the Board of the Dallas Division of the American Heart Association and is a member of National Petroleum Council. Mr. Kendall holds a Bachelor of Science degree in Engineering with a Civil Specialty from the Colorado School of Mines and has also completed the Advanced Management Program at the Harvard Business School. Please see www.crc.com for more details.

As previously disclosed, Julio M. Quintana, who has served as a member of CRC’s Board of Directors since October 2020, did not seek reelection as a Director at the 2024 Annual Meeting. CRC thanks Mr. Quintana for his outstanding leadership, knowledge, and contributions to the Company throughout his tenure on the Board of Directors and wish him all the best.

Upcoming Investor Conference Participation

CRC’s executives will be participating in the following events in May through July 2024:

Goldman Sachs Ninth Annual Leveraged Finance and Credit Conference on May 13 and 14 in Rancho Palos Verdes, CA
2024 Citi Energy & Climate Technology Conference on May 14 to 15 in Boston, MA
TD Cowen’s 2nd Annual Sustainability Week on May 21 held virtually
Stifel 2024 Cross Sector Insights Conference on June 3 in Boston, MA
RBC Capital Markets Global Energy, Power & Infrastructure Conference on June 5 in New York, NY
BofA Securities Energy Credit Conference on June 6 in New York, NY
2024 JP Morgan Energy, Power & Renewables Conference on June 17 to 18 in New York, NY
2024 TD Calgary Energy Conference on July 9 to 10 in Calgary, AB, Canada

CRC’s presentation materials will be available the day of the events on the Events and Presentations page in the Investor Relations section on www.crc.com.

Conference Call Details

A conference call is scheduled for Wednesday, May 8, 2024 at 1:00 p.m. Eastern Time (10:00 a.m. Pacific Time). To participate in the call, please dial (877) 328-5505 (International calls please dial +1 (412) 317-5421) or access via webcast at www.crc.com 15 minutes prior to the scheduled start time to register. Participants may also pre-register for the conference call at https://dpregister.com/sreg/10187009/fbc013eb9d. A digital replay of the conference call will be archived for approximately 90 days and supplemental slides for the conference call will be available online in the Investor Relations section of www.crc.com.

1 See Attachment 3 for the non-GAAP financial measures of operating costs per BOE (excluding effects of PSCs), adjusted net income (loss), adjusted net income (loss) per share – basic and diluted, net cash provided by operating activities before changes in operating assets and liabilities, net, adjusted EBITDAX, free cash flow and adjusted G&A, including reconciliations to their most directly comparable GAAP measure, where applicable. For the 2Q24 estimates of the non-GAAP measure of adjusted general and administrative expenses, including reconciliations to its most directly comparable GAAP measure, see Attachment 2.

2 2Q24 guidance assumes Brent price of $86.17 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $1.78 per mcf. CRC’s share of production under PSC contracts decreases when commodity prices rise and increases when prices fall.

3 Margin from Marketing of Purchased Commodities is calculated as the difference between Revenue from Marketing of Purchased Commodities and Costs Related to Marketing of Purchased Commodities

4 Electricity Margin is calculated as the difference between Electricity Sales and Electricity Generation Expenses

About California Resources Corporation

California Resources Corporation (CRC) is an independent energy and carbon management company committed to energy transition. CRC produces some of the lowest carbon intensity production in the US and is focused on maximizing the value of its land, mineral and technical resources for decarbonization by developing CCS and other emissions reducing projects. For more information about CRC, please visit www.crc.com.

About Carbon TerraVault

Carbon TerraVault Holdings, LLC (CTV), a subsidiary of CRC, provides services that include the capture, transport and storage of carbon dioxide for its customers. CTV is engaged in a series of carbon capture and storage (CCS) projects that inject CO2 captured from industrial sources into depleted underground reservoirs and permanently store CO2 deep underground. For more information about CTV, please visit www.carbonterravault.com.

