EX-99.1 8 chap1203-991.txt ESTIMATED FUTURE RESERVES EXHIBIT 99.1 CHAPARRAL RESOURCES, INC. Estimated Future Reserves and Income Attributable to Certain Leasehold Interests of Karakuduk-Munay, JSC SEC Parameters As of December 31, 2003 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
R S RYDER SCOTT COMPANY ------------------- PETROLEUM CONSULTANTS FAX (713) 651-0849 1100 LOUISIANA SUITE 3800 HOUSTON, TEXAS 77002-5218 TELEPHONE (713) 651-9191 March 5, 2004 Chaparral Resources, Inc. 2 Gannett Drive, Suite 418 White Plains, NY 10604 Gentlemen: At your request, we have prepared an estimate of the reserves, future production and income attributable to leasehold interests of Karakuduk-Munay, JSC (KKM) in the Karakuduk field (located in the Republic of Kazakhstan) as of December 31, 2003. The income data were estimated using the Securities and Exchange Commission (SEC) requirements for future price and cost parameters. The estimated reserves and future income amounts presented in this report are related to hydrocarbon prices. Hydrocarbon prices in effect at December 31, 2003 were used in the preparation of this report as required by SEC rules (see discussion on Hydrocarbon Prices); however, actual future prices may vary significantly from December 31, 2003 prices. Therefore, volumes of reserves actually recovered and amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below. SEC PARAMETERS Estimated Net Reserve and Income Data Certain Leasehold Interests of Karakuduk-Munay, JSC As of December 31, 2003 Proved ----------------------------------------------------- Developed -------------------------- Total Producing Non-Producing Undeveloped Proved ----------- ------------- ----------- ----------- Net Remaining Reserves ---------------------- Oil/Condensate - Barrels 10,874,659 4,232,196 10,508,873 25,615,728 Income Data - M$ ---------------- Future Gross Revenue $ 250,770 $ 97,596 $ 242,335 $ 590,700 Deductions 85,599 41,028 114,084 240,711 ----------- ----------- ----------- ----------- Future Net Income (FNI) $ 165,170 $ 56,568 $ 128,250 $ 349,989 Discounted FNI @ 10% $ 118,588 $ 25,207 $ 81,867 $ 225,662 1200, 530 8TH AVENUE, S.W. CALGARY, ALBERTA T2P 3S8 TEL (403) 262-2799 FAX (403) 262-2790 621 17TH STREET, SUITE 1550 DENVER, COLORADO 80293-1501 TEL (303) 623-9147 FAX (303) 623-4258
Chaparral Resources, Inc. March 5, 2004 Page 2 Probable -------------------------------------------- Developed Total Non-Producing Undeveloped Probable ------------- ----------- ----------- Net Remaining Reserves ---------------------- Oil/Condensate - Barrels 524,075 36,896,441 37,420,516 Income Date - M$ ---------------- Future Gross Revenue $ 12,085 $ 850,835 $ 862,920 Deductions 2,841 223,843 226,684 ----------- ----------- ----------- Future Net Income (FNI) $ 9,244 $ 626,991 $ 636,236 Discounted FNI @ 10% $ 3,940 $ 281,272 $ 285,212 Liquid hydrocarbons are expressed in standard 42 gallon barrels. The deductions from future gross revenue after royalty (6.8 percent of gross volume) comprise the normal direct costs of operating the wells, Naftex Commission and export tariff ($ 2.46 per stock tank barrel of oil), local sales tariff and transportation costs ($4.44 per stock tank barrel of oil), recompletion costs, development costs, and abandonment costs. The future net income is before the deduction of government taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for 100 percent of total future gross revenue from proved reserves. Gas reserves were not included at the request of Chaparral Resources, Inc. (Chaparral) due to uncertainties in gas sales stability, market conditions, and a potential gas re-injection program. The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown on each estimated projection of future production and income presented in a later section of this report and in summary form below. Discounted Future Net Income - M$ As of December 31, 2003 ----------------------------------- Discount Rate Total Total Percent Proved Probable ------------- ------------ ------------ 8 $244,677 $330,174 12 $208,784 $248,001 15 $186,842 $203,462 20 $157,395 $150,570 The results shown above are presented for your information and should not be construed as our estimate of fair market value. Reserves Included in This Report The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission's Regulation S-X Part 210.4-10 (a) as clarified by subsequent Commission Staff Accounting Bulletins. The probable reserves included herein conform to definitions of probable reserves approved by the SPE/WPC using the deterministic methodology. The definitions of proved and probable reserves are included under the tab "Petroleum Reserves Definitions" in this report. Chaparral Resources, Inc. March 5, 2004 Page 3 We have included probable reserves and income in this report at the request of Chaparral. These data are for Chaparral's information only, and should not be included in reports to the SEC according to the SEC disclosure specifications. The probable reserves are less certain to be recovered than the proved reserves. The reserves and income quantities attributable to the different reserve classifications that are included herein have not been adjusted to reflect the varying degrees of risk associated with them and thus are not comparable. Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled. The various reserve status categories are defined under the tab "Petroleum Reserves Definitions" in this report. The developed non-producing reserves included herein are comprised of the shut-in and behind-pipe categories. Estimates of Reserves The Karakuduk field comprises ten identified reservoirs (Jurrasic-1 through Jurrasic-10 or J-1 through J-10) of which eight have been found productive (J-1, J-2, J-4, J-6, J-7, J-8, J-9, and J-10). Production began in March of 1998. Many of the wells that were producing from lower sands have recently been re-completed to the prolific J-1 sand to optimize J-1 production, but will be returned to production once the J-1 sand has been depleted. Remaining volumes expected to be recovered from the lower sands in wells that were re-completed to the J-1 reservoir are currently carried as non-producing leases (i.e. shut-in, behind pipe). The field contains a total of 49 existing wells of which 40 are producing as of December 31, 2003. Of the nine non-producing wells, two are awaiting completion after hydraulic fracture treatment (#13 and #145), four wells are awaiting conversion to injection (#7, #22 and #159 in J-1, #88 in J-8/J-9), one well is already injecting into J-1 (#103), and two wells are in line for pump installations or repairs (#21, #173). General reserves estimation assumptions --------------------------------------- In general, the reserves included herein were estimated by a combination of the volumetric and performance methods. The performance method by itself was applied only in cases where the historically established decline trend was definitive. Reserves were estimated by the volumetric method in those cases where there were inadequate historical performance data to establish a definitive trend or where the exclusive use of production performance data as a basis for the reserve estimates was considered to be inappropriate. An average drainage area per well was determined for each reservoir based on the estimated drainage area of existing producing wells. For the J-4, J-6A, J-6B, and J-10 zones, an average ultimate drainage area of 180 acres was estimated. An average ultimate drainage area of 90 acres per well was estimated for reservoirs J-2, J-7, and J-8/J-9. The original development plan for the Karakuduk field proposed 90-acre well spacing. Our review of the most recent performance data indicates that 150 to 180-acre well spacing may be more appropriate for the better sands. This was confirmed by a reservoir simulation model which indicated an average drainage area of 150 acres per well for the J-1 reservoir. Additional studies are planned to investigate benefits from horizontal wells. Chaparral Resources, Inc. March 5, 2004 Page 4 2003 Drilling activities at the Karakuduk Field ----------------------------------------------- o 13 new wells were drilled during 2003 o 141 - drilled & completed in J-1/J-2 in March 2003 o 111 - drilled & completed in J-1/J-2 in April 2003 o 193 - drilled & completed in J-1/J-2 in April 2003 o 145 - drilled & completed in J-1 in June 2003 o 122 - drilled & completed in J-1 in June 2003 o 124 - drilled & completed in J-1 in July 2003 o 159 - drilled & completed in J-1 in July/August 2003 - candidate for conversion o 119 - drilled & completed in J-1 in August 2003 o 105 - drilled & completed in J-1 in September 2003 o 110 - drilled & completed in J-1 in October/November 2003 o 177 - drilled & completed in J-1/J-2 in October/November 2003 o 200 - drilled & completed in J-1 in November 2003 o 196 - drilled in J-1 in December 2003 (not yet completed) The estimated oil in place in the J-1 reservoir increased from 159.0 million stock tank barrels (MMstb) to 167.0 MMstb as a result of drilling these thirteen wells. The net add to proved reserves from the 2003 well activities is estimated at 1.8 MMstb. Seven of the thirteen wells had been carried as proved-undeveloped locations during the December 31, 2002 SEC evaluation and did not result in proved reserves additions this year. Four new proved-undeveloped locations where added, however, based on successful expansion drilling in the southern areas of the J-1 reservoir. Preliminary evaluations of the lower reservoirs (J-3 through J-10) in the new wells did not result in any adjustments to reserves. The thirteen new wells were designed to increase production and identify additional proved oil-in-place-volume in the J-1 