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)
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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.