Attached files
EXHIBIT 99.2
[Letterhead of Netherland, Sewell & Associates, Inc.
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April 12, 2010
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Ms. Delores Hinkle
Marathon Oil Company
5555 San Felipe Road
Houston, Texas 77056
Dear Ms. Hinkle:
In accordance with your request, we have prepared this letter with respect to our report dated March 30, 2009. We prepared a reserves certification and deliverability analysis, as of December 31, 2008, of certain oil and gas properties located in Alba Field, offshore Equatorial Guinea, Africa. It is our understanding that the proved reserves estimated in the March 30 report constituted approximately 37.7 percent of all proved reserves owned by Marathon Oil Company, as of December 31, 2008. The estimates of reserves in the March 30 report were prepared in accordance with the definitions and guidelines set forth in the 2007 Petroleum Resources Management System (PRMS) approved by the Society of Petroleum Engineers.
For the purposes of the March 30 report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. The reserves in the March 30 report were estimated using deterministic methods; these estimates were prepared in accordance with generally accepted petroleum engineering and evaluation principles. We used standard engineering and geoscience methods, or a combination of methods, such as performance analysis, volumetric analysis, analogy, and reservoir modeling, that we considered to be appropriate and necessary to establish reserves quantities and reserves categorization that conform to PRMS definitions and guidelines. In evaluating the information at our disposal concerning the March 30 report, we have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting, rather than engineering and geoscience. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.
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Sincerely,
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NETHERLAND, SEWELL & ASSOCIATES, INC.
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/s/ G. Lance Binder
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G. Lance Binder, P.E.
Executive Vice President
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DFN:MZS
[Letterhead of Netherland, Sewell & Associates, Inc.]
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March 30, 2009
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Marathon E.G. Production Limited
5555 San Felipe Road
Houston, Texas 77056
Ladies and Gentlemen:
In accordance with your request, we have prepared a reserves certification and deliverability analysis of certain oil and gas properties located in Alba Field, offshore Equatorial Guinea. Pursuant to the terms of the Gas Purchase and Sales Agreement (GPSA) between the Alba Field Production Sharing Contract (PSC) contractors (referred to herein as the "Alba Field owners") and Atlantic Methanol Production Company (AMPCO), the primary purpose of this report is to verify that there are (1) sufficient proved (1P) reserves in Alba Field to cover delivery of gas from the Alba Field owners to AMPCO equal to 100 percent of the stated maximum daily quantities over the remaining term of the GPSA that ends May 3, 2026, and (2) sufficient proved developed reserves in Alba Field to deliver, for a period of five years, 102 percent of the maximum daily contract quantity. For the purposes of this report, the maximum daily contract quantity is 135,000 MMBTU per day, or 140 million cubic feet of gas per day (MMCFD). We have independently verified that the reserves presented in this report are economically viable to develop and produce throughout the lives of the properties. The estimates of reserves in this report have been prepared in accordance with the definitions and guidelines set forth in the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers; definitions are presented immediately following this letter.
During 2008, average production from Alba Field was 883 MMCFD, with associated condensate from 13 wells and approximately 129 MMCFD reinjected offshore. Primary condensate separation occurs offshore. The condensate and remaining gas streams are sent to onshore processing facilities at Punta Europa where the condensate is stabilized, liquefied petroleum gas (LPG) is extracted from the gas stream in the LPG plant, and remaining gas is sent to both the methanol and liquefied natural gas (LNG) plants with excess gas being reinjected offshore. Phase 3 of the Alba Field development plan was the LNG plant project, which was completed in 2006. During 2007, the LNG plant was commissioned, and Marathon E.G. Production Limited (Marathon) ramped up gas sales to the plant. During 2008, sales to the LNG plant averaged 565 MMCFD, and the average gas reinjection rate decreased to 129 MMCFD from an average of 400 MMCFD during 2007.
We estimate the gross (100 percent) reserves in Alba Field, as of December 31, 2008, to be:
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Gross (100 Percent) Reserves
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Condensate
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LPG
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Gas
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Category
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(MMBBL)
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(MMBBL)
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(BCF)
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Proved Developed
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117
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51
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2,046
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Total Proved (1P)
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181
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87
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3,455
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Condensate and LPG volumes are expressed in millions of barrels (MMBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in billions of cubic feet (BCF) at standard temperature and pressure bases. A list of abbreviations used in this report is presented following the definitions.
