10-K

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, 2000

     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, 2001, 16,244,044 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 $ 74,607,760 (based on the last traded price of $6.375).

DOCUMENTS INCORPORATED BY REFERENCE

Document	Form 10-K Part III
Proxy	Items 11 and 12

PART I

Item 1. Business

     The Company is an independent energy company engaged primarily in the development, production and marketing of natural gas and oil. The Company has grown primarily through drilling and development activities, the acquisition of natural gas and oil producing wells and the expansion of its natural gas marketing activities. As of December 31, 2000, the Company operates approximately 2,025 wells located in the Appalachian basin, Michigan, and the Rocky Mountain Region, with gross proved reserves of 307 Bcfe of natural gas of which the Company's share is 132 Bcfe of natural gas. The wells operated by the Company currently produce an aggregate of approximately 47,000 thousand cubic feet equivalent ("Mcfe", based on one barrel of oil equals 6 thousand cubic feet "Mcf" of gas.) of natural gas per day, of which the Company's share is approximately 19,500 Mcfe.

     The Company's operations are divided into three regions, the Appalachian Basin, Michigan, and the Rocky Mountains. The Company has conducted operations in Appalachia since its inception in 1969, in Michigan since 1997, and the Rocky Mountains since 1999. As of the end of 2000 approximately 39% of production was generated by Appalachian Basin wells, 36% by Michigan wells, and 25% by Colorado wells. At the end of 2000 the Company's reserves were divided almost equally among three regions, with all of the recorded proved undeveloped reserves in Michigan and Colorado. This reflects the planned drilling for 2001, which will be focused in Colorado and to a lesser extent in Michigan.

     In all three regions the Company has historically targeted shallow, developmental natural gas reserves for development. In most areas of Colorado the wells also produce oil in conjunction with natural gas. In one of our areas in Michigan, oil is the dominant economic product. The Company is also investigating the potential for deeper exploratory wells in the Rocky Mountain region, with plans to include several exploratory prospects in its 2001 drilling plans.

     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 2000, the Company raised $55.6 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 22.7 Tcf of natural gas consumed in 2000 represented approximately 23% of the total energy used in the United States. Natural gas is consumed in the United States as follows: 45% by industrial end-users as feedstock for products such as plastic and fertilizer or as the energy source for producing products such as glass; 22% and 16% by residential and commercial end-users, respectively, for uses including heating, cooling and cooking; 12% by utilities for the generation of electricity; and the remainder for transportation purposes. (Source U.S. Energy Information Administration)

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     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.

     -  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 regions. The natural gas industry in the Appalachian Basin and Michigan benefit from 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.

     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. 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. The Company expanded its operations in the Rocky Mountains in 2000, by drilling 52 successful wells and adding over 50,000 acres to its position in the Wattenberg and Grand Valley fields. The Company plans to do the majority of its development work in these areas in 2001.

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:

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     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 97 wells in 2000, compared to 178 for the year of 1999. The decrease in the number of wells drilled results primarily from the greater cost of the Rocky Mountain wells compared to the Company's Appalachian and Michigan wells. 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, 2000, the Company had 11,000 undeveloped acres in the Michigan Basin, 12,900 undeveloped acres in the Appalachian Basin and 164,600 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.

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.

Prospect Generation

     The Company's staff of professional geologists is responsible for identifying areas with potential for economic production of natural gas and oil. These geologists have decades of cumulative drilling of successful, economically feasible natural gas and oil wells. They utilize 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.

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     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, 2000, the Company had a total leasehold inventory of approximately 294,040 acres. See--"Properties--Natural Gas Leases."

Drilling Activities

     When prospects have been identified and leased, the Company develops these properties by drilling wells. In 2000, the Company drilled a total of 97 wells, with no 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.

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. During 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. During 2000, the Company purchased 100% of the working interest in 168 producing wells in the DJ Basin of Colorado which added 4.9 Bcf of natural gas and 560,000 barrels of oil to the Company's reserves. Also purchased in 1998, 1999 and 2000 were certain well interests in its Company sponsored partnerships.

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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.

	Year Ended December 31,
	2000	1999	1998	1997	1996
Production(1):
Oil(MBbls)	109	8	8	9	7
Natural Gas (MMcf)	5,737	3,451	2,453	1,810	1,495
Equivalent MMcfs(2)	6,391	3,499	2,501	1,864	1,537
Average sales price:
Oil (per Bbl)	$29.99	$18.75	$10.61	$16.10	$16.35
Natural gas (per Mcf)(3)	$2.74	$2.46	$2.46	$2.88	$3.04
Average production cost  (lifting cost) per  equivalent Mcf(4)	$0.66	$0.69	$0.61	$0.65	$0.63

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(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) The Company utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price volatility of its natural gas sales. The effect of hedges on the average sales price of natural gas for the years ended December 31, 2000, 1999 and 1998 was $(0.91), $(0.01) and $0.14, respectively.

(4) 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 wells in the Appalachian Basin, 209 wells in the Michigan Basin and 277 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 52% ownership interest in the wells it operates. Currently these wells produce an aggregate of about 47,000 Mcfe of natural gas per day, including the Company's share of 19,500 Mcfe 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.

Transportation

     Natural gas wells are connected by pipelines to natural gas markets. Over the years, the Company has developed extensive gathering systems in some of 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.

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     The Company had an Ohio subsidiary, Paramount Natural Gas Company ("PNG"), which commenced operations in October 1992 as a regulated Ohio distribution utility. In 2000, all of the assets of PNG were sold and the Company ceased operations as an Ohio utility.

Item 2. Properties

Drilling Activity

     The following table summarizes the Company's development drilling activity for the years ended December 31, 1996, 1997, 1998, 1999 and 2000. 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.

	Development Wells Drilled
	Total		Productive		Dry
	Drilled	Net	Drilled	Net	Drilled	Net
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
2000	97	27.39	97	27.39	-	-
Total	747	197.18	713	189.17	34	8.01

Summary of Productive Wells

The table below shows the number of the Company's productive gross and net wells at December 31, 2000.

	WELLS
	Gas		Oil
Location	Gross	Net	Gross	Net
Colorado	277	228.02	-	-
Michigan	206	110.20	3	1.42
Ohio	16	7.35	5	2.34
Pennsylvania	539	162.89	-	-
Tennessee	1	0.71	39	15.87
West Virginia	932	520.20	6	2.58
Total	1,971	1,029.37	53	22.21

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 118,640,000 MCf of natural gas and 2,166,000 Bbls of oil at December 31, 2000, 101,245,000 Mcf of natural gas and 1,154,000 Bbls of oil at December 31, 1999, and 80,819,000 Mcf of natural gas and 29,000 Bbls of oil at December 31, 1998.

     The Company's approximate net proved developed reserves were estimated, by Wright & Company to be 92,131,000 Mcf of natural gas and 1,527,000 Bbls of oil at December 31, 2000, 82,628,000 Mcf of natural gas and 798,000 Bbls of oil at December 31, 1999, and 64,562,000 Mcf of natural gas and 29,000 Bbls of oil at December 31, 1998.

