CONFORMED COPY

                        SECURITIES AND EXCHANGE COMMISSION
                              Washington, D.C.  20549

- -  ANNUAL REPORT PURSUANT TO SECTION 13 or 15 (d) OF
   THE SECURITIES EXCHANGE ACT OF 1934 
   For the fiscal year ended December 31, 1998

   Commission File Number  0-7246

- -     Transition Report Pursuant to Section 13 or 15(d) of the Securities 
      Exchange Act of 1934 for the transaction period from              
      to               

                        PETROLEUM DEVELOPMENT CORPORATION                     
              (Exact name of registrant as specified in its charter)

          Nevada                                                95-2636730    
(State or other jurisdiction of                         (I.R.S. Employer 
incorporation or organization)                          Identification No.)

103 East Main Street, Bridgeport, West Virginia  26330   
(Address of principal executive offices)     (zip code)     

Registrant's telephone number, including area code           (304) 842-3597  
                                                           
         SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:  NONE
                                         
            SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

          Petroleum Development Corporation Common Stock, $.01 par value
                                 (Title of class)

Indicate by check mark whether the registrant (1) has filed all reports 
required to be filed by Section 13 or 15(d) of the Securities Exchange Act 
of 1934 during the preceding 12 months and (2) has been subject to such  
filing requirements for the past 90 days.  Yes X  No   

Indicate by check mark if disclosure of delinquent filers pursuant to Item 
405 of Regulation S-K is not contained herein, and will be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to 
this Form 10-K.  [  ]

As of March 15, 1999, 15,737,795 shares of the Registrant's Common Stock were
issued and outstanding, and the aggregate market value of such shares held by
non-affiliates of the Registrant on such date was $42,401,823 (based on the 
last traded price of $3.344).

                        DOCUMENTS INCORPORATED BY REFERENCE
Document                                                Form 10-K Part III
Proxy                                                   Items 11 and 12

<PAGE>

                                     PART I

Item 1.  Business

      The Company is a regional independent energy company engaged
primarily in the development, production and marketing of natural gas. The
Company has grown primarily through increased drilling and development
activities, the acquisition and subsequent development of natural gas
producing wells and the expansion of its natural gas marketing activities.
As of December 31, 1998, the Company operated approximately 1,600 wells
located in the Appalachian and Michigan Basins, and had net proved
reserves of 80.8 Bcf of natural gas. The Company's wells currently produce
an aggregate of approximately 27,000 Mcf of natural gas per day, of which
the Company's share is approximately 7,500 Mcf.  

      The majority of the wells operated by the Company are located in the
West Virginia and Pennsylvania portions of the Appalachian Basin. The
Appalachian Basin is characterized by shallow developmental wells, which
generally have provided highly predictable drilling success rates. In
addition, because wells drilled in the Appalachian Basin are closer to the
large demand centers for natural gas in the northeastern United States,
natural gas from this area typically has commanded a price premium
relative to natural gas produced in areas such as the Gulf Coast and
Mid-Continent regions of the United States. In 1997, the Company commenced
drilling in the Antrim shale formation of the Michigan Basin, and, through
December 31, 1998, had drilled 122 wells in this location. In addition to
its drilling activities, the Company purchases natural gas producing
properties.  During 1998, the Company purchased 133 net wells.

      In April 1996, the Company acquired Riley Natural Gas (RNG), an
Appalachian Basin natural gas marketing company, which aggregates and
resells natural gas developed by the Company and other producers. This
acquisition allowed the Company to diversify its operations beyond natural
gas drilling and production.  RNG has established relationships with many
of the small natural gas producers in the Appalachian Basin and has
significant expertise in the natural gas end-user market. In addition, RNG
has extensive experience in the use of hedging strategies, which the
Company utilizes to reduce the financial impact on the Company of changes
in the price of natural gas.

      Since 1984, the Company has sponsored limited partnerships formed to
engage in drilling operations. The Company typically retains a 20%
ownership interest in these drilling limited partnerships. In 1998, the
Company raised $40.9 million through four public drilling partnerships,
making it the sponsor of the largest public oil and gas partnership
program in the United States in that year. The drilling programs have
provided the Company with access to the capital resources necessary to
expand its drilling opportunities and to maintain the infrastructure
necessary to support such activities.

Industry Overview

      Natural gas is the second largest energy source in the United States,
after liquid petroleum. The 22 Tcf of natural gas consumed in 1997
represented approximately 23% of the total energy used in the United
States.  Natural gas is consumed in the United States as follows: 46% by
industrial end-users as feedstock for products such as plastic and
fertilizer or as the energy source for producing products such as glass;
23% and 15% by residential and commercial end-users, respectively, for
uses including heating, cooling and cooking; 13.4% by utilities for the
generation of electricity; and the remainder for transportation purposes.

      The Company believes that the market for natural gas will grow in the
future. The demand for natural gas has increased due to four main factors:

      -  Efficiency.  Relative to other energy sources, natural gas losses
         during transportation from source to destination are slight,
         averaging only about 9% of the natural gas energy.


                                       -2-
<PAGE>
      -  Environmentally favorable.  Natural gas is the cleanest and most
         environmentally safe of the fossil fuels.

      -  Safety.  The delivery of natural gas is among the safest means of
         distributing energy to customers, as the natural gas transmission
         system is fixed and is located underground.

      -  Price.  The deregulation of the natural gas industry and a
         favorable regulatory environment have resulted in end-users'
         ability to purchase natural gas on a competitive basis from a
         greater variety of sources.

The Company believes that the foregoing factors, together with the
increased availability of natural gas as a form of energy for residential,
commercial and industrial uses, should increase the demand for natural gas
as well as create new markets for natural gas.

      As local supplies of natural gas are inadequate to meet demand, the
West Coast and the Northeast import natural gas from producing areas via
interstate natural gas pipelines. The cost of transporting natural gas
from the major producing areas to markets creates a price advantage for
production located closer to the consuming region. Appalachian Basin
natural gas production enjoys two advantageous factors affecting price.
First, the Appalachian Basin is characterized by shallow development gas
wells that generally have provided highly predictable drilling success
rates of 90% to 92%, which permits a more basic approach to drilling based
on the geology unique to the area. Also, the natural gas industry in the
Appalachian Basin benefits from its proximity to the northeastern United
States. 

      In the early 1980's, natural gas companies began exploiting the
northern portion of Michigan's lower peninsula, when certain favorable tax
credits for natural gas development were enacted. The result of such
development was new advances in drilling technology, which made natural
gas drilling in this area profitable even after the expiration of these
tax credits. In Michigan's lower peninsula, there is an abundance of
shallow Antrim gas shale, which should provide significant reserves per
well drilled. Additionally, this area is close to certain end-user
markets, which should provide favorable premiums. With a current
productive area of nearly 2.5 million acres, Michigan is one of the most
active areas for natural gas drilling in the United States.

      During 1998 the Company began to establish a lease position in the
Rocky Mountain producing region.  While the region is believed to hold
substantial undeveloped natural gas resources, it is relatively
undeveloped compared to other producing regions.  Recent additions to
pipeline capacity in the region have made the area more attractive for
development.  Gas from the region will generally sell for less than gas in
the Appalachian and Michigan Basins, but costs of development are expected
to be less.  During 1998, the Company leased 39,500 acres of oil and gas
development rights acres in Utah, and was investigating opportunities in
several other areas.

Business Strategy

      The Company's objective is to expand its natural gas reserves,
production and revenues through a strategy that includes the following key
elements:

      Expand drilling operations.  The Company has had one of the most
active drilling programs in the Northeast in the 1990's and will seek to
continue to build on the experience developed in drilling more than 625
shallow natural gas wells since 1993.  The Company drilled 214 wells in
1998, compared to 168 for the year of 1997.  The Company believes that it
will be able to drill a substantial number of new wells on its current
undeveloped leased properties.  As of December 31, 1998, the Company had


                                       -3-

<PAGE>
62,600 net undeveloped acres in the Michigan Basin, 34,990 net undeveloped
acres in the Appalachian Basin and 39,500 acres in Utah.  As drilling
activity increases, the Company benefits as its fixed costs may be spread
over a larger number of wells.

      Acquire producing properties.  The Company's acquisition efforts are
focused on properties that fit well within existing operations or that
help to build critical mass in areas where the Company is establishing new
operations.  Acquisitions will likely offer economies in management and
administration, and therefore the Company believes that it will be able to
acquire more producing wells without incurring substantial increases in
its costs of operations.

      Pursue geographic expansion.  The Company has a proven ability to
drill and operate shallow natural gas wells successfully. There are a
number of areas outside the Appalachian Basin where drilling and operating
characteristics are similar to those in Appalachia. For example, since
1996, the Company expanded into the Michigan Basin, which permitted the
Company to leverage its expertise developed in the Appalachian Basin
because of the similarities in methods of drilling, depth, equipment and
operations. Moreover, expected reserves and production levels of two to
three times that of Appalachian levels for a similar investment should
more than offset higher expected operating costs. The Company will
continue to evaluate opportunities to expand geographically on an ongoing
basis.

      Reduce risks inherent in natural gas development and marketing.  An
integral part of the Company's strategy has been and will continue to be
to concentrate on shallow development, (rather than exploratory) drilling,
and geographical diversification to reduce risk levels associated with
natural gas and oil production. Development drilling is less risky than
exploratory drilling and is likely to generate cash returns more quickly.
The focus on shallow wells builds on the Company's knowledge and
experience, and also provides greater investment diversification than an
equal investment in a smaller number of deeper and/or more expensive
wells. Geographical diversification can help to offset possible weakness
in the natural gas market or disappointing drilling results in one area.
The Company believes that, as natural gas markets are deregulated,
successful natural gas marketing is essential to profitable operations. To
further this goal, the Company acquired RNG, an experienced Appalachian
Basin natural gas marketer in 1996.  The Company intends to continue to
expand its marketing capacity to keep pace with the changing natural gas
industry.

      Expand strategic relationships.  By managing drilling programs for
itself and other investors, the Company is able to share administrative,
overhead and other costs with its partners, reducing costs for both. The
Company also is able to maintain a larger and more capable geology and
engineering staff than would be possible without partners. Other benefits
from these associations include greater buying power for drilling services
and materials, larger amounts of natural gas available to market, profits
to the Company from drilling and operating wells for partners, and greater
awareness of the Company in the investment community.

Exploration and Development Activities

      The Company's development activities focus on the identification and
drilling of new productive wells and the acquisition of existing producing
wells from other producers.








                                       -4-

<PAGE>
Prospect Generation

      The Company's staff of professional geologists is responsible for
identifying areas with potential for economic production of natural gas.
The Company's team of professional geologists has decades of experience
drilling successful, economically feasible natural gas wells. The
geological team utilizes results from logs and other tools to evaluate
existing wells and to predict the location of attractive new gas reserves.
To further this process, the Company has collected and continues to
collect logs, core data, production information and other raw data
available from state and private agencies, other companies and individuals
actively drilling in the regions being evaluated. From this information
the geologists develop models of the subsurface structures and
stratigraphy that are used to predict areas with above-average prospects
for economic development. 

      On the basis of these models, the geologists instruct the Company's
land department to obtain available natural gas leaseholds in these
prospective areas. These leases are then obtained, if possible, by the
Company's land department or contract landmen under the direction of the
Company's land manager. In most cases, the Company pays a lease bonus and
annual rental payments, converting, upon initiation of production, to a
12.5% royalty on gross production revenue in return for obtaining the
leases. In some instances of particularly attractive properties,
additional overriding royalty payments may be made to third parties or
royalty owners.  As of December 31, 1998, the Company had a total
leasehold inventory of approximately 220,820 gross acres and 214,090 net
acres. See--"Properties--Natural Gas Leases."

Drilling Activities

      When prospects have been identified and leased, the Company develops
these properties by drilling wells.  In 1998, the Company drilled a total
of 214 wells, of which 11 were dry holes.  Typically, the Company will act
as driller-operator for these prospects, entering into contracts with
partnerships, including Company-sponsored partnerships, and other entities
that are interested in exploration or development of the prospects. The
Company generally retains an interest in each well it drills. See
"Financing of Drilling Activities."

      Much of the work associated with drilling, completing and connecting
wells, including drilling, fracturing, logging and pipeline construction,
is performed by subcontractors specializing in those operations, as is
common in the industry. A large part of the material and services used by
the Company in the development process is acquired through competitive
bidding by approved vendors. The Company also directly negotiates rates
and costs for services and supplies when conditions indicate that such an
approach is warranted. As the prices paid to the Company by its investor
partners for the Company's services are frequently fixed before the wells
are drilled or are determined solely on the well depth, the Company is
subject to the risk that prices of goods or services used in the
development process could increase, rendering its contracts with its
investor partners less profitable or unprofitable. In addition, problems
encountered in the process can substantially increase development costs,
sometimes without recourse for the Company to recover its costs from its
partners. To minimize these risks, the Company seeks to lock in its
development costs in advance of drilling and, when possible, at the time
of negotiation and execution of its investor partnership agreements.
 
Acquisitions of Producing Properties

      In addition to drilling new wells, the Company continues to pursue
opportunities to purchase existing producing wells from other producers
and greater ownership interests in the wells it operates. Generally,
outside interests purchased include a majority interest in the wells and
well operations.


                                       -5-

<PAGE>
 
      In 1996, the Company purchased approximately 188 producing wells from
Angerman Associates, Inc. The wells, located primarily in Gilmer County,
West Virginia, added more than four Bcf of proved producing reserves at
December 31, 1996, in addition to several proved undeveloped locations.
During 1998 the Company purchased an 80% interest in 122 producing wells
located in Pennsylvania from Pemco, and a 100% working interest in 13
producing wells in Michigan, as well as certain well interests in its
Company sponsored partnerships.  These acquistions added 12 Bcf to the
Company's reserves at December 31, 1998.  

Production

      The following table shows the Company's net production in Bbls of
crude oil and in Mcf of natural gas and the costs and weighted average
selling prices thereof, for the last five years.

<TABLE>
<C>                           <C>        <C>      <C>     <C>       <C>
                                       Year Ended December 31,        
                             1998      1997     1996     1995      1994 

Production(1):
  Oil(MBbls)                    8          9       7       11        11
  Natural Gas (MMcf)        2,453      1,810   1,495    1,336     1,195
  Equivalent MMcfs(2)       2,501      1,864   1,537    1,402     1,261
Average sales price:
  Oil (per Bbl)            $10.61     $16.10  $16.35   $15.80   $14,.41
  Natural gas (per Mcf)     $2.46      $2.88   $3.04    $1.75     $2.01
Average production cost 
  (lifting cost) per
  equivalent Mcf(3)         $0.61      $0.65   $0.63    $0.53     $0.58
- ----------
</TABLE>

(1)   Production as shown in the table is net to the Company and is
      determined by multiplying the gross production volume of properties
      in which the Company has an interest by the percentage of the
      leasehold or other property interest owned by the Company.

(2)   A ratio of energy content of natural gas and oil (six Mcf of natural
      gas equals one barrel of oil) was used to obtain a conversion factor
      to convert oil production into equivalent Mcfs of natural gas.

(3)   Production costs represent oil and gas operating expenses as
      reflected in the financial statements of the Company.

Well Operations

      The Company currently operates approximately 1,422 natural gas wells
in the Appalachian Basin and 129 natural gas wells in the Michigan Basin. 
The Company also operates 50 oil wells in the Appalachian Basin.  The
Company's ownership interest in these wells ranges from 0% to 100%, and,
on average, the Company has an approximate 43% ownership interest in the
wells it operates. Currently these wells produce an aggregate of about
27,000 Mcf of natural gas per day, including the Company's share of 7,500
Mcf per day.

      The Company is paid a monthly operating charge for each well it
operates. The rate is competitive with rates charged by other operators in
the area. The charge covers monthly operating and accounting costs,
insurance and other recurring costs. The Company may also receive
additional compensation for special non-recurring activities, such as
reworks and recompletions.

Transportation

      Natural gas wells are connected by pipelines to natural gas markets.
Over the years, the Company has developed extensive gathering systems in
its areas of operations. The Company also continues to construct new
trunklines as necessary to provide for the marketing of natural gas being
developed from new areas and to enhance or maintain its existing systems.

                                       -6-

<PAGE>
The Company is paid a transportation fee for natural gas that is moved by 
other producers through these pipeline systems. In many cases the Company
has been able to receive higher natural gas prices as a result of its
ability to move natural gas to more attractive markets through this
pipeline system, to the benefit of both the Company and its investor
partners.

      The Company has an Ohio subsidiary, Paramount Natural Gas Company
("PNG"), which commenced operations in October 1992 as a regulated Ohio
distribution utility. As a utility, PNG has been able to connect new
customers, and the Company is able to compete for the natural gas markets
of these customers by transporting natural gas through the PNG system. The
majority of PNG's throughput is attributable to natural gas transported
for the Company and industrial customers for a transportation tariff, with
the balance being sales to residential, commercial and industrial
customers.


I
tem 2. Properties

Drilling Activity

      The following table summarizes the Company's development drilling
activity for the years ended December 31, 1994, 1995, 1996, 1997 and 1998. 
There is no correlation between the number of productive wells completed
during any period and the aggregate reserves attributable to those wells.
The Company's exploratory wells drilled in the past five years consist of
one dry hole (0.19 net) drilled in 1998. 

<TABLE>
      <C>                 <C>     <C>         <C>       <C>      <C>      <C>
                                            Development Wells Drilled           

                            Total            Productive Gas          Dry    
                        Drilled   Net       Drilled    Net     Drilled   Net

      1994                75     13.76        71      13.00       4      .76
      1995                72     13.40        64      11.80       8     1.60
      1996                97     17.44        92      16.46       5      .98
      1997               168     40.72       158      38.00      10     2.72
      1998               214     58.11       203      55.34      11     2.77

           Total         626    143.43       588     134.60      38     8.83
</TABLE>











                                       -7-

<PAGE>
Summary of Productive Wells
 
The table below shows the number of the Company's productive gross and net
wells at December 31, 1998.

<TABLE>
<C>                        <C>             <C>      <C>        <C>
                                            WELLS              
                                   Gas                   Oil       
Location                  Gross            Net    Gross         Net
Michigan                    129          60.50       -          -
Ohio                         16           5.51       5          2.34
Pennsylvania                443         142.60       -          - 
Tennessee                     1           0.71      39         15.81
West Virginia               962         461.90       6          2.58
   Total                  1,551         671.22      50         20.73
</TABLE>

Reserves
 
       All of the Company's oil and natural gas reserves are located in the
United States. The Company's approximate net proved reserves were
estimated by Wright & Company, Inc. independent petroleum engineers
("Wright & Company"), to be 80,819,000 Mcf of natural gas and 29,000 Bbls
of oil at December 31, 1998; 57,243,000 Mcf of natural gas and 45,000 Bbls
of oil at December 31, 1997; and 43,312,000 Mcf of natural gas and 81,000
Bbls of oil at December 31, 1996.

