Category: Oil and Gas

Majors make $22 billion in global E&P asset sales so far this year

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The world’s largest E&P companies have been extremely active in selling assets this year according to analysis available in Evaluate Energy’s latest M&A infographic.

Evaluate Energy’s data shows that over $22 billion has been raised by oil and gas majors – public companies with an enterprise value of over $10 billion – since the start of 2022 by selling assets or stakes in their upstream portfolios.

“There have been 46 individual deals with majors selling assets since the start of the year across 17 countries, with a large number of assets sold to private equity buyers,” explains Eoin Coyne, Evaluate Energy’s Senior M&A Analyst.

While sales have been frequent, acquisitions have been thin on the ground.

“The current price environment is seemingly steering these producers towards sales and potentially furthering development of existing core assets and away from any kind of widespread acquisition activities,” said Coyne.

“Investment in renewable energy sectors has also been growing.”

Evaluate Energy’s Q3 infographic provides detailed information on asset sales by Repsol, ExxonMobil and Shell, among others.



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Op-ed: Price cap hype casts investment cloud over gas

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This article was originally published in The Australian.

As the debate over energy prices roared across the media in the wake of the Federal Budget, new domestic gas price data from several major Australian gas companies went largely unnoticed. 

While commentators lined up to call for gas price caps – some even suggesting a limit of $10/GJ – several east coast gas producers reported results with average realised prices between $8.50/GJ and $13/GJ. 

For example, Beach Energy said its September quarter price was down 3% to $8.50/GJ. 

Cooper Energy reported $9.06/GJ while Australia Pacific LNG reported $12.44/GJ, lower than its LNG sales at $19.52/GJ. 

Earlier, Senex Energy, in its last report before delisting, reported a price of $7.60/GJ. 

The gas market is complex and these figures underscore the misinformation about energy and contract gas prices as well as proposals for intervention in the gas market. 

To get the best outcome for Australia, governments need to recognise that the energy system as a whole is under pressure. Effective solutions will need to be found across the energy supply chain, rather than targeting only one part of it. 

Focusing on gas prices in electricity generation is also misleading because coal – now rightly being identified as a major problem given its soaring price – and hydro more often set the price of power than any other energy source. 

For example, in the second quarter of 2022, in NSW hydro set the price 48% of the time, coal set the price 34% of the time, with gas only doing so 17% of the time.  

Along the east coast of Australia, gas is setting the power price less than 20% of the time. It also accounts for less than 7% of electricity generated in the national energy market. 

In terms of gas prices, most business users have supply locked in at lower prices because most of the gas sold to industry is on long-term contracts that cover about 90% per cent of the market. 

It is important to note that long-term contracts were still being offered to businesses at the start of this year for between $6.70/GJ and $9.40/GJ. 

This underscores the point that regulatory price intervention may have a much smaller impact for manufacturers than what some claim.  

But it will have a much bigger impact on the broad strength of the Australian economy than what those calling for caps have admitted. 

Price caps will undermine investor confidence in the new supply that is critical to putting downward pressure on prices – creating more problems down the road.  

It would also obviously mean less revenue, less profit and less economic contribution for cash-strapped federal and state governments. 

That means the industry’s strong government receipts – like recent forecasts from our gas exporters of delivering an extra $9 billion in Petroleum Resource Rent Tax, corporate income tax, state royalties and excise this financial year – will be negatively impacted. 

Are state governments like Queensland, where almost $6 billion of gas royalties are forecast in coming years, happy with a price cap to limit the revenues from the gas sales they rely on for revenue in order to build hospitals, roads and schools? 

A price cap is not the only intervention being discussed and each measure or change, even if only threatened, chips away at investment confidence. 

Whether it be suggested changes to the industry-led Code of Conduct; the recent announced changes to the Australian Domestic Gas Security Mechanism (ADGSM); the additional powers to the Australian Energy Market Operator (AEMO) to intervene in the market’s operation; the ongoing Australian Competition and Consumer Commission (ACCC) inquiry into the gas industry; or the Budget’s cuts to carbon capture and storage funding (despite the technology being crucial if Australia is to meet its net zero goals), each sends a message that rattles investment confidence.  

Ultimately, it comes down to simple maths when the numbers needed to make large multibillion dollar, capital-intensive investments stack up financially frequently change and the policy environment shifts again. 

And it doesn’t just risk new investment and supply – it risks the associated and substantial economic, emissions reduction and energy security benefits of that supply. 

It is ironic that the source of much of the debate around gas prices and intervention at the moment is Australia’s world-leading LNG export industry. 

Critics often try to paint our gas exports as the problem for pricing pressures but export levels have actually stayed flat or slightly down this year. 

And anyone who knows the fundamentals of business and encouraging investment would see the policy environment that fostered the global success of our LNG exports as an example of the kind of policy solution Australia needs now. 

In little more than a decade, the gas industry invested over $300 billion in seven new LNG projects which are now set to produce record-breaking export earnings of $90 billion this financial year. 

Critically, this investment was supported by positive investment policy environments from federal and state governments in Queensland, Western Australia and the Northern Territory that laid the foundations for the returns we see today. 

These governments and their constituents are now reaping the benefits – the projects are underpinning our domestic energy security, delivering billions of dollars in new revenues and supporting thousands of jobs. 

Consider the success of this collaboration between industry and government in the national interest against the current short-sighted debate we see today. 

We need new investment in new gas supply, not intervention, if we are to get the best outcome for Australia.  

Samantha McCulloch is the Chief Executive of the Australian Petroleum Production & Exploration Association (APPEA) 

Read the original publication via The Australian here.