The estimates shown in this report are for proved developed producing, proved developed non-producing, and proved undeveloped reserves. As requested, probable and possible reserves that exist for these properties have not been included. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves included herein have not been adjusted for risk. In this report, we have attributed estimated gas sales volumes and LPG reserves to Alba Field, even though the LPG plant is separate from the field facilities. This classification is based on our interpretation of the agreement between the Alba Field owners and the LPG plant owners that states that title to the gas sales volumes and LPG liquids is transferred from the Alba Field owners at the tailgate of the LPG plant and that those volumes are valued on an MMBTU basis. It is our understanding that this interpretation is consistent with Marathon's internal reserves booking practice for Alba Field. As shown in the Table of Contents, the Technical Discussion consists of an Executive Summary and four major reports: Reserves Certification Report, Economic Viability Report, Resources Dedication Report, and Deliverability Report.
In order to satisfy the primary objective of this report, certain assumptions were made regarding future field production and injection rates. The most significant assumption pertains to the rate of Alba Field gas consumption by the LNG plant. Three LNG plant consumption scenarios have been used: a low-take case, a mid-take case, and a high-take case. As explained in the Technical Discussion, the LNG plant low-take case is 560 MMCFD, the mid-take case is 600 MMCFD, and the high-take case is 640 MMCFD.
We have determined that if the LNG plant receives gas as described in the low-take case until it is no longer economic to operate, there will be a shortfall of proved reserves to supply the AMPCO methanol plant in 2025 and 2026. If the LNG plant receives gas as described in the mid-take and high-take cases until it is no longer economic to operate, we estimate that there will be a shortfall of proved reserves to supply the AMPCO methanol plant in 2024, 2025, and 2026. Therefore, for all cases presented in this report we have limited the supply of gas to the LNG plant following the supply plateau period to ensure that supply obligations to the AMPCO plant can be met. We have also determined that there are sufficient proved developed reserves to satisfy the requirement to supply the AMPCO methanol plant with 102 percent of the maximum daily contract quantity for a period of five years.
For our study, we had access to certain data and analyses provided by Marathon that were initially presented to us in various reviews and meetings held from June through September 2003. We have received updated data on an annual basis for the purposes of performing an audit of Alba Field reserves on behalf of Noble Energy, Inc. In January 2009, Marathon presented an additional update of Alba Field, including development plans and a review of their latest analyses. Marathon is in the process of developing a revised geologic model for Alba Field. The information and data received to date include, but are not limited to, a geological and geophysical review of Marathon's current interpretation of the Alba Field area, limited structure and amplitude maps, formation test results and fluid gradient analysis, petrophysical methodology, fluid property analysis methodology, and potential future development plans. We were provided a digital backup of an OpenWorks project (a subset of the 3-D seismic survey), multiple interpreted seismic horizons, routine and special core analysis data, pressure data, fluid and laboratory analysis reports and subsequent fluid property analysis, LAS well files, capillary pressure data, and historical production data. A thorough explanation of Marathon's reservoir simulation studies was also provided, as were all necessary digital input decks and supporting engineering data and analyses.
Our study consisted of (1) a geophysical and geological review of the Alba Reservoir; (2) a review of structure and generation of gross isopach maps; (3) a petrophysical analysis of net hydrocarbon pay, porosity, and connate water saturation; (4) a review of pressure and temperature properties as well as fluid properties using existing fluid laboratory analysis and black oil correlations; (5) the generation of 1P estimates of wet gas-in-place, dry gas-in-place, condensate-in-place, and LPG-in-place; (6) a reservoir simulation to derive estimates of dry gas,
condensate, and LPG recoveries; (7) a review of contractual sales and deliverability obligations for Alba Field, the Alba LPG plant, the LNG plant, and the methanol plant; (8) the generation of production profiles for primary and secondary condensate, LPG, offshore and onshore fuel and flare gas, gas used by the LPG plant and the methanol plant, and remaining gas available for the LNG plant; and (9) a review of economic terms of the Alba PSC and LPG plant contracts.
