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.

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.

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.

Abstract In a previous paper (Morales and Lee 2018), the authors described reasons why differences continue to exist between proved reserves disclosed by entities using SEC regulations and in documents in which they disclose proved reserves following PRMS standards. At that time, we deferred discussion of project maturity as one of the potential root causes for such differences. Different interpretations of the SEC guidance requiring a "final investment decision (FID)" have been identified as a potential root cause that may result in an unconscious under estimation of disclosed SEC proved undeveloped (PUD) reserves. This paper completes the discussion of the differences between PRMS and SEC proved reserves and focuses on the available evidence that explains what the SEC actually requires to support a claim that an "FID" has been reached, and its alignment with PRMS guidance. We examined exchanges of comment letters between the SEC and 110 Oil and Gas companies that disclosed PUD reserves in filings from end 2009 to end 2018, where the keywords "Final Investment Decision," "FID," "Adopted Development Plan," or "Development Plan" were mentioned in the exchanges. The objective was to determine the criteria that filers used to satisfy the requirements for an "FID" and how the SEC treated these arguments. The SEC presented its requirement for an "FID" in its 26 October 2009 "Compliance and Disclosure Interpretations [C&DI]" guidance. The PRMS 2018 update, and the 2008 modernization of the SEC regulations (the latter based to a large extent on the PRMS), were also used in this analysis, with a focus on their reserves definitions and on the PRMS requirements for the PUD reserves sub-classes "Justified for Development" and "Approved for Development," and their link to SEC PUD reserves. The analysis showed that companies replying with an explanation of their processes to disclose SEC PUD reserves typically described the requirements for an "FID" to be satisfied by the projects with PUD reserves being part of a five year business or "Development Plan", annually reviewed, challenged and updated by the company's relevant departments, including the reserves governance organization and reserves committees, and approved by relevant senior management and the Board of Directors, if applicable, resulting in what is usually called the "Adopted Development Plan." When the other SEC criteria for PUD reserves are also satisfied (e.g., "reasonable certainty" of the projects' PUD reserves converted to developed reserves within five years from first disclosure, etc.), this Adopted Development Plan becomes the basis for the disclosed PUD reserves in 20-Fs, 10-Ks or other documents (e.g., Forms S-1, S-4). We established that the SEC did not object to this approach; this means that the SEC takes a conscious and liberal, rather than a literal, view of the requirements for an "FID", consistent with its general approach to enforcing its regulations on a principles-, rather than prescriptive-, basis. However, we also found that some companies still seem to require, as an internal control procedure, satisfaction of the literal definition of "FID" as a prerequisite for disclosure of resource volumes as SEC PUD reserves. The extent to which this criterion is applied has not been fully disclosed. We conclude that this approach is sufficient, but not necessary, to classify a project as having PUD reserves and comply with SEC regulations and that a literal interpretation of "FID" can also account for some of the differences in PUD reserves estimated using the PRMS and SEC systems. This paper, coupled with its predecessor (Morales and Lee, 2018), provides to the industry a logical and needed explanation of why SEC and PRMS proved reserves sometimes differ despite the belief by many in the industry that, after the introduction of PRMS in 2007, its update in 2018, and the modernization of the SEC reserves regulations in 2008, the PRMS and SEC proved reserves would be essentially the same. The implications that these differences in interpretations may have in reflecting the company's true value and growth potential (from the undeveloped projects portfolio) are not addressed in this paper.

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.

Summary Many shales previously thought of as only source rocks are now recognized as self-sourcing reservoirs that contain large volumes of natural gas and liquid hydrocarbons that can be produced by use of horizontal drilling and hydraulic fracturing. However, shale-gas resources and development economics are uncertain, and these uncertainties beg for a probabilistic solution. Our objective was to probabilistically determine the distribution of technically recoverable resources in highly uncertain and risky shale-gas reservoirs for seven world regions. To assess technically recoverable resources, we used the Unconventional Gas Resource Assessment System, which integrates Monte Carlo simulation with an analytical reservoir simulator, to derive a representative probability distribution of 25-year recovery factors (RFs) from five shale-gas plays in the US: the Barnett, Eagle Ford, Marcellus, Fayetteville, and Haynesville shales. The RFs for the five shale-gas plays follow a general beta-distribution with a mean value of 25%. Finally, we extended the distribution of RFs gained from the five shale-gas plays in the US to estimate technically recoverable shale-gas resources for the seven world regions. World technically recoverable shale-gas resources were estimated to range from 4,400 (P90) to 24,000 (P10) Tcf.1 This work provides important statistics for the five shale-gas plays in the US. Results of this work verify the existence of significant technically recoverable shale-gas resources and can help the industry better target its exploitation efforts in shale-gas plays worldwide.