Additional Information and Where to Find It

This communication may be deemed to be solicitation material in respect of the transactions contemplated by the merger agreement pursuant to which California Resources Corporation (“CRC”) has agreed to combine with Aera Energy, LLC (“Aera”) (the “Merger Agreement”), including the proposed issuance of CRC’s common stock pursuant to the Merger Agreement. In connection with the transaction, CRC filed a proxy statement on Schedule 14A with the U.S. Securities and Exchange Commission (“SEC”), as well as other relevant materials. Following the filing of the definitive proxy statement, CRC mailed the definitive proxy statement and a proxy card to its stockholders. INVESTORS AND SECURITY HOLDERS OF CRC ARE URGED TO READ THE PROXY STATEMENT AND OTHER RELEVANT DOCUMENTS FILED OR TO BE FILED WITH THE SEC CAREFULLY WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT CRC, AERA, THE TRANSACTION AND RELATED MATTERS. Investors and security holders will be able to obtain copies of the proxy statement (when available) as well as other filings containing information about CRC, Aera and the transaction, without charge, at the SEC’s website, www.sec.gov. Copies of documents filed with the SEC by CRC will be available, without charge, at CRC’s website, www.crc.com.

Participants in Solicitation

CRC and its directors and executive officers may be deemed to be participants in the solicitation of proxies in connection with the transaction. Information about the directors and executive officers of CRC is set forth in the proxy statement for CRC’s 2024 Annual Meeting of Stockholders, which was filed with the SEC on March 21, 2024. Investors may obtain additional information regarding the interest of such participants by reading the proxy statement regarding the transaction when it becomes available.

Forward-Looking Statements

This document contains statements that CRC believes to be “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 historical facts are forward-looking statements, and include statements regarding its future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and plans and objectives of management for the future. Words such as “expect,” “could,” “may,” “anticipate,” “intend,” “plan,” “ability,” “believe,” “seek,” “see,” “will,” “would,” “estimate,” “forecast,” “target,” “guidance,” “outlook,” “opportunity” or “strategy” or similar expressions are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements. Additionally, the information in this report contains forward-looking statements related to the recently announced Aera Merger.

Although CRC believes the expectations and forecasts reflected in its forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond the company’s control. No assurance can be given that such forward-looking statements will be correct or achieved or that the assumptions are accurate or will not change over time. Particular uncertainties that could cause CRC’s actual results to be materially different than those expressed in its forward-looking statements include:

fluctuations in commodity prices, including supply and demand considerations for CRC’s products and services;
decisions as to production levels and/or pricing by OPEC or U.S. producers in future periods;
government policy, war and political conditions and events, including the military conflicts in Israel, Ukraine and Yemen and the Red Sea;
the ability to successfully integrate the business of Aera once the Aera Merger is completed;
the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the Aera Merger that could reduce anticipated benefits or cause the parties to abandon the Aera Merger;
the occurrence of any event, change or other circumstances that could give rise to the termination of the Merger Agreement;
the possibility that the stockholders of CRC may not approve the issuance of new shares of common stock in the Aera Merger;
the ability to obtain the required debt financing pursuant to CRC’s commitment letters and, if obtained, the potential impact of additional debt on its business and the financial impacts and restrictions due to the additional debt;
regulatory actions and changes that affect the oil and gas industry generally and CRC in particular, including (1) the availability or timing of, or conditions imposed on, permits and approvals necessary for drilling or development activities or its carbon management business; (2) the management of energy, water, land, greenhouse gases (GHGs) or other emissions, (3) the protection of health, safety and the environment, or (4) the transportation, marketing and sale of the company’s products;
the impact of inflation on future expenses and changes generally in the prices of goods and services;
changes in business strategy and CRC’s capital plan;
lower-than-expected production or higher-than-expected production decline rates;
changes to CRC’s estimates of reserves and related future cash flows, including changes arising from the inability to develop such reserves in a timely manner, and any inability to replace such reserves;
the recoverability of resources and unexpected geologic conditions;
general economic conditions and trends, including conditions in the worldwide financial, trade and credit markets;
production-sharing contracts’ effects on production and operating costs;
the lack of available equipment, service or labor price inflation;
limitations on transportation or storage capacity and the need to shut-in wells;
any failure of risk management;
results from operations and competition in the industries in which CRC operates;
the ability to realize the anticipated benefits from prior or future efforts to reduce costs;
environmental risks and liability under federal, regional, state, provincial, tribal, local and international environmental laws and regulations (including remedial actions);
the creditworthiness and performance of CRC’s counterparties, including financial institutions, operating partners, CCS project participants and other parties;
reorganization or restructuring of CRC’s operations;
the ability to claim and utilize tax credits or other incentives in connection with CRC’s CCS projects;
the ability to realize the benefits contemplated by CRC’s energy transition strategies and initiatives, including CCS projects and other renewable energy efforts;
the ability to successfully identify, develop and finance carbon capture and storage projects and other renewable energy efforts, including those in connection with the Carbon TerraVault JV, and the ability to convert CRC’s CDMAs to definitive agreements and enter into other offtake agreements;
the ability to maximize the value of CRC’s carbon management business and operate it on a stand alone basis;
the ability to successfully develop infrastructure projects and enter into third party contracts on contemplated terms;
uncertainty around the accounting of emissions and the ability to successfully gather and verify emissions data and other environmental impacts;
changes to CRC’s dividend policy and share repurchase program, and the ability to declare future dividends or repurchase shares under its debt agreements;
limitations on CRC’s financial flexibility due to existing and future debt;
insufficient cash flow to fund CRC’s capital plan and other planned investments and return capital to shareholders;
changes in interest rates;
CRC’s access to and the terms of credit in commercial banking and capital markets, including the ability to refinance its debt or obtain separate financing for its carbon management business;
changes in state, federal or international tax rates, including the ability to utilize net operating loss carryforwards to reduce CRC’s income tax obligations;
effects of hedging transactions;
the effect of CRC’s stock price on costs associated with incentive compensation;
inability to enter into desirable transactions, including joint ventures, divestitures of oil and natural gas properties and real estate, and acquisitions, and the ability to achieve any expected synergies;
disruptions due to earthquakes, forest fires, floods, extreme weather events or other natural occurrences, accidents, mechanical failures, power outages, transportation or storage constraints, labor difficulties, cybersecurity breaches or attacks or other catastrophic events;
pandemics, epidemics, outbreaks, or other public health events, such as the COVID-19 pandemic; and
other factors discussed in Part I, Item 1A – Risk Factors in CRC’s 2023 Annual Report.

CRC cautions you not to place undue reliance on forward-looking statements contained in this document, which speak only as of the filing date, and it undertakes no obligation to update this information. This document may also contain information from third party sources. This data may involve a number of assumptions and limitations, and CRC has not independently verified them and does not warrant the accuracy or completeness of such third-party information.

Attachment 1

SUMMARY OF RESULTS

1st Quarter

4th Quarter

1st Quarter

($ and shares in millions, except per share amounts)

2024

2023

2023

Statements of Operations:

Revenues

Oil, natural gas and NGL sales

$

429

$

483

$

715

Net (loss) gain from commodity derivatives

(71

)

119

42

Revenue from marketing of purchased commodities

74

71

187

Electricity sales

15

42

68

Other revenue

7

11

12

Total operating revenues

454

726

1,024

Operating Expenses

Operating costs

176

186

254

General and administrative expenses

57

66

65

Depreciation, depletion and amortization

53

55

58

Asset impairment

–

–

3

Taxes other than on income

38

33

42

Exploration expense

1

1

1

Costs related to marketing of purchased commodities

54

42

124

Electricity generation expenses

8

18

49

Transportation costs

20

18

17

Accretion expense

12

11

12

Carbon management business expenses

8

17

5

Other operating expenses, net

37

21

8

Total operating expenses

464

468

638

Net gain on asset divestitures

6

25

7

Operating (Loss) Income

(4

)

283

393

Non-Operating (Expenses) Income

Interest and debt expense

(13

)

(13

)

(14

)

Loss from investment in unconsolidated subsidiary

(3

)

(3

)

(2

)

Net loss on early extinguishment of debt

–

(1

)

–

Other non-operating income (loss), net

1

1

(1

)

(Loss) Income Before Income Taxes

(19

)

267

376

Income tax benefit (provision)

9

(79

)

(75

)

