EXHIBIT (c)(3)

March 9, 2000

Petroglyph Energy, Inc.
1302 North Grand
Hutchinson, Kansas 67501

Attention: Mr. Robert C. Murdock, President

Re: Appraisal
Petroglyph Energy, Inc.
Oil and Gas Interests-All Properties
Constant Prices and Expenses

Gentlemen:

In accordance with your request, we have prepared an appraisal of the interests
owned by Petroglyph Energy, Inc. (Petroglyph) in various properties located in
the states of Texas and Utah. The effective date of the appraisal is January 1,
2000, and the results are summarized as follows:

ESTIMATED REMAINING
NET RESERVES FUTURE NET REVENUE
----------------------------- -----------------------------
RESERVE Oil Gas Present Worth
CLASSIFICATION (Barrels) (MCF) Total Disc.@10%
- -------------- ------------ ------------ ------------ -------------

Proved Developed
Producing 1,784,400 4,964,306 $ 25,711,630 $ 16,996,020
Behind Pipe 2,353,932 6,102,745 45,137,510 16,579,550
Non-Producing Secondary 6,235,659 13,074,730 135,807,700 76,652,670
------------ ------------ ------------ ------------

Total Proved Developed 10,373,991 24,141,781 $206,656,840 $110,228,240

Proved Undeveloped
Primary 0 2,262,363 $ 3,446,076 $ 1,713,594
Secondary 1,717,487 3,612,688 36,085,200 18,750,050
Primary and Secondary 6,397,224 13,415,380 100,195,500 20,590,870
------------ ------------ ------------ ------------

Total Proved Undeveloped 8,114,711 19,290,431 $139,726,776 $ 41,054,514

TOTAL ALL RESERVES 18,488,702 43,432,212 $346,383,616 $151,282,754

Note: Totals may not agree due to computer roundoff.

Future net revenue is the amount, exclusive of state and federal income taxes,
which will accrue to the appraised interests from continued operation of the
properties to depletion. It should not be construed as a fair market or trading
value. No provision has been made for the cost of plugging and abandoning the
properties or for the value of salvable equipment.

Summary forecasts of annual gross and net production, severance and ad valorem
taxes, operating income, and net revenue by reserve type are included in
Schedule No. 1, Volume I. Also presented in Schedule No. 1 are present worth
determinations at ten discount rates, ranging from 10 to 100 per cent and plots
showing the historical and projected performance for each category. Schedule No.
2, Volume I reflects summary forecasts and performance plots for the individual
fields by reserve category. Schedule No. 3, Volume I is an alphabetical listing
by lease name for each field. Schedule No. 4, Volume I is a sequential listing
of the individual properties based on discounted future net revenue for the
various reserve categories. The determination of future net revenue by reserve
category for the individual leases is reflected on Schedule Nos. 5 through 9 of
Volume I and Schedule Nos. 1 through 4 of Volume II. The interests shown on the
various schedules are the interests owned as of the effective date. Changes
provided for in various contracts have been taken into consideration in our
calculations.

The appraised properties are grouped into five areas, Antelope Creek and
Duchesne Fields, Duchesne County, Utah, Natural Buttes Field, Uinta County, Utah
and the Texas properties located in Dewitt and Victoria Counties. Antelope Creek
is the major field having over 83 per cent of the proved developed producing and
97 per cent of the proved undeveloped reserves in terms of barrels of oil
equivalent. Petroglyph is the operator of all the evaluated properties with the
exception of several of the Texas properties.

The Antelope Creek Unit in the Antelope Creek Field is not fully developed.
Development plans included in this evaluation are based upon the information
currently available from Petroglyph. Petroglyph may make some revisions as more
wells are drilled and additional geologic information regarding the extent of
the producing areas and the quality of the pay section becomes available. Such
changes may affect our estimates of reserves and projections.

