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Summary This paper incorporates the findings of our previous publication (Morales and Lee 2022) and identifies, isolates, and quantifies elements in the annually disclosed proved reserves revisions that should not be considered technical or economic revisions. This has resulted in significantly different technical and economic revisions compared to those simplistically and directly derived using a common interpretation of the Financial Accounting Standards Board (FASB) Topic 932-235-50-5 (a) definition. We have assessed the reliability and comparability of the updated technical revisions when used to judge the reasonable certainty of the underlying proved reserves. We have carried out the analysis separating the proved reserves into developed and undeveloped. To derive a realistic data set to generate the updated technical and economic revisions, we reviewed more than 1,000 annual reports (10K and 20F Forms) and more than 600 comment letters from 141 companies filing annual reports to the Securities and Exchange Commission (SEC) during the period 2010–2020, extracting the information related to annual reserves changes and explicitly focusing on the disclosed revisions of previous estimates (RPE). We present evidence showing that the approach followed is robust and more reliable than the simple approach where technical revisions are estimated by simply subtracting the disclosed revisions due to price effects from the disclosed revisions in annual reports. The root causes for the significant differences between the simplistic approach and the one presented in this paper are mainly due to (1) including annual reserves changes due to nontechnical or economic factors as technical revisions, (2) using different interpretations of SEC and FASB regulations, and (3) not providing critical disaggregation information needed to estimate technical, economic, or other types of revisions correctly. Without proper consideration of these issues, the derived technical and economic revisions from disclosed data can be significantly distorted, affecting any conclusions derived. The annual average changes in technical revisions during a representative period, if correctly estimated, can provide an indication of both overstated and understated certainty of proved reserves estimates, which can impact a company’s relative valuation, asset impairment, internal depreciation, profit/loss, standardized measure, unit development costs, and other indicators based on proved reserves, making the reliability of the technical revisions and their actual upward or downward movements of paramount importance. We also highlight the significant different root causes driving the major differences between developed and undeveloped reserves in their annual technical revisions. The results indicate that for some companies that provide most of the information required for proper analysis, the certainty level of their disclosed developed and undeveloped proved reserves points toward an apparent overestimation of historically disclosed proved reserves. Our analysis shows the dubious quality and lack of reliability and comparability of the disclosed proved reserves revisions and highlights the limited value of existing guidance and current practices. We provide evidence that calls for FASB and SEC to provide complementary guidance in critical areas that currently limit the value, reliability, and comparability of the proved reserves revisions disclosed.
- Research Report > New Finding (0.46)
- Research Report > Experimental Study (0.46)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Reserves classification (1.00)
- Management > Asset and Portfolio Management > Reserves replacement, booking and auditing (1.00)
Abstract This paper presents a quantitative approach, using disclosed annual revisions of proved reserves, to judge the reasonable certainty of the underlying proved reserves. We identified issues that affect proper categorization of annual reserves changes in a previous SPE publication (SPE 209695) and incorporated them in this paper to quantify the technical revisions of disclosed proved reserves (and their reasonable certainty) during the period 2010 to 2020. Both over- and under-stated certainty of reserves estimates can impact a company's relative valuation, asset impairment, internal depreciation, profit/loss, standardized measure, unit development costs, and other indicators based on proved reserves. We analyzed 141 companies and extracted annual proved reserves changes disclosed from 2010 to 2020 in their SEC 10-K and 20-F forms or from comment letters for total, developed, and undeveloped reserves (in barrels of oil equivalent). As described in SPE 209695, we excluded, when available, (1) the impact due to changes in commodity prices and (2) other factors that distort the estimated technical revisions. We present, with