No one had seen anything like this.
Unlike previous downturns, no amount of bracing could save some oil companies from bankruptcy or falling into the arms of peers with stronger balance sheets.
With an oil price war between OPEC+ brewing and a pandemic spreading across the world, the oil and gas industry buckled under the pressure of slowed demand as travel came to a near halt in the spring. Oil prices nosedived. Producers shut in production. Previously trimmed budgets got even thinner, and operators and service providers alike laid off thousands.
The situation, however, appears to have improved—at least as of late summer. Stay-at-home orders intended to slow the spread of COVID-19 eased, and production cuts brought supply and demand closer to balance. Oil prices stabilized around $40/bbl after falling into negative territory.
Yet, the damage is evident, and the potential for more disruption and demand destruction exists.
Planning for the next chapter in the predictably unpredictable oil and gas sector could seem like a tall order—not knowing which direction attempts to slow the global pandemic could swing demand.
However, today’s market turmoil has not blinded executives from long-term company goals. It may have even shed more light on specific paths different types of companies are taking, evidenced by where capital is being directed.
As the industry picks itself up from another fall, technology—which helped drive U.S. shale production to new heights—could focus on autonomous, digital and remote applications, some say.
Given shale’s steep production decline and investor sentiment, conventional assets could return to the spotlight as the energy transition keeps natural gas and renewables on the radar long term. Meanwhile, the inevitability of consolidation and bankruptcies could mean quality acreage in key basins could become available.
While no one knows how energy companies will look post-pandemic, many agree that those that do survive will emerge looking a bit different. For an industry that oftentimes evolves at the pace of sea change, the coronavirus pandemic might indeed force an acceleration.
“Without fundamental change, it will be difficult to return to the attractive industry performance that has historically prevailed,” McKinsey & Co. stated in a May report on the post-COVID-19 oil and gas industry. “On its current course and speed, the industry could now be entering an era defined by intense competition, technology-led rapid supply response, flat to declining demand, investor skepticism, and increasing public and government pressure regarding the impact on climate and the environment. The question of how to create value in the next normal is, therefore, fundamental.”
Making ‘real money’
Even prior to the COVID-19 outbreak and OPEC+ price war that crippled the industry, oil and gas producers, particularly those operating in unconventional development, faced mounting debt issues. Operators found that expensive shale wells showed significant IP but fell off sharply after only a few months, resulting in shortfalls in expected production, and therefore investor returns. As a result, lenders became skeptical and companies responded by slashing their budgets and honing in on only their best assets.
Now, with budgets cut even further and investors looking elsewhere, companies are focusing almost exclusively on their assets that generate cash flow.
Chevron reduced its 2020 capital guidance from $20 billion to $14 billion following the onset of the COVID-19 pandemic and the price war between Saudi Arabia and Russia.
“The focus has really been on short-cycle capital. So capital that was addressing long-term production or long-term value, we largely sustained that,” Chevron CFO Pierre Breber told E&P Plus. “We certainly took haircuts across everything, but the disproportionate reductions were really in the short cycle.”
For Chevron, that meant cuts across its unconventional assets in the Permian Basin and Loma Campana in Argentina’s Vaca Muerta Formation along with its base business in San Joaquin Valley, infill drilling projects and in West Africa.
The company reported an $8.3 billion loss in the second quarter, writing down $5.6 billion on oil and gas assets amid the downturn. Chevron wasn’t alone. So did majors including Eni, Royal Dutch Shell and Total—to name a few. According to IHS Herold, the oil and gas industry cut spending by $24.4 billion in 2020 compared to 2019.
“A growing number of investors are questioning whether today’s oil and gas companies will ever generate acceptable returns,” McKinsey & Co. reported.
For tight oil investments to create value, companies should earn a return on capital employed above 10%, according to James West, senior managing director with Evercore ISI.
Yet, “this industry has proven an inability to do that, particularly in tight oil, particularly in U.S. shale,” he told Hart Energy in a video interview.
Despite pushing U.S. oil production up to about 13 MMbbl/d in January, the U.S. shale industry didn’t fare so well in other areas. Deloitte data show the industry impaired more than $450 billion worth of invested capital, reported net negative free cash flows of $300 billion and has filed more than 190 bankruptcies since 2010.
Deloitte doesn’t have a hurdle rate in mind for an acceptable tight oil return on invested capital, seeing how a global pandemic can destroy demand.