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Has the oil price found the direction – finally?

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The price of crude oil, which almost mimicked a turbulent whirlpool in a swollen river for the past few weeks, finally seemed to have found a certain sense of direction.

For three successive weeks, it has been rising despite the endless gloomy, economic news that has cast an ominous shadow across the globe: the unprecedented interest rate hikes, rampant inflation, stagnation of the tech sector and the relative apathy of consumers for spending, to name but a few.

Against this backdrop, the frequent, random lockdowns by China, the world’s largest importer of crude oil, hardly helped resurrecting the sentiment in the oil sector.

There are, however, encouraging signs that China is finally relaxing their rigid Zero-Covid approach in order to minimize the inevitable, collective economic cost associated with it; the reported relaxation of the curbed imposed on air travel over Covid-19 is a case in point.

In another development, Saudi Arabia, meanwhile, reduced the price of crude oil for Asia this week. The announcement came hot on the heels of an interview given by the Iranian ambassador to India on Friday, in which the latter said that Iran was willing to sell oil to India, the world’s third largest importer of oil,  if the latter could get round the US sanctions imposed on the former.

Since India managed to import oil from Russia despite the displeasure of the US over the issue, analysts believe India may turn to Iran too, in order to look after its own economic interests first – perhaps at the expense of  its exiting, strong ties with Iran’s foe in the region, Saudi Arabia.

The development generated a greater buzz in political circles, because of a report in the Wall Street Journal about an ‘imminent’ attack by Iran against Saudi Arabia, citing Saudi intelligent sources. 

It did not materialize in 48 hours as predicted; nor did it alarm the US allies to issue a rallying cry to assemble what President George Bush Jr used to call, a ‘Coalition of the willing’ in similar circumstances.

It is highly unlikely that Iran, which is in the middle of an unprecedented movement of protests by women over their rights, is in a position get involved in a war with Saudi Arabia – or any other country for that matter – which manages the two holiest sites in Islam at Makkah and Medina.

After a few days of silence, Iran scoffed at the report, while the Saudis kept mum about it.

The vulnerability of Saudi Arabia, however,  when it comes to defending its oil facilities has been a hot topic in Washington, because the Biden administration and the Saudi royal family, especially the Crown Prince,  have a frosty relationship that could determine the defense corporation between the two allies. 

The recent production cut by the OPEC+ dealt a serious blow to the relationship that had already been under strain for months. The US vowed a strong response in return, without specifying what that could be, leaving it to wild interpretations, one of which, of course, is the potential removal of anti-missile systems from the Kingdom.

With the US midterm elections just 3 days away, the rising fuel costs and the inevitable inflation that stems from it can still affect the outcome. 

In this context, if the Democrats suffer at the ballot box, the loyalists of the party will not find it difficult to identify the scapegoats. 

All in all, the stakes cannot be higher for Saudi Arabia if the price of oil keeps rising on the grounds of supply woes, partly fueled by the production cuts. 

 



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Malcy’s Blog: Oil price, Genel, PetroTal, Longboat, Harbour, Sound. And finally…

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Another good day for oil, a weak dollar initially helped but after the Fed’s comments about the economy it firmed a bit. Also Opec+ are still producing some 1.3m less than quotas which won’t get easier.
An update from Genel shows an acquisition fund of $500m+ by the year end and PetroTal announce that the 13H well is producing at around 8,000 b/d. Longboat announced that Oswig disappointed but did find a condensate discovery to analyse more of later. Harbour made its guidance and is bringing debt down and Sound cant get the Moroccan Tax Authorities persistence.

The post Oil price, Genel, PetroTal, Longboat, Harbour, Sound. And finally… appeared first on Malcy's Blog.



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How unifying power and process enables CapEx reductions in biorefineries

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As global organizations rapidly migrate towards low-emission production facilities and industrial infrastructures, biofuels become critical for decarbonizing transportation and reducing our dependence on fossil fuels.

The interest in biofuels is high because greenhouse gas (GHG) emissions from bioethanol, biodiesel, and renewable diesel are 60-80% lower than conventional fuels. As a result, according to the International Energy Agency (IEA), biofuel demand will increase by 28% between 2021-2026 – an increase of approximately 41 billion liters.

Biofuels can be placed into two main categories with very important differences:

  1. First-generation biofuels are produced from types of biomasses that are often used for food. Grains and starch crops produce bioethanol, while vegetable oils are used for biodiesel.
  2. Second- and next-generation biofuels, such as renewable diesel, sustainable aviation fuel (SAF), and lignocellulosic ethanol, expand on these traditional resources by developing fuels from non-food sources such as used cooking oil, animal fats, municipal wastes, cellulosic biomass, and algae-based resources, to name a few. These biofuels will continue to grow over the years thanks to policy mandates in various regions.

Biofuel projects can be deployed in a variety of ways:

  • Brownfield projects usually involve co-processing inside an operating refinery (low-blended products). Although physically located within a larger operating refinery, the integrated refinery still maintains segregated production.
  • Greenfield projects are often characterized by new plants that are either built adjacent to existing facilities, part of a refinery conversion project, or as facilities built as a new standalone plant. Today, standalone greenfield projects are dominant despite higher capital investment costs.

Refineries seeking to meet their decarbonization goals and accommodate the growing biofuel demand are either upgrading their existing plants or building new plants to increase their biofuel processing footprint. It is common for refineries to upgrade elements such as hydrotreaters and to repurpose assets such as storage tanks, loading and discharge jetties, electrical utilities, gas processing, wastewater treatment, and hydrogen supply to produce 100% renewable distillate.

