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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

ANNUAL REPORT

PURSUANT TO SECTIONS 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

(Mark One)

[X] ANNUAL REPORT PURSUANT TO SECTION 13 or 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2005

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

      For the transition period from                 to                  

Commission File Number  0-7246

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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes       No   X  

Indicate by check mark if registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes       No   X  

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.  [X]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or non-accelerated file. See definition of "accelerated filer and larger accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated Filer   [ ]                               Accelerated Filer  [ X ]                                      Non-Accelerated Filer [  ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes        No   X  

As of May 5, 2006, 16,057,065 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 June 30, 2005, the last business day of the Registrant's most recently completed second quarter was $518,136,692 (based on the last traded price of  $31.85).

DOCUMENTS INCORPORATED BY REFERENCE

Document

Form 10-K Part III

Proxy

Items 10, 11, 12, and 13

(except as presented herein)



EXPLANATORY NOTE REGARDING RESTATEMENT

                In this Annual Report on Form 10-K for the year ended December 31, 2005, the Company is amending and restating its prior consolidated statements of income for the years ended December 31, 2004 and 2003, and for each of the quarters ended in the years 2004 and 2003.  The restatement also affected periods prior to 2003, those restated numbers are included in "Item 6. Selected Financial Data". This Annual Report on Form 10-K is also amending and restating our consolidated statements of income for the quarterly periods ended March 31, 2005, June 30, 2005, and September 30, 2005.

                As previously announced in a Form 8K as filed with the Securities and Exchange Commission on April 3, 2006, the Company identified that corrections were needed to certain revenues and expenses to properly reflect the elimination of transactions between the Company and the Company sponsored limited partnerships.  The corrections resulted in elimination of revenues and expenses of equal amounts. The restatement had no effect on Net Income, Earnings per Share, Cash Flow, Proved Oil and Gas Reserves, or the Company's financial position.

                For a discussion of the individual restatement adjustments, see Note 22 to the Company's consolidated financial statements in "Item 8. Financial Statements and Supplementary Data". Additionally, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations." For more information on the impact of the restatement on years 2001 and 2002, see "Item 6. Selected Financial Data."

                The Company did not amend its Annual Report on Form  10-K or Quarterly Reports on Form 10-Q for prior periods affected by the restatement. The financial statements and related financial information contained in the Company's previously filed reports should no longer be relied upon.

                All referenced amounts in this Annual Report for prior periods and prior period comparisons reflect the balances and amounts on a restated basis.

Item 1.     Business

Petroleum Development Corporation is an independent energy company engaged primarily in the development, production and marketing of natural gas and oil. Since it began oil and gas operations in 1969, the Company has grown primarily through drilling and development activities, the acquisition of producing natural gas and oil wells and the expansion of its natural gas marketing activities. As of December 31, 2005, the Company operates approximately 2,800 wells located in the Appalachian Basin, Michigan, and the Rocky Mountain Region, with gross proved reserves of 708 billion cubic feet equivalent of natural gas ("Bcfe", based on one barrel of oil equals 6 thousand cubic feet equivalent of natural gas ("Mcfe")) of which the Company's share is 275 Bcfe. The Company's share of production for the fourth quarter of 2005 averaged 38,800 Mcfe per day.

See Glossary of Terms used in this Form 10-K on Page 61.

Business Segments

The Company's operations are divided into four segments for management and reporting purposes.  (See Note 20).

Drilling and Development

The Company drills wells not only for itself, but also for other investor partners.  When the Company drills wells for others it earns profit above the cost of the wells.  The Drilling and Development segment records the payments received from others as revenue and the related costs as expenses.

Since 1984, the Company has sponsored limited partnerships formed to engage in drilling operations. The Company typically purchases a 20% to 30% ownership working interest in these drilling limited partnerships. In 2005, the Company, through two public and one private drilling partnership, raised $116 million making it one of the largest sponsors of public oil and gas partnership programs in the United State s as it has been for the last several years. With the partnerships as a drilling partner, the Company has been able to expand its drilling opportunities, reduce its drilling risk through greater diversification, and to share the costs of the infrastructure necessary to support such activities.

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Natural Gas Marketing

The Company's wholly-owned subsidiary, Riley Natural Gas (RNG), purchases, 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 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 economic hedging and derivative strategies, which the Company utilizes to help manage the financial impact on the Company and its Partnerships of changes in the price of natural gas and oil.  RNG also manages the marketing of oil and gas for the Company's wells outside the Appalachian Basin, but does not market gas or oil for non-affiliated producers in those areas.

Oil and Gas Sales

Revenue from the sale of oil and natural gas from the Company's interest in oil and gas wells is reported in this segment.  The Company has interests in approximately 2,800 wells ranging from a few percent to 100 percent. During 2005 approximately 12% of the Company's production was generated by Appalachian Basin wells, 12% by Michigan Basin wells and 76% by Rocky Mountain wells. As of the end of 2005, the Company's total proved reserves were located as follows: Appalachian Basin 14%, Michigan 9% and Rocky Mountain Region 77%.  The majority of the Company's undeveloped reserves are in the Rocky Mountain Region and the planned drilling for 2006 will be focused in that area.

Well Operations

The Company operates almost all of the approximately 2,800 wells in which it owns an interest.  When it owns less than 100 percent of the working interest in a well, it charges the other owners a competitive operating fee for operating the well.  These revenues and the associated costs are reflected in the Well Operations segment.

Areas of Operations

The Company's operations are divided into three regions, the Appalachian Basin, Michigan, and the Rocky Mountain Region.  The Company has conducted operations in the Appalachian Basin since its inception in 1969, in Michigan since 1997, and in the Rocky Mountain Region since 1999. The Company includes its North Dakota operations in the Rocky Mountain Region.

In all three regions the Company has historically targeted shallow (less than 10,000 feet), developmental natural gas reserves for development.  In some areas of the Rocky Mountain Region, Michigan and the Appalachian Basin the wells also produce oil in conjunction with natural gas.  Recently the Company has begun to drill to progressively deeper targets in the Rocky Mountain Region.  In particular it has drilled several wells with depths of more than 12,000 feet and horizontal wells with a total drilled footage approaching 20,000 feet.  The Company's management believes these deeper and horizontal wells offer the possibility of significantly greater reserves and production than shallow wells, although they are also more expensive to drill.  In addition the probability of encountering problems when drilling a deep or horizontal well is generally greater than when drilling a shallow well.  With increasing costs for and declining availability of proved developed drilling locations, the Company's management believes the additional risk associated with exploratory drilling is justified by the potential to generate additional proved locations at a significantly lower cost than would be required to purchase proved undeveloped locations.

Business Strategy

The Company's primary objective is to increase shareholder value by expanding its oil and natural gas reserves, production and revenues through a strategy that includes the following key elements:

Drill and Develop

Drilling new wells, particularly shallow, developmental natural gas wells, has been the mainstay of the Company's drilling program for a number of years.  The Company drilled 242 wells in 2005, compared to 158 wells in 2004. In addition the Company seeks to maximize the value of its existing wells through a program of well recompletions and drilling in areas where attractive opportunities exist. The Company's management believes that it will be able to drill a substantial number of new wells on its current undeveloped leased properties.  As of December 31, 2005, the Company had leases or other development rights to 3,000 undeveloped acres in the Michigan Basin, 10,000 undeveloped acres in the northern Appalachian Basin and 245,250 undeveloped acres in the Rocky Mountain Region. The Company also has about 67 Wattenberg Field wells (Colorado) that it plans to recomplete in 2006, including 43 of the new wells it has drilled since 1999 in the field.

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To support future development activities the Company has conducted exploratory drilling in the past and has continuing exploratory drilling plans in 2006.  The goal of the exploration program is to develop several significant new areas for the Company to include in its future development drilling programs.

Acquire

The Company's acquisition efforts are focused on producing properties that fit well within existing operations or in areas where the Company is establishing new operations. Preferred properties have most of their value in producing wells, behind pipe reserves or high quality proved undeveloped locations.  Acquisitions have historically offered economies in management and administration, and the Company's management believes that it can acquire and manage more producing wells without incurring substantial increases in its administrative costs. 

Diversify and Focus

With operations in the Rocky Mountains, Michigan and the Appalachian Basin, the Company has proven its ability to grow through operations in geographically diverse areas. While these areas provide geographic diversification, within each area the Company has concentrated positions that lend themselves to effective development and operation.  The Company plans to conduct the majority of its drilling activities in the Rocky Mountain Region during 2006, but will continue to seek additional opportunities for expansion in areas where the Company's experience and expertise can be applied successfully.

Manage Risk

The Company seeks opportunities to reduce the risks inherent in the oil and gas industry in a variety of ways.  For a number of years an integral part of the Company's strategy has been to concentrate on development drilling and geographical diversification to reduce risk levels associated with natural gas and oil drilling, production and markets. Development drilling is less risky than exploratory drilling and is likely to generate cash returns more quickly. Development drilling will remain the foundation of our drilling activities in 2006. However the Company's management believes the increasing cost of high quality development locations has made exploratory drilling more attractive.  Exploratory wells have the potential of identifying new development opportunities at a significantly lower cost than the current cost of proven locations.  While successful exploratory efforts could add to the Company's future drilling opportunities at favorable costs, under the successful efforts method of accounting, exploratory dry holes are expensed at the time it is recognized that they are unproductive. This could result in greater short term expenses and a reduction in the near-term profitability of the Company.

