The Mancos Shale and Other Plays in the San Juan Basin of Northwest New Mexico and Southwestern Colorado: Ripe for a Resurgence?

     The San Juan Basin in northwestern New Mexico and southwestern Colorado, which mainly produces natural gas, saw booms and busts in the 1950s, 1980s, and 1990s. By 2000, the basin was producing its peak at 4.5BCF per day, about 8% of U.S. natural gas production at the time. Since then, however, as shown below, San Juan Basin production has steadily dropped by more than half from that peak to about 2 BCF/day. The graph shows basin production in the three counties that make up nearly all of it, Rio Arriba and San Juan counties in New Mexico, and La Plata County in Colorado.

     The main reason for the drop is that plays with better economics became available, especially as once surging Fruitland Formation coalbed methane production dropped. Big players like BP and ConocoPhillips left the basin for better plays like the Permian. The stratigraphic section below shows some of the producing reservoirs.

Source: Wikipedia

    RBN Energy reports that two operators in particular are poised to develop the Mancos Shale in the San Juan Basin, TXO Partners and Mach Natural Resources. TXO Partners, led by industry veteran Bob Simpson, reported in January 2025 that they think they can eventually produce up to 3 Tcf of gas in their 58,500-acre position in the basin from the Mancos Shale. They think that with modern technology, they can produce up to 25BCF per well in their core acreage position. 

     Mach Natural Resources, led by another industry veteran, Tom Ward, recently entered the San Juan Basin while looking to expand beyond the competitive Midcontinent region. RBN describes Mach’s recent entry into the basin via acquisition:

“Mach Natural Resources also announced July 10 that it had reached a deal to buy Sabinal Energy’s 130,000 net acres and 11 Mboe/d of production (98% liquids and 2% gas) in the Permian for $500 million. The IKAV and Sabinal deals diversify Mach’s holdings, which previously had been limited to the Anadarko Basin. When the deals close, Mach’s production will total 152 Mboe/d, including 596 MMcf/d of gas (56% of it in the San Juan {about 334 MMCF/day or 17% of basin production} and almost all of the rest in the Anadarko), 30 Mb/d of crude oil and 22 Mb/d of NGLs.”

     RBN also notes the availability of pipeline takeaway capacity in the region, but also notes a history of changing/reversing flows on those systems. San Juan gas mostly moves north and west from the basin.  

      Seeking Alpha reports that Mach is shifting to a focus on natural gas, up to 70% and over 50% of company-wide revenue beginning in 2026, which the Mancos Shale can help to provide. They plan to run three rigs in the San Juan basin in 2026, focusing on Mancos gas.

     According to Wikipedia:

“The San Juan Basin contains ample fuel resources, including oil, gas, coal, and uranium. The basin has produced from over 300 oil fields and nearly 40,000 wells, most of which are sourced from Cretaceous-aged rocks. Furthermore, 90% of the wells have been drilled in the state of New Mexico. As of 2009, cumulative production reached 42.6 trillion cubic feet of gas and 381 million barrels of oil.”

     The Wikipedia entry also gives some history of oil and gas production in the basin:

     In addition, there is some production from Paleozoic reservoirs of Mississippian, Pennsylvanian, and Permian age to the west in the Four Corners area.

     The Lewis Shale in the basin, which I once used as a correlate for a fractured siltstone play in Southern West Virginia, is not very productive in the basin; it does produce significant hydrocarbons in the Green River Basin to the north, into Wyoming. The Fruitland coalbed methane play in the basin, unfortunately, has been associated with a methane cloud that formed over the basin, mainly due to the de-watering of the coalbed, which allowed large quantities of methane to escape into the atmosphere.

     The Mancos produces some oil to the south, but the highest TOC rock is to the north in the gas window. A 2019 oral presentation given at the 2019 AAPG Rocky Mountain Section Meeting is the source of the following graphics and abstract. The paper focused mainly on oil production and thermal maturity in the southeastern part of the basin. Production there resurged as horizontal drilling sought to tap oil, mainly from 2011-2015.

