[Ryder Scott Company Petroleum Consultants Letterhead]
April 10, 2002
Chaparral Resources, Inc.
16945 North Chase Drive
Suite 1620
Houston, Texas 77060
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) as of December 31, 2001. The subject property is located in the
Karakuduk field in the Republic of Kazakhstan. 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, 2001 were used in the preparation of this report as required by SEC
rules; however, actual future prices may vary significantly from December 31,
2001 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, 2001
-------------------------------------------------------------
Proved
---------------------------------------------------------
Developed
--------------------------- Total
Producing Non-Producing Undeveloped Proved
------------ ------------ ------------ ------------
Net Remaining Reserves*
- -----------------------
Oil/Condensate - Barrels 4,885,163 8,634,447 16,400,987 29,920,597
Income Data
- -----------
Future Gross Revenue $ 67,185,656 $118,749,524 $225,562,767 $411,497,947
Deductions 33,808,268 74,390,453 148,098,213 256,296,934
------------ ------------ ------------ ------------
Future Net Income (FNI) $ 33,377,388 $ 44,359,071 $ 77,464,554 $155,201,013
Discounted FNI @ 10% $ 27,077,014 $ 27,427,882 $ 49,426,636 $103,931,532
*after royalty deduction. This is in contrast to previously published reports by
Ryder Scott on this property, where per request by Chaparral Resources, Inc.,
royalty was deducted as a production tax.
Chaparral Resources, Inc.
April 10, 2002
Page 2
Rrobable
--------------------------------------------
Developed Total Total
Non-Producing Undeveloped Probable
------------ ------------ ------------
Net Remaining Reserves*
Oil/Condensate - Barrels 848,866 44,568,312 45,417,178
Income Data
Future Gross Revenue $ 11,674,444 $612,947,999 $624,622,443
Deductions 4,765,093 212,546,797 217,311,890
------------ ------------ ------------
Future Net Income (FNI) $ 6,909,351 $400,401,202 $407,310,553
Discounted FNI @ 10% $ 1,300,252 $133,602,169 $134,902,421
*after royalty deduction. This is in contrast to previously published reports by
Ryder Scott on this property, where per request by Chaparral Resources, Inc.,
royalty was deducted as a production tax.
Liquid hydrocarbons are expressed in standard 42 gallon barrels.
The deductions from future gross revenue after royalty comprise the normal
direct costs of operating the wells, Stasco Commission, export tariff, local
sales tariff, transportation costs, recompletion costs, development costs, and
certain 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 Chaparral Resources, Inc. (Chaparral) request, 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
As of January 1, 2002
-------------------------------------------------
Discount Rate Total Total
Percent Proved Probable
- --------------------- ------------------- -------------------
8 $112,416,300 $166,604,975
12 $ 96,227,829 $109,682,005
14 $ 89,235,246 $ 89,504,042
16 $ 82,885,264 $ 73,273,758
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 "Reserve Definitions" in this
report.
Chaparral Resources, Inc.
April 10, 2002
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.
All proved and probable reserves incorporated herein are based on the
current definitions of the field limits. KKM has an active exploratory and
development drilling program that may result in the discovery or
reclassification of additional volumes.
The various reserve status categories are defined under the tab "Reserve
Definitions" in this report. The developed non-producing reserves included
herein are comprised of the shut-in and behind-pipe categories.
Estimates of Reserves
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. Existing
performance data was, however, used to guide volumetric drainage area estimates
based on an assumed 30.0 percent annual decline rate from current rates.
Proved and probable reserves attributed to primary recovery by the
volumetric method were determined by assigning a 16.0 percent primary recovery
efficiency of original oil in place to an estimated drainage area. An average
drainage area per well was determined for each reservoir based on the estimated
drainage area of existing producing wells. An average ultimate drainage area of
150 acres per well was estimated for the J-1 reservoir. 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. Additional studies (e.g. numerical reservoir simulation) are
planned to investigate and quantify the appropriate expected well drainage
areas, including the incremental benefit of horizontal wells, which may recover
two to three times the volume of conventional vertical wells.
The average expected recovery of existing producers in the J-1 sand is
350,000 STB/well. Proved undeveloped and behind pipe locations in the J-1 sand
were assigned an average of 350,000 STB/well depending on expected drainage for
a given location 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.
Chaparral Resources, Inc.
April 10, 2002
Page 4
In general, proved behind pipe reserves were assigned to sands (in existing
wellbores) with a positive oil test or to sands with a good log signature that
were 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.
In the J-1 sand, probable undeveloped locations were assigned to wells
contained within the area designated as probable oil in place. 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.
The reserves attributed to the waterflood project at the Karakuduk field
were classified as probable undeveloped. Incremental reserves from the
waterflood were estimated at 16.0 percent of original oil in place, in addition
to primary recovery. Waterflood reserves were estimated by fractional flow
analysis based on available rock and fluid data and an estimate of 60.0 percent
volumetric sweep efficiency. Thus, the total primary plus secondary recovery is
estimated at 32.0 percent of original oil in place. The 32.0 percent primary
plus secondary recovery efficiency is based on the assumption of depleting the
reservoir under primary recovery to a pressure near the bubble point such that
recovery under depletion drive is optimized. Based on this assumption, the
waterflood is expected to commence mid 2004.
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 40.8 million stock tank barrels
(MMSTB), and are comprised of the following:
1. Volumes outside three well spacings but inside the currently defined
limits of the field (29.4 MMSTB based on a 32.0 percent primary plus
secondary recovery efficiency).
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 (11.4 MMSTB based on a 32.0 percent primary plus
secondary recovery efficiency).
Additional potential beyond 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 No. 20 showed a zone that is approximately 150 feet thick with a
good log response in the J-13 sand, however, 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
Chaparral Resources, Inc.
April 10, 2002
Page 5
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 Chaparral. As of the time of this report there
were 27 producing wells and 2 shut-in wells (not including shut-in wells with
zero remaining production due to acceleration and/or mechanical problems with
re-entry) with remaining production. 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, 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.
Future incremental rates attributable to the waterflood were estimated to
begin in year 2005. Development costs and injection for the waterflood are
expected to begin in year 2004. The rate profile was based on general waterflood
analogy and cursory fractional flow analysis.
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.
Hydrocarbon Prices
Chaparral furnished us with hydrocarbon prices in effect at December 31,
2001.
In accordance with FASB Statement No. 69, December 31, 2001 market prices
were determined using the daily oil price or daily gas sales price ("spot
price") adjusted for oilfield or gas gathering hub and wellhead price
differences (e.g. grade, transportation, gravity, sulfur and BS&W) as
appropriate. Also in accordance with SEC and FASB specifications, changes in
market prices subsequent to December 31, 2001 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 80.0 percent of their crude production and sell 20.0
percent on the domestic market.
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 with the exception of 2001, where the applied
operating cost includes trade payables as requested by Chaparral. 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.
Development costs 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.
Chaparral Resources, Inc.
April 10, 2002
Page 6
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 187 present our estimated projection of production
and income by years beginning December 31, 2001, by reserve category and well.
The estimates of reserves presented herein are based upon a detailed study
of the properties in which KKM 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, 2001.
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
-----------------------------------
Thomas Wagenhofer
Petroleum Engineer
TW/sw
Approved:
/s/ Dean C Rietz
- -------------------------------
Dean Rietz, P.E.
Vice President - Manager Reservoir Simulation
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Chaparral Resources, Inc.
Estimated
Future Reserves and Income
Attributable to Certain
Leasehold Interests of
Karakuduk-Munay, JSC
SEC Parameters
As of
December 31, 2001
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.