Power and process automation convergence drive biofuel operational cost savings

In the past, the separation of power and process automation made sense. By its very nature, process control is a continuous activity with response times that can extend to several seconds. Conversely, electrical system automation is generally asynchronous, event-driven, and often occurs over a millisecond timeframe.

However, within most industrial sites, electrical equipment interacts with process control frequently and on an ongoing basis (e.g., generators, pumps, compressors, fans, valve equipment, and heating equipment). The converged power and process approach is to broaden data sharing between these two disciplines so that higher production efficiency can be attained.

The industrial internet of things and digitization create the connectivity required for these two domains to be managed more uniformly. These systems can now easily integrate into a collaborative and agile plant control system, making an attainable, cost-justifiable goal once an expensive and daunting task.

According to the ARC Advisory Group, “The fusion of power and automation is a catalyst for operational resilience and improved sustainability across the plant’s lifecycle.” Their report on the benefits of power and automation fusion concluded that by utilizing this fusion:

  • CapEx costs can be reduced by up to 20%
  • OpEx costs can be reduced by up to 15%
  • Profitability can increase by up to 3%
  • Energy procurement costs can be reduced by 2-5%; and
  • Carbon footprint can be reduced by up to 7-12%

How one refinery integrated power and process automation

One North American Fortune 500 refinery company that manufactures transportation fuels and petrochemical products recently embraced an integrated energy and automation approach. To decrease CapEx, reduce infrastructure footprint, and meet low carbon fuel standards, the company built a greenfield plant, producing renewable diesel next to its existing refinery site as part of its sustainability program. By partnering with Schneider Electric and deploying an EcoStruxure Power and Process solution suite, the company reduced capital costs by 15% and saved space at their existing site.

A consolidated E-house (i.e., a prefabricated modular power distribution center) containing transformers, switches, cables, circuit breakers, uninterruptible power supplies, and precision cooling (among other devices) now connects and interacts with distributed control systems (DCS), safety systems, and turbo machinery control on the processing side to drive faster and more accurate processing decisions.

On the maintenance side, if an issue occurs within the unified system, the technician knows if it’s an electrical or process problem as soon as the incident is reported. The electrical and process experts act as a virtual team. Confusion is eliminated, and the technicians are properly equipped to perform repairs quickly and efficiently.

To learn more about how modern power and process systems can drive higher production efficiencies while lowering carbon emissions within your biofuel operations, visit our EcoStruxure Power and Process or energies and chemicals solutions webpages.





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Pioneer Natural Resources Reports Third Quarter 2022 Financial and Operating Results

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Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today reported financial and operating results for the quarter ended September 30, 2022. Pioneer reported third quarter net income attributable to common stockholders of $2.0 billion, or $7.93 per diluted share. These results include the effects of noncash mark-to-market adjustments and certain other unusual items. Excluding these items, non-GAAP adjusted income for the third quarter was $1.9 billion, or $7.48 per diluted share. Cash flow from operating activities for the third quarter was $3.0 billion.

Highlights

  • Generated strong third quarter free cash flow1 of $1.7 billion
  • Based on third quarter results, declared a quarterly base-plus-variable dividend of $5.71 per share to be paid in December 2022
  • Repurchased $500 million of shares during the third quarter
  • Announced participation in wind and solar generation projects to increase use of renewable energy and reduce Scope 2 emissions

Chief Executive Officer Scott D. Sheffield stated, “Pioneer continues to execute on our investment framework that provides best-in-class capital returns to shareholders. This framework is expected to result in $7.5 billion of cash flow being returned to shareholders during 2022, including $26 per share in dividends and continued opportunistic share repurchases.

“To further enhance our top-tier free cash flow generation and return of capital, we have increased the return thresholds for wells to be included in our future development programs, which is expected to improve our program well productivity in 2023 and subsequent years, surpassing 2021 productivity levels. Additionally, our current 15,000-foot lateral program, which we plan to expand in 2023, is delivering improved returns through lower capital costs per lateral foot. With an inventory of more than twenty years of high-return wells, our improved 2023 development program is highly repeatable and will deliver affordable energy to the world, with some of the lowest emissions as a result of the Company’s high environmental standards.”

Oil & Gas Permits Download

Pioneer Wells Drilled 2022

Pioneer-Well-Spud-by-Quarter-2022Download

Financial Highlights

Pioneer maintains a strong balance sheet, with unrestricted cash on hand at the end of the third quarter of 2022 of $1.3 billion and net debt of $3.9 billion. The Company had $3.7 billion of liquidity as of September 30, 2022, comprised of $1.3 billion of cash, $372 million of short-term commercial paper investments and a $2.0 billion unsecured credit facility (undrawn as of September 30, 2022).

Cash flow from operating activities during the third quarter was $3.0 billion, leading to free cash flow1 of $1.7 billion.

During the third quarter, the Company’s total capital expenditures2, including drilling, completion, facilities and water infrastructure totaled $1.0 billion.

For the fourth quarter of 2022, the Company’s Board of Directors (Board) has declared a quarterly base-plus-variable dividend of $5.71 per share, comprised of a $1.10 base dividend and $4.61 variable dividend. This represents a total annualized dividend yield of approximately 9%3.

In addition to a strong dividend program, the Company continues to execute opportunistic share repurchases. During the third quarter, the Company repurchased $500 million of common stock at an average share price of $218. Pioneer believes this peer-leading return of capital strategy, which combines a strong base dividend, a substantial variable dividend and opportunistic share repurchases, creates significant value for shareholders4. The combination of fourth quarter dividends and third quarter share repurchases, on an annualized basis, represents a total stockholder return yield of approximately 12%5.