examples based on actual data, the importance of separately analyzing developed and undeveloped proved reserves and the key drivers of the significant differences in average annual revisions between them. If these drivers are not carefully considered, results will lead to incorrect conclusions. Of the 141 companies analyzed, only 70 provided disclosures for five or more consecutive years of revisions for their total and undeveloped reserves during the 2010 to 2020 period. Of these, only 31 (or 22% of the 141) also disclosed revisions due to price changes in their total and undeveloped reserves. Other non-technical revisions are also required to estimate the technical revisions and judge the reasonable certainty of the disclosed developed and undeveloped reserves. However, the number of companies providing sufficient information to estimate technical revisions decreased to only 27 (or 19% of the 141) when we also considered the issues raised in our previous publication. Results indicate that, for many companies that provide the information required for proper analysis, the certainty level of their disclosed developed and undeveloped proved reserves can be significantly different, and appears to be much lower than the reasonable certainty, or high degree of confidence, required for proved developed and undeveloped reserves quantities, pointing towards an apparent over-estimation of historically disclosed proved reserves for many companies. We also highlight the issues that may still affect the estimated technical revisions, which may limit the validity of any conclusions drawn using the disclosed information. Our analysis shows the dubious quality and lack of reliability and consistency of some proved reserves revisions disclosed and highlights the limited value of current practices in disclosures of revisions in annual proved reserves. We provide evidence that call for FASB and/or SEC to provide complementary guidance in critical areas that currently limit the value and reliability of revisions to proved reserves disclosed.
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Reserves classification (1.00)
- Management > Asset and Portfolio Management > Reserves replacement, booking and auditing (1.00)
Abstract If properly estimated, technical revisions to disclosed proved reserves can be used to establish the reasonable certainty of both proved developed and undeveloped reserves. The trends in these technical revisions are important because they should result in overall positive revisions in EUR within a representative time period. If this criterion is not met, then the proved status of the reserves disclosed becomes questionable with the implications that this may have in depreciation, profit and loss, impairment tests and other reserves indicators where proved reserves are used. Unfortunately, in our review of the annual proved reserves revisions of developed and undeveloped proved reserves disclosed by companies to the SEC, we identified different interpretations and inconsistencies in the annual changes of proved reserves. We used data from annual reports issued between 2010 and 2020 by 141 companies, complemented by hundreds of comment letters issued by the SEC during this period, and found that companies did not apply the regulations and standards consistently, highlighting the limited effect the SEC comment letters have had in improving clarity and understanding in this important area of reserves estimation and categorization. We identified several issues which, if not carefully considered, may lead to incorrect interpretations and conclusions regarding the reliability and comparability of the disclosed proved reserves annual changes and their embedded level of certainty. The paper highlights different interpretations of key definitions and the different approaches and practices that seem to exist in companies when evaluators estimate, categorize, and disclose annual proved reserves changes due to revisions, improved recovery and extensions and discoveries, with special focus on isolating the technical revisions. We also show that the approach that some companies use to estimate the impact of changes due to changes in economic factors in the disclosed proved reserves leads to incorrect estimates and distorts the overall results or comparisons between companies. The evidence shown in the paper calls for improved and systematic official guidance if the proved reserves disclosures are to be used in a practical and useful manner. In the absence of such official guidance, this paper provides a simple project-based framework that may be used to properly analyze and extract value from the disclosed annual changes of proved reserves to improve the alignment, consistency, and proper interpretation of the disclosed proved reserves information and ensure that annual reserves changes do not end up being useless, impractical, or unreliable.
