1
[RYDER SCOTT COMPANY LETTERHEAD]
February 7, 1996
Pennzoil Company
Post Office Box 2967
Houston, Texas 77001
Gentlemen:
At your request we have prepared an estimate of the reserves,
future production, and income attributable to certain leasehold and royalty
interests of Pennzoil Company including Pennzoil Exploration and Production
Company, Pennzoil Petroleums, Ltd. (excluding those properties purchased from
Co-enerco Resources Ltd.), Pennzoil Caspian Corporation, Pennzoil Venezuela
Incorporated, Pennzoil Products Company, and Pennzoil Company (formerly Proven
Properties, Inc.) (collectively referred to herein as the Company) as of
December 31, 1995. In accordance with the requirements of FASB 69, our
estimates of the Company's net proved reserves as of December 31, 1992, 1993,
1994, and 1995, as contained in this report and our previous reports, are
presented in attached Table No. 1 together with a tabulation of the components
of the differences in the estimates as of such dates. The Company's reserves
in the United States are located in all the main producing states (except
Alaska), and in state and federal waters offshore California, Louisiana, and
Texas. The Company's foreign reserves are located in Canada, Venezuela, and
Azerbaijan.
The estimated reserve volumes and future income amounts
presented in this report are related to hydrocarbon prices. December 1995
hydrocarbon prices were used in the preparation of this report as required by
Securities and Exchange Commission (SEC) and Financial Accounting Standards
Bulletin No. 69 (FASB 69) guidelines; however, actual future prices may vary
significantly from December 1995 prices. Therefore, volumes of reserves
actually recovered and amounts of income actually received may differ
significantly from the estimated quantities presented in this report. Our
estimates of the proved net reserves attributable to the interests of the
Company as of December 31, 1995 are shown below:
Proved Net Reserves
As of December 31, 1995
-------------------------------------
Liquid, Barrels Gas, MMCF
--------------- ---------
Developed and Undeveloped
United States 174,937,377 1,255,861
Foreign 16,687,189 35,473
----------- ---------
Total Worldwide 191,624,566 1,291,334
Developed
United States 151,245,806 1,131,773
Foreign 1,304,786 29,338
----------- ---------
Total Worldwide 152,550,592 1,161,111
The "Liquid" reserves shown above are comprised of crude oil,
condensate, and natural gas liquids. Natural gas liquids comprise 16 percent
of the Company's developed liquid reserves and
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February 7, 1996
Page 2
14 percent of the Company's developed and undeveloped liquid reserves. All
hydrocarbon liquid reserves are expressed in standard 42 gallon barrels. All
gas volumes are hydrocarbon sales gas expressed in MMCF at the pressure and
temperature bases of the area where the gas reserves are located. Our estimates
of hydrocarbon sales gas reserves as of December 31, 1995 do not include 156,339
MMCF of carbon dioxide which is also sales gas. Revenues from carbon dioxide
sales are included in our estimates of future cash inflows as of December 31,
1995. In addition, the Company owns 83,317 long tons of sulfur reserves as of
December 31, 1995 which are not shown above; however, the revenue from these
sulfur reserves is included in the cash inflow data in this report. Our
estimates of proved net reserves as of December 31, 1995 include 1,154,321
barrels and 4,702 MMCF for Pennzoil Venezuela, Inc. for which Pennzoil has a
contract to develop and produce but does not have actual ownership of the
hydrocarbons.