To help offset the relatively high business risk inherent in the oil and gas industry the Company maintains a conservative financial structure.  The Company's management believes that successful natural gas marketing is essential to profitable operations in a deregulated gas market. To further this goal, the Company utilizes its marketing subsidiary, Riley Natural Gas (RNG), to manage the marketing of the Company's oil and natural gas and its commodity derivatives. This allows the Company to maintain better control over third party risk in sales and derivative activities. The Company uses natural gas and oil derivatives to reduce the effects of volatility of energy prices.

Available Information Posted on the Company's Website

The Company's Internet address is www.petd.com. Electronic copies of the Company's annual report on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, and amendments to those reports are available free of charge by visiting the "Financial Information" section of www.petd.com. These reports are posted as soon as reasonably practicable after they are electronically filed with the Securities and Exchange Commission. Additionally, information including the Company's press releases, current drilling program sales, Bylaws, Committee Charters, Code of Business Conduct and Ethics, Shareholder Communication Policy, Board Nomination Procedures and the Whistleblower and Qualified Legal Compliance Committee Hotline is also available at the site.

Industry Overview

Natural gas is the second largest energy source in the United States, after liquid petroleum. The estimated 21.9 Tcf of natural gas consumed in 2005 represented approximately 23% of the total energy used in the United States. Natural gas is consumed in the United States as follows: 35% 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 14% by residential and commercial end-users, respectively, for uses including heating, cooling and cooking; and 26% by utilities for the generation of electricity; and 3% for other users. (Source U.S. Energy Information Administration)

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The Company's management believes that the market for natural gas will continue to grow in the future. Natural gas is the cleanest and most environmentally safe of the fossil fuels. Relative to other energy sources, natural gas usage and losses during transportation from source to destination are slight, averaging only about 3% of the natural gas energy. 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.

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.  Increasing international demand for petroleum combined with supply constraints drove oil prices to record high levels in 2005.  Continuing increases in world energy demand appear likely in 2006 and beyond.  This makes natural gas more competitive in domestic markets as a replacement for oil and increases the value of domestic oil and natural gas reserves.

The Company's management 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 even at prices that are high by historical standards.

Because local supplies of natural gas are inadequate to meet demand in sections of the country, areas including 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. Natural gas producers in the Appalachian Basin and Michigan benefit from proximity to the northeastern United States.

In contrast, much of the production in the Rocky Mountains is transported significant distances to end user markets. As a result the price received for gas in the Rocky Mountains is generally less than the price received in areas closer to the primary consuming areas. The Rocky Mountain Region is believed to hold substantial undeveloped natural gas resources.  Recent and planned additions to pipeline capacity in the region have made the area more attractive for development.  Although gas from the region will generally sell for less than gas in the Appalachian and Michigan Basins, development costs may be less.

Operations

Exploration and Development Activities

The Company's development activities focus on the identification and drilling of new productive wells, the acquisition of existing producing wells from other producers, and maximizing the value of the Company's current properties through infill drilling, recompletions, and other production enhancements.

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 experience evaluating prospects and drilling natural gas and oil wells. They utilize results from logs, seismic data and other tools to evaluate existing wells and to predict the location of economically 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 formations that are used to predict areas with prospects for economic development.

On the basis of these models, the geologists instruct the Company's land department to obtain available natural gas and oil leaseholds, farmouts and other development rights in these prospective areas. These rights 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 royalty on gross production revenue in return for obtaining the leases. In addition overriding royalty payments may be made to third parties in conjunction with the acquisition of drilling rights initially leased by others.  As of December 31, 2005, the Company had leasehold rights to approximately 258,000 acres available for development. See "Properties--Oil and Natural Gas Leases."

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Drilling Activities

When prospects have been identified and leased, the Company develops these properties by drilling wells.  In 2005, the Company drilled a total of 234 development wells of which 232 were successfully completed as producing wells. Typically, the Company will act as driller‑operator for these prospects, frequently selling interests in the wells to partnerships, primarily Company‑sponsored partnerships, and other entities that are interested in exploration or development of the prospects. The Company retains a working interest in each well it drills.   

The Company also drilled 8 exploratory wells in 2005 and plans additional exploratory wells in 2006.  Currently the Company plans to retain most if not all of the working interest in the exploratory wells, since the Company partnerships focus on developmental activities and are allowed only limited participation in exploratory drilling.  Five of the exploratory wells drilled in 2005 were dry. The associated costs of these dry holes were $11,115,100 and these costs were expensed in 2005. See "Financing of Company Drilling and Development Activities" And "Drilling and Development Activities Conducted for Company Sponsored Partnerships."

Much of the work associated with drilling, completing and connecting wells, including drilling, fracturing, logging and pipeline construction is performed under the Company's direction by subcontractors specializing in those operations, as is common in the industry. When judged advantageous, material and services used by the Company in the development process are 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. Because the prices paid to the Company by its drilling partnerships for the Company's services are frequently fixed before the wells are drilled or are determined based primarily 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 fix its development costs in advance of drilling when possible.

Drilling Activity

The following tables summarize the Company's development and exploratory drilling activity for the last five years. There is no correlation between the number of productive wells completed during any period and the aggregate reserves attributable to those wells.

Development Wells Drilled

Total

Productive

Dry

Drilled

Net

Drilled

Net

Drilled

Net

2001

141

40.00

135

37.94

6

2.06

2002

70

13.71

70

13.71

-

-

2003

110

28.51

110

28.51

-

-

2004

157

43.00

153

42.40

4

0.60

2005

234

103.40

232

102.00

2

1.40

Total

712

228.62

700

224.56

12

4.06

Exploratory Wells Drilled

Total

Productive

Dry

Drilled

Net

Drilled

Net

Drilled

Net

2001

-

-

-

-

-

-

2002

-

-

-

-

-

-

2003

1

1.00

-

-

1

1

2004

1

1.00

-

-

1

1

2005

8

7.30

3

2.30

5

5.00

Total

10

9.30

3

2.30

7

7.00

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Financing of Company Drilling and Development Activities

The Company conducts development drilling activities for its own account and acts as operator for other investors.   When conducting activities for its own account the Company uses cash flow from operations and capital provided from its long term credit facility to fund its share of operations.  The Company currently has activated $80 million of a $200 million credit facility with J.P. Morgan Chase Bank, NA and BNP Paribas (collectively "the Banks"), however the Banks have determined that the Company's current oil and gas reserves would support up to $125 million of borrowing if the need arose. As of the end of 2005 the Company had $24 million outstanding under the facility.

Drilling and Development Activities Conducted for Company Sponsored Partnerships

In addition to wells and interests in wells that it drills for itself, the Company also acts as operator for other oil and gas investors.  Historically these other investors have included individuals, corporations, partnerships formed by non-affiliated parties and other investors.  Currently the Company's drilling partners consist primarily of public and private partnerships sponsored by the Company.  The Company makes a cash investment to purchase an interest in the drilling and development activities of each partnership.

In 1984, the Company began sponsoring private drilling limited partnerships, and, in 1989, the Company began to offer partnership interests in public drilling programs registered with the SEC.  The Company's public and private partnerships had $116 million in subscriptions in 2005, $100 million in subscriptions in 2004, and $78.3 million in subscriptions in 2003. The Company invests, as its equity contribution to each drilling partnership, an additional sum approximating 22% to 32% of the aggregate subscriptions received for that particular drilling partnership and receives a 20% to 30% working interest in each partnership, respectively.  As a result, the Company is subject to substantial cash commitments at the closing of each drilling partnership. During 2005 this contribution amounted to $29.0 million. The funds received from these programs are restricted for 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.  Substantially all of the Company's drilling and development funds are now 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 number of unaffiliated parties.

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

The Company's drilling contracts with its investor partners have historically taken many different forms. Starting in 2006 the drilling agreements can be classified as a "cost plus" rate, whereby the Company receives a percentage profit in addition to the actual well costs. In the past the drilling contracts could be classified as on a "footage-based" rate, whereby the Company received drilling and completion payments based on the depth of the well. Oil and gas leases are sold to the partnership at the Company's cost. The Company may also purchase an additional working interest in the partnership properties. In its financial reporting the Company reports only its share of reserves, production, oil and gas sales and costs associated with wells in which other investors participate. 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. Accepting investments from third party investors and Company sponsored partnerships enables the Company to diversify its holdings, thereby reducing the risk of the Company's 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's management 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 or that the favorable tax treatment will continue.

Purchases of Producing Properties

In addition to drilling new wells, the Company continues to pursue opportunities to purchase existing wells from other producers as well as greater ownership interests in the wells it operates. Generally, outside interests purchased include a majority interest in the wells and the right to operate the wells. Although the Company made several offers to purchase properties during 2005, other potential purchasers outbid the Company; therefore none of its offers were successful.