Financial Results

For the third quarter of 2022, the average realized price for oil was $94.23 per barrel. The average realized price for natural gas liquids (NGLs) was $38.09 per barrel, and the average realized price for gas was $7.58 per thousand cubic feet. These prices exclude the effects of derivatives.

Production costs, including taxes, averaged $13.62 per barrel of oil equivalent (BOE). Depreciation, depletion and amortization (DD&A) expense averaged $10.61 per BOE. Exploration and abandonment costs were $8 million. General and administrative (G&A) expense was $90 million, or $80 million when excluding $10 million in humanitarian aid to Ukraine. Interest expense was $30 million. The net cash flow impact related to purchases and sales of oil and gas, including firm transportation, was a loss of $135 million. Other expense was $36 million. Cash taxes totaled $308 million, and the Company’s effective tax rate was 20% for the quarter.

Operations Update

Pioneer continues to deliver strong operational performance in the Midland Basin, enabling the Company to place 128 and 399 horizontal wells on production during the third quarter and the first nine months of the year, respectively.

The Company is increasing the return thresholds for wells to be included in future development programs, providing a substantial improvement in expected program well productivity and returns. With these changes, Pioneer expects future well productivity to surpass 2021 levels. Future returns and well productivity reflect optimized full-stack development, drilling extended lateral lengths and a reduction in drilling of delayed targets. The Company’s deep inventory of high-return locations is expected to sustain Pioneer’s development program for multiple decades.

The Company continues to see significant capital savings and higher returns from the development of wells with lateral lengths in excess of 15,000 feet. Pioneer’s savings of approximately 15% per lateral foot on extended laterals results in internal rates of return that are 20% higher than that of a 10,000-foot lateral.

Drilling longer laterals, reducing drilling days per well and completing more feet per day, among other operational efficiency improvements, continue to benefit capital efficiency and dampen inflationary pressures.

Pioneer Operational Map (click for access)

2022 Outlook

The Company expects its 2022 total capital budget2 to range between $3.6 to $3.8 billion. Pioneer expects its capital program to be fully funded from 2022 cash flow6 of over $12 billion.

During 2022, the Company plans to operate an average of 22 to 24 horizontal drilling rigs in the Midland Basin, including a three-rig average program in the southern Midland Basin joint venture area. The 2022 capital program is expected to place 475 to 505 wells on production. Pioneer expects 2022 oil production of 350 to 365 thousand barrels of oil per day (MBOPD) and total production of 623 to 648 thousand barrels of oil equivalent per day (MBOEPD).

Fourth Quarter 2022 Guidance

Fourth quarter 2022 oil production is forecasted to average between 346.5 to 361.5 MBOPD and total production is expected to average between 655 to 680 MBOEPD. Production costs are expected to average $12.00 per BOE to $13.50 per BOE. DD&A expense is expected to average $10.50 per BOE to $12.00 per BOE. Total exploration and abandonment expense is forecasted to be $10 million to $20 million. G&A expense is expected to be $75 million to $85 million. Interest expense is expected to be $28 million to $33 million. Other expense is forecasted to be $20 million to $40 million. Accretion of discount on asset retirement obligations is expected to be $3 million to $6 million. The cash flow impact related to purchases and sales of oil and gas, including firm transportation, is expected to be a loss of $45 million to a loss of $85 million, based on forward oil price estimates for the quarter. The Company’s effective income tax rate is expected to be between 22% to 27%, with cash taxes expected to be $10 million to $30 million, representing estimated federal and state tax payments that will be paid based on forecasted 2022 taxable income.

Environmental, Social & Governance (ESG)

Pioneer views sustainability as a multidisciplinary effort that balances economic growth, environmental stewardship and social responsibility. The Company emphasizes developing natural resources in a manner that protects surrounding communities and preserves the environment.

Pioneer recently published its 2022 Sustainability Report highlighting the Company’s focus and significant progress on ESG initiatives. The comprehensive report details the Company’s leadership position on ESG metrics and targets during 2021, including enhanced disclosures on air emissions; water management practices; diversity, equity and inclusion (DEI); board of director governance and community engagement.

The Company has multiple initiatives underway that are expected to result in tangible progress towards Pioneer’s net zero emissions ambition. Pioneer has made significant progress towards the Company’s 2030 emissions intensity targets by achieving a 22% reduction in greenhouse gas emission intensity and a 50% reduction in methane emission intensity, when compared to a 2019 baseline. Additionally, Pioneer achieved a flaring intensity of 0.41% in 2021, well below the Company’s goal to limit flaring to 1% of natural gas produced. Pioneer continues to prioritize environmental stewardship and accelerated the Company’s target to end routine flaring by 2025, five years earlier than the Company’s previous 2030 target.

Pioneer is participating in two renewable energy projects that will supply low-cost, renewable power to the Company’s Permian Basin operations and to the Texas electric grid. One project includes a 140-megawatt (MW) wind generation facility on Pioneer-owned surface acreage in Midland County, which will be developed by a subsidiary of NextEra Energy Resources, LLC and is supported by a power purchase agreement with Pioneer, in which Targa Resources Corporation (Targa) will participate. This project is expected to be operational during 2024. Additionally, Pioneer will also participate in a 160 MW Concho Valley Solar project through a power purchase agreement executed by Targa. The Concho Valley Solar project commenced delivering renewable electricity during October 2022. Pioneer will not incur any capital expenditures associated with either of these projects. Pioneer will continue to evaluate wind and solar developments on the Company’s extensive owned surface acreage in the Permian Basin.