The proved reserves presented in this report comply with the
SEC's Regulation S-X Part 210.4-10 Sec. (a) as clarified by subsequent
Commission Staff Accounting Bulletins, and are based on the following
definitions and criteria:
Proved reserves of crude oil, condensate, natural gas, and natural
gas liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future
from known reservoirs under existing conditions. Reservoirs are
considered proved if economic producibility is supported by actual
production or formation tests. In certain instances, proved reserves are
assigned on the basis of a combination of core analysis and electrical
and other type logs which indicate the reservoirs are analogous to
reservoirs in the same field which are producing or have demonstrated the
ability to produce on a formation test. The area of a reservoir
considered proved includes (1) that portion delineated by drilling and
defined by fluid contacts, if any, and (2) the adjoining portions not yet
drilled that can be reasonably judged as economically productive on the
basis of available geological and engineering data. In the absence of
data on fluid contacts, the lowest known structural occurrence of
hydrocarbons controls the lower proved limit of the reservoir. Proved
reserves are estimates of hydrocarbons to be recovered from a given date
forward. They may be revised as hydrocarbons are produced and additional
data become available. Proved natural gas reserves are comprised of
non-associated, associated, and dissolved gas. An appropriate reduction
in gas reserves has been made for the expected removal of natural gas
liquids, for lease and plant fuel, and the exclusion of non- hydrocarbon
gases if they occur in significant quantities and are removed prior to
sale. Reserves that can be produced economically through the application
of improved recovery techniques are included in the proved classification
when these qualifications are met: (1) 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, and (2) it is reasonably certain the project will
proceed. Improved recovery includes all methods for supplementing
natural reservoir forces and energy, or otherwise increasing ultimate
recovery from a reservoir, including (1) pressure maintenance, (2)
cycling, and (3) secondary recovery in its original sense. Improved
recovery also includes the enhanced recovery methods of thermal, chemical
flooding, and the use of miscible and immiscible displacement fluids.
Estimates of proved reserves do not include crude oil, natural gas, or
natural gas liquids being held in underground storage. Depending on the
status of development, these proved reserves are further subdivided into:
(i) "developed reserves" which are those proved reserves
reasonably expected to be recovered through existing wells with
existing equipment and operating methods, including (a) "developed
producing reserves" which are those proved developed reserves
reasonably expected to be produced from existing completion
intervals now open for production in
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February 7, 1996
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existing wells, and (b) "developed non-producing reserves" which are
those proved developed reserves which exist behind the casing of
existing wells which are reasonably expected to be produced
through these wells in the predictable future where the cost of
making such hydrocarbons available for production should be
relatively small compared to the cost of a new well; and
(ii) "undeveloped reserves" which are those proved reserves
reasonably expected to be recovered from new wells on undrilled
acreage, from existing wells where a relatively large expenditure
is required, and from acreage for which an application of fluid
injection or other improved recovery technique is contemplated
where the technique has been proved effective by actual tests in
the area in the same reservoir. Reserves from undrilled acreage
are limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved
reserves for other undrilled units are included only where it can
be demonstrated with reasonable certainty that there is continuity
of production from the existing productive formation.
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 and reserves assigned to the
undeveloped portions of secondary or tertiary projects which we have been
assured will definitely be developed.
The Company has interests in certain tracts which have
substantial additional hydrocarbon quantities which cannot be classified as
proved and consequently are not included herein. The Company has active
exploratory and development drilling programs which may result in the
reclassification of significant additional volumes to the proved category.
In accordance with the requirements of FASB 69, our estimates
of future cash inflows, future costs, and future net cash inflows before income
tax as of December 31, 1995 from this report and as of December 31, 1994 from
our previous report are presented below.
Total Worldwide
As of December 31(1)(2)
----------------------------------------
1995 1994
-------------- --------------
Future Cash Inflows $6,569,120,413 $5,326,553,844
Future Costs
Production $1,954,332,406 $2,041,184,473
Development 536,689,322 493,685,669
-------------- --------------
Total Costs $2,491,021,728 $2,534,870,142
Future Net Cash Inflows
Before Income Tax $4,078,098,685 $2,791,683,702
Present Value at 10%
Before Income Tax $2,646,967,469 $1,810,037,273
__________________________________
(1) The cash inflow data for December 31, 1995 include revenues from 156,339 net
MMCF of carbon dioxide reserves which have a future net cash inflow before
income tax of $45,992,640 and present value at 10 percent before income tax of
$18,647,279. The cash inflow data for December 31, 1994 include revenues from
160,678 net MMCF of carbon dioxide reserves which have a future net cash inflow
before income tax of $38,780,628 and present value at 10 percent before income
tax of $14,153,613.
(2) The cash inflow data for December 31, 1995 includes net cash inflow before
income tax of $4,665,490 and present value at 10 percent before income tax of
$3,257,189 attributable to Pennzoil Venezuela, Inc.
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February 7, 1996
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Our estimates as of December 31, 1995 and 1994 of future cash
inflows, future costs, future net cash inflows before income tax, and present
value at 10 percent before income tax are shown individually for total
worldwide, total United States (onshore and offshore), and foreign areas in
Table No. 2 which is attached.