The Company purchased a number of small interests in its partnerships from investor partners wishing to sell their interests in 2005, 2004 and 2003.

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Production

The following table shows the Company's net production in thousands of barrels (MBbl) of crude oil and in million cubic feet (Mmcf) of natural gas and the costs and weighted average selling prices of oil in barrels (Bbl) and gas in thousands of cubic feet (Mcf).

Year Ended December 31,

2005

2004

2003

2002

2001

Production(1):

   Oil(MBbl)

439

381

289

227

195

   Natural Gas (Mmcf)

11,031

10,372

8,712

6,462

6,085

   Equivalent Mmcf(2)

13,665

12,659

10,449

7,824

7,255

 Average sales price:

   Oil (per Bbl)(3)

$50.56

$38.00

$29.43

$24.41

$22.53

   Natural gas (per Mcf)(3)

$7.29

$5.30

$4.58

$2.65

$4.08

Average production cost  (lifting cost)

   Per equivalent Mcf(4) (restated)

$1.19

$1.12

$0.93

$0.76

$0.79

                (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 Mcf of natural gas.

                (3)             The Company utilizes commodity based economic derivative instruments to hedge and manage a portion of its exposure to price volatility of its natural gas and oil sales.  The above table does not include the results of derivative transactions.

                (4)             Production costs represent oil and gas operating expenses which include severance and ad valorem taxes as reflected in the financial statements of the Company.  See Oil and Gas Production and Well Operations Costs in Management's Discussion and Analysis.

Natural Gas Sales

Natural gas produced by the Company's well interests is generally sold under monthly contracts.  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's management 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, utilities, other gas marketers, and other wholesale gas purchasers. Three customers accounted for 15.2%, 12.9% and 10.6% respectively of the Company's revenues from oil and gas sales (9.9%, 8.4% and 6.9% of total revenues) in 2005. Two customers accounted for 14.1% and 11.3% respectively of the Company's revenues from oil and gas sales (8.6% and 7.0% of total revenues) in 2004. Three customers accounted for 16.4%, 17.2% and 14.2%, respectively of the Company's revenues from oil and gas sales (10.5%, 11.1% and 9.1% of total revenues) in 2003. No other single purchaser of the Company's natural gas accounted for 10% or more of the Company's total revenues during 2005, 2004, and 2003.

At December 31, 2005, natural gas produced by the Company sold at prices per Mcf ranging from $2.52 to $13.31, depending upon well location, the date of the sales contract and other factors.  The weighted net average price of natural gas sold by the Company during 2005 was $7.29 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 significant curtailment by providing natural gas to purchasers at competitive prices. Open access transportation through the country's interstate pipeline system makes a broad range of markets accessible to the Company. Whenever feasible the Company obtains access to multiple pipelines and markets from each of its gathering systems seeking the best available market for its natural gas at any point in time.

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Oil Sales

Some of the Company's wells in the Appalachian Basin, Michigan, most of the Company's wells in Wattenberg field in Colorado, and the Company's North Dakota wells produce oil in addition to natural gas. At the end of 2005 oil was about 10% of the Company's total equivalent reserves.

The Company is currently able to sell all the oil that it can produce under existing sales contracts with petroleum refiners and marketers. The Company does not refine any of its oil production. The Company's crude oil production is sold to purchasers at or near the Company's wells under short-term purchase contracts. One purchaser accounted for 10.5%, 7.8% and 10.9% of the Company's revenues from oil and gas sales (6.9%, 4.8% and 7.0% of total revenues) in 2005, 2004, and 2003. At December 31, 2005, oil produced by the Company sold at prices ranging from $54.40 to $57.37 per barrel, depending upon the location and quality of oil. In 2005, the weighted net average price per barrel of oil sold by the Company was $50.56.

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 and Counter-measures ("SPCC") 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.

Natural Gas Marketing

The Company's natural gas marketing activities involve the purchase of natural gas from other producers and the sale of that natural gas along with natural gas produced by the Company. The Company's management believes that in a deregulated market, successful natural gas marketing is an essential component of 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 alternative 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.

RNG, a wholly owned subsidiary, is a natural gas marketing company that specializes in the purchase, aggregation and sale of natural gas production in the Company's operating areas. 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 natural gas markets 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. 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.

Derivative Activities

The Company utilizes commodity based economic derivative instruments to manage a portion of the exposure to price volatility stemming from its oil and natural gas sales and marketing activities.  These instruments consist of NYMEX-traded natural gas futures and option contracts for Appalachian, Michigan and eastern Colorado production, and CIG (Colorado Interstate Gas Index)-based contracts for other Colorado production and NYMEX traded oil futures and option contracts for Colorado oil production. The Company may utilize derivatives based on other indices or markets where appropriate. The contracts economically hedge committed and anticipated natural gas purchases and sales and anticipated oil sales, generally forecasted to occur within the next two to three year period. Company policy prohibits the use of natural gas or oil futures or options for speculative purposes and permits utilization of derivatives only if there is an underlying physical position.

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The Company through RNG has extensive experience with the use of cash-settled derivatives to reduce the risk and impact of natural gas price changes. These financial derivatives are used by RNG to coordinate fixed and variable priced purchases and sales, and by the Company to "lock in" fixed prices from time to time for the Company's share of production, and to establish "floors" and "ceilings" or "collars" on the possible range of the prices realized for the sale of natural gas and oil. RNG also enters into fixed-price purchases and sales contracts with counterparties. These fixed physical contracts meet the FAS 133 definition of a derivative. Both types of derivatives (i.e., the physical deals and the cash settled contracts) are carried on the balance sheet at fair value with changes in fair values recognized currently in the income statement. While derivatives can help provide price protection if spot prices drop, derivatives can also limit upside potential.

For natural gas sales not subject to fixed price contracts, the Company is subject to price fluctuations for natural gas sold in the spot market and under market index contracts. The Company continues to evaluate the potential for reducing these risks by entering into derivative transactions. In addition, the Company may also close out any portion of derivatives that may exist from time to time which may result in a realized gain or loss on that derivative transaction.  The Company economically manages the price risk on only a portion of its anticipated production, so some of the production is subject to the full fluctuation of market pricing.

Well Operations

The Company currently operates approximately 1,365 wells in the Appalachian Basin, 205 wells in the Michigan Basin and 1,077 wells in the Rocky Mountain Region. The Company's ownership interest in these wells ranges from less than 1% to 100%, and, on average, the Company has an approximate 50.35% ownership interest in the wells it operates.  The Company has an interest in approximately 143 non-operated wells in the Rocky Mountain Region.

The Company is paid a monthly operating fee for each well it operates for outside owners including the limited partnerships sponsored by the Company. The fee is competitive with rates charged by other operators in the area. The fee 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 gathering systems in some of its areas of operations. The Company also continues to construct new trunk lines 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 shippers 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.

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 protect consumers from unfair treatment, control and reduce the risk to the public and workers from the drilling, completion, production and transportation of oil and natural gas, 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.  In the western part of the United States the federal and state governments own a large percentage of the land and the rights to develop oil and natural gas.  Recently the Company has increased its positions in these types of leases.  Generally government leases are subject to additional regulations and controls not commonly seen on private leases. 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's management believes that it is in 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.

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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 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 may establish maximum rates of production from oil and natural gas wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production. Where wells are to be drilled on state or federal leases, additional regulations and conditions may apply.  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.  Inasmuch 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 were regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (the "NGPA") and the regulations promulgated thereunder by the Federal Energy Regulatory Commission (FERC). Maximum selling prices of certain categories of natural gas sold in "first sales," whether sold in interstate or intrastate commerce, were regulated pursuant to the NGPA. The Natural Gas Wellhead Decontrol Act (the "Decontrol Act") removed, as of January 1, 1993, all remaining federal price controls from natural gas sold in "first sales" on or after that date. FERC's jurisdiction over natural gas transportation was unaffected by the Decontrol Act. While sales by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at market prices, Congress could reenact price controls in the future.

The Company's sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. In the past, 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 was 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 has 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 occur frequently in the Congress, FERC, state commissions, state legislatures, 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 and reduced access to the natural gas industry in general, the business and prospects of the Company could be adversely affected.

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

CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for release of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the 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 2005 were not significant in relation to operating costs and the Company expects no material change in 2006. 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.

Operating Hazards and Insurance

The Company's exploration and production operations include a variety of operating risks, including the risk of fire, explosions, blowouts, cratering, 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's management believes that its exploration, drilling and production capabilities and the experience of its management and professional staff 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 oil and natural gas and obtaining desirable oil and 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 that 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.  During 2005 the industry experienced increased demand for drilling services and supplies.  This is resulting in increasing costs, and in some cases the demand for supplies and services exceeds the available supplies. This can result in higher well costs and delays in the execution of planned drilling operations. Factors affecting competition in the oil and natural gas industry include price, location, availability, quality and volumes produced. The Company's management 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, 2005, the Company had 150 employees, including 21 in finance and data processing, 9 in administration, 15 in exploration and development, 99 in production and 6 in natural gas marketing. The Company's engineers, supervisors and well tenders are 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 added 36 new employees in 2005.