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     The Company's reserves by region are as follows as of December 31, 2000:

	Oil (Mbbl)	Gas (Mmcf)	MCFE (Mmcfe)	%
Developed Reserves
Appalachian	60	46,888	47,248	46.65%
Michigan	54	30,777	31,101	30.70%
Rocky Mountains	1,413	14,466	22,944	22.65%
Total Developed Reserves	1,527	92,131	101,293	100.00%
Proved Undeveloped
Appalachian	0	0	0	0.00%
Michigan	240	8,292	9,732	32.08%
Rocky Mountains	399	18,217	20,611	67.92%
Total Proved Undeveloped	639	26,509	30,343	100.00%
Total Reserves
Appalachian	60	46,888	47,248	35.89%
Michigan	294	39,069	40,833	31.02%
Rocky Mountains	1,812	32,683	43,555	33.09%
Total Reserves	2,166	118,640	131,636	100.00%

     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, 2000. 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 2000, 1999 and 1998 to be $104.6 million as of December 31, 2000, $58.5 million as of December 31, 1999 and $30.2 million as of December 31, 1998. These amounts are based on year-end prices, adjusted for hedging contracts 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.

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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, 2000 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, 2000 to December 31, 2000, all of which are located within the United States, is shown below:

	Natural Gas (Mcf)	Oil (Bbls)
Proved developed and undeveloped reserves:
Beginning of year (January 1, 2000)	101,245,000	1,154,000
Revisions of previous estimates	(3,859,000)	10,000
Beginning of year as revised	97,386,000	1,164,000
New discoveries and extensions
Michigan	14,191,000	265,000
Wattenberg field	5,681,000	535,000
Piceance basin	8,922,000	-
Appalachian basin	266,000	-
Dispositions to partnerships	(8,498,000)	(262,000)
Acquisitions
Michigan	-	-
Wattenberg field	5,761,000	573,000
Appalachian basin	668,000	-
Production	(5,737,000)	(109,000)
End of period (December 31, 2000)	118,640,000	2,166,000
Proved developed reserves:
Beginning of year (January 1, 2000)	86,628,000	1,154,000
End of period (December 31, 2000)	92,131,000	1,527,000

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, 2000 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.

	December 31, 2000
Future estimated cash flows	$ 520,010,000
Future estimated production costs	(144,505,000)
Future estimated development costs	(50,278,000)
Future estimated income tax expense	(80,982,000)
Future net cash flows	244,245,000
10% annual discount for estimated timing of cash flows	(139,606,000)
Standardized measure of discounted
future estimated net cash flows	$ 104,639,000

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     The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows from January 1, 2000 through December 31, 2000:

Sales of oil and natural gas production,
net of production costs	$(14,816,000)
Net changes in prices and production costs	70,514,000
Extensions, discoveries and improved recovery,
less related costs	73,636,000
Dispositions to partnerships	(16,850,000)
Acquisitions	27,907,000
Development costs incurred during the period	15,556,000
Revisions of previous quantity estimates	(5,925,000)
Changes in estimated income taxes	(41,052,000)
Changes in discount	(59,731,000)
Changes in production rate (timing) and other	(3,054,000)
	$ 46,185,000

     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, 2000, the acres of developed and undeveloped oil and natural gas properties owned by the Company, listed alphabetically by state.

	Developed Areage	Undeveloped Acreage
Colorado	11,100	105,800
Michigan	30,800	11,000
Ohio	740	500
Pennsylvania	8,900	6,200
Tennessee	5,400	-
Utah	-	58,800
West Virginia	48,600	6,200
Total	105,540	188,500

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 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.

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

Natural Gas Sales

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

     The Company sells its natural gas to industrial end-users and utilities. One customer, Cinnabar Energy Services, accounted for 17.7% of the Company's revenues from oil and gas sales (11.3% of total revenues) in 2000. 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. No other single purchaser of the Company's natural gas accounted for 10% or more of the Company's total revenues during 2000, 1999 or 1998.

     At December 31, 2000, natural gas produced by the Company sold at prices per Mcf ranging from $0.90 to $7.73, 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 2000 was $2.74 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.

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 in a deregulated market, 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/manager 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 Company's areas of operations. 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.

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     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.

In late 1999 and the first several months of 2000, the Company established hedges on most of its 2000 production. As a result, the Company realized limited benefit from the rapid increase in natural gas prices during 2000.

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 $55.6 million in subscriptions in 2000, $36.1 million in 1999 and $40.9 million in 1998. 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.

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      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 of 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.

Oil Production

     The Company's acquisition in December 1999 of 53 wells and in April 2000 of 108 wells in the Wattenberg field in Colorado and ongoing development activities in Colorado and Michigan are resulting in significant increase in oil production and reserves. At the end of 2000 oil was about 10% of the Company's total equivalent reserves. Oil production in 2000 was 109,00 barrels, up from 8,000 barrels in 1999.

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 2000, 1999 or 1998. At December 31, 2000, oil produced by the Company sold at prices ranging from $23.25 to $33.43 per barrel, depending upon the location and quality of oil. In 2000, the weighted net average price per barrel of oil sold by the Company was $29.99.

     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.

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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.

Regulation of Oil and Natural Gas Exploration and Production

     The Company's oil and 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 oil and 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 oil and 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 oil and 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.

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     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 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 benefited 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.

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     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 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 2000 were not significant in relation to operating costs and the Company expects no material change in 2001. 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 was 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 (PUCO) 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. All of the assets of PNG were sold during 2000 pursuant to approval by PUCO, and PNG ceased operations as an Ohio utility.

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.

     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.

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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 oil and 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 oil and 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 companies to increase their domestic oil and natural gas exploration. Furthermore, competition among companies for favorable prospects can be expected to continue, and it is anticipated that the cost of acquiring 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 oil and 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, 2000, the Company had 86 employees, including 15 in finance, 6 in administration, 14 in exploration and development, 46 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.

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 Colorado, Michigan and Pennsylvania 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.

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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
2000
First Quarter	4 29/64	3-3/4
Second Quarter	6 1/32	3-7/8
Third Quarter	7 1/8	4 23/32
Fourth Quarter	7	5 3/16
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, 2000, there were approximately 1,266 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.