       The Company's approximate net proved developed reserves were
estimated, by Wright & Company to be 64,562,000 Mcf of natural gas and
29,000 Bbls of oil at December 31, 1998; 42,411,000 Mcf of natural gas and
45,000 Bbls of oil at December 31, 1997; and 35,516,000 Mcf of natural gas
and 81,000 Bbls of oil at December 31, 1996.

       No major discovery or other favorable or adverse event that would
cause a significant change in estimated reserves is believed by the
Company to have occurred since December 31, 1998.  Reserves cannot be
measured exactly, as reserve estimates involve subjective judgment. The
estimates must be reviewed periodically and adjusted to reflect additional
information gained from reservoir performance, new geological and
geophysical data and economic changes.
 
       The standardized measure of discounted future net cash flows
attributable to the Company's proved oil and gas reserves, giving effect
to future estimated income tax expenses, was estimated by Wright & Company
in 1998, 1997 and 1996 to be $30.2 million as of December 31, 1998, $27.9
million as of December 31, 1997, and $34.3 million as of December 31,
1996.  These amounts are based on year-end prices at the respective dates. 
The values expressed are estimates only, and may not reflect realizable
values or fair market values of the natural gas and oil ultimately
extracted and recovered. The standardized measure of discounted future net
cash flows may not accurately reflect proceeds of production to be
received in the future from the sale of natural gas and oil currently
owned and does not necessarily reflect the actual costs that would be
incurred to acquire equivalent natural gas and oil reserves.
















                                       -8-

<PAGE>
Net Proved Natural Gas and Oil Reserves

       The proved reserves of natural gas and oil of the Company as
estimated by Wright & Company at December 31, 1998 are set forth below.
These reserves have been prepared in compliance with the rules of the
Securities and Exchange Commission (the "SEC") based on year-end prices.
An analysis of the change in estimated quantities of natural gas and oil
reserves from January 1, 1998 to December 31, 1998, all of which are
located within the United States, is shown below:

<TABLE>
<C>                                                              <C>
                                                       Natural Gas (Mcf)
 
 Proved developed and undeveloped reserves:
 Beginning of year (January 1, 1998)                         57,243,000 
 Revisions of previous estimates                             (3,517,000)
 Beginning of year as revised                                53,726,000 
 New discoveries and extensions                              23,552,000 
 Dispositions, to partnerships                               (6,009,000)
 Acquisitions                                                12,003,000 
 Production                                                  (2,453,000)
 End of period (December 31, 1998)                           80,819,000 
 
 Proved developed reserves:
 Beginning of year (January 1, 1998)                         42,411,000 
 End of period (December 31, 1998)                           64,562,000 

                                                              Oil (Bbls)
Proved developed and undeveloped reserves:
Beginning of year (January 1, 1998)                              45,000 
Revisions of previous estimates                                 (10,000)
Beginning of year as revised                                     35,000 
Dispositions                                                        -   
Acquisitions                                                      2,000 
Production                                                       (8,000)
End of period (December 31, 1998)                                29,000 

Proved developed reserves:
Beginning of year (January 1, 1998)                              45,000 
End of period (December 31, 1998)                                29,000 

</TABLE>

Standardized Measure of Discounted Future Net Cash Flows and Changes
Therein  Relating to Proved Natural Gas and Oil Reserves

       Summarized in the following table is information for the Company
with respect to the standardized measure of discounted future net cash
flows relating to proved natural gas and oil reserves.  Future cash
inflows are computed by applying year-end prices of natural gas and oil 
relating to the Company's proved reserves to year-end quantities of those
reserves.  Future production, development, site restoration and
abandonment costs are derived based on current costs, assuming
continuation of existing economic conditions.  Future income tax expenses
are computed by applying the statutory rate in effect at December 31, 1998
to the future pretax net cash flows, less the tax basis of the properties,
and gives effect to permanent differences, tax credits and allowances
related to the properties.

<TABLE>
<C>                                                              <C>
                                                       December 31, 1998

Future estimated cash flows                                $186,598,000 
Future estimated production and development costs           (95,670,000)
Future estimated income tax expense                         (20,322,000)
Future net cash flows                                        70,606,000 
10% annual discount for estimated 
 timing of cash flows                                       (40,412,000)
Standardized measure of discounted 
 future estimated net cash flows                           $ 30,194,000 
</TABLE>

                                       -9-
<PAGE>
       The following table summarizes the principal sources of change in
the standardized measure of discounted future estimated net cash flows
from January 1, 1998 through December 31, 1998:

<TABLE>
<C>                                                              <C>
 Sales of oil and natural gas production, 
  net of production costs                                  $ (4,605,000)
 Net changes in prices and production costs                 (23,083,000)
 Extensions, discoveries and improved recovery, 
  less related cost                                          18,615,000 
 Dispositions to partnerships                                (5,762,000)
 Acquisitions                                                13,938,000 
 Development costs incurred during the period                14,903,000 
 Revisions of previous quantity estimates                    (5,605,000)
 Changes in estimated income taxes                              459,000 
 Accretion of discount                                        1,224,000 
 Other                                                       (7,826,000)
                                                           $  2,258,000 
</TABLE>

 
       The foregoing data should not be viewed as representing the expected
cash flow from, or current value of, existing proved reserves, as the
computations are based on a large number of estimates and arbitrary
assumptions.  Reserve quantities cannot be measured with precision, and
their estimation requires many judgmental determinations and frequent
revisions.  The required projection of production and related expenditures
over time requires further estimates with respect to pipeline
availability, rates of demand and governmental control. Actual future
prices and costs are likely to be substantially different from the current
prices and costs utilized in the computation of reported amounts. Any
analysis or evaluation of the reported amounts should give specific
recognition to the computational methods and the limitations inherent
therein.

       Substantially all of the Company's natural gas and oil reserves have
been mortgaged or pledged as security for the Company's credit agreement.
See Note 3 of Notes to Consolidated Financial Statements. 

Natural Gas Leases

       The following table sets forth, as of December 31, 1998, the acres
of developed and undeveloped natural gas and oil properties in which the
Company had an interest, listed alphabetically by state.

<TABLE>
          <C>            <C>       <C>         <C>        <C>
                          Developed             Undeveloped
                           Acreage                Acreage    
                        Gross     Net         Gross       Net
       Michigan        19,200   18,400       67,420     62,600
       Ohio               740      740        1,300      1,220
       Pennsylvania     4,460    4,460       18,600     18,470
       Tennessee        5,400    5,400         -          -   
       Utah              -        -          39,500     39,500
       West Virginia   48,900   48,000       15,300     15,300
      Total            78,700   77,000      142,120    137,090
</TABLE>

Title to Properties

       The Company believes that it holds good and indefeasible title to
its properties, in accordance with standards generally accepted in the
natural gas industry, subject to such exceptions stated in the opinion of
counsel employed in the various areas in which the Company conducts its
exploration activities, which exceptions, in the Company's judgment, do
not detract substantially from the use of such property. As is customary
in the natural gas industry, only a perfunctory title examination is
conducted at the time the properties believed to be suitable for drilling
operations are acquired by the Company. Prior to the commencement of
drilling operations, an extensive title examination is conducted and
curative work is performed with respect to defects which the Company deems

                                      -10-
<PAGE>
to be significant. A title examination has been performed with respect to
substantially all of the Company's producing properties. No single
property owned by the Company represents a material portion of the
Company's holdings. The Company's properties are subject to customary
royalty interests, liens incident to operating agreements, liens for
current taxes and other burdens which the Company believes do not
materially interfere with the use of or affect the value of such
properties.

       The properties owned by the Company are subject to royalty,
overriding royalty and other outstanding interests customary in the
industry. The properties are also subject to burdens such as liens
incident to operating agreements, current taxes, development obligations
under natural gas and oil leases, farm-out arrangements and other
encumbrances, easements and restrictions. The Company does not believe
that any of these burdens will materially interfere with the use of the
properties.

Natural Gas Sales

       Natural gas is sold by the Company under contracts with terms
ranging from one month to three years.  Virtually all of the Company's
contract pricing provisions are tied to a market index, with certain
adjustments based on, among other factors, whether a well delivers to a
gathering or transmission line, quality of natural gas and prevailing
supply and demand conditions, so that the price of the natural gas
fluctuates to remain competitive with other available natural gas
supplies.  As a result, the Company's revenues from the sale of natural
gas will suffer if market prices decline and benefit if they increase. The
Company believes that the pricing provisions of its natural gas contracts
are customary in the industry.

       The Company sells its natural gas to industrial end-users and
utilities. One customer, Hope Gas, Inc., a regulated public utility ("Hope
Gas"), accounted for 12.6% of the Company's revenues from oil and gas
sales (5.4% of total revenues) in 1998; 26.6% of the Company's revenues
from oil and gas sales (12.0% of total revenues) in 1997 and 30.7% of the
Company's revenues from oil and gas sales (16.1% of total revenues) in
1996.  The Company and Hope Gas are parties to a Pipeline Purchase
Agreement, which expires on May 31, 1999, pursuant to which agreement the
Company must deliver to Hope Gas, upon demand, minimum quantities of
natural gas (4,500 dth per day delivered directly to Hope Gas's pipelines
and 11,000 dth per day for total deliveries including both direct and
transferred volumes). The Company and Hope Gas are also parties to a
Master Gas Purchase Agreement, which expires on May 31, 1999, pursuant to
which the Company must offer to Hope Gas all volumes of natural gas
available at specific points of delivery, up to the minimum delivery
requirements of the Pipeline Purchase Agreement. No other single purchaser
of the Company's natural gas accounted for 10% or more of the Company's
total revenues during 1998, 1997 or 1996. 

       At December 31, 1998, natural gas produced by the Company sold at
prices per Mcf ranging from $0.90 to $3.28, depending upon well location,
the date of the sales contract and whether the natural gas was sold in
interstate or intrastate commerce.  The weighted net average price of
natural gas sold by the Company during 1998 was $2.46 per Mcf.

       In general, the Company, together with its marketing subsidiary,
RNG, has been and expects to continue to be able to produce and sell
natural gas from its wells without curtailment by providing natural gas to
purchasers at competitive prices. Open access transportation on the
country's interstate pipeline system has greatly increased the range of
potential markets. Whenever feasible the Company allows for multiple
market possibilities from each of its gathering systems, while seeking the
best available market for its natural gas at any point in time. 



                                      -11-

<PAGE>
Natural Gas Marketing

       The Company's natural gas marketing activities involve the
aggregation and reselling of natural gas produced by the Company and
others. The Company believes that, as natural gas markets are deregulated,
successful natural gas marketing is essential to profitable operations. A
variety of factors affect the market for natural gas, including the
availability of other domestic production, natural gas imports, the
availability and price of alterative fuels, the proximity and capacity of
natural gas pipelines, general fluctuations in the supply and demand for
natural gas and the effects of state and federal regulations on natural
gas production and sales. The natural gas industry also competes with
other industries in supplying the energy and fuel requirements of
industrial, commercial and individual customers.

       In 1996, the Company acquired RNG, an Appalachian Basin natural gas
marketing company that specializes in the acquisition and aggregation of
Appalachian Basin gas production. The owner/managers and employees of RNG
joined the Company, and RNG's operations were relocated to the Company's
headquarters. RNG markets natural gas produced by the Company and also
purchases natural gas from other producers and resells to utilities, end
users or other marketers. The employees of RNG have extensive knowledge of
the natural gas market in the Appalachian region. Such knowledge should
assist the Company in maximizing its prices as it markets natural gas from
Company-operated wells. RNG and its management also bring to the Company
specific knowledge and relationships with many producers in the
Appalachian Basin region. Paramount Transmission Corporation ("PTC"), an
Ohio subsidiary of the Company, focuses its efforts on the marketing of
Ohio natural gas production to commercial and industrial end-users.

       In West Virginia, Pennsylvania and Michigan, the Company markets
natural gas from its own wells and wells operated for its investment
partnerships.  The gas is marketed to natural gas utilities, pipelines and
industrial and commercial customers, either directly through the Company's
gathering system, or utilizing transportation services provided by
regulated interstate pipeline companies.

Hedging Activities

       The Company utilizes commodity-based derivative instruments as
hedges to manage a portion of its exposure to price volatility stemming
from its natural gas sales and marketing activities.  These instruments
consist of NYMEX-traded natural gas futures and option contracts.  The
contracts hedge committed and anticipated natural gas purchases and sales,
generally forecasted to occur within a three- to twelve-month period.
Company policy prohibits the use of natural gas futures or options for
speculative purposes and permits utilization of hedges only if there is an
underlying physical position.

       The Company has extensive experience with the use of financial
hedges to reduce the risk and impact of natural gas price changes. These
hedges are used to coordinate fixed and variable priced purchases and
sales and to "lock in" fixed prices from time to time for the Company's
share of production. In order for future contracts to serve as effective
hedges, there must be sufficient correlation to the underlying hedged
transaction.  While hedging can help provide price protection if spot
prices drop, hedges can also limit upside potential.

       Despite the measures taken by the Company to attempt to control
price risk, the Company remains subject to price fluctuations for natural
gas sold in the spot market. The Company continues to evaluate the
potential for reducing these risks by entering into hedge transactions. In
addition, the Company may also close out any portion of hedges that may
exist from time to time. As of December 31, 1998, there were 73 existing
hedge positions.  Total natural gas purchased and sold under hedging
arrangements during the year ended December 31, 1998 was 2,020,000 MMbtu. 
Under such hedging arrangements, the Company realized a gain of $171,400
for the year ended December 31, 1998.

                                      -12-
<PAGE>
Financing of Drilling Activities

       The Company conducts development drilling activities for its own
account and for other investors. In 1984, the Company began sponsoring
private drilling limited partnerships, and, in 1989, the Company began to
register the partnership interests offered under public drilling programs
with the SEC.  The Company's public partnerships had $40.9 million in
subscriptions in 1998.  Funds received pursuant to drilling contracts were
$35.5 million in 1997 and $25.5 million in 1996.  The Company generally
invests, as its equity contribution to each drilling partnership, an
additional sum approximating 20% of the aggregate subscriptions received
for that particular drilling partnership.  As a result, the Company is
subject to substantial cash commitments at the closing of each drilling
partnership.  The funds received from these programs are restricted to use
in future drilling operations.  While funds were received by the Company
pursuant to drilling contracts in the years indicated, the Company
recognizes revenues from drilling operations on the percentage of
completion method as the wells are drilled, rather than when funds are
received.  Most of the Company's drilling and development funds now are
received from partnerships in which the Company serves as managing general
partner. However, because wells produce for a number of years, the Company
continues to serve as operator for a large number of unaffiliated parties.
In addition to the partnership structure, the Company also utilizes joint
venture arrangements for financing drilling activities.

       The financing process begins when the Company enters into a
development agreement with an investor partner, pursuant to which the
Company agrees to assign its rights in the property to be drilled to the
partnership or other entity. The partnership or other entity thereby
becomes owner of a working interest in the property.

        The Company's development contracts with its investor partners have
historically taken many different forms. Generally the agreements can be
classified as on a "footage-based" rate, whereby the Company receives
drilling and completion payments based on the depth of the well;
"cost-plus," in which the Company is reimbursed for its actual cost of
drilling plus some additional amount for overhead and profit; or
"turnkey," in which a specified amount is paid for drilling and another
amount for completion. As part of the compensation for its services, the
Company also has received some interest in the production from the well in
the form of an overriding royalty interest, working interest or other
proportionate share of revenue or profits. Often the Company's development
contracts provide for a combination of several of the foregoing payment
options.  Basic drilling and completion operations are performed on a
footage-based rate, with leases and gathering pipelines being contributed
at Company cost. The Company also purchases a working interest in the
subject properties.

       The level of the Company's drilling and development activity is
dependent upon the amount of subscriptions in its public drilling
partnerships and investments from other partnerships or other joint
venture partners. The use of partnerships and similar financing structures
enables the Company to diversify its holdings, thereby reducing the risks
to its development investments. Additionally, the Company benefits through
such arrangements by its receipt of fees for its management services
and/or through an increased share in the revenues produced by the
developed properties.  The Company believes that investments in drilling
activities, whether through Company-sponsored partnerships or other
sources, are influenced in part by the favorable treatment that such
investments enjoy under the federal income tax laws. No assurance can be
given that the Company will continue to have access to funds generated
through these financing vehicles.






                                      -13-

<PAGE>
Oil Production
 
       Before 1980, the Company generated a significant portion of its
revenues from oil production. However, the Company made a strategic
decision to concentrate its development efforts on natural gas production
and most of the Company's current oil production is associated with
natural gas production. The Company does not believe its current
production of oil, from wells located in Tennessee, Ohio and West
Virginia, to be material, as its share of oil production has declined to
about 8,000 barrels per year. The Company is currently able to sell all
the oil that it can produce under existing sales contracts with petroleum
refiners and marketers. The Company does not refine any of its oil
production. The Company's crude oil production is sold to purchasers at or
near the Company's wells under short-term purchase contracts at prices and
in accordance with arrangements which are customary in the oil industry.
No single purchaser of the Company's crude oil accounted for 10% or more
of the Company's revenues from oil and gas sales in 1998, 1997 or 1996. At
December 31, 1998, oil produced by the Company sold at prices ranging from
$8.25 to $9.25 per barrel, depending upon the location and quality of oil. 
In 1998, the weighted net average price per barrel of oil sold by the
Company was $10.61.

       Oil production is subject to many of the same operating hazards and
environmental concerns as natural gas production, but is also subject to
the risk of oil spills. Federal regulations require certain owners or
operators of facilities that store or otherwise handle oil, such as the
Company, to procure and implement spill prevention, control, counter-
measures and response plans relating to the possible discharge of oil into
surface waters. The Oil Pollution Act of 1990 ("OPA") subjects owners of
facilities to strict joint and several liability for all containment and
cleanup costs and certain other damages arising from oil spills.
Noncompliance with OPA may result in varying civil and criminal penalties
and liabilities. Operations of the Company are also subject to the Federal
Clean Water Act and analogous state laws relating to the control of water
pollution, which laws provide varying civil and criminal penalties and
liabilities for release of petroleum or its derivatives into surface
waters or into the ground.