The Company's employees are not covered by a collective bargaining agreement. The Company considers relations with its employees to be excellent.

Item 1A. Risks Related to the Oil and Natural Gas Industry and the Company

You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock or other securities.

Oil and natural gas prices fluctuate unpredictably and a decline in oil and natural gas prices can significantly affect the Company's financial results and impede its growth.

The Company's revenue, profitability and cash flow depend in large part upon the prices and demand for oil and natural gas. The markets for these commodities are very volatile and even relatively modest drops in prices can significantly affect the Company's financial results and impede its growth. Changes in oil and natural gas prices have a significant impact on the value of the Company's reserves and on its cash flow. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond the Company's control, including national and international economic and political factors and federal and state legislation.

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Lower oil and natural gas prices may not only decrease the Company's revenues, but also may reduce the amount of oil and natural gas that the Company can produce economically. This may result in the Company having to make substantial downward adjustments to its estimated proved reserves. If this occurs or if the Company's estimates of development costs increase, production data factors change or the Company's exploration results deteriorate, accounting rules may require us to write down to fair value, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. The Company assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which management reasonably estimates such products to be sold. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows. The Company may incur impairment charges in the future, which could have a material adverse effect on its results of operations.

The Company's estimated oil and gas reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of the Company's reserves.

No one can measure underground accumulations of oil and natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate. The Company's estimates of oil and gas reserves are prepared by the independent petroleum engineers, using pricing, production, cost, tax and other information provided by the Company. Over time, the independent petroleum engineers may make material changes to reserve estimates taking into account the results of actual drilling, testing, and production. The reserve estimates are based on certain assumptions regarding future oil and natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect the estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, future depreciation, depletion and amortization rates and amounts, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Some of our reserve estimates are made without the benefit of a lengthy production history, which renders these reserve estimates less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which the reserve estimates are based, as described above, often result in the actual quantities of oil and gas recovered being different from earlier reserve estimates.

The present value of future net cash flows from the proved reserves is not necessarily the same as the current market value of the estimated oil and natural gas reserves (the Securities and Exchange Commission requires the use of year end prices). The estimated discounted future net cash flows from proved reserves are based on selling prices in effect on the day of estimate (year end) and future estimated costs. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as actual prices we receive for oil and natural gas, the amount and timing of actual production, amount and timing of future development costs, supply of and demand for oil and natural gas, and changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor (rate required by the Securities and Exchange Commission) we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates currently in effect and risks associated with our oil and gas properties or the oil and natural gas industry in general.

Unless oil and natural gas reserves are replaced as they are produced, the Company's reserves and production will decline, which would adversely affect the Company's business, financial condition and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline will change if production from existing wells declines in a different manner than we have estimated and can change due to other circumstances. Thus, the Company's future oil and natural gas reserves and production and, therefore, its cash flow and income are highly dependent on efficiently developing and exploiting the Company's current reserves and economically finding or acquiring additional recoverable reserves. The Company may not be able to develop, discover or acquire additional reserves to replace our current and future production at acceptable costs. As a result, the Company's operations, financial condition and results of operations would be adversely affected.

Prospects drilled by the Company may not yield natural gas or oil in commercially viable quantities.

A prospect is a property on which the Company's geologists have identified what they believe, based on available information, to be indications of natural gas or oil bearing rocks. However, the use of available data and other technologies and the study of producing fields in the same area will not enable the geologists to know conclusively prior to drilling and testing whether natural gas or oil will be present or, if present, whether natural gas or oil will be present in sufficient quantities to repay drilling or completion costs and generate a profit. If a well is determined to be dry or uneconomic, which can occur even though it contains some

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oil or gas, it is classified as a dry hole and must be plugged and abandoned in accordance with applicable regulations.  This generally results in the loss of the entire cost of drilling and completion to that point, the cost of plugging, and lease costs associated with the prospect.  Even wells that are completed and placed into production may not produce sufficient oil and gas to be profitable.  If the Company drills a dry hole or non-profitable well on current and future prospects, the profitability of its operations will decline and the value of the Company will be reduced. In sum, the cost of drilling, completing and operating any well is often uncertain and new wells may not be productive.

The Company may not be able to identify enough attractive prospects on a timely basis to meet its own development needs and those of the partnerships it forms for investors, which could limit the Company's development opportunities and/or force it to reduce the partnership activity.

Our geologists have identified a number of potential drilling locations on our existing acreage. These drilling locations must be replaced as they are drilled for the Company to continue to grow its reserves and production, and for it to be able to continue its partnership drilling activities. The Company's ability to identify and acquire new drilling locations depends on a number of uncertainties, including the availability of capital, regulatory approvals, oil and natural gas prices, competition, costs, drilling results, and the ability of the Company's geologists to successfully identify potentially successful new areas to develop. Because of these uncertainties, the Company's profitability and growth opportunities may be limited by the timely availability of new drilling locations, and it could be forced to terminate or curtail its partnership activities because of a lack of suitable prospects for the partnerships.  As a result, the Company's operations and profitability would be adversely affected.

 

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect the Company's business, financial condition and results of operations.

Drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil and natural gas can be unprofitable, not only from dry holes, but from productive wells that do not produce sufficient revenues to return a profit. In addition, drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including unusual or unexpected geological formations, pressures, fires, blowouts, loss of drilling fluid circulation, title problems, facility or equipment malfunctions, unexpected operational events, shortages or delivery delays of equipment and services, compliance with environmental and other governmental requirements, and adverse weather conditions.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and regulatory penalties.  The Company maintains insurance against various losses and liabilities arising from operations; however, insurance against all operational risks is not available. Additionally, the Company management may elect not to obtain insurance if the cost of available insurance is excessive relative to the perceived risks presented. Thus, losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on the Company's business activities, financial condition and results of operations.

Increased drilling activity, particularly in the Rocky Mountain Region, may create a shortage of drilling rigs, service providers, or materials forcing the Company to curtail its drilling operations for itself and its partnerships thereby reducing revenue and profits from new oil and gas wells and from the Company's drilling and completion activities. 

 

With high levels of oil and gas prices many oil and gas companies have increased their levels of drilling and completing new wells and reworking old wells.  At the same time there is a limited supply of drilling rigs, completion equipment and qualified personnel to provide the services necessary to drill, complete and rework new wells.  In particular, the Rocky Mountain Region has seen a great increase in activity over the past few years.  If the demand for these goods and services continues to increase shortages may develop, which could result in increased prices for these goods and services or the Company's inability to complete all of the drilling it has planned.  This could result in less drilling by the Company and the temporary or permanent loss of part or all of its partnership drilling activity and less profitability for the Company.

 

The Company's drilling and development segment receives virtually all of its revenue from the partnerships it sponsors, and a reduction or loss of that business could reduce or eliminate the revenue and profits associated with those activities.

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The Company's drilling activities are dependent upon the capital raised by the Company as a sponsor of limited partnerships.  The Company sells oil and natural gas partnerships through a network of non-affiliated NASD broker dealers.  The largest of those broker dealers sold about 13.8% of the partnership units in 2005.  Investors in the partnerships are interested in the tax deductions generated by the intangible drilling costs and the cash flow generated by the partnerships.  If the tax laws were changed to reduce or eliminate the tax advantages, if the cash flow from the partnerships were to decline due to weak wells or lower energy prices, or if the brokers decide to stop offering our partnerships for some reason, the sales of the partnership units would decline, reducing or eliminating the revenue and profits associated with the drilling and development business segment. As a result, the Company's operations and profitability would be adversely affected.

Under the Successful Efforts accounting method used by the Company unsuccessful exploratory wells must be expensed in the period when they are determined to be non-productive which results in a reduction of the Company's  net income and profitability and could have a negative impact on the Company's stock price.

 

The Company increased its exploratory drilling in 2005 and plans to further increase its exploratory drilling in 2006 in order to identify additional opportunities for future development.  However the cost of unsuccessful exploratory wells must be charged to expense in the period when they are determined to be unsuccessful under the successful efforts method of accounting used by the Company.  In addition lease costs for acreage condemned by the unsuccessful well must also be expensed.  In contrast unsuccessful development wells are capitalized as a part of the investment in the field where they are located.  Because exploratory wells generally are more likely to be unsuccessful than development wells, the Company anticipates that some or all of its exploratory wells may not be productive.  The costs of such unsuccessful wells could result in a significant reduction in the Company's profitability in periods when the costs are required to be expensed, which could have an adverse effect on the Company's stock price.  In addition unsuccessful wells will not add to the Company's reserves or production.

We may incur substantial impairment write-downs, due to revisions in our estimates of our reserves, if development costs exceed estimates or if price of oil and natural gas declines.

