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, 1999

   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, 2000, 15,982,376 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 $45,985,012 (based on the 
last traded price of $4.00).

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


                                     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 drilling and development activities,
the acquisition of natural gas producing wells and the expansion of its
natural gas marketing activities. As of December 31, 1999, the Company
operated approximately 1,800 wells located in the Appalachian and Michigan
Basins and the Rocky Mountain Region, and had net proved reserves of 101
Bcf of natural gas. The Company's wells currently produce an aggregate of
approximately 37,000 Mcf of natural gas per day, of which the Company's
share is approximately 14,500 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 has historically 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, 1999, had drilled 183 wells in this area.  In 1999 in
addition to its drilling activities, the Company purchased natural gas
producing properties.  In December 1999, the Company purchased 53 net
wells in Colorado.

      The Company owns 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 allows 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 1999, the
Company raised $36.1 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 1999
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; 
21% and 14% by residential and commercial end-users, respectively, for
uses including heating, cooling and cooking; 15% 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-
      -  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 can provide significant reserves per well
drilled. Additionally, this area is close to certain end-user markets,
which has provided favorable premiums. With a current productive area of
nearly 2.5 million acres, Michigan has been one of the most active areas
for natural gas drilling in the United States over the past decade.

      During 1998 the Company began to establish a lease position in the
Rocky Mountain producing region.  The region is believed to hold
substantial undeveloped natural gas resources.  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.  In 1999 the company drilled four unsuccessful
exploratory wells, two in Moffatt County, Colorado and two in Carter
County, Montana.  In November and December 1999 the Company acquired
drilling rights to 20 locations in the Wattenberg field in Weld County,
Colorado and a 7,400 acre lease in the Grand Valley field in Garfield
County, Colorado.  Prior to the end of 1999, the Company had drilled five
successful wells in the Wattenberg field and was prepared to drill its
first Grand Valley test well. Wells in both areas are generally
development wells.

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:


                                       -3-

      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.  The Company drilled 178
wells in 1999, compared to 213 for the year of 1998.  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, 1999, the    
Company had 37,000 net undeveloped acres in the Michigan Basin, 28,430 net
undeveloped acres in the Appalachian Basin and 88,020 net undeveloped
acres in the Rocky Mountain Region. 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, reserves and production levels of two to three times
that of Appalachian levels for a similar investment more than offset
higher expected operating costs. The Company's Colorado development
projects also build on our shallow gas well operating experience.  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 has the expertise of RNG, an experienced
natural gas marketer. 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-

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, 1999, the Company had a total
leasehold inventory of approximately 247,140 gross acres and 246,710 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 1999, the Company drilled a total
of 178 wells, of which 13 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 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-

During 1998 the Company purchased an 80% interest in 122 producing wells
located in Pennsylvania from Pemco Gas, Inc. and a 100% working interest
in 13 producing wells in Michigan, as well as certain well interests in
its Company sponsored partnerships.  In 1999, the Company purchased a 100%
working interest in 53 producing wells in the D-J Basin of Colorado which
added 3.6 Bcf of natural gas and 370,000 barrels of oil to the Company's
reserves.  Also purchased in 1999 were certain well interests in its
Company sponsored partnerships.  

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,        
                             1999      1998     1997     1996      1995 
Production(1):
  Oil(MBbls)                    8          8       9        7        11
  Natural Gas (MMcf)        3,451      2,453   1,810    1,495     1,336
  Equivalent MMcfs(2)       3,499      2,501   1,864    1,537     1,402
Average sales price:
  Oil (per Bbl)            $18.75     $10.61  $16.10   $16.35    $15.80
  Natural gas (per Mcf)     $2.46      $2.46   $2.88    $3.04     $1.75
Average production cost 
  (lifting cost) per
  equivalent Mcf(3)         $0.69      $0.61   $0.65    $0.63     $0.53
</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 1,538 natural gas wells
in the Appalachian Basin, 200 wells in the Michigan Basin and 58 wells in
the Rocky Mountain Region. The Company's ownership interest in these wells
ranges from 0% to 100%, and, on average, the Company has an approximate
48% ownership interest in the wells it operates. Currently these wells
produce an aggregate of about 37,000 Mcf of natural gas per day, including
the Company's share of 14,500 Mcf per day.

      The Company is paid a monthly operating charge for each well it
operates for outside owners. 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.







                                       -6-

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.

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, 1995, 1996, 1997, 1998 and 1999. 
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 and five dry holes (2.44 net)
drilled in 1999.

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

                            Total            Productive              Dry   
                        Drilled   Net       Drilled    Net     Drilled   Net

      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               212     56.99       201      54.22      11     2.77
      1999               173     54.64       165      53.10       8     1.54

           Total         722    183.19       680     173.58      42     9.61
</TABLE>











                                       -7-

Summary of Productive Wells
 
The table below shows the number of the Company's productive gross and net
wells at December 31, 1999.

<TABLE>
<C>                       <C>              <C>        <C>        <C>
                                            WELLS              
                                   Gas                   Oil       
Location                  Gross           Net     Gross         Net 
Colorado                     58          53.78       -          -
Michigan                    199          97.67       1           .80
Ohio                         16           7.19       5          2.34
Pennsylvania                527         164.26       -          - 
Tennessee                     1           0.71      39         15.87
West Virginia               944         523.94       6          2.58
   Total                  1,745         847.55      51         21.59
</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 101,245,000 Mcf of natural gas and 1,154,000
Bbls of oil at December 31, 1999; 80,819,000 Mcf of natural gas and 29,000
Bbls of oil at December 31, 1998; and 57,243,000 Mcf of natural gas and
45,000 Bbls of oil at December 31, 1997. 

       The Company's approximate net proved developed reserves were
estimated, by Wright & Company to be 82,628,000 Mcf of natural gas and
798,000 Bbls of oil at December 31, 1999; 64,562,000 Mcf of natural gas
and 29,000 Bbls of oil at December 31, 1998; and 42,411,000 Mcf of natural
gas and 45,000 Bbls of oil at December 31, 1997. 

       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, 1999.  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 1999, 1998 and 1997 to be $58.5 million as of December 31, 1999, $30.2
million as of December 31, 1998 and $27.9 million as of December 31, 1997.
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-

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, 1999 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, 1999 to December 31, 1999, 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, 1999)                         80,819,000 
 Revisions of previous estimates                             (4,475,000)
 Beginning of year as revised                                76,344,000 
 New discoveries and extensions                              24,781,000 
 Dispositions, to partnerships                               (8,774,000)
 Acquisitions                                                12,345,000 
 Production                                                  (3,451,000)
 End of period (December 31, 1999)                          101,245,000 
 
 Proved developed reserves:
 Beginning of year (January 1, 1999)                         64,562,000 
 End of period (December 31, 1999)                           82,628,000 

                                                             Oil (Bbls) 
Proved developed and undeveloped reserves:
Beginning of year (January 1, 1999)                              29,000 
Revisions of previous estimates                                  67,000 
Beginning of year as revised                                     96,000 
New discoveries and extensions                                  404,000 
Dispositions                                                        -   
Acquisitions                                                    662,000 
Production                                                       (8,000)
End of period (December 31, 1999)                             1,154,000 

Proved developed reserves:
Beginning of year (January 1, 1999)                              29,000 
End of period (December 31, 1999)                               798,000 