Governmental Regulation

       The Company's business and the natural gas industry in general are
heavily regulated. The availability of a ready market for natural gas
production depends on several factors beyond the Company's control. These
factors include regulation of natural gas production, federal and state
regulations governing environmental quality and pollution control, the
amount of natural gas available for sale, the availability of adequate
pipeline and other transportation and processing facilities and the
marketing of competitive fuels. State and federal regulations generally
are intended to prevent waste of natural gas, protect rights to produce
natural gas between owners in a common reservoir and control contamination
of the environment.  Pipelines are subject to the jurisdiction of various
federal, state and local agencies.  The Company takes the steps necessary
to comply with applicable regulations both on its own behalf and as part
of the services it provides to its investor partnerships. The Company
believes that it is in substantial compliance with such statutes, rules,
regulations and governmental orders, although there can be no assurance
that this is or will remain the case. The following discussion of the
regulation of the United States natural gas industry is not intended to
constitute a complete discussion of the various statutes, rules,
regulations and environmental orders to which the Company's operations may
be subject.







                                      -14-

<PAGE>
Regulation of Natural Gas Exploration and Production

       The Company's natural gas operations are subject to various types of
regulation at the federal, state and local levels. Prior to commencing
drilling activities for a well, the Company must procure permits and/or
approvals for the various stages of the drilling process from the
applicable state and local agencies in the state in which the area to be
drilled is located. Such permits and approvals include those for the
drilling of wells, and such regulation includes maintaining bonding
requirements in order to drill or operate wells and regulating the
location of wells, the method of drilling and casing wells, the surface
use and restoration of properties on which wells are drilled, the plugging
and abandoning of wells and the disposal of fluids used in connection with
operations. The Company's operations are also subject to various
conservation laws and regulations. These include the regulation of the
size of drilling and spacing units or proration units and the density of
wells, which may be drilled and the unitization or pooling of natural gas
properties. In this regard, some states allow the forced pooling or
integration of tracts to facilitate exploration while other states rely
primarily or exclusively on voluntary pooling of lands and leases. In
areas where pooling is voluntary, it may be more difficult to form units,
and therefore, more difficult to develop a project if the operator owns
less than 100% of the leasehold.  In addition, state conservation laws
establish maximum rates of production from natural gas wells, generally
prohibit the venting or flaring of natural gas and impose certain
requirements regarding the ratability of production. The effect of these
regulations may limit the amount of natural gas the Company can produce
from its wells and may limit the number of wells or the locations at which
the Company can drill. The regulatory burden on the natural gas industry
increases the Company's costs of doing business and, consequently, affects
its  profitability.  In as much as such laws and regulations are
frequently expanded, amended and reinterpreted, the Company is unable to
predict the future cost or impact of complying with such regulations.

Regulation of Sales and Transportation of Natural Gas

       Historically, the transportation and sale for resale of natural gas
in interstate commerce have been regulated pursuant to the Natural Gas Act
of 1938, the Natural Gas Policy Act of 1978 (the "NGPA") and the
regulations promulgated thereunder by FERC. Maximum selling prices of
certain categories of natural gas sold in "first sales," whether sold in
interstate or intrastate commerce, were regulated pursuant to the NGPA.
The Natural Gas Wellhead Decontrol Act (the "Decontrol Act") removed, as
of January 1, 1993, all remaining federal price controls from natural gas
sold in "first sales" on or after that date. FERC's jurisdiction over
natural gas transportation was unaffected by the Decontrol Act. While
sales by producers of natural gas and all sales of crude oil, condensate
and natural gas liquids can currently be made at market prices, Congress
could reenact price controls in the future.

       The Company's sales of natural gas are affected by the availability,
terms and cost of transportation. The price and terms for access to
pipeline transportation are subject to extensive regulation. In recent
years, FERC has undertaken various initiatives to increase competition
within the natural gas industry. As a result of initiatives like FERC
Order No.636, issued in April 1992, the interstate natural gas
transportation and marketing system has been substantially restructured to
remove various barriers and practices that historically limited
non-pipeline natural gas sellers, including producers, from effectively
competing with interstate pipelines for sales to local distribution
companies and large industrial and commercial customers. The most
significant provisions of Order No.636 require that interstate pipelines
provide transportation separate or "unbundled" from their sales service,
and require that pipelines provide firm and interruptible transportation
service on an open access basis that is equal for all natural gas
suppliers. In many instances, the result of Order No.636 and related
initiatives have been to substantially reduce or eliminate the interstate

                                      -15-

<PAGE>
pipelines' traditional role as wholesalers of natural gas in favor of
providing only storage and transportation services. Another effect of
regulatory restructuring is the greater transportation access available on
interstate pipelines. In some cases, producers and marketers have
benefitted from this availability. However, competition among suppliers
has greatly increased and traditional long-term producer-pipeline
contracts are rare. Furthermore, gathering facilities of interstate
pipelines are no longer regulated by FERC, thus allowing gatherers to
charge higher gathering rates.

       Additional proposals and proceedings that might affect the natural
gas industry are pending before Congress, FERC, state commissions and the
courts.  The natural gas industry historically has been very heavily
regulated; therefore, there is no assurance that the less stringent
regulatory approach recently pursued by FERC and Congress will continue.
The Company cannot determine to what extent future operations and earnings
of the Company will be affected by new legislation, new regulations, or
changes in existing regulation, at federal, state or local levels.

Environmental Regulations

       The Company's operations are subject to numerous laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. Public interest in the
protection of the environment has increased dramatically in recent years.
The trend of more expansive and stricter environmental legislation and
regulations could continue. To the extent laws are enacted or other
governmental action is taken that restricts drilling or imposes
environmental protection requirements that result in increased costs to
the natural gas industry in general, the business and prospects of the
Company could he adversely affected.

       The Company generates wastes that may be subject to the Federal
Resource Conservation and Recovery Act ("RCRA") and comparable state
statutes. The U.S. Environmental Protection Agency ("EPA") and various
state agencies have limited the approved methods of disposal for certain
hazardous and nonhazardous wastes.  Furthermore, certain wastes generated
by the Company's operations that are currently exempt from treatment as
"hazardous wastes" may in the future be designated as "hazardous wastes,"
and therefore be subject to more rigorous and costly operating and
disposal requirements.

       The Company currently owns or leases numerous properties that for
many years have been used for the exploration and production of oil and
natural gas. Although the Company believes that it has utilized good
operating and waste disposal practices, prior owners and operators of
these properties may not have utilized similar practices, and hydrocarbons
or other wastes may have been disposed of or released on or under the
properties owned or leased by the Company or on or under locations where
such wastes have been taken for disposal.  These properties and the wastes
disposed thereon may be subject to the Comprehensive Environmental
Response, Compensation and Liability Act ("CERCLA"), RCRA and analogous
state laws as well as state laws governing the management of oil and
natural gas wastes. Under such laws, the Company could be required to
remove or remediate previously disposed wastes (including wastes disposed
of or released by prior owners or operators) or property contamination
(including groundwater contamination) or to perform remedial plugging
operations to prevent future contamination. 

       CERCLA and similar state laws impose liability, without regard to
fault or the legality of the original conduct, on certain classes of
persons that are considered to have contributed to the release of a
"hazardous substance" into the environment. These persons include the
owner or operator of the disposal site or sites where the release occurred
and companies that disposed of or arranged for the disposal of the
hazardous substances found at the site. Persons who are or were
responsible for release of hazardous substances under CERCLA may be
subject to joint and several liability for the costs of cleaning up the

                                      -16-

<PAGE>
hazardous substances that have been released into the environment and for
damages to natural resources, and it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damage allegedly caused by the hazardous substances released into
the environment.

       The Company's operations may be subject to the Clean Air Act ("CAA")
and comparable state and local requirements. Amendments to the CAA were
adopted in 1990 and contain provisions that may result in the gradual
imposition of certain pollution control requirements with respect to air
emissions from the operations of the Company. The EPA and states have been
developing regulations to implement these requirements. The Company may be
required to incur certain capital expenditures in the next several years
for air pollution control equipment in connection with maintaining or
obtaining operating permits and approvals addressing other air
emission-related issues.

       The Company's expenses relating to preserving the environment during
1998 were not significant in relation to operating costs and the Company
expects no material change in 1999. Environmental regulations have had no
materially adverse effect on the Company's operations to date, but no
assurance can be given that environmental regulations will not, in the
future, result in a curtailment of production or otherwise have a
materially adverse effect on the Company's business, financial condition
or results of operations.

       As a matter of corporate policy and commitment, the Company attempts
to minimize the adverse environmental impact of all its operations. For
example, during 1998, the Company was one of the most active drilling
companies in the northeast. Even with this level of activity, the Company
was able to maintain a high level of environmental sensitivity. During the
1990's, the Company has been a four-time recipient of the West Virginia
Department of Environmental Protection's top award in recognition of the
quality of the Company's environmental and reclamation work in its
drilling activities.

Utility Regulation

       PNG, which is an Ohio public utility, is subject to regulation by
the Public Utilities Commission of Ohio in virtually all of its
activities, including pricing and supply of services, addition of and
abandonment of service to customers, design and construction of
facilities, and safety issues.

Operating Hazards and Insurance

       The Company's exploration and production operations include a
variety of operating risks, including the risk of fire, explosions,
blowouts, craterings, pipe failure, casing collapse, abnormally pressured
formations, and environmental hazards such as gas leaks, ruptures and
discharges of toxic gas, the occurrence of any of which could result in
substantial losses to the Company due to injury and loss of life, severe
damage to and destruction of property, natural resources and equipment,
pollution and other environmental damage, clean-up responsibilities,
regulatory investigation and penalties and suspension of operations. The
Company's pipeline, gathering and distribution operations are subject to
the many hazards inherent in the natural gas industry.  These hazards
include damage to wells, pipelines and other related equipment, and
surrounding properties caused by hurricanes, floods, fires and other acts
of God, inadvertent damage from construction equipment, leakage of natural
gas and other hydrocarbons, fires and explosions and other hazards that
could also result in personal injury and loss of life, pollution and
suspension of operations.





                                      -17-

<PAGE>
 
       Any significant problems related to its facilities could adversely
affect the Company's ability to conduct its operations. In accordance with
customary industry practice, the Company maintains insurance against some,
but not all, potential risks; however, there can be no assurance that such
insurance will be adequate to cover any losses or exposure for liability.
The occurrence of a significant event not fully insured against could
materially adversely affect the Company's operations and financial
condition. The Company cannot predict whether insurance will continue to
be available at premium levels that justify its purchase or whether
insurance will be available at all.

Competition

       The Company believes that its exploration, drilling and production
capabilities and the experience of its management generally enable it to
compete effectively. The Company encounters competition from numerous
other natural gas companies, drilling and income programs and partnerships
in all areas of its operations, including drilling and marketing natural
gas and obtaining desirable natural gas leases. Many of these competitors
possess larger staffs and greater financial resources than the Company,
which may enable them to identify and acquire desirable producing
properties and drilling prospects more economically. The Company's ability
to explore for natural gas prospects and to acquire additional properties
in the future depends upon its ability to conduct its operations, to
evaluate and select suitable properties and to consummate transactions in
this highly competitive environment. The Company competes with a number of
other companies which offer interests in drilling partnerships with a wide
range of investment objectives and program structures. Competition for
investment capital for both public and private drilling programs is
intense. The Company also faces intense competition in the marketing of
natural gas from competitors including other producers as well as
marketing companies. Also, international developments and the possible
improved economics of domestic natural gas exploration may influence other
oil companies to increase their domestic natural gas exploration.
Furthermore, competition among natural gas companies for favorable natural
gas prospects can be expected to continue, and it is anticipated that the
cost of acquiring natural gas properties may increase in the future. 
Factors affecting competition in the natural gas industry include price,
location, availability, quality and volume of natural gas. The Company
believes that it can compete effectively in the natural gas industry on
each of the foregoing factors, due to the location of its wells near the
large demand centers for natural gas located in the northeastern United
States and the price premiums generally available for Appalachian Basin
natural gas, the quality and availability of the natural gas the Company
produces, the proximity of its wells to transportation and the significant
volume of natural gas produced by the Company on a daily basis.
Nevertheless, the Company's business, financial condition or results of
operations could be materially adversely affected by competition.

Employees

       As of December 31, 1998, the Company had 81 employees, including 13
in finance, 7 in administration, 14 in exploration and development, 42 in
production and 5 in natural gas marketing.  The Company's engineers,
supervisors and well tenders are generally responsible for the day-to-day
operation of wells and pipeline systems.  In addition, the Company retains
subcontractors to perform drilling, fracturing, logging, and pipeline
construction functions at drilling sites. The Company's employees act as
supervisors of the subcontractors.
 
       The Company's employees are not covered by a collective bargaining
agreement. The Company considers relations with its employees to be
excellent.





                                      -18-

<PAGE>
Facilities

       The Company owns and occupies three buildings in Bridgeport, West
Virginia, two of which serve as the Company's headquarters and one which
serves as a field operating site. The Company also owns a field operating
building in Gilmer County, West Virginia. The Company believes that its
current facilities are sufficient for its current and anticipated
operations.


Item 3. Legal Proceedings
 
       From time to time the Company is a party to various legal
proceedings in the ordinary course of business.  The Company is not
currently a party to any litigation that it believes would materially
affect the Company's business, financial condition or results of
operations.


Item 4.  Submission of Matters to a Vote of Security Holders

       No matters were submitted to a vote of security holders during the
fourth quarter of the fiscal year covered by this report.


                                     PART II


Item 5. Market for the Company's Common Stock and Related Security Holder
          Matters

       The common stock of the Company is traded in the over-the-counter
market under the symbol PETD.  The following table sets forth, for the
periods indicated, the high and low bid quotations per share of the
Company's common stock in the over-the-counter market, as reported by the
National Quotation Bureau Incorporated.  These quotations represent inter-
dealer prices without retail markups, markdowns, commissions or other
adjustments and may not represent actual transactions.

<TABLE>            <C>                          <C>          <C>
                                               High         Low

              1997
              First Quarter                     5 1/8       3 9/16
              Second Quarter                    5 5/16      2 7/8
              Third Quarter                    11 7/16      4 13/16
              Fourth Quarter                   10 7/16      4 3/4

              1998
              First Quarter                    6 5/8        4 1/8
              Second Quarter                   6 1/2        4 13/16
              Third Quarter                    5 1/2        3 5/16
              Fourth Quarter                   5 3/8        2 15/16
</TABLE>


       As of December 31, 1998, there were approximately 1,715 record
holders of the Company's common stock.

       The Company has not paid any dividends on its common stock and
currently intends to retain earnings for use in its business.  Therefore,
it does not expect to declare cash dividends in the foreseeable future. 
Further, the Company's Credit Agreement restricts the payment of
dividends.










                                      -19-

<PAGE>

Item 6.  Selected Financial Data (1)

<TABLE>
<C>                       <C>              <C>              <C>             <C>             <C>
                                                      Year Ended December 31,                      
                             1998         1997             1996             1995            1994   
Revenues
 Oil and gas well
 drilling 
 operations           $40,447,100     $34,405,400      $18,698,200    $13,941,000       $15,190,200
 Oil and gas sales     35,560,300      33,390,200       26,051,100      4,150,600         4,361,300
 Well operations
  income                4,581,000       4,509,300        3,928,800      3,750,900         3,730,300
 Other income           2,385,200       1,573,100          935,600        504,000           524,400
   Total              $82,973,600     $73,878,000      $49,613,700    $22,346,500       $23,806,200
Costs and Expenses
  (excluding
  interest and
  depreciation,
  depletion and
  amortization)       $71,094,900     $61,219,600      $42,274,100    $18,042,300       $20,559,500
Interest Expense      $      -        $   315,900      $   380,000    $   319,700       $   300,200
Depreciation,
 Depletion and
 Amortization         $ 3,253,600     $ 2,660,300      $ 2,309,600    $ 2,152,100       $ 1,848,200

Net Income            $ 6,658,000     $ 7,586,800      $ 3,549,400    $ 1,481,500       $   921,600

Basic earnings
 per common share          $.43          $ .67             $ .34          $ .13            $ .08 

Diluted earnings 
 per share                 $.41          $ .67             $ .34          $ .13            $ .08

Average Common and
 Common Equivalent
 Shares Outstanding
 During the Year       16,338,298      12,540,165       11,542,315     11,611,164        12,115,612

                                                December 31,                             
                          1998           1997            1996               1995            1994   
Total Assets          $111,300,400    $98,411,600     $63,604,200     $40,620,100      $38,325,300 
Working Capital       $  1,524,800    $16,483,200     $(2,357,200)    $(1,519,700)     $(1,613,700)
Long-Term Debt,
 excluding current
 maturities           $       -       $      -        $ 5,320,000     $ 2,500,000      $ 3,100,000 
Stockholders'
 Equity               $ 62,746,700    $55,766,100     $23,072,500     $19,920,900      $18,380,500 
                     
</TABLE>

[FN]
(1) See Consolidated Financial Statements elsewhere herein.
</FN>



                                                   -20-

<PAGE>

Item 7.    Management's Discussion and Analysis of Financial Condition and
           Results of Operations

Safe Harbor Statement Under the Private Securities 
Litigation Reform Act of 1995

      Statements, other than historical facts, contained in this Annual
Report on Form 10-K, including statements of estimated oil and gas
production and reserves, drilling plans, future cash flows, anticipated
capital expenditures and Management's strategies, plans and objectives, are
"forward looking statements" within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities
Exchange Act of 1934, as amended.  Although the Company believes that its
forward looking statements are based on reasonable assumptions, it cautions
that such statements are subject to a wide range of risks and uncertainties
incident to the exploration for, acquisition, development and marketing of
oil and gas, and it can give no assurance that its estimates and
expectations will be realized.  Important factors that could cause actual
results to differ materially from the forward looking statements include,
but are not limited to, changes in production volumes, worldwide demand, and
commodity prices for petroleum natural resources; the timing and extent of
the Company's success in discovering, acquiring, developing and producing
oil and gas reserves; risks incident to the drilling and operation of oil
and gas wells; future production and development costs; the effect of
existing and future laws, governmental regulations and the political and
economic climate of the United States; the effect of hedging activities; and
conditions in the capital markets.  Other risk factors are discussed
elsewhere in this Form 10-K.