The future cash inflows are gross revenues before any
deductions. The production costs were based on current data and include
production taxes in the United States, certain foreign taxes where applicable,
ad valorem taxes, and certain other items such as transportation and processing
costs, in addition to the operating costs directly applicable to the individual
leases or wells. The development costs were based on current data and include
certain dismantlement and abandonment costs net of salvage for properties where
such costs are relatively significant.
The Company furnished us with gas prices in effect at December
31, 1995 and with its forecasts of future gas prices which take into account
SEC guidelines, current market prices, contract prices, and fixed and
determinable price escalations where applicable. In accordance with SEC
guidelines, the future gas prices used in this report make no allowances for
future gas price increases which may occur as a result of inflation nor do they
account for seasonal variations in gas prices which may cause future yearly
average gas prices to be somewhat different than December gas prices. For gas
sold under contract, the contract gas price including fixed and determinable
escalations exclusive of inflation adjustments, was used until the contract
expires and then was adjusted to the current market price for the area and held
at this adjusted price to depletion of the reserves.
The Company furnished us with liquid prices in effect at
December 31,1995 and these prices were held constant to depletion of the
properties. In accordance with SEC guidelines, changes in liquid prices
subsequent to December 31,1995 were not considered in this report.
The Alberta Royalty Tax Credit and the British Columbia Cost
of Service Allowance were not applied in our estimates of future net income
from the Company's properties in Canada.
Operating costs for the leases and wells in this report were
based on the operating expense reports of the Company and include only those
costs directly applicable to the leases or wells. When applicable, the
operating costs include a portion of general and administrative costs allocated
directly to the leases and wells under terms of operating agreements.
Development costs were furnished to us by the Company and are based on
authorizations for expenditure for the proposed work or actual costs for
similar projects. The current operating and development costs were held
constant throughout the life of the properties. At the request of Pennzoil,
their estimate of zero net abandonment costs after salvage value for onshore
properties was used in this report. Ryder Scott has not performed a detailed
study of the abandonment costs nor the salvage value and makes no warranty for
Pennzoil's estimate. The estimated net cost of abandonment after salvage was
included for offshore properties where abandonment costs net of salvage are
significant. The estimates of the offshore net abandonment costs furnished by
the Company were accepted without independent verification. No deduction was
made for indirect costs such as general administration and overhead expenses,
loan repayments, interest expenses, and exploration and development
prepayments. The Company supplied data on accumulated gas production
imbalances which were taken into account in our estimates of future production
and income.
The estimates of reserves presented herein are based upon a
detailed study of the properties in which the Company owns an interest;
however, we have not made any field examination
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Pennzoil Company
February 7, 1996
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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. The Company 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 factual data furnished by the Company were accepted without
independent verification. The estimates presented in this report are based on
data available through December 1995.
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.
In general, we estimate that future gas production rates will
continue to be the same as the average rate for the latest available 12 months
of actual production until such time that the well or wells are incapable of
producing at this rate. The well or wells were then projected to decline at
their decreasing delivery capacity rate. Our general policy on estimates of
future gas production rates is adjusted when necessary to reflect actual gas
market conditions in specific cases. The future production rates from wells
now on production may be more or less than estimated because of changes in
market demand 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.
While it may reasonably be anticipated that the future prices
received for the sale of production and the operating costs and other costs
relating to such production may also increase or decrease from existing levels,
such changes were, in accordance with rules adopted by the SEC, omitted from
consideration in making this evaluation.
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 cash inflows
for the subject properties.
Very truly yours,
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
/s/ RAYMOND V. CRUCE
-------------------------
Raymond V. Cruce, P.E.
