Category: Nieuws

The European Union has agreed a substantial grant to support a carbon capture and green fuel production project in Greece.

Greece’s Vardinoyiannis Group-backed Motor Oil and the European Commission have signed the EU Innovation Fund Grant Agreement of €127m ($138m), for a pioneering Internet Registry Information Service (IRIS) project regarding the construction and operation of a Carbon Capture, Utilisation and Storage (CCS) and e-methanol production system at Motor Oil’s Agioi Theodoroi Refinery.

The IRIS project is among the 41 projects selected, out of the 239 proposals submitted, under the second round of the EU Innovation Fund’s ‘large-scale’ calls for proposals, and just the third in Europe involving a Steam Methane Reformer.

The IRIS project will integrate several innovative industrial processes, on a scale that has never been implemented before in an independent refinery.

In particular, the project will contribute to a 25% reduction of the refinery’s CO2 emissions, and thus to the achievement of the industry’s national and EU carbon reduction targets. At the same time, there are plans to establish an innovative e-methanol production plant, which will be produced from the available renewable hydrogen and part of the captured carbon dioxide, which will be one of the first plants to be set up in Europe.

Part of Motor Oil Group’s ‘Blue Med’ strategic plan, the project aims at the development of a hydrogen value chain in Greece. The quantities of renewable hydrogen produced by the 30MW electrolysis plant under development in Motor Oil’s EPHYRA project will be supplemented by sufficient quantities of low-carbon hydrogen that will comply with the prescribed limits of the EU Classification Regulation.

The launch of the construction of the project, once all the necessary individual agreements have been completed and the final investment decision has been obtained by the company, is expected to start in mid-2025 with a three-year completion deadline, so as to be operational in mid-2028, according to the timetable approved by the European Commission.

George Triantafyllou, gm of strategy at Motor Oil Group, said: “Motor Oil Group is determined to guide the industry’s energy transition and play a leading role in achieving the industrial decarbonisation goals and in establishing the hydrogen and hydrogen derivatives market in Greece.

“The funding from the European Union’s Innovation Fund marks a major milestone for the Group. We remain committed and fully aligned to the €4bn energy transition plan that has been announced, having invested €1bn up to now in this direction.

“We are leading the way, utilising our competitive advantages and we are committed to implementing emblematic and pioneering projects and investments, that will accelerate the transformation of our country’s energy mix, on the road to ensuring energy autonomy.”

January 15, 2024

H2 Energy Europe, a builder of hydrogen ecosystems in Europe, has obtained environmental approval for its large-scale green hydrogen production facility in Esbjerg, Denmark.

The approval issued for the facility, which will have a 1 GW electrolysis capacity, is said to be a significant milestone, bringing the project closer to a final investment decision (FID).

According to H2 Energy Europe, the planned facility will support the decarbonization of heavy industries and road transportation, while also serving as chemical feedstock for the production of sustainable e-fuels like methanol and ammonia, advancing Europe’s green transition.

In addition to creating approximately 60 permanent jobs and up to 700 jobs during the construction phase, the facility will also produce CO2-neutral surplus heat, which has the potential to supply the majority of households in Esbjerg with district heating.

Jesper Frost Rasmussen, the mayor of Esbjerg municipality, said the environmental approval granted to the upcoming hydrogen plant by H2 Energy Europe is of immense significance for Esbjerg, positioning it as a leading green business city in Europe.

“H2 Energy Europe will play a pivotal role in attracting additional Power-to-X (PtX) companies to Esbjerg. However, there remains a need for clarity regarding the placement of the hydrogen pipeline and its expected establishment, which are critical for the realisation of a robust hydrogen industry in Denmark. We hope for a resolution on these matters very soon, further advancing the region’s green energy ambitions,” Rasmussen explained.

Mark Pedersen, Operations Manager at H2 Energy Europe, stated: “Our foremost priority is the safety of our operations. Achieving an environmental approval for a project of this size and at such an early stage in the year highlights our commitment to ensuring the well-being of our community. It also reflects the supportive and forward-thinking approach of Esbjerg municipality. We are deeply grateful for their cooperation and shared vision in making this project a reality.”

While this approval represents a significant milestone for Denmark in leading the way in Power-to-X technology, H2 Energy Europe noted it acknowledges the challenges that lie ahead.

The significance of the proposed pipeline, slated for completion by 2028, cannot be overstated, as it will play a vital role in distributing the green hydrogen produced by the facility to other countries in Europe, bolstering Denmark’s economy, the company concluded.