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Item 6. Selected Financial Data (1)

	Year Ended December 31,
	2000	1999	1998	1997	1996
Revenues  Oil and gas well   drilling operations	$43,194,700	$42,115,600	$40,447,100	$34,405,400	$18,698,200
Oil and gas sales	90,419,700	46,988,100	35,560,300	33,390,200	26,051,100
Well operations   Income	5,061,600	5,314,500	4,581,000	4,509,300	3,928,800
Other income	2,540,500	2,392,400	2,385,200	1,573,100	935,600
Total	$141,216,500	$96,810,600	$82,973,600	$73,878,000	$49,613,700
Costs and Expenses  (excluding interest   and depreciation,   depletion and   amortization)	$118,813,300	$82,496,500	$71,094,900	$61,219,600	$42,274,100
Interest Expense	$1,186,000	$ 182,400	$ -	$ 315,900	$ 380,000
Depreciation,  Depletion and  Amortization	$6,943,500	$ 4,031,200	$ 3,253,600	$ 2,660,300	$ 2,309,600
Net Income	$10,681,000	$ 7,824,300	$ 6,658,000	$ 7,586,800	$ 3,549,400
Basic earnings  per common share	$.66	$.50	$.43	$ .67	$ .34
Diluted earnings  per share	$.65	$.48	$.41	$ .67	$ .34
Average Common and  Common Equivalent  Shares Outstanding  During the Year	16,437,488	16,286,852	16,338,298	12,540,165	11,542,315
	December 31,
	2000	1999	1998	1997	1996
Total Assets	$187,684,500	$132,083,600	$111,409,000	$98,411,600	$63,604,200
Working Capital	$    780,700	$ (2,503,900)	$  1,633,400	$16,483,200	$(2,357,200)
Long-Term Debt,  Excluding current  Maturities	$ 17,350,000	$ 9,300,000	$       -	$     -	$ 5,320,000
Stockholders' Equity	$ 82,256,900	$70,724,900	$ 62,746,700	$55,766,100	$23,072,500

(1) See Consolidated Financial Statements elsewhere herein.

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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, 2000 Compared with December 31, 1999

     Revenues. Total revenues for the year ended December 31, 2000 were $141.2 million compared to $96.8 million for the year ended December 31, 1999, an increase of approximately $44.4 million, or 45.9%. Drilling revenues for the year ended December 31, 2000 were $43.2 million compared to $42.1 for the year ended December 31, 1999, an increase of approximately $1.1 million, or 2.6%. Natural gas sales from the marketing activities of RNG for the year ended December 31, 2000 were $71.4 million compared to $38.4 million for the year ended December 31, 1999, an increase of approximately $33.0 million or 85.9%. Such increase was due to increased volumes of gas sold with higher average sales prices. Oil and gas sales from the Company's producing properties for the year ended December 31, 2000 were $19.0 million compared to $8.6 million for the year ended December 31, 1999, an increase of approximately $10.4 million or 120.9%. Such increase was due to increased production which resulted from acquisitions of producing properties along with new wells drilled and higher average sales prices of natural gas and oil from the Company's producing properties. Financial results depend upon many factors, particularly the price of natural gas and our ability to market our production on economically attractive terms. Price volatility in the natural gas market has remained prevalent in the last few years. From the third quarter of 1998 through the first quarter of 1999, we experienced a decline in energy commodity prices. However, in the summer of 1999 and continuing into early 2000, prices improved. For the months of April through December, 2000, we had certain natural gas hedges in place that prevented us from realizing the full impact of this price environment. Despite this limitation, our realized natural gas price for each month in the year 2000 was higher than the previous year. In the final months of 2000, the NYMEX futures market reported unprecedented natural gas contract prices. During 2000, the hedging activities resulted in oil and gas sales being $5.2 million lower than if the Company had not hedged. Well operations and pipeline income for the year ended December 31, 2000 was $5.1 million compared to $5.3 million for the year ended December 31, 1999, a decrease of approximately $200,000 or 3.8%. Other income for the year ended December 31, 2000 was $2.5 million compared to $2.4 million for the year ended December 31, 1999, an increase of approximately $100,000 or 4.2%.

     Costs and expenses. Costs and expenses for the year ended December 31, 2000 were $126.9 million compared to $86.7 million for the year ended December 31, 1999, an increase of approximately $40.2 million, or 46.4%. Oil and gas well drilling operations costs for the year ended December 31, 2000 were $35.2 million compared to $35.5 million for the year ended December 31, 1999, a decrease of approximately $300,000 or 0.8%.

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     The costs of gas marketing activities for the year ended December 31, 2000 were $71.6 million compared to $38.5 million for the year ended December 31, 1999, an increase of $33.1 million or 86.0%. Such increase was due to the increased gas marketing activity of RNG with increased volumes purchased at higher average sale prices. Based on the nature of the Company's gas marketing activities, hedging did not have a significant impact on the Company's net margins from marketing activities during 2000. Oil and gas production costs from the Company's producing properties for the year ended December 31, 2000 were $8.3 million compared to $5.7 million for the year ended December 31, 1999 an increase of $2.6 million or 45.6%. Such increase was due to the increased production volumes from the Company's producing properties. General and administrative expenses for the year ended December 31, 2000 were $3.6 million compared to $2.8 million for the year ended December 31, 1999, an increase of approximately $800,000. Depreciation, depletion and amortization costs for the year ended December 31, 2000 were $6.9 million compared to $4.0 million for the year ended December 31, 1999, an increase of approximately $2.9 million or 72.5%. Such increase was due to the increased amount of investment in oil and gas properties owned by the Company. Interest costs for the year ended December 31, 2000 were $1.2 compared to $200,000 for the year ended December 31, 1999 an increase of approximately $1.0 million. The increase was due to the Company utilizing its credit agreement to purchase oil and gas properties.

     Net income. Net income for the year ended December 31, 2000 was $10.7 million compared to $7.8 million for the year ended December 31, 1999, an increase of approximately $2.9 million or 37.2%.

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. Natural gas sales from the marketing activities of RNG for the year ended December 31, 1999 were $38.4 million compared to $29.2 million for the year ended December 31, 1998, an increase of approximately $9.2 million or 31.5% Oil and gas sales from the Company's producing properties for the year ended December 31, 1999 were $8.6 million compared to $6.3 million for the year ended December 31, 1998, an increase of approximately $2.3 million or 36.5%. Such increase was due to increased production of natural gas and oil from the Company's producing properties which resulted from acquisitions of producing properties along with new wells drilled. 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%. The cost of gas marketing activities for the year ended December 31, 1999 were $38.5 million compared to $29.3 million for the year ended December 31, 1998, an increase of $9.2 million or 31.4%. Such increase was due to the increased gas marketing activity of RNG. Oil and gas production costs from the Company's producing properties for the year ended December 31, 1999 were $5.7 million compared to $4.2 million for the year ended December 31, 1998, an increase of 1.5 million or 35.7%. Such increase was due to the increased production volumes 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.

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     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%.

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 Bank One, formerly First National Bank of Chicago, which provides a borrowing base of $30.0 million, subject to adequate oil and natural gas reserves. As of December 31, 2000, the balance outstanding on the line of credit is $17.35 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, 2004.

     The Company closed four public drilling partnerships during 2000. The total amount received during 2000 was $55.6 million compared to $36.1 million for 1999. The Company closed its fourth program of 2000 on December 27, 2000 in the amount of $25.0 million and will drill the wells during the first quarter 2001. The Company generally invests, as its equity contribution to each drilling partnership, an additional sum approximating 20% of the aggregate subscriptions received for that particular drilling partnership. As a result, the Company is subject to substantial cash commitments at the closing of each drilling partnership. The funds received from these programs are restricted to use in future drilling operations. No assurance can be made that the Company will continue to receive this level of funding from these or future programs.