For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and their related facilities. We have not investigated possible environmental liability related to the properties.
The reserves shown in this report are estimates only and should not be construed as exact quantities. The reserves may or may not be recovered, and, because of governmental policies and uncertainties of supply and demand, the actual production rates may vary from assumptions made while preparing this report. A substantial portion of these reserves are categorized as undeveloped because of an offshore compression project that lacks sufficient production history upon which performance-related estimates of reserves can be based. Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics; it may be necessary to revise these estimates as additional performance data become available. Also, estimates of reserves may increase or decrease as a result of future operations.
In evaluating the information at our disposal concerning this report, we have excluded from our consideration all matters as to which the controlling interpretation may be political, socioeconomic, legal, or accounting, rather than engineering and geologic. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geologic data; therefore, our conclusions necessarily represent only informed professional judgment.
The data used in our estimates were obtained from Marathon and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. Supporting geologic, field performance, and work data are on file in our office. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties and are not employed on a contingent basis.
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Sincerely,
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NETHERLAND, SEWELL & ASSOCIATES, INC.
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/s/ C.H. (Scott) Rees III, P.E.
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By: C.H. (Scott) Rees III, P.E.
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Chairman and Chief Executive Officer
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/s/ Derek F. Newton, P.E.
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/s/ Patrick L. Higgs, P.G.
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By: Derek F. Newton, P.E.
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By: Patrick L. Higgs, P.G.
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Vice President
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Vice President
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Date Signed: March 30, 2009
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Date Signed: March 30, 2009
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| Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document. |
DFN:JLR
This document contains information excerpted from definitions and guidelines prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE) and reviewed and jointly sponsored by the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG), and the Society of Petroleum Evaluation Engineers (SPEE).
Preamble
Petroleum resources are the estimated quantities of hydrocarbons naturally occurring on or within the Earth's crust. Resource assessments estimate total quantities in known and yet-to-be-discovered accumulations; resources evaluations are focused on those quantities that can potentially be recovered and marketed by commercial projects. A petroleum resources management system provides a consistent approach to estimating petroleum quantities, evaluating development projects, and presenting results within a comprehensive classification framework.
These definitions and guidelines are designed to provide a common reference for the international petroleum industry, including national reporting and regulatory disclosure agencies, and to support petroleum project and portfolio management requirements. They are intended to improve clarity in global communications regarding petroleum resources. It is expected that this document will be supplemented with industry education programs and application guides addressing their implementation in a wide spectrum of technical and/or commercial settings.
It is understood that these definitions and guidelines allow flexibility for users and agencies to tailor application for their particular needs; however, any modifications to the guidance contained herein should be clearly identified. The definitions and guidelines contained in this document must not be construed as modifying the interpretation or application of any existing regulatory reporting requirements.
1.0 Basic Principles and Definitions
The estimation of petroleum resource quantities involves the interpretation of volumes and values that have an inherent degree of uncertainty. These quantities are associated with development projects at various stages of design and implementation. Use of a consistent classification system enhances comparisons between projects, groups of projects, and total company portfolios according to forecast production profiles and recoveries. Such a system must consider both technical and commercial factors that impact the project's economic feasibility, its productive life, and its related cash flows.
1.1 Petroleum Resources Classification Framework
[Chart Graphic]
Petroleum is defined as a naturally occurring mixture consisting of hydrocarbons in the gaseous, liquid, or solid phase. Petroleum may also contain non-hydrocarbons, common examples of which are carbon dioxide, nitrogen, hydrogen sulfide and sulfur. In rare cases, non-hydrocarbon content could be greater than 50%.
The term "resources" as used herein is intended to encompass all quantities of petroleum naturally occurring on or within the Earth's crust, discovered and undiscovered (recoverable and unrecoverable), plus those quantities already produced. Further, it includes all types of petroleum whether currently considered "conventional" or "unconventional."
Figure 1-1 is a graphical representation of the SPE/WPC/ AAPG/SPEE resources classification system. The system defines the major recoverable resources classes: Production, Reserves, Contingent Resources, and Prospective Resources, as well as Unrecoverable petroleum.