 

 

   

 

References:

 

The Mancos Shale in the Southeastern San Juan Basin: A play limited by structure and associated thermal maturity. Ron Broadhead. AAPG. Search and Discovery. Article #11273 (2019), December 16, 2019. View PDF (searchanddiscovery.com)

I'm Still Standing - The San Juan Basin Has Seen Many Ups and Downs. Is Another Upturn Just Ahead? Housely Carr. RBN Energy. August 5, 2025. I'm Still Standing - The San Juan Basin Has Seen Many Ups and Downs. Is Another Upturn Just Ahead? | RBN Energy

Mach Natural Resources outlines shift to 70% natural gas mix by 2026 while targeting leverage reduction. Seeking Alpha. August 9, 2025. Mach Natural Resources outlines shift to 70% natural gas mix by 2026 while targeting leverage reduction

TXO Partners, LP. Investor Presentation. August 2025. TXO+Investor+Presentation_8.4.25_vFinal.pdf

San Juan Basin. Wikipedia. San Juan Basin - Wikipedia

 

 

Kimmeridge White Paper on Remaining North American Shale Inventory is Informative: Summary Review, & Commentary

  

      This May 2025 paper utilizes some interesting economic methodologies, cost-comparisons, and reserves evaluation to determine economic inventory remaining in the major North American shale plays, encompassing both oil and gas plays. It ranks plays according to future potential and shows that there will be some shifting of play focuses. In Canada, there is significant room to expand the Montney and Duverney plays. With Canada contemplating another major oil pipeline to the Pacific Coast and more LNG export capacity on that Pacific Coast, there is interest in expanding the country’s energy superpower status to new markets. Canada is the world’s fourth-largest oil producer after the U.S., Russia, and Saudi Arabia. In the U.S., some prominent shale basins are getting low on core location inventory. These include Haynesville, Midland, Williston, and SCOOP/STACK.

     Kimmeridge explains its goals and focuses in the report:

“…we set out to model well economics for the majority of foreseeable North American shale inventory  to provide a nuanced, bottom-up view on where the industry falls within the capital efficiency life cycle. Then we used this information to achieve a greater understanding of the current investment opportunity landscape and what the future has in store by coupling historical well data with our inventory characterization to illustrate the full life cycle of shale capital efficiency. We finish this piece with our views on Kimmeridge’s large remaining investment opportunity set, and also some notes on potential global supply implications from our work.”

     The report makes me wonder about the future of oil & gas supply in light of planned significant increases in U.S. LNG exports and oil exports, along with expected higher natural gas demand due to higher electricity demand. Oil demand trends are less certain, but with expected OPEC near-term increases and corresponding low oil price forecasts, it seems that oil is well-supplied for the moment. Some macro trends in North American oil plays by Eneverus are shown below:

     The report also notes that there is still some great inventory out there and opportunities to make deals that pay out well. However, they also indicate that there is a likelihood of production plateauing at some point:

“The Step-Change in Production Growth Is Behind Us: We expect that declines in capital efficiency should cause North American production to plateau and ultimately begin to decline over the coming decade. This will likely set a floor for commodity prices longer-term, as the industry will struggle to deliver the hydrocarbons the world demands. This dynamic will also undoubtedly spur further consolidation of the North American E&P sector over the next 10 years, as shale matures.”

     Their outlook 10 years into the future suggests that natural gas growth may not be able to keep up with new LNG demand expected to come online over the next decade without the price of natural gas rising. The EIA expects the natural gas price to rise, especially in areas like the Marcellus, where it is suppressed due to inadequate pipeline takeaway capacity. This, along with projected domestic electricity demand growth, could mean higher electricity prices for U.S. consumers (grumble, grumble). Higher prices could unleash non-core locations that could then be drilled economically.

     The white paper says that there are three ways to compare inventory quality by basin:

1) recycle ratio,

2) calculating the number of locations with economics above a certain threshold

3) comparing inventory between basins by front-end inventory duration.