     On 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 limited partnership interest in 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 3.0 Bcfe of proved undeveloped reserves attributable to these 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.

     On June 6, 2000 the Company purchased all of the working interest in 168 producing wells in Colorado for $5,650,000. The transaction was effective April 1, 2000. The wells have net remaining reserves of 560,000 barrels of oil and 4.9 billion cubic feet of natural gas. The Company utilized its bank credit agreement to finance this purchase.

-22-

 

     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 and No. 138, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133/138), was issued by the Financial Accounting Standards Board. SFAS No. 133/138 standardized the accounting for derivative instruments, including certain derivative instruments embedded in other contracts. The Company is required to adopt the provisions of SFAS 133/138 effective January 1, 2001. On adoption, the provisions of SFAS No. 133/138 must be applied prospectively. The natural gas futures and options and the interest rate swap agreement discussed in note 12 are derivatives pursuant to SFAS 133/138. The Company's derivatives will be treated as hedges of committed and/or anticipated transactions and have a total estimated fair value of $(20,131,800) on December 31, 2000. On January 1, 2001, the Company will record this estimated fair value as a liability with a corresponding adjustment to accumulated other comprehensive income (AOCI). The adjustment to AOCI will be recorded net of the related tax effects.

Item 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, 2000 is $46,872,000 with an average interest rate of 5.24 percent. As of December 31, 2000, the Company has long-term debt of $17,350,000 of which $10,000,000 is subject to an interest rate swap at a rate of 8.39%, $5,000,000 at a LIBOR rate of 8.52% and $2,350,000 was subject to a prime rate of 9.50%.

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, 2000, PDC had entered into a series of natural gas future contracts and options contracts. Open future contracts maturing in 2001 are for the sale of 4,923,320 dt of natural gas with a weighted average price of $4.07 dt resulting in a total contract amount of $20,134,300, and a fair market value of $(19,340,400). Open option contracts maturing in 2001 are for the sale of 2,276,400 dt with a weighted average floor price of $3.68 dt and a fair value of $(757,600). As of December 31, 1999, PDC had entered into a series of natural gas future contracts. Open future contracts maturing in 2000 were for the sale of 1,820,000 dt of natural gas with a weighted average price of $2.3725 dt resulting in a total contract amount of $4,317,950, and a fair market value of $350,500. The average NYMEX closing price for natural gas for the years 2000, 1999, and 1998 was $3.88 dt, $2.27 dt and $2.11 dt. The average NYMEX closing price for oil for the years 2000, 1999, and 1998 was $30.95 bbl, $18.06 bbl and $14.64 bbl. Future near-term gas prices will be affected by various supply and demand factors such as weather, government and environmental regulation and new drilling activities within the industry.

-23-

Disclosure of Limitations

     As the information above incorporates only those exposures that exist at December 31, 2000, it does not consider those exposures or positions which could arise after that date. As a result, the Company's ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, the Company's hedging strategies at the time, and interest rates and commodity prices at the time.

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 Executive Officers of the Company

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

Name	Age	Positions and Offices Held	Held Current Position Since
James N. Ryan	69	Chairman, Chief Executive Officer and Director	November 1983
Steven R. Williams	49	President and Director	March 1983
Dale G. Rettinger	56	Chief Financial Officer, Executive Vice President, Treasurer and Director	July 1980
Roger J. Morgan	73	Secretary and Director	November 1969
Vincent F. D'Annunzio	48	Director	February 1989
Jeffrey C. Swoveland	45	Director	March 1991
Donald B. Nestor	52	Director	March 2000

James N. Ryan has served as President and Director of PDC from 1969 to 1983 and was elected Chairman and Chief Executive Officer in March 1983

Steven R. Williams has served as President and Director of PDC since March 1983. Prior to joining PDC, Mr. Williams was employed by Exxon until 1979 and attended Stanford Graduate School of Business, graduating in 1981. He then worked with Texas Oil and Gas until July 1982, when he joined Exco Enterprises, an oil and gas investment company as manager of operations.

Dale G. Rettinger has served as Vice President and Treasurer of PDC since July 1980, and was appointed Chief Financial Officer in September 1997. Mr. Rettinger was elected Director in 1985. Previously Mr. Rettinger was a partner with Main Hurdman, Certified Public Accountants, having served in that capactiy since 1976.

Roger J. Morgan has been a member of the law firm of Young, Morgan & Cann, Clarksburg, West Virginia since 1955. Mr. Morgan is not active in the day-to-day business of PDC, but his law firm provides legal services to PDC.

Vincent F. D'Annunzio has served as president of Beverage Distributors, Inc. located in Clarksburg, West Virginia since 1985.

Jeffrey C. Swoveland has served as Chief Financial Officer of Body Media since September, 2000. Prior thereto, Mr. Swoveland was Vice President-Finance and Treasurer of Equitable Resources Inc since 1994.

-24-

 

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 served in that capacity since 1975.

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. 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; and Mr Williams, Mr. Morgan and Mr. Nestor are members of the class whose term expires in 2003. There is no family relationship between any director or executive officer and any other director or executive officer of the Company. There are no arrangements or understandings between any director or officer and any other person pursuant to which such person was selected as an officer.

Item 11. Management Remuneration and Transactions

     There is incorporated by reference herein in response to this Item the material under the heading "Election of Directors - Remuneration of Directors and Officers", "Election of Directors - Stock Options" and "Election of Directors - Interest of Management in Certain Transactions" in the Company's definitive proxy statement for its 2001 annual meeting of stockholders filed or to be filed with the Commission on or before April 30, 2001.

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 2001 annual meeting of stockholders filed or to be filed with the Commission on or before April 30, 2001.

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.

-25-

 

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 23, 2001

     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 James N. Ryan	Chairman, Chief Executive Officer and Director	March 23, 2001
/s/ Steven R. Williams Steven R. Williams	President and Director	March 23, 2001
/s/ Dale G. Rettinger Dale G. Rettinger	Chief Financial Officer Executive Vice President,Treasurer and Director (principal financial and accounting officer	March 23, 2001
/s/ Roger J. Morgan Roger J. Morgan	Secretary and Director	March 23, 2001

-26-

 

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, 2000 and 1999	F-3 & 4
	Consolidated Statements of Income -       Years Ended December 31, 2000, 1999 and 1998	F-5
	Consolidated Statements of Stockholders' Equity -       Years Ended December 31, 2000, 1999 and 1998	F-6
	Consolidated Statements of Cash Flows -       Years Ended December 31, 2000, 1999 and 1998	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 auditing standards generally accepted in the United States of America. 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, 2000 and 1999, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States of America. 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 8, 2001

F-2

 