Results of Operations

Year Ended December 31, 1998 Compared with December 31, 1997

      Revenues.  Total revenues for the year ended December 31, 1998 were
$83.0 million compared to $73.9 million for the year ended December 31,
1997, an increase of approximately $9.1 million, or 12.3%.  Drilling
revenues for the year ended December 31, 1998 were $40.4 million compared to
$34.4 for the year ended December 31, 1997, an increase of approximately
$6.0 million, or 17.4%.  Such increase was due to an increase in drilling
and completion activities, which was a direct result of an increase in
drilling funds from the Company's public drilling programs.  Oil and gas
sales for the year ended December 31, 1998 were $35.6 million compared to
$33.4 million for the year ended December 31, 1997, an increase of
approximately $2.2 million, or 6.6%.  Such increase was due primarily to the
natural gas marketing activities of RNG, along with increased production
from the Company's producing properties.  This increase in production was
offset in part by lower average sales prices from the Company's producing
properties and decreased natural gas purchased for resale.  Well operations
and pipeline income for the year ended December 31, 1998 was $4.6 million
compared to $4.5 million for the year ended December 31, 1997, an increase
of approximately $100,000, or 2.2%.  Such increase resulted from an increase
in the number of wells operated by the Company.  Other income for the year
ended December 31, 1998 was $2.4 million compared to $1.6 million for the
year ended December 31, 1997, an increase of approximately $800,000 or
50.0%.  Such increase was due to management fees earned on higher volumes of
drilling partnerships and interest earned on higher average cash balances. 

      Costs and expenses.  Costs and expenses for the year ended December 31,
1998 were $74.3 million compared to $64.2 million for the year ended
December 31, 1997, an increase of approximately $10.1 million, or 15.7%. 
Oil and gas well drilling operations costs for the year ended December 31,
1998 were $35.0 million compared to $28.0 million for the year ended
December 31, 1997, an increase of approximately $7.0 million, or 25.0%. Such
increase resulted from additional expenses due to increased drilling
activity.  Oil and gas purchases and production costs for the year ended
December 31, 1998 were $33.6 million compared to $30.9 million for the year



                                       -21-

<PAGE>
ended December 31, 1997, an increase of approximately $2.7 million, or 8.7%. 
Such increase was due primarily to natural gas marketing activities of RNG
along with production costs associated with the increased production from
the Company's producing properties, offset in part by lower volumes of gas
purchased for resale by the Company.  General and administrative expenses
for the year ended December 31, 1998 were $2.5 million compared to $2.3
million for the year ended December 31, 1997, an increase of approximately
$200,000.  Depreciation, depletion and amortization costs for the year ended
December 31, 1998 were $3.3 million compared to $2.7 million for the year
ended December 31, 1997, an increase of approximately $600,000 or 18.5%. 
Such increase was due to the increased amount of investment in oil and gas
properties owned by the Company.  Interest costs were eliminated after the
Company extinguished the balance on its bank credit line in November, 1997.

      Net income.  Net income for the year ended December 31, 1998 was $6.7
million compared to $7.6 million for the year ended December 31, 1997, a
decrease of approximately $900,000, or 11.8%.

Year Ended December 31, 1997 Compared with December 31, 1996

      Revenues.  Total revenues for the year ended December 31, 1997 were
$73.9 million compared to $49.6 million for the year ended December 31,
1996, an increase of approximately $24.3 million, or 49.0%.  Drilling
revenues for the year ended December 31, 1997 were $34.4 million compared to
$18.7 for the year ended December 31, 1996, an increase of approximately
$15.7 million, or 84.0%.  Such increase was due to an increase in drilling
and completion activities, which was a direct result of an increase in
drilling funds from the Company's public drilling programs.  Oil and gas
sales for the year ended December 31, 1997 were $33.4 million compared to
$26.1 million for the year ended December 31, 1996, an increase of
approximately $7.3 million, or 28.0%.  Such increase was due primarily to
the natural gas marketing activities of RNG, along with increased production
from the Company's producing properties.  This increase was offset in part
by lower average sales prices from the Company's producing properties and
decreased natural gas purchased for resale.  Well operations and pipeline
income for the year ended December 31, 1997 were $4.5 million compared to
$3.9 million for the year ended December 31, 1996, an increase of
approximately $600,000, or 15.4%.  Such increase resulted from an increase
in the number of wells operated by the Company.  Other income for the year
ended December 31, 1997 was  $1,573,000 compared to $936,000 for the year
ended December 31, 1996, an increase of approximately $637,000 or 68.1%. 
Such increase was due to management fees earned on higher volumes of
drilling partnerships, interest earned on higher average cash balances along
with a gain on the sale of equipment.  

      Costs and expenses.  Costs and expenses for the year ended December 31,
1997 were $64.2 million compared to $45.0 million for the year ended
December 31, 1996, an increase of approximately $19.2 million, or 42.7%. 
Oil and gas well drilling operations costs for the year ended December 31,
1997 were $28.0 million compared to $15.8 million for the year ended
December 31, 1996, an increase of approximately $12.2 million, or 77.2%.
Such increase resulted from additional expenses due to increased drilling
activity.  Oil and gas purchases and production costs for the year ended
December 31, 1997 were $30.9 million compared to $24.2 million for the year
ended December 31, 1996, an increase of approximately $6.7 million, or
27.7%.  Such increase was due primarily to natural gas purchases by RNG for
resale and offset partially by lower volumes of natural gas purchased for
resale.  

      Net income.  Net income for the year ended December 31, 1997 was $7.6
million compared to $3.5 million for the year ended December 31, 1996, an
increase of approximately $4.1 million, or 117.1%.




                                       -22-

<PAGE>
Year 2000 Issue

State of Readiness

      The Year 2000 Issue is the risk that computer programs using two-digit
data fields will fail to properly recognize the year 2000, with the result
being business interruption due to computer system failures by the Company's
software or hardware or that of government entities, service providers and
vendors.  The Company has assessed the extent of the Year 2000 Issues
affecting the Company.  The Company believes that the new computer system
including operating software installed during 1998 along with modifications
made by the Company's computer technicians have addressed the dating system
flaw inherent in most operating systems.  The Company has completed a
remediation plan and believes it is currently fully Year 2000 Compliant.

      The Company has initiated formal communications with its significant
suppliers and service providers to determine the extent to which the Company
may be vulnerable to their failure to correct their own Year 2000 issues. 
It is expected that full identification will be completed by April 30, 1999. 
To the extent that responses to Year 2000 readiness are unsatisfactory, the
Company intends to take appropriate action, including identifying
alternative suppliers and service providers who have demonstrated Year 2000
readiness.

Cost of Readiness

      Expenditures related to Year 2000 remediation did not exceed $35,000. 
These expenditures include costs related to the data processing transition,
a new computer system, purchase of software, modifications and
implementation costs.  A portion of these costs were capitalized and will be
amortized over the estimated useful life of the asset beginning in the third
quarter of 1998.  The remainder of these costs have been expensed as
incurred.  Management believes that the cost to become Year 2000 Compliant
is not material to the Company's financial position or results of
operations.

Risks of Year 2000 Issues

      The Company presently believes the Year 2000 Issue will not present a
materially adverse risk to the Company's future consolidated results of
operations, liquidity, and capital resources.  However, if the level of
timely compliance by key suppliers or service providers is not sufficient,
the Year 2000 Issue could have a material impact on the Company's operations
including, but not limited to, increased operating costs, loss of customers
or suppliers, loss of accounting functions, including well revenue
distributions, or other significant disruptions to the Company's business.

Contingency Plan

      The Company has a contingency plan, and will implement it on systems
that remains non-compliant as of December 31, 1999, if any.

Liquidity and Capital Resources

      The Company funds its operations through a combination of cash flow
from operations, capital raised through stock offerings and drilling
partnerships, and use of the Company's credit facility.  Operational cash
flow is generated by sales of natural gas from the Company's well interests,
well drilling and operating activities for the Company's investor partners,
natural gas gathering and transportation, and natural gas marketing.  Cash
payments from Company-sponsored partnerships are used to drill and complete
wells for the partnerships, with operating cash flow accruing to the Company
to the extent payments exceed drilling costs.  The Company utilizes its
revolving credit arrangement to meet the cash flow requirements of its
operating and investment activities.


                                       -23-

<PAGE>
      Sales volumes of natural gas have continued to increase while natural
gas prices fluctuate monthly.  The Company's natural gas sales prices are
subject to increase and decrease based on various market-sensitive indices. 
A major factor in the variability of these indices is the seasonal variation
of demand for the natural gas, which typically peaks during the winter
months.  The volumes of natural gas sales are expected to continue to
increase as a result of continued drilling activities and additional
investment by the Company in oil and gas properties.  The Company utilizes
commodity-based derivative instruments (natural gas futures and option
contracts traded on the NYMEX) as hedges to manage a portion of its exposure
to this price volatility.  The futures contracts hedge committed and
anticipated natural gas purchases and sales, generally forecasted to occur
within a three to twelve-month period.  

      The Company has a bank credit agreement with First National Bank of
Chicago, which provides a borrowing base of $10.0 million, subject to
adequate oil and natural gas reserves.  At the request of the Company, the
bank, at its sole discretion, may increase the borrowing base to $20.0
million.  As of December 31, 1998, no balance is outstanding on the line of
credit.  Interest accrues at prime, with LIBOR (London Interbank Market
Rate) alternatives available at the discretion of the Company.  No principal
payments are required until the credit agreement expires on December 31,
1999.  The Company is currently working on an amendment with the bank to
extend the expiration date of the credit agreement.

      In September 1997, the Company completed a private offering of Common
Stock pursuant to which it issued and sold 500,000 shares at a price of
$4.00 per share and issued warrants for 125,000 shares of Common Stock
exercisable during a two-year period ending September 15, 1999 at an
exercise price of $6.00 per share, resulting in proceeds to the Company of
$2.0 million.  No registration rights were granted in connection with the
securities issued in this offering.

      In November 1997, the Company completed a public offering of 4,077,500
shares of its Common Stock at a price of $6.25 per share.  Net proceeds to
the Company of approximately $23 million from the sale of common stock is
designated to fund development drilling on new and existing properties,
potential acquisition of producing properties and general corporate
purposes, including working capital and possible acquisitions of
complementary businesses.

      The Company closed four public drilling partnerships during 1998.  The
total amount received during 1998 was $40.9 million compared to $35.5
million for 1997, an increase of $5.4 million or 15.2%.  The Company closed
a record drilling program on December 31, 1998 in the amount of $20.6
million and will drill the wells during the first quarter 1999.  The Company
generally invests, as its equity contribution to each drilling partnership,
an additional sum approximating 20% of the aggregate subscriptions received
for that particular drilling partnership.  As a result, the Company is
subject to substantial cash commitments at the closing of each drilling
partnership.  The funds received from these programs are restricted to use
in future drilling operations.  No assurance can be made that the Company
will continue to receive this level of funding from these or future
programs.

      On February 19, 1998, the Company offered to purchase from Investors
their units of investment in the Company's Drilling Programs formed prior to
1993.  The Company purchased approximately $2.3 million of producing oil and
gas properties in conjunction with this offer, which expired on March 31,
1998.  The Company utilized capital received from its Public Stock Offering
to fund this purchase.



                                       -24-

<PAGE>
      On June 12, 1998 the Company purchased for $3.1 million a majority
interest in the assets of Pemco Gas, Inc., a Pennsylvania producing company. 
The assets include 122 natural gas wells, 2,700 undeveloped acres, gathering
systems, natural gas compressors and other facilities.  The Company
estimates that its interest includes 4.7 Bcf of natural gas reserves.  The
Company utilized capital received from its Public Stock Offering to fund
this purchase.

      On November 16, 1998, the Company purchased all of the working interest
in a 13 well Antrim Shale production unit and adjacent development locations
in Montmorency County, Michigan.  The Company estimates that the purchase
includes approximately 4 Bcf of proved developed producing reserves and 1.5
Bcf of proved undeveloped reserves, with an acquisition cost of $2.8
million.  The Company utilized capital received from its Public Offering to
fund this purchase.

      On January 29, 1999, the Company offered to purchase from the Investors
their units of investment in the Company's Drilling Programs formed prior to
1996.  The total of the offer if accepted by all of the approximately 6,500 
investors would be approximately $13.8 million.  The offer expires on March
31, 1999.  Management does not expect the entire amount of the offer to be
accepted by the investors.  The Company plans to utilize capital received
from its Public Stock Offering to fund this purchase obligation.

      The Company continues to pursue capital investment opportunities in
producing natural gas properties as well as its plan to participate in its
sponsored natural gas drilling partnerships, while pursuing opportunities
for operating improvements and costs efficiencies.  Management believes that
the Company has adequate capital to meet its operating requirements.

New Accounting Standards

      During the fourth quarter of 1998, the Company adopted SFAS No. 131,
Disclosures about Segments of an Enterprise and Related Information in its
full year 1998 financial statements.  SFAS No. 131 establishes standards for
the way that public enterprises report information about operating segments
in annual and interim financial statements.  Because SFAS No. 131 has a
disclosure-only effect on the notes to the Company's financial statements,
adoption of SFAS No. 131 has no impact on the Company's result of operations
or financial condition.  

      Statement of Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities (SFAS No. 133), was issued by the
Financial Accounting Standards Board in June, 1998.  Statement 133
standardized the accounting for derivative instruments, including certain
derivative instruments embedded in other contracts.  The Company must adopt
SFAS No. 133 by January 1, 2000; however, early adoption is permitted.  On
adoption, the provisions of SFAS No. 133 must be applied prospectively.  At
the present time, the Company cannot determine the impact that SFAS No. 133
will have on its financial statements upon adoption, as such impact will be
based on the extent of derivative instruments, such as natural gas futures
and options contracts, outstanding at the date of adoption.


I
tem 7.a.   Quantitative and Qualitative Disclosure About Market Risk.

Market-Sensitive Instruments and Risk Management

      The Company's primary market risk exposures are interest rate risk and
commodity price risk.  These exposures are discussed in detail below:






                                       -25-

<PAGE>
Interest Rate Risk

      The Company's exposure to market risk for changes in interest rates
relates primarily to the Company's interest-bearing cash and cash
equivalents.  The Company has no interest rate risk related to long-term
debt including current maturities, since no amounts were outstanding as of
December 31, 1998.  Interest-bearing cash and cash equivalents includes
money market funds, certificates or deposit and checking and savings
accounts with various banks.  The amount of interest-bearing cash and cash
equivalents as of December 31, 1998 is 13,769,100 with an average interest
rate of 4.9 percent.

Commodity Price Risk

      The Company utilizes commodity-based derivative instruments as hedges
to manage a portion of its exposure to price risk from its natural gas sales
and marketing activities.  These instruments consist of NYMEX-traded natural
gas futures contracts and option contracts.  These hedging arrangements have
the effect of locking in for specified periods (at predetermined prices or
ranges of prices) the prices the Company will receive for the volume to
which the hedge relates.  As a result, while these hedging arrangements are
structured to reduce the Company's exposure to decreases in price associated
with the hedging commodity, they also limit the benefit the Company might
otherwise have received from price increases associated with the hedged
commodity.  The Company's policy prohibits the use of natural gas future and
option contracts for speculative purposes.  As of December 31, 1998, PDC had
entered into a series of natural gas future contracts and options contracts. 
Open future contracts maturing in 1999 are for the purchase of 520,000 MMBtu
of natural gas with a weighted average price of $2.15/MMBtu resulting in a
total contract amount of $1,120,300, with a fair value of $(105,400).  Open
option contracts maturing in 1999 are for the purchase of 210,000 MMBtu of
natural gas with a weighted average price of $.15 per MMBtu resulting in a
total contract amount of $31,500 with a fair value of $45,800.


                                     PART III


Item 8.   Financial Statements and Supplementary Data:

      The response to this Item is set forth herein in a separate section of
this Report, beginning on Page F-1.



Item 9.    Changes in and Disagreements with Accountants on Accounting and
           Financial Disclosure.

               None.


Item 10.   Directors and Executive Officers of the Company

Directors and Officers of the Company

      The directors and officers of the Company, their principal occupations
for the past five years and additional  information are set forth below:

<TABLE>
<C>                        <C>         <C>
 Name                      Age    Positions and Offices Held

 James N. Ryan             67     Chairman, Chief Executive Officer and Director
 Steven R. Williams        47     President and Director
 Dale G. Rettinger         54     Chief Financial Officer, Executive Vice
                                   President, Treasurer and Director
 Ersel E. Morgan           55     Vice President of Production
 Thomas F. Riley           46     Vice President of Business Development
 Eric R. Stearns           40     Vice President of Exploration and Development
 Darwin L. Stump           43     Controller
 Roger J. Morgan           71     Secretary and Director
 Vincent F. D'Annunzio     46     Director
 Jeffrey C. Swoveland      43     Director
</TABLE>

                                       -26-
<PAGE>
James N. Ryan served as President of the Company from 1969 to 1983 and has
served as director of the Company since 1969. Mr. Ryan was elected Chairman
and Chief Executive Officer of the Company in March 1983. Mr. Ryan focuses
on capital formation through the Company's drilling partnerships.

Steven R. Williams has served as President and director of the Company since
March 1983. Prior to joining the Company, Mr. Williams was employed by Exxon
as an engineer from 1973 until 1979. A 1981 graduate of the Stanford
Graduate School of Business, Mr. Williams was employed by Texas Oil and Gas
Company as a financial analyst from 1981 until July 1982, when he joined
Exco Enterprises as Manager of Operations, and served in that capacity until
he joined the Company.

Dale G. Rettinger has served as Vice President and Treasurer of the Company
since July 1980. Additionally, Mr. Rettinger has served as President of PDC
Securities Incorporated since 1981. Mr. Rettinger was elected director in
1985 and appointed Chief Financial Officer in September 1997. Previously,
Mr. Rettinger was a partner with KMG Main Hurdman, Certified Public
Accountants, and served in that capacity from 1976 until he joined the
Company.

Ersel E. Morgan has served as Vice President of Production of the Company
since 1995.  Prior to assuming this position, Mr. Morgan served as the
Company's Manager of the Land and Operations groups from 1981 until 1993 and
as Manager of Production of the Company from 1993 to 1995.

Thomas E. Riley has served as Vice President of Business Development of the
Company since April 1996.  Mr. Riley co-founded and has served as President
of RNG since its inception in 1987 until the present. See "Certain
Transactions."

Eric R. Stearns has served as Vice President of Exploration and Development
of the Company since 1995.  Mr. Stearns joined the Company in 1985 as a
wellsite geologist and served as Manager of Geology from 1988 until 1995.

Darwin L. Stump has served as Controller of the Company since 1980.
Previously, Mr. Stump was a senior accountant with Main Hurdman, Certified
Public Accountants, having served in that capacity from 1977 until he joined
the Company.

Roger J. Morgan, a director and Secretary of the Company since 1969, has
been a member of the law firm of Young, Morgan & Cann, Clarksburg, West
Virginia, for more than the past five years. Mr. Morgan is not active in the
day-to-day business of the Company, but his law firm provides legal services
to the Company.