     According to Investopedia:

“A recycle ratio, or recycle rate, is a key profitability measure of the oil and gas industry. The ratio is calculated by dividing the profit per barrel of oil by the cost of finding and developing that barrel of oil.”

     The white paper explains the recycle ratio in detail:

“As we discussed in prior research, the recycle ratio is a useful economic metric for determining and comparing profitability at the well, asset or company level. Specifically, we have discussed in depth how the proved developed recycle ratio can be determined at the company level from Form 10-K data and is useful for comparing capital efficiency both between companies in a given year as well as for the US oil and gas industry through time. In its simplest form, the recycle ratio calculation is:

“Said another way, the recycle ratio is the operating cash flow generated per barrel produced divided by the cost to add a barrel of reserves to replace it. This metric indicates whether you are generating enough cash flow to replace the barrels you are producing, and therefore can grow economically through internally generated cash flow. As an example, a recycle ratio of 200% (or 2.0x) means the operator is generating $2 for every $1.00 invested. A recycle ratio of 50% (or 0.5x) means the operator is only generating $0.50 for every $1.00 invested, which suggests capital is not being invested in an efficient manner.”

     Below are the five basins with the best recycle ratios:

1. Delaware at 3.24x

2. Marcellus at 3.19x

3. Montney at 2.79x

4. Midland at 2.69x

5. Williston at 2.61x

 

     They note that recycle ratios often do not tell the whole story and can be incomplete. This is because they are an average and that the average can be pulled down in large basins with a variation in rock quality and economics (Ex, Eagle Ford & Austin Chalk) or pulled up in basins where economics are challenging enough that only Tier 1 locations are drilled (Ex, SCOOP/STACK).

     They also utilize creaming curves for each basin in their recycle ratio analysis, as shown in the second graphic below, where they plot each basin’s recycle ratio with its creaming curve. This is how they arrive at method #2 of deriving the remaining inventory by the total number of locations with economics above a certain threshold. The creaming curve is a metric used to determine the production maturity of a basin. According to a 2014 AAPG presentation paper by Mauricio Orozco Bohorquez of Repsol:

     Based on method #2, they give the following basin rankings by remaining locations above a certain economic threshold, in this case, using recycle ratios above the 2023 average of 2.6x. One limitation of method #2 is that it ignores the pace of development. If operators are burning through inventory, there will be less room to grow in the future.

1. Delaware at 24,000

2. Montney at 20,000

3. Marcellus at 4,600

4. Midland at 4,500

5. Eagle Ford and Austin Chalk at 2,400

     They consider method #3 - comparing inventory between basins by front-end inventory duration – to be the best overall method.

“This means evaluating how long it would take for operators to drill from the highest to the lowest recycle ratio locations at the current activity pace (2023, in this case) until they start drilling below-2023-average wells (i.e., below the average recycle ratio.)”

     The basin rankings for method #3 are given below:

1. Montney at 22 years

2. Duvernay at 15 years

3. Delaware at 8 years

4. Marcellus at 6 years

5. Uinta at 4 years

     The paper goes on to explain some of the possible overly optimistic assumptions as well as the possible overly pessimistic assumptions in their analysis. They believe that those assumptions will more or less cancel each other out.

   In the appendix, they explain how they did the modeling for the paper:

 Step 1: Build and Train Machine Learning (ML) Models

     First, they built and trained ML models for two key metrics: estimated ultimate recovery (EUR) and capex across 25 major oil and gas plays. They utilized Shapley plots to estimate the impact of each variable.

 Step 2: Establish Commercial Assumptions Models 

     Here, they built a framework for estimating key commercial parameters for any given well location. The averaged mapped value for each of the eight parameters used is shown in the table below.

Step 3: Make Standardized Maps

     Then, based on the previous steps, they were able to make standardized maps for each basin for EURs, capex, and economic performance. Below is a standardized recycle ratio map for the 25 major North American oil & gas plays.