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets

December 31, 2000 and 1999

		2000		1999
Assets
Current assets:
Cash and cash equivalents	$ 43,933,700		28,444,900
Restricted cash	2,938,300		614,300
Notes and accounts receivable	23,648,000		10,263,200
Inventories	1,097,900		577,600
Prepaid expenses	7,134,800		2,360,100
Total current assets	78,752,700		42,260,100
Properties and equipment:
Oil and gas properties (successful     efforts accounting method)	131,271,900		105,837,900
Pipelines	6,147,800		8,643,400
Transportation and other equipment	2,704,300		2,686,800
Land and buildings	1,174,600		1,181,000
	141,298,600		118,349,100
Less accumulated depreciation,     depletion and amortization	35,344,700		31,207,300
	105,953,900		87,141,800
Other assets	2,977,900		2,681,700
	$187,684,500		132,083,600

(Continued)

F-3

 

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets

December 31, 2000 and 1999

	2000	1999
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$ 27,742,600	14,678,900
Accrued taxes	-	276,400
Other accrued expenses	3,979,900	2,643,700
Advances for future drilling contracts	43,809,400	25,137,400
Funds held for future distribution	2,440,100	2,027,600
Total current liabilities	77,972,000	44,764,000
Long-term debt	17,350,000	9,300,000
Other liabilities	4,396,800	3,160,600
Deferred income taxes	5,708,800	4,134,100
Commitments and contingencies
Stockholders' equity:
Common stock, par value $.01 per share;    authorized 50,000,000 shares; issued and    outstanding 16,244,044 and 15,737,795 shares	162,400	157,400
Additional paid-in capital	32,917,000	32,071,000
Retained earnings	49,177,500	38,496,500
Total stockholders' equity	82,256,900	70,724,900
	$187,684,500	132,083,600

See accompanying notes to consolidated financial statements.

F-4

 

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Consolidated Statements of Income

Years Ended December 31, 2000, 1999 and 1998

	2000	1999	1998
Revenues:
Oil and gas well drilling operations	$ 43,194,700	42,115,600		40,447,100
Gas sales from marketing activities	71,402,400	38,359,700		29,244,900
Oil and gas sales	19,017,300	8,628,400		6,315,400
Well operations and pipeline income	5,061,600	5,314,500		4,581,000
Other income	2,540,500	2,392,400		2,385,200
	141,216,500	96,810,600		82,973,600
Costs and expenses:
Cost of oil and gas well     drilling operations	35,244,300	35,507,300		35,047,500
Cost of gas marketing activities	71,648,500	38,459,000		29,350,200
Oil and gas production costs	8,303,600	5,729,200		4,206,700
General and administrative expenses	3,616,900	2,801,000		2,490,500
Depreciation, depletion and amortization	6,943,500	4,031,200		3,253,600
Interest	1,186,000	182,400		-
	126,942,800	86,710,100		74,348,500
Income before income taxes	14,273,700	10,100,500		8,625,100
Income taxes	3,592,700	2,276,200		1,967,100
Net income	$ 10,681,000	7,824,300		6,658,000
Basic earnings per common share	$.66	.50		.43
Diluted earnings per common  and common equivalent share	$.65	.48		.41

See accompanying notes to consolidated financial statements.

F-5

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Consolidated Statements of Stockholders' Equity

Years Ended December 31, 2000, 1999 and 1998

	Common stock        Issued
	Number Of Shares	Amount	Additional Paid-in- capital	Warrants Out- Standing	Retained Earnings	Total
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
	15,510,762	$ 155,100	31,873,100	46,300	30,672,200	62,746,700
Balance December 31, 1998
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
Issuance of common stock:
Exercise of employee stock options	511,584	5,100	511,700	-	-	516,800
Purchase of properties	100,000	1,000	549,000	-	-	550,000
Amortization of stock award	-	-	5,500	-	-	5,500
Repurchase and cancellation of treasury stock	(105,335)	(1,100)	(420,100)	-	-	(421,200)
Income tax benefit from the exercise  of stock options	-	-	199,900	-	-	199,900
Net income	-	-	-	-	10,681,000	10,681,000
Balance December 31, 2000	16,244,044	$162,400	32,917,000	-	49,177,500	82,256,900

See accompanying notes to consolidated financial statements.

F-6

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Consolidated Statements of Cash Flows

Years Ended December 31, 2000, 1999 and 1998

	2000	1999	1998
Cash flows from operating activities:
Net income	$10,681,000	7,824,300	6,658,000
Adjustment to net income to reconcile    to cash provided by operating activities:
Deferred income taxes	1,838,300	108,900	244,000
Depreciation, depletion and amortization	6,943,500	4,031,200	3,253,600
(Gain) loss from sale of assets	(199,200)	(501,800)	18,700
Disposition of leasehold acreage	672,700	618,100	196,200
Amortization of stock award	5,500	12,200	12,200
Increase in notes and     accounts receivable	(13,384,800)	(4,239,100)	(1,100,700)
(Increase) decrease in inventories	(520,300)	124,800	(404,500)
(Increase) decrease in prepaid expenses	(4,774,700)	312,600	(600)
Increase in other assets	(375,700)	(750,900)	(911,200)
Increase in accounts payable     and accrued expenses	15,359,700	5,347,300	1,304,000
Increase (decrease) in advances for     future drilling contracts	18,672,000	(3,183,400)	5,029,200
Increase (decrease) in funds held for     future distribution	412,500	1,043,400	(675,500)
Total adjustments	24,649,500	2,923,300	6,965,400
Net cash provided by          operating activities	35,330,500	10,747,600	13,623,400
Cash flows from investing activities:
Capital expenditures	(27,932,100)	(27,758,200)	(26,629,700)
Proceeds from sale of leases	1,588,700	1,224,200	1,283,600
Proceeds from sale of fixed assets	680,100	651,000	56,300
(Increase) decrease in restricted cash	(2,324,000)	(458,100)	769,900
Net cash used in          investing activities	(27,987,300)	(26,341,100)	(24,519,900)
Cash flows from financing activities:
Proceeds from debt	8,050,000	9,300,000	-
Proceeds from issuance of stock	95,600	-	-
Net cash provided by          financing activities	8,145,600	9,300,000	-
Net increase (decrease) in cash     and cash equivalents	15,488,800	(6,293,500)	(10,896,500)
Cash and cash equivalents,     beginning of year	28,444,900	34,738,400	45,634,900
Cash and cash equivalents, end of year	$43,933,700	28,444,900	34,738,400

See accompanying notes to consolidated financial statements.

F-7

 

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Years Ended December 31, 2000, 1999 and 1998

(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. An inventory of oil located in stock tanks on well locations, is carried at market at the end of each period.

     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.

(Continued)

F-8

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

     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.

     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 restoration, 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.

     Sales of natural gas are recognized when sold, oil revenues are recognized when produced into a stock tank.

     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.

     Derivative Financial Instruments

     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.

     The Company has entered into an interest rate swap agreement to reduce its exposure to market risks from changing interest rates. The interest rate differential to be paid or received is accrued and recognized currently in interest expense.

     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.

(Continued)

F-10

 

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated 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.

     Reclassifications

     Certain items and amounts reported in the 1999 and 1998 consolidated financial 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, 2000, 1999 and 1998.