January 15, 2024

South Africa’s Transnet National Ports Authority has appointed Dutch terminal operator Vopak and its consortium partner Transnet Pipelines to build and operate a liquefied natural gas (LNG) import facility at the Port of Richards Bay.

Both TNPA and Transnet Pipeline are part of South African rail, port, and pipeline company, Transnet, owned by the government of South Africa.

Following a procurement process through a request for proposals, TNPA has appointed the Vopak & TPL consortium to design, develop, construct, finance, operate, and maintain the LNG terminal in the South Dunes Precinct at the Port of Richards Bay for a period of 25 years, it said in a statement.

TNPA said the terminal is a partnership between the private sector and the public sector, with the private sector as the lead investor.

Also, TNPA will invest in the common user port infrastructure, while the terminal operator will provide the terminal infrastructure.

2027

TNPA said this terminal is set to change the “economic dynamics of the port city, the KwaZulu Natal Province and introduce an alternative source of energy as South Africa battles an energy crisis and transitions towards decarbonization.”

The firm said this project is the first of its kind in South Africa and brings TNPA closer to its strategic goal of assisting the country through this LNG import terminal and as a midstream LNG importation infrastructure for markets in the KwaZulu Natal hinterland.

According to TNPA, project timelines will see the commercial operation during 2027, with the next step being the signing of the terminal operator agreement which is currently under negotiation.

TNPA did not reveal any information regarding the LNG import terminal in the statement.

According to TNPA’s tender documents issued in 2022, the LNG-to-power project must be designed to enable the realization of a minimum annual throughput of 1 million tons per annum scaling up to achieve a throughput of 5 million tons per annum by 2036.

TNPA’s document show that the project includes an FSRU which would be located at Berth 207 in the port.

Vopak’s LNG growth

LNG Prime contacted Vopak to provide more information on the terminal.

A spokeswoman for Vopak said this move “very well fits into Vopak’s strategy to grow in LNG”, but she declined to provide more details.

Vopak has extensive experience in LNG terminal operations.

In partnership with Dutch Gasunie, it operates the Gate LNG terminal in Rotterdam and the FSRU-based LNG hub in Eeemshaven.

Vopak also has a 60 percent stake in the Altamira LNG terminal in Mexico, a 49 percent share in Colombia’s only FSRU-based LNG import facility in Cartagena, and a 44 percent stake in the Engro Elengy FSRU-based terminal in Pakistan.

LNG Prime, January 12, 2024

Growing oil producer Guyana is talking with five potential investors interested in building and operating the country’s first refinery, vice-president Bharrat Jagdeo said last week.

The government issued a tender in October for the 30,000 b/d facility, but has not said when it will decide which bidder will design, construct and operate the refinery.

Guyana “is exploring all options to ensure that its refinery will be economically viable, sustainable, and will bring added benefits to the country,” Jagdeo said.

A Guyana plant would counter a trend in the Caribbean basin that was once dominated by large plants with cumulative capacity of over 1.6mn b/d that process mainly imported feedstock.

But the region’s refining capacity has been reduced to approximately 160,000 b/d inthe past 35 years as refineries have been shuttered.

Closed refineries include the 650,000 b/d St Croix plant in the US Virgin Islands, Curacao’s 335,000 b/d Isla, Aruba’s 235,000 b/d San Nicolas facility and the 165,000 b/d Guaracara plant in Trinidad and Tobago.

US Virgin Islands domestic start-up Port Hamilton is locked in legal arguments with US federal environmental agency EPA that ordered a halt in 2022 to preparatory work to reopen St Croix.

China’s GZE, Germany’s Klesch, Dutch contractor Corc and US-Brazilian consortium CPR are among companies that unsuccessfully vied to reopen Isla, which was shuttered in 2019 when Venezuela’s state oil company PdV declined to renew its expired long-term lease.

Trinidad shut Guaracara in 2018 because it became uneconomic. Despite approaches from a domestic labor union-owned company and California-based electrical contractor Quanten, the government has been unable to offload the facility.

Negotiations for Quanten to purchase San Nicolas also failed after state-owned oil company RdA cancelled an agreement in June 2022.

Problems that afflicted PdV have also set back expansion plans in regional refineries in which it had in interest.