The "Range of Uncertainty" reflects a range of estimated quantities potentially recoverable from an accumulation by a project, while the vertical axis represents the "Chance of Commerciality", that is, the chance that the project that will be developed and reach commercial producing status. The following definitions apply to the major subdivisions within the resources classification:
TOTAL PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production plus those estimated quantities in accumulations yet to be discovered (equivalent to "total resources").
DISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production.
PRODUCTION is the cumulative quantity of petroleum that has been recovered at a given date. While all recoverable resources are estimated and production is measured in terms of the sales product specifications, raw production (sales plus non-sales) quantities are also measured and required to support engineering analyses based on reservoir voidage (see Production Measurement, section 3.2).
Multiple development projects may be applied to each known accumulation, and each project will recover an estimated portion of the initially-in-place quantities. The projects shall be subdivided into Commercial and Sub-Commercial, with the estimated recoverable quantities being classified as Reserves and Contingent Resources respectively, as defined below.
RESERVES are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status.
CONTINGENT RESOURCES are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status.
UNDISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum estimated, as of a given date, to be contained within accumulations yet to be discovered.
PROSPECTIVE RESOURCES are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective Resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be sub-classified based on project maturity.
UNRECOVERABLE is that portion of Discovered or Undiscovered Petroleum Initially-in-Place quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.
Estimated Ultimate Recovery (EUR) is not a resources category, but a term that may be applied to any accumulation or group of accumulations (discovered or undiscovered) to define those quantities of petroleum estimated, as of a given date, to be potentially recoverable under defined technical and commercial conditions plus those quantities already produced (total of recoverable resources).
1.2 Project-Based Resources Evaluations
The resources evaluation process consists of identifying a recovery project, or projects, associated with a petroleum accumulation(s), estimating the quantities of Petroleum Initially-in-Place, estimating that portion of
those in-place quantities that can be recovered by each project, and classifying the project(s) based on its maturity status or chance of commerciality.
This concept of a project-based classification system is further clarified by examining the primary data sources contributing to an evaluation of net recoverable resources (see Figure 1-2) that may be described as follows:
[Chart Graphic]
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The Reservoir (accumulation): Key attributes include the types and quantities of Petroleum Initially-in-Place and the fluid and rock properties that affect petroleum recovery.
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The Project: Each project applied to a specific reservoir development generates a unique production and cash flow schedule. The time integration of these schedules taken to the project's technical, economic, or contractual limit defines the estimated recoverable resources and associated future net cash flow projections for each project. The ratio of EUR to Total Initially-in-Place quantities defines the ultimate recovery efficiency for the development project(s). A project may be defined at various levels and stages of maturity; it may include one or many wells and associated production and processing facilities. One project may develop many reservoirs, or many projects may be applied to one reservoir.
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The Property (lease or license area): Each property may have unique associated contractual rights and obligations including the fiscal terms. Such information allows definition of each participant's share of produced quantities (entitlement) and share of investments, expenses, and revenues for each recovery project and the reservoir to which it is applied. One property may encompass many reservoirs, or one reservoir may span several different properties. A property may contain both discovered and undiscovered accumulations.
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In context of this data relationship, "project" is the primary element considered in this resources classification, and net recoverable resources are the incremental quantities derived from each project. Project represents the link between the petroleum accumulation and the decision-making process. A project may, for example, constitute the development of a single reservoir or field, or an incremental development for a producing field, or the integrated development of several fields and associated facilities with a common ownership. In general, an individual project will represent the level at which a decision is made whether or not to proceed (i.e., spend more money) and there should be an associated range of estimated recoverable quantities for that project.
An accumulation or potential accumulation of petroleum may be subject to several separate and distinct projects that are at different stages of exploration or development. Thus, an accumulation may have recoverable quantities in several resource classes simultaneously.
In order to assign recoverable resources of any class, a development plan needs to be defined consisting of one or more projects. Even for Prospective Resources, the estimates of recoverable quantities must be stated in terms of the sales products derived from a development program assuming successful discovery and commercial development. Given the major uncertainties involved at this early stage, the development program will not be of the detail expected in later stages of maturity. In most cases, recovery efficiency may be largely based on analogous projects. In-place quantities for which a feasible project cannot be defined using current, or reasonably forecast improvements in, technology are classified as Unrecoverable.