reservoir but are located outside the proved areas of the lower reservoirs. None of the new wells identified new productive areas in the lower sands beyond already defined proven areas. As a result, proved behind-pipe and undeveloped locations in the lower sands have been carried forward from last year without adjustments. Pressure maintance program and waterflood operations in the J-1 reservoir ------------------------------------------------------------------------- No evidence of natural aquifer support has been observed to date. In the summer of 2002, injection of produced water began in well #103 at the crest of the J-1 reservoir at an average rate of 50 m3/day (315 bbl/day). The volume of injection was small, however, compared to off-take and did not result in any measurable pressure changes nor did it result in a measurable waterflood response. As a result, from 1998 through the latter parts of 2003 the field has, for all practical purpose, produced under primary depletion drive in all sands. Water injection into well #103 increased in October 2003 to an average of 400 m3/day (2,500 bbl/day) with water from a new water-supply well (#4w). Two additional water supply wells (#5w and #6w) were drilled in 2003 and are currently undergoing completion and pump installations. The average deliverability of a water supply well is 400 to 500 m3/day (2,500 to 3,150 bbl/day) from a shallow aquifer situated above the Karakuduk pay sands. Additional water supply wells are scheduled for 2004 (3 wells) and 2005 (3 to 4 wells) for a total of nine to ten water supply wells with a total estimated capacity of 3,600 to 5,000 m3/day (22,000 to 30,000 bbl/day). As of December 31, 2003 there have been some indications that increased injection into well #103 has resulted in incremental oil recovery in the J-1 reservoir at off-set pattern producers #178, #179, #180, #186, and #187. The oil rate response was ambiguous, however, due to frequent choke adjustments during the same period. While no clear rate response can be isolated and attributed to an initial waterflood response, there has been a pressure increase of 180 psia and 570 psia in wells #180 and #186, respectively (wells #178, #179, and #180 were not tested). Chaparral Resources, Inc. March 5, 2004 Page 5 A new recovery factor of 17.0 percent of original oil in place was estimated for the J-1 reservoir based on a pressure maintenance/support program as a result of: o continued injection of 400 m3/day (2,500 bbl/day) of water injection into J-1 in well #103 o a positive pressure response in wells #180 and #186 o ample water supply to meet J-1 injection requirements of approximately 2,000 m3/day (13,000 bbl/day) for a pressure maintenance program. Ultimately a total of up to ten water supply wells (three existing) with an estimated capacity of up to 5,000 m3/day (30,000 bbl/day) are expected to be in place by year-end 2005. o five additional planned wells for injection into the J-1 reservoir during 2004 and early 2005 (#22, #159, #4, #7, and #143 (new drill)). The 17.0 percent ultimate recovery factor represents an increase of 3.5 percent over last year's estimate under depletion drive mechanism of 13.5 percent of original-oil-in-place. The 17.0 percent recovery factor was also confirmed by simulation results. The incremental 3.5 percent proved reserves add (5.870 MMstb) is included as a proved-producing pressure maintenance lease for the J-1 reservoir. All other reservoirs were still subject to the recovery estimate of 13.5 percent of original oil in place under primary recovery methods. Proved undeveloped locations ---------------------------- Based on an average well spacing of 150 acres per well in the J-1 reservoir 33 additional proved-undeveloped wells are expected to be drilled in the J-1 reservoir. The average expected recovery per well from these wells was estimated at 319 Mstb/well. Proved undeveloped reserves in all other sands were assigned to locations within one well spacing (as established by performance to date) from proved producing, behind pipe, or shut-in locations. Reserves assigned to these undeveloped locations were based on volumetric calculations for a reservoir specific drainage area and a 13.5 percent primary recovery factor. Proved behind pipe locations ---------------------------- In general, proved behind pipe reserves were assigned to sands (in existing wellbores) with a positive oil test or to wells with a comparable log signature to producing wells in a particular sand where the well in question was inside the area of one well spacing from proved producing or shut-in locations. Proved behind pipe reserves were also assigned to estimated incremental reserves in producing or shut-in wells that require a pump or a hydraulic fracture treatment. Reserves assigned to these behind pipe locations were based on volumetric calculations for a