The Dominican Republic took complete ownership of the 34,000 b/d Haina refinery in August 2021 with the purchase of PdV’s 49pc stake, saying it was “disappointed” by PdV’s delay in implementing its commitment to expand Haina’s capacity to 60,000 b/d.

Jamaica’s government also took PdV’s 49pc stake in the 35,000 b/d Kingston facility, contending that the Venezuelan firm had reneged on an agreement to expand the capacity to 50,000 b/d.

Cuba’s state oil company Cupet took over PdV’s 49pc stake in the 65,000 b/d Cienfuegos refinery in 2017, after the collapse of an agreement to lift capacity to 150,000 b/d.

Russian oil firm Rosneft is yet to deliver on a later project to expand Cienfuegos and upgrade the island’s Soviet-era Nico Lopez refinery in Havana and the Hermanos Diaz in Santiago.

Guyana is projecting crude output of 1.2mn b/d by 2027. Its rapidly expanding production raised hopes of available feedstock to lift refinery capacity in the region.

The Dominican Republic said in August that it reached an agreement with Guyana to jointly develop a 50,000 b/d plant on Guyana’s north coast.

But Guyana has no immediate plans to build a second facility, Jagdeo said a week later. “We do not have the capacity for two refineries now.”

Trinidad’s Guaracara facility could be reopened to process Guyana’s crude, Trinidad energy minister Stuart Young said. But Guyana will not accept that offer, according to natural resources minister Vickram Bharrat.

“Everything points to a successful refinery project in Guyana,” a Trinidadian industry official told Argus last week. “But there’s little hope of a reopening or expansion of any refinery in the region. And I would not be surprised if some existing capacity were to be shut down.”

Argus Media, Canute James, January 8, 2024

Chinese privately-controlled refiner Rongsheng Petrochemical (002493.SZ) and Saudi Aramco (2222.SE) are in talks for the Chinese company to buy a 50% stake in the Saudi company’s refining unit SASREF, a filing showed on Tuesday.

Rongsheng is also negotiating to sell Aramco an up to a 50% stake in its unit Ningbo Zhongjin Petrochemical Co, the Chinese company said in a statement to the Shenzhen stock exchange, citing a memorandum of understanding signed on Tuesday.

Saudi Aramco Jubail Refinery Company (SASREF), located in Jubail Industrial city, processes crude oil into petroleum products and has a production capacity of 305,000 barrels per day (bpd), its website shows.

If the SASREF stake acquisition happens, it would be the first investment by a private Chinese firm in a significant Saudi refining asset. State refining giant Sinopec Corp is so far the only Chinese company that owns a refinery stake in Saudi Arabia.

The companies also discussed expanding the Saudi refinery and upgrading its products.

The final investment decision is pending due diligence on Ningbo Zhongjin and SASREF by the two buyers respectively, Rongsheng Petrochemical said.

Aramco said in March it had agreed to acquire a 10% stake in Rongsheng, an investment attached to a 20-year crude oil supply deal with Rongsheng-controlled Zhejiang Petrochemical Corp. The deal closed in July at a valuation of $3.4 billion.

It has also been in talks to buy a 10% stake in Shandong Yulong Petrochemical Co, which is building a refinery complex that can process 400,000 barrels of crude a day in eastern China’s Shandong province.

In September, Aramco announced plans to become a strategic investor in another private Chinese refiner Jiangsu Shenghong Petrochemical, which operates a 320,000 bpd refinery and petrochemical complex in the eastern province of Jiangsu.

In a separate filing to the stock exchange, Rongsheng said it plans to invest 67.5 billion yuan ($9.46 billion) in new materials at its base Zhoushan in east China that makes products such as high-performing plastic material ethylene vinyl acetate (EVA)and polyolefin elastomers used in solar panels.

Reuters, Aizhu Chen, Andrew Hayley and Roxanne Liu, January 2, 2024

As the energy mix transitions to meet decarbonisation demands, natural gas and hydrogen are expected to play major roles.

The contribution of natural gas in terms of capacity and generation is crucial for the decarbonisation of the electricity sector. This is true as we move towards zero emissions and on reaching that target.

However, the degree to which natural gas can be effective depends on several vital factors including the design of relevant policies, the availability of technologies for carbon removal, the effectiveness in reducing methane emissions from upstream sources and the risks associated with transitioning to new technologies.

Hydrogen is equally important in the mix.

The New Climate Institute states, “Hydrogen is expected to play an important role in the decarbonisation effort to keep global warming at 1.5 degrees. Net-zero models foresee its share in final energy consumption ranging between 3-20% by 2050.