- North America > Canada > Alberta (0.28)
- North America > United States > Texas (0.28)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Louisiana > Delhi Field (0.99)
- North America > United States > Kentucky > Illinois Basin (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Reserves Evaluation > Reserves classification (1.00)
- Management > Asset and Portfolio Management > Reserves replacement, booking and auditing (1.00)
An Integrated Workflow for Reserves Evaluation in the U.S. Permian Basin Based on SPEE Monograph 3
Xia, Xiaoyang (Ryder Scott Company, United States) | Nelson, Eric (Ryder Scott Company, United States) | Olds, Dan (Ryder Scott Company, United States) | Connor, Larry (Ryder Scott Company, United States) | Zhang, He (Ryder Scott Company, United States)
Abstract In 2011, the Society of Petroleum Evaluation Engineers (SPEE) published Monograph 3 as an industry guideline for reserves evaluation of unconventionals, especially for probabilistic approaches. This paper illustrates the workflow recommended by Monograph 3. The authors also point out some dilemmas one may encounter when applying the guidelines. Finally, the authors suggest remedies to mitigate limitations and improve the utility of the approach. This case study includes about 300 producing shale wells in the Permian Basin. Referring to Monograph 3, analogous wells were identified based on location, geology, drilling-and-completion (D&C) technology; Technically Recoverable Resources (TRRs) of these analogous wells were then evaluated by Decline Curve Analysis (DCA). Next, five type-wells were developed with different statistical characteristics. Lastly, a number of drilling opportunities were identified and, consequently, a Monte Carlo simulation was conducted to develop a statistical distribution for undeveloped locations in each type-well area. The authors demonstrated the use of probit plots and demonstrated the binning strategy, which could best represent the study area. The authors tuned the binning strategy based on multiple yardsticks, including median values of normalized TRRs per lateral length, slopes of the distribution lines in lognormal plots, ratios of P10 over P90, and well counts in each type-well category in addition to other variables. The binning trials were based on different geographic areas, producing reservoirs, and operators, and included the relatively new concept of a "learning curve" introduced by the Society of Petroleum Engineers (SPE) 2018 Petroleum Resources Management System (PRMS). To the best of the authors’ knowledge, this paper represents the first published case study to factor in the "learning curves" method. This paper automated the illustrated workflow through coded database queries or manipulation, which resulted in high efficiencies for multiple trials on binning strategy. The demonstrated case study illustrates valid decision-making processes based on data analytics. The case study further identifies methods to eliminate bias, and present independent objective reserves evaluations. Most of the challenges and situations herein are not fully addressed in Monograph 3 and are not documented in the regulations of the U.S. Security and Exchange Commission (SEC) or in the PRMS guidelines. While there may be differing approaches, and some analysts may prefer alternate methods, the authors believe that the items presented herein will benefit many who are starting to incorporate Monograph 3 in their work process. The authors hope that this paper will encourage additional discussion in our industry.
- Research Report > New Finding (0.48)
- Overview > Innovation (0.34)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Reserves classification (1.00)
- (4 more...)
Incremental Method vs Split Conditions: Discussing the Similarities Between Reserves Evaluation and a Madoff Scheme
Salacz, Dominique (Abu Dhabi national Oil Company) | Allam, Farid (Abu Dhabi national Oil Company) | Szilagyi, Imre (Eötvös Loránd University) | Mansoori, Yousof Al (Abu Dhabi national Oil Company)
Abstract After the oil price crashes in 2014 & 2020 several M&A deals ended up in legal debates because operators cancelled major projects or infills wells that were booked in the "probable" reserves only. This document challenges the compatibility between the deterministic incremental reserve assessment method (PRMS2018, chapter 4.2.1.3), and the concept of split condition (PRMS2018 chapter 2.2.0.3), which is not allowed for reserves booking under PRMS. With a few examples, we explain why the incremental method may be misleading investors, if used wrongly. Policies, stock market requirements, or simply the understanding of reserves guidelines may differ from one company to another. Many filers and auditors are still keen on using the deterministic incremental approach. This method consists in "defining discrete parts or segments of the accumulation that reflect high, best, and low confidence regarding the estimates of recoverable quantities under the defined development plan". In principle, this should give similar result to the widely accepted scenario method (PRMS2018, chapter 4.2.1.3) but in reality, major discrepancies are observed. Some reserve evaluation may also become misleading for banks, investors, or even for good asset management. I many cases, the estimation of recoverable volumes is reasonable, but it does not match the company CAPEX requirements, affecting corporate cash flow as well as potential Reserves Based Lending (RBL) requirements. In another case, the 1P case will be robust, but the 2P may be grossly overestimated, affecting M&A or share price. "Reserves guidelines are principle based" this has recently become a very fashionable statement in the context of SEC bookings. Similar discussions will also occur when reviewing PRMS reports. However, different interpretations for keywords such as "Project", "Spit condition", or "FID" should not prevent the evaluator to provide a reliable reserves estimation to investor or company management. This document questions the threshold where ethics disappears, and a Madoff scheme may become legal.