</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, 1999
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, 1999

Future estimated cash flows                                $307,816,000 
Future estimated production and development costs          (129,557,000)
Future estimated income tax expense                         (39,930,000)
Future net cash flows                                       138,329,000 
10% annual discount for estimated 
 timing of cash flows                                       (79,875,000)
Standardized measure of discounted 
 future estimated net cash flows                           $ 58,454,000 
</TABLE>

                                       -9-
       The following table summarizes the principal sources of change in
the standardized measure of discounted future estimated net cash flows
from January 1, 1999 through December 31, 1999:

<TABLE>
<C>                                                            <C>
 Sales of oil and natural gas production, 
  net of production costs                                   $(6,206,000)
 Net changes in prices and production costs                  29,547,000 
 Extensions, discoveries and improved recovery, 
  less related cost                                          39,653,000 
 Dispositions to partnerships                                (6,152,000)
 Acquisitions                                                31,915,000 
 Development costs incurred during the period                17,168,000 
 Revisions of previous quantity estimates                    (4,944,000)
 Changes in estimated income taxes                          (19,608,000)
 Changes in discount                                        (39,463,000)
 Changes in production rate (timing) and other              (13,650,000)
                                                           $ 28,260,000 
</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, 1999, 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 
       Colorado           2,080    2,080      7,600      7,600
       Michigan          27,500   27,500     37,000     37,000
       Montana              -        -       22,000     22,000
       Ohio                 740      740        500        500
       Pennsylvania       8,700    8,700     19,000     19,000
       Tennessee          5,400    5,400       -          -   
       Utah                -        -        58,420     58,420
       West Virginia     49,000   48,840      9,200      8,930
      Total              93,420   93,260    153,720    153,450
</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-
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. No customer accounted for more than 10.0% of total revenues in
1999.  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 and 26.6% of the Company's revenues
from oil and gas sales (12.0% of total revenues) in 1997.  The Company and
Hope Gas were parties to a Pipeline Purchase Agreement, pursuant to which
agreement the Company delivered 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 were also
parties to a Master Gas Purchase Agreement, which expired on May 31, 1999,
pursuant to which the Company offered 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 1999, 1998 or 1997. 

       At December 31, 1999, natural gas produced by the Company sold at
prices per Mcf ranging from $0.90 to $4.35, 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 1999 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-

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 assists
the Company in maximizing its prices as it markets natural gas from
Company-operated wells. RNG and its management also brought 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, Michigan and Colorado, 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, 1999, there were 182 existing
hedge positions representing 1,820,000 Mmbtu.  



                                      -12-

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 $36.1 million in
subscriptions in 1999.  Funds received pursuant to drilling contracts were
$40.9 million in 1998 and $35.5 million in 1997.  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. The Company's development
contracts may 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 may also purchase 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-

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's current production of oil is from
wells located in Tennessee, Ohio, West Virginia and Colorado.  In 1999,
its share of oil production is about 8,000 barrels. The Company's
acquisition in December 1999 of 53 wells in Colorado, and ongoing
development activities in Colorado and Michigan are resulting in a
significant increase in oil production and reserves.  At the end of 1999
oil was about 6% of the Company's total equivalent reserves.  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 1999, 1998 or 1997. At December 31, 1999, oil produced by the
Company sold at prices ranging from $21.75 to $24.57 per barrel, depending
upon the location and quality of oil.  In 1999, the weighted net average
price per barrel of oil sold by the Company was $18.75.

       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-

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-
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-

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
1999 were not significant in relation to operating costs and the Company
expects no material change in 2000. 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 1999, 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 nine-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-
 
       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.  Nevertheless, the Company's business,
financial condition or results of operations could be materially adversely
affected by competition.

Employees

       As of December 31, 1999, the Company had 91 employees, including 13
in finance, 7 in administration, 14 in exploration and development, 52 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-

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 leases field
operating offices in Pennsylvania, Michigan, Colorado, and Ohio under
operating leases. 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.

                                               High         Low

              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

              1999
              First Quarter                     3 15/16     2 7/8
              Second Quarter                    4 11/16     3 5/16
              Third Quarter                     5 3/8       4 3/16
              Fourth Quarter                    4 13/16     3 23/32


       As of December 31, 1999, there were approximately 1,349 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-


Item 6.  Selected Financial Data (1)

<TABLE>
<C>                       <C>             <C>              <C>             <C>             <C>
                                                         Year Ended December 31,                   
                        1999              1998             1997             1996            1995   
Revenues
 Oil and gas well
 drilling 
 operations          $42,115,600      $40,447,100      $34,405,400     $18,698,200     $13,941,000 
 Oil and gas sales    46,988,100       35,560,300       33,390,200      26,051,100       4,150,600 
 Well operations
  income               5,314,500        4,581,000        4,509,300       3,928,800       3,750,900 
 Other income          2,392,400        2,385,200        1,573,100         935,600         504,000 
   Total             $96,810,600      $82,973,600      $73,878,000     $49,613,700     $22,346,500 
Costs and Expenses
  (excluding
  interest and
  depreciation,
  depletion and
  amortization)      $82,496,500      $71,094,900      $61,219,600     $42,274,100     $18,042,300 
Interest Expense     $   182,400      $      -         $   315,900     $   380,000     $   319,700 
Depreciation,
 Depletion and
 Amortization        $ 4,031,200      $ 3,253,600      $ 2,660,300     $ 2,309,600     $ 2,152,100 

Net Income           $ 7,824,300      $ 6,658,000      $ 7,586,800     $ 3,549,400     $ 1,481,500 

Basic earnings
 per common share          $.50          $.43              $ .67          $ .34            $ .13

Diluted earnings 
 per share                 $.48          $.41              $ .67          $ .34            $ .13

Average Common and
 Common Equivalent
 Shares Outstanding
 During the Year       16,286,852     16,338,298        12,540,165      11,542,315      11,611,164 

                                                December 31,                             
                          1999           1998            1997               1996            1995   
Total Assets         $132,083,600    $111,409,000      $98,411,600    $63,604,200      $40,620,100 
Working Capital      $ (2,503,900)   $  1,633,400      $16,483,200    $(2,357,200)     $(1,519,700)
Long-Term Debt,
 excluding current
 maturities           $ 9,300,000    $       -         $      -       $ 5,320,000      $ 2,500,000 
Stockholders'
 Equity               $70,724,900    $ 62,746,700      $55,766,100    $23,072,500      $19,920,900 
                     
</TABLE>

(1) See Consolidated Financial Statements elsewhere herein.




















                                                   -20-


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, 1999 Compared with December 31, 1998

      Revenues.  Total revenues for the year ended December 31, 1999 were
$96.8 million compared to $83.0 million for the year ended December 31,
1998, an increase of approximately $13.8 million, or 16.6%.  Drilling
revenues for the year ended December 31, 1999 were $42.1 million compared to
$40.4 for the year ended December 31, 1998, an increase of approximately
$1.7 million, or 4.2%.  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, 1999 were $47.0 million compared to $35.6
million for the year ended December 31, 1998, an increase of approximately
$11.4 million, or 32.0%.  Such increase was due to the natural gas marketing
activities of RNG, along with increased production from the Company's
producing properties.  The increase in production from the Company's
producing properties from 1998 to 1999 was 40.7%.  Well operations and
pipeline income for the year ended December 31, 1999 was $5.3 million
compared to $4.6 million for the year ended December 31, 1998, an increase
of approximately $700,000 or 15.2%.  Such increase resulted from an increase
in the number of wells operated by the Company.  Other income remained
constant at $2.4 million for the years ended December 31, 1999 and 1998. 
However for the year ended December 31, 1999 a gain on the sale of oil and
gas property offset the decrease in interest earned in 1999 compared to 1998
due to lower average cash balances.