reservoir specific drainage area and a 13.5 percent primary recovery factor. Probable undeveloped locations ------------------------------ In the J-1 sand, nine probable-undeveloped locations were assigned to wells approximately one to two well spacings away from existing wells in the southern part of the field. The limits of the field have not yet been defined in the southern part by either fluid contact or thinning of the sand. In all other sands probable undeveloped and behind pipe locations were assigned to locations within three well spacings but outside one well spacing from proved producing, behind pipe, or shut-in locations. Chaparral Resources, Inc. March 5, 2004 Page 6 The reserves attributed to the waterflood project for all sands at the Karakuduk field were classified as probable undeveloped as no clear waterflood response has been observed to date. Waterflood reserves (or fractions thereof) may be reclassified as proved once a definitive oil rate increase can be observed as a result of water injection. The total primary plus secondary recovery is estimated at 30.0 percent of original-oil-in-place based on results from a J-1/J-2 reservoir simulation model constructed in 2002. The economic evaluation of possible reserves was not included in this report. We did, however, complete a preliminary analysis of volumes that would be considered possible based on currently available data. Possible recoverable volumes identified by our firm amount to approximately 35.0 MMstb, and are comprised of the following: 1. Volumes outside three well spacings but inside the currently defined limits of the field 2. Volumes that are contained within the probable oil region but were not included as probable reserves due to uncertainty in pay thickness and distribution Additional possible reserves may exist outside the currently defined limits, especially in the J-1 sand. New delineation or exploratory drilling may result in reclassification or reserve additions in the future. Potential for reserve additions may also be realized in sands below the J-10 sand. Well #20 showed a zone that is approximately 150 feet thick with a good log response in the J-13 sand; this zone has not yet been tested. Further potential may also be realized from re-injection of produced gas at the top of the reservoir for pressure maintenance and/or a double displacement process (peripheral water and up-dip gas injection). No analysis has been performed by our firm at this time to quantify any of these potentials. The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations. Future Production Rates Initial production rates are based on the current producing rates for those wells now on production. If a decline trend has been established, this trend was used as the basis for estimating future production rates. Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations which are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by KKM. Several sands stratigraphically below the J-1 reservoir have been produced for short periods of time, in order to establish potential production profiles. Many of these stratigraphically lower sands have since been shut-in in order to exploit the J-1 sand, but will be returned to production, once the prolific J-1 sand has been depleted. After the J-1 sand is depleted, the general procedure will be to complete and produce each of the remaining sands, starting with the stratigraphically lowest, and moving up the wellbore. Probable waterflood reserves are scheduled to begin mid 2004 at which point a response is expected to occur near the existing injector #103. Waterflood volumes are in addition to volumes assigned to the pressure maintenance lease in the J-1 reservoir. The future production rates from wells now on production may be more or less than estimated because of changes in market conditions or allowables set by regulatory bodies. Wells or locations which are not currently producing may start producing earlier or later than anticipated in our estimates of their future production rates. Chaparral Resources, Inc. March 5, 2004 Page 7 Hydrocarbon Prices Chaparral furnished us with hydrocarbon prices in effect at December 31, 2003. In accordance with FASB Statement No. 69, December 31, 2003 market prices were determined using the daily Brent oil price ("spot price") adjusted for oil quality and density. Also in accordance with SEC and FASB specifications, changes in market prices subsequent to December 31, 2003 were not considered in this report. Chaparral advised us that KKM has been required to sell a portion of their production on the domestic Kazakhstan market and that for the purpose of this report, KKM will export 95.0 percent of their crude production and sell 5.0 percent on the domestic market. The effective oil price after quality and density adjustments and a 95:5 export:local sales split was $25.52 per