Step 4: Construct Inventory Shapefiles and Database

“The final step in our process utilized our in-house geographic information systems (GIS) expertise to create “shapefiles” representing the remaining inventory in North America. Using the same well spacing assumptions from the standardized mapping workflow, we extrapolated inventory shapes between existing wells and out to the basin edges. Each location was credited with as much lateral length as possible, given nearby offsets and land constraints. Each remaining location required a modern well within a five-mile radius. Key details—such as lateral length, child designation, likely operator, true vertical depth, and completion design—were populated for each location. EUR and capex predictions were then extracted from the nearest mapped grid point and scaled based on the actual lateral length of each location. Finally, commercial assumptions were applied to calculate the well’s recycle ratio at midcycle $70 oil and $3.50 gas prices.”

     Overall, this was an excellent report. It shows that there are other geologists, engineers, and accountants working on ML-based basin analysis and comparison besides NOVI Labs, who also does excellent work in this area.

     Below are some interesting summaries of Kimmeridge’s analysis published by OilGasLeads.com, which characterize the aspects of the five best-ranked plays (by method #3) through about 2035: Montney, Uinta, Marcellus, Delaware, and Duverney.

   

 

 

References:

 

What Remains: North American Upstream Inventory. Kimmeridge. May 2025. What-Remains-North-American-Inventory.pdf

The Next Shale Frontier: Kimmeridge Ranks the Top North American Basins for the Next Decade. OilGasLeads.com. May 3, 2025. The Next Shale Frontier: Kimmeridge Ranks the Top North American Basins for the Next Decade – Oil Gas Leads

Recycle Ratio: What it Means, How it Works, Example. Will Kenton. Updated September 20, 2022.Reviewed by Thomas Brock. Investopedia.  Recycle Ratio: What it Means, How it Works, Example

Hydrocarbon Discovery Potential in Colombian Basins: Creaming Curve Analysis. Mauricio Orozco Bohorquez. AAPG Search and Discovery Article #10613 (2014). Hydrocarbon Discovery Potential in Colombian Basins: Creaming Curve Analysis; #10613 (2014)

BP’s New Oil Find in Sub-Salt Santos Basin Carbonates Offshore Brazil is Huge but There are CO2 Concerns

  

     BP describes their recent oil discovery in the Bumerangue Block Offshore Brazil, targeting carbonates in the sub-salt Santos Basin, as its biggest find in 25 years. According to BP’s press release, the well was drilled:

“…404 kilometres (218 nautical miles) from Rio de Janeiro, in a water depth of 2,372 metres. The well was drilled to a total depth of 5,855 metres.”

“The well intersected the reservoir about 500 metres below the crest of the structure and penetrated an estimated 500 metre gross hydrocarbon column in high-quality pre-salt carbonate reservoir with an areal extent of greater than 300 square kilometres.”

“Results from the rig-site analysis indicate elevated levels of carbon dioxide. bp will now begin laboratory analysis to further characterize the reservoir and fluids discovered, which will provide additional insight into the potential of the Bumerangue block. Further appraisal activities are planned to be undertaken, subject to regulatory approval.”

     This discovery also dovetails nicely with the South American emergence as the leader in oil production growth in the Western Hemisphere, which I wrote about last month.

     The abundance of CO2 in the pre-salt Santos Basin is well-established. Due to this, the CO2 is mitigated by capturing it and re-injecting it. Brazil’s Petrobras reinjected 14.2 million tons of CO2 in 2024 from 22 floating production, storage, and offloading (FPSO) vessels. It is injected for enhanced oil recovery, which makes it useful as a working fluid. Injection of produced CO2  into these pre-salt reservoirs makes up more than a quarter (28%) of the global capacity reported for 2024. Thus, the Santos Basin is a major CCS hub, or more specifically, a CCUS-EOR hub.