Net (Loss) Income

$

(10

)

$

188

$

301

Net (loss) income per share – basic

$

(0.14

)

$

2.74

$

4.22

Net (loss) income per share – diluted

$

(0.14

)

$

2.60

$

4.09

Adjusted net income

$

54

$

67

$

193

Adjusted net income per share – basic

$

0.78

$

0.98

$

2.71

Adjusted net income per share – diluted

$

0.75

$

0.93

$

2.63

Weighted-average common shares outstanding – basic

69.0

68.7

71.3

Weighted-average common shares outstanding – diluted

69.0

72.3

73.5

Adjusted EBITDAX

$

149

$

179

$

358

Effective tax rate

45

%

30

%

20

%

1st Quarter

4th Quarter

1st Quarter

($ in millions)

2024

2023

2023

Cash Flow Data:

Net cash provided by operating activities

$

87

$

131

$

310

Net cash used in investing activities

$

(49

)

$

(42

)

$

(61

)

Net cash used in financing activities

$

(131

)

$

(72

)

$

(79

)

March 31,

December 31,

($ in millions)

2024

2023

Selected Balance Sheet Data:

Total current assets

$

839

$

929

Property, plant and equipment, net

$

2,793

$

2,770

Deferred tax asset

$

139

$

132

Total current liabilities

$

594

$

616

Long-term debt, net

$

541

$

540

Noncurrent asset retirement obligations

$

429

$

422

Stockholders’ Equity

$

2,093

$

2,219

GAINS AND LOSSES FROM COMMODITY DERIVATIVES

1st Quarter

4th Quarter

1st Quarter

($ millions)

2024

2023

2023

Non-cash derivative (loss) gain

$

(59

)

$

168

$

107

Net payments on settled commodity derivatives

(12

)

(49

)

(65

)

Net (loss) gain from commodity derivatives

$

(71

)

$

119

$

42

CAPITAL INVESTMENTS

1st Quarter

4th Quarter

1st Quarter

($ millions)

2024

2023

2023

Facilities (1)

$

14

$

20

$

9

Drilling

15

16

25

Workovers

7

11

6

Total E&P capital

36

47

40

CMB (1)

4

4

1

Corporate and other

14

15

6

Total capital program

$

54

$

66

$

47

(1) Facilities capital includes $0, $1 million and $1 million in the first quarter of 2024 and fourth and first quarter of 2023, respectively, to build replacement water injection facilities which will allow CRC to divert produced water away from a depleted oil and natural gas reservoir held by the Carbon TerraVault JV. Construction of these facilities supports the advancement of CRC’s carbon management business and CRC reported these amounts as part of adjusted CMB capital in this Earnings Release. Where adjusted CMB capital is presented, CRC removed the amounts from facilities capital and presented adjusted E&P, Corporate and Other capital.

Attachment 2

2024 PRELIMINARY OUTLOOK

Total 2024E

Net Production (MBoe/d)

75 – 79

Oil Production (%)

~61%

Capital ($ millions)

$200 – $240

CRC GUIDANCE

Total

2Q24E

CMB

2Q24E

E&P, Corp. & Other 2Q24E

Net Production (MBoe/d)

74 – 78

74 – 78

Oil Production (%)

~61%

~61%

CMB Expenses & Operating Costs ($ millions)

$170 – $183

$10 – $13

$160 – $170

General and Administrative Expenses ($ millions)

$56 – $64

$1 – $3

$55 – $61

Adjusted General and Administrative Expenses ($ millions)

$49 – $57

$1 – $3

$48 – $54

Capital ($ millions)

$50 – $57

$3 – $5

$47 – $52

Margin from Marketing of Purchased Commodities ($ millions) (1)

$5 – $15

$5 – $15

Electricity Margin ($ millions) (2)

$34 – $42

$34 – $42

Other Operating Revenue & Expenses, net ($ millions)

$0 – $5

$0 – $5

Transportation Costs ($ millions)

$14 – $17

$14 – $17

Taxes Other Than on Income ($ millions) (3)

$44 – $46

$44 – $46

Interest and Debt Expense ($ millions)

$13 – $15

$13 – $15

Commodity Assumptions:

Brent ($/Bbl)

$86.17

$86.17

NYMEX ($/Mcf)

$1.78

$1.78

Oil – % of Brent:

97% – 99%

97% – 99%

NGL – % of Brent:

50% – 55%

50% – 55%

Natural Gas – % of NYMEX:

89% – 93%

89% – 93%

1) Margin from Marketing of Purchased Commodities is calculated as the difference between Revenue from Marketing of Purchased Commodities and Costs Related to Marketing of Purchased Commodities.