Vincent F. D 'Annunzio, a director since February 1989, has for more than
the past five years served as President of Beverage Distributors, Inc.
located in Clarksburg, West Virginia. 

Jeffrey C. Swoveland, a director since March 1991, has been employed by
Equitable Resources, an oil and gas production, marketing and distribution
company, since 1994 and presently serves as Treasurer.  Mr. Swoveland
previously served as Vice President and a lending officer with Mellon Bank,
N.A. from July 1989 until 1994.












                                       -27-

<PAGE>
The Company's By-Laws provide that the directors of the Company shall be
divided into three classes and that, at each annual meeting of stockholders
of the Company, successors to the class of directors whose term expires at
the annual meeting will be elected for a three-year term. The classes are
staggered so that the term of one class expires each year.  Mr. Rettinger
and Mr. Swoveland are members of the class whose term expires in 1999; Mr
Williams and Mr. Morgan are members of the class whose term expires in 2000;
and Mr. Ryan and Mr. D'Annunzio are members of the class whose term expires
in 2001. There is no family relationship between any director or executive
officer and any other director or executive officer of the Company. There
are no arrangements or understandings between any director or officer and
any other person pursuant to which such person was selected as an officer.


Item 11.  Management Remuneration and Transactions

      There is incorporated by reference herein in response to this Item the
material under the heading "Election of Directors - Remuneration of
Directors and Officers", "Election of Directors - Stock Options" and
"Election of Directors - Interest of Management in Certain Transactions" in
the Company's definitive proxy statement for its 1999 annual meeting of
stockholders filed or to be filed with the Commission on or before April 30,
1999.


Item 12.  Security Ownership of Certain Beneficial Owners and Management

      There is incorporated by reference herein in response to this Item, the
material under the heading "Election of Directors", in the Company's
definitive proxy statement for its 1999 annual meeting of stockholders filed
or to be filed with the Commission on or before April 30, 1999.


Item 13.    Certain Relationships and Related Transactions

      The response to this item is set forth herein in Note 8 in the Notes to
Consolidated Financial Statements.  



                                      PART IV


Item 14.   Exhibits, Financial Statement Schedules and Reports on Form 8-K

           (a)  (1) Financial Statements:

                    See Index to Financial Statements and Schedules on page 
                    F-1.

                (2) Financial Statement Schedules:

                    See Index to Financial Statements and Schedules on page 
                    F-1.


                Schedules and Financial Statements Omitted

                All other financial statement schedules are omitted because
                they are not required, inapplicable, or the information is
                included in the Financial Statements or Notes thereto.

                (3) Exhibits:

                    See Exhibits Index on page E-1.







                                       -28-

<PAGE>
                                                              CONFORMED COPY


                                    SIGNATURES

       Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.

                                               PETROLEUM DEVELOPMENT CORPORATION




                                               By  /s/ James N. Ryan            

                                                  James N. Ryan, Chairman


                                                     March 17, 1999

       Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated:

       Signature                        Title                          Date


/s/ James N. Ryan                Chairman, Chief Executive      March 17, 1999
James N. Ryan                    Officer and Director


/s/ Steven R. Williams           President and Director         March 17, 1999
Steven R. Williams


/s/ Dale G. Rettinger            Chief Financial Officer        March 17, 1999
Dale G. Rettinger                Executive Vice President,
                                 Treasurer and Director
                                 (principal financial and
                                 accounting officer)


/s/ Roger J. Morgan              Secretary and Director         March 17, 1999
Roger J. Morgan











                                       -29-

<PAGE>



                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

          Index to Financial Statements and Financial Statement Schedules






1.   Financial Statements:
       Independent Auditors' Report                                     F-2
       Consolidated Balance Sheets - December 31, 1998 and 1997         F-3 & 4
       Consolidated Statements of Income - Years Ended 
         December 31, 1998, 1997, and 1996                              F-5
       Consolidated Statements of Stockholders' Equity -
         Years Ended December 31, 1998, 1997, and 1996                  F-6
       Consolidated Statements of Cash Flows -
         Years Ended December 31, 1998, 1997, and 1996                  F-7
       Notes to Consolidated Financial Statements                       F-8 - 23


2.   Financial Statement Schedule:
       Schedule II - Valuation and Qualifying Accounts
         and Reserves                                                   F-24


































                                        F-1

<PAGE>


                           Independent Auditors' Report




The Stockholders and Board of Directors
Petroleum Development Corporation:


We have audited the consolidated financial statements of Petroleum
Development Corporation and subsidiaries as listed in the accompanying
index.  In connection with our audits of the consolidated financial
statements, we also have audited the financial statement schedule as listed
in the accompanying index.  These consolidated financial statements and
financial statement schedule are the responsibility of the Company's
management.  Our responsibility is to express an opinion on these
consolidated financial statements and financial statement schedule based on
our audits.

We conducted our audits in accordance with generally accepted auditing
standards.  Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement.  An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. 
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation.  We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of
Petroleum Development Corporation and subsidiaries as of December 31, 1998
and 1997, and the results of their operations and their cash flows for each
of the years in the three-year period ended December 31, 1998, in conformity
with generally accepted accounting principles.  Also in our opinion, the
related financial statement schedule, when considered in relation to the
basic consolidated financial statements taken as a whole, presents fairly,
in all material respects, the information set forth therein.








                                                                      KPMG LLP










Pittsburgh, Pennsylvania
March 5, 1999


                                        F-2

<PAGE>



                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                            Consolidated Balance Sheets

                            December 31, 1998 and 1997



<TABLE>
         <C>                                          <C>            <C>

                                                      1998          1997   

           Assets

Current assets:
  Cash and cash equivalents (includes 
   restricted cash of $156,200 and 
   $926,100, respectively)                      $ 34,894,600     46,561,000
  Notes and accounts receivable                    6,024,100      4,923,400

  Inventories                                        702,400        297,900
  Prepaid expenses                                 2,387,500      2,076,500

                  Total current assets            44,008,600     53,858,800


Properties and equipment:
  Oil and gas properties (successful
   efforts accounting method)                     81,592,700     57,614,900
  Pipelines                                        7,669,700      7,007,800
  Transportation and other equipment               2,332,200      2,014,000
  Land and buildings                               1,152,700      1,155,500

                                                  92,747,300     67,792,200

  Less accumulated depreciation,
   depletion and amortization                     27,356,700     24,222,900

                                                  65,390,600     43,569,300

Other assets                                       1,901,200        983,500

                                                                           

                                                $111,300,400     98,411,600

</TABLE>









                                                                           
(Continued)



                                        F-3
<PAGE>




                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                            Consolidated Balance Sheets

                            December 31, 1998 and 1997

<TABLE>
                <C>                                      <C>               <C>

                                                        1998              1997 

        Liabilities and Stockholders' Equity

Current liabilities:
  Accounts payable                                $ 11,218,900       9,792,300 
  Accrued taxes                                           -            367,000 
  Other accrued expenses                             1,959,900       2,265,000 
  Advances for future drilling contracts            28,320,800      23,291,600 
  Funds held for future distribution                   984,200       1,659,700 

                  Total current liabilities         42,483,800      37,375,600 

Other liabilities                                    2,233,500       1,684,000 

Deferred income taxes                                3,836,400       3,585,900 

Commitments and contingencies 

Stockholders' equity:
  Common stock, par value $.01 per share;
    authorized 50,000,000 shares; issued and
    outstanding 15,510,762 and 15,245,758              155,100         152,500 
  Additional paid-in capital                        31,925,400      31,617,600 
  Warrants outstanding                                  46,300          46,300 
  Retained earnings                                 30,672,200      24,014,200 
  Unamortized stock award                              (52,300)        (64,500)

                  Total stockholders' equity        62,746,700      55,766,100 

                                                  $111,300,400      98,411,600 
</TABLE>



See accompanying notes to consolidated financial statements.







                                        F-4

<PAGE>
                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                         Consolidated Statements of Income

                   Years Ended December 31, 1998, 1997 and 1996

<TABLE>
<C>                                                <C>          <C>              <C>

                                                  1998         1997            1996  
Revenues:

  Oil and gas well drilling operations       $ 40,447,100   34,405,400     18,698,200
  Oil and gas sales                            35,560,300   33,390,200     26,051,100
  Well operations and pipeline income           4,581,000    4,509,300      3,928,800
  Other income                                  2,385,200    1,573,100        935,600
                                               82,973,600   73,878,000     49,613,700
Costs and expenses:
  Cost of oil and gas well drilling 
   operations                                  35,047,500   28,033,200     15,779,800
  Oil and gas purchases and production 
   cost                                        33,556,900   30,867,600     24,190,300
  General and administrative expenses           2,490,500    2,318,800      2,304,000
  Depreciation, depletion
   and amortization                             3,253,600    2,660,300      2,309,600
  Interest                                           -         315,900        380,000
                                               74,348,500   64,195,800     44,963,700

        Income before income taxes              8,625,100    9,682,200      4,650,000

Income taxes                                    1,967,100    2,095,400      1,100,600
        Net income                            $ 6,658,000    7,586,800      3,549,400

Basic earnings per common share                   $.43          .67             .34

Diluted earnings per common
 and common equivalent share                      $.41          .61             .31

</TABLE>


See accompanying notes to consolidated financial statements.














                                          F-5

<PAGE>
                     PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                       Consolidated Statements of Stockholders' Equity

                        Years Ended December 31, 1998, 1997 and 1996

<TABLE>
<C>                                   <C>         <C>            <C>            <C>          <C>           <C>              <C>
                                       Common stock
                                          issued      
                                    Number                    Additional   Warrants
                                    of                        paid-in      out-         Retained        Unamortized
                                    shares      Amount        capital      standing     earnings        stock award       Total

Balance, December 31, 1995        11,208,6277  $112,100        7,019,800        -       12,878,000         (89,000)    19,920,900

Issuance of common stock:
  Exercise of employee
   stock options                     230,699      2,300          166,100        -            -                -           168,400 
  Purchase of subsidiary             236,094      2,300          446,800        -            -                -           449,100 
Amortization of stock award                                                                                 12,200         12,200 
Repurchase and cancellation
 of treasury stock                (1,214,667)   (12,100)      (1,015,400)       -            -                -        (1,027,500)
Net income                              -           -               -           -        3,549,400            -         3,549,400 

Balance December 31, 1996         10,460,753   $104,600        6,617,300        -       16,427,400         (76,800)    23,072,500 

Issuance of common stock:
  Stock offerings                  4,577,500     45,800       24,903,600      46,300          -               -        24,995,700 
  Exercise of employee
   stock options                     207,505      2,100           96,700        -             -               -            98,800 
Amortization of stock award                                                                                 12,300         12,300 
Net income                              -           -               -           -        7,586,800            -         7,586,800 

 Balance December 31, 1997        15,245,758   $152,500       31,617,600      46,300    24,014,200         (64,500)    55,766,100 

Issuance of common stock:
  Exercise of employee
   stock options                     324,333      3,200          300,800        -             -                -          304,000 
Amortization of stock award             -           -               -           -             -             12,200         12,200 
Repurchase and cancellation
 of treasury stock                   (59,329)      (600)        (303,400)       -             -               -          (304,000)
Income tax benefit from the
 exercise of stock options              -           -            310,400        -             -               -           310,400 
Net income                              -           -               -           -        6,658,000            -         6,658,000 

 Balance December 31, 1998        15,510,762   $155,100       31,925,400      46,300    30,672,200         (52,300)    62,746,700 
</TABLE>

See accompanying notes to consolidated financial statements.

                                                                    F-6

<PAGE>
                            PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                                   Consolidated Statements of Cash Flows

                               Years Ended December 31, 1998, 1997 and 1996

<TABLE>
<C>                                                        <C>              <C>             <C> 

                                                         1998             1997             1996    
Cash flows from operating activities:
  Net income                                        $ 6,658,000        7,586,800         3,549,400 
   Adjustment to net income to reconcile
    to cash provided by operating activities:
    Deferred income taxes                               244,000          107,700           213,900 
    Depreciation, depletion and amortization          3,253,600        2,660,300         2,309,600 
    Disposition of leasehold acreage                    196,200          187,200           151,700 
    Employee compensation paid in stock                  12,200           12,300            17,900 
    (Increase) decrease in notes and 
     accounts receivable                             (1,100,700)       1,772,600        (1,480,600)
    (Increase) decrease in inventories                 (404,500)         269,300          (349,300)
    (Increase) decrease in prepaid expenses                (600)        (998,200)          203,300 
    Increase in other assets                           (911,200)        (453,000)         (226,400)
    Increase in accounts payable
     and accrued expenses                             1,304,000        1,298,400         3,938,200 
    Increase in advances for future
     drilling contracts                               5,029,200        4,894,600         8,327,400 
    (Decrease) increase in funds held for
     future distribution                               (675,500)         795,700           160,000 
    Other                                                18,700          (39,600)           90,700 
          Total adjustments                           6,965,400       10,507,300        13,356,400 

         Net cash provided by operating
          activities                                 13,623,400       18,094,100        16,905,800 

Cash flows from investing activities:
  Capital expenditures                              (26,629,700)     (13,675,100)      (10,415,500)
  Proceeds from sale of leases                        1,283,600        1,710,900           655,400 
  Proceeds from sale of fixed assets                     56,300           87,600            10,800 
  Net cash acquired from 
    purchase of subsidiary                                 -                -            1,450,000 

         Net cash used in investing
          activities                                (25,289,800)     (11,876,600)       (8,299,300)

Cash flows from financing activities:
  Proceeds from debt                                      -                 -            4,200,000 
  Proceeds from issuance of stock                         -           25,048,100           135,300 
  Purchase of treasury stock                              -                 -           (1,000,000)
  Retirement of debt                                      -           (5,320,000)       (1,380,000)

         Net cash provided by 
           financing activities                           -           19,728,100         1,955,300 

Net (decrease) increase in cash 
 and cash equivalents                               (11,666,400)      25,945,600        10,561,800 

Cash and cash equivalents,
 beginning of year                                   46,561,000       20,615,400        10,053,600 

Cash and cash equivalents, end of year             $ 34,894,600       46,561,000        20,615,400 

</TABLE>


See accompanying notes to consolidated financial statements.


                                                    F-7

<PAGE>
                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                    Notes to Consolidated Financial Statements

                   Years Ended December 31, 1998, 1997 and 1996

(1)   Summary of Significant Accounting Policies

      Principles of Consolidation

      The accompanying consolidated financial statements include the accounts
        of Petroleum Development Corporation and its wholly owned
        subsidiaries.  All material intercompany accounts and transactions
        have been eliminated in consolidation.  The Company accounts for its
        investment in limited partnerships under the proportionate
        consolidation method.  Under this method, the Company's financial
        statements include its prorata share of assets and liabilities and
        revenues and expenses, respectively, of the limited partnerships in
        which it participates.

      The Company is involved in three business segments.  The segments are
        drilling and development, natural gas sales and well operations. (See
        Note 18)

      The Company grants credit to purchasers of oil and gas and the owners
        of managed properties, substantially all of whom are located in West
        Virginia, Tennessee, Pennsylvania, Ohio and Michigan.

      Cash Equivalents

      For purposes of the statement of cash flows, the Company considers all
        highly liquid debt instruments with original maturities of three
        months or less to be cash equivalents.

      Inventories

      Inventories of well equipment, parts and supplies are valued at the
        lower of average cost or market.  An inventory of natural gas is
        recorded when gas is purchased in excess of deliveries to customers
        and is recorded at the lower of cost or market.

      Oil and Gas Properties

      Exploration and development costs are accounted for by the successful
        efforts method.

      The Company assesses impairment of capitalized costs of proved oil and
        gas properties by comparing net capitalized costs to undiscounted
        future net cash flows on a field-by-field basis using expected
        prices.  Prices utilized in each years calculation for measurement
        purposes and expected costs are held constant throughout the
        estimated life of the properties.  If net capitalized costs exceed
        undiscounted future net cash flow, the measurement of impairment is
        based on estimated fair value which would consider future discounted
        cash flows.

      Property acquisition costs are capitalized when incurred.  Geological
        and geophysical costs and delay rentals are expensed as incurred. 
        The costs of drilling exploratory wells are capitalized pending
        determination of whether the wells have discovered economically
        producible reserves.  If reserves are not discovered, such costs are
        expensed as dry holes.  Development costs, including equipment and
        intangible drilling costs related to both producing wells and
        developmental dry holes, are capitalized.

      Unproved properties are assessed on a property-by-property basis and
        properties considered to be impaired are charged to expense when such
        impairment is deemed to have occurred.

                                                                   (Continued)
                                        F-8
<PAGE>
                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                    Notes to Consolidated Financial Statements

      Costs of proved properties, including leasehold acquisition,
        exploration and development costs and equipment, are depreciated or
        depleted by the unit-of-production method based on estimated proved
        developed oil and gas reserves.

      Upon sale or retirement of complete units of depreciable or depletable
        property, the net cost thereof, less proceeds or salvage value, is
        credited or charged to income.  Upon retirement of a partial unit of
        property, the cost thereof is charged to accumulated depreciation and
        depletion.

      Based on the Company's experience, management believes site restor-
        ation, dismantlement and abandonment costs net of salvage to be
        immaterial in relation to operating costs.  These costs are being
        expensed when incurred.

      Transportation Equipment, Pipelines and Other Equipment

      Transportation equipment, pipelines and other equipment are carried at
        cost.  Depreciation is provided principally on the straight-line
        method over useful lives of 3 to 17 years.  These assets are reviewed
        for impairment whenever events or changes in circumstances indicate
        that the carrying amount of the assets may not be recoverable.  An
        impairment loss based on estimated fair value is recorded when the
        review indicates that the related expected future net cash flow
        (undiscounted and without interest charges) is less than the carrying
        amount of the asset.

      Maintenance and repairs are charged to expense as incurred.  Major
        renewals and betterments are capitalized.  Upon the sale or other
        disposition of assets, the cost and related accumulated depreciation,
        depletion and amortization are removed from the accounts, the
        proceeds applied thereto and any resulting gain or loss is reflected
        in income.

      Buildings

      Buildings are carried at cost and depreciated on the straight-line
        method over estimated useful lives of 30 years.

      Advances for Future Drilling Contracts

      Represents funds received from Partnerships and other joint ventures
        for drilling activities which have not been completed and accordingly
        have not yet been recognized as income in accordance with the
        Company's income recognition policies.

      Retirement Plans

      The Company has a 401-K contributory retirement plan (401-K Plan)
        covering full-time employees.  The Company provides a discretionary
        matching of employee contributions to the plan.  