“For hydrogen technologies to fulfil this role, sizeable investments need to be made to reduce production costs and improve end-use applications.”

Elixir Energy Ltd (ASX:EXR) has a foot in both camps.

The company is focused on an exploration and appraisal program targeting natural gas in the form of coal-bed methane (CBM – known as coal seam gas or CSG in Australia) in the South Gobi, Mongolia and Queensland, Australia. It has also been developing the Gobi H2 green hydrogen project and solar project in Mongolia.

Elixir has built a strong foundation of multiple-level government and other energy stakeholder relationships that are now being used as a platform to grow cleaner energy options.

Elixir’s energy mix
Elixir is focused on three main projects close to important infrastructure in Mongolia and Queensland.

Its projects include:

The 100%-owned Nomgon IX Coal Bed Methane (CBM) Production Sharing Contract (PSC) Project in the South Gobi region of Mongolia.
The Grandis Gas Project in Queensland covers an area of 1,000 square kilometres located close to existing gas transmission infrastructure centred on the Wallumbilla gas hub. This hub is connected to domestic and international markets.

A Mongolian natural gas business run via wholly-owned subsidiary, GOH Clean Energy LLC, that pursues renewable energy ventures, including hydrogen and solar.

The projects – Grandis Gas Project
In August 2022, Elixir Energy expanded its portfolio by acquiring a 100% interest in the petroleum exploration permit ATP 2044 in Queensland.

This was achieved through the acquisition of the special-purpose vehicle EnergyCapture Pty Ltd, now rebranded as the Grandis Gas Project.

Spanning 1,000 square kilometres, the Grandis Gas Project is advantageously located near the Wallumbilla gas hub, which is connected to domestic and international markets. The site, part of the long-established Taroom Trough oil and gas province, benefits from easy road access to well locations.

The project could also benefit from market factors driving new rounds of drilling in the Taroom Trough, including by majors.

Elixir, along with these majors, hopes to capitalise on the growing demand/supply gap in the East Coast gas market, spare capacity in Queensland’s LNG plants and international buyers’ requirements for reliable supply – especially given the Ukraine War and other geopolitical factors.

The Taroom Trough has been described as an emerging energy super basin. Wood Mackenzie described the concept of the super basin as “basins with the co-location of upstream hydrocarbons, clean electricity, standalone and/or hub-scale CCS”.

Currently in the Taroom Trough are Shell, Santos (with whom Elixir recently executed a Data Sharing Agreement) and Omega.

Santos CEO Kevin Gallagher recently said of his company’s presence: “If the play works, then we believe there is multi-Tcf potential”.

A recent milestone for the Grandis project was drilling of the Daydream-2 appraisal well, which reached a total depth (TD) of 4,300 metres on December 7, 2023. This depth exceeded the initial plan by about 100 metres due to higher-than-expected gas levels and provides greater operational flexibility for future appraisal phases.

The drilling process encountered a rapid increase in well penetration rate associated with a gas influx, leading to an estimated 50,000 cubic feet of gas being flared. Following standard drilling practices, this influx was safely managed, and the well was drilled to its final depth.

This discovery, deep within the well, indicates potential for substantial reservoirs, though further work is needed to fully understand its implications.

Nomgon CBM PSC
Elixir’s most mature asset is the Nomgon IX Coal Bed Methane (CBM) Production Sharing Contract (PSC) project in Mongolia’s South Gobi region.

The 100%-owned foundation asset is located on the Mongolian/Chinese border with excellent infrastructure, mines and planned pipelines.

The project is being managed by a highly experienced CSG team and is a first mover in taking Australia’s industry-leading skills to Mongolia.

Exploration started in 2019 and the first CBM discovery was made in 2020. The Production Pilot Project will continue through 2024.

Elixir aims to dewater coals and flow gas from the Nomgon CBM discovery; provide proof of concept for commercial development; conduct its first extended production test in Mongolia and continue to grow cooperation with other operators in the region.

Varied flow rates are typical of a first pilot in the region and measured up to 200,000 cubic feet per day.

Water and gas production will continue into 2024.

Gobi H2
Elixir’s green hydrogen project, Gobi H2, in the Gobi region of southern Mongolia, represents a significant venture into renewable energy, specifically hydrogen produced from renewable electrical sources.