      Costs and expenses.  Costs and expenses for the year ended December 31,
1999 were $86.7 million compared to $74.3 million for the year ended
December 31, 1998, an increase of approximately $12.4 million, or 16.7%. 
Oil and gas well drilling operations costs for the year ended December 31,
1999 were $35.5 million compared to $35.0 million for the year ended
December 31, 1998, an increase of approximately $500,000 or 1.4%.  Such
increase resulted from additional expenses due to increased drilling
activity.  Oil and gas purchases and production costs for the year ended
December 31, 1999 were $44.2 million compared to $33.6 million for the year
ended December 31, 1998, an increase of approximately $10.6 million, or
31.5%.  Such increase was due primarily to natural gas marketing activities
of RNG along with production costs associated with the increased production

                                       -21-

from the Company's producing properties.  General and administrative
expenses for the year ended December 31, 1999 were $2.8 million compared to
$2.5 million for the year ended December 31, 1998, an increase of
approximately $300,000.  Depreciation, depletion and amortization costs for
the year ended December 31, 1999 were $4.0 million compared to $3.3 million
for the year ended December 31, 1998, an increase of approximately $700,000
or 21.2%.  Such increase was due to the increased amount of investment in
oil and gas properties owned by the Company.  Interest costs were $182,000
for the year ended December 31, 1999 as the Company utilized its credit
agreement during the third and fourth quarters of 1999.

      Net income.  Net income for the year ended December 31, 1999 was $7.8
million compared to $6.7 million for the year ended December 31, 1998, an
increase of approximately $1.1 million or 16.4%.

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
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.




                                       -22-

      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 2000 Issue

      The Company experienced no known disruptions as a result of the year
date change and intends to continue monitoring its critical systems at
various other date changes during the Year 2000. 

      The Company expenditures for addressing Year 2000 issues were not
material, nor does the Company expect to incur any significant costs
addressing Year 2000 issues in the future.

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.

      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 $20.0 million, subject to
adequate oil and natural gas reserves.  As of December 31, 1999, the balance
outstanding on the line of credit is $9.3 million.  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, 2002.  

      The Company closed four public drilling partnerships during 1999.  The
total amount received during 1999 was $36.1 million compared to $40.9
million for 1998. The Company closed its fourth program of 1999 on December
31, 1999 in the amount of $18.7 million and will drill the wells during the
first quarter 2000.  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.




                                       -23-

      On January 29, 1999, the Company offered to purchase from Investors
their units of investment in the Company's Drilling Programs formed prior to
1996.  The Company purhased approximately $1.8 million of producing oil and
gas properties in conjunction with this offer, which expired on March 31,
1999.  The Company utilized capital received from its 1997 public stock
offering to fund this purchase.

      On December 15, 1999, the Company purchased all of the working interest
in 53 producing wells in the D-J Basin of Colorado.  The Company estimates
that the purchase includes proved developed reserves of approximately 3.6
Bcf of natural gas and 370,000 barrels of oil or approximately 5.8 Bcf
equivalent (Bcfe), along with another 3.0 Bcfe of net development drilling
locations.  The total acquisition cost for the wells and locations was $5.2
million.  The Company utilized part of its existing line of credit to fund
the transaction.  The effective date of the transaction was December 1,
1999. 

      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

      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.  SFAS No. 133
standardized the accounting for derivative instruments, including certain
derivative instruments embedded in other contracts.  SFAS No. 133 is
effective for years beginning after June 15, 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.


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:

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 and long-term debt.  Interest-bearing cash and cash equivalents
includes money market funds, certificates of deposit and checking and
savings accounts with various banks.  The amount of interest-bearing cash
and cash equivalents as of December 31, 1999 is $9,992,700 with an average
interest rate of 3.63 percent.  As of December 31, 1999, the Company has
long-term debt of $9,300,000 of which $6,300,000 is at a prime interest rate
of 8.5% and $3,000,000 at a LIBOR interest rate of 7.73%.










                                       -24-

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, 1999, PDC had
entered into a series of natural gas future contracts and options contracts. 
Open future contracts maturing in 2000 are for the purchase of 1,820,000
MMBtu of natural gas with a weighted average price of $2.3725 MBtu resulting
in a total contract amount of $4,317,950, and a fair market value of
$350,500.  


                                     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:

 Name                      Age    Positions and Offices Held

 James N. Ryan             68     Chairman, Chief Executive Officer and Director
 Steven R. Williams        48     President and Director
 Dale G. Rettinger         55     Chief Financial Officer, Executive Vice
                                   President, Treasurer and Director
 Ersel E. Morgan           56     Vice President of Production
 Thomas F. Riley           47     Vice President of Business Development
 Eric R. Stearns           41     Vice President of Exploration and Development
 Darwin L. Stump           44     Controller
 Roger J. Morgan           72     Secretary and Director
 Vincent F. D'Annunzio     47     Director
 Jeffrey C. Swoveland      44     Director
 Donald B. Nestor          50     Director

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.
                                       -25-

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.

Donald B. Nestor, elected as a director in March, 2000, is a Certified
Public Accountant and a Partner in the CPA firm of Toothman Rice, P.L.L.C.
and is in charge of the firm's Buckhannon, West Virginia office.  Mr. Nestor
has servied in that capacity for more than the past five years.


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 Williams and
Mr. Morgan are members of the class whose term expires in 2000; Mr. Ryan and
Mr. D'Annunzio are members of the class whose term expires in 2001; and Mr.
Rettinger and Mr. Swoveland are members of the class whose term expires in
2002.  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.






                                       -26-


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 2000 annual meeting of
stockholders filed or to be filed with the Commission on or before April 30,
2000.


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 2000 annual meeting of stockholders filed
or to be filed with the Commission on or before April 30, 2000.


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.