These two renewable energy projects, along with any future projects, are expected to provide an offset to Pioneer’s Scope 2 emissions through the use of renewable electricity, helping Pioneer to reduce the emission intensity of the Company’s operations while continuing to supply low-cost, responsibly sourced energy to the world.

Pioneer Energy News

Pioneer Natural Resources Reports Third Quarter 2022 Financial and Operating Results

Pioneer Natural Resources Reports Third Quarter 2022 Financial and Operating Results

Pioneer Natural Resources Reports First Quarter 2022 Financial and Operating Results

Pioneer Natural Resources Reports First Quarter 2022 Financial and Operating Results

ProPetro Announces Services Agreement with Pioneer Natural Resources

ProPetro Announces Services Agreement with Pioneer Natural Resources

Pioneer Resources to spend $3.3 billion in 2022 on 500 permian wells

Pioneer Resources to spend $3.3 billion in 2022 on 500 permian wells

Pioneer Natural Resources Reports Q3 2021 Financial and Operating Results

Pioneer Natural Resources Reports Q3 2021 Financial and Operating Results

Pioneer Announces $3.25B Permian Deal

Pioneer Announces $3.25B Permian Deal

Midland Basin Playbook

Midland Basin Playbook

Pioneer Natural Resources completes aerial surveys in the Permian

Pioneer Natural Resources completes aerial surveys in the Permian

Pioneer Natural Resources Playbook

Pioneer Natural Resources Playbook

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Benefit from the carbon capture and storage trend in 5 steps

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But what benefits of carbon capture and storage technologies are worth your attention and funding? Let’s see how you can capitalize on this trend.

What is CCS and how is it done? 

For business owners, CCS is a way to move towards a low-carbon model by “greening” energy production and operations. If we’re talking science, you can apply carbon capture and storage systems to remove CO2 emissions from stationary sources or processes, store them in underground reservoirs, and reuse them in other industries. It helps mitigate your enterprise’s carbon footprint and implement enhanced oil recovery (EOR). 

How does carbon capture work? 

CCS is a three-stage process that includes: 

  1. Capturing CO2 from various industrial sites and compressing it with the proper methods 
  1. Transporting trapped CO2 to a storage location via road transport, pipelines, or tankers 
  1. Long-term storing of captured carbon in geological formations away from the atmosphere 

Hard-to-decarbonize plants across the globe are implementing CCS to future-proof operations and remain resilient in the long run. This is because one of the critical benefits of carbon capture and storage technology is its ability to neutralize around 90% of CO2 emissions. 

How to capitalize on the carbon capture and storage trend in 5 simple steps 

Whether you plan to build your own carbon capture and storage solution or invest in an existing one, you should understand what you’re dealing with. So, here are our hands-on recommendations you can leverage to reap the benefits of the carbon capture and storage model. 

#1 Select the right approach 

There are three main types of CO2 capture to navigate: 

  • What is pre-combustion carbon capture? 

In pre-combustion carbon capture, you remove carbon before the actual combustion process by converting fuel into a mix of hydrogen and CO2 with heat. Then, you isolate and burn hydrogen to produce energy and transport the compressed CO2 to a storage facility. You’ll have to incorporate the required infrastructure as you build a new power plant to apply this type of carbon capture and storage in your production. But the effort pays off as pre-combustion capture is less energy-consuming and offers higher capture rates than post-combustion. 

  • What is post-combustion? 

Here you bind and separate CO2 from other greenhouse gases after combustion using a liquid solvent and gas separator. This is the most widely applied carbon capture and storage technology because it allows reusing CO2 at a storage facility and can be added to existing sites. However, this method requires high capital costs and heavily equipped infrastructure that consumes more energy. 

This approach is applicable only in specific cases when you process fuel in pure oxygen-rich environments. After you cool and liquefy CO2 and water vapor in a boiler or gas turbine, you can dehydrate and compress carbon for further transportation. It also allows the use of generated steam to power your turbines or produce electricity. Moreover, the oxyfuel  method is costly but can be integrated at some types of existing plants and offers the possibility of complete CO2 removal. 

#2 Create a business plan 

Would you buy a big share of carbon capture stocks, or would you migrate your plant to a carbon capture and storage business model? Whatever you choose, there are costs to consider beforehand. Numerous studies over the past decade have emphasized the possibility of reducing OpEx and CapEx by around 30-70% when equipping your facilities with CCS. It’s just much easier to do through technology refinement, retrofitting, and continuous efficiency improvements from a first-generation site to the next. 

What you can do to future-proof your CCS projects: 

  • Explore existing low-carbon business models to develop your own financial strategy 
  • Elaborate risk management strategies and anti-crisis plans 
  • Calculate the expected revenues and possible losses (for each carbon capture stock, for instance) 
  • Communicate your business plan to all stakeholders and get their support 
  • Collaborate with governmental organizations to win their substantial support or even funding 
  • Partner with other CCS providers and innovators to create a network and join forces for large-scale constructions 

Yes, you’ll invest heavily, but a potential ROI is worth it. Official estimates state that a CCS approach can save you 40% of the expenses you’ll need to meet the 50% global emissions reduction by 2050. Sounds promising, doesn’t it? 

save costs for next-gen carbon capture and storage projects

#3 Opt for tech advancements 

The latest Industry 4.0 achievements are what you need when it comes to carbon capture and storage systems. So, we advise investigating the carbon capture stock market to find Big Tech companies that develop highly advanced and efficient CCS solutions with high capture capacity. 