Leveraging its extensive experience in Mongolia’s energy sector and robust stakeholder engagement with governments at various levels, communities, and customers, Elixir has laid a strong foundation for the development of the Gobi H2 business.

The project’s potential was highlighted in mid-2022 when Elixir announced the signing of an MoU with Japan’s SB Energy Corp, which later became Terras Energy following a takeover by Toyota Tsusho. This partnership underscored the viability and strength of the Gobi H2 concept.

To further solidify this venture, Elixir commissioned a pre-feasibility study (PFS) from the global consulting firm AECOM earlier in the year. The positive and encouraging results of this confidential PFS led to a significant advancement in February 2023.

Elixir and SB Energy expanded upon their initial MoU by executing a term sheet. This crucial document set forth an exclusive framework for both parties to work towards establishing a binding 50/50 joint venture later in the year.

The project’s relevance and potential are further amplified by the development of green hydrogen infrastructure projects in neighbouring China. These include the creation of a regional hydrogen pipeline transmission network.

The strategic location of the Gobi H2 project positions it to benefit from these developments, as the network could be expanded northwards to harness the Gobi region’s exceptional renewable resources. This expansion presents a unique opportunity for Elixir’s Gobi H2 project to play a pivotal role in the broader regional green energy landscape.

Elixir Energy, Jonathan Jackson, January 4, 2024

After enduring a torrid season for much of the second half of 2023 due to falling commodity prices, the energy sector is looking to close out the year on a high after a long-awaited Fed pivot finally arrived. Not surprisingly, Wall Street and investors have started peering into their crystal balls to try and divine what the new year holds in store for energy markets, with some predicting we shall see more of the same while others are saying to expect an oil price rebound.

Investors will also be watching closely to see if another corner of the market will finally sputter back to life: dealmaking. The value of global oil and gas mergers and acquisitions (M&A) has declined to only 3% of the industry’s market capitalization per annum, down from a peak of 10% in 2014. Thankfully, there’s a glimmer of hope: the U.S. oil patch recorded a small 3% Y/Y increase in the third quarter with 105 M&A deals announced, worth a total value of $47bn. Interestingly, the global energy sector has suddenly come alive with all manner of deals from M&A and asset sale/purchase deals to supply deals being announced in the final month of the year. Here are some notable ones.

Tokyo Gas To Acquire Rockcliff Energy
Japan’s largest gas supplier Tokyo Gashas entered an agreement to acquire privately held Haynesville Shale gas producer Rockcliff Energyfor $2.7 billion in an all-share deal. The agreement comes nearly a year after Tokyo Gas’ partially owned Houston-based subsidiary TG Natural Resources (TGNR) and Rockcliff were reportedly in advanced talks on a merger that was at the time reported to be worth ~ $4.6 billion. The deal fell apart after US natural gas prices collapsed to $2 per million Btu from a summer 2022 peak around $9/MMBtu.

TGNR has been active in the Haynesville after acquiring Shell Plc’s (NYSE:SHEL) assets in the Texas/Louisiana play in 2019. Haynesville has seen little M&A action over the past two years amid volatile gas prices.

Brookfield To Sell Renewable Assets
Canada’s Brookfield Corp. (BN.TO) has announced plans to sell renewable assets owned by its company Saeta Yieldworth 1.5 billion euros ($1.64 billion) including debt. The assets to be sold are wind and photovoltaic plants located in Spain and Portugal. Saeta owns 28 wind farms and 10 photovoltaic parks; however, its seven solar thermal plants are not part of the sale process.

Spain and Portugal’s abundant solar and wind resources have made them a hotspot for both domestic and foreign firms looking to leverage the growing demand for renewable energy. This has sparked a flurry of renewable energy deals in the region with the broader global trend towards sustainable investments.

Carlos Slim Bets on Mexico’s Mega Oil Projects
Mexican billionaire Carlos Slim’s Grupo Carso SAB has agreed to acquire PetroBal SAPI’s stake in two oil fields in Campeche in southern Mexico for $530 million, expanding its bet on energy production. Under the deal, Grupo Carso will take a 50% stake in the Ichalkil and Pokoch oil fields, the company has revealed in a statement. According to the company, the fields produce about 16,350 barrels of crude oil equivalent per day. Carso shares have jumped to record highs of 181.79 pesos after the deal was announced.

Mexican President Andres Manuel Lopez Obrador has welcomed the deal despite earlier being critical of energy reforms that opened exploration to private investment, “Why do I celebrate this? Because it stays in the hands of Mexicans and I’m sure that they’re going to invest to extract crude. I consider that to be good news,” the president said at his daily news conference.