However, “the hurdle rate is going to definitely be impacted if we look at statements from the likes of BlackRock and others,” Duane Dickson, Deloitte’s vice chairman and U.S. oil, gas and chemicals leader, told E&P Plus.
Sustainability will also probably factor more into the return equation, he added.
Investors have not deprioritized sustainability, according to BlackRock, a New York-based investment management company. The firm voted against the management of 53 companies, including 37 energy companies with a combined market cap of nearly $408 billion globally for their “lack of progress on climate, across carbon-intensive sectors” in its 2020 proxy season.
McKinsey & Co. offered that the model for value creation has been led by the supermajors, which focus on scale, strong balance sheets, best-in-class integrated portfolios, advantaged assets and superior operational abilities.
“Basin leadership has also long been a source of distinctiveness and value creation in oil and gas. Similarly, low-cost commodity suppliers with first-quartile assets have also thrived,” the company reported.
As Allen Gilmer, founder of industry analyst Enverus, explained, there are several opportunities for nonmajor oil companies to find value. He pointed out that major oil companies became major oil companies because they developed quality assets in many places, which led to a variety of cash flow opportunities in both oil and gas. Companies capable of doing multiple tasks and doing them well mean they can make “real money,” Gilmer said.
So, who is going to be focused on making real money? The majors? Privately owned companies?
“That’s not to say that they can’t take on debt,” Gilmer added. “But I do think that they definitely need to be focused on how they can make real money and how they do so in an environment that has a fair amount of alpha and beta, with regard to the underlying commodity price of that which they produce.”
Assessing the short and long cycles
Not all companies went into this downturn and pandemic as strong as their peers, with some having much stronger financial positions and far better assets.
“Companies with the strongest balance sheets and the greater number of options are the ones that are focusing on repositioning,” Deloitte’s Dickson said, adding others may need to find a partner or restructure.
Moving forward, the industry also will get a better sense of the role of shale.
“Longer term, is shale an asset that’s easy to turn on and turn off or not?” Dickson said.
Supermajors have found turning their shale assets off is the initial approach to cauterize the wounds that price and demand destruction have wrought. The short-cycle economics for shale offer operators, particularly those that are highly diversified, the option of cutting costs during a downturn without risking long-term financial success.
Even those that are not diversified were forced to curtail their only revenue stream by shutting in production. The slow but steady uptick in demand this summer, coupled with global supply cuts, has allowed those producers to cautiously bring wells back online.
Treadstone Energy Partners II holds about 40,000 acres in the Austin Chalk trend. Founder Frank McCorkle said the company essentially shut down production at the onset of the pandemic.
“We shut in a majority of our production for a couple of months, and we’re just now starting to ramp our production back up,” he said. “We aren’t at full production and probably won’t be at full production until the end of the year. We did that because selling oil at such a low price is just value-destructive to our company. We didn’t have to sell oil, and we didn’t see a need to sell it at extremely low prices.”
Among the lessons that operators can take away from this downturn is a firm understanding of their short-cycle and long-cycle capital commitments, and which of their assets and projects offer financial flexibility during price volatility. But the ability to flex capital between assets is only possible with a diversified portfolio.
“You need to have the types of projects and the types of investments and asset classes that allow you to do that,” Breber said. “And that tends to be unconventional, the infill drilling types of activities where you can withdraw capital, preserve that cash and really save the production for when prices respond and produce when prices are higher.”
Looking ahead, West believes the U.S. shale industry will eventually shrink.
“It’ll be a smaller group of companies, smaller production than we peaked out at late last year,” West told Hart Energy, “and we do think that the incremental barrels that are going to be needed for demand growth over time will come from international markets rather than the shale market.”
Global oil demand could rise 400,000 bbl/d from its outlook in June to 92.1 MMbbl/d, according to the International Energy Agency (IEA).
Oil prices are also a factor.
Although WTI prices have seemingly stabilized in the $40/bbl range, Enverus’ Gilmer expects prices to settle at about the $50/bbl range by the end of the year. If prices continue to climb, the world could be facing more oversupply issues.
“The biggest issue that we have here is when the price of oil reaches $60 to $65 WTI. We have the infrastructure and we have the capability of adding a million barrels a day, year over year and for several years,” Gilmer said. “And that is something that’s going to be really hard for the planet to get around. And it’s relatively quick to come online. So we believe that that’s the buffer on the upside.”