(2) Electricity Margin is calculated as the difference between Electricity Sales and Electricity Generation Expenses.

(3) Other Operating Revenue & Expenses, net is calculated as the difference between Other Revenue and Other Operating Expenses, net. Current guidance does not include estimated Aera Merger and integration expenses of $30 – $40 million dependent on the timing of close.

See Attachment 3 for management’s disclosure of its use of these non-GAAP measures and how these measures provide useful information to investors about CRC’s results of operations and financial condition.

ESTIMATED ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES RECONCILIATION

2Q24 Estimated

Consolidated

CMB

E&P, Corporate & Other

($ millions)

Low

High

Low

High

Low

High

General and administrative expenses

$

56

$

64

$

1

$

3

$

55

$

61

Equity-settled stock-based compensation

(6

)

(5

)

(6

)

(5

)

Other

(1

)

(2

)

(1

)

(2

)

Estimated adjusted general and administrative expenses

$

49

$

57

$

1

$

3

$

48

$

54

Attachment 3

NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS

To supplement the presentation of its financial results prepared in accordance with U.S generally accepted accounting principles (GAAP), management uses certain non-GAAP measures to assess its financial condition, results of operations and cash flows. The non-GAAP measures include adjusted net income (loss), adjusted EBITDAX, E&P, Corporate & Other adjusted EBITDAX, CMB adjusted EBITDAX, net cash provided by operating activities before changes in operating assets and liabilities, net, free cash flow, E&P, Corporate & Other free cash flow, CMB free cash flow, adjusted general and administrative expenses, operating costs per BOE, and adjusted total capital among others. These measures are also widely used by the industry, the investment community and CRC’s lenders. Although these are non-GAAP measures, the amounts included in the calculations were computed in accordance with GAAP. Certain items excluded from these non-GAAP measures are significant components in understanding and assessing CRC’s financial performance, such as CRC’s cost of capital and tax structure, as well as the effect of acquisition and development costs of CRC’s assets. Management believes that the non-GAAP measures presented, when viewed in combination with CRC’s financial and operating results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting the Company’s performance. The non-GAAP measures presented herein may not be comparable to other similarly titled measures of other companies. Below are additional disclosures regarding each of the non-GAAP measures reported in this earnings release, including reconciliations to their most directly comparable GAAP measure where applicable.

ADJUSTED NET INCOME (LOSS)

Adjusted net income (loss) and adjusted net income (loss) per share are non-GAAP measures. CRC defines adjusted net income as net income excluding the effects of significant transactions and events that affect earnings but vary widely and unpredictably in nature, timing and amount. These events may recur, even across successive reporting periods. Management believes these non-GAAP measures provide useful information to the industry and the investment community interested in comparing CRC’s financial performance between periods. Reported earnings are considered representative of management’s performance over the long term. Adjusted net income (loss) is not considered to be an alternative to net income (loss) reported in accordance with GAAP. The following table presents a reconciliation of the GAAP financial measure of net income and net income attributable to common stock per share to the non-GAAP financial measure of adjusted net income and adjusted net income per share.