     A 2019 paper in Geosciences explores the geotectonic controls on the accumulation of CO2 in Brazilian pre-salt basins. Mantle intrusions associated with rifting are thought to be the source of high-CO2 areas, with small faults possibly connecting the magmatic body to the sedimentary section above it. The abstract below explains the geological hypothesis, and the maps show locations, stratigraphy, and structural features of the Santos Basin. I assume BP’s block is within or very near to the Santos Outer High, as depicted.

     Below, they explain different geological ideas about the sources and distribution of CO2 in the reservoirs.

“The large concentrations CO₂ in Santos Basin were unexpected during the early exploratory process of its deep-water areas. However, drilled pre-salt prospects have shown a wide range of CO₂ contents bringing together environmental and production complications. The mantellic origin of these CO₂ occurrences was established via noble gases isotopic analyses [4]. Nevertheless, processes and mechanisms responsible for the fate (introduction, migration, and preservation) of CO₂ in petroleum systems still remain unclear.”

“Many authors have suggested that the “CO₂-risk” in sedimentary basins could be related to the proximity of igneous intrusions and deep-seated faults, or to geothermal gradient higher than 30° C/km [3,5]. Other geoscientists suggested empirically that in some areas as, for example, in the Southeast Asia, CO₂ accumulations must be controlled by type and age of crustal basement, fault density, temperature, and pressure of reservoirs [6].”

“More recently, strong evidence has been gathered indicating that mantle helium and occurrences with higher percentages of CO₂ were related to areas of crustal thinning in depths of about 26–28 km, with thermal flux higher than 61 mW/m² [7].”

“Such conditions suggest rock melting due to the asthenosphere rising towards the crust. However, the occurrence of just one or more factors described above is not an unequivocal proxy for large accumulations of CO₂ in petroleum reservoirs. Such uncertainties are the main reason to investigate more thoroughly processes and mechanisms that generate, introduce, and accumulate CO₂ in petroleum systems. Independently of such myriad of details to be studied, a tool with the power to recognize deep related magmatic processes would be an excellent proxy to infer “CO₂-risk” in petroleum reservoirs.”

“In this way, our work focused on crustal studies is based mainly on potential method data associated with the geologic interpretation of the Jupiter Prospect data, where the highest CO₂ concentrations are reported up to date. The obtained results allow us to propose an association of the CO₂ and intracrustal intrusions of mantle-derived material.”

“Both gravity and magnetic data indicate the existence of a highly stretched continental crust under the São Paulo Plateau and a rather unique and conspicuous anomaly under the Jupiter Prospect. Modeling indicates that this anomaly corresponds to an intracrustal intrusion that reached almost to the top of the basement rocks in this area. We interpret this intrusion as the main responsible agent to transport CO₂ from the mantle into the reservoir levels in the pre-salt section of this area. Other occurrences of CO₂ in Santos Basin are all located in the stretched crust of the basin and are also interpreted as provenient from mantle material ascending along major fault segments.”

     

 

References:

 

bp announces hydrocarbon discovery at Bumerangue exploration well, offshore Brazil. BP. August 4, 2025. bp announces hydrocarbon discovery at Bumerangue exploration well, offshore Brazil | News and insights | Home

BP Announces Major Oil and Gas Discovery Off Brazil Coast. Pipeline Technology Journal. August 5, 2025. BP Announces Major Oil and Gas Discovery Off Brazil Coast | Pipeline Technology Journal

22 FPSOs in Brazil’s pre-salt enable Petrobras to break CO2 reinjection record. Melisa Cavcic. Offshore Energy. March 31, 2025. 22 FPSOs in Brazil’s pre-salt enable Petrobras to break C02 reinjection record - Offshore Energy

Geotectonic Controls on CO2 Formation and Distribution Processes in the Brazilian Pre-Salt Basins. Luiz Gamboa, André Ferraz, Rui Baptista and Eugênio V. Santos Neto. Geosciences 2019, 9(6), 252. May 14, 2019. Geotectonic Controls on CO2 Formation and Distribution Processes in the Brazilian Pre-Salt Basins