stock tank barrel (see detail below). Oil Price Calculation --------------------- Export Sales U.S. $/stb Local Sales U.S. $/stb Brent Price Assumptions 30.48 Brent/Urals Differential (1.50) Density Price Adjustment (2.59) Net Export OIl Price 26.39 Local sales price 8.92 Export Sales % 95% Local Sales Percentage 5% ----- ---- Export Price 25.07 Local Price 0.45 ===== ==== Effective Oil Price 25.52 U.S. $/stb ===== Costs Operating costs for the leases and wells in this report are based on the operating expense reports of Chaparral and include only those costs directly applicable to the leases or wells. No deduction was made for indirect costs such as general administration and overhead expenses, loan repayments, interest expenses, and exploration and development prepayments that are not charged directly to the leases or wells. Proven operating costs (as provided by Chaparral) were combined with proven facility development cost (as provided by Chaparral) and 100.0 percent allocated to proven reserve category summaries (i.e. proved producing summary, proved shut-in summary, proved behind pipe summary, and proved undeveloped summary) based on future net income. The resulting cost summaries for the four proven reserve categories can be found in Tables 143 through 146. Probable operating costs (as provided by Chaparral) were combined with proven facility development cost (as provided by Chaparral) and 100.0 percent allocated to probable reserve category summaries (i.e. probable behind pipe summary, and probable undeveloped summary) based on future net income. The resulting cost summaries for the two probable reserve categories can be found in Tables 147 and 148. Chaparral Resources, Inc. March 5, 2004 Page 8 Development cost schedules (drilling, completions, pumps, and hydraulic fractures) were furnished to us by Chaparral and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The estimated net cost of abandonment after salvage was included at $80,000 per well. The estimates of the net abandonment costs furnished by Chaparral were accepted without independent verification. Current costs were held constant throughout the life of the properties. General Table A presents a one line summary of proved reserve and income data for each of the subject properties which are ranked according to their future net income discounted at 10 percent per year. Table B presents a one line summary of gross and net reserves and income data for each of the subject properties. Table C presents a one line summary of initial basic data for each of the subject properties. Tables 1 through 148 present our estimated projection of production and income by years beginning January 1, 2004, by reserve category and well. The estimates of reserves presented herein are based upon a detailed study of the properties in which Chaparral owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities which may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices. Chaparral has informed us that they have furnished us all of the accounts, records, geological and engineering data, and reports and other data required for this investigation. The ownership interests, prices, and other data furnished by Chaparral were accepted without independent verification. The estimates presented in this report are based on data available through December 31, 2003. Neither we nor any of our employees have any interest in the subject properties and neither the employment to make this study nor the compensation is contingent on our estimates of reserves and future income for the subject properties. This report was prepared for the exclusive use and sole benefit of Chaparral. The data, work papers, and maps used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service. Very truly yours, RYDER SCOTT COMPANY, L.P. /s/ Thomas Wagenhofer, P.E. --------------------------- Thomas Wagenhofer, P.E. Petroleum Engineer TW/pl Reviewed by: /s/ Dean C. Rietz ------------------------------- Dean C. Rietz, P.E. Managing Senior Vice President PETROLEUM RESERVES DEFINITIONS SECURITIES AND EXCHANGE COMMISSION INTRODUCTION ------------ Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. It should be noted that Securities and Exchange Commission Regulation S-K prohibits the disclosure of estimated quantities of probable or possible reserves of oil and gas and any estimated value thereof in any documents publicly filed with the Commission. Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change. Reserves do not include quantities of petroleum being held in inventory, and may be reduced for usage or processing losses if required for financial reporting. Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve. PROVED RESERVES (SEC DEFINITIONS) --------------------------------- Securities and Exchange Commission Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows: Proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. (i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes: (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. PETROLEUM RESERVES DEFINITIONS Page 2 (ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. (iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources. Proved developed oil and gas reserves. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. Proved undeveloped reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff's view on specific questions pertaining to proved oil and gas reserves. Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35) PETROLEUM RESERVES DEFINITIONS Page 3 In determining whether "proved undeveloped reserves" encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary recovery when a field is in the late stages of depletion? ... The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35) Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35) The staff believes that since coalbed methane gas can be recovered from coal in its natural and original location, it should be included in proved reserves, provided that it complies in all other respects with the definition of proved oil and gas reserves as specified in Rule 4-10(a)(2) including the requirement that methane production be economical at current prices, costs, (net of the tax credit) and existing operating conditions. (extracted from SAB-85) Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission's official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws. SUB-CATEGORIZATION OF DEVELOPED RESERVES (SPE/WPC DEFINITIONS) -------------------------------------------------------------- In accordance with guidelines adopted by the Society of Petroleum Engineers (SPE) and the World Petroleum Congress (WPC), developed reserves may be sub-categorized as producing or non-producing. Producing. Reserves sub-categorized as producing are expected to be recovered from completion intervals which are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation. Non-Producing. Reserves sub-categorized as non-producing include shut-in and behind pipe reserves. 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 started producing, (2) wells which were shut-in awaiting pipeline connections or as a result of a market interruption, 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 recompletion prior to the start of production. PETROLEUM RESERVES DEFINITIONS Page 4 UNPROVED RESERVES (SPE/WPC DEFINITIONS) --------------------------------------- Unproved reserves are based on geologic and/or engineering data similar to that used in estimates of proved reserves; but technical, contractual, economic, or regulatory uncertainties preclude such reserves being classified as proved. Unproved reserves may be further classified as probable reserves and possible reserves. Unproved reserves may be estimated assuming future economic conditions different from those prevailing at the time of the estimate. The effect of possible future improvements in economic conditions and technological developments can be expressed by allocating appropriate quantities of reserves to the probable and possible classifications. Probable Reserves. Probable reserves are those unproved reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable. In this context, when probabilistic methods are used, there should be at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves. In general, probable reserves may include (1) reserves anticipated to be proved by normal step-out drilling where sub-surface control is inadequate to classify these reserves as proved, (2) reserves in formations that appear to be productive based on well log characteristics but lack core data or definitive tests and which are not analogous to producing or proved reserves in the area, (3) incremental reserves attributable to infill drilling that could have been classified as proved if closer statutory spacing had been approved at the time of the estimate, (4) reserves attributable to improved recovery methods that have been established by repeated commercially successful applications when (a) a project or pilot is planned but not in operation and (b) rock, fluid, and reservoir characteristics appear favorable for commercial application, (5) reserves in an area of the formation that appears to be separated from the proved area by faulting and the geologic interpretation indicates the subject area is structurally higher than the proved area, (6) reserves attributable to a future workover, treatment, re-treatment, change of equipment, or other mechanical procedures, where such procedure has not been proved successful in wells which exhibit similar behavior in analogous reservoirs, and (7) incremental reserves in proved reservoirs where an alternative interpretation of performance or volumetric data indicates more reserves than can be classified as proved.