1st Quarter

4th Quarter

1st Quarter

($ millions, except per share amounts)

2024

2023

2023

Net (loss) income

$

(10

)

$

188

$

301

Unusual, infrequent and other items:

Non-cash derivative loss (gain)

59

(160

)

(107

)

Asset impairment

–

–

3

Severance and termination costs

–

–

1

Aera Merger transaction fees

10

–

–

Aera Merger integration fees

3

–

–

Increased power and fuel costs due to power plant shutdown

21

–

–

Net loss on early extinguishment of debt

–

1

–

Net gain on asset divestitures

(6

)

(25

)

(7

)

Other, net

2

16

3

Total unusual, infrequent and other items

89

(168

)

(107

)

Income tax (benefit) provision of adjustments at effective tax rate

(25

)

47

30

Income tax (benefit) provision – out of period

–

–

(31

)

Adjusted net income

$

54

$

67

$

193

Net (loss) income per share – basic

$

(0.14

)

$

2.74

$

4.22

Net (loss) income per share – diluted

$

(0.14

)

$

2.60

$

4.09

Adjusted net income per share – basic

$

0.78

$

0.98

$

2.71

Adjusted net income per share – diluted

$

0.75

$

0.93

$

2.63

ADJUSTED EBITDAX

CRC defines Adjusted EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; other unusual, infrequent and out-of-period items; and other non-cash items. CRC believes this measure provides useful information in assessing its financial condition, results of operations and cash flows and is widely used by the industry, the investment community and its lenders. Although this is a non-GAAP measure, the amounts included in the calculation were computed in accordance with GAAP. Certain items excluded from this non-GAAP measure are significant components in understanding and assessing CRC’s financial performance, such as its cost of capital and tax structure, as well as depreciation, depletion and amortization of CRC’s assets. This measure should be read in conjunction with the information contained in CRC’s financial statements prepared in accordance with GAAP. A version of Adjusted EBITDAX is a material component of certain of its financial covenants under CRC’s Revolving Credit Facility and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP.

The following table represents a reconciliation of the GAAP financial measures of net income and net cash provided by operating activities to the non-GAAP financial measure of adjusted EBITDAX. CRC has supplemented its non-GAAP measures of consolidated adjusted EBITDAX with adjusted EBITDAX for its exploration and production and corporate items (Adjusted EBITDAX for E&P, Corporate & Other) which management believes is a useful measure for investors to understand the results of the core oil and gas business. CRC defines adjusted EBITDAX for E&P, Corporate & Other as consolidated adjusted EBITDAX less results attributable to its carbon management business (CMB).

1st Quarter

4th Quarter

1st Quarter

($ millions, except per BOE amounts)

2024

2023

2023

Net (loss) income

$

(10

)

$

188

$

301

Interest and debt expense

13

13

14

Depreciation, depletion and amortization

53

55

58

Income tax (benefit) provision

(9

)

79

75

Exploration expense

1

1

1

Interest income

(6

)

(7

)

(4

)

Unusual, infrequent and other items (1)

89

(168

)

(107

)

Non-cash items

Accretion expense

12

11

12

Stock-based compensation

5

6

7

Post-retirement medical and pension

1

1

1

Adjusted EBITDAX

$

149

$

179

$

358

Net cash provided by operating activities

$

87

$

131

$

310

Cash interest payments

21

1

23

Cash interest received

(6

)

(7

)

(4

)

Cash income taxes

22

41

–

Exploration expenditures

1

1

1

Adjustments to changes in operating assets and liabilities

24

12

28

Adjusted EBITDAX

$

149

$

179

$

358

E&P, Corporate & Other Adjusted EBITDAX

$

162

$

199

$

367

CMB Adjusted EBITDAX

$

(13

)

$

(20

)

$

(9

)

Adjusted EBITDAX per Boe

$

21.47

$

23.57

$

44.55

(1) See Adjusted Net Income (Loss) reconciliation.

FREE CASH FLOW AND SUPPLEMENTAL CASH FLOW MEASURES

Management uses free cash flow, which is defined by CRC as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of CRC’s net cash provided by operating activities to free cash flow. CRC supplemented its non-GAAP measure of free cash flow with (i) net cash provided by operating activities before changes in operating assets and liabilities, net, (ii) adjusted free cash flow, and (iii) free cash flow of exploration and production, and corporate and other items (Free Cash Flow for E&P, Corporate & Other), which it believes is a useful measure for investors to understand the results of CRC’s core oil and gas business. CRC defines Free Cash Flow for E&P, Corporate & Other as consolidated free cash flow less results attributable to its carbon management business (CMB). CRC defines adjusted free cash flow as net cash provided by operating activities less adjusted capital investments.