                                       -27-

                                                              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, 2000

       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, 2000
James N. Ryan                    Officer and Director


/s/ Steven R. Williams           President and Director           March 17, 2000
Steven R. Williams


/s/ Dale G. Rettinger            Chief Financial Officer          March 17, 2000
Dale G. Rettinger                Executive Vice President,
                                 Treasurer and Director
                                 (principal financial and
                                 accounting officer)


/s/ Roger J. Morgan              Secretary and Director           March 17, 2000
Roger J. Morgan











                                       -28-




                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, 1999 and 1998         F-3 & 4
       Consolidated Statements of Income - Years Ended 
         December 31, 1999, 1998, and 1997                              F-5
       Consolidated Statements of Stockholders' Equity -
         Years Ended December 31, 1999, 1998, and 1997                  F-6
       Consolidated Statements of Cash Flows -
         Years Ended December 31, 1999, 1998, and 1997                  F-7
       Notes to Consolidated Financial Statements                       F-8 - 22


2.   Financial Statement Schedule:
       Schedule II - Valuation and Qualifying Accounts
         and Reserves                                                   F-23


































                                        F-1



                           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, 1999
and 1998, and the results of their operations and their cash flows for each
of the years in the three-year period ended December 31, 1999, 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 6, 2000


                                        F-2




                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                            Consolidated Balance Sheets

                            December 31, 1999 and 1998


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


                                                      1999          1998   

           Assets

Current assets:
  Cash and cash equivalents (includes 
   restricted cash of $614,300 and 
   $156,200, respectively)                       $29,059,200     34,894,600
  Notes and accounts receivable                   10,263,200      6,024,100

  Inventories                                        577,600        702,400
  Prepaid expenses                                 2,360,100      2,496,100

                  Total current assets            42,260,100     44,117,200


Properties and equipment:
  Oil and gas properties (successful
   efforts accounting method)                    105,837,900     81,592,700
  Pipelines                                        8,643,400      7,669,700
  Transportation and other equipment               2,686,800      2,332,200
  Land and buildings                               1,181,000      1,152,700

                                                 118,349,100     92,747,300

  Less accumulated depreciation,
   depletion and amortization                     31,207,300     27,356,700

                                                  87,141,800     65,390,600

Other assets                                       2,681,700      1,901,200

                                                                           

                                                $132,083,600    111,409,000
</TABLE>










                                                                           
(Continued)



                                        F-3




                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                            Consolidated Balance Sheets

                            December 31, 1999 and 1998

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


                                                        1999              1998 

        Liabilities and Stockholders' Equity

Current liabilities:
  Accounts payable                                 $ 14,678,900     11,218,900 
  Accrued taxes                                         276,400           -    
  Other accrued expenses                              2,643,700      1,959,900 
  Advances for future drilling contracts             25,137,400     28,320,800 
  Funds held for future distribution                  2,027,600        984,200 

                  Total current liabilities          44,764,000     42,483,800 

Long-term debt                                        9,300,000          -     
Other liabilities                                     3,160,600      2,233,500 
Deferred income taxes                                 4,134,100      3,945,000 

Commitments and contingencies 

Stockholders' equity:
  Common stock, par value $.01 per share;
    authorized 50,000,000 shares; issued and
    outstanding 15,737,795 and 15,510,762               157,400        155,100 
  Additional paid-in capital                         32,071,000     31,873,100 
  Warrants outstanding                                     -            46,300 
  Retained earnings                                  38,496,500     30,672,200 


                  Total stockholders' equity         70,724,900     62,746,700 

                                                   $132,083,600    111,409,000 

</TABLE>


See accompanying notes to consolidated financial statements.














                                        F-4
                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                         Consolidated Statements of Income

                   Years Ended December 31, 1999, 1998 and 1997

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

                                                  1999         1998            1997  
Revenues:

  Oil and gas well drilling operations        $42,115,600   40,447,100     34,405,400
  Oil and gas sales                            46,988,100   35,560,300     33,390,200
  Well operations and pipeline income           5,314,500    4,581,000      4,509,300
  Other income                                  2,392,400    2,385,200      1,573,100
                                               96,810,600   82,973,600     73,878,000
Costs and expenses:
  Cost of oil and gas well drilling 
   operations                                  35,507,300   35,047,500     28,033,200
  Oil and gas purchases and production 
   cost                                        44,188,200   33,556,900     30,867,600
  General and administrative expenses           2,801,000    2,490,500      2,318,800
  Depreciation, depletion
   and amortization                             4,031,200    3,253,600      2,660,300
  Interest                                        182,400         -           315,900
                                               86,710,100   74,348,500     64,195,800

        Income before income taxes             10,100,500    8,625,100      9,682,200

Income taxes                                    2,276,200    1,967,100      2,095,400
        Net income                            $ 7,824,300    6,658,000      7,586,800

Basic earnings per common share                   $.50          .43             .67

Diluted earnings per common
 and common equivalent share                      $.48          .41             .61


</TABLE>

See accompanying notes to consolidated financial statements.













                                          F-5
 
                           PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                             Consolidated Statements of Stockholders' Equity

                                 Years Ended December 31, 1999, 1998 and 1997


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

Balance December 31, 1996              10,460,753   $104,600        6,540,500        -       16,427,400      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       31,553,100      46,300    24,014,200      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       31,873,100      46,300    30,672,200      62,746,700 

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                        (97,300)      (900)        (303,100)       -             -           (304,000)
Income tax benefit from the
 exercise of stock options                   -           -            141,700        -             -            141,700 
Warrants expired                             -           -             46,300     (46,300)         -               -    
Net income                                   -           -               -           -        7,824,300       7,824,300 

 Balance December 31, 1999             15,737,795   $157,400       32,071,000        -       38,496,500      70,724,900 

</TABLE>

See accompanying notes to consolidated financial statements.

                                                                    F-6
                            PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                                   Consolidated Statements of Cash Flows

                               Years Ended December 31, 1999, 1998 and 1997

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

                                                         1999             1998             1997    
Cash flows from operating activities:
  Net income                                        $ 7,824,300        6,658,000         7,586,800 
   Adjustment to net income to reconcile
    to cash provided by operating activities:
    Deferred income taxes                               108,900          244,000           107,700 
    Depreciation, depletion and amortization          4,031,200        3,253,600         2,660,300 
    (Gain) Loss from sale of assets                    (501,800)          18,700           (39,600)
    Disposition of leasehold acreage                    618,100          196,200           187,200 
    Amortization of stock award                          12,200           12,200            12,300 
    (Increase) decrease in notes and 
     accounts receivable                             (4,239,100)      (1,100,700)        1,772,600 
    Decrease (increase) in inventories                  124,800         (404,500)          269,300 
    Decrease (increase) in prepaid expenses             312,600             (600)         (998,200)
    (Increase) in other assets                         (750,900)        (911,200)         (453,000)
    Increase in accounts payable
     and accrued expenses                             5,347,300        1,304,000         1,298,400 
    (Decrease) increase in advances for 
     future drilling contracts                       (3,183,400)       5,029,200         4,894,600 
    Increase (decrease) in funds held for
     future distribution                              1,043,400         (675,500)          795,700 

          Total adjustments                           2,923,300        6,965,400        10,507,300 

         Net cash provided by operating
          activities                                 10,747,600       13,623,400        18,094,100 

Cash flows from investing activities:
  Capital expenditures                              (27,758,200)     (26,629,700)      (13,675,100)
  Proceeds from sale of leases                        1,224,200        1,283,600         1,710,900 
  Proceeds from sale of fixed assets                    651,000           56,300            87,600 

         Net cash used in investing
          activities                                (25,883,000)     (25,289,800)      (11,876,600)

Cash flows from financing activities:
  Proceeds from debt                                  9,300,000            -                  -    
  Proceeds from issuance of stock                          -               -            25,048,100 
  Retirement of debt                                       -               -            (5,320,000)

         Net cash provided by 
           financing activities                       9,300,000            -            19,728,100 

Net (decrease) increase in cash 
 and cash equivalents                                (5,835,400)     (11,666,400)       25,945,600 

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

Cash and cash equivalents, end of year             $ 29,059,200       34,894,600        46,561,000 

</TABLE>


See accompanying notes to consolidated financial statements.