Not all technically feasible development plans will be commercial. The commercial viability of a development project is dependent on a forecast of the conditions that will exist during the time period encompassed by the project's activities (see Commercial Evaluations, section 3.1). "Conditions" include
technological, economic, legal, environmental, social, and governmental factors. While economic factors can be summarized as forecast costs and product prices, the underlying influences include, but are not limited to, market conditions, transportation and processing infrastructure, fiscal terms, and taxes.
The resource quantities being estimated are those volumes producible from a project as measured according to delivery specifications at the point of sale or custody transfer (see Reference Point, section 3.2.1). The cumulative production from the evaluation date forward to cessation of production is the remaining recoverable quantity. The sum of the associated annual net cash flows yields the estimated future net revenue. When the cash flows are discounted according to a defined discount rate and time period, the summation of the discounted cash flows is termed net present value (NPV) of the project (see Evaluation and Reporting Guidelines, section 3.0).
The supporting data, analytical processes, and assumptions used in an evaluation should be documented in sufficient detail to allow an independent evaluator or auditor to clearly understand the basis for estimation and categorization of recoverable quantities and their classification.
2.0 Classification and Categorization Guidelines
2.1 Resources Classification
The basic classification requires establishment of criteria for a petroleum discovery and thereafter the distinction between commercial and sub-commercial projects in known accumulations (and hence between Reserves and Contingent Resources).
2.1.1 Determination of Discovery Status
A discovery is one petroleum accumulation, or several petroleum accumulations collectively, for which one or several exploratory wells have established through testing, sampling, and/or logging the existence of a significant quantity of potentially moveable hydrocarbons.
In this context, "significant" implies that there is evidence of a sufficient quantity of petroleum to justify estimating the in-place volume demonstrated by the well(s) and for evaluating the potential for economic recovery. Estimated recoverable quantities within such a discovered (known) accumulation(s) shall initially be classified as Contingent Resources pending definition of projects with sufficient chance of commercial development to reclassify all, or a portion, as Reserves. Where in-place hydrocarbons are identified but are not considered currently recoverable, such quantities may be classified as Discovered Unrecoverable, if considered appropriate for resource management purposes; a portion of these quantities may become recoverable resources in the future as commercial circumstances change or technological developments occur.
2.1.2 Determination of Commerciality
Discovered recoverable volumes (Contingent Resources) may be considered commercially producible, and thus Reserves, if the entity claiming commerciality has demonstrated firm intention to proceed with development and such intention is based upon all of the following criteria:
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Evidence to support a reasonable timetable for development.
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A reasonable assessment of the future economics of such development projects meeting defined investment and operating criteria.
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A reasonable expectation that there will be a market for all or at least the expected sales quantities of production required to justify development.
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Evidence that the necessary production and transportation facilities are available or can be made available.
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Evidence that legal, contractual, environmental and other social and economic concerns will allow for the actual implementation of the recovery project being evaluated.
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To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within a reasonable time frame. A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the scope of the project. While 5 years is recommended as a benchmark, a longer time frame could be applied where, for example, development of economic projects are deferred at the option
of the producer for, among other things, market-related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented.
To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests.
2.2 Resources Categorization
The horizontal axis in the Resources Classification (Figure 1.1) defines the range of uncertainty in estimates of the quantities of recoverable, or potentially recoverable, petroleum associated with a project. These estimates include both technical and commercial uncertainty components as follows:
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The total petroleum remaining within the accumulation (in-place resources).
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That portion of the in-place petroleum that can be recovered by applying a defined development project or projects.
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Variations in the commercial conditions that may impact the quantities recovered and sold (e.g., market availability, contractual changes).
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Where commercial uncertainties are such that there is significant risk that the complete project (as initially defined) will not proceed, it is advised to create a separate project classified as Contingent Resources with an appropriate chance of commerciality.
2.2.1 Range of Uncertainty
The range of uncertainty of the recoverable and/or potentially recoverable volumes may be represented by either deterministic scenarios or by a probability distribution (see Deterministic and Probabilistic Methods, section 4.2).