Abstract Since the release of its modernized reserves reporting rules in late 2008 (NARA, 2009), the U.S. Securities & Exchange Commission (SEC) has issued little formal guidance on proper interpretation of the modernized rules. The SEC staff issued major guidance in October, 2009, and guidance on a single issue in May, 2013. To supplement the new rules, the Financial Accounting Standards Board has issued revised accounting guidelines (FASB ASC, 2010), which extends some reporting requirements. In addition, we have observed some consistent patterns and clarifications in comment letters which the SEC has made public for filings covering the 2009, 2010, 2011, and 2012 fiscal years. Finally, there have also been a limited number of public presentations by SEC staff (e.g., in November 2009, April 2010, April 2011, August 2013 and June 2014), where SEC staff has provided some clarification on certain positions. This paper summarizes the more important aspects of the SEC guidance and clarification provided to date, and includes a discussion of issues such as clarification of separate products whose reserves are required to be disclosed, situations in which exemptions to the "five-year rule" are either likely or not likely to be allowed, a refined definition of "project", requirements for third-party reports in conjunction with 10-K or 20-F filings with the commission, status of resources that meet all requirements for proved undeveloped reserves except that they cannot be developed within five years, undeveloped locations more than one offset from existing wells and speed of converting proved undeveloped reserves into developed reserves. An overview of other key issues raised by the SEC during the last four years is also provided. Potential differences between the SEC regulations and the SPE-PRMS (PRMS, 2007) are described.

Abstract Lease fuel (also called fuel gas, fuel consumed in operations or lease-used gas) is defined by the SPE/WPC/AAPG/SEG/SPEE-Petroleum Resource Management System (SPE-PRMS) as "that portion of produced natural gas, crude oil, or condensate consumed as fuel in production and lease plant operations." Reporting this "fuel" as reserves, usually with a clear reference to the reserves attributed to these volumes, has been a practice commonly used by many companies, but not by all. Differences exist within a country and between countries regarding the application and interpretation of the existing standards and regulations concerning the reporting of lease fuel as reserves, resulting in a lack of consistency and comparability between oil and gas companies in the reserves externally disclosed. Annual reports, 10-K and 20-F forms of oil and gas companies indicate that, during the last few years, significant volumes of additional reserves are still being added as a result of including, for the first time, the fuel Consumed in Operations (CiO) in the disclosed reserves. These volumes can be material. Based on the companies reviewed, these volumes can represent up to 12% of the company's total proved reserves, depending on the amount of produced hydrocarbon products consumed as fuel, the type of processes used (e.g., normal production of oil and gas, LNG processing, electricity generation, compression needs, etc.) and the location of the terminal point (SEC terminology) or reference point (SPE-PRMS terminology). A review of definitions, apparent misaligned standards (e.g., SPE-PRMS, Canadian Oil and Gas Evaluation Handbook (COGEH)) and requirements from regulatory bodies (Canadian Securities Administrators (CSA), US Securities and Exchange Commission (SEC), UK London Stock Exchange (LSE-AIM), European Securities and Market Authority (ESMA), Australian (ASX), Hong Kong (HKEx) and Singapore (SGX) Stock Exchanges) are discussed in this paper. Examples are also presented with the rationale of why these "lease fuel" volumes should be part of the reported reserves and should include proper narrative on these volumes. Updates of the lease fuel definition and references to lease fuel in the SPE-PRMS are also suggested in this paper, in order to reflect that, during the last few years, many countries and/or regulators have adopted the SPE-PRMS as the estimation and classification standard for reserves and resources, as well as the increasing amount of large integrated energy intensive projects (some of them presently in the undeveloped reserves category), and the increased relevance of unconventional resources and their role in lease fuel. Inconsistencies in the approach to report (or not) the "lease fuel" as reserves are addressed, highlighting the need for clarity in the standards and disclosures being applied to ensure proper transparency, consistent valuation and reporting within the industry in the area of lease fuel, allowing proper comparability.