                                                    F-7
                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                    Notes to Consolidated Financial Statements

                   Years Ended December 31, 1999, 1998 and 1997

(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, Michigan and Colorado.

      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 year's 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
                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

                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

      The Company has 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
                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                    Notes to Consolidated Financial Statements


      Reclassifications

      Certain items and amounts reported in the 1998 and 1997 consolidated
      finnancial statements have been reclassified to conform to the current
      year's reporting format.

      Fair Value of Financial Instruments

      The carrying values and fair values of the Company's receivables,
      payables and debt obligations are estimated to be substantially the
      same as of December 31, 1999, 1998 and 1997.

      New Accounting Standards

        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.  SFAS No. 133
      standardized the accounting for derivative instruments, including
      certain derivative instruments embedded in other contracts.  SFAS No.
      133 is effective for years beginning after June 15, 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, 1999 and 1998, in the amounts of $494,000 and
        $617,900 net of the allowance for doubtful accounts of $216,900 and
        $129,800, respectively.

      The allowance for doubtful current accounts receivable as of December
        31, 1999 and 1998 was $221,500 and $144,800, respectively.

(3)   Long-Term Debt


      On June 22, 1999 the Company executed an Amendment to its Credit
        Agreement with First National Bank of Chicago.  The amendment
        provides a $20.0 million borrowing base, subject to adequate oil and
        gas reserves.  The Company has activated $10.0 million of such
        borrowing base, and has at its discretion the ability to activate the
        additional $10.0 million.  The Company is required to pay a
        commitment fee of 1/4 percent on the unused portion of the activated
        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, 2002.  

      As of December 31, 1999 the outstanding balance was $9,300,000 of which
        $6,300,000 is at a prime rate of 8.5% and $3,000,000 at a LIBOR rate
        of 7.73%. At December 31, 1998 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
                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>
                                1999             1998          1997   
      Current:
       Federal              $1,434,300        1,197,800     1,349,600 
       State                   733,000          525,300       638,100 
        Total current
         income taxes        2,167,300        1,723,100     1,987,700 

      Deferred:
       Federal                 (65,300)            (500)      (32,100)
       State                   174,200          244,500       139,800 
        Total deferred
         income taxes          108,900          244,000       107,700 

        Total taxes         $2,276,200        1,967,100     2,095,400 
</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>
                                   1999         1998        1997  
                                  Amount       Amount      Amount 
Computed "expected" tax       $3,434,200    2,932,500   3,291,900 
State income tax                 598,800      508,100     513,400 
Percentage depletion            (612,000)    (343,400)   (263,500)
Nonconventional source
 fuel credit                    (846,800)    (696,700)   (846,400)
Adjustments to valuation
 allowance                      (375,000)    (473,200)   (565,200)
Other                             77,000       39,800     (34,800)
                              $2,276,200    1,967,100   2,095,400 
</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, 1999 and 1998 are presented below:

<TABLE>
<C>                                               <C>            <C>
                                                 1999           1998   
Deferred tax assets:
  Allowance for doubtful accounts           $   175,400        108,600 
  Drilling notes                                105,700        109,200 
  Alternative minimum tax credit
   carryforwards (Section 29)                 1,982,300      1,783,000 
  Future abandonment                            273,100           -    
  Deferred compensation                       1,213,800        968,500 
  Other                                          51,600        148,300 
    Total gross deferred tax assets           3,801,900      3,117,600 
    Less valuation allowance                       -          (375,000)
    Deferred tax assets                       3,801,900      2,742,600 
    Less current deferred tax assets
      (included in prepaid expenses)         (1,007,600)      (927,400)
    Net non-current deferred 
      tax assets                              2,794,300      1,815,200 
Deferred tax liabilities:
  Plant and equipment, principally
   due to differences in
   depreciation and amortization             (6,928,400)    (5,760,200)
    Total gross deferred
     tax liabilities                         (6,928,400)    (5,760,200)
    Net deferred tax liability              $(4,134,100)    (3,945,000)
</TABLE>



                                                                   (Continued)
                                       F-12
                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                    Notes to Consolidated Financial Statements

      The net changes in the total valuation allowance were decreases of
      $375,000, $473,200 and $782,300 for the years ended December 31, 1999,
      1998 and 1997, respectively. 

      At December 31, 1999, the Company has alternative minimum tax credit
      carryforwards (Section 29) of approximately $1,982,300 which are
      available to reduce future federal regular income taxes over an
      indefinite period.  

(5)   Common Stock

      Options

      Options amounting to 145,000, 20,000 and 500,000 shares were granted
      during 1999, 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 six month period for the 1999 grant and a two
      year period for the 1998 and 1997 grants.  The outstanding options
      expire from 2000 to 2009.

      The estimated fair value of the options granted during 1999, 1998 and
      1997 was $2.44, $3.92 and $3.30 per option, respectively.  The fair
      value was estimated using the Black-Scholes option pricing model with
      the following assumptions for the 1999, 1998 and 1997 grant,
      respectively:  risk-free interest rate of 5.1%, 5.9% and 6.3%, expected
      dividend yield of 0%, expected volatility of 61.3%, 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, 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

Granted                                     145,000         $3.75     3.75 - 3.75
Exercised                                  (324,333)        $0.94     .94 -  .94 
Expired                                        -            $ -           -      

Outstanding December 31, 1999             1,388,984         $2.87     .94 -  6.13
</TABLE>


   As of December 31, 1999, there were 723,984 options outstanding and
exercisable in the $.94 to $1.62 exercise price range which have a weighted
average remaining contractual life of 2.7 years and weighted average
exercise price of $1.05.  Also as of December 31, 1999 there were 665,000
options outstanding and exercisable at a $3.75 to $6.13 exercise price range
having a weighted average remaining contractual life of 7.9 years and
weighted average exercise price of $4.86.





                                                                   (Continued)
                                       F-13

                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>         

                                      1999                         1998          
                             As Reported    Pro Forma     As Reported    Pro Forma

       Net income            $7,824,300    $7,336,200     $6,658,000    $5,918,800

       Basic earnings 
       per share               $ .50           $ .47         $ .43          $ .38

       Diluted earnings
       per share               $ .48           $ .45         $ .41          $ .37
</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 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.  The warrants were not exercised and expired on
      September 15, 1999.  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 was 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

                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                    Notes to Consolidated Financial Statements

(6)   Employee Benefit Plans

   The Company made 401-K Plan contributions of $217,400, $202,600 and
      $171,300 for 1999, 1998 and 1997, respectively.  

   The Company has a profit sharing plan (the Plan) covering full-time
      employees.  The Company contributed $47,000, $17,000 and $15,500, to
      the plan in cash during 1999, 1998 and 1997, respectively.

   During 1999, 1998 and 1997 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.  The unamortized stock
      award is being amortized to expense over the employees' expected years
      to retirement and amounted to $12,200, $12,200 and $12,300 in 1999,
      1998 and 1997, respectively.

   At December 31, 1999 and 1998, the Company has recorded as other assets
      $300,000 and $240,000, 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

   Basic earnings per share is based on the weighted average number of
      common share outstanding of 15,734,063 for 1999, 15,505,680 for 1998,
      and 11,278,800 for 1997.

