1
EXHIBIT 99(a)
RYDER SCOTT COMPANY FAX (713) 651-0849
PETROLEUM ENGINEERS
1100 LOUISIANA SUITE 3800 HOUSTON, TEXAS 77002-5218
TELEPHONE (713) 651-9191
January 30, 1995
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 Products Company, and Pennzoil Company
(formerly Proven Properties, Inc.) (collectively referred to herein as the
Company) as of December 31, 1994. In accordance with the requirements of FASB
69, our estimates of the Company's net proved reserves as of December 31, 1991,
1992, 1993, and 1994, 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 Alabama, California,
Louisiana, and Texas. The Company's foreign reserves are located in Canada.
The estimated reserve volumes and future income amounts
presented in this report are related to hydrocarbon prices. December 1994
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 1994 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, 1994 are shown below:
Proved Net Reserves
As of December 31, 1994
-------------------------------------------
Liquid, Barrels Gas, MMCF
--------------------- ---------------
Developed and Undeveloped
United States 204,518,402 1,341,370
Foreign 1,639,361 35,091
----------- ---------
Total Worldwide 206,157,763 1,376,461
Developed
United States 176,074,795 1,242,256
Foreign 1,635,344 31,179
----------- ---------
Total Worldwide 177,710,139 1,273,435
The "Liquid" reserves shown above are comprised of crude oil,
condensate, and natural gas liquids. Natural gas liquids comprise 18 percent
of the Company's developed liquid reserves and 16 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
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January 30, 1995
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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, 1994 do not include 160,678 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, 1994. In addition, the
Company owns 83,819 long tons of sulfur reserves as of December 31, 1994 which
are not shown above; however, the revenue from these sulfur reserves is
included in the cash inflow data in this report.
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
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
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January 30, 1995
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(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, 1994 from this report and as of December 31, 1993 from
our previous report are presented below.
Total Worldwide
As of December 31<F1>
----------------------------------------------
1994 1993
-------------------- --------------------
Future Cash Inflows $5,326,553,844 $5,952,316,500
Future Costs
Production $2,041,184,473 $1,978,446,786
Development 493,685,669 493,541,577
-------------- --------------
Total Costs $2,534,870,142 $2,471,988,363
Future Net Cash Inflows
Before Income Tax $2,791,683,702 $3,480,328,137
Present Value at 10%
Before Income Tax $1,810,037,273 $2,257,766,836
__________________________________
<FN>
<F1> 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.
The cash inflow data for December 31, 1993 include revenues from 161,674 net MMCF of carbon dioxide reserves which have a
future net cash inflow before income tax of $40,598,126 and present value at 10 percent before income tax of $14,445,148.
</FN>
Our estimates as of December 31, 1994 and 1993 of future cash inflows,
future costs, future net cash inflows before income tax, and present value at 10
percent before income tax are
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January 30, 1995
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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 and include the British Columbia Cost of Service Allowance for
certain Canadian properties. 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, and the Alberta Royalty Tax Credit where applicable, in
addition to the operating costs directly applicable to the individual leases or
wells. The development costs were based on current data and include
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, 1994 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, 1994 and these prices were held constant to depletion of the
properties. In accordance with SEC guidelines, changes in liquid prices
subsequent to December 31, 1994 were not considered in this report.
The Alberta Royalty Tax Credit and the British Columbia Cost
of Service Allowance were 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. For properties located
onshore, this study did not consider the salvage value of the lease equipment
or the abandonment cost since both are relatively insignificant and tend to
offset each other. 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 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
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January 30, 1995
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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 1994.