1st Quarter

4th Quarter

1st Quarter

($ millions)

2024

2023

2023

Net cash provided by operating activities before changes in operating assets and liabilities, net

$

92

$

104

$

316

Changes in operating assets and liabilities, net

(5

)

27

(6

)

Net cash provided by operating activities

87

131

310

Capital investments

(54

)

(66

)

(47

)

Free cash flow

$

33

$

65

$

263

E&P, Corporate and Other

$

50

$

84

$

270

CMB

$

(17

)

$

(19

)

$

(7

)

Adjustments to capital investments:

Replacement water facilities(1)

$

–

$

1

$

1

Adjusted capital investments:

E&P, Corporate and Other

$

50

$

61

$

45

CMB

$

4

$

5

$

2

Adjusted free cash flow:

E&P, Corporate and Other

$

50

$

85

$

271

CMB

$

(17

)

$

(20

)

$

(8

)

(1) Facilities capital includes $0, $1 million and $1 million in the first quarter of 2024 and fourth and first quarter of 2023, respectively, to build replacement water injection facilities which will allow CRC to divert produced water away from a depleted oil and natural gas reservoir held by the Carbon TerraVault JV. Construction of these facilities supports the advancement of CRC’s carbon management business and CRC reported these amounts as part of adjusted CMB capital in this press release. Where adjusted CMB capital is presented, CRC removed the amounts from facilities capital and presented adjusted E&P, Corporate and Other capital.

ADJUSTED GENERAL & ADMINISTRATIVE EXPENSES

Management uses a measure called adjusted general and administrative (G&A) expenses to provide useful information to investors interested in comparing CRC’s costs between periods and performance to our peers. CRC supplemented its non-GAAP measure of adjusted general and administrative expenses with adjusted general and administrative expenses of its exploration and production and corporate items (adjusted general & administrative expenses for E&P, Corporate & Other) which it believes is a useful measure for investors to understand the results or CRC’s core oil and gas business. CRC defines adjusted general & administrative Expenses for E&P, Corporate & Other as consolidated adjusted general and administrative expenses less results attributable to its carbon management business (CMB).

1st Quarter

4th Quarter

1st Quarter

($ millions)

2024

2023

2023

General and administrative expenses

$

57

$

66

$

65

Stock-based compensation

(5

)

(6

)

(7

)

Information technology infrastructure

(2

)

(4

)

(3

)

Other

(1

)

(1

)

–

Adjusted G&A expenses

$

49

$

55

$

55

E&P, Corporate and Other adjusted G&A expenses

$

47

$

53

$

52

CMB adjusted G&A expenses

$

2

$

2

$

3

OPERATING COSTS PER BOE

The reporting of PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only CRC’s net share, inflating the per barrel operating costs. The following table presents operating costs after adjusting for the excess costs attributable to PSCs.

1st Quarter

4th Quarter

1st Quarter

($ per BOE)

2024

2023

2023

Energy operating costs (1)

$

8.07

$

8.65

$

15.56

Gas processing costs (2)

0.58

0.60

0.62

Non-energy operating costs

17.15

15.24

15.43

Operating costs

$

25.80

$

24.49

$

31.61

Costs attributable to PSCs

Excess energy operating costs attributable to PSCs

$

(0.99

)

$

(1.01

)

$

(1.19

)

Excess non-energy operating costs attributable to PSCs

(1.55

)

(1.32

)

(1.04

)

Excess costs attributable to PSCs

$

(2.54

)

$

(2.33

)

$

(2.23

)

Energy operating costs, excluding effect of PSCs (1)

$

7.08

$

7.64

$

14.37

Gas processing costs, excluding effect of PSCs (2)

0.58

0.60

0.62

Non-energy operating costs, excluding effect of PSCs

15.60

13.92

14.39

Operating costs, excluding effects of PSCs

$

23.26

$

22.16

$

29.38

(1) Energy operating costs consist of purchased natural gas used to generate electricity for operations and steamfloods, purchased electricity and internal costs to generate electricity used in CRC’s operations.