ANTELOPE CREEK UNIT

Petroglyph currently owns a 100 per cent working interest in the Antelope Creek
Unit, which comprises approximately 16,000 gross acres. The unit has been
developed on 40-acre spacing and includes approximately 87 full-time and 27
part-time producing wells, 4 wells waiting on completion and 37 injection wells
at the time of this evaluation.

Oil production, which is obtained from various intervals of the Green River
formation, has been established on approximately 5,500 acres of the Unit. The
produced oil has an API gravity of 31 degrees with a high paraffin content,
giving it a viscosity of 2.9 centipoise at initial reservoir conditions and a
pour point at surface conditions of greater than 100 degrees F. Consequently,
certain special surface facilities are necessary to produce this crude oil.

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Oil production in the Unit area commenced in 1983. A cumulative volume of
approximately 3.2 million barrels of oil and 10.3 BCF of gas has been recovered
to December 1, 1999. The wells produced an average of 952 barrels of oil and 743
MCF of gas per day during the month of November 1999. In addition, the wells
produced a daily average of 1,349 barrels of water.

The Green River formation, which is encountered between depths of 4,000 and
6,000 feet, includes multiple sandstone zones ranging in thickness from 4 to 25
feet. Typical wells produce from two to nine zones in the Antelope Creek Unit.
Average porosity of the zones of interest is 14 per cent with an average sand
net pay thickness of 75 feet per well. The lower Green River sands in this area
are of similar time and deposition and correlate very well across a large area.

The Antelope Creek Unit is felt to be an analog to several successful secondary
recovery projects in the general area, all of which have been in operation for a
number of years. It is planned to continue to develop the Antelope Creek Unit as
a secondary recovery project. Water is being obtained from three different
sources, namely; produced water, purchased water and water supply wells. A
pipeline bringing water from the East Duchesne Water District was completed in
August, 1997. Seven water supply wells, capable of producing 7,000 barrels of
water per day from a shallow aquifer and a commitment from East Duchesne Water
District for 10,000 barrels of water per day are currently providing the
necessary injection volumes.

The expanded injection program, initiated in mid-1997, has demonstrated response
in several areas of the field. Producing wells in Sections 18, 19, 21 and 28,
have recently displayed the initial phases of the anticipated response profile
as a result of the injection in these areas.

CLASSIFICATION OF RESERVES

Reserves attributed to the appraised leases have been classified "proved
developed producing," "proved developed behind-pipe," "proved developed
non-producing secondary," "proved undeveloped primary," and "proved undeveloped
secondary."

Proved Developed Producing Reserves in the Antelope Creek Unit and Duchesne
Field are those reserves expected to be recovered from currently producing zones
under continuation of present operating methods. These reserves include some
secondary reserves in areas where initial response is currently evident.

Proved Developed Behind-Pipe Reserves in the Antelope Creek Unit are those
reserves expected to be recovered from zones currently behind-pipe in existing
wells. These zones are considered proven by virtue of successful testing or
production in offsetting wells. These reserves include both primary and
secondary reserves.

Proved Developed Non-Producing Secondary Reserves in the Antelope Creek Unit are
those secondary reserves expected to be recovered from producing wells
immediately offsetting injection wells. These reserves are in addition to any
secondary reserves currently projected in the proved producing reserve
forecasts.

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Proved Undeveloped Primary Reserves in the Natural Buttes Field are those
reserves attributable to wells to be drilled at locations which can be
considered proved by virtue of favorable structural position and which can be
anticipated with a high degree of certainty.

Proved Undeveloped Secondary Reserves in the Antelope Creek Unit have been
estimated for wells in developed areas that are more than one location away from
active injection wells. These reserves are attributable to the pressure
maintenance project currently being developed. The reserves are considered
proved by virtue of successful pilot projects, successful projects involving the
zones in the vicinity and the initial response noted in certain areas of the
unit.