   Diluted earnings per share is based on the weighted average number of
      common and common equivalent shares outstanding of 16,286,852 for 1999,
      16,338,298 for 1998 and 12,540,165 for 1997.   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 $24,002,500
      in 1999, $22,997,300 in 1998 and $22,985,400 in 1997 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 $10,322,500 in 1999, $9,621,700 in
      1998 and $8,113,000 in 1997 for those services.  

   During 1999, 1998 and 1997, the Company paid $31,600, $30,000 and
      $63,800, respectively to the Corporate Secretary's law firm for various
      legal services.


                                                                    (Continued)





                                       F-15
                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 1999 or 1998.  One customer, Hope
      Gas, Inc., a regulated public utility accounted for 12.0% of total
      revenue in 1997.

   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 $759,000.  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 $124,200, $0, and $380,000 for interest in 1999, 1998
      and 1997, respectively.  The Company paid income taxes in 1999, 1998
      and 1997 in the amounts of $1,327,800, $2,349,100 and $1,932,500,
      respectively.

(11)  Acquisitions

   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.

   On January 29, 1999, the Company offered to purchase from Investors their
      units of investment in the Company's Drilling Programs formed prior to
      1996.  The Company purchased approximately $1.8 million of producing
      oil and gas properties in conjunction with this offer, which expired on
      March 31, 1999.  The Company utilized capital received from its Public
      Stock Offering to fund this purchase.

                                                                   (Continued)
                                       F-16

                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                    Notes to Consolidated Financial Statements



   On December 15, 1999, the Company purchased all of the working interest
      in 53 producing wells in the D-J Basin of Colorado.  The Company
      estimates that the purchase includes proved developed reserves of
      approximately 3.6 Bcf of natural gas and 370,000 barrels of oil or
      approximately 5.8 Bcf equivalent (Bcfe), along with another 3.0 Bcfe of
      proved undeveloped reserves.  Also included in the acquistion was 16.5
      net development drilling locations.  The total acquisition cost for the
      wells and locations was $5.2 million.  The company utiltized part of
      its existing line of credit to fund the transaction.  The effective
      date of the transaction was December 1, 1999.

(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, 1999 and 1998, the Company had futures contracts for
      the purchase of $4,318,000 and $1,120,300 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 $350,500 at December 31, 1999 and $(105,400) at December 31, 1998.

   The Company is required to maintain margin deposits with brokers for
      outstanding futures contracts.  As of December 31, 1999 and 1998, cash
      in the amount of $614,300 and $156,200 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,     
                                           1999            1998           1997   
   Property acquisition cost:
     Proved undeveloped
     properties                         $2,532,200       1,903,200      3,109,000
     Producing properties                6,997,500       8,679,000         85,100
   Development costs                    17,168,000      14,902,500      9,863,200
                                       $26,697,700      25,484,700     13,057,300
</TABLE>







                                                                   (Continued)
                                       F-17
                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,        
                                                 1999             1998   
Proved properties:
  Tangible well equipment                   $ 62,996,900       46,722,500
  Intangible drilling costs                   36,270,300       28,379,200
  Well equipment leased to others              4,063,600        4,063,600
  Undeveloped properties                       2,507,100        2,427,400
                                             105,837,900       81,592,700
     Less accumulated depreciation,
      depletion and amortization              23,652,000       20,395,400
                                            $ 82,185,900       61,197,300
</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,     
                                              1999          1998        1997   
      Revenue:
        Oil and gas sales                 $8,628,400    6,121,700     5,363,600
      Expenses:
        Production costs                   2,422,000    1,516,700     1,206,000
        Depreciation, depletion
          and amortization                 3,220,900    2,392,000     1,629,900
                                           5,642,900    3,908,700     2,835,900
        Results of operations for
         oil and gas producing
         activities before provision
         for income taxes                  2,985,500    2,213,000     2,527,700

      Provision for income taxes             469,400      398,600       567,800

        Results of operations for oil
         and gas producing activities
         (excluding corporate over-
         head and interest costs)         $2,516,100    1,814,400     1,959,900
</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

                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, 1999, 1998 and 1997.  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)              
                                            1999            1998           1997  
Proved developed and
 undeveloped reserves:
   Beginning of year                         29,000         45,000        81,000 
   Revisions of previous estimates           67,000        (10,000)      (27,000)
   Beginning of year as revised              96,000         35,000        54,000 
   New discoveries and extensions           404,000           -             -    
   Dispositions                                -              -             -    
   Acquisitions                             662,000          2,000          -    
   Production                                (8,000)        (8,000)       (9,000)
   End of year                            1,154,000         29,000        45,000 
Proved developed reserves:
   Beginning of year                         29,000         45,000        81,000 
   End of year                              798,000         29,000        45,000 

                                                        Gas (MCF)                
                                             1999           1998          1997   
Proved developed and
 undeveloped reserves:
   Beginning of year                     80,819,000     57,243,000    43,312,000 
   Revisions of previous estimates       (4,475,000)    (3,517,000)      875,000 
   Beginning of year as revised          76,344,000     53,726,000    44,187,000 
   New discoveries and extensions        24,781,000     23,552,000     2,489,000 
   Dispositions to partnerships          (8,774,000)    (6,009,000)         -    
   Acquisitions, net of sales to
      partnerships in 1997               12,345,000     12,003,000    12,377,000 
   Production                            (3,451,000)    (2,453,000)   (1,810,000)
   End of year                          101,245,000     80,819,000    57,243,000 
 Proved developed reserves:
   Beginning of year                     64,562,000     42,411,000    35,516,000 
   End of year                           82,628,000     64,562,000    42,411,000 

</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

                PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

                    Notes to Consolidated Financial Statements

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

                                                   Years Ended December 31,      
                                            1999            1998          1997   
      Future estimated cash flows      $307,816,000    186,598,000   159,618,000 
      Future estimated production
        and development costs          (129,557,000)   (95,670,000)  (69,265,000)
      Future estimated income
        tax expense                     (39,930,000)   (20,322,000)  (20,781,000)
        Future net cash flows           138,329,000     70,606,000    69,572,000 
      10% annual discount for
        estimated timing of cash
        flows                           (79,875,000)   (40,412,000)  (41,636,000)
        Standardized measure of
         discounted future
         estimated net cash flows      $ 58,454,000     30,194,000    27,936,000 
</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,      
                                            1999            1998           1997  
        Sales of oil and gas
         production, net of 
         production costs               $(6,206,000)    (4,605,000)   (4,158,000)
        Net changes in prices
         and production costs            29,547,000    (23,083,000)  (63,573,000)
        Extensions, discoveries
         and improved recovery,
         less related cost               39,653,000     18,615,000     3,705,000 
        Dispositions to partnerships     (6,152,000)    (5,762,000)         -    
        Acquisitions, net of sales
         to partnerships in 
         1997                            31,915,000     13,938,000    13,299,000 
        Development costs incurred
         during the period               17,168,000     14,903,000     9,863,000 
        Revisions of previous
         quantity estimates              (4,944,000)    (5,605,000)    2,332,000 
        Changes in estimated
         income taxes                   (19,608,000)       459,000    12,718,000 
        Changes in discount             (39,463,000)     1,224,000    24,597,000 
        Changes in production rates
         (timing) and other             (13,650,000)    (7,826,000)   (5,109,000)
                                      $  28,260,000      2,258,000    (6,326,000)
</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

                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, commercial 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, 1999, 1998 and 1997 is as follows:

<TABLE>
            <C>                                    <C>             <C>           <C>
                                                  1999           1998          1997  

   REVENUES
     Drilling and Development                    $42,116         40,447       34,406 
     Natural Gas Sales                            46,988         35,560       33,390 
     Well Operations                               5,314          4,581        4,509 
     Unallocated amounts (1)                       2,392          2,385        1,573 
   Total                                         $96,810         82,973       73,878 
</TABLE>

   (1) Includes interest on investments, partnership management fees and gain on
   sale of assets in 1999 which are not allocated in assessing segment
   performance.