 

The Four Requirements for Effective Nature-Based Climate Solutions Involving Carbon Offsets, According to New Research

  

     Carbon offsets have long been criticized as vulnerable to manipulation, errors, and questionable emissions reduction accounting. The offsets are very often associated with and generated by nature-based climate solutions (NbCS). According to American University’s factsheet, NbCSs:

“…involve conserving, restoring, or better managing ecosystems to remove carbon dioxide (CO2) from the atmosphere. Examples include allowing forests to regrow, restoring coastal wetlands, and switching to restorative agricultural practices, such as cover crop rotation, that support healthy soils. These ecosystems reduce climate change by capturing CO2 from the air and sequestering it in plants, soils, and sediments. They also provide a wide range of other important benefits, such as cleaner air and water, economic benefits, and increased biodiversity.”

     They can be classified into those that prevent or avoid emissions and those that draw down or remove emissions. For example, preventing deforestation prevents emissions, and reforestation draws down emissions. Along with nature-based solutions, there are engineered solutions such as CCS. 

     There are also co-benefits and concerns about NbCSs that must be considered and accounted for, summarized below from American University's factsheet.

     A 2017 PNAS study concluded that NbCSs could mitigate up to 20% of global emissions for a 2 °C by 2050 climate target. That would require quite a lot of projects, most of them difficult to quantify. Those projects would also require accurate measurement, verification, and reporting (MVR). Each should be evaluated according to various offset protocols. This raises the cost of projects, but it is necessary to show some level of proof that the projects are working as intended. An issue for land-based solutions, such as soil sequestration, is how long the carbon is retained in the soil. This depends on many factors, notably the future land uses and what happens to the land. Thus, I would say the estimate from the PNAS paper is overly optimistic by a large margin. The chart below, from the PNAS paper, shows the mitigation potential of different NbCSs. Below that is a chart showing and comparing emissions avoidance vs. emissions drawdown for forests, grasses, and wetlands. 

     Of course, the most cost-effective solutions will be pursued the most, so comparing costs is important. A 2024 paper in Nature Climate Change explored the underlying science of NbCSs. The paper explored and compared 43 NbCS pathways, noting differences in certainty, as noted in the abstract below. The graph below shows the scale of impact vs. level of uncertainty for each pathway. This is followed by a table showing the number of carbon credits issued for each category of NbCS.

 

Table 1 Credit issuance by NbCS category

The Four Requirements for Effective Nature-Based Climate Solutions

     New research led by the University of Utah's Wilkes Center for Climate Science & Policy analyzes different strategies for improving NbCSs. According to Phys.org, the study:

“…identifies four components where nature-based climate actions have not lived up to their billing and proposes reforms to improve their performance and scalability.”

     Since trees and forests offer the most effective NbCS, even if they can be hard to quantify at times, that is the focus of the paper. One of the paper’s authors noted the widespread problems with carbon accounting in evaluations of offsets. The example given is albedo. While it can reduce and even negate emissions benefits in some cases, there is no accounting for it in carbon offset evaluation. The study came up with four critical factors for successful NbCSs, shown below.

     The study also came up with a slightly different approach, emphasizing contributions to well-verified and well-quantified solutions as opposed to choosing less-verifiable, less-quantifiable solutions. These can be legally argued better, as well as leaving fewer doubts.

     Factor 1- ensuring a cooling effect, is given the albedo example again. If one plants conifers in a snow-covered area, the change in albedo from the reflecting snow to the dark-colored trees that absorb heat in the day might cancel out the emissions benefits. Factor 2 is simply ensuring the climate benefits of an action relative to not doing the action. For example, if a forest is being preserved that was not likely to be cut down, there is no real change, and any credits issued would not have real benefits. Factor 3 involves “leakage” of the carbon back into the atmosphere, either through land-use changes or simply moving the land disturbance from one place to another. Factor 4 is the durability of the solutions. The preference is that the carbon will remain sequestered for at least a century. Unfortunately, natural disasters such as wildfires, droughts, pests, diseases, and anything that kills trees can also negate an NbCS, so the likelihood of these high-risk disturbance events also needs to be considered. Thus, any NbCS should be able to prove that it deals with these four requirements for effectiveness. According to Phys.org:

"You have to know how big the risks are, and you have to account for those risks in the policies and programs," Anderegg said. "Otherwise, basically you're going to lose a lot of that carbon storage as climate change accelerates the risks."