Obradors’ nationalist policies have seen the Mexican government become increasingly hostile to foreign companies. Earlier in the year, giant oil and commodities trading firm, Trafigura, was forced to scale back its oil trading business in Mexico thanks to shrinking margins. Trafigura has recorded margin compression due to fuel subsidies by the Mexican government.

Adnoc Signs LNG Supply Deal With ENN Natural Gas

Adnoc has just signed a 15-year agreement with ENN LNG, a subsidiary of China’s ENN Natural Gas, for the delivery of at least a million metric tonnes a year of LNG. The super-chilled fuel will primarily be sourced from Adnoc’s Ruwais LNG project in Abu Dhabi, with deliveries expected to kick off in 2028. According to Adnoc, the Ruwais plant will be the first LNG project in the region to run on clean power, making it “one of the lowest carbon-intensity LNG facilities in the world”, according to Adnoc.

As one of the largest private energy companies in China, ENN has been signing multiple long-term supply deals. Back in June, Cheniere signed a long-term LNG sale and purchase agreement with ENN Energy Holdings. Under terms of the deal, ENN will purchase ~1.8M metric tons/year of LNG on a free-on-board basis at Henry Hub prices for a 20-year term, with deliveries to commence mid-2026 ramping up to 0.9 million tonne per annum (mtpa) in 2027.

Egypt, Saudi Arabia Sign $4 bn Green Hydrogen Deal
Egypt has reached an agreement with Saudi Arabia’s ACWA Power to develop a green hydrogen project worth $4 billion, the Egyptian government has revealed. Egypt’s minister of Electricity, Dr. Mohamed Shaker, has revealed that an action plan will be implemented shortly for the first phase of the green hydrogen project. The initial phase will have a production capacity of up to 600,000 tons per year of green ammonia with total investments expected to exceed $4 billion.

Three years ago, Aramco made the world’s first blue ammonia shipment from Saudi Arabia to Japan. Japan is looking for dependable suppliers of hydrogen fuel with its mountainous terrain and extreme seismic activity rendering it unsuitable for the development of sustainable renewable energy.

Two years ago, Saudi Aramco announced that it had abandoned former plans to develop its LNG sector in favor of hydrogen. The company said that the kingdom’s immediate plan is to produce enough natural gas for domestic use to stop burning oil in its power plants then convert the remainder into hydrogen.

Oilprice.com, Alex Kimani, January 4, 2024

Last week Robert Rapier pointed out in a TikTok video that the U.S. is poised to set a new oil production record. In response, someone took exception to my claim by stating that he works in the industry, and drilling rigs are stacking up.

It is correct that the rig count has fallen. According to data from Baker HughesBHI, the number of rigs drilling for oil and gas has fallen by about 20% in the past year.

This decline reversed a steady increase that began after the rig count bottomed out below 300 in the early stages of the Covid-19 pandemic in 2020. The rig count recovered back to nearly 800 rigs by the end of 2022 but has since declined back to about 620.

Nevertheless, U.S. oil and natural gas production are both poised to set new annual production records, after monthly production has risen steadily all year. How can that be if the rig count is falling?

Keep in mind that the rig count is a measure of rigs that are currently drilling for oil and gas. In many cases, the wells are drilled, but they aren’t completed. These are called drilled but uncompleted wells (DUCs), and that inventory is tracked by the Energy Information Administration (EIA) here.

What we can see is that since last December, the inventory of DUCs has declined from 5,300 to about 4,500. That reflects about 800 wells that started producing oil and gas, but that would not have been impacted by the falling rig count.

In addition, there are continuous technology improvements that have enabled a higher recovery of oil and gas per well. The biggest example of that can be seen in the natural gas rig count.

Back in 2007, there were around 1,500 rigs drilling for natural gas. In 2009, that fell below 1,000. In 2012, it went below 500, and it fell below 100 in 2016. Today it stands at about 120.

Yet, during the time, U.S. natural gas production increased by 80%.

It’s a similar story for oil. In 2014 there were 1,600 rigs drilling for oil. Today, there are 620, but oil production is 50% higher than it was in 2014.

Thus, using rig counts as a proxy for natural gas or oil production would have grossly misled you. Don’t confuse drilling with production.

OilPrice.com, Robert Rapier, January 4, 2024