When the range of uncertainty is represented by a probability distribution, a low, best, and high estimate shall be provided such that:
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There should be at least a 90% probability (P90) that the quantities actually recovered will equal or exceed the low estimate.
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There should be at least a 50% probability (P50) that the quantities actually recovered will equal or exceed the best estimate.
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There should be at least a 10% probability (P10) that the quantities actually recovered will equal or exceed the high estimate.
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When using the deterministic scenario method, typically there should also be low, best, and high estimates, where such estimates are based on qualitative assessments of relative uncertainty using consistent interpretation guidelines. Under the deterministic incremental (risk-based) approach, quantities at each level of uncertainty are estimated discretely and separately (see Category Definitions and Guidelines, section 2.2.2).
These same approaches to describing uncertainty may be applied to Reserves, Contingent Resources, and Prospective Resources. While there may be significant risk that sub-commercial and undiscovered accumulations will not achieve commercial production, it is useful to consider the range of potentially recoverable quantities independently of such a risk or consideration of the resource class to which the quantities will be assigned.
2.2.2 Category Definitions and Guidelines
Evaluators may assess recoverable quantities and categorize results by uncertainty using the deterministic incremental (risk-based) approach, the deterministic scenario (cumulative) approach, or probabilistic methods (see "2001 Supplemental Guidelines," Chapter 2.5). In many cases, a combination of approaches is used.
Use of consistent terminology (Figure 1.1) promotes clarity in communication of evaluation results. For Reserves, the general cumulative terms low/best/high estimates are denoted as 1P/2P/3P, respectively. The associated incremental quantities are termed Proved, Probable and Possible. Reserves are a subset of, and must be viewed within context of, the complete resources classification system. While the categorization criteria are proposed specifically for Reserves, in most cases, they can be equally applied to
Contingent and Prospective Resources conditional upon their satisfying the criteria for discovery and/or development.
For Contingent Resources, the general cumulative terms low/best/high estimates are denoted as 1C/2C/3C respectively. For Prospective Resources, the general cumulative terms low/best/high estimates still apply. No specific terms are defined for incremental quantities within Contingent and Prospective Resources.
Without new technical information, there should be no change in the distribution of technically recoverable volumes and their categorization boundaries when conditions are satisfied sufficiently to reclassify a project from Contingent Resources to Reserves. All evaluations require application of a consistent set of forecast conditions, including assumed future costs and prices, for both classification of projects and categorization of estimated quantities recovered by each project (see Commercial Evaluations, section 3.1).
Based on additional data and updated interpretations that indicate increased certainty, portions of Possible and Probable Reserves may be re-categorized as Probable and Proved Reserves.
Uncertainty in resource estimates is best communicated by reporting a range of potential results. However, if it is required to report a single representative result, the "best estimate" is considered the most realistic assessment of recoverable quantities. It is generally considered to represent the sum of Proved and Probable estimates (2P) when using the deterministic scenario or the probabilistic assessment methods. It should be noted that under the deterministic incremental (risk-based) approach, discrete estimates are made for each category, and they should not be aggregated without due consideration of their associated risk (see "2001 Supplemental Guidelines," Chapter 2.5).
Table 1: Recoverable Resources Classes and Sub-Classes
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Class/Sub-Class
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Definition
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Guidelines
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Reserves
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Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions.
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Reserves must satisfy four criteria: they must be discovered, recoverable, commercial, and remaining based on the development project(s) applied. Reserves are further subdivided in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their development and production status.
To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within a reasonable time frame.
A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the scope of the project. While 5 years is recommended as a benchmark, a longer time frame could be applied where, for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented.
To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests.
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On Production
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The development project is currently producing and selling petroleum to market.
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The key criterion is that the project is receiving income from sales, rather than the approved development project necessarily being complete. This is the point at which the project "chance of commerciality" can be said to be 100%.
The project "decision gate" is the decision to initiate commercial production from the project.
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Approved for Development
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All necessary approvals have been obtained, capital funds have been committed, and implementation of the development project is under way.