     New Accounting Standards

     Statement of Accounting Standards No. 133 and No. 138, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133/138), was issued by the Financial Accounting Standards Board. SFAS No. 133/138 standardized the accounting for derivative instruments, including certain derivative instruments embedded in other contracts. The Company is required to adopt the provisions of SFAS 133/138 effective January 1, 2001. On adoption, the provisions of SFAS No. 133/138 must be applied prospectively. The natural gas futures and options and the interest rate swap agreement discussed in note 12 are derivatives pursuant to SFAS 133/138. The Company's derivatives will be treated as hedges of committed and/or anticipated transactions and have a total estimated fair value of $(20,131,800) on December 31, 2000. On January 1, 2001, the Company will record this estimated fair value as a liability with a corresponding adjustment to accumulated other comprehensive income (AOCI). The adjustment to AOCI will be recorded net of the related tax effects.

(2)  Notes and Accounts Receivable

     Included in other assets are noncurrent accounts receivable as of December 31, 2000 and 1999, in the amounts of $245,300 and $494,000 net of the allowance for doubtful accounts of $183,000 and $216,900, respectively.

     The allowance for doubtful current accounts receivable as of December 31, 2000 and 1999 was $341,500 and $221,500, respectively.

(3)  Long-Term Debt

     On August 29, 2000 the Company executed an Amendment to its Credit Agreement with Bank One, formerly First National Bank of Chicago. The amendment provides and the Company has activated a $30.0 million borrowing base, subject to adequate oil and gas reserves. 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, 2004.

(Continued)

F-11

 

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

     As of December 31, 2000 and 1999 the outstanding balance was $17,350,000 and $9,300,000, respectively. 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. As of December 31, 2000 and 1999 the Company was in compliance with all financial covenants in the credit agreement.

     At December 31, 2000, $10,000,000 of the outstanding balance was subject to an interest rate swap at a rate of 8.39%, $5,000,000 at a LIBOR rate of 8.52% and $2,350,000 was subject to a prime rate of 9.50%.

(4)  Income Taxes

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

	2000	1999	1998
Current:
Federal	$1,182,000	1,434,300	1,197,800
State	572,400	733,000	525,300
Total current income taxes	1,754,400	2,167,300	1,723,100
Deferred:
Federal	1,415,600	(65,300)	(500)
State	422,700	174,200	244,500
Total deferred income taxes	1,838,300	108,900	244,000
Total taxes	$3,592,700	2,276,200	1,967,100

     Income tax expense differed from the amounts computed by applying the U.S.

       federal income tax rate of 34 percent to pretax income as a result of

       the following:

	2000	1999	1998
	Amount	Amount	Amount
Computed "expected" tax	$4,853,100	3,434,200	2,932,500
State income tax	656,800	598,800	508,100
Percentage depletion	(758,300)	(612,000)	(343,400)
Nonconventional source fuel credit	(1,067,500)	(846,800)	(696,700)
Adjustments to valuation allowance	-	(375,000)	(473,200)
Other	(91,400)	77,000	39,800
	$3,592,700	2,276,200	1,967,100

(Continued)

F-12

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

The tax effects of temporary differences that give rise to significant

portions of the deferred tax assets and deferred tax liabilities at December 31, 2000 and 1999 are presented below:

	2000	1999
Deferred tax assets:
Allowance for doubtful accounts	$   209,800	175,400
Drilling notes	101,900	105,700
Alternative minimum tax credit    carryforwards (Section 29)	2,132,300	1,982,300
Future abandonment	347,200	273,100
Deferred compensation	1,729,200	1,213,800
Other	49,400	51,600
Total gross deferred tax assets	4,569,800	3,801,900
Less valuation allowance	-	-
Deferred tax assets	4,569,800	3,801,900
Less current deferred tax assets
(included in prepaid expenses)	(853,300)	(1,007,600)
Net non-current deferred
tax assets	3,716,500	2,794,300
Deferred tax liabilities:
Properties and equipment, principally    due to differences in depreciation    and amortization	(9,425,300)	(6,928,400)
Total gross deferred
tax liabilities	(9,425,300)	(6,928,400)
Net deferred tax liability	$(5,708,800)	(4,134,100)

     The valuation allowance for the deferred tax assets as of January 1, 2000 and 1999 was $0 and $375,000, respectively. The net changes in the total valuation allowance were decreases of $375,000 and $473,200 for the years ended December 31, 1999 and 1998, respectively. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment.

     At December 31, 2000, the Company has alternative minimum tax credit carryforwards (Section 29) of approximately $2,132,300 which are available to reduce future federal regular income taxes over an indefinite period.

(5)  Common Stock

     Options

     Options amounting to 180,000, 145,000 and 20,000 shares were granted during 2000, 1999 and 1998, 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 2000 and 1999 grants and a two year period for the 1998 grant. The outstanding options expire from 2005 to 2010.

(Continued)

F-13

 

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

     The estimated fair value of the options granted during 2000, 1999 and 1998 was $2.48, $2.44 and $3.92 per option, respectively. The fair value was estimated using the Black-Scholes option pricing model with the following assumptions for the 2000, 1999 and 1998 grant, respectively: risk-free interest rate of 6.13%, 5.1% and 5.9%, expected dividend yield of 0%, expected volatility of 57.31%, 61.3% and 58.0% and expected life of 7 years.

		Average	Range of
	Number	Exercise	Exercise
	of Shares	Price	Prices
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
Granted	180,000	$3.875	3.875 - 3.875
Exercised	(511,584)	$1.01	.94 - 1.625
Expired	(12,400)	$3.31	1.50 - 3.75
Outstanding December 31, 2000	1,045,000	$3.95	1.125 - 6.125

     As of December 31, 2000, there were 210,000 options outstanding and exercisable at the $1.125 exercise price which have a weighted average remaining contractual life of 4.9 years. Also as of December 31, 2000 there were 835,000 options outstanding and exercisable at a $3.75 to $6.13 exercise price range having a weighted average remaining contractual life of 7.4 years and weighted average exercise price of $4.66.

     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:

	2000		1999
	As Reported	Pro Forma	As Reported	Pro Forma
Net income	$10,681,000	$10,346,700	$7,824,300	$7,336,200
Basic earnings
per share	$ .66	$ .64	$ .50	$ .47
Diluted earnings
per share	$ .65	$ .63	$ .48	$ .45

(Continued)

F-14

 

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

     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.

(6)  Employee Benefit Plans

     The Company made 401-K Plan contributions of $252,613, $217,400 and $202,600 for 2000, 1999 and 1998, respectively.

     The Company has a profit sharing plan (the Plan) covering full-time employees. The Company contributed $1,000, $47,000 and $17,000, to the plan in cash during 2000, 1999 and 1998, respectively.

     During 2000, 1999 and 1998 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 $5,500, $12,200 and $12,200 in 2000, 1999 and 1998, respectively.

     At December 31, 2000 and 1999, the Company has recorded as other assets $360,000 and $300,000, 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 shares outstanding of 16,157,532 for 2000, 15,734,063 for 1999 and 15,505,680 for 1998.