- North America > United States (0.46)
- Asia > Middle East > UAE (0.28)
- Law (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Banking & Finance > Trading (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- Reservoir Description and Dynamics > Reserves Evaluation > Reserves classification (1.00)
- Management > Asset and Portfolio Management > Reserves replacement, booking and auditing (1.00)
Estimating Fair Market Value of Petroleum Assets in Nigeria: A Risk-Based Approach
Ojukwu, Kelechi (Petrosmart Limited) | Iledare, Omowumi (UCC Institute for Oil & Gas Studies, Cape Coast, Ghana) | Ajienka, Joseph (Emerald Energy Institute, University of Port Harcourt) | Dosunmu, Adewale (Emerald Energy Institute, University of Port Harcourt) | Ibe, Chidi (Emerald Energy Institute, University of Port Harcourt)
Abstract Many independent Nigerian oil & gas companies have emerged over the last decade out ofthe divestments of ageing petroleum assets by multinational oil companies. Thesetransactions are marked by pervasive cases of overvaluation and huge gap in offers that leadto unnecessarily high acquisition costs. Petroleum analysts around the world adopt the Discounted Cashflow Analysis method forestimating present value of future oil production revenues. Unfortunately, project economicsusing conventional analysis does not de-risk the reserves components appropriately oraccount for the excess and political risk premiums. Even when analysts derive the NetPresent Value from conventional evaluation, say at discount rates of say 10% or 15%, theyface the dilemma of extracting offer price from that figure. Some post a conservative offerbased on 50% NPV, while others throw in all the NPV in a scheme to win the bid at all cost. Some also start by guesstimating value by rule of thumb and then offer the NPV that is leftbehind. The decision to offer a given percentage of the NPV is entirely subjective and variesamongst investors and as such does not depict a logical perception of market value, or therisks thereof. Furthermore, by omitting political risk, buyers are invariably ignoring the mostcrucial risk of all. The adoption of different bases of reserves tend to compound the problemby yielding NPVs that are few and far between each other. They are usually based on un-risked ‘proved plus probable’ (2P) reserves, which is highly speculative and unrealistic forvaluation. For the first time, the concerns of high purchase price and offer gaps were debuggedleveraging the new Risk-Based Valuation approach which is based on a modified Discounted Cashflow model. A research deeply investigates the problems first by reconstructing originaltransaction to identify the root causes. Furthermore, the study concludes that buyers arepaying on average 4 times the value and that regulating reserves base is fundamental inorder to minimize offer gaps that sometimes tend to a billion dollars for large deals. Thus, the Risk-Based Discounted Cashflow Analysis technique can help prevent overpricing orunderpricing of Nigerian assets, minimize offer gaps in the market as well as account for theimpact of political risks (or its mitigation) in valuation.
- Africa > Nigeria (1.00)
- North America > United States > Texas (0.28)
- Research Report > Experimental Study (0.48)
- Research Report > New Finding (0.46)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Drilling (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Reserves classification (1.00)
- Production and Well Operations (1.00)
- (3 more...)