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 Onshore Foreign
Total Worldwide and Offshore Canada
------------------------- ------------------------- -------------------------
1994 1993 1992 1994 1993 1992 1994 1993 1992
------ ------ ------ ------ ------ ------ ------ ------ ------
Net Proved Liquid<F1> Reserves,
Millions of Barrels
- ------------------------------------
Developed and Undeveloped
Beginning of Year 200.9 220.2 139.0 198.9 218.0 136.8 2.0 2.2 2.2
Revisions<F2> 7.9 -7.3 2.3 7.9 -7.3 2.0 Neg Neg 0.3
Extensions and Discoveries 18.0 15.5 7.5 17.9 15.4 7.5 0.1 0.1 Neg
Improved Recovery 0.6 0.0 0.0 0.6 0.0 0 0 0 0
Estimated Production -24.6 -24.3 -14.6 -24.3 -24.0 -14.3 -0.3 -0.3 -0.3
Purchase of Reserves In-Place<F4> 7.6 5.2 92.5 7.6 5.2 92.5 0 0 0
Sales of Reserves In-Place -4.2 -8.4 -6.5 -4.1 -8.4 -6.5 -0.1 Neg 0
----- ----- ----- ----- ----- ----- ---- ---- ----
End of Year 206.2 200.9 220.2 204.5 198.9 218.0 1.7 2.0 2.2
Developed
Beginning of Year 164.2 182.5 110.3 162.3 180.3 108.1 1.9 2.2 2.2
End of Year 177.7 164.2 182.5 176.1 162.3 180.3 1.6 1.9 2.2
Net Proved Gas<F3> Reserves,
Billions of Cubic Feet
- ------------------------------------
Developed and Undeveloped
Beginning of Year 1,491 1,652 926 1,453 1,617 892 38 35 34
Revisions 12 0 9 15 -1 9 -3 1 Neg
Extensions and Discoveries 203 122 80 200 117 78 3 5 2
Improved Recovery Neg 0 0 Neg 0 0 0 0 0
Estimated Production -247 -223 -162 -244 -220 -161 -3 -3 -1
Purchase of Reserves In-Place<F4> 14 91 823 14 91 823 0 0 0
Sales of Reserves In-Place -97 -151 -24 -97 -151 -24 Neg 0 0
----- ----- ---- ----- ----- ----- ---- ---- ----
End of Year 1,376 1,491 1,652 1,341 1,453 1,617 35 38 35
Developed
Beginning of Year 1,341 1,446 837 1,306 1,412 803 35 34 34
End of Year 1,273 1,341 1,446 1,242 1,306 1,412 31 35 34
__________________________________
<FN>
<F1> Liquid reserves shown above are comprised of crude oil, condensate, and
natural gas liquids.
<F2> 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.
<F3> Excludes carbon dioxide reserve and production data.
<F4> Purchase of reserves in place in 1992 for Worldwide and United States
includes 91.9 million barrels, 800 billion cubic feet, and 57,248 long
tons of sulfur attributable to Pennzoil Petroleum Company at October 30,
1992.
</FN>
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TABLE NO. 2
PENNZOIL COMPANY
Cash Inflow and Cost Data <F1>
(millions of U.S. dollars)
United States
Total Worldwide Onshore and Offshore Canada
As of December 31 As of December 31 As of December 31
------------------------------ ----------------------------- -------------------------
1994 1993 1994 1993 1994 1993
------- ------- ------- ------- ------- -------
Future Cash Inflows<F2> $5,327 $5,952 $5,262 $5,868 $65 $84
Future Costs
Production<F3> -$2,041 -$1,978 -$2,031 -$1,971 -$10 -$ 7
Development<F4> -494 -494 -493 -492 -1 -2
------- ------- ------- ------- ---- ----
Total Costs -$2,535 -$2,472 -$2,524 -$2,463 -$11 -$ 9
Future Cash Inflows
Before Income Tax $2,792 $3,480 $2,738 $3,405 $54 $75
Present Value @ 10%
Before Income Tax $1,810 $2,258 $1,777 $2,213 $33 $45
__________________________________
<FN>
<F1> Data for 1994 and 1993 include cash inflows and costs attributable to carbon dioxide reserves located in the United States.
The 1994 carbon dioxide reserves account for $38.8 million of cash inflows before income tax and $14.2 million of present
value at 10% before income tax. The 1993 carbon dioxide reserves account for $40.6 million of future cash inflows before
income tax and $14.4 million of present value at 10% before income tax.
<F2> Gross revenues are before any deductions. Gross revenues include British Columbia Producer Cost of Service Allowance.
<F3> Includes production taxes in the U.S.A., certain foreign taxes where applicable, ad valorem taxes, certain other items such
as transportation and processing charges, and Alberta Royalty Tax Credit where applicable.
<F4> Includes future dismantlement and abandonment costs net of salvage for offshore properties where such costs are relatively
significant.
</FN>