      The Company also has a profit sharing plan covering full-time
        employees.  The Company's contributions to this plan are
        discretionary.

      The Company has a deferred compensation arrangement covering executive
        officers of the Company as a supplemental retirement benefit.  




                                                                  (Continued)
                                        F-9

<PAGE>
                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                    Notes to Consolidated Financial Statements

      The Company has established split-dollar life insurance arrangements
        with certain executive officers.  Under these arrangements, advances
        are made to these officers equal to the premiums due.  The advances
        are collateralized by the cash surrender value of the policies.  The
        Company records as other assets its share of the cash surrender value
        of the policies.

      Revenue Recognition

      Oil and gas wells are drilled primarily on a contract basis.  The
        Company follows the percentage-of-completion method of income
        recognition for drilling operations in progress.

      Well operations income consists of operation charges for well upkeep,
        maintenance and operating lease income on tangible well equipment.

      Income Taxes

      Deferred tax assets and liabilities are recognized for the future tax
        consequences attributable to differences between the financial
        statement carrying amounts of existing assets and liabilities and
        their respective tax bases.  Deferred tax assets and liabilities are
        measured using enacted tax rates expected to apply to taxable income
        in the years in which those temporary differences are expected to be
        recovered or settled.  The effect on deferred tax assets and
        liabilities of a change in tax rates is recognized in income in the
        period that includes the enactment date.

      Derivatives

      Gains and losses related to qualifying hedges of firm commitments or
        anticipated transactions through the use of natural gas futures and
        option contracts are deferred and recognized in income or as
        adjustments of carrying amounts when the underlying hedged
        transaction occurs.  In order for futures contracts to qualify as a
        hedge, there must be sufficient correlation to the underlying hedged
        transaction.  The change in the fair value of derivative instruments
        which do not qualify for hedging are recognized into income
        currently.

      Stock Compensation

      On January 1, 1996, the Company adopted SFAS No. 123, "Accounting for
        Stock-Based Compensation," which permits entities to recognize as
        expense over the vesting period the fair value of all stock-based
        awards on the date of grant.  Alternatively, SFAS 123 allows entities
        to continue to measure compensation cost for stock-based awards using
        the intrinsic value based method of accounting prescribed by APB
        Opinion No. 25, "Accounting for Stock Issued to Employees," and to
        provide pro forma net income and pro forma earnings per share
        disclosures as if the fair value based method defined in SFAS 123 had
        been applied.  The Company has elected to continue to apply the
        provisions of APB 25 and provide the pro forma disclosure provisions
        of SFAS 123.  See note 5 to the financial statements.

      Use of Estimates

      Management of the Company has made a number of estimates and
        assumptions relating to the reporting of assets and liabilities and
        revenues and expenses and the disclosure of contingent assets and
        liabilities to prepare these financial statements in conformity with
        generally accepted accounting principles.  Actual results could
        differ from those estimates.  Estimates which are particularly
        significant to the consolidated financial statements include
        estimates of oil and gas reserves and future cash flows from oil and
        gas properties.
                                                                   (Continued)
                                       F-10
<PAGE>
                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                    Notes to Consolidated Financial Statements

      New Accounting Standards

        During the fourth quarter of 1998, the Company adopted SFAS No. 131,
      Disclosures about Segments of an Enterprise and Related Information in
      its full year 1998 financial statements.  SFAS No. 131 establishes
      standards for the way that public enterprises report information about
      operating segments in annual and interim financial statements.  Because
      SFAS No. 131 has a disclosure-only effect on the notes to the Company's
      financial statements, adoption of SFAS No. 131 has no impact on the
      Company's result of operations or financial condition.  

        Statement of Accounting Standards No. 133, Accounting for Derivative
      Instruments and Hedging Activities (SFAS No. 133), was issued by the
      Financial Accounting Standards Board in June, 1998.  Statement 133
      standardized the accounting for derivative instruments, including
      certain derivative instruments embedded in other contracts.  The
      Company must adopt SFAS No. 133 by January 1, 2000; however, early
      adoption is permitted.  On adoption, the provisions of SFAS No. 133
      must be applied prospectively.  At the present time, the Company cannot
      determine the impact that SFAS No. 133 will have on its financial
      statements upon adoption, as such impact will be based on the extent of
      derivative instruments, such as natural gas futures and option
      contracts, outstanding at the date of adoption.

(2)   Notes and Accounts Receivable

      Included in other assets are noncurrent notes and accounts receivable
        as of December 31, 1998 and 1997, in the amounts of $617,870 and
        $22,522 net of the allowance for doubtful accounts of $129,800 and
        $129,800, respectively.

      The allowance for doubtful current accounts receivable as of December
        31, 1998 and 1997 was $144,800 and $145,600, respectively.

(3)   Long-Term Debt

      On March 13, 1997, the Company amended and restated its bank credit
        agreement with First National Bank of Chicago, which provides a
        borrowing base of $10.0 million, subject to adequate oil and natural
        gas reserves.  At the request of the Company, the bank, at its sole
        discretion, may increase the borrowing base to $20.0 million.  As of
        December 31, 1998, the balance available under the line was $10.0
        million.  The Company is required to pay a commitment fee of 1/8% to
        1/4% on the unused portion of the credit facility.  Interest accrues
        at prime, with LIBOR (London Interbank Market Rate) alternatives
        available at the discretion of the Company.  No principal payments
        are required until the credit agreement expires on December 31, 1999. 
        The Company is currently working on an amendment with the bank to
        extend the expiration date of the credit agreement.

      As of December 31, 1998 and 1997 there was no balance outstanding.  Any
        amounts outstanding under the credit agreement are secured by
        substantially all properties of the Company.  The credit agreement
        requires, among other things, the existence of satisfactory levels of
        natural gas reserves, maintenance of certain working capital and
        tangible net worth ratios along with a restriction on the payment of
        dividends.





                                                                  (Continued)

                                       F-11
<PAGE>
                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                    Notes to Consolidated Financial Statements

(4)  Income Taxes

     The Company's provision for income taxes consisted of the following:

<TABLE>
         <C>                     <C>              <C>           <C> 
                                1998             1997          1996   
      Current:
       Federal              $1,197,800        1,349,600       545,600 
       State                   525,300          638,100       341,100 
        Total current
         income taxes        1,723,100        1,987,700       886,700 

      Deferred:
       Federal                    (500)         (32,100)      165,800 
       State                   244,500          139,800        48,100 
        Total deferred
         income taxes          244,000          107,700       213,900 

        Total taxes         $1,967,100         2,095,400    1,100,600 
</TABLE>

      Income tax expense differed from the amounts computed by applying the
        U.S. federal income tax rate of 34 percent to pretax income from
        continuing operations as a result of the following: 

<TABLE>
<C>                                 <C>          <C>         <C>
                                   1998         1997        1996  
                                  Amount       Amount      Amount 
Computed "expected" tax       $2,932,500    3,291,900   1,581,000 
State income tax                 508,100      513,400     249,900 
Percentage depletion            (343,400)    (263,500)   (205,800)
Nonconventional source
 fuel credit                    (696,700)    (846,400)   (510,500)
Adjustments to valuation
 allowance                      (473,200)    (565,200)       -    
Other                             39,800      (34,800)    (14,000)
                              $1,967,100    2,095,400   1,100,600 
</TABLE>

The tax effects of temporary differences that give rise to
significant portions of the deferred tax assets and deferred tax
liabilities at December 31, 1998 and 1997 are presented below:

<TABLE>
<C>                                               <C>            <C>
                                                 1998           1997   
Deferred tax assets:
  Drilling notes, principally due to 
   allowance for doubtful accounts           $  109,200        110,800 
  Alternative minimum tax credit
   carryforwards (Section 29)                 1,783,000      1,413,400 
   Deferred Compensation                        968,500        710,300 
  Other                                         256,900        170,300 
    Total gross deferred tax assets           3,117,600      2,404,800 
    Less valuation allowance                   (375,000)      (848,200)
    Deferred tax assets                       2,742,600      1,556,600 
    Less current deferred tax assets
      (included in prepaid expenses)           (818,800)      (713,600)
    Net non-current deferred 
      tax assets                              1,923,800        843,000 
Deferred tax liabilities:
  Plant and equipment, principally
   due to differences in
   depreciation and amortization             (5,760,200)    (4,428,900)
    Total gross deferred
     tax liabilities                         (5,760,200)    (4,428,900)
    Net deferred tax liability              $(3,836,400)    (3,585,900)
</TABLE>




                                                                  (Continued)
                                       F-12

<PAGE>
                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                    Notes to Consolidated Financial Statements

      The Company has evaluated each deferred tax asset and has provided a
      valuation allowance where it is believed it is more likely than not
      that some portion of the asset will not be realized.  The valuation
      allowance relates principally to the alternative minimum tax credit
      carryforwards (Section 29).

      The net changes in the total valuation allowance were for the year
      ended December 31, 1998 a decrease of $473,200 and a decrease of
      $782,300 for the year ended December 31, 1997. 

      At December 31, 1998, the Company has alternative minimum tax credit
      carryforwards (Section 29) of approximately $1,783,000 which are
      available to reduce future federal regular income taxes over an
      indefinite period.  

(5)   Common Stock

      Options

      Options amounting to 20,000 and 500,000 shares were granted during 1998
      and 1997, respectively, to certain employees and directors under the
      Company's Stock Option Plans.  These options were granted with an
      exercise price equal to market value as of the date of grant and vest
      over a two year period.  The outstanding options expire from 2000 to
      2007.

      The estimated fair value of the options granted during 1998 and 1997
      was $3.92 and $3.30 per option.  The fair value was estimated using the
      Black-Scholes option pricing model with the following assumptions for
      the 1998 and 1997 grant, respectively:  risk-free interest rate of 5.9%
      and 6.3%, expected dividend yield of 0%, expected volatility of 58.0%
      and 57.4% and expected life of 7 years.

<TABLE>
<C>                                           <C>             <C>            <C>
                                                            Average      Range of
                                             Number         Exercise     Exercise
                                             of Shares      Price        Prices

Outstanding December 31, 1995             1,852,650         $0.91     .50 -  1.63
Granted                                        -    
Exercised                                  (230,000)        $0.72     .50 - 1.125
Expired                                     (40,000)        $0.80     .50 - 1.625

Outstanding December 31, 1996             1,582,650         $0.94     .50 - 1.625

Granted                                     500,000         $5.13     5.13 - 5.13
Exercised                                  (210,000)        $0.58      .50 - 1.13
Expired                                        -            $ -        .   -  .  

Outstanding December 31, 1997             1,872,650         $2.10      .94 - 5.13

Granted                                      20,000         $6.13    6.13 -  6.13
Exercised                                  (324,333)        $0.94     .94 -   .94
Expired                                        -            $ -       .   -   .  

Outstanding December 31, 1998             1,568,317         $2.39      .94 - 6.13
</TABLE>

   As of December 31, 1998, there were 1,048,317 options outstanding and
exercisable in the $.94 to $1.63 exercise price range which have a weighted
average remaining contractual life of 3.5 years and weighted average
exercise price of $1.01.  Also as of December 31, 1998 there were 520,000
options outstanding at a $5.13 to $6.13 exercise price range having weighted
average remaining contractual life of 8.6 years and weighted average
exercise price of $5.16.  As of December 31, 1998 half of these options were
exercisable.


                                                                   (Continued)
                                       F-13

<PAGE>
                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                    Notes to Consolidated Financial Statements

      The Company accounts for its stock-based compensation plans under APB
      25.  For stock options granted, the option price was not less than the
      market value of shares on the grant date, therefore, no compensation
      cost has been recognized.  Had compensation cost been determined under
      the provisions of SFAS 123, the Company's net income and earnings per
      share would have been the following on a pro forma basis:

<TABLE>
            <C>                  <C>          <C>             <C>           <C>
                                      1998                         1997          
                             As Reported    Pro Forma     As Reported    Pro Forma

       Net income            $6,658,000    $5,918,800      $7,586,800   $7,163,600

       Basic earnings 
       per share               $ .43           $ .38         $ .67          $ .64

       Diluted earnings
       per share               $ .41           $ .37         $ .61          $ .58
</TABLE>

Stock Redemption Agreement

   The Company has stock redemption agreements with three officers of the
      Company.  The agreements require the Company to maintain life insurance
      on each executive in the amount of $1,000,000.  The agreements provide
      that the Company shall utilize the proceeds from such insurance to
      purchase from such executives' estates or heirs, at their option,
      shares of the Company's stock.  The purchase price for the outstanding
      common stock is to be based upon the average closing asked price for
      the Company's stock as quoted by NASDAQ during a specified period.  The
      Company is not required to purchase any shares in excess of the amount
      provided for by such insurance.

   Stock Purchase

   On January 31, 1996, the Company purchased 1,200,000 shares of its common
      stock pursuant to an option agreement.  The option was obtained in
      connection with a debt restructuring in 1990.  The company utilized
      its' revolving credit line to acquire the shares for $1,000,000 or
      $0.83 a share.  The shares representing approximately 11% of the
      outstanding stock at the date of acquisition were retired by the
      Company.

   Stock Offerings

   In September 1997, the Company completed a private offering of Common
      Stock pursuant to which it issued and sold 500,000 shares at a price of
      $4.00 per share and issued warrants for 125,000 shares of Common Stock
      exercisable during a two-year period ending September 15, 1999 at an
      exercise price of $6.00 per share, resulting in proceeds to the Company
      of $2.0 million.  No registration rights were granted in connection
      with the securities issued in this offering.

   In November 1997, the Company completed a public offering of 4,077,500
      shares of its Common Stock at a price of $6.25 per share.  Net proceeds
      to the Company of approximately $23 million from the sale of common
      stock is designated to fund development drilling on new and existing
      properties, potential acquisition of producing properties and general
      corporate purposes, including working capital and possible acquisitions
      of complementary businesses.






                                                                  (Continued)
                                       F-14

<PAGE>
                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                    Notes to Consolidated Financial Statements

(6)   Employee Benefit Plans

   The Company made 401-K Plan contributions of $202,600, $171,300 and
      $139,800 for 1998, 1997 and 1996, respectively.  

   The Company has a profit sharing plan (the Plan) covering full-time
      employees.  The Company contributed $17,000, $15,500 and 50,000 to the
      plan in cash during 1998, 1997 and 1996, respectively.

   During 1998, 1997 and 1996 the Company expensed and established a
      liability for $90,000 each year under a deferred compensation
      arrangement with the executive officers of the Company.  

   In 1995, a total of 90,000 restricted shares of the Company's common
      stock were granted to certain employees and available to them upon
      retirement.  The market value of shares awarded was $101,300.  This
      amount was recorded as unamortized stock award and is shown as a
      separate component of stockholders' equity.  The unamortized stock
      award is being amortized to expense over the employees' expected years
      to retirement and amounted to $12,200, $12,300 and $12,200 in 1998,
      1997 and 1996, respectively.

   At December 31, 1998 and 1997, the Company has recorded as other assets
      $240,000 and $180,000, respectively as its share of the cash surrender
      value of the life insurance pledged as collateral for the payment of
      premiums on split-dollar life insurance policies owned by certain
      executive officers.

(7)   Earnings Per Share

   In 1997, the Company adopted Statement of Financial Accounting Standards
      ("SFAS") No. 128, Earnings per share.  All periods presented have been
      restated to conform to SFAS No. 128.

   Basic earnings per share is based on the weighted average number of
      common share outstanding of 15,505,680 for 1998, 11,278,800 for 1997
      and 10,449,137 for 1996.

   Diluted earnings per share is based on the weighted average number of
      common and common equivalent shares outstanding of 16,338,298 for 1998,
      12,540,165 for 1997 and 11,542,315 for 1996.   Stock options are
      considered to be common stock equivalents and, to the extent
      appropriate, have been added to the weighted average common shares
      outstanding.  

(8)   Transactions with Affiliates

   As part of its duties as well operator, the Company received $22,997,300
      in 1998, $22,985,400 in 1997 and $18,234,200 in 1996 representing
      proceeds from the sale of oil and gas and made distributions to
      investor groups according to their working interests in the related oil
      and gas properties.  The Company provided oil and gas well drilling
      services to affiliated partnerships, substantially all of the Company's
      oil and gas well drilling operations was for such partnerships.  The
      Company also provided related services of operation of wells,
      reimbursement of syndication costs, management fees, tax return
      preparation and other services relating to the operation of the
      partnerships.  The Company received $9,621,700 in 1998, $8,113,000 in
      1997 and $6,435,700 in 1996 for those services.  

   During 1998, 1997 and 1996, the Company paid $30,000, $63,800 and
      $35,400, respectively to the Corporate Secretary's law firm for various
      legal services.


                                                                  (Continued)
                                       F-15

<PAGE>
                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                    Notes to Consolidated Financial Statements

(9)   Commitments and Contingencies

   The nature of the independent oil and gas industry involves a dependence
      on outside investor drilling capital and involves a concentration of
      gas sales to a few customers.  The Company sells natural gas to various
      public utilities and   industrial customers.  No customer accounted for
      more than 10.0% of total revenues in 1998.  One customer, Hope Gas,
      Inc., a regulated public utility accounted for 12.0% and 16.1% of total
      revenue in 1997 and 1996, respectively.

   Substantially all of the Company's drilling programs contain a repurchase
      provision where Investors may tender their partnership units for
      repurchase at any time beginning with the third anniversary of the
      first cash distribution.  The provision provides that the Company is
      obligated to purchase an aggregate of 10% of the initial subscriptions
      per calendar year (at a minimum price of four times the most recent 12
      months' cash distributions), only if such units are tendered, subject
      to the Company's financial ability to do so.  The maximum annual 10%
      repurchase obligation, if tendered by the investors, is currently
      approximately $1.3 million.  The Company has adequate capital to meet
      this obligation.

   The Company is not party to any legal action that would materially affect
      the Company's results of operations or financial condition.

(10)  Supplemental Disclosure of Cash Flows

   The Company paid $380,000 and $319,700 for interest in 1997 and 1996,
      respectively.  The Company paid income taxes in 1998, 1997 and 1996 in
      the amounts of $2,349,100, $1,932,500 and $664,300, respectively.

(11)  Acquisitions

   On April 1, 1996, the Company acquired Riley Natural Gas Company (RNG),
      a privately held gas marketing company in a stock for stock exchange
      accounted for as a purchase.  The acquisition has substantially
      increased the Company's capabilities in the natural gas marketing area. 
      PDC issued 236,094 shares with a market value of $449,100, for 100% of
      the outstanding common stock of RNG.  Key employees of RNG have entered
      into employment contracts with PDC to assure the continuity of RNG's
      gas marketing operations.