Chairman and CEO
RVC/sw
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TABLE NO. 1
PENNZOIL COMPANY
PROVED NET RESERVE DATA
United States
Total Worldwide Total Onshore and Offshore Foreign(1)
----------------------- -------------------------- --------------------
1995 1994 1993 1995 1994 1993 1995 1994 1993
---- ---- ---- ---- ---- ---- ---- ---- ----
Net Proved Liquid(2) Reserves,
Millions of Barrels
- ----------------------------
Developed and Undeveloped
Beginning of Year 206.2 200.9 220.2 204.5 198.9 218.0 1.7 2.0 2.2
Revisions(3) -14.9 7.9 -7.3 -14.4 7.9 -7.3 -0.5 Neg Neg
Extensions and Discoveries 20.4 18.0 15.5 18.9 17.9 15.4 1.5 0.1 0.1
Improved Recovery 2.7 0.6 0.0 2.7 0.6 0.0 0 0 0
Estimated Production -22.1 -24.6 -24.3 -21.9 -24.3 -24.0 -0.2 -0.3 -0.3
Purchase of Reserves In-Place 22.2 7.6 5.2 8.0 7.6 5.2 14.2 0 0
Sales of Reserves In-Place -22.9 -4.2 -8.4 -22.9 -4.1 -8.4 Neg -0.1 Neg
----- ----- ----- ----- ----- ----- ---- ---- ---
End of Year 191.6 206.2 200.9 174.9 204.5 198.9 16.7 1.7 2.0
Developed
Beginning of Year 177.7 164.2 182.5 176.1 162.3 180.3 1.6 1.9 2.2
End of Year 152.6 177.7 164.2 151.2 176.1 162.3 1.3 1.6 1.9
Net Proved Gas(4) Reserves,
Billions of Cubic Feet
- -------------------------
Developed and Undeveloped
Beginning of Year 1,376 1,491 1,652 1,341 1,453 1,617 35 38 35
Revisions 51 12 0 56 15 -1 -5 -3 1
Extensions and Discoveries 219 203 122 211 200 117 8 3 5
Improved Recovery 1 Neg 0 1 Neg 0 0 0 0
Estimated Production -220 -247 -223 -218 -244 -220 -2 -3 -3
Purchase of Reserves In-Place 26 14 91 26 14 91 0 0 0
Sales of Reserves In-Place -162 -97 -151 -161 -97 -151 -1 Neg 0
----- ----- ----- ----- ----- ----- -- --- --
End of Year 1,291 1,376 1,491 1,256 1,341 1,453 35 35 38
Developed
Beginning of Year 1,273 1,341 1,446 1,242 1,306 1,412 31 35 34
End of Year 1,161 1,273 1,341 1,132 1,242 1,306 29 31 35
__________________________________
(1) 1995 includes 1.2 million barrels and 5 billion cubic feet in Venezuela for
which Pennzoil has a contract to develop and produce but does not have
actual ownership of the hydrocarbons.
(2) Liquid reserves shown above are comprised of crude oil, condensate, and
natural gas liquids.
(3) Revisions in 1993 include a reduction of 13.7 million barrels and 7 billion
cubic feet which is the results of depressed oil and condensate prices on
December 31, 1993.
(4) Excludes carbon dioxide reserve and production data.
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TABLE NO. 2
PENNZOIL COMPANY
CASH INFLOW AND COST DATA(1)
(MILLIONS OF U.S. DOLLARS)
United States
Total Worldwide Onshore and Offshore Foreign
As of December 31 As of December 31 As of December 31
---------------------- ---------------------- ------------------
1995 1994 1995 1994 1995 1994
------ ------- ------ ------ ----- ----
Future Cash Inflows(2) $6,569 $5,327 $6,287 $5,262 $282 $65
Future Costs
Production(3) -$1,954 -$2,041 -$1,849 -$2,031 -$105 -$10
Development(4) - 537 -494 - 480 -493 57 -1
------- ------- ------- ------ ---- ---
Total Costs -$2,491 -$2,535 -$2,329 -$2,524 -$162 -$11
Future Cash Inflows
Before Income Tax $4,078 $2,792 $3,958 $2,738 $120 $54
Present Value @ 10%
Before Income Tax $2,647 $1,810 $2,587 $1,777 $ 60 $33
__________________________________
(1) Data for 1995 and 1994 include cash inflows and costs attributable to
carbon dioxide reserves located in the United States. The 1995 carbon
dioxide reserves account for $46.0 million of cash inflows before income
tax and $18.6 million of present value at 10% before income tax. The
1994 carbon dioxide reserves account for $38.8 million of future cash
inflows before income tax and $14.2 million of present value at 10%
before income tax.
(2) Gross revenues are before any deductions.
(3) Includes production taxes in the U.S.A., certain foreign taxes where
applicable, ad valorem taxes, and certain other items such as
transportation and processing charges.
(4) Includes future dismantlement and abandonment costs net of salvage for
offshore properties where such costs are relatively significant.