Recent experiences combined with shale’s steep decline and investor sentiment may even drive some U.S. shale players toward conventional assets in search of higher returns.
“I wouldn’t be surprised to see some companies that really drove into shale and sold off some of their international and offshore assets go back into the international markets [and] go back to the offshore,” West said.
Turning to technology
Cost reductions have been a primary focus for oil companies and service providers for at least the past few years. Such cuts have come both in the field with operational improvements and in boardrooms through downsizing and asset sales. However, that will only get companies part of the way in further cutting costs, Deloitte’s Dickson said.
When the shock fades and market resets, technology will likely be something the industry will crave more. The real change Dickson expects to see is more agility.
“I think we’re going to see signs that the industry itself will develop greater agility by way of technology,” Dickson said, referencing digital productivity tools. “They bring in more machine learning, artificial intelligence, ability to train people faster [and the] ability to make decisions better and quicker. That translates to better processes and better profit velocity that’s possible.”
Digital technologies will become more normalized in the energy space, he said.
The recovery track for the shale industry could also require bringing disruptive technologies like nanotechnology together with tracer analytics, microseismic monitoring and other advanced analytics, according to Deloitte. In a report, the firm suggested operators team up with vendors to automate and digitize operations to realize savings, shorten value chains and create pathways for the energy transition.
Following the last downturn, the industry saw remarkable efficiencies gained in completion designs, particularly in the number of fracked stages per lateral and proppant usage. But by many accounts, those efficiencies have leveled off, especially in proppant loading. Now that the industry is emerging from yet another downturn, the environment is likely ripe for more efficiencies, such as in production optimization.
Enverus’ Gilmer believes opportunities also exist in better reservoir evaluation.
“I think efficiencies can really be found in understanding your reservoirs, really understanding what you can do with those,” he said. “That’s why right now I like private companies because they are not punished for doing experiments, looking to see how they can expand their production and expand their reserve base. And there’s probably no one magic recipe. It’s going to come down to capital discipline, which is something that has been sorely lacking in the industry for a while with regard to things that are not necessary.”
However, Gilmer explained that the responsibility of more efficient operations lies not only with producers but also with service companies.
“We have a lot of really smart people in this industry that are building tools and ideas in the oilfield services,” he said. “But it’s incumbent for them to be able to show how it improves either oil cuts, costs or improves return either above and beyond. The ROI has to be pretty clear.”
As companies adjust, they are also mindful of how they position themselves in the market. That, Dickson added, is being driven by discussions around sustainability and diversification.
The transition fuel
A common belief among analysts is that the oil and gas industry—both operators and service providers—faces a crucial challenge: evolve or perish. Gilmer likened the current industry environment to that of biological evolution, in which an organism dies if it does not adapt and evolve. McKinsey & Co. shared similar sentiments.
“The winners will be those that use this crisis to boldly reposition their portfolios and transform their operating models,” the analyst stated in its May report. “Companies that don’t will restructure or inevitably atrophy.”
One of the weaknesses of the U.S. shale industry is that a lack of diversification, whether it be in a company’s production mix or its acreage positions, can leave them vulnerable to sudden and sharp market variances.
Varying opinions exist among industry experts on the current role of natural gas as it pertains to value creation. Although, as a long-term fuel source, most agree natural gas will play an important part in the energy mix.
The IEA forecasts natural gas demand will fall by 4% this year, contributing to lost growth of about 75 Bcm/year between its 2019 and 2025 forecast period. However, global gas demand is expected to grow on average 1.5% per year during that time, surpassing 370 Bcm annually in 2025.
Enverus sees future opportunities for natural gas in a post-pandemic environment with demand possibly reaching pre-COVID-19 levels relatively quickly.
“I know a lot of analysts are saying, ‘As we bring more production back online and the associated gas gets back online, that we’ll quickly find ourselves in an oversupplied situation once again,’” Gilmer said. “We don’t think that. We’re pretty bullish on natural gas at this point. Our guys are saying that they definitely believe that we’re going to see $3.50 prices in natural gas. We’re not as bullish with regard to oil.”
Having both oil and gas—universally seen as the transition fuel in the energy transition—in portfolios gives optionality, said Kate Hardin, executive director of the Deloitte Research Center for Energy & Industrials.