CO2 capture tech

For instance, check inventions in the direct air or compact carbon capture fields. Companies like Baker Hughes, Carbon Clean, and Mitsubishi Heavy Industries develop groundbreaking bite-sized capture tech with modular designs that promote more widespread use for small and mid-size businesses. What’s more, manufacturers expect smaller systems like these to capture around 95% of CO2 emissions. 

#4 Leverage the benefits of carbon capture and storage 

You might not be a leading climate change activist, but your investors and customers most likely are. So, a low-carbon business model is what will help you secure their loyalty. As society shifts toward renewable energy and net-zero initiatives, you can use CCS advantages to accelerate changes while maintaining your O&G business continuity. 

Top 8 opportunities in the carbon capture and storage sector: 

  1. Increase power generation with CO2 steam cycles 
  1. Improve your on-site waste management 
  1. Optimize fuel consumption and oil production 
  1. Unlock new revenue streams with eco-friendly services 
  1. Boost the quality of natural gas by removing CO2 from it 
  1. Reduce facility management and maintenance costs 
  1. Safeguard existing on-site jobs and create new ones 
  1. Produce new materials using CO2 (concrete, hydrocarbons, polyurethanes) 

global carbon capture and storage hubs

#5 Invest in CCS strategically 

The carbon capture stock market offers plenty of options to benefit your portfolio, and it’ll only skyrocket in the next decade. So, you’ll not only fund energy transition initiatives but also profit from a billion-dollar industry while the competition is still relatively low. 

How can you buy the perfect carbon capture stock? There is no universal recipe—you know that investing is a risky business. We can advise starting with established carbon capture and storage market players in the USA, Europe, and Japan. Diversify your portfolio as much as possible to manage disruptions proactively. 

The 5 best carbon capture stocks to invest in 2022-2023: 

  1. Aker ASA (AKER: NO) 
  1. Exxon Mobil (NYSE: XOM) 
  1. Equinor (NYSE: EQNR) 
  1. Occidental Petroleum (NYSE: OXY) 
  1. NRG Energy (NYSE: NRG) 

Summing up, you have a great chance to capitalize on the new climate legislation and CCS solutions by cutting your emissions and earning money in the process. 

companies that invest in CCS

What does the future hold for carbon capture and storage tech and stocks? 

Positive outcomes in the CO2 footprint mitigation field will only increase demand for EOR and advanced carbon capture and storage projects. It means investments in CCS technologies can bring you substantial ROI, open up new markets, and attract stakeholders motivated to drive decarbonization. Moreover, carbon capture stocks will remain resilient and lucrative, so getting the ball rolling now will help you avoid tight competition and overspending. Considering all this, who wouldn’t want some carbon capture and storage stocks in their portfolio to gain a competitive advantage? 

future of the carbon capture and storage sector



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IS OILFIELD SERVICES (OFS)  THE WAY TO PLAY ENERGY RIGHT NOW?

Post By Oil and Gas


Halliburton (HAL – NYSE) released their third quarter results on Tuesday night and boy were they ever bullish on oil field services (OFS).

Right out of the gate CEO Jeff Miller put it bluntly – “our outlook is strong”.  He followed it up by saying why: “oil and gas supply [will] remain tight for the foreseeable future”.

These comments echoed what we heard from Baker Hughes (BKR – NYSE) when they reported last week.

While Baker Hughes admitted that the macro-outlook was “increasingly uncertain” they said they were looking forward to a “multiyear upswing” in upstream oil and gas spending.

The irony is that what is driving the outlook is the lackluster response of operators.  There is no drilling boom.  Quite the opposite.

It is financial discipline that is setting the stage for a much longer – and potentially more profitable – upcycle.

Baker Hughes expects prices to remain strong even if there is a recession because we just aren’t seeing the usual “drill-baby-drill” response we have seen in the past.  Halliburton pointed to “multiple years of underinvestment” supporting their long-term thesis.

While North America is strong, it is international operations that are accelerating.   South America, West Africa and the Middle East are leading the way.
 
That’s probably why Schlumberger (SLB-NYSE) is up 50% in a month, and hitting 4 year highs.  This OFS major is very well distributed around the globe.

In the US, The S&P Oil & Gas Equipment & Services Select Industry Index (XES-NYSE) has also had a run recently, within 8% of its year high (which is also its 3 yr high).

In Canada, analysts are talking about a 30% increase in OFS fees to producers this year, with another 10% next year.

So it looks like an increase in revenue and EBITDA for the rest of this year and next year is in the bag—much of it at the expense of oil and gas producers, their customers.

Like the producers, OFS companies have gone crazy trying to grow, with new capex for yellow iron remaining low.  The most I see in costs is actually a “greening” of OFS equipment—moving away from diesel to natgas fueled rigs and machinery.

PRODUCER CASH FLOW COULD FLATLINE OR DROP
EVEN IF OIL GOES HIGHER

 
If you have been reading my blog for even a couple years (I started blogging in 2009) you will remember one of my sayings—there is no such thing as an American oil stock.  They are almost all natgas producers with a 40% + wighting in oil.  The Permian starts off oily, but gets gassy quickly.  Only the Bakken up in North Dakota—where the geology is shallower—do you see true oil stocks.

That means producers’ cash flows are heavily weighted towards natgas—which is looking weak right now, and will likely get weaker.

Natural gas pricing has dropped from levels that quite honestly, I never thought we’d see.  Some say a correction was due.  I say the industry is catching up.  It always catches up.

So there’s a good chance that even if oil prices rise a bit–highly likely–overall cash flows for NA producers might not benefit from higher cash flows if natgas falls even more.