Abstract Two recent papers (URTeC 3003052 and SPE 200626) have presented detailed investigations of reasons why proved reserves estimates based on PRMS principles and on SEC regulations differ by substantial amounts in several instances. This paper synthesizes and extends this previous work and addresses implications of differences and reasons for differences. We examined the relatively limited number of cases in which reserves filers have reported reserves as of a given date based on both PRMS definitions and SEC regulations. To understand the differences, we also reviewed numerous annual reports and comment letter exchanges between reserves filers and the SEC staff during the period 2009 to 2019. We devoted attention to identify differences that might arise from different interpretations of reserves definitions adopted by the two different systems. Since COGEH is quite like PRMS regarding the use of forecast prices and costs, we extended our analysis to include comparisons with COGEH proved reserves when addressing prices and costs as root causes for the differences. While we examined many potential reasons why proved reserves using SEC and PRMS definitions and principles are different, we found three that appeared to be dominant. The first is that the SEC requires use of current prices in reserves estimates whereas PRMS (and COGEH) allow use of forecasted prices (often escalated) for sales volumes. The second is that PRMS requires firm evidence that a recovery project for resources has been fully approved and funded to reach classification as reserves with the status of "Approved for Development," but also allows recovery projects which are reasonably expected to receive approval to be classified as reserves with the status of "Justified for Development." Examination of comment letter exchanges indicates that the SEC also requires "reasonable certainty" that a "Final Investment Decision" will be reached to classify resources as reserves, essentially the same as the PRMS requirement for "Justified for Development" status. Comment letter exchanges indicate that this is the SEC staff's customary practice even though a literal reading of SEC guidance might suggest a stricter standard. The implication is that some reserves filers may unknowingly limit their reserves bookings, which might not be in the filers' or other stakeholders' best interests. The third reason is the five-year SEC development limitation (unless specific circumstances justify a longer time). Interpretation of reserves disclosure requirements in principles-based regulations based on how they are enforced in practice may serve investors and owners of resources better than assumptions based on literal readings of these regulations.
- Law > Business Law (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Banking & Finance > Trading (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Reserves classification (1.00)
- Management > Asset and Portfolio Management > Reserves replacement, booking and auditing (1.00)
Summary In this paper, we present methodology to quantify biases in reserves estimates using technical revisions (TRs) listed in reserves‐reconciliation reports filed with regulators in the US and Canada. Using this methodology, we assessed the reliability of reserves estimates for 34 companies filing in Canada and 32 companies filing in the US from 2007 to 2017. Filers in both Canada and the US overestimated proved (1P) reserves, and US filers overestimated 1P reserves (51% positive TRs instead of 90%) more often than Canadian filers (72% positive TRs). Canadian filers underestimated proved‐plus‐probable (2P) reserves slightly (54% positive TRs instead of 50%). Considering the entire reserves distribution, Canadian filers were moderately overconfident (underestimated uncertainty) and slightly pessimistic. US filers, who report only 1P, were somewhere between the combination of extreme overconfidence and neutral directional bias (DB) and the combination of moderate overconfidence and extreme optimism. Three groups of professionals can benefit from this study: estimators, who can use the methodology to track their TRs over time, calibrate them, and use this information to improve future estimation procedures; investors, who can analyze reported reserves estimates to compare volumes fairly; and regulators, to whom the paper provides quantitative methodology to suggest to filers to help them ensure compliance with appropriate criteria for 1P and 2P reserves and avoid significant reserves write‐downs later.
- North America > Canada (1.00)
- North America > United States > Texas (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (26 more...)
