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Commercial and economic assumptions in production forecasting
The following guidelines are provided to promote consistency in production forecasting and reporting. “Reporting” refers to the presentation of evaluation results within the business entity conducting the evaluation and should not be construed as replacing guidelines for subsequent public disclosures under guidelines established by regulatory and/or other government agencies, or any current or future associated accounting standards.
Impact of commercial terms on production forecasts
Commercial terms refer both to those specified in Production Operating Agreements (POA) and to the tax laws existing in the affected countries. The POA typically describes the production entitlement of the operating groups and the mechanisms for sharing or recovering costs. The majority of this document focuses on forecasting the total production from a reservoir or field (gross volumes forecast). The incorporation of the commercial terms allows entities to determine their net entitlement volumes. The commercial terms also impact the gross volumes forecast by their effect on field life, and the size of the future capital and expense work programs. A field development may even be optimized based on POA terms if their impact is significant enough.
Cash-flow-based production forecasts
Production forecasts are based on estimates of future production volumes and the associated cash flow schedules. The associated annual net cash flows forecast the profitability and viability of the future field operations. The calculation of annual net cash flow should reflect:
- The expected quantities of production projected over identified time periods. Fig 1.1 shows a typical asset production profile built up of base plus several additional later projects that add incremental production over the field’s life.
- The estimated costs associated with the projects to develop, recover, and produce the quantities of production, including environmental, abandonment, and reclamation costs charged to the project, based on the evaluator’s view of the costs expected to apply in future periods.
- The estimated revenues from the quantities of production based on the evaluator’s view of the prices expected to apply to the respective commodities in future periods including that portion of the costs and revenues accruing to the entity.
- Future projected production and revenue related taxes and royalties expected to be paid by the entity.
- A project life that is limited to the period of entitlement or reasonable expectation thereof. While each organization may define specific criteria for continuing field operations, a field is generally considered to be at the end of life when its “best estimate” case has a negative annual net cash flow.
INSERT Figure 1 Asset production forecast over field life (Pending permission approval)
Forecasters must clearly identify the assumptions on commercial conditions utilized in the evaluation and must document the basis for these assumptions. The economic evaluation underlying the investment decisions are based on the entity’s reasonable forecast of future conditions, including costs and prices, which will exist during the life of the project (forecast case). Such forecasts are based on projected changes to current conditions.
In PRMS, SPE defines current conditions as the average of those existing during the previous 12 months. Alternative economic scenarios are considered in the decision process and, in some cases, to supplement reporting requirements. Forecasters may examine a case in which current conditions are held constant (no inflation or deflation) throughout the project life (constant case). Evaluations may be modified to accommodate criteria imposed by regulatory agencies regarding external disclosures. External reporting requirements may also specify alternative guidance on current conditions (for example, year-end costs and prices).
The economic limit is defined as the production rate beyond which the net operating cash flows from a project, which may be an individual well, lease, or entire field, are negative, a point in time that defines the project’s economic life. Operating costs should be based on the same type of projections as used in price forecasting (taking historical performance into account). Operating costs should include only those costs that are incremental to the project for which the economic limit is being calculated (i.e., only those cash costs that will actually be eliminated if project production ceases should be considered in the calculation of economic limit). Operating costs should include fixed property-specific overhead charges if these are actual incremental costs attributable to the project and any production and property taxes but, for purposes of calculating economic limit, should exclude depreciation, abandonment and reclamation costs, and income tax, as well as any overhead above that required to operate the subject property itself. Operating costs may be reduced, and thus project life extended, by various cost-reduction and revenue-enhancement approaches, such as sharing of production facilities, pooling maintenance contracts, demanning facilities if appropriate or marketing of associated non-hydrocarbons.
Interim negative project net cash flows may be accommodated in short periods of low product prices or major operational problems, provided that the longer-term forecasts must still indicate positive economics.
Resources entitlement and recognition
While assessments are conducted to establish estimates of the total Petroleum Initially-in-Place and that portion recovered by defined projects, the allocation of sales quantities, costs, and revenues impacts the project economics and commerciality. This allocation is governed by the applicable contracts between the mineral owners (lessors) and contractors (lessees) and is generally referred to as “entitlement.” There are several basic types of contracts which are summarized in the following sections.
Royalty refers to payments that are due to the host government or mineral owner (lessor) in return for depletion of the reservoirs by the producer (lessee/contractor) having access to the petroleum resources. Many agreements allow for the lessee/contractor to lift the royalty volumes and sell them on behalf of, and pay the proceeds to, the royalty owner/lessor. Some agreements provide for the royalty to be taken only in-kind by the royalty owner. In either case, royalty volumes must be deducted from the lessee’s entitlement to resources. In some agreements, royalties owned by the host government are actually treated as taxes to be paid in cash. Applicable royalty rates vary by country and individual asset agreement.
Production-sharing contract reserves
Production-Sharing Contracts (PSCs) of various types replace conventional tax-royalty systems in many countries. Under the PSC terms, the producers have an entitlement to a portion of the production. This entitlement, often referred to as “net entitlement” or “net economic interest,” is estimated using a formula based on the contract terms incorporating project costs (cost oil) and project profits (profit oil). Although ownership of the production invariably remains with the government authority up to the export point of the project, the producers may take title to their share of the net entitlement at that point.
Unlike traditional royalty-lease agreements, the cost recovery system in production-sharing, risk service, and other related contracts typically reduce the production share obtained by a contractor in periods of high price and increase volumes in periods of low price. While this ensures cost recovery, it introduces a significant price-related volatility in annual net entitlement production forecasts.
Contract extensions or renewals
As production-sharing or other types of agreements approach maturity, they can be extended by negotiation for contract extensions, by the exercise of options to extend, or by other means. For most forecasting purposes (eg. Reserves, economic analysis for decision making), additional production and extension of field life should not be assumed beyond the ending date of the current agreement unless there is reasonable expectation that an extension, a renewal, or a new contract will be granted. Such reasonable expectation may be based on the historical treatment of similar agreements by the license-issuing jurisdiction. Moreover, it may not be reasonable to assume that the fiscal terms in a negotiated extension will be similar to existing terms. This aligns with Production forecasting activity scheduling of the 2007 PRMS guidance document. The exception may be when generating a production forecast to determine “technical limit recovery” where it is appropriate to ignore commercial constraints such as these but assumptions for the forecast should be clearly stated.
Noteworthy papers in OnePetro
Jalilova, N., Tautiyev, A., Forcadell, J., Rodriguez, J. C., & Sama, S. 2008. Production Optimization in an Oil Producing Asset - The BP Azeri Field Optimizer Case. Society of Petroleum Engineers. http://dx.doi.org/10.2118/118454-MS.
Okoh, E., Sathyamoorthy, S., Olaniyan, E., & Ezeokeke, O. 2010. Application of Integrated Production System Modelling in Effective Well and Reservoir Management of the Bonga Field. Society of Petroleum Engineers. http://dx.doi.org/10.2118/140632-MS.
Roadifer, R. D., Sauve, R. E., Torrens, R., Mead, H. W., Pysz, N. P., Uldrich, D. O., & Eiben, T. 2012. Integrated Asset Modeling for Reservoir Management of a Miscible WAG Development on Alaska. Society of Petroleum Engineers. http://dx.doi.org/10.2118/158497-MS.
Production forecasts and reserves estimates in unconventional resources. Society of Petroleum Engineers. http://www.spe.org/training/courses/FPE.php
Production Forecasts and Reserves Estimates in Unconventional Resources. Society of Petroleum Engineers. http://www.spe.org/training/courses/FPE1.php