There has not been movement among U.S. shale players, for example, from oil-dominant plays into natural gas plays considering the recent downturn was demand-driven, but a Deloitte survey of executives shows company strategies are relying more heavily on gas or doing more with the gas produced.
Still, there are challenges.
Even before COVID-19, the natural gas market faced significant oversupply, weakening prices and causing some operators, like Chevron, to reassess their natural gas assets. According to the IEA, data covering half of global demand suggest that gas consumption fell by more than 3% in first-quarter 2020, and supply failed to respond accordingly.
Plus, there are earnings to think about.
In December 2019, Chevron exited its western Canada Kitimat gas export project. That same month, Chevron said it would divest its Marcellus assets, which the company acquired in 2011 in a $4.3 billion purchase of Atlas Energy Inc.
Those projects “just don’t compete for capital” in the current market, Breber said.
“[Natural gas is] a very good business. The demand side is good, but there are a lot of folks adding to supply, and we need to increase our returns on capital. Chevron and the industry do,” he added.
“The only way to do that is to be very disciplined with your capital. Only invest your capital, the shareholders’ capital, in the highest return projects, and right now, and maybe in the short to medium term, that’s not where natural gas projects are.”
Chevron may have shed some natural gas assets, but its move to buy out Noble Energy will give the company a substantial natural gas position in the Mediterranean Sea.
Weighing moves based on financials, ESG and investor concerns, and short- and long-term energy needs amid market volatility is a delicate balance.
Looking at moves taken during the second quarter, the height of the oil price war and COVID-19 turbulence, increasing divergence among energy companies is clearly visible for Keith Myers, president of research with the U.K.-based Westwood Global Energy Group. Myers said he has never seen a bigger divergence in how companies see the future in his more than three-decade tenure in the business.
“The leaders in changing the paradigm at the moment are the European majors that have been announcing how they’re realigning their business to be compatible with the Paris agreement goals,” Myers said during a July webinar.
Diverging Views on the Energy Transition
The role of sustainable energy
While there is little to suggest oil and gas won’t be significant contributors to meeting future energy needs, producers and service providers are implementing goals in technologies and operating methods that work toward established sustainability goals.
“Across the spectrum of energy companies, some are preparing for a growth-oriented, renewable energy focused future,” Deloitte’s Dickson said. “Others are preparing to be the low cost, strong brand, last competitor standing because it’s going to be a very, very long time before the economy changes away from the way we provide fuels and move around.”
When it comes to new energy investments, however, time can be a deterrent.
Royal Dutch Shell’s strategy is focused on the transition to a low-carbon future, but company executives are aware of the challenges.
“It takes a tremendously long time getting from the very first commercial application of a technology to it being 1% of the energy mix,” Royal Dutch Shell CEO Ben van Beurden said during a discussion with IHS Markit Vice Chairman Daniel Yergin. “It tends to take 25 years in our sector.”
European majors are leading by realigning businesses to become compatible with Paris agreement goals, while U.S. majors are taking a more risk management approach, examining the robustness of their portfolios to oil demand forecasts consistent with 2 C (35.6 F) of warming, Myers said.
Plans of the independents run the gamut.
“There’s a huge diversity of views on the future from those [independents] that are ignoring the issue completely to those that are trying to address the issue but with a focus on Scope 1 and 2 [emissions],” Myers said, “because if you’re an independent, there’s not a lot you can do about Scope 3.”
As defined by the U.S. EPA, Scope 3 greenhouse-gas (GHG) emissions result from activities from assets that the reporting company doesn’t own or control but indirectly impacts its value chain. Scope 2 emissions are indirect emissions from sources owned or controlled by the company, while Scope 1 emissions are direct emissions from sources owned or controlled by the company.
The specifics, however, are not clear yet.
“What we’re not yet seeing is the details of what this means for the industry and where investment’s going,” Myers said.
Indication may lie in where European majors chose to cut spending in recent months.
“Pre the COVID pandemic and the oil price crash, renewable investments were mainly 10% or less” of European majors’ capital budgets, Myers said. “But post the cuts, you can see that the percentage has grown. So, the renewables were protected from the cuts that the upstream took.”
Norway’s Equinor, Spain’s Repsol and France’s Total have dedicated the highest percentages of their capex to low-carbon investments. bp, which is transitioning from an international oil company to an integrated energy company, said in August it aims to increase such investments tenfold to about $5 billion annually as the company strengthens its portfolio with renewables, bioenergy, hydrogen, and carbon capture, use and storage.