   On August 6, 1996 the Company purchased an interest in 188 oil and gas
      wells in West Virginia.  The Company utilized its revolving credit line
      to finance the purchase.  The purchase increased the Company's oil and
      gas reserves by 4.3 Bcf of natural gas and 27,000 barrels of oil, added
      12,000 acres of leases to its leasehold inventory and increased the
      Company's gathering systems by forty-nine miles.  The purchase price
      was $3.3 million.

















                                                                   (Continued)
                                       F-16

<PAGE>
                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                    Notes to Consolidated Financial Statements

   On February 19, 1998, the Company offered to purchase from Investors
      their units of investment in the Company's Drilling Programs formed
      prior to 1993.  The Company purchased approximately $2.3 million of
      producing oil and gas properties in conjunction with this offer, which
      expired on March 31, 1998.  The Company utilized capital received from
      its Public Stock Offering to fund this purchase.

   On June 12, 1998 the Company purchased for $3.1 million a majority
      interest in the assets of Pemco Gas, Inc., a Pennsylvania producing
      company.  The assets include 122 natural gas wells, 2,700 undeveloped
      acres, gathering systems, natural gas compressors and other facilities. 
      The Company estimates that its interest includes 4.7 Bcf of natural gas
      reserves.  The Company utilized capital received from its Public Stock
      Offering to fund this purchase.

   On November 16, 1998, the Company purchased all of the working interest
      in a 13 well Antrim Shale production unit and adjacent development
      locations in Montmorency County, Michigan.  The Company estimates that
      the purchase includes approximately 4 Bcf of proved developed producing
      reserves and 1.5 Bcf of proved undeveloped reserves, with an
      acquisition cost of approximately $2.8 million.  The Company utilized
      capital received from its Public Stock Offering to fund this purchase.

(12)  Derivatives and Hedging Activities

   The company utilizes commodity based derivative instruments as hedges to
      manage a portion of its exposure to price volatility stemming from its
      integrated natural gas production and marketing activities.  These
      instruments consist of natural gas futures and option contracts traded
      on the New York Mercantile Exchange.  The futures and option contracts
      hedge committed and anticipated natural gas purchases and sales,
      generally forecasted to occur within a 12 month period.  The Company
      does not hold or issue derivatives for trading or speculative purposes.

   As of December 31, 1998 and 1997, the Company had futures contracts for
      the purchase of $1,120,300 and sale of $4,599,700 of natural gas,
      respectively.  While these contracts have nominal carrying value, their
      fair value, represented by the estimated amount that would be received
      upon termination of the contracts, based on market quotes, was a net
      value of $(105,400) at December 31, 1998 and $277,200 at December 31,
      1997.

   As of December 31, 1998, the Company had option contracts totalling
      $31,500 for the purchase of natural gas with a fair value of $45,800.

   The Company is required to maintain margin deposits with brokers for
      outstanding futures contracts.  As of December 31, 1998 and 1997, cash
      in the amount of $156,200 and $926,100 was on deposit.

(13)  Costs Incurred in Oil and Gas Property Acquisition, Exploration and
     Development Activities

   Costs incurred by the Company in oil and gas property acquisition,
      exploration and development are presented below:

<TABLE>
            <C>                               <C>             <C>            <C>
                                           Years Ended December 31,     
                                           1998            1997            1996  
   Property acquisition cost:
     Proved undeveloped
     properties                         $1,903,200       3,109,000        543,600
     Producing properties                8,679,000          85,100      3,211,800
   Development costs                    14,902,500       9,863,200      5,344,900
                                       $25,484,700      13,057,300      9,100,300
</TABLE>

                                                                   (Continued)
                                       F-17

<PAGE>
                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                    Notes to Consolidated Financial Statements

      Property acquisition costs include costs incurred to purchase, lease or
        otherwise acquire a property.  Development costs include costs
        incurred to gain access to and prepare development well locations for
        drilling, to drill and equip development wells and to provide
        facilities to extract, treat, gather and store oil and gas.

(14)  Oil and Gas Capitalized Costs

      Aggregate capitalized costs for the Company related to oil and gas
        exploration and  production activities with applicable accumulated
        depreciation, depletion and amortization are presented below:

<TABLE>
       <C>                                        <C>              <C>
                                                     December 31,        
                                                 1998             1997   
Proved properties:
  Tangible well equipment                    $46,722,500       31,820,100
  Intangible drilling costs                   28,379,200       19,700,200
  Well equipment leased to others              4,063,600        4,063,600
  Undeveloped properties                       2,427,400        2,031,000
                                              81,592,700       57,614,900
     Less accumulated depreciation,
      depletion and amortization              20,395,400       17,828,500
                                             $61,197,300       39,786,400
</TABLE>

(15)    Results of Operations for Oil and Gas Producing Activities

   The results of operations for oil and gas producing activities (excluding
        marketing) are presented below:

<TABLE>
             <C>                               <C>          <C>           <C>  
                                           Years Ended December 31,     
                                               1998        1997        1996    
      Revenue:
        Oil and gas sales                $6,121,700      5,363,600    4,674,900
      Expenses:
        Production costs                  1,516,700      1,206,000      963,600
        Depreciation, depletion
          and amortization                2,392,000      1,629,900    1,248,200
                                          3,908,700      2,835,900    2,211,800
        Results of operations for
         oil and gas producing
         activities before provision
         for income taxes                 2,213,000      2,527,700    2,463,100

      Provision for income taxes            398,600        567,800      519,600

        Results of operations for oil
         and gas producing activities
         (excluding corporate over-
         head and interest costs)        $1,814,400      1,959,900    1,943,500
</TABLE>

      Production costs include those costs incurred to operate and maintain
        productive  wells and related equipment, including such costs as
        labor, repairs, maintenance, materials, supplies, fuel consumed,
        insurance and other production taxes.  In addition, production costs
        include administrative expenses and depreciation applicable to
        support equipment associated with these activities.

      Depreciation, depletion and amortization expense includes those costs
        associated  with capitalized acquisition, exploration and development
        costs, but does not include the depreciation applicable to support
        equipment.

      The provision for income taxes is computed at the statutory federal
        income tax rate and is reduced to the extent of permanent
        differences, such as investment tax and non-conventional source fuel
        tax credits and statutory depletion allowed for income tax purposes.

                                                                  (Continued)
                                       F-18

<PAGE>
                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                    Notes to Consolidated Financial Statements


(16)  Net Proved Oil and Gas Reserves (Unaudited)

      The proved reserves of oil and gas of the Company have been estimated
        by an independent petroleum engineer, Wright & Company, Inc. at
        December 31, 1998, 1997 and 1996.  These reserves have been prepared
        in compliance with the Securities and Exchange Commission rules based
        on year end prices.  An analysis of the change in estimated
        quantities of oil and gas reserves, all of which are located within
        the United States, is shown below: 

<TABLE>
    <C>                                          <C>          <C>           <C>
                                                  Oil (BBLS)              
                                               1998         1997           1996  
Proved developed and
 undeveloped reserves:
   Beginning of year                         45,000         81,000       140,000 
   Revisions of previous estimates          (10,000)       (27,000)      (30,000)
   Beginning of year as revised              35,000         54,000       110,000 
   Dispositions                                -              -          (49,000)
   Acquisitions                               2,000           -           27,000 
   Production                                (8,000)        (9,000)       (7,000)
   End of year                               29,000         45,000        81,000 
Proved developed reserves:
   Beginning of year                         45,000         81,000       140,000 
   End of year                               29,000         45,000        81,000 

                                                         Gas (MCF)               
                                             1998           1997          1996   
Proved developed and
 undeveloped reserves:
   Beginning of year                     57,243,000     43,312,000    33,829,000 
   Revisions of previous estimates       (3,517,000)       875,000    (1,037,000)
   Beginning of year as revised          53,726,000     44,187,000    32,792,000 
   New discoveries and extensions        23,552,000      2,489,000     2,613,000 
   Dispositions to partnerships          (6,009,000)          -         (127,000)
   Acquisitions, net of sales to
      partnerships in 1997 and 1996      12,003,000     12,377,000     9,529,000 
   Production                            (2,453,000)    (1,810,000)   (1,495,000)
   End of year                           80,819,000     57,243,000    43,312,000 
 Proved developed reserves:
   Beginning of year                     42,411,000     35,516,000    29,326,000 
   End of year                           64,562,000     42,411,000    35,516,000 
</TABLE>


(17)  Standardized Measure of Discounted Future Net Cash Flows and Changes
      Therein Relating to Proved Oil and Gas Reserves (Unaudited)

      Summarized in the following table is information for the Company with
        respect to the standardized measure of discounted future net cash
        flows relating to proved oil and gas reserves.  Future cash inflows
        are computed by applying year-end prices of oil and gas relating to
        the Company's proved reserves to the year-end quantities of those
        reserves.  Future production, development, site restoration and
        abandonment costs are derived based on current costs assuming
        continuation of existing economic conditions.  Future income tax 
        expenses are computed by applying the statutory rate in effect at the
        end of each year to the future pretax net cash flows, less the tax
        basis of the properties and gives effect to permanent differences,
        tax credits and allowances related to the properties.




                                                                   (Continued)

                                       F-19

<PAGE>
                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                    Notes to Consolidated Financial Statements

<TABLE>
              <C>                           <C>            <C>            <C>

                                                   Years Ended December 31,      
                                            1998            1997          1996   
      Future estimated cash flows      $186,598,000    159,618,000   193,800,000 
      Future estimated production
        and development costs           (95,670,000)   (69,265,000)  (59,806,000)
      Future estimated income
        tax expense                     (20,322,000)   (20,781,000)  (33,499,000)
        Future net cash flows            70,606,000     69,572,000   100,495,000 
      10% annual discount for
        estimated timing of cash
        flows                           (40,412,000)   (41,636,000)  (66,233,000)
        Standardized measure of
         discounted future
         estimated net cash flows       $30,194,000     27,936,000    34,262,000 
</TABLE>

      The following table summarizes the principal sources of change in the
        standardized measure of discounted future estimated net cash flows:

<TABLE>
               <C>                            <C>            <C>             <C>
                                                   Years Ended December 31,      
                                            1998            1997           1996  
        Sales of oil and gas
         production, net of 
         production costs              $ (4,605,000)    (4,158,000)   (3,711,000)
        Net changes in prices
         and production costs           (23,083,000)   (63,573,000)   42,384,000 
        Extensions, discoveries
         and improved recovery,
         less related cost               18,615,000      3,705,000     9,659,000 
        Dispositions to partnerships     (5,762,000)          -             -    
        Acquisitions, net of sales
         to partnerships in 
         1997 and 1996                   13,938,000     13,299,000    17,775,000 
        Development costs incurred
         during the period               14,903,000      9,863,000     5,345,000 
        Revisions of previous
         quantity estimates              (5,605,000)     2,332,000    (2,902,000)
        Changes in estimated
         income taxes                       459,000     12,718,000   (13,495,000)
        Accretion of discount             1,224,000     24,597,000   (37,107,000)
        Other                            (7,826,000)    (5,109,000)   (4,746,000)
                                       $  2,258,000     (6,326,000)   13,202,000 
</TABLE>

      It is necessary to emphasize that the data presented should not be
        viewed as representing the expected cash flow from, or current value
        of, existing proved reserves since the  computations are based on a
        large number of estimates and arbitrary assumptions.  Reserve
        quantities cannot be measured with precision and their estimation
        requires many judgmental determinations and frequent revisions.  The
        required projection of production and related expenditures over time
        requires further estimates with respect to pipeline availability,
        rates of demand and governmental control.  Actual future prices and
        costs are likely to be substantially different from the current
        prices and costs utilized in the computation of reported amounts. 
        Any analysis or evaluation of the reported amounts should give
        specific recognition to the computational methods utilized and the
        limitations inherent therein.





                                                                  (Continued)

                                       F-20

<PAGE>
                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                    Notes to Consolidated Financial Statements

(18)  Business Segments (Thousands)

PDC's operating activities can be divided into three major segments: 
drilling and developement, natural gas sales, and well operations.  The
Company drills natural gas wells for Company-sponsored drilling partnerships
and retains an interest in each well.  The Company also engages in oil and
gas sales to residential, commerical and industrial end-users.  The Company
charges Company-sponsored partnerships and other third parties competitive
industry rates for well operations and gas gathering.  Segment information
for the years ended December 31, 1998, 1997 and 1996 is as follows:

<TABLE>
         <C>                                        <C>           <C>            <C>
                                                  1998           1997          1996  

   REVENUES
     Drilling and Development                    $40,447         34,406       18,698 
     Natural Gas Sales                            35,560         33,390       26,051 
     Well Operations                               4,581          4,509        3,929 
     Unallocated amounts (1)                       2,385          1,573          936 
   Total                                         $82,973         73,878       49,614 
</TABLE>

   (1) Includes interest on investments and partnership management fees which
   are not allocated in assessing segment performance.

<TABLE>
         <C>                                       <C>             <C>           <C>
                                                  1998           1997          1996  
   SEGMENT INCOME BEFORE INCOME TAXES
     Drilling and Development                    $ 5,400          6,372        2,918 
     Natural Gas Sales                             2,064          2,780        2,303 
     Well Operations                               1,372          1,701        1,302 
     Unallocated amounts (2)
           General and Administrative 
            expenses                              (2,491)        (2,660)      (2,310)
           Interest expense                         -              (316)        (380)
           Other (1)                               2,280          1,805          817 
   Total                                         $ 8,625          9,682        4,650 
</TABLE>

   (2)  Items which are not allocated in assessing segment performance.

<TABLE>
        <C>                                         <C>            <C>           <C>
                                                  1998           1997          1996  
   SEGMENT ASSETS
     Drilling and Development                   $ 27,288         22,110       15,957 
     Natural Gas Sales                            65,256         45,888       37,504 
     Well Operations                               7,136          5,953        5,732 
     Unallocated amounts 
       Cash                                        7,814         20,942        1,985 
       Other                                       3,806          3,519        2,426 
           Total                                $111,300         98,412       63,604 

</TABLE>


<TABLE>
          <C>                                      <C>             <C>          <C>
                                                  1998           1997          1996  
   EXPENDITURES FOR SEGMENT 
   LONG-LIVED ASSETS
     Drilling and Development                    $ 1,953          2,862        1,140 
     Natural Gas Sales                            23,645         10,207        8,633 
     Well Operations                                 947            505          364 
     Unallocated amounts                              85            101          279 
           Total                                 $26,630         13,675       10,416 

</TABLE>

                                         F-21

<PAGE>
                  PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                      Notes to Consolidated Financial Statements

(19)  Quarterly Financial Data (Unaudited)

   Summarized quarterly financial data for the years ended December 31, 1998 and
     1997, are as follows:

<TABLE>
   <C>                   <C>              <C>       <C>           <C>           <C>
                                            1998                            
                                        Quarter                                Year 

                          First       Second        Third       Fourth   
Revenues              $25,247,400   $19,161,600  $16,649,400  $21,915,200   $82,973,600
Cost of operations     21,203,300    16,328,500   15,157,200   19,169,000    71,858,000
 Gross profit           4,044,100     2,833,100    1,492,200    2,746,200    11,115,600
General and
 administrative
 expenses                 440,100       611,000      731,600      707,800     2,490,500
Interest expense             -             -            -            -             -   
                          440,100       611,000      731,600      707,800     2,490,500
Income before
 income taxes           3,604,000     2,222,100      760,600    2,038,400     8,625,100
Income taxes              807,300       497,700      180,400      481,700     1,967,100
 Net income            $2,796,700   $ 1,724,400  $   580,200   $1,556,700   $ 6,658,000
 Basic earnings
 per share               $ .18          $ .11         $ .04       $ .10        $ .43
 Diluted earnings
 per share               $ .17          $ .11         $ .03       $ .10        $ .41

                                            1997                            
                                        Quarter                                Year 

                        First        Second        Third       Fourth    
Revenues              $23,407,800   $14,917,400  $13,955,000  $21,597,800   $73,878,000
Cost of operations     19,490,600    12,205,000   11,409,700   18,455,800    61,561,100
 Gross profit           3,917,200     2,712,400    2,545,300    3,142,000    12,316,900
General and
 administrative
 expenses                 498,600       592,900      631,900      595,400     2,318,800
Interest expense          102,600       101,900       83,600       27,800       315,900
                          601,200       694,800      715,500      623,200     2,634,700
Income before
 income taxes           3,316,000     2,017,600    1,829,800    2,518,800     9,682,200
Income taxes              812,400       611,700      376,800      294,500     2,095,400
 Net income            $2,503,600   $ 1,405,900  $ 1,453,000  $ 2,224,300   $ 7,586,800
 Basic earnings
 per share               $ .24          $ .13         $ .14       $ .16        $ .67
 Diluted earnings
 per share               $ .21          $ .12         $ .12       $ .16        $ .61
</TABLE>

     Cost of operations include cost of oil and gas well drilling operations,
        oil and gas purchases and production costs and depreciation, depletion
        and amortization.