“The methods now in place, known as "buffer pools," to account for these risks are not robust or rigorous currently, according to research by Anderegg's lab, which expects to release a study soon highlighting potential fixes.”

     An article about the research in Anthropocene Magazine notes:

“Currently, nature-based climate solutions and forest carbon markets are struggling to deliver effective climate mitigation,” says study team member William Anderegg, a forest ecologist at the University of Utah. “Our study provides a roadmap to improve these programs in four critical areas and also proposes a novel funding mechanism that could support projects without carbon offsets.”

“The study focuses on forests because of their ability to capture such large volumes of carbon. But forests don’t just store carbon; they can also change patterns of cloud cover, release volatile organic compounds and aerosols, and alter the color of the landscape. All of these changes can have either a warming or a cooling effect. So the first requirement for an effective project is to make sure that it results in net cooling, the researchers say.”

     The researchers' proposed contribution approach vs. an offset approach is simply a suggestion for companies to focus on the most accepted forms of mitigation, essentially putting a carbon tax on themselves to reduce emissions. Voluntary emissions reduction is important in that it avoids the pressure and some of the regulatory requirements of compliance-based emissions reduction. The paper abstract is below.

    

 

References:

 

Carbon 'offsets' aren't working: Researchers offer a 'roadmap' to improve nature-based climate solutions. Science X staff. Phys.org. July 30 2025. Carbon 'offsets' aren't working: Researchers offer a 'roadmap' to improve nature-based climate solutions

What are Nature-Based Solutions? American University. Factsheet. 2025. Fact Sheet: Nature-Based Solutions to Climate Change | American University, Washington, DC

Towards more effective nature-based climate solutions in global forests. William R. L. Anderegg, Libby Blanchard, Christa Anderson, Grayson Badgley, Danny Cullenward, Peng Gao, Michael L. Goulden, Barbara Haya, Jennifer A. Holm, Matthew D. Hurteau, Marysa Lague, Meng Liu, Kimberly A. Novick, James Randerson, Anna T. Trugman, Jonathan A. Wang, Christopher A. Williams, Chao Wu & Linqing Yang. Nature volume 643, pages1214–1222 (July 30, 2025). Towards more effective nature-based climate solutions in global forests | Nature

Expert review of the science underlying nature-based climate solutions. B. Buma, D. R. Gordon, K. M. Kleisner, A. Bartuska, A. Bidlack, R. DeFries, P. Ellis, P. Friedlingstein, S. Metzger, G. Morgan, K. Novick, J. N. Sanchirico, J. R. Collins, A. J. Eagle, R. Fujita, E. Holst, J. M. Lavallee, R. N. Lubowski, C. Melikov, L. A. Moore, E. E. Oldfield, J. Paltseva, A. M. Raffeld, N. A. Randazzo, …S. P. Hamburg Show authors. Nature Climate Change volume 14, pages402–406 (March 21, 2024). Expert review of the science underlying nature-based climate solutions | Nature Climate Change

Most forest carbon offset schemes fail. Here’s a four-step road map to fix them. Sarah DeWeerdt. Anthropocene Magazine. August 5, 2025. Most forest carbon offset schemes fail. Here’s a four-step road map to fix them.

Natural climate solutions. Bronson W. Griscom, Justin Adams, Peter W. Ellis, Joseph Fargione. et.al. October 16, 2017 PNAS. Vol. 114 | No.44) 11645-11650. October 16, 2017. Natural climate solutions | PNAS