                If management's estimate of the recoverable reserves on a property is revised downward, if development costs exceed previous estimates or if oil and natural gas prices decline, we may be required to record additional non-cash impairment writedowns in the future, which would result in a negative impact to our financial position. We review our proved oil and gas properties for impairment on a quarterly basis. To determine if a depletable unit is impaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying management's estimates of future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property.  Future net cash flows are based upon our independent reserve engineers' estimates of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions. For each property determined to be impaired, we recognize an impairment loss equal to the difference between the estimated fair value and the carrying value of the property on a depletable unit basis. Fair value is estimated to be the present value of the aforementioned expected future net cash flows. Any impairment charge incurred is recorded as a reduction to the asset value. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units' estimated reserves, future cash flows and fair value.  There were no impairments during 2005, 2004 or 2003.

Rising finding and development costs may impair our profitability.

In order to continue to grow and maintain its profitability, the Company must annually add new reserves exceeding its yearly production at a finding and development cost that yields an acceptable operating margin and depreciation, depletion and amortization rate. Without cost effective exploration, development or acquisition activities, production, reserves and profitability will decline over time. Given the relative maturity of most gas basins in North America the cost of finding new reserves through exploration and development operations has been increasing. The acquisition market for natural gas properties has become extremely competitive among producers for additional production and expanded drilling opportunities in North America. Acquisition values climbed toward historic highs during 2005 on a per unit basis, particularly in the Rocky Mountain Region, and the Company believes these values may continue to increase in 2006. This increase in finding and development costs is resulting in higher depreciation, depletion and amortization rates. If the upward trend in finding and development costs continues, the Company will be exposed to an increased likelihood of a write-down in carrying value of its natural gas and oil properties in response to falling prices, which would impair its profitability.

The Company's development and exploration operations require substantial capital and it may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our natural gas and oil reserves and production.

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The oil and natural gas industry is capital intensive. The Company makes and expects to continue to make substantial capital expenditures in its business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. To date, the Company has financed capital expenditures primarily with cash generated by operations, limited partnership offerings and proceeds from bank borrowings. Currently the Company intends to finance its capital expenditures with cash flows from operations, and its existing financing arrangements. Cash flows from operations and access to capital are subject to a number of variables, including the Company's proved reserves, the level of oil and natural gas the Company is able to produce from existing wells, the prices at which oil and natural gas are sold, and the Company's ability to acquire, locate and produce new reserves.

If the Company's revenues or the borrowing base under its revolving credit facility decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, it may have limited ability to obtain the capital necessary to sustain its operations at planned levels.

If additional capital is needed, the Company may not be able to obtain debt or equity financing on favorable terms, or at all. If cash generated by operations or sale of limited partnerships or available under our revolving credit facility is not sufficient to meet our capital requirements, failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our natural gas and oil reserves and a decline in our profitability.

The Company's credit facility and other debt financing have substantial restrictions and financial covenants and the Company may have difficulty obtaining additional credit, which could adversely affect our operations.

The Company will depend on its revolving credit facility for future capital needs. We also are required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flows from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the revolving credit facility or other debt financing could result in a default under those facilities, which could cause all of our existing indebtedness to be immediately due and payable.

The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion, based upon projected revenues from the oil and natural gas properties securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility. Our inability to borrow additional funds under our credit facility could adversely affect our operations.

A substantial part of the Company's producing properties is located in the Rocky Mountains, making it vulnerable to risks associated with operating in one major geographic area.

The Company's operations are becoming increasingly focused on the Rocky Mountain Region, which means its producing properties and new drilling opportunities are geographically concentrated in that area. As a result, the Company, the success of its operations, and its profitability may be disproportionately exposed to the impact of delays or interruptions of production from existing or planned new wells by significant governmental regulation, transportation capacity constraints, curtailment of production, interruption of transportation, or fluctuations in prices of oil and natural gas produced from the wells in the region.

Seasonal weather conditions and lease stipulations adversely affect the Company's ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in the Rocky Mountains are adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife. In certain areas, including parts of the Sand Wash and Piceance Basins in Colorado, drilling and other oil and natural gas activities are restricted or prohibited by lease stipulations, or prevented by weather conditions, for up to 6 months out of the year. This limits operations in those areas and can intensify competition during those months for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay operations and materially increase operating and capital costs and therefore adversely affect profitability.   

17



Properties that the Company buys may not produce as projected and the Company may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them.

One of the Company's growth strategies is to acquire producing oil and natural gas reserves in its areas of operations and in new areas to help establish a base of operations for further development. However, reviews of potential acquisitions are inherently incomplete because it generally is not feasible to review in depth every individual property. Ordinarily, the Company focuses review efforts on the higher value properties and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable or detectable even when an inspection is undertaken. Even when problems are identified, the Company may choose to assume certain environmental and other risks and liabilities in connection with acquired properties.

We have limited control over activities on properties we do not operate, which could reduce our production and revenues.

The Company operates most of the wells in which it owns an interest.  However there are some wells the Company does not operate because it participates through joint operating agreements under which it owns partial interests in oil and natural gas properties operated by other entities. If the Company does not operate the properties in which it owns an interest, it does not have control over normal operating procedures, expenditures or future development of underlying properties. The failure of an operator to adequately perform operations, or an operator's breach of the applicable agreements, could reduce production and revenues and affect our profitability. The success and timing of drilling and development activities on properties operated by others therefore depends upon a number of factors outside of the Company's control, including the operator's timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells, and use of technology.

Market conditions or operational impediments hinder access to oil and natural gas markets or delay production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder access to oil and natural gas markets or delay production. The availability of a ready market for oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. The Company's ability to market its production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Failure to obtain such services on acceptable terms could materially harm the Company's business. We may be required to shut in wells for lack of market or because of inadequacy or unavailability of natural gas pipeline, gathering system capacity or processing facilities. If that were to occur, the Company would be unable to realize revenue from those wells until production arrangements were made to deliver the production to market and its profitability would be adversely affected.

Our derivative activities could result in financial losses or could reduce our income.

To achieve a more predictable cash flow, to reduce exposure to adverse fluctuations in the prices of oil and natural gas and to allow our gas marketing company to offer pricing options to gas sellers and purchasers, the Company uses derivatives for a portion of its oil and natural gas production from its own wells, and for gas purchases and sales by its marketing subsidiary. These arrangements expose the Company to the risk of financial loss in some circumstances, including when production, purchases or sales are different than expected, the counter-party to the derivative contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the derivative agreement and actual prices received.  In addition, derivative hedging arrangements may limit the benefit from changes in the prices for oil and natural gas and may require the use of Company resources to meet cash margin requirements. Since the Company does not use hedge accounting treatment for their derivatives, its earnings are subject to greater volatility.

The inability of one or more of our customers to meet their obligations may adversely affect our financial results.

Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, the Company's oil and natural gas derivatives as well as the derivatives used by its marketing subsidiary expose the Company to credit risk in the event of nonperformance by counterparties.

The Company depends on a limited number of key personnel who would be difficult to replace.

The Company depends on the performance of our executive officers and other key employees. The loss of any member of senior management or other key employees could negatively impact the Company's ability to execute its strategy. The Company does not maintain key person life insurance policies on any of its employees.

18



Terrorist attacks or similar hostilities may adversely impact our results of operations.

 

                The terrorist attacks that took place in the United States on September 11, 2001 were unprecedented events that have created many economic and political uncertainties, some of which may materially adversely impact our business. Uncertainty surrounding military strikes or a sustained military campaign may affect our operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or indirect casualties of, an act of terror or war. The continuation of these developments may subject our operations to increased risks and depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations, financial condition and prospects.

Our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur.

The occurrence of a significant accident or other event not fully covered by our insurance could have a material adverse effect on our operations and financial condition. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable.

We may not be able to keep pace with technological developments in our industry.

                The natural gas and oil industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies.  As others use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those new technologies at substantial cost. In addition, other natural gas and oil companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

 

Competition in the oil and natural gas industry is intense, which may adversely affect the Company's ability to succeed.

The oil and natural gas industry is intensely competitive, and the Company competes with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than the Company can, which would adversely affect the Company's competitive position. The Company's ability to acquire additional properties and to discover reserves in the future will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because many companies in our industry have greater financial and human resources, the Company may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.   These factors could adversely affect the success of the Company's operations and its profitability.

The Company is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.

The Company's exploration, development, production and marketing operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Under these laws and regulations, the Company could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of operations and subject the Company to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

19



Part of the regulatory environment includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. In addition, the Company's activities are subject to the regulation by oil and natural gas-producing states of conservation practices and protection of correlative rights. These regulations affect operations and limit the quantity of oil and natural gas that can be produced and sold. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals, drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on the Company's ability to explore on or develop its properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect profitability. Furthermore, the Company may be put at a competitive disadvantage to larger companies in the industry who can spread these additional costs over a greater number of wells and larger operating staff. See "Business - Governmental Regulation - Regulation of Oil and Natural Gas Exploration and Production" and "Business - Governmental Regulation - Environmental Regulations" for a description of the laws and regulations that affect us.

Item 2. Properties

Summary of Productive Wells

The table below shows the number of the Company's productive gross and net wells at December 31, 2005.