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

                                                  1999           1998          1997  
   SEGMENT INCOME BEFORE INCOME TAXES
     Drilling and Development                     $6,608          5,400        6,372 
     Natural Gas Sales                             2,967          2,064        2,780 
     Well Operations                               1,219          1,372        1,701 
     Unallocated amounts (2)
           General and Administrative 
            expenses                              (2,801)        (2,491)      (2,660)
           Interest expense                         (182)          -            (316)
           Other (1)                               2,289          2,280        1,805 
   Total                                         $10,100          8,625        9,682 
</TABLE>

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

<TABLE>
            <C>                                    <C>            <C>            <C>
                                                  1999           1998          1997  
   SEGMENT ASSETS
     Drilling and Development                    $23,957         27,288       22,110 
     Natural Gas Sales                            93,073         65,256       45,888 
     Well Operations                               7,977          7,136        5,953 
     Unallocated amounts 
       Cash                                        1,967          7,814       20,942 
       Other                                       4,934          3,806        3,519 
           Total                                $131,908        111,300       98,412 

                                                  1999           1998          1997  
   EXPENDITURES FOR SEGMENT 
   LONG-LIVED ASSETS
     Drilling and Development                    $ 1,710          1,953        2,862 
     Natural Gas Sales                            24,613         23,645       10,207 
     Well Operations                               1,328            947          505 
     Unallocated amounts                             107             85          101 
           Total                                 $27,758         26,630       13,675 
</TABLE>

                                         F-21

                  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, 1999 and
     1998, are as follows:

<TABLE>
<C>                        <C>           <C>         <C>           <C>            <C>
                                            1999                            
                                        Quarter                                Year 

                        First        Second        Third       Fourth    
Revenues              $27,666,300   $21,064,000  $23,841,700  $24,238,600   $96,810,600
Cost of operations     23,837,400    18,411,200   20,038,900   21,439,200    83,726,700
 Gross profit           3,828,900     2,652,800    3,802,800    2,799,400    13,083,900
General and
 administrative
 expenses                 464,400       595,800      859,200      881,600     2,801,000
Interest expense             -             -          88,100       94,300       182,400
                          464,400       595,800      947,300      975,900     2,983,400
Income before
 income taxes           3,364,500     2,057,000    2,855,500    1,823,500    10,100,500
Income taxes              753,700       460,700      842,000      219,800     2,276,200
 Net income            $2,610,800   $ 1,596,300  $ 2,013,500  $ 1,603,700   $ 7,824,300
 Basic earnings
 per share               $ .17          $ .10         $ .13       $ .10        $ .50
 Diluted earnings
 per share               $ .16          $ .10         $ .12       $ .10        $ .48

                                            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
</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
                  PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

 
                   SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
                                     AND RESERVES

                     Years Ended December 31, 1999, 1998 and 1997



<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
     1999                   $274,600         $272,500         $108,700       $438,400

     1998                   $275,400         $ 46,800         $ 47,600       $274,600

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

</TABLE>





































                                           F-23




                      The First National Bank of Chicago
                           One First National Plaza
                            Chicago, Illinois 60670
         
                           Dated as of June 22, 1999
         
         Petroleum Development Corporation
         103 E. Main Street
         P.O. Box 26
         Bridgeport, West Virginia 26330
         
         Attention:     Mr. Dale C. Rettinger
         
            Re:   First Amendment to Credit Agreement
         
         Ladies and Gentlemen:
         
      ARTICLE I. Amendments. Upon the conditions set forth in Article III being
fulfilled, the Credit Agreement dated as of March 13, 1997 (the "Credit
Agreement"), between Petroleum Development Corporation (the "Company"), and The
First National Bank of Chicago (the "Bank"), shall be amended as follows:
         
      1.1   I 1 The pricing matrix in the definition of "Applicable LIBOR Rate
Margin" in Section 1. 1 shall be deleted and replaced with the following pricing
matrix:

                                                            LIBOR Rate
      Percentage of Borrowing Base Used                     Margin
      Less than 25%                                         1.00%
      Greater than or equal to 25% but less than 50%        1.25%
      Greater than or equal to 50% but less than 75%        1.50%
      Greater than or equal to 75%                          1.75%
         
      1.2   The definition of "First Amendment Date" is added to Section 1.1, to
read as follows:

            "First Amendment Date" shall mean June 22. 1999.
         
      1.3   The definition of "Termination Date" in Section 1.1 shall be amended
and restated, to read as follows:
         
            "Termination Date" shall mean the earlier to occur of (a) December

31, 2002, and (b) the date on which the Commitment shall be terminated pursuant
to Section 2.2 or S.2.
         
      1.4   Section 4.4(a) is amended and restated, to read as follows:
Petroleum Development corporation
Dated as of June 22, 1999
Page 2

            (a)   The Company agrees to pay to the Bank a commitment fee
      computed at the rate of one-quarter of one percent (0.25%) per annum on
      the amount by which the Commitment exceeds the aggregate outstanding
      principal amount of the Advances and any Rate Hedging Obligations, for the
      period from the Effective Date until the Termination Date. This fee shall
      be paid quarterly in arrears, on the last Business Day of each January,
      April, July, and October and on the Termination Date, commencing on such
      date after the Effective Date.
         
      1.5   Section 4.4(d) is amended and restated, to read as follows:

            (d)   The Company agrees to pay to the Bank a facility fee each time
the Bank increases the amount of the Commitment pursuant to Section 2.3 of this 
Agreement, which facility fee shall be computed at the rate of one-quarter of 
one percent (0.25%) of the amount by which the Bank increases the amount of the
Commitment.

      1.6   Section 7.2(a) is amended and restated, to read as follows:

            (a)   Tangible Net Worth. Permit or suffer the Consolidated 
      Tangible Net Worth of the Company and its Subsidiaries to be less than (1)
      $45,000,000 at any time during the period from and including the First
      Amendment Date to and including December 31, 1999, and (ii) the sum of
      $45,000,000 plus an amount equal to 50% of the Consolidated Net Income of
      the Company and it Subsidiaries for each fiscal year of the Company
      thereafter, to be added as of the end of each fiscal year commencing with
      the fiscal year ending December 31, 2000, provided that if the
      Consolidated Net Income of the Company and its Subsidiaries negative in
      any fiscal year. the amount added for such fiscal year shall be zero.

      1.7   1.7  The Bank shall adjust the Borrowing Base to equal $22,000,000
from and after the First Amendment Date, and the Bank does not now anticipate
redetermining the Borrowing Base before June 1, 2000, absent the earlier
occurrence of a Default or Event of Default, or the Company selling material
assets included in calculating the Borrowing Base.
         