- Reservoir Description and Dynamics > Reserves Evaluation > Reserves classification (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Management > Asset and Portfolio Management > Reserves replacement, booking and auditing (1.00)
Abstract In recent years, internationally recognized reserves estimation and reporting standards have been adopted in Latin America by government regulators and national operators. This paper describes the current regional situation from the perspective of a third-party auditor. Potential investors need a clear understanding of how a country and its oil and gas sector companies evaluate their petroleum resources to optimize asset portfolio management and value. To this end, the current reserves estimation and reporting practices of several major Latin American oil and gas producers were investigated to identify the level of standardization by country. This review includes the application of the main resource classification standards used by the government regulators in the region and how they have influenced the estimation of reserves in recent years. The role of the third-party reserve auditor is discussed, including the importance of intangible influences which must be taken into consideration. The process of reserve estimation is complex and involves multiple skills, knowledge and judgement while applying a variety of international reserves standards to provide a reliable independent audit for operators or regulators alike. Documented examples of inadequate reserves audit are presented. The SPE PRMS is the reserve reporting standard used by most of the regulators and operators, but those companies that are listed on the USA or Canadian stock exchanges use SEC and COGEH, respectively. Annual independent reserves estimation from third-party auditors is mandatory for most of the Latin American countries reviewed, although some continue to use in-house reserves estimations. Examples are given to illustrate how some government regulators use their own internal guidelines with additional considerations for reserves estimation and reporting. The paper shows that those countries where reserves estimation and reporting have been standardized, and which are audited by third-parties, have given more confidence to the global investment community. Standardization has been fundamental in helping to attract development funding for the oil and gas sector in Latin America, as it brings clarity to decision making based on reliable estimates of recoverable petroleum volumes. This paper provides a review of information regarding the status of standardization of reserve estimation and reporting in Latin America. Best practices are shared, and some necessary areas of improvement are proposed. Getting it right can result in improved transparency and increased international investment.
- South America (1.00)
- North America > United States (1.00)
- North America > Central America (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Stabroek Block > Liza Field > Liza Deep Field (0.99)
- South America > Peru (0.91)
- South America > Ecuador (0.91)
- (10 more...)
- Reservoir Description and Dynamics > Reserves Evaluation > Reserves classification (1.00)
- Management > Asset and Portfolio Management > Reserves replacement, booking and auditing (1.00)
Abstract The story of the US shale revolution is well known. Hydraulic fracturing techniques were executed by Mitchell Energy in vertical Barnett Play gas wells in the early 2000's, vertical wells matured into horizontal multi-stage frac wells, and one of the largest land leasing campaigns in history exploded as operators chased high gas prices. As the natural gas market became saturated, the industry started to strip the natural gas liquids (NGLs) out of the gas stream to take advantage of the ever-rising oil pricing. When gas prices tumbled in 2011, and oil prices climbed north of $100/bbl, the industry looked to the liquid rich/oil plays, such as the Williston Basin, the DJ Basin, and the Permian Basin. The turning point came in November 2014 when oil prices fell rapidly. As prices bottomed out at $22/bbl in February 2015, the industry saw a large exodus of operators and capital from the gas rich plays around the US to the liquid rich Permian. The Permian proved to be the haven for oil and gas development with its multiple pay zone targets, high EURs, low break-even costs, friendly regulatory environment, and access to markets. The rush for land, once again ensued, with the hope of an oil price rebound and promise of high returns to capital investors. The rapid ramp up in activity from 2015–2018 did not come without challenges as it put strain on the availability of services and people, access to pipelines and markets, and access to frac sand/water. This drove up costs and resulted in mixed results for many companies. In addition, operators soon saw that with higher-than-expected gas and water production, expenses to manage these by-products sky-rocketed. Water handling and disposal became a huge portion of operating expenses and with gas export facilities at full capacity, companies started to flare gas in large volumes. Associated gas became a waste product, causing operators needed remove the gas and associated liquids from the revenue stream, and in some cases pay a high cost for flaring permits, rather than shutting in wells. By 2019, a shift in the investment community was well underway. The days of growth-focused investment were coming to an end, and investors wanted to see returns on their investments. As prices still hovered around the $55/bbl range, investors were getting anxious to recover their capital invested in the industry, and throughout 2019 operators all talked about the ability to generate free cash flow. This paper analyses the free cash flow for three key unconventional basins across the US and discusses the associated economic impacts in each basin.
- North America > United States > Texas (1.00)
- North America > United States > North Dakota (1.00)
- North America > United States > New Mexico (1.00)
- (2 more...)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.40)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.36)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.97)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin (0.99)
- (42 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Reserves classification (1.00)
- (3 more...)