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At this point, it must be certain that the development project is going ahead. The project must not be subject to any contingencies such as outstanding regulatory approvals or sales contracts. Forecast capital expenditures should be included in the reporting entity's current or following year's approved budget.
The project "decision gate" is the decision to start investing capital in the construction of production facilities and/or drilling development wells.
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Justified for Development
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Implementation of the development project is justified on the basis of reasonable forecast commercial conditions at the time of reporting, and there are reasonable expectations that all necessary approvals/contracts will be obtained.
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In order to move to this level of project maturity, and hence have reserves associated with it, the development project must be commercially viable at the time of reporting, based on the reporting entity's assumptions of future prices, costs, etc. ("forecast case") and the specific circumstances of the project. Evidence of a firm intention to proceed with development within a reasonable time frame will be sufficient to demonstrate commerciality. There should be a development plan in sufficient detail to support the assessment of commerciality and a reasonable expectation that any regulatory approvals or sales contracts required prior to project implementation will be forthcoming. Other than such approvals/contracts, there should be no known contingencies that could preclude the development from proceeding within a reasonable timeframe (see Reserves class).
The project "decision gate" is the decision by the reporting entity and its partners, if any, that the project has reached a level of technical and commercial maturity sufficient to justify proceeding with development at that point in time.
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Contingent Resources
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Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable due to one or more contingencies.
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Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status.
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Development Pending
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A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future.
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The project is seen to have reasonable potential for eventual commercial development, to the extent that further data acquisition (e.g. drilling, seismic data) and/or evaluations are currently ongoing with a view to confirming that the project is commercially viable and providing the basis for selection of an appropriate development plan. The critical contingencies have been identified and are reasonably expected to be resolved within a reasonable time frame. Note that disappointing appraisal/evaluation results could lead to a re-classification of the project to "On Hold" or "Not Viable" status.
The project "decision gate" is the decision to undertake further data acquisition and/or studies designed to move the project to a level of technical and commercial maturity at which a decision can be made to proceed with development and production.
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Development Unclarified or on Hold
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A discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant delay.
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The project is seen to have potential for eventual commercial development, but further appraisal/evaluation activities are on hold pending the removal of significant contingencies external to the project, or substantial further appraisal/evaluation activities are required to clarify the potential for eventual commercial development. Development may be subject to a significant time delay. Note that a change in circumstances, such that there is no longer a reasonable expectation that a critical contingency can be removed in the foreseeable future, for example, could lead to a reclassification of the project to "Not Viable" status.
The project "decision gate" is the decision to either proceed with additional evaluation designed to clarify the potential for eventual commercial development or to temporarily suspend or delay further activities pending resolution of external contingencies.
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| Class/Sub-Class | Definition | Guidelines |
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Development Not Viable
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A discovered accumulation for which there are no current plans to develop or to acquire additional data at the time due to limited production potential.
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The project is not seen to have potential for eventual commercial development at the time of reporting, but the theoretically recoverable quantities are recorded so that the potential opportunity will be recognized in the event of a major change in technology or commercial conditions.
The project "decision gate" is the decision not to undertake any further data acquisition or studies on the project for the foreseeable future.
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Prospective Resources
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Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations.
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Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects. It is recognized that the development programs will be of significantly less detail and depend more heavily on analog developments in the earlier phases of exploration.
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Prospect
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A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target.
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Project activities are focused on assessing the chance of discovery and, assuming discovery, the range of potential recoverable quantities under a commercial development program.
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Lead
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A project associated with a potential accumulation that is currently poorly defined and requires more data acquisition and/or evaluation in order to be classified as a prospect.
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Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to confirm whether or not the lead can be matured into a prospect. Such evaluation includes the assessment of the chance of discovery and, assuming discovery, the range of potential recovery under feasible development scenarios.
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Play
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A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects.
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Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to define specific leads or prospects for more detailed analysis of their chance of discovery and, assuming discovery, the range of potential recovery under hypothetical development scenarios.
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Table 2: Reserves Status Definitions and Guidelines
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Status
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Definition
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Guidelines
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Developed Reserves
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Developed Reserves are expected quantities to be recovered from existing wells and facilities.
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Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed Reserves may be further sub-classified as Producing or Non-Producing.