ESTIMATION OF RESERVES

Proved Developed Producing Reserves

Antelope Creek Unit, Duchesne Field and Texas Properties

The majority of the existing wells have been producing for a considerable length
of time, and their production exhibits well-established decline trends. Oil and
gas reserves attributable to these wells were based upon extrapolation of these
trends to economic limits. Gas reserves were reduced by eleven per cent to
account for lease use and compression in the Antelope Creek Unit.

Reserves anticipated from new wells in the Antelope Creek Unit have been based
upon analogy with similar wells, which are producing from the same horizons in
the respective areas. Structural position, net pay thickness, well productivity,
gas-oil ratios, water production, pressures, and other pertinent factors were
considered in the estimations of these reserves.

Reserves anticipated from wells responding to injection in the Antelope Creek
Unit have been based upon a flattening of the production rate followed by a
return to the established field decline to the economic limit. Any additional
secondary reserves projected for future response have been classified as proved
developed non-producing secondary.

Proved Developed Behind-Pipe Reserves

Antelope Creek Unit

Two groups of behind-pipe reserves have been assigned. The first group includes
behind-pipe Green River reserves in four wells drilled and waiting on
completion. The second group consists of behind-pipe Green River reserves in 98
active producing wells.

Estimated reserves have been based on an analysis of the producing Green River
completions. This analysis related the projected ultimate primary recovery to
the completed Green River porosity-feet for each producing well. Based on this
relationship, the anticipated behind-pipe primary reserves were estimated for
the porosity-feet behind-pipe in the 98 producing wells, 24 injection wells and
the four wells waiting on completion.

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Behind-pipe reserves have been limited to the porosity-feet in each well
considered floodable by correlation to offset injection wells. These reserves
include the anticipated secondary reserves, which have been based on a secondary
to primary recovery ratio of 1:1.

Natural Buttes Field

Behind-pipe reserves have been assigned to one well drilled and waiting on
pipeline hook-up and fracture treatment. Reserves have been based upon analogy
to other wells in the area producing from the Wasatch formation and volumetric
determinations considering net pay thickness, porosity, water saturation,
drainage area and other pertinent factors.

Texas Properties

Behind-pipe reserves have been assigned to three wells in Texas.

Proved Developed Non-Producing Secondary Reserves

Antelope Creek Field

Proved developed non-producing secondary reserves have been assigned to the
producing wells that offset active injection wells, which have not responded to
date. These reserves were based on a secondary to primary oil recovery ratio,
which was obtained from a study of other Green River secondary projects in the
area.

In certain areas of the Antelope Creek Field, the initial production response
from water injection has influenced the proved developed producing reserves. For
these wells, estimates of the ultimate primary recovery were compared to the
proved developed producing ultimate recovery. Adjustments were made to the
non-producing secondary reserves to account for the portion of ultimate
secondary recovery currently included in the proved developed producing
reserves.

Proved Undeveloped Primary Reserves

Natural Buttes Field

Proved undeveloped reserves have been assigned to wells to be drilled at two
locations in the Natural Buttes Field to the Wasatch formation which is
encountered at depths of over 6,500 feet. Anticipated recovery is estimated to
be 1.1 BCF of gas per location. Direct offsets have produced over 1 BCF of gas
per well and reserves have been based upon analogy to these offsetting wells.

Proved Undeveloped Secondary Reserves

Antelope Creek Field

Undeveloped secondary reserves attributable to the current development were
estimated on an individual well basis by applying a secondary to primary ratio
to the average primary recovery of the respective well. The secondary to primary
well recovery ratio was

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obtained from a study of other Green River secondary recovery projects in the
area. Consideration was also given to the production response from limited water
injection in the Antelope Creek Field, as well as the continuity of the Green
River reservoir in the respective areas.

Proved Undeveloped Primary and Secondary Reserves

Undeveloped primary and secondary reserves were assigned to eighty-three 40-acre
locations considered proved by virtue of having at least two offsetting wells.
Reserves were assigned to these locations by using the average primary recovery
of the offsetting wells and the anticipated secondary-to-primary ratio.