Productive Wells

Gas

Oil

Location

Gross

 Net 

 Gross

 Net  

Colorado

1,187

644.34

4

0.79

Kansas

25

22.00

-

-

Michigan

198

110.17

7

2.66

North Dakota

-

-

4

2.50

Pennsylvania

420

92.21

-

-

Tennessee

1

0.71

35

13.73

West Virginia

905

514.01

4

1.72

   Total

2,736

1,383.44

54

21.40

Oil and Gas 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 independent petroleum engineers, to be 247,288,000 Mcf of natural gas and 4,538,000 Bbls of oil at December 31, 2005, 197,549,000 Mcf of natural gas and 3,316,000 Bbls of oil at December 31, 2004, and 180,998,000 Mcf of natural gas and 3,029,000 Bbls of oil at December 31, 2003.

The Company's approximate net proved developed reserves were estimated, by independent petroleum engineers, to be 155,354,000 Mcf of natural gas and 3,860,000 Bbls of oil at December 31, 2005, 146,152,000 Mcf of natural gas and 3,190,000 Bbls of oil at December 31, 2004, and 134,936,000 Mcf of natural gas and 2,889,000 Bbls of oil at December 31, 2003.

The Company utilized the services of two independent petroleum engineers for its 2005 independent reserve report.  Wright & Company prepared the reserve report for the Appalachian and Michigan Basins and Colorado wells.  Ryder Scott Company, LLP prepared the reserve report for the North Dakota Bakken Shale wells. Wright & Company prepared all of the reserve reports for the Company for 2004 and 2003.

The Company's oil and natural gas reserves by region are as follows as of December 31, 2005:

20



Natural Gas

 Oil  

Gas  

Equivalent

(Mbbl)

(Mmcf)

 (Mmcfe) 

   %   

Proved Developed Reserves

Appalachian Basin

42

37,843

38,095

21.34

Michigan Basin

53

25,094

25,412

14.24

Rocky Mountain Region

3,765

92,417

115,007

64.42

Total Proved Developed Reserves

3,860

155,354

178,514

100.00

Proved Undeveloped Reserves

Appalachian Basin

-

-

-

-

Michigan Basin

-

544

544

0.57

Rocky Mountain Region

678

91,390

95,458

99.43

Total Proved Undeveloped

678

91,934

96,002

100.00

Total Proved Reserves

Appalachian Basin

42

37,843

38,095

13.88

Michigan Basin

53

25,638

25,956

9.46

Rocky Mountain Region

4,443

183,807

210,465

76.66

Total Proved Reserves

4,538

247,288

274,516

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, 2005.  Reserves cannot be measured exactly, because 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 estimated net cash flows attributable to the Company's proved oil and gas reserves, giving effect to future estimated income tax expenses, was estimated by our independent petroleum engineers to be $405.4 million as of December 31, 2005, $229.4 million as of December 31, 2004, and $202.4 million as of December 31, 2003. These amounts are based on December 31 prices in the respective years. 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.

Net Proved Natural Gas and Oil Reserves

The proved reserves of natural gas and oil of the Company as estimated by our independent petroleum engineers at December 31, 2005 are set forth below. These reserves have been prepared in compliance with the rules of the Securities and Exchange Commission (the "SEC") based on December 31, 2005 prices. These reserve estimates were not filed with another Federal authority or agency since the Company filed its Form 10-K/A as of December 31, 2004. An analysis of the change in estimated quantities of natural gas and oil reserves from January 1, 2005 to December 31, 2005, all of which are located within the United States, is shown below:

21



 

Natural Gas (Mcf)

Oil (Bbl)

Proved developed and undeveloped reserves:

Beginning of year

197,549,000

3,316,000

Revisions of previous estimates

(15,850,000)

80,000

Beginning of year as revised

181,699,000

3,396,000

New discoveries and extensions

     Rocky Mountain region

85,624,000

1,576,000

Dispositions to partnerships

(9,556,000)

-

Acquisitions

     Michigan Basin

47,000

-

     Rocky Mountain region

71,000

5,000

     Appalachian basin

434,000

-

Production

(11,031,000)

(439,000)

End of  year

247,288,000

4,538,000

Proved developed reserves:

Beginning of year 

146,152,000

3,190,000

End of  year

155,354,000

3,860,000

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, 2005 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.

Future Estimated Cash Flows

 $    2,381,238,000

Future Estimated Production Costs

        (545,683,000)

Future Estimated Development Costs

        (207,164,000)

Future Estimated Income Tax Expense

        (633,444,000)

Future Net Cash Flows

          994,947,000

10% Annual Discount for Estimated

Timing of Cash Flows

        (589,517,000)

Standardized Measure of Discounted

Future Estimated Net Cash Flows

 $       405,430,000

22



The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows from January 1, 2005 through December 31, 2005:

2005

Sales of oil and gas production

net of production costs

 $       (86,366,000)

Net changes in prices and production costs

208,353,000

Extensions, discoveries, and improved

recovery, less related costs

150,654,000

Sales of reserves

(14,456,000)

Purchase of reserves

1,266,000

Development costs incurred during the period

24,035,000

Revisions of previous quantity estimates

(24,130,000)

Changes in estimated income taxes

(112,054,000)

Accretion of discount

38,241,000

Timing and other

(9,541,000)

Total

 $       176,002,000

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, because 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 their inherent limitations.

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 to the notes to the Company's financial statements.

Oil and Natural Gas Leases

The following table sets forth, as of December 31, 2005, the acres available for development of oil and natural gas available to the Company, listed alphabetically by state.

Colorado

115,200

Kansas

22,800

Michigan

3,000

New York

North Dakota

10,000

80,000

Wyoming

 27,250

Total

258,250

Title to Properties

The Company's management 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. Those 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.

23



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.

Facilities

The Company owns and occupies three buildings in Bridgeport, West Virginia, two of which serve as the Company's headquarters and one that serves as a field operating facility. The Company is currently building a new corporate office in Bridgeport, WV which it will occupy in late 2006. The Company also owns a field operating building in Weld County, Colorado and Gilmer County, West Virginia.  The Company has operating leases for field offices in Colorado, Michigan and Pennsylvania.

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 have a materially adverse affect on the Company's business, financial condition, results of operations, or liquidity.

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

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

PART II

Item 5.    Market for the Registrant's Common Equity and Related Stockholders Matters and Issuer Purchases of Equity Securities.

The common stock of the Company is traded in the NASDAQ National 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 NASDAQ. These quotations represent inter-dealer prices without retail markups, markdowns, commissions or other adjustments and may not represent actual transactions.

High

Low

2005

First Quarter

$44.19

$35.72

Second Quarter

37.28

22.65

Third Quarter

40.00

32.54

Fourth Quarter

39.55

30.53

2004

First Quarter

33.93

16.70

Second Quarter

32.63

21.01

Third Quarter

44.80

24.50

Fourth Quarter

49.26

32.06

As of May 11, 2006, there were approximately 874 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.

24



Item 6.  Selected Financial Data  


Year Ended December 31,

2005

2004 (1)

2003 (1)

2002 (2)

2001 (2)

(Restated)

(Restated)

(Restated)

(Restated)

Revenues:

  Oil and gas well drilling operations

 $    99,962,900

 $   94,076,000

 $   57,509,600

 $   45,842,000

 $   60,756,300

  Gas sales from marketing activities

     121,104,100

      94,626,800

      73,131,700

      43,536,400

      67,070,900

  Oil and gas sales

     102,559,200

      69,492,100

      48,393,800

      22,688,100

      29,199,100

  Well operations and pipeline income

         8,759,600

        7,676,900

        6,907,100

        5,771,200

        5,349,200

  Other income

       10,747,300

        1,880,700

        3,528,500

        2,796,800

        3,132,400

          Total revenues

     343,133,100

    267,752,500

    189,470,700

    120,634,500

    165,507,900

Costs and expenses:

  Cost of oil and gas well drilling operations

       88,184,900

      77,696,200

      46,945,900

      37,859,100

      50,465,000

  Cost of gas marketing activities

     119,643,700

      92,881,200

      72,361,400

      43,167,700

      66,545,100

 Oil and gas production and well  operations costs

       19,934,700

      17,277,200

      13,251,300

        8,672,400

        8,327,700

 Exploratory dry hole costs

       11,115,100

             -      

             -      

             -      

             -      

  General and administrative expenses

         6,960,300

        4,505,600

        4,974,400

        4,391,900

        4,145,700

  Depreciation, depletion and amortization

       21,116,200

      18,155,900

      15,312,800

      12,601,500

      11,582,100

  Impairment of oil and gas properties

             -      

             -      

             -      

             -      

      10,541,900

          Total costs and expenses

     266,954,900

    210,516,100

    152,845,800

    106,692,600

    151,607,500

  Income from operations

       76,178,200

      57,236,400

      36,624,900

      13,941,900

      13,900,400

  Interest expense

            682,300

           673,700

        1,195,300

        1,504,800

       1,898,700

 Oil and gas price risk management loss, net

         9,368,100

        3,084,600

           812,400

           369,800

        3,311,200

   Income before income taxes and cumulative effect

     of change in accounting principle

       66,127,800

      53,478,100

      34,617,200

 12,067,300 

        8,690,500

Income taxes

       24,676,100

      20,250,500

      11,933,500

   3,186,200 

        1,803,100

   Net income before cumulative effect of change in

      accounting principle

       41,451,700

      33,227,600

      22,683,700

        8,881,100

        6,887,400

Cumulative effect of change in accounting

  principle  (net of taxes of $1,392,000)

