<PAGE>   1

                                                                   EXHIBIT 23-A














                                     CONSENT


                   As independent petroleum and natural gas consultants, we
hereby consent to the filing of this Letter Report dated January 21, 1997 in its
entirety as an Exhibit to the 1996 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 1997; 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 1996 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 21, 1997




<PAGE>   2










                                      January 21, 1997



The Columbia Gas System, Inc.
Suite 300, Sunrise Plaza
12355 Sunrise Valley Drive
Reston, Virginia  20191-3420

          Attention:  Mr. Jeffrey W. Grossman, Vice President and Controller

Arthur Andersen LLP
1345 Avenue of the Americas
New York, New York  10105

          Attention:  Mr. Dave Gorin

Gentlemen:

                   The estimated reserve volumes and future income amounts
presented in this report are related to hydrocarbon prices. December 1996
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 1996 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, 1996 are presented below. Table 1 is a tabulation of the oil,
gas, and natural gas liquid reserves. The Company's reserves are located in the
states of Kentucky, Maryland, Michigan, New York, Ohio, Pennsylvania, Virginia
and West Virginia.
<TABLE>
<CAPTION>

                                                      Proved Net Reserves
                                                    As of December 31, 1996
                                   ---------------------------------------------------------
                                        Liquid, Barrels                   Gas, MMCF
                                   --------------------------     --------------------------
<S>                                         <C>                            <C>
Developed and Undeveloped                   774,073                        644,450


Developed                                   730,323                        518,317
</TABLE>


                   The "Liquid" reserves shown above are comprised of crude oil
and condensate. All hydrocarbon liquid reserves are expressed in standard 42
gallon barrels. All gas volumes are sales gas


<PAGE>   3


The Columbia Gas System, Inc.
Arthur Andersen LLP
January 21, 1997
Page 3




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, 1993, 1994, 1995, and
1996, 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.




<PAGE>   4


The Columbia Gas System, Inc.
Arthur Andersen LLP
January 21, 1997
Page 4




                   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 wells4
                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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The Columbia Gas System, Inc.
Arthur Andersen LLP
January 21, 1997
Page 5




                (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


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The Columbia Gas System, Inc.
Arthur Andersen LLP
January 21, 1997
Page 6




                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, 1996 from this report and as of December 31, 1995 from
our previous report are presented below.
<TABLE>
<CAPTION>

                                                As of December 31
                                                     ($000)
                                 -----------------------------------------------
                                        1996                          1995
                                 ---------------------       ------------------

<S>                                  <C>                           <C>
Future Cash Inflows                  $2,389,131                    $2,256,591

Future Costs
    Production                       $  715,535                    $  711,564
    Development                         165,759                       217,685
                                     ----------                    ----------
        Total Costs                  $  881,294                    $  929,249

Future Net Cash Inflows
    Before Income Tax                $1,507,837                    $1,327,342

Present Value at 10%
    Before Income Tax                $  639,932                    $  706,832
</TABLE>


                   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.


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The Columbia Gas System, Inc.
Arthur Andersen LLP
January 21, 1997
Page 7




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, 1996 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


<PAGE>   8


The Columbia Gas System, Inc.
Arthur Andersen LLP
January 21, 1997
Page 8




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, 1996 and these prices were held constant to depletion of the
properties. In accordance with SEC guidelines, changes in liquid prices
subsequent to December 31, 1996 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 estimates of 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. No attempt has been made to quantify or
otherwise account for any accumulated gas production imbalances that may exist.
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 1996.

                   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.



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The Columbia Gas System, Inc.
Arthur Andersen LLP
January 21, 1997
Page 9




                   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.




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The Columbia Gas System, Inc.
Arthur Andersen LLP
January 21, 1997
Page 10



                   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