                                         F-22
<PAGE>
                  PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                      Notes to Consolidated Financial Statements



(20)  Subsequent Event (unaudited)

     On January 29, 1999, the Company offered to purchase from the Investors
        their units of investment in the Company's Drilling Programs formed
        prior to 1996.  The total of the offer if accepted by all of the 
        approximately 6,500 investors would be approximately $13.8 million.
        The offer expires on March 31, 1999.  Management does not expect the
        entire amount of the offer to be accepted by the investors.  The 
        Company plans to utilize capital received from its Public Stock 
        Offering (see Note 5) to fund this purchase obligation.












































                                         F-23

<PAGE>

                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

 
                 SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
                                   AND RESERVES

                   Years Ended December 31, 1998, 1997 and 1996



<TABLE>
            <C>                <C>              <C>            <C>            <C>


       Column A            Column B         Column C         Column D      Column E
                                            Additions,
                           Balance at       Charged to                     Balance
                           Beginning        Costs and                      at End
       Description         of Period        Expenses         Deductions    of Period

Allowance for doubtful 
  accounts deducted from 
  accounts and notes receivable 
  in the balance sheet
     1998                   $275,400         $ 46,800         $ 47,600       $274,600

     1997                   $287,800         $  4,200         $ 16,600       $275,400

     1996                   $389,000         $108,100         $209,300       $287,800

</TABLE>



































                                           F-24






<TABLE> <S> <C>

<ARTICLE> 5
       
<S>                             <C>
<PERIOD-TYPE>                   12-MOS
<FISCAL-YEAR-END>                          DEC-31-1998
<PERIOD-END>                               DEC-31-1998
<CASH>                                      34,894,600
<SECURITIES>                                         0
<RECEIVABLES>                                6,024,100
<ALLOWANCES>                                   274,600
<INVENTORY>                                    702,400
<CURRENT-ASSETS>                            44,008,600
<PP&E>                                      92,747,300
<DEPRECIATION>                              27,356,700
<TOTAL-ASSETS>                             111,300,400
<CURRENT-LIABILITIES>                       42,483,800
<BONDS>                                              0
<PREFERRED-MANDATORY>                                0
<PREFERRED>                                          0
<COMMON>                                       155,100
<OTHER-SE>                                  62,591,600
<TOTAL-LIABILITY-AND-EQUITY>               111,300,400
<SALES>                                     35,560,300
<TOTAL-REVENUES>                            82,973,600
<CGS>                                       33,556,900
<TOTAL-COSTS>                               74,348,500
<OTHER-EXPENSES>                                     0
<LOSS-PROVISION>                                46,800
<INTEREST-EXPENSE>                                   0
<INCOME-PRETAX>                              8,625,100
<INCOME-TAX>                                 1,967,100
<INCOME-CONTINUING>                          6,658,000
<DISCONTINUED>                                       0
<EXTRAORDINARY>                                      0
<CHANGES>                                            0
<NET-INCOME>                                 6,658,000
<EPS-PRIMARY>                                      .43
<EPS-DILUTED>                                      .41
        

</TABLE>







             Third Modification to Employment Agreement

     AGREEMENT, Made as of January 1, 1999, between PETROLEUM DEVELOPMENT
CORPORATION, a Nevada Corporation with its principal offices at 103 E.
Main Street, Bridgeport, West Virginia 26330, party of the first part,
sometimes herein called the "Employer" and JAMES N. RYAN, 202 5. Warfield
Street, Wildwood, Florida 34785, party of the second part, herein
sometimes called the "Employee".

     1.    Recitals. (a) WHEREAS, the Employer employs the Employee under
the term of a written employment agreement dated July 1, 1988, and amended
and modified by subsequent written agreements dated March 1, 1991, and
October 21, 1994; and (b) WHEREAS, by corporate resolution adopted by the
Board of Directors on January 5, 1999, authorized further modifications to
said employment agreements by extending the terms of the agreement to
December 31, 2003 and otherwise amending and modifying the terms thereof
by adding to said agreements provisions for an executive deferred
retirement plan; and (c) WHEREAS, in recognition of past services and
competitive industry compensation practices, and as an incentive to induce
the Employee to extend his period of employment with the Employer, the
within deferred retirement
 is hereby established.

     NOW THEREFORE, in consideration of the premises and the parties
intending to be bound, agree as follows:

     2.    Amendment. Employment Agreements and amendments thereto be and
are further modified and amended by the following provisions providing for
an executive deferred retirement plan to the benefit of the employee.

     3.    Term Extended. The term of the current Employment Agreements
and the amendment be and are hereby extended for three (3) additional
years to December 31, 2003.

     4.    Terms and Conditions. Terms and conditions of this executive
deferred retirement program are as follows:

           a.    The program includes the named Employee.

           b.    Except in the event of the death or disability of the
                 Employee or of a change of control of the company, the
                 benefits of the program will vest upon the completion of
                 five years of employment commencing January 1, 1999. In
                 the event of death or disability or of a change of
                 control vesting will be immediate for the Employee who
                 has not yet completed the additional five years of
                 service.

           c.    When the vesting requirements have been met the Employee
                 will be entitled to receive an annual payment equal to
                 $60,000 per year upon retirement from the company
                 beginning July 1, 2004, and continuing for a total of
                 ten payments. If the Employee continues to be employed
                 by the company the start of the payments will be delayed
                 until the first of July following his retirement from
                 the company. The employee may also elect to have his
                 payments deferred for a period of up to 5 years
                 following his retirement. In the event of employment
                 beyond the five year vesting period or the deferral of

<PAGE>
                 payment following retirement the amount of the annual
                 benefit will be increased by 10.75 percent compounded
                 annually for each additional year of employment and/or
                 each year which the beginning of payment is deferred.
                 (See schedule in paragraph five (5) below)

           d.    The Employee and/or his spouse shall be entitled to
                 participate in the group health plan of the company or
                 its successors or for as long as either shall live by
                 paying the same premium for such coverage as is charged
                 to other employees of the company or its successor.

           e.    In the event of the death or disability of the Employee,
                 payments due under this retirement program shall be made
                 as designated by the Employee for any remaining unpaid
                 benefits. In the event the Employee is still employed at
                 the time of his death, his designees will receive the
                 full amount specified in the retirement program paid
                 over a 10 year period commencing with July 1 following
                 his death in addition to any other benefits specified in
                 the contract.

           f.    In the event the company or a majority of its assets are
                 acquired by another entity the benefits due under this
                 agreement will be accelerated and due immediately. In
                 the case of an employee who has already retired he shall
                 be paid a single payment equal to the sum of the
                 remaining payments he is entitled to receive. In the
                 case of an employee who has not yet retired he shall be
                 entitled to receive an accelerated retirement benefit as
                 set forth above for ten years less the period used to
                 calculate the change of control payment under Section
                 11.01 of the employment agreement as set forth in
                 "Modifications to Employment Agreement (No. 2)."

           g.    The provisions of this amendment shall survive the
                 expiration of the employment agreement and its
                 amendments.

     5.    Year  Amount
     
            5    $60,000
            6    $66,454
            7    $73,603
            8    $81,520
            9    $90,289
           10    $100,002

<PAGE>
     IN WITNESS WHEREOF, the parties hereto have executed this Agreement
as of the day and year first hereinabove written.

                                  EMPLOYER:

                                  PETROLEUM DEVELOPMENT CORPORATION,
                                  a Nevada corporation

                                  By:                                 

                                       Its                           

ATTEST:

                                   
Secretary

                                  EMPLOYEE:

                                                               
                                  JAMES N. RYAN


STATE OF WEST VIRGINIA,
COUNTY OF HARRISON, TO-WIT:

The foregoing instrument was acknowledged before me this          day of
January, 1999, by                                        ,               
      of PETROLEUM DEVELOPMENT CORPORATION, a Nevada corporation, for
and on behalf of the Corporation.

My Commission Expires:                             


                                                                     
                                       NOTARY PUBLIC

STATE OF WEST VIRGINIA,
COUNTY OF HARRISON, TO-WIT:

     The foregoing instrument was acknowledged before me this       
day of January, 1999, by JAMES N. RYAN.

My Commission Expires:                              


                                                          
                               NOTARY PUBLIC

This instrument prepared by:

Roger J. Morgan, Esquire
YOUNG, MORGAN & CANN, Attorneys at Law
Suite One, Schroath Building, Clarksburg, West Virginia 26301




             Third Modification to Employment Agreement

     AGREEMENT, Made as of January 1, 1999, between PETROLEUM DEVELOP-
MENT CORPORATION, a Nevada Corporation with its principal offices at 103 E. Main
Street, Bridgeport, West Virginia 26330, party of the first part, sometimes 
herein called the "Employer" and STEVEN R. WILLIAMS, 137 Ashford Drive, 
Bridgeport, West Virginia 26330, party of the second part, herein sometimes 
called the "Employee."

     1.    Recitals. (a) WHEREAS, the Employer employs the Employee under the
term of a written employment agreement dated July 1, 1988, and amended and 
modified by subsequent written agreements dated March 1, 1991, and October 
21, 1994; and (b) WHEREAS, by corporate resolution adopted by the Board of 
Directors on January 5, 1999, authorized further modifications to said 
employment agreements by extending the terms of the agreement to December 
31, 2003 and otherwise amending and modifying the terms thereof by adding to
said agreements provisions for an executive deferred retirement plan; and 
(c) WHEREAS, in recognition of past services and competitive industry
compensation practices, and as an incentive to induce the Employee to extend
his period of employment with the Employer, the within deferred
 retirement 
is hereby established.

     NOW THEREFORE, in consideration of the premises and the parties 
intending to be bound, agree as follows:

     2.    Amendment. Employment Agreements and amendments thereto be and are
further modified and amended by the following provisions providing for an 
executive deferred retirement plan to the benefit of the employee.

     3.    Term Extended. The term of the current Employment Agreements and the
amendment be and are hereby extended for three (3) additional years to 
December 31, 2003.
     
     4.    Terms and Conditions. Terms and conditions of this executive 
deferred retirement program are as follows:

           a.    The program includes the named Employee.

           b.    Except in the event of the death or disability of the
                 Employee or of a change of control of the company, the 
                 benefits of the program will vest upon the completion of
                 five years of employment commencing January 1, 1999. In the
                 event of death or disability or of a change of control 
                 vesting will be immediate for the Employee who has not yet
                 completed the additional five years of service.

           c.    When the vesting requirements have been met the Employee 
                 will be entitled to receive an annual payment equal to 
                 $40,000 per year upon retirement from the company beginning
                 July 1, 2004, and continuing for a total of ten payments. If
                 the Employee continues to be employed by the company the 
                 start of the payments will be delayed until the first of 
                 July following his retirement from the company. The Employee
                 may also elect to have his payments deferred for a period of
                 up to 5 years following his retirement. In the event of 
                 employment beyond the five year vesting period or the
                 deferral of payment following retirement the amount of

<PAGE>
                 the annual benefit will be increased by 10.75 percent 
                 compounded annually for each additional year of employment 
                 and/or each year which the beginning of payment is deferred.
                 (See schedule in paragraph five (5) below)

           d.    The Employee and/or his spouse shall be entitled to 
                 participate in the group health plan of the company or its 
                 successors or for as long as either shall live by paying the
                 same premium for such coverage as is charged to other 
                 employees of the company or its successor.

                 In the event of the death or disability of the Employee,
                 payments due under this retirement program shall be made as
                 designated by the Employee for any remaining unpaid 
                 benefits. In the event the Employee is still employed at 
                 the time of his death, his designees will receive the full
                 amount specified in the retirement program paid over a 10
                 year period commencing with July 1 following his
                 death in addition to any other benefits specified in the 
                 contract.

           f.    In the event the company or a majority of its assets are
                 acquired by another entity the benefits due under this 
                 agreement will be accelerated and due immediately. In the 
                 case of an employee who has already retired he shall be 
                 paid a single payment equal to the sum of the remaining 
                 payments he is entitled to receive. In the case of an 
                 employee who has not yet retired he shall be entitled to
                 receive an accelerated retirement benefit as set forth above
                 for ten years less the period used to calculate the change 
                 of control payment under Section 11.01 of the employment 
                 agreement as set forth in "Modifications to Employment 
                 Agreement (No. 2)."

           g.    The provisions of this amendment shall survive the 
                 expiration of the employment agreement and its amendments.

     5.    Year  Amount

            5    $40,000
            6    $44,303
            7    $49,068
            8    $54,347
            9    $60,193
           10    $66,668

<PAGE>
          IN WITNESS WHEREOF, the parties hereto have executed this Agreement as
of the day and year first hereinabove written.

                                  EMPLOYER:

                                  PETROLEUM DEVELOPMENT
CORPORATION,
                                  a Nevada corporation

                                  By:                                  

                                  Its                           

ATTEST:

                                   
Secretary

                                  EMPLOYEE:

                                                         
                                  STEVEN R. WILLIAMS


STATE OF WEST VIRGINIA,
COUNTY OF HARRISON, TO-WIT:

The foregoing instrument was acknowledged before me this          day of 
January, 1999, by                         ,                of PETROLEUM
DEVELOPMENT CORPORATION, a Nevada corporation, for and on behalf of the
Corporation.

My Commission Expires:                             



                                                               
                                  NOTARY PUBLIC


STATE OF WEST VIRGINIA,
COUNTY OF HARRISON, TO-WIT:

          The foregoing instrument was acknowledged before me this        
day of January, 1999, by STEVEN R. WILLIAMS.

My Commission Expires:                              




                                                          
                               NOTARY PUBLIC




This instrument prepared by:

Roger J. Morgan, Esquire
YOUNG, MORGAN & CANN, Attorneys at Law
Suite One, Schroath Building, Clarksburg, West Virginia 26301




             Third Modification to Employment Agreement

     AGREEMENT, Made as of January 1, 1999, between PETROLEUM DEVELOP-
MENT CORPORATION, a Nevada Corporation with its principal offices at 103 E. Main
Street, Bridgeport, West Virginia 26330, party of the first part, sometimes 
herein called the "Employer" and DALE G. RETTINGER, 116 Cherry Tree Road, 
Addison, Pennsylvania 15411, party of the second part, herein sometimes 
called the "Employee." 

     1.    Recitals. (a) WHEREAS, the Employer employs the Employee under the
term of a written employment agreement dated July 1, 1988, and amended and 
modified by subsequent written agreements dated March 1, 1991, and October 
21, 1994; and (b) WHEREAS, by corporate resolution adopted by the Board of 
Directors on January 5, 1999, authorized further modifications to said 
employment agreements by extending the terms of the agreement to December 
31, 2003 and otherwise amending and modifying the terms thereof by adding to
said agreements provisions for an executive deferred retirement plan; and (c)
WHEREAS, in recognition of past services and competitive industry 
compensation practices, and as an incentive to induce the Employee to extend
his period of employment with the Employer, the within deferred
 retirement 
is hereby established.

     NOW THEREFORE, in consideration of the premises and the parties 
intending to be bound, agree as follows:

     2.    Amendment. Employment Agreements and amendments thereto be and are
further modified and amended by the following provisions providing for an 
executive deferred retirement plan to the benefit of the Employee.

     3.    Term Extended. The term of the current Employment Agreements and the
amendment be and are hereby extended for three (3) additional years to 
December 31, 2003.

     4.    Terms and Conditions. Terms and conditions of this executive 
deferred retirement program are as follows:

           a.    The program includes the named Employee.

           b.    Except in the event of the death or disability of the 
                 Employee or of a change of control of the company, the
                 benefits of the program will vest upon the completion of 
                 five years of employment commencing January 1, 1999. In the
                 event of death or disability or of a change of control 
                 vesting will be immediate for the Employee who has not yet
                 completed the additional five years of service.

           c.    When the vesting requirements have been met the Employee will
                 be entitled to receive an annual payment equal to $40,000 
                 per year upon retirement from the company beginning July 1,
                 2004, and continuing for a total of ten payments. If the 
                 Employee continues to be employed by the company the start
                 of the payments will be delayed until the first of July 
                 following his retirement from the company. The employee may
                 also elect to have his payments deferred for a period of up
                 to 5 years following his retirement. In the event of 
                 employment beyond the five year vesting period or the
                 deferral of payment following retirement the amount of the
                 annual benefit will be increased by 10.75 percent

<PAGE>
                 compounded annually for each additional year of employment
                 and/or each year which the beginning of payment is deferred. 
                 (See schedule in paragraph five (5) below)

           d.    The Employee and/or his spouse shall be entitled to 
                 participate in the group health plan of the company or its
                 successors or for as long as either shall live by paying 
                 the same premium for such coverage as is charged to other
                 employees of the company or its successor.

           e.    In the event of the death or disability of the Employee, 
                 payments due under this retirement program shall be made as
                 designated by the Employee for any remaining unpaid 
                 benefits. In the event the Employee is still employed at the
                 time of his death, his designees will receive the full 
                 amount specified in the retirement program paid over a 10
                 year period commencing with July 1 following his death in
                 addition to any other benefits specified in the contract.

           f.    In the event the company or a majority of its assets are 
                 acquired by another entity the benefits due under this 
                 agreement will be accelerated and due immediately. In the 
                 case of an employee who has already retired he shall be 
                 paid a single payment equal to the sum of the remaining 
                 payments he is entitled to receive. In the case of an 
                 employee who has not yet retired he shall be entitled to
                 receive an accelerated retirement benefit as set forth 
                 above for ten years less the period used to calculate the 
                 change of control payment under Section 11.01 of the 
                 employment agreement as set forth in "Modifications to
                 Employment Agreement (No. 2)."

           g.    The provisions of this amendment shall survive the 
                 expiration of the employment agreement and its amendments.
     
     5.    Year  Amount
     
            5    $40,000
            6    $44,303
            7    $49,068
            8    $54,347
            9    $60,193
           10    $66,668

<PAGE>
     IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of
the day and year first hereinabove written.

                                  EMPLOYER:

                                  PETROLEUM DEVELOPMENT CORPORATION,
                                  a Nevada corporation

                                  By:                                  

                                  Its                           

ATTEST:

                                   
Secretary


                                  EMPLOYEE:

                                                               
                                  STEVEN R. WILLIAMS



STATE OF WEST VIRGINIA,
COUNTY OF HARRISON, TO-WIT:

The foregoing instrument was acknowledged before me this          day of 
January, 1999, by                                   ,                      of
PETROLEUM DEVELOPMENT CORPORATION, a Nevada corporation, for and on behalf of
the Corporation.

My Commission Expires:                             



                                                                     
                                       NOTARY PUBLIC

STATE OF WEST VIRGINIA,
COUNTY OF HARRISON, TO-WIT:

          The foregoing instrument was acknowledged before me this       
day of January, 1999, by STEVEN R. WILLIAMS.
          
My Commission Expires:                              




                                                          
                               NOTARY PUBLIC



This instrument prepared by:

Roger J. Morgan, Esquire
YOUNG, MORGAN & CANN, Attorneys at Law
Suite One, Schroath Building, Clarksburg, West Virginia 26301




                     PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
                                         EXHIBIT 11
                       SCHEDULE OF COMPUTATION OF NET INCOME PER SHARE

<TABLE>
<C>                                                <C>             <C>              <C> 

                                                       Years Ended December 31,            
 

            BASIC                                                                         
                                                   1998           1997            1996    
 
Net income for basic income 
 per common share                              $6,658,000      7,586,800        3,549,400 

Weighted average number of common shares 
 outstanding during the year                   15,505,680     11,278,800       10,449,137 

Basic earnings per share                       $     .43     $       .67       $      .34

            DILUTED

Net income for basic earnings per
 common share                                 $ 6,658,000    $ 7,586,800       $ 3,549,400

      Net income for diluted
       earnings per share                     $ 6,658,000    $ 7,586,800      $ 3,549,400 

      Weighted average number of shares
       used in calculating basic earnings
       per common share                        15,505,680     11,278,800       10,449,137 

  Shares issuable for diluted calculation         832,618      1,261,365        1,093,178 

      Weighted average number of shares
       used in calculation of 
       diluted earnings per share              16,338,298     12,540,165       11,542,315 

Diluted earnings per share                     $     .41     $       .61      $       .31

</TABLE>























                                            E-2