             -    

             -    

       (2,271,300)

              -    

            -      

Net income

 $    41,451,700

 $   33,227,600

 $   20,412,400

 $     8,881,100

 $     6,887,400

Basic earnings per common share

$2.53

$2.05

$1.30

$0.56

$0.42

Diluted earnings per share

$2.52

$2.00

$1.25

$0.55

$0.41

December 31,

2005

2004

2003

2002

2001

Total Assets

 $  449,084,900

 $ 335,028,300

 $ 297,541,600

 $ 201,022,200

 $ 186,255,700

Working Capital (Deficit)

 $  (25,831,200)

 $        231,100

 $     7,287,800

 $     3,173,300

 $     3,310,800

Long-Term Debt

 $    24,000,000

 $   21,000,000

 $   53,000,000

 $   25,000,000

 $   28,000,000

Stockholders' Equity

 $  188,265,300

 $ 154,020,600

 $ 112,559,200

 $   92,886,600

 $   87,616,300

(1)     See Note 22 on page F-36 for the effect of the restatement on the above data.

(2)     See Explanatory Note regarding restatement on Page 2.

25



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's management 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 incidental 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; the Company's ability to acquire leases, drilling rigs, supplies and services at reasonable prices; the availability of capital to the Company; the Company's ability to raise funds through its Partnership Drilling Programs;  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 oil and gas derivatives activities; and conditions in the capital markets.  Other risk factors are discussed elsewhere in this Form 10-K.

2005 Restatement

As previously mentioned under "Explanatory Note Regarding Restatement" on Page 2 and Note 22 on F-35, the Company is amending and restating its prior consolidated statements of income for the years ended December 31, 2004 and 2003, for the quarterly periods ended March 31, 2005, June 30, 2005 and September 30, 2005 and for each of the quarters ended in the years 2004 and 2003. The selected financial data for the years ended December 31, 2002 and 2001 has also been restated. The restatement is being made to correct errors in the reporting of certain revenues and expenses to properly reflect the elimination of transactions between the Company and the Company sponsored limited partnerships. The corrections resulted in the elimination of revenues and expenses of equal amounts. The restatement had no effect on net income, earnings per share, cash flows, proved oil and gas reserves, or the Company's financial position.

Results of Operations

Management Overview

The Company has recorded historically strong revenues, income and cash flow for 2005. High oil and natural gas prices in combination with record Company production were the largest contributors to both income and cash flow. The high energy prices increased the Company's revenues both for sales of Company-owned production and for gas purchased and sold by RNG, our natural gas marketing subsidiary. Management also believes that high energy prices made the Company's partnership investment programs more attractive to investors resulting in a significant increase in the sale of program interests.   This resulted in an increase of drilling activity, volume of production revenues, and gross profit for the Company's drilling and development segment.  The new wells drilled for the partnerships also led to an increase in revenues for the Company to operate wells for the partnerships and others.

The increased level of activities also increased the costs associated with the drilling and development and well operations activities because goods, services and other costs were incurred as a result of the higher levels of activities and prices have increased in response to higher demand.

Profitability in 2005 was reduced by losses in derivative transactions relating to the Company's oil and gas sales in the amount of $9.4 million as recorded in the "Oil and gas price risk management" line item in the income statement. These consisted of both realized and unrealized losses. Realized losses are cash losses incurred at the maturity of derivatives positions which amounted to $6.4 million during 2005. Unrealized losses are charges that reflect possible losses on derivative positions maturing in future periods, and may increase or decrease depending on the level of gas or oil prices at the date the derivatives mature or on the date they are closed, whichever occurs first, which amounted to $3.0 million during 2005.

The increased profitability and cash flow from operations allowed the Company to continue to invest in capital projects. The majority of capital investment was for oil and gas drilling and development activities.

26



Year Ended December 31, 2005 Compared with December  31, 2004

Revenues

Total revenues for the year ended December 31, 2005 were $343.1 million compared to a restated $267.8 million for the year ended December 31, 2004, an increase of approximately $75.3 million, or 28.1 percent. The increase was a result of increased drilling revenues, gas sales from natural gas marketing activities, oil and gas sales, well operations and pipeline income, and other income.

Costs and Expenses

Total costs and expenses for the year ended December 31, 2005 were $267.0 million compared to a restated $210.5 million for the year ended December 31, 2004, an increase of approximately $56.5 million or 26.8 percent. The increase was primarily the result of increased cost of oil and gas well drilling operations, cost of gas marketing activities, oil and gas production and well operations cost, exploratory dry hole costs, general and administrative expenses and depreciation, depletion and amortization.

Drilling Operations

 

Drilling revenues for the year ended December 31, 2005 were $100.0 million compared to a restated $94.1 million for the year ended December 31, 2004, an increase of approximately $5.9 million or 6.3 percent. Such increase was due to the increased drilling funds raised and drilled during the year through the Company's drilling programs. The two public and one private drilling program of 2005 raised $116 million compared to $100 million in 2004. We believe higher oil and natural gas prices and the resulting improved performance of our prior programs are the reasons for the increase in our drilling program sales.

Oil and gas well drilling operations costs for the year ended December 31, 2005 were $88.2 million compared to a restated $77.7 million for the year ended December 31, 2004, an increase of approximately $10.5 million or 13.5 percent. The increase was due to the higher levels of drilling activity from our public drilling programs referred to above and increased costs from higher charges for services and materials provided to the Company. The gross margin on the drilling activities for the year ended December 31, 2005 was 11.8 percent compared with 17.4 percent for the year ended December 31, 2004, a decrease in gross margin of approximately 5.6 percent. The decrease was due to significantly increasing well drilling and completion costs, particularly the costs of fracturing and rising steel costs for casing and other well equipment and oil field services.  The private drilling partnership funded on December 30, 2005 with wells to be drilled during the first quarter 2006 and future partnerships will be drilled on a "cost plus basis"; that should reduce these fluctuations in drilling gross margins.

                This new cost-plus drilling arrangement eliminates the Company's risk of loss, thus the drilling revenues and corresponding costs will be netted to a one-lined income statement item representing only the gross profit portion of the drilling arrangement. This would have a significant effect on the Company's 2006 gross drilling revenues and corresponding drilling expenses, but would not change the gross profit.

Natural Gas Marketing Activities

 

Natural gas sales from the marketing activities of RNG, the Company's marketing subsidiary for the year ended December 31, 2005 were $121.1 million compared to $94.6 million for the year ended December 31, 2004, an increase of approximately $26.5 million or 28.0 percent. The increase was the result of significantly higher average natural gas sales prices and higher volumes sold offset in part by an increase in unrealized losses on derivative transactions which amounted to approximately $9.2 million and $700,000 for the years ended December 31, 2005 and 2004, respectively.

The costs of gas marketing activities for the year ended December 31, 2005 were $119.6 million compared to $92.9 million for the year ended December 31, 2004, an increase of $26.7 million or 28.7 percent. The increase was due to higher average volumes of natural gas purchased for resale and significantly higher average purchase prices offset in part by an increase in unrealized gains on derivative transactions which amounted to approximately $9.7 million and $1.4 million for the years ended December 31, 2005 and 2004, respectively. Income before income taxes for the Company's natural gas marketing subsidiary decreased from $1.8 million for the year ended December 31, 2004 to $1.7 million for the year ended December 31, 2005. Based on the nature of the Company's gas marketing activities, derivatives did not have a significant impact on the Company's net margins from marketing activities during either period.

27



Oil and Gas Sales

Oil and gas sales from the Company's producing properties for the year ended December 31, 2005 were $102.6 million compared to $69.5 million for the year ended December 31, 2004, an increase of $33.1 million or 47.6 percent. The increase was due to higher volumes sold at significantly higher average sales prices of oil and natural gas. The volume of natural gas sold for the year ended December 31, 2005 was 11.0 million Mcf at an average price of $7.29 per Mcf compared to 10.4 million Mcf at an average sales price of $5.30 per Mcf for the year ended December 31 , 2004. Oil sales for the year ended December 31, 2005 were 439,000 barrels at an average sales price of $50.56 per barrel compared to 381,000 barrels at an average sales price of $38.00 per barrel for the year ended December 31, 2004.  The increase in natural gas and oil volumes was the result of the Company's increased investment in oil and gas properties, primarily recompletions of existing wells, wells drilled in our NECO, Colorado area of operation, and the investment in oil and gas properties we own in our public drilling program partnerships.