      1.8   Schedule 6.17 shall be amended and restated, to read as set forth on
Schedule 6.17 attached hereto.

      ARTICLE II. Representations and Warranties. In order to induce the Bank to
amend the Credit Agreement as set forth herein, the Company represents and
warrants as follows:
         
      2.1.  The representations and warranties contained in the Credit Agreement
and in each other document executed and delivered in connection therewith are
true and correct as of the date hereof, as if such representations and 
warranties were made on and as of the date hereof.
Petroleum Development Corporation
Dated as of June 22, 1999
Page 3

      2.2.  No Default or Event of Default under the Credit Agreement exists or
has occurred and is continuing on the date hereof, both before and after giving
effect to this letter amendment, other than defaults which have been cured as of
the date of execution hereof by the Company.

      ARTICLE III. Conditions of Effectiveness. This Amendment shall not become
effective until each of the following has been satisfied:

      3.1   The Company delivers to the Bank copies of resolutions adopted by 
the Board of Directors of the Company, certified by an officer of the Company as
being true and correct and in fill force and effect, without amendment as of the
date hereof, authorizing the Company to enter into this Amendment and any other
documents or agreements executed pursuant hereto.

      3.2   This Amendment shall be signed by the Company and the Bank.

      3.3   The Company shall have executed a Confirmation of Security Documents
and, if requested by the Bank (which request has not been made at this time),
shall provide the Bank with updated schedules and exhibits to the Security
Documents and shall take such other action as the Bank may reasonably consider
necessary or proper to establish, maintain, or continue a perfected and valid
security interest of the Bank in the Collateral.
         
      3.4   The Company shall pay to the Bank a closing fee of $25,000.

      3.5   Each of the Guarantors delivers to the Bank copies of resolutions
adopted by the Board of Directors of each of the Guarantors, certified by an
officer of the Guarantors, respectively, as being true and correct and in full
force and effect, without amendment as of the date hereof, authorizing the
Guarantors to enter into a Confirmation of Guaranty and any other documents or 
agreements executed pursuant hereto.
         
      3.6   Each of the Guarantors shall have executed a Confirmation of
Guaranty.

ARTICLE IV. Miscellaneous.

      4.1   References in the Credit Agreement to "this Agreement" and 
references in any note, certificate, instrument, or other document to the 
"Credit Agreement" shall be deemed to refer to the Credit Agreement as 
amended hereby and as further amended from time to time.

      4.2   The Company agrees to pay and to save the Bank harmless for the
payment of all costs and expenses arising in connection with this Amendment,
including the reasonable fees of counsel to the Bank in connection with 
preparing this Amendment and the related documents.

      4.3   The Company acknowledges and agrees that the Bank has fully 
performed all of its obligations under all documents executed in connection 
with the Credit Agreement and all actions taken by the Bank are reasonable 
and appropriate under the circumstances and within its rights under the 
Credit Agreement and all other documents executed in connection therewith
and otherwise available. 







Petroleum Development Corporation
Dated as of June 22, 1999
Page 4

The Company represents and warrants that it is not aware of any claims or causes
of action against the Bank, or any of its successors or assigns. Notwithstanding
this representation and as further  consideration for the agreements and
understandings herein, the Company and its heirs, successors and assigns,
release the Bank and its successors and assigns from any liability, claim,
right or cause of action which now exists or hereafter arises, whether known
or unknown, arising from or in any way related to facts in existence as of 
the date hereof to any agreements or transactions between the Bank and the 
Company or to any acts or omissions of the Bank in connection therewith or 
otherwise. 
         
      4.4   Except as expressly amended hereby, the Company agrees that the
Credit Agreement, the promissory note, and all other documents and agreements
executed by the Company in connection with the Credit Agreement in favor of the
Bank are ratified and confirmed and shall remain in full force and effect, and
that it has no set off, counterclaim, or defense with respect to any of the
foregoing. Terms used but not defined herein shall have the respective meanings
ascribed thereto in the Credit Agreement.
         
      4.5   This Amendment shall be governed by and construed in accordance with
the laws of the State of Michigan.

      4.6   This Amendment may be signed in any number of counterparts with the
same effect as if the signatures thereto and hereto were upon the same
instrument.
         
      If the foregoing is acceptable to you, as it is to us, please execute each
of the enclosed copies of this letter amendment and return them to us.

                                          Very truly yours,
                                          THE FIRST NATIONAL BANK OF CHICAGO

                                          By  /s/ Joseph C. Giampetroni
                                                Joseph C. Giampetroni
                                          Its:   Vice President
         
Agreed and Accepted as of the
date set forth above:

PETROLEUM DEVELOPMENT CORPORATION

By: /s/ Dale G. Rettinger
         Dale G. Rettinger
         Its: Executive Vice President
         


         DETROIT 7-2487 438227




                     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                                                                         
                                                   1999           1998            1997    
 
Net income for basic income 
 per common share                             $ 7,824,300       6,658,000       7,586,800 

Weighted average number of common shares 
 outstanding during the year                   15,734,063      15,505,680      11,278,800 

Basic earnings per share                      $      .50       $     .43      $       .67

            DILUTED

Net income for basic earnings per
 common share                                 $ 7,824,300       6,658,000     $ 7,586,800 

      Net income for diluted
       earnings per share                     $ 7,824,300       6,658,000     $ 7,586,800 

      Weighted average number of shares
       used in calculating basic earnings
       per common share                        15,734,063      15,505,680      11,278,800 

  Shares issuable for diluted calculation         552,789         832,618       1,261,365 

      Weighted average number of shares
       used in calculation of 
       diluted earnings per share              16,286,852      16,338,298      12,540,165 

Diluted earnings per share                    $      .48      $      .41      $       .61


</TABLE>






















                                            





<TABLE> <S> <C>

<ARTICLE>  5
       
<S>                             <C>
<PERIOD-TYPE>                   12-MOS
<FISCAL-YEAR-END>                          DEC-31-1999
<PERIOD-END>                               DEC-31-1999
<CASH>                                      29,059,200
<SECURITIES>                                         0
<RECEIVABLES>                               10,263,200
<ALLOWANCES>                                   438,400
<INVENTORY>                                    577,600
<CURRENT-ASSETS>                            42,260,100
<PP&E>                                     118,349,100
<DEPRECIATION>                              31,207,300
<TOTAL-ASSETS>                             132,083,600
<CURRENT-LIABILITIES>                       44,764,000
<BONDS>                                              0
<PREFERRED-MANDATORY>                                0
<PREFERRED>                                          0
<COMMON>                                       157,400
<OTHER-SE>                                  70,567,500
<TOTAL-LIABILITY-AND-EQUITY>               132,083,600
<SALES>                                     46,988,100
<TOTAL-REVENUES>                            96,810,600
<CGS>                                       44,188,200
<TOTAL-COSTS>                               86,710,100
<OTHER-EXPENSES>                                     0
<LOSS-PROVISION>                               272,500
<INTEREST-EXPENSE>                             182,400
<INCOME-PRETAX>                             10,100,500
<INCOME-TAX>                                 2,276,200
<INCOME-CONTINUING>                          7,824,300
<DISCONTINUED>                                       0
<EXTRAORDINARY>                                      0
<CHANGES>                                            0
<NET-INCOME>                                 7,824,300
<EPS-BASIC>                                      .50
<EPS-DILUTED>                                      .48
        

</TABLE>