     Diluted earnings per share is based on the weighted average number of common and common equivalent shares outstanding of 16,437,488 for 2000, 16,286,852 for 1999 and 16,338,298 for 1998. 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 $44,899,200 in 2000, $24,002,500 in 1999 and $22,997,300 in 1998 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. Funds held for future distribution on the consolidated balance sheet includes amounts owed to affiliated partnerships as of December 31, 2000 and 1999.

(Continued)

F-15

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

     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 $15,713,300 in 2000, $10,322,500 in 1999 and $9,621,700 in 1998 for those services. Amounts due from the partnerships as of December 31, 2000 and 1999 were $957,700 and $895,900, and are included in notes and accounts receivable.

     During 2000, 1999 and 1998, the Company paid $40,400, $31,600 and $30,000, respectively to the Corporate Secretary's law firm for various legal services.

(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. One customer, Cinnabar Energy Services, accounted for 11.3% of total revenues in 2000. No customer accounted for more than 10.0% of total revenues in 1999 or 1998.

     The Company would be exposed to natural gas price fluctuations on underlying purchase and sale contracts should the counterparties to the Company's hedging instruments or the counterparties to the Company's gas marketing contracts not perform. Such nonperformance is not anticipated. There were no counterparty default losses in 2000, 1999 or 1998.

     Substantially all of the Company's drilling programs contain a repurchase provision where Investors may tender their partnership units for repurchase at any time beginning with the third anniversary of the first cash distribution. The provision provides that the Company is obligated to purchase an aggregate of 10% of the initial subscriptions per calendar year (at a minimum price of four times the most recent 12 months' cash distributions), only if such units are tendered, subject to the Company's financial ability to do so. The maximum annual 10% repurchase obligation, if tendered by the investors, is currently approximately $1,188,000. 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 $875,800, $124,200 and $0 for interest in 2000, 1999 and 1998, respectively. The Company paid income taxes in 2000, 1999 and 1998 in the amounts of $2,256,800, $1,327,800 and $2,349,100, respectively.

     The Company exchanged common stock in the amount of $550,000 and cash in the amount of $5,100,000 for the purchase of oil and gas properties in Colorado during 2000.

(11) Acquisitions and Divestitures

     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. At the date of acquisition, 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 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.

     On June 6, 2000, the Company purchased all of the working interest in 168 producing wells in Colorado for $5,650,000. The transaction was effective April 1, 2000. At the date of acquisition, the wells had net remaining reserves of 560,000 barrels of oil and 4.9 billion cubic feet of natural gas. The Company utilized its bank credit agreement to finance this purchase.

     On December 31, 2000, the Company sold its Ohio gas gathering and sales systems. The result was a net gain of $109,600.

(12) Derivative Financial Instruments

     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, 2000 and 1999, the Company had futures contracts for the sale of 6,230,000 dt and 4,318,0000 dt of natural gas, respectively and option contracts for the sale of 2,276,400 dt as of December 31, 2000. While these contracts have nominal carrying value, their fair value, represented by the estimated amount that would be received (paid) upon termination of the contracts, based on market quotes, was a value of $(11,526,500) stemming from its marketing activities at December 31, 2000 and $350,500 stemming from its marketing activities at December 31, 1999. Based on the nature of the Company's gas marketing activities, hedging is not expected to have a significant impact on the Company's net margins from marketing activities during 2001.The fair value of these contracts was $(8,571,500) stemming from its natural gas production, $(5,142,900) net of tax at December 31, 2000.

      The Company is required to maintain margin deposits with brokers for outstanding futures contracts. As of December 31, 2000 and 1999, cash in the amount of $2,938,300 and $614,300 was on deposit.

      Interest rate swap agreements are used to reduce the potential impact of increases in interest rates on variable rate long-term debt. At December 31, 2000, the Company was a party to an interest rate swap agreement expiring on October 11, 2004. The agreement entitles the Company, on a quarterly basis, to a fixed-rate interest payment of 6.89% plus its current LIBOR rate margin (+1.50% At December 31, 2000) on a $10,000,000 notional amount related to its outstanding line of credit.

F-17

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

     The fair value of the interest rate swap agreement was $(33,800), $(20,300) net of tax at December 31, 2000. Current market pricing models were used to estimate fair value.

     By using derivative financial instruments to hedge exposures to changes in interest rates and commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates repayment risk. The Company minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties.

(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:

	Years Ended December 31,
	2000	1999	1998
Property acquisition cost:
Proved undeveloped properties	$3,397,500	2,532,200	1,903,200
Producing properties	8,361,400	6,997,500	8,679,000
Development costs	15,556,200	17,168,000	14,902,500
	$27,315,100	26,697,700	25,484,700

     Of the above development costs incurred for the years ended December 31, 2000, 1999 and 1998 the amounts of $2,379,300, $2,977,500 and $2,657,700, respectively were incurred to develop proved undeveloped properties from the prior year end. The proved reserves attributable to these development costs were 1,388,200 Mcf and 83,900 bbls for 2000, 6,885,000 Mcf for 1999 and 5,787,000 Mcf for 1998 (amounts unaudited).

     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:

	December 31,
	2000	1999
Proved properties:
Tangible well equipment	$82,304,400	67,060,500
Intangible drilling costs	44,944,000	36,270,300
Undeveloped properties	4,023,500	2,507,100
	131,271,900	105,837,900
Less accumulated depreciation,  depletion and amortization	29,739,500	23,652,000
	$101,532,400	82,185,900

F-18

 

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

(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:

	Years Ended December 31,
	2000	1999	1998
Revenue:
Oil and gas sales	$19,017,300	8,628,400	6,121,700
Expenses:
Production costs	4,201,400	2,422,000	1,516,700
Depreciation, depletion
and amortization	6,031,200	3,220,900	2,392,000
	10,232,600	5,642,900	3,908,700
Results of operations for    oil and gas producing    activities before provision    for income taxes	8,874,700	2,985,500	2,213,000
Provision for income taxes	2,713,900	469,400	398,600
Results of operations for oil    and gas producing activities    (excluding corporate over-    head and interest costs)	$6,070,800	2,516,100	1,814,400

     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-19

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, 2000, 1999 and 1998. 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:

	Oil (BBLS)
	2000	1999	1998
Proved developed and
undeveloped reserves:
Beginning of year	1,154,000	29,000	45,000
Revisions of previous estimates	10,000	67,000	(10,000)
Beginning of year as revised	1,164,000	96,000	35,000
New discoveries and extensions
Michigan	265,000	-	-
Wattenberg field	535,000	404,000	-
Dispositions to partnerships	(262,000)	-	-
Acquisitions
Wattenberg field	573,000	652,000	-
Appalachian basin	-	10,000	2,000
Production	(109,000)	(8,000)	(8,000)
End of year	2,166,000	1,154,000	29,000
Proved developed reserves:
Beginning of year	798,000	29,000	45,000
End of year	1,527,000	798,000	29,000
	Gas (MCF)
	2000	1999	1998
Proved developed and
undeveloped reserves:
Beginning of year	101,245,000	80,819,000	57,243,000
Revisions of previous estimates	(3,859,000)	(4,475,000)	(3,517,000)
Beginning of year as revised	97,386,000	76,344,000	53,726,000
New discoveries and extensions
Michigan	14,191,000	4,559,000	17,383,000
Wattenberg field	5,681,000	4,070,000	-
Pieance basin	8,922,000	9,974,000	-
Appalachian basin	266,000	6,178,000	6,169,000
Dispositions to partnerships	(8,498,000)	(8,774,000)	(6,009,000)
Acquisitions
Michigan	-	-	2,842,000
Wattenberg field	5,761,000	5,546,000	-
Appalachian basin	668,000	6,799,000	9,161,000
Production	(5,737,000)	(3,451,000)	(2,453,000)
End of year	118,640,000	101,245,000	80,819,000
Proved developed reserves:
Beginning of year	82,628,000	64,562,000	42,411,000
End of year	92,131,000	82,628,000	64,562,000

(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, adjusted for hedging contracts, 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-20

 

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

	Years Ended December 31,
	2000	1999	1998
Future estimated cash flows	$520,010,000	307,816,000	186,598,000
Future estimated production costs	(144,505,000)	(104,233,000)	(84,078,000)
Future estimated development costs	(50,278,000)	(25,324,000)	(11,592,000)
Future estimated income   tax expense	(80,982,000)	(39,930,000)	(20,322,000)
Future net cash flows	244,245,000	138,329,000	70,606,000
10% annual discount for estimated   timing of cash flows	(139,606,000)	(79,875,000)	(40,412,000)
Standardized measure of discounted future estimated net cash flows	$104,639,000	58,454,000	30,194,000

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

	Years Ended December 31,
	2000	1999	1998
Sales of oil and gas
production, net of
production costs	$(14,816,000)	(6,206,000)	(4,605,000)
Net changes in prices
and production costs	70,514,000	29,547,000	(23,083,000)
Extensions, discoveries
and improved recovery,
less related cost	73,636,000	39,653,000	18,615,000
Dispositions to partnerships	(16,850,000)	(6,152,000)	(5,762,000)
Acquisitions	27,907,000	31,915,000	13,938,000
Development costs incurred
during the period	15,556,000	17,168,000	14,903,000
Revisions of previous
quantity estimates	(5,925,000)	(4,944,000)	(5,605,000)
Changes in estimated
income taxes	(41,052,000)	(19,608,000)	459,000
Changes in discount	(59,731,000)	(39,463,000)	1,224,000
Changes in production rates
(timing) and other	(3,054,000)	(13,650,000)	(7,826,000)
	$46,185,000	28,260,000	2,258,000

     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.

F-21

 

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 development, 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, 2000, 1999 and 1998 is as follows:

	2000	1999	1998
REVENUES
Drilling and Development	$43,195	42,116	40,447
Natural Gas Sales	90,420	46,988	35,560
Well Operations	5,061	5,314	4,581
Unallocated amounts (1)	2,540	2,392	2,385
Total	$141,216	96,810	82,973
(1) Includes interest on investments and partnership management fees in          2000, 1999 and 1998 and gain on sale of assets in 2000 and 1999 which          are not allocated in assessing segment performance.
	2000	1999	1998
SEGMENT INCOME BEFORE INCOME TAXES
Drilling and Development	$ 7,950	6,608	5,400
Natural Gas Sales	7,364	2,967	2,064
Well Operations	1,385	1,219	1,372
Unallocated amounts (2)
General and Administrative expenses	(3,617)	(2,801)	(2,491)
Interest expense	(1,186)	(182)	-
Other (1)	2,378	2,289	2,280
Total	$ 14,274	10,100	8,625
(2) Items which are not allocated in assessing segment performance.
	2000	1999	1998
SEGMENT ASSETS
Drilling and Development	$ 31,592	23,957	27,288
Natural Gas Sales	139,116	93,073	65,256
Well Operations	8,490	7,977	7,136
Unallocated amounts
Cash	1,567	1,967	7,814
Other	6,920	5,110	3,915
Total	$187,685	132,084	111,409
	2000	1999	1998
EXPENDITURES FOR SEGMENT LONG-LIVED ASSETS
Drilling and Development	$ 3,217	1,710	1,953
Natural Gas Sales	23,958	24,613	23,645
Well Operations	650	1,328	947
Unallocated amounts	107	107	85
Total	$ 27,932	27,758	26,630

F-22

 

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, 2000 and 1999, are as follows:

	2000
	Quarter				Year
	First	Second	Third	Fourth
Revenues	$34,504,400	$29,063,200	$32,818,600	$44,830,300	$141,216,500
Cost of operations	29,600,900	25,225,800	28,646,900	38,666,300	122,139,900
Gross profit	4,903,500	3,837,400	4,171,700	6,164,000	19,076,600
General and
administrative
expenses	679,200	1,032,300	1,038,300	867,100	3,616,900
Interest expense	14,600	275,400	437,500	458,500	1,186,000
	693,800	1,307,700	1,475,800	1,325,600	4,802,900
Income before
income taxes	4,209,700	2,529,700	2,695,900	4,838,400	14,273,700
Income taxes	968,300	581,900	555,000	1,487,500	3,592,700
Net income	$3,241,400	$ 1,947,800	$ 2,140,900	$ 3,350,900	$10,681,000
Basic earnings
per share	$ .20	$ .12	$ .13	$ .21	$ .66
Diluted earnings
per share	$ .20	$ .12	$ .13	$ .20	$ .65

	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

     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-23

 

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

AND RESERVES

Years Ended December 31, 2000, 1999 and 1998

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
2000	$438,400	$573,000	$486,900	$524,500
1999	$274,600	$272,500	$108,700	$438,400
1998	$275,400	$ 46,800	$ 47,600	$274,600

F-24

EX-11

Petroleum Development Corporation

Index to Exhibits

11 Schedule of Computation of Net Income Per Share E-6

E-1

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

EXHIBIT 11

SCHEDULE OF COMPUTATION OF NET INCOME PER SHARE

	Years Ended December 31,
BASIC	2000	1999	1998
Net income for basic income  per common share	$ 10,681,000	7,824,300	6,658,000
Weighted average number  of common  shares outstanding during the year	16,157,532	15,734,063	15,505,680
Basic earnings per share	$       .66	$     .50	$      .43
DILUTED
Net income for basic earnings per  common share	$10,681,000	7,824,300	6,658,000
Net income for diluted        earnings per share	$10,681,000	7,824,300	6,658,000
Weighted average number of shares        used in calculating basic        earnings per common share	16,157,532	15,734,063	15,505,680
Shares issuable for diluted    calculation	279,956	552,789	832,618
Weighted average number of         shares used in calculation of         diluted earnings per share	16,437,488	16,286,852	16,338,298
Diluted earnings per share	$       .65	$       .48	$      .41

E-6