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Developed Producing Reserves
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Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.
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Improved recovery reserves are considered producing only after the improved recovery project is in operation.
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Developed Non-Producing Reserves
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Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.
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Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production.
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
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Undeveloped Reserves
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Undeveloped Reserves are quantities expected to be recovered through future investments:
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(1) from new wells on undrilled acreage in known accumulations, (2) from deepening existing wells to a different (but known) reservoir, (3) from infill wells that will increase recovery, or (4) where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects.
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Table 3: Reserves Category Definitions and Guidelines
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Category
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Definition
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Guidelines
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Proved Reserves
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Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations.
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If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.
The area of the reservoir considered as Proved includes (1) the area delineated by drilling and defined by fluid contacts, if any, and (2) adjacent undrilled portions of the reservoir that can reasonably be judged as continuous with it and commercially productive on the basis of available geoscience and engineering data.
In the absence of data on fluid contacts, Proved quantities in a reservoir are limited by the lowest known hydrocarbon (LKH) as seen in a well penetration unless otherwise indicated by definitive geoscience, engineering, or performance data. Such definitive information may include pressure gradient analysis and seismic indicators. Seismic data alone may not be sufficient to define fluid contacts for Proved reserves (see "2001 Supplemental Guidelines," Chapter 8).
Reserves in undeveloped locations may be classified as Proved provided that:
· The locations are in undrilled areas of the reservoir that can be judged with reasonable certainty to be commercially productive.
· Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with drilled Proved locations.
For Proved Reserves, the recovery efficiency applied to these reservoirs should be defined based on a range of possibilities supported by analogs and sound engineering judgment considering the characteristics of the Proved area and the applied development program.
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Probable Reserves
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Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves.
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It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate.
Probable Reserves may be assigned to areas of a reservoir adjacent to Proved where data control or interpretations of available data are less certain. The interpreted reservoir continuity may not meet the reasonable certainty criteria.
Probable estimates also include incremental recoveries associated with project recovery efficiencies beyond that assumed for Proved.
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Possible Reserves
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Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recoverable than Probable Reserves.
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The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P), which is equivalent to the high estimate scenario. When probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate.
Possible Reserves may be assigned to areas of a reservoir adjacent to Probable where data control and interpretations of available data are progressively less certain. Frequently, this may be in areas where geoscience and engineering data are unable to clearly define the area and vertical reservoir limits of commercial production from the reservoir by a defined project.
Possible estimates also include incremental quantities associated with project recovery efficiencies beyond that assumed for Probable.
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| Category | Definition | Guidelines |
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Probable and Possible Reserves
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(See above for separate criteria for Probable Reserves and Possible Reserves.)
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The 2P and 3P estimates may be based on reasonable alternative technical and commercial interpretations within the reservoir and/or subject project that are clearly documented, including comparisons to results in successful similar projects.
In conventional accumulations, Probable and/or Possible Reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from Proved areas by minor faulting or other geological discontinuities and have not been penetrated by a wellbore but are interpreted to be in communication with the known (Proved) reservoir. Probable or Possible Reserves may be assigned to areas that are structurally higher than the Proved area. Possible (and in some cases, Probable) Reserves may be assigned to areas that are structurally lower than the adjacent Proved or 2P area.
Caution should be exercised in assigning Reserves to adjacent reservoirs isolated by major, potentially sealing, faults until this reservoir is penetrated and evaluated as commercially productive. Justification for assigning Reserves in such cases should be clearly documented. Reserves should not be assigned to areas that are clearly separated from a known accumulation by non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results); such areas may contain Prospective Resources.
In conventional accumulations, where drilling has defined a highest known oil (HKO) elevation and there exists the potential for an associated gas cap, Proved oil Reserves should only be assigned in the structurally higher portions of the reservoir if there is reasonable certainty that such portions are initially above bubble point pressure based on documented engineering analyses. Reservoir portions that do not meet this certainty may be assigned as Probable and Possible oil and/or gas based on reservoir fluid properties and pressure gradient interpretations.
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The 2007 Petroleum Resources Management System can be viewed in its entirety at
http://www.spe.org/spe-app/spe/industry/reserves/prms.htm.