Targeting carbon neutrality by 2030, Equinor said it aims to increase its renewable energy capacity tenfold by 2026 as it grows within the wind and solar segments. Repsol has its sight on net zero emissions by 2050, while Eni has set a fixed 2050 absolute emissions reduction target of 80% covering all of its products.
Size is key to a company’s strategy, Deloitte’s Hardin said.
Larger companies can have a longer reach with an international presence and ability to invest in new business models, she said, noting such companies have the wherewithal to invest in solar, wind or even electric vehicles.
“For the smaller companies, North American independents, for example, what we’ve seen over time, is there is more of the classic health, safety and environment play, which they have been reporting in their documents for a while,” Hardin said, adding they are tracking and working to lower emissions and water usage. “Some companies have been making their sustainability reports public since before the Paris agreement.”
Speaking during the company’s second-quarter investor call, Equinor CFO and executive vice president Lars Christian Bacher said that as the company looks to further diversify its production mix, particularly in arenas such as offshore wind power, it looks to do so with a focus on quality assets that provide a solid return.
“If we’re entering into a business, onshore, offshore, oil, gas, deep water, shallow water, renewables or not, it has to be among the good assets,” Bacher said. “In my mind, people too often are having a vertical line between assets, whether you should invest in one category or the other. For me, it’s a horizontal line. Everything above a certain good return, I’m very eager to look at and see if we can get it if it’s among the best ones. That also goes for onshore positions. Whether we will enter and when and where, that remains to be seen.”
Chevron is aiming to lower its oil net GHG emission intensity by up to 10% and natural gas net GHG emission intensity by up to 5% by 2023. The company is also looking to reduce net methane emissions intensity by 20% to 25% and reduce net flaring intensity by 25% to 30% by 2023.
Speaking with E&P Plus, Breber said he expects the energy transition to take “decades,” and the energy transition is “a long-term question” but will still be relevant post-pandemic.
“[The energy transition issue] will be there when we’re on the other side of it,” Breber said. “Right now we’re in the middle of it. The effort that we’re taking to address climate change and the energy transition, which are really addressing long-term value, those are largely sustained.”
He acknowledged that any focus on energy transition and renewables amid the current climate is “in the backdrop” but remains a component of the company’s long-term value strategy.
“When we think about long-term value, we do think about the investments that we’re making that will bring on oil and gas production in years,” he said. “Because we don’t know, well, we don’t even know what’s going to happen six months from now.”
Opportunities in acreage
Low prices often equal opportunity, particularly on the M&A front. With the inevitability of sell-offs and bankruptcies, deals are likely there to be had, and acreage in key basins could become available.
But for smaller operators like Treadstone, identifying the most economic basins and opportunities rather than the most popular ones is a key factor in possible acreage growth.
“We’ve always avoided the really popular basins,” McCorkle said. “The Permian, the Bakken, not because they are bad, but because they’ve gotten way overpriced. I think there is still a challenge in some of those where people have gotten in for such a high price. I think seeing mergers, particularly for public companies or larger private companies, could happen because they’re doing it on a like-for-like basis rather than trying to lay out cash for assets that have been bought at too high of prices to start with.”
However, one challenge facing smaller companies, especially those that operate in less-popular resource plays but in highly coveted basins, is the cost of acquiring acreage. Such opportunities likely only make financial sense in a higher oil price environment.
“We’re primarily focused on the Austin Chalk in the oil window, which most people have avoided,” McCorkle said. “The challenge with that is often people put a lot of money into the Eagle Ford resource play below the Austin Chalk, so it makes acquiring the Austin Chalk a bit challenging. People want to get paid a lot for their resource plays and location. It’s not economic until you get into a much, much higher oil price.”
Although bolt-on acreage might be available, the key is to acquire properties that allow for the development of longer laterals, Gilmer said.
“Having acreage, just the raw number of acres is not very telling, but the ability to put long laterals [is what’s important],” Gilmer said. “Long laterals being 10,000-ft-plus laterals really, really, substantively improves the value of that average. Not all acres are equal. Because the difference in some cases between a 4,000-ft lateral and an 8,000-ft lateral can be the difference in a 15% or 20% internal rate of return and a 100% rate of return.”