And that’s VERY possible.  The big headline this week was that spot EU natural gas prices went negative.  Less of a headline was that Permian natural gas prices (the big Texas oil play that produces many billions of cubic feet of associated natural gas) also went negative.

Of course, that has everything to do with pipeline constraints.  But it does demonstrate that producers of natural gas are doing what they do best – producing more of it.

In the Marcellus (northeast USA)  and Haynesville (Oklahoma/Louisiana) rigs are up 50%.  In the Permian, it’s up 30%.  We are seeing higher output as a result – up 4.5 bcf/d year-over-year.

Source: Bank of America Global Research

Production of natural gas is sneaking up.  I’ve been telling subscribers for weeks that prices will be coming down as the US is increasing natgas production steadily in 2022—often by 500 million – 700 million cubic feet of natgas per day per month. Inventories of natural gas are sneaking back up towards the 5-year average. 

Prices are going the other way.

2

Source: Bank of America Global Research

Natural gas prices are still above $5 which means there is still incentive to drill.  But it won’t take much (a warm winter anyone?) to send them down further. 

At some point that could mean a much lower natgas rig count in the US—now at 157.  My research suggests it only taks 110 rigs to keep US production flat, so that’s 47 rigs that could drop over time.  But while the front month natgas price is down a lot, the pricing two years out on the futures curve has not moved near as much.

That’s not a huge predictor of price, but I think that’s what producers will be looking at before seriously putting down rigs. (That will take pricing even lower of course!)

WHAT IF OIL JUST GETS BORING?

 
While natural gas has a few headwinds, oil looks better.  Trying to figure out what oil prices should be (meaning absent intervention) is impossible.  What with

  1. the OPEC+ cuts,
  2. SPR releases in the USA
  3. Chinese lockdowns,
  4. and the huge shortages of refined products (especially diesel) in the western world

that are pushing up prices further up the chain – it makes my head hurt.

The simplest answer – the one no one ever says – is maybe oil prices just don’t do much of anything at all?

We’re always looking for a big run up or a huge collapse.  It would confound everyone if oil just sat this one out, in a relatively tight range, and bored all the traders to sleep.

If it does that, the OFS providers will take it as a win.  Those with international exposure (to Brent and Middle East pricing), will do well.

The operators with the biggest exposure are the big guys.  Baker Hughes, Halliburton, Schlumberger (SLB – NYSE).

Going big is usually out of my wheelhouse.  But international small cap OFS is a tough find these days.

The problem with the big boys is that they aren’t exactly cheap.

3

Source: Sentieo Data

There may be upside to these estimates, but paying some 20x earnings and 10x EBITDA for OFS doesn’t strike me as a bargain.
 

GO TO SEA

 
One comment that caught me off guard came from Baker Hughes.   They made special note of the growth in offshore activity – saying it is “noticeably strengthening”.

Baker Hughes forecasts “several years of growth” in their international and offshore business.  Quite the statements given that offshore has been left for dead by many.

Those comments led me to do a shallow dive into Transocean (RIG – NASDAQ).
I fully admit I had written off companies like Transocean just like everyone else.

Yet Transocean did $245 million of EBITDA last quarter   On their last call, which was Q2 back in August, Transocean said they saw a “rapid tightening of the offshore market for high capability drilling assets unfolding across multiple regions”.

Yet the stock is barely back to where it was at the end of August and still well off of levels from March to May.

4

Source: Stockwatch.com

Of course, everyone watching Transocean is worried about the debt.  For good reason.  One year default swaps on Transocean imply about a 1 in 5 chance they default.

Transocean has a lot of debt–$7.2 billion of it.  While they have $2.5 billion of liquidity today, they expect that liquidity to decline to $1.1 billion by December 2023.

Lots to worry about.  But its hard to ignore what they are saying about the business.  A “very constructive outlook”, expecting “further tightening”, and “increasingly healthy day rates” – again this was back in August.  Now Baker Hughes is telling us that the outlook has only gotten better.
 

WHAT COULD HAVE BEEN

 
What I would really like is a straightforward bet on international OFS activity.  Fortunately, I know just the name!  Unfortunately, there is a catch.

I owned National Energy Services Reunited (NESR – NASDAQ) as a portfolio company from mid-2020 until the summer of 2021.

This is not a household name, but also not a micro-cap.  You may never had heard of NESR.  But it is one of the largest OFS companies in the Middle East and Asia Pacific region.

NESR is the only publicly traded oilfield service pure play in the region.

You could argue a focus on the Middle East, what with OPEC+ cuts to production, does not play in their favor. 

But NESR might make up for it on volume.  In September they announced that they had secured their first multiyear directional drilling contract with Saudi Aramco.  This after they were awarded a $300 million fracturing contract from Aramco in April.

NESR seems in many ways like the ideal play.  

The problem, for the moment, is that they have no financials.

In February NESR announced they would have to restate their 2021 financials due to issues with accounts payable and accrued liability accounting.

They’ve quantified the restatement (at most $90 million) and at the time of the restatement announcement they guided to decent YE results.  But still, its tough to make a call here until the restatement is out of the way.

I’ve always liked the NESR business, and as I said I owned them in the portfolio last year, but I never jump into a stock where I can’t see the numbers.

I am on the lookout for news that the accounting issues are behind them.
 
In North America, there are 6-10 drillers and frackers in both Canada and the US.  Like the producers, they were priced for bankruptcy and then had GREAT stock runs in 2021. 

Energy is slowly getting more respect from generalist funds due to low valuation and return of capital (Share buybacks and dividends). Now energy charts suggest they could run again–but multi-baggers are gone, just like with the producers now. 