FUTURE NET REVENUE

Oil Income

Income from the sale of oil was estimated using the following oil prices
provided by the staff of Petroglyph:

FIELD $/BARREL
----- --------

Antelope Creek 19.95 to January, 2001
Antelope Creek 25.60 thereafter
Duchesne Same as Antelope Creek
Natural Buttes --
Texas Properties 24.33

This price was held constant throughout the life of each lease. Provisions were
made for state severance and ad valorem taxes.

Gas Income

Income from the sale of gas was based upon the following gas prices provided by
the staff of Petroglyph:

FIELD $/MCF
----- -----

Antelope Creek 2.04 to January 2001
Antelope Creek 1.95 thereafter
Duchesne Same as Antelope Creek
Natural Buttes Same as Antelope Creek
Texas Properties 2.30

These prices were held constant throughout the life of each lease. Adjustments
were made for state severance and ad valorem taxes.

Lease Operating Expenses

Operating expenses were based upon actual operating costs, which were supplied
by the staff of Petroglyph. These costs have been reduced to account for the
portion of COPAS overhead paid by other working interest owners.

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Lease operating expenses have been forecast on an individual well basis for the
life of the producing reserves. Expenses for the various categories of
non-producing reserves begin following the producing life of the respective
well.

No escalations were applied to any of the estimated lease operating expenses.

Future Expenses

Future expenses projected for the completion of the behind-pipe reserves include
the perforating and stimulation costs. These expenses have been based on
information provided by Petroglyph and supported by historical cost comparisons
on a porosity-foot basis.

Future expenses projected for the development of the undeveloped reserves
include drilling and completion costs, infrastructure and pipeline costs and
injection well conversion costs. These expenses have been based upon information
provided by Petroglyph and supported with historical cost comparisons from the
wells drilled to date.

These estimated future expenses have been held constant throughout the life of
the field.

GENERAL

Information upon which this appraisal has been based was furnished by the staff
of Petroglyph or was obtained by us from outside sources we consider to be
reliable. This information is assumed to be correct. No attempt has been made to
verify title or ownership of the appraised properties.

Leases were not inspected by a representative of this firm, nor were the wells
tested under our supervision; however, the performance of the majority of the
wells was discussed with employees of Petroglyph.

This report has been prepared utilizing methods and procedures regularly used by
petroleum engineers to estimate oil and gas reserves for properties of this type
and character. The recovery of oil and gas reserves and projection of producing
rates are dependent upon many variable factors including prudent operation,
compression of gas when needed, market demand, installation of lifting
equipment, and remedial work when required. The reserves included in this report
have been based upon the assumption that the wells will be operated in a prudent
manner and that the waterflood expansion will proceed as projected. Actual
production results and future well data may yield additional facts, not
presently available to us, which will require an adjustment to our estimates.

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. As in all aspects of oil and
gas evaluation, there are uncertainties inherent in the interpretation of
engineering data and, therefore, our conclusions necessarily represent only
informed professional judgments.

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Graphs showing past production and estimated future performance of the
individual properties precede the respective cash flow projections. Estimates of
future performance shown on the graphs were made prior to the economic
determinations. These forecasts may extend beyond the calculated economic limits
reflected by the cash flow projections.

No attempt has been made to quantify or otherwise account for any accumulative
gas production imbalances that may exist. Neither has an attempt been made to
determine whether the wells and facilities are in compliance with various
governmental regulations, nor have costs been included in the event they are
not.

The projection of cash flow has been made assuming constant prices. There is no
assurance that prices will not vary. For this reason and those stated above, the
future net cash from the sale of production from the appraised properties may
vary from the estimates contained in this report.

The information developed during the course of this investigation, basic data,
maps and worksheets showing recovery determinations are available for inspection
in our office.

This report is to be used only in its entirety. Individual cash projections are
not to be distributed unless accompanied by this letter.

We appreciate this opportunity to be of service to you.

Very truly yours,

/s/ LEE KEELING AND ASSOCIATES, INC.
LEE KEELING AND ASSOCIATES, INC.