Oil and Gas Production

The Company's oil and gas production by area of operations along with average sales price (excluding derivative losses) is presented below:

Year Ended December 31, 2005

Year Ended December 31, 2004

Natural Gas

Natural Gas

Oil

Natural Gas

Equivalents

Oil

Natural Gas

Equivalents

(Bbl)

(Mcf)

(Mcfe)

(Bbl)

(Mcf)

(Mcfe)

Appalachian Basin

3,973

1,631,552

1,655,390

4,893

1,812,407

1,841,765

Michigan Basin

4,732

1,555,958

1,584,350

5,786

1,728,435

1,763,151

Rocky Mountains

430,266

7,843,250

10,424,846

370,482

6,831,032

9,053,924

Total

438,971

11,030,760

13,664,586

381,161

10,371,874

12,658,840

 Average Sales Price

$50.56

$7.29

$7.51

$38.00

$5.30

$5.49

                Financial results depend upon many factors, particularly the price of natural gas and our ability to market our production effectively. In recent years, natural gas and oil prices have been among the most volatile of all commodity prices. These price variations can have a material impact on our financial results. Natural gas prices in the Rocky Mountain Region continue to trail prices which we receive for our Appalachian and Michigan gas. The Company's management believes the lower prices in the Rocky Mountain Region, including Colorado, reflect the higher costs to move gas to major market areas compared to Michigan and the Appalachian Basin resulting in a lower price compared to the eastern areas. In May, 2003 a pipeline expansion project was completed, leading to improved natural gas prices in the region which reduced the local surplus. There is currently a substantial amount of drilling activity in the Rockies, and if future additions to the pipeline system are not made in a timely fashion it is possible that pipeline constraints could create a local oversupply situation in the future which could mean lower natural gas prices.  Like most other producers in the area we rely on major interstate pipeline companies to construct these facilities, so their timing and construction is not within our control. 

Oil and Gas Derivative Activities

Because of uncertainty surrounding natural gas prices we have used various derivative instruments to manage some of the impact of fluctuations in prices. Through October 2007 we have in place a series of floors and ceilings on part of our natural gas production. Under the arrangements, if the applicable index rises above the ceiling price, we pay the counterparty, however if the index drops below the floor the counterparty pays us. During the three months ended December 31, 2005 the Company averaged natural gas volumes sold of 973,700 Mcf per month and oil sales of 36,050 barrels per month. The positions in effect as of April 30, 2006 on the Company's share of production (The table below does not include positions related to Riley Marketing activities or derivative contracts entered into by the Company on behalf of the affiliate Partnerships as the Managing General Partner) by area are shown in the following table.

28



           Floors             

        Ceilings              

Monthly

Monthly

Quantity

Contract

Quantity

Contract

Mmbtu

Price

Mmbtu

Price

Month Set

Month

Colorado Interstate Gas (CIG) Based Derivatives (Piceance Basin)

Jan-05

Jan 2006 - Mar 2006

60,000

$4.50

30,000

$7.15

Jul-05

Jan 2006 - Mar 2006

27,500

$6.50

13,750

$8.27

Sep-05

Jan 2006 - Mar 2006

78,700

$9.00

-

-

Mar-05

Apr 2006 - Oct 2006

42,000

$4.50

21,000

$7.25

Jul-05

Apr 2006 - Oct 2006

27,500

$5.50

13,750

$7.63

Jul-05

Nov 2006 - Mar 2007

27,500

$6.00

13,750

$8.40

Feb-06

Nov 2006 - Mar 2007

60,000

$6.50

-

-

Feb-06

Apr 2007 - Oct 2007

44,000

$5.50

-

-

NYMEX Based Derivatives - (Appalachian and Michigan Basins)

Jan-05

Jan 2006 - Mar 2006

156,000

$5.00

78,000

$8.50

Sep-05

Jan 2006 - Mar 2006

156,000

$10.50

-

-

Mar-05

Apr 2006 - Oct 2006

78,000

$5.50

39,000

$7.40

Jul-05

Apr 2006 - Oct 2006

61,000

$6.25

30,000

$8.98

Jul-05

Nov 2006 - Mar 2007

68,000

$7.00

34,000

$9.27

Feb-06

Nov 2006 - Mar 2007

34,000

$8.00

-

-

Feb-06

Nov 2006 - Mar 2007

34,000

$8.50

34,000

$13.73

Feb-06

Apr 2007 - Oct 2007

34,000

$7.00

-

-

Feb-06

Apr 2007 - Oct 2007

34,000

$7.50

34,000

$10.83

NYMEX Based Derivatives (NECO)

Jan-05

Jan 2006 - Mar 2006

150,000

$5.00

75,000

$8.45

Panhandle Based Derivatives (NECO)

 

 

 

 

Sep-05

Jan 2006 - Mar 2006

100,000

$10.00

-

-

Mar-05

Apr 2006 - Oct 2006

150,000

$5.00

75,000

$8.62

Jul-05

Nov 2006 - Mar 2007

150,000

$6.50

75,000

$8.56

Feb-06

Apr 2007 - Oct 2007

60,000

$6.00

-

-

Feb-06

Apr 2007 - Oct 2007

60,000

$6.50

60,000

$9.80

Well Operations and Pipeline Income

Well operations and pipeline income for the year ended December 31, 2005 were $8.8 million compared to a restated $7.7 million for the year ended December 31, 2004, an increase of approximately $1.1 million or 14.3 percent. The increase was due to an increase in the number of wells and pipeline systems operated by the Company for our public drilling programs as well as for third parties.

Other Income

                Other income for the year ended December 31, 2005 was $10.7 million compared to a restated $1.9 million for the year ended December 31, 2004, an increase of $8.8 million. The increase is a result of a sale of a portion of one of our undeveloped leases in Garfield County, Colorado, which we sold to an unaffiliated entity in the first quarter of 2005 for a pre-tax gain of $6.2 million, a second quarter gain on sale to an unaffiliated party of some Pennsylvania wells in the amount of $1.7 million, management fees collected from the funding of three drilling partnerships, and interest earned on higher average cash balances and higher interest rates.

29



Oil and Gas Production and Well Operations Costs

                Oil and gas production and well operations costs from the Company's producing properties for the year ended December 31, 2005 were $19.9 million compared to a restated $17.3 million for the year ended December 31, 2004, an increase of approximately $2.6 million or 15.0 percent.  The increase was due to the increased production costs and severance and property taxes on the increased volumes and  higher average sales prices of natural gas and oil sold, along with the increased number of wells and pipelines operated by the Company. Lifting costs per Mcfe increased from a restated $1.12 per Mcf for the year ended December 31, 2004 to $1.19 per Mcfe for the year ended December 31, 2005 due to increased severance and property taxes on the significantly increased oil and gas sales prices along with additional well workovers and production enhancements work performed.

Exploratory Dry Hole Costs

The Company drilled eight exploratory wells in 2005 of which five were deemed to be dry holes. In the fourth quarter of 2005 four Kansas wells were drilled and plugged and abandoned for a total combined cost of $314,200, which included lease acreage with cost of $70,600 which was deemed impaired. Also in the fourth quarter the Coffeepot Springs #24-34 well in Colorado was determined to be uneconomical at a total dry hole cost of approximately $5.42 million, which included lease acreage with a cost of $90,000 which was deemed impaired. In the second quarter of 2005, it was determined the Fox Federal #1-13 well which was drilled in 2004 in Colorado was also an uneconomic well and total costs of approximately $5.39 million were expensed, which included lease acreage with a cost of $384,000 which was deemed impaired. These exploratory dry hole expenses were expensed in the period in which it was determined that the well was unsuccessful in accordance with the successful efforts method of accounting. All costs were incurred 100% by the Company because the drilling fund partnerships did not participate in these exploratory wells.

General and Administrative Costs

                General and administrative expenses for the year ended December 31, 2005 increased to $7.0 million compared to $4.5 million for the year ended December 31, 2004 an increase of approximately $2.5 million or 55.6 percent. The increase was primarily due to increased costs of complying with the various provisions of Sarbanes-Oxley, in particular Section 404 (Internal Controls), the cost of the Company's financial statement restatements and increased personnel costs for the increased number of employees.

Depreciation, Depletion, and Amortization

                Depreciation, depletion, and amortization costs for the year ended December 31, 2005 increased to $21.1 million from approximately $18.2 million for the year ended December 31, 2004, an increase of approximately $2.9 million or 15.9 percent. Such increase was due to the significantly increased production and investment in oil and gas properties by the Company as referred to above.

Interest Expense

Interest expense for the year ended December 31, 2005 was $682,000 compared to $674,000 for the year ended December 31, 2004, an increase of $8,000 or 1.2 percent. Such increase is due to increased accretion of the Company's asset retirement obligation and rising interest rates offset in part by lower average outstanding balance of our credit facility.  The Company utilizes its daily cash balances to reduce its line of credit to lower its cost of interest expense. The average outstanding debt balances for the year ended December 31, 2005 was $4.1 million compared to $11.3 million for the year ended December 31, 2004.

Oil and Gas Price Risk Management Loss, Net

                Oil and gas price risk management loss, net for the year ended December 31, 2005 was $9.4 million compared to approximately $3.1 million for the year ended December 31, 2004