I’m happy with 50% in a year.  But unless the multiples get up off the mat–most are trading 2-3.5x cash flow–they will need their multiple to almost double as well.  With lower natgas potentially keeping producer cash flows in check, I think we’re at that part of the energy cycle where if it happens anywhere, it can happen in OFS stocks.



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Energy Market Growth & Production: 3 Trends You Need To Know | Enverus

Post By Oil and Gas


Operators and oilfield service companies need to keep pace with the volatile and rapidly evolving energy industry. However, if you are relying solely on public filings to make investment decisions or anticipate future activity, you’re shortchanging yourself. Public data often lags by three months and can be inaccurately reported. If you consider the state of the industry three months ago compared to today, you know the public filings are not going to get your company to where it needs to be in the next quarter.

Every day there is a new headline to consider, with direct implications to near-term strategic planning. Whether the global news involves the economic downturn affecting oil demand, such as Russian supply being hit with EU sanctions or the major economic headwinds in China, or LNG construction delays, these geopolitical events affect daily market trends and drive changes in oilfield activity.

In our October 2022 “Macro Forecaster” published by Enverus Intelligence Research, our analysts assert that weakening economic conditions and outperforming Russian supply will incentivize crude and product builds. Embedded in this view was extensive analysis on North American supply, specifically in the Lower 48. We detected well pads being constructed in real time, outlined historical and current trends in rig deployments and frac crew demand, and offered productivity metrics in a single platform, so you can stay ahead of the changing energy landscape.

Using Activity Analytics, we uncovered three key trends to help you know what’s happening in the oilfield.

1. DUC inventory is nearly depleted

In the published report, analysts suggest excess drilled uncompleted (DUC) inventory is nearly depleted, with new wells coming mainly from newly drilled inventory. This shift in strategy comes from oil price pressures easing while operating costs rise.

Using only publicly filed permits, your ability to assess the change in strategy would be both delayed and incorrect, because not all approved permits will see drilling activity. Focusing your efforts on satellite detected constructed pads, you will have an accurate, near real-time view of where drilling, completions and production will occur, rather than taking an educated guess on which permits will be drilled.

With detected constructed well pads, you can determine:

  • Where and when service companies can be poised to support operations.
  • If pricing environments are worthwhile for operators to continue development plans.
  • If the DUC duration from a specific operator falls within a normal timeframe compared to peers, or if it seems the operator is sitting on the asset.

2. Pricing power for service providers as demand outpaces supply growth

For operators and service companies alike, it is crucial to keep tabs on demand for oilfield goods and services. Active rig tracking shows demand continues to outpace the ability and desire to grow supply, leading to increased pricing power for service companies.

Additionally, analysts expect the rig count in oil plays to increase further in 2H22, while rigs targeting gas are expected to decline in 2023 due to takeaway constraints.

Leverage real-time, GPS monitored rig activity to understand where more than 90% of the rigs are in North America to directly inform how you can fit your strategy to near-term market trends.

Use proprietary rig and drilling tracking to:

  • Indicate subsequent investment from operators.
  • Assess changes in market share from service companies.
  • Determine which types of rigs can support your asset development plan to save service costs.
Rigs through time, colored by operator.

3. Frac crew demand pushes upper bounds of available capacity

Frac crew demand continues to push the upper bounds of available capacity, meaning equipment shortages are creating pressure on service companies to fulfill scheduled fleet activations.

Operators are making an early start in planning for 2023 to lock in materials and assets for the year. However, the U.S. is currently operating at a near 100% effective crew utilization, limiting overall production growth. Leveraging satellite informed completion activity allows for an accurate, near real-time view of frac crew activity and utilization.

Get ahead of delayed and inaccurate completion filings to:

  • Identify where and when operators are completing wells, giving you an indication of when wells will complete their lifecycle.
  • Understand fluctuations in activity and future market needs.
Frac crews through time, colored by operator.

Enverus Activity Analytics offers insights into changes in activity levels across North America. With access to both active and historical pad construction, drilling and completions, you can:

  • Find answers faster to determine who is positioned for growth to uncover investment opportunities and track market shifts.
  • Increase efficiency by getting an edge on development planning and more accurate production timeline predictions.
  • Save time and resources by having all data sets and intelligence linked in a single platform.

Learn more about how Activity Analytics can help you stay informed about important oilfield events.



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Pertamina Says Gas Output Improves at Mahakam Block

Post By Oil and Gas





October 26, 2022


File image – Credit: Pertamina

Natural gas output at Indonesia’s Mahakam block rose to 590 million standard cubic feet per day (mmscfd) in October, the state energy company Pertamina said on Wednesday, as the operator boosted drilling.

Once a major gas-producing block, output at Mahakam dropped to 505 MMSCFD earlier this year, a company spokesperson said. Production was expected to hit an average 524 mmscfd this year.

“We have implemented more effective, efficient, and faster drilling in finding new oil and gas resources,” said Pertamina Hulu Mahakam General Manager Krisna, adding that government incentives, including VAT exemption, helped the company increase its investment. 

New wells from Mahakam’s North Sisi and North Nubi fields,  which started operation in recent months, contributed to the higher output, Krisna said, adding the company would continue to invest in new wells. 

Indonesia’s gas distribution in the January to September period stood at 5,353 mmscfd, below the government’s 5,800 mmscfd target, due to delays in several major projects, upstream oil and gas regulator SKK Migas said earlier this month.

(Reuters – Reporting by Bernadette Christina; Editing by Fransiska Nangoy and Kanupriya Kapoor)



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