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Exhibit 23-A
CONSENT
As independent petroleum and natural gas consultants, we
hereby consent to the filing of this Letter Report dated January 29, 1996 in
its entirety as an Exhibit to the 1995 Annual Report of The Columbia Gas
System, Inc., to the Securities and Exchange Commission on Form 10-K, and any
Registration Statement of The Columbia Gas System, Inc., relating to the issue
of securities to the public during 1996; to the quotation or summarization of
portions of this Letter Report, subject to our approval of the related page(s)
of the document(s), in the 10-K, the Prospectus included in said Registration
Statement(s) or the 1995 annual Report to Stockholders; and, subject to
approval of the related page(s) of the document(s), to the use of our name and
the reliance upon our authority as experts in said Annual Report to
Stockholders, Form 10-K and Prospectus(es) and in Part II of said Registration
Statement(s). We have no interest of a substantial or material nature in The
Columbia Gas System, Inc., or in any affiliate, nor are we to receive any such
interest as payment for the preparation of this Letter Report; we have not been
employed for such preparation on a contingent fee basis; and we are not
connected with The Columbia Gas System, Inc., or any affiliate as a promoter,
underwriter, voting trustee, director, officer, employee, or affiliate.
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
Houston, Texas
January 29, 1996
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EXHIBIT 23-A
January 29, 1996
The Columbia Gas System, Inc.
20 Montchanin Road
Wilmington, Delaware 19807
Attention: Mr. Jeffrey Grossman, Assistant Controller
Arthur Andersen & Company
1345 Avenue of the Americas
New York, New York 10105
Attention: Mr. J. M. Sepanski
Gentlemen:
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 net proved reserves attributable to the
interests of The Columbia Gas System, Inc. (referred to herein as the Company)
as of December 31, 1995 are presented below. Table 1 is a tabulation of the
oil, gas, and natural gas liquid reserves by subsidiary. The Company's
reserves are located in the United States and the Federal Offshore waters.
Proved Net Reserves
As of December 31, 1995
-----------------------------------------
Liquid, Barrels Gas, MMCF
------------------ -------------
Developed and Undeveloped 11,551,735 736,520
Developed 10,568,537 583,274
The "Liquid" reserves shown above are comprised of crude oil,
condensate, and natural gas liquids. Natural gas liquids comprise 11.6 percent
of the Company's developed liquid reserves and 11.0 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 sales gas
expressed in MMCF at the pressure and temperature bases of the area where the
gas reserves are located.
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. 2 together with a tabulation of the components of the
differences in the estimates as of such dates.
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The Columbia Gas System, Inc.
Arthur Andersen & Company
January 29, 1996
Page 2
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
(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
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The Columbia Gas System, Inc.
Arthur Andersen & Company
January 29, 1996
Page 3
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.
As of December 31
($000)
---------------------------------------
1995 1994
--------------- ---------------
Future Cash Inflows $ 2,256,591 $ 1,667,288
Future Costs
Production $ 711,564 $ 492,036
Development 217,685 167,946y
------------ -------------
Total Costs $ 929,249 $ 659,982
Future Net Cash Inflows
Before Income Tax $ 1,327,342 $ 1,007,306
Present Value at 10%
Before Income Tax $ 706,832 $ 549,046
The future cash inflows are gross revenues before any
deductions. The production costs were based on current data and include
production taxes, ad valorem taxes, and certain other items such as
transportation 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.
Table 3 presents a tabulation showing future cash inflow data by subsidiary.
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 lower than December gas prices. For gas sold
under contract, the contract gas price including fixed and determinable
escalations
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The Columbia Gas System, Inc.
Arthur Andersen & Company
January 29, 1996
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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.
Operating costs for the leases and wells in this report are
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. The estimated net cost of
abandonment after salvage was considered for the Appalachia properties and
offshore properties where abandonment costs net of salvage are significant.
The estimates of net abandonment costs furnished by the Company were accepted
without independent verification. Abandonment costs for certain other onshore
properties were not considered because of their relative insignificance.
No deduction was made for indirect costs such as general
administration and overhead expenses, loan repayments, interest expenses, and
exploration and development prepayments. No attempt has been made to quantify
or otherwise account for any accumulated gas production imbalances that may
exist.
In our examination, we made a detailed investigation of
reserves and future production and income for those properties of the Company
which comprise 93.0 percent of the total future net income discounted at 10
percent. Due to the limitations of time and to their relative insignificance,
we accepted without examination and included herein the Company's estimates of
reserves and future production and income for those properties which comprise
the remaining 7.0 percent of total future net income discounted at 10 percent.
No consideration was given in this report to potential environmental
liabilities which may exist nor were any costs included for potential inability
to restore and clean up damages, if any, caused by past operating practices.
The Company informed us that it has furnished us all of the accounts, records,
geological and engineering data and reports and other data required for our
investigation The ownership interests, prices and other factual data were
accepted as represented. Moreover, to facilitate timely issuance of this
report, production data used in this report includes estimated production for
the last few months of 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
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The Columbia Gas System, Inc.
Arthur Andersen & Company
January 29, 1996
Page 5
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
Harry J. Gaston, Jr., P.E.
President
HJG/sw