(2) Gas processing costs include costs associated with compression, maintenance and other activities needed to run CRC’s gas processing facilities at Elk Hills.

Attachment 4

PRODUCTION STATISTICS

1st Quarter

4th Quarter

1st Quarter

Net Production Per Day

2024

2023

2023

Oil (MBbl/d)

San Joaquin Basin

30

32

35

Los Angeles Basin

18

18

20

Total

48

50

55

NGLs (MBbl/d)

San Joaquin Basin

11

11

11

Total

11

11

11

Natural Gas (MMcf/d)

San Joaquin Basin

90

114

119

Los Angeles Basin

1

1

1

Sacramento Basin

14

15

16

Total

105

130

136

Total Production (MBoe/d)

76

83

89

Gross Operated and Net Non-Operated

1st Quarter

4th Quarter

1st Quarter

Production Per Day

2024

2023

2023

Oil (MBbl/d)

San Joaquin Basin

34

36

39

Los Angeles Basin

24

25

26

Total

58

61

65

NGLs (MBbl/d)

San Joaquin Basin

11

11

12

Total

11

11

12

Natural Gas (MMcf/d)

San Joaquin Basin

128

129

135

Los Angeles Basin

7

8

7

Sacramento Basin

17

18

20

Total

152

155

162

Total Production (MBoe/d)

94

98

103

Attachment 5

PRICE STATISTICS

1st Quarter

4th Quarter

1st Quarter

2024

2023

2023

Oil ($ per Bbl)

Realized price with derivative settlements

$

77.17

$

71.34

$

63.04

Realized price without derivative settlements

$

80.16

$

82.00

$

78.68

NGLs ($/Bbl)

$

50.50

$

49.08

$

58.88

Natural gas ($/Mcf)

Realized price with derivative settlements

$

3.90

$

4.66

$

21.56

Realized price without derivative settlements

$

3.90

$

4.66

$

21.56

Index Prices

Brent oil ($/Bbl)

$

81.84

$

82.69

$

82.22

WTI oil ($/Bbl)

$

76.96

$

78.32

$

76.13

NYMEX average monthly settled price ($/MMBtu)

$

2.24

$

2.88

$

3.42

Realized Prices as Percentage of Index Prices

Oil with derivative settlements as a percentage of Brent

94

%

86

%

77

%

Oil without derivative settlements as a percentage of Brent

98

%

99

%

96

%

Oil with derivative settlements as a percentage of WTI

100

%

91

%

83

%

Oil without derivative settlements as a percentage of WTI

104

%

105

%

103

%

NGLs as a percentage of Brent

62

%

59

%

72

%

NGLs as a percentage of WTI

66

%

63

%

77

%

Natural gas with derivative settlements as a percentage of NYMEX contract month average

174

%

162

%

630

%

Natural gas without derivative settlements as a percentage of NYMEX contract month average

174

%

162

%

630

%

Attachment 6

FIRST QUARTER 2024 DRILLING ACTIVITY

San Joaquin

Los Angeles

Ventura

Sacramento

Wells Drilled

Basin

Basin

Basin

Basin

Total

Development Wells

Primary

2

–

–

–

2

Waterflood

–

–

–

–

–

Steamflood

–

–

–

–

–

Total (1)

2

–

–

–

2

(1) Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled.

Attachment 7

OIL HEDGES AS OF MARCH 31, 2024

Q2 2024

Q3 2024

Q4 2024

1H 2025

2H 2025

Sold Calls

Barrels per day

30,000

30,000

29,000

28,000

27,500

Weighted-average Brent price per barrel

$90.07

$90.07

$90.07

$86.88

$86.90

Swaps

Barrels per day

8,875

8,875

5,500

3,500

3,250

Weighted-average Brent price per barrel

$79.28

$80.10

$77.45

$72.81

$72.50

Purchased Puts

Barrels per day

30,000

30,000

29,000

28,000

27,500

Weighted-average Brent price per barrel

$65.17

$65.17

$65.17

$61.43

$61.45

Source: Rbcrichardsonbarr.com

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The post California Resources Reports First Quarter 2024 Financial and Operating Results appeared first on Energy News Beat.