McCorkle echoes that sentiment, saying that when Treadstone does look to add acreage, it does so to enhance the company’s ability to extend its lateral length in the Austin Chalk.
“We usually focus on very contiguous acreage or acreage that is along our boundary that we can drill into from our acreage,” he said. “And the primary reason for that is the lateral length. It’s much more challenging to make an economic development with 3,000-ft to 5,000-ft laterals any more than it is to get to 8,000-ft to 10,000-ft lateral lengths. Obviously, that’s truer in some reservoirs more than others, but for the most part, added lateral length is more economic.”
Deloitte is tracking three areas to gauge how the industry shapes up in the near and longer term: COVID-19 containment and recovery, economic recovery, and energy demand.
“It’s hard to say exactly where we’re going to end up after the disruptions that we’ve seen,” Hardin said. The next normal will likely be a lower demand environment, she said, possibly with more price volatility.
According to Deloitte, the global industry may evolve to include new telecommuting norms, regionalized trade and supply chains, and a new fuel order.
During the worst of the pandemic in March and April, power demand dropped 10% to 15% in some of the hardest-hit regions, and vehicle traffic fell by 40% to 50% compared to pre-COVID-19 levels, impacting demand for gasoline and other fuels, before picking back up, Hardin said. The world is also awaiting the return of air travel, which she said remains sluggish.
“We have seen a real decline in jet fuel demand post-COVID-19,” Hardin said.
Dickson observe that jet fuel demand might never return to pre-COVID-19 levels.
Whether the pandemic changes when the world reaches peak oil demand also remains to be seen. Decarbonization, however, is expected to slow long-term oil demand growth.
As energy companies await normalcy in new forms, agility and flexibility with an ability to grow production capacity to meet long-term demand are key to staying competitive, according to Deloitte’s midyear industry outlook.
“In the coming months, [producers] should balance the trade-offs between short-term cost-cutting and long-term investments so they are best positioned for the future,” Deloitte said. “Even if energy demand drops in the coming year and the energy mix begins to change, the long-term demand for energy overall will likely continue to grow.”
Data from the IEA showed global oil demand was down 16.4 MMbbl/d during the second-quarter 2020 compared to a year ago. Lockdowns related to the pandemic were behind the drop. Improvement is expected in the second half of the year.
Natural gas markets, which have seen depressed prices, also face continued headwinds with power demand falling, including in Europe, and renewables displacing LNG imports in parts of the world, according to Deloitte.
However, “fuel switching could dictate the recovery” and “natural gas still has a role to play in providing energy security in a lower-carbon world and can underpin economic growth in many developed and developing economies,” Deloitte said in an outlook, referring specifically to the power sector.
For the industry to not just recover from the current downturn but thrive in a new post-pandemic reality, companies will likely need to evaluate their assets, identifying what provides true returns and what generates cash, while also appeasing sentiments toward a more environmentally friendly approach to energy production.
Breber said Chevron is well positioned for a post-pandemic industry with a low-teens net debt ratio and a strong balance sheet, but he noted that many other companies in the industry are more highly leveraged.
“In an industry where your revenue can decrease 50% almost overnight, that’s not a capital structure that I think makes a lot of sense for shareholders,” Breber said. “This is the third time in 10-plus years this has happened, so you don’t have to go back to ancient history books to have learned this lesson. Coming out of this we should see better capitalized companies and companies with stronger balance sheets that can weather the price volatility that we’ve seen in the past, and we’re very likely to see in the future.”
2022-11-29 - Exxon Mobil’s oil output in Equatorial Guinea, a member of OPEC, peaked at more than 300,000 bbl/d eight years ago and has been declining since.
2022-11-14 - “The most important thing is for people to see America’s largest natural gas producer here at COP27 as a symbol that we’re going to be a leader in energy transition,” EQT CEO Toby Rice told Reuters on the sidelines of COP27.
2022-10-07 - Interior’s Bureau of Land Management said it was seeking public input for 30 days on a plan to offer 251,086 acres in Wyoming and 10,124 acres in New Mexico to oil and gas companies.
2022-10-07 - In the new licensing round, the North Sea Transition Authority (NSTA) is offering 898 blocks, encouraging applications, especially for the southern North Sea where hydrocarbons are close to existing infrastructure allowing for swift development.
2022-11-28 - The proposal would place monthly limits on flaring and require oil and gas companies to undertake methane leak detection programs on federal land.