Summary The SPE-Petroleum Resources Management System (2007) (SPE-PRMS) is a project-based system in which the project definition and its treatment play key roles in the estimation and categorization of reserves and resources and their range of uncertainty. This is key to capturing the potential downside and upside of the project and the commercial opportunities that may exist. Wrongly defining the project may result in an improper ring-fencing of the elements that one must consider in reserves and resource estimation and in improper risk assessment, with potential for missed opportunities or failure as an outcome. The SPE-PRMS is clear on the type of aggregation that one can use within a field, a property, or a project, with probabilistic addition allowed within each of these entities. However, despite this clarity, and on the basis of information provided in 10-Ks, 20-Fs, and annual reports, most companies in the oil-and-gas industry have not yet adapted their methods to reflect these best practices in external disclosures. The technical literature has devoted significant effort to address technical and commercial issues in probabilistic reserves and resource estimation of a field or incremental activity (e.g., drilling wells). However, very little effort has been devoted to the proper definition of a “project,” its attributes, ring-fencing, uncertainty-assessment approaches for the fields within the project, and in the categorization and aggregation of reserves or resources within the project. Furthermore, downside project economics should capture the true project's downside (or the true P90 of the project) rather than an overly pessimistic estimate of its proved reserves calculated with arithmetic additions within the project. To describe a simple approach to a project's reserves estimates, this paper uses an actual liquefied-natural-gas (LNG) project and its reserves estimates, estimated by different companies, with the arithmetic aggregation approach and the probabilistic aggregation approach. This example highlights different interpretations of the existing standards and regulations among joint venture (project) partners within the same project. This paper also highlights the overall impact that the two types of proved-reserves-aggregation methods (arithmetic and probabilistic) may have. In the specific example presented in this paper, the difference between the two methods can account for up to 15% of the project's proved reserves. One can also use the approach described in other types of projects (e.g., a project with satellite developments by use of common facilities) or resources estimates (e.g., projects in contingent resources), to properly capture the downside risk and realistic upside, uncertainty ranges, and project business opportunities, truly reflecting the project's reasonable certainty at the P90 level. Gas projects are preferred to illustrate this approach. For gas-commitment purposes, many buyers require the LNG project's proved (P90) reserves to be independently certified before contractual commitments can be finalized. Underestimation of the project's true proved reserves may result in loss of opportunities and/or in an overly pessimistic assessment of the proved reserves not reflecting reasonable certainty. Requirements from regulatory bodies [e.g., NARA (SEC) 2009; ESMA 2011] and their linkages to reserves aggregation within a project are also addressed in this paper. In the project analyzed, this underestimation is between 12 and 15% of the project's proved reserves, depending on the year of disclosure.

Summary A key element in determining a project's commercial maturity is the evidence of a firm intent to proceed with development within a reasonable time frame. The Petroleum Resource Management System (PRMS) (SPE 2007) recommends 5 years as a benchmark, although a longer time can be applied in some cases. The U.S. Securities and Exchange Commission (SEC) also provides specific guidance and requirements on undeveloped reserves and the 5-year-maturation time limit. Despite the apparent clarity in the PRMS and SEC regulations regarding project maturity, this paper describes actual examples in the public domain in which different levels of commercial maturity were introduced within a project for proved and probable reserves as a result of the 5-year time limit. This has resulted in projects with their proved reserves reclassified as probable reserves because they will not be developed within the 5-year time limit. This paper reviews SPE standards and SEC wording on commercial maturity requirements and the 5-year time limit, providing clarity on whether a project's recoverable volumes should be classified as reserves or contingent resources if its undeveloped reserves are not matured into developed reserves within 5 years of their first reporting, and specific circumstances for a longer maturation time frame do not exist. When referring to projects with proved undeveloped reserves falling outside the 5-year time limit, the SEC uses different wording throughout the Final Rule document issued in January 2009 (NARA 2009). This has resulted in apparently different interpretations of the requirements for projects to meet this criterion. On the basis of the wording used in SEC forms 10-K and 20-F, public disclosures seem to range from reporting only the projects with undeveloped reserves that have been continuously disclosed for 5 years or more in the annual filings, to reporting all projects that have been or will remain undeveloped for 5 years or more from the time of their first disclosure date. Given the wording in the SEC Final Rule, it is understandable that different interpretations of the regulations may emerge. This paper presents an analysis of the SEC language used in the Final Rule and related wording used in SEC comment letters from the last few years. Failing further clarity from the SEC, this analysis provides the authors' opinion on the clarity required to ensure consistency in the way the SEC 5-year rule should be interpreted and in the spirit of comparability among companies that provides the basis for the SEC requirement to report these undeveloped reserves as a separate item. Another area discussed in this paper relates to the wording used by the SEC regarding a project's undeveloped-reserves volumes (i.e., its undeveloped reserves in barrels of oil equivalent) and the potential different interpretations that the industry may give to the SEC Final Rule. A simple example is presented to provide clarity on the option that is most likely to meet the SEC requirements. Potential inconsistencies resulting from different interpretation are highlighted. The analysis and recommendations presented in this paper aim at creating consistent approaches leading to better comparability among oil and gas companies by use of an aligned interpretation of standards and requirements for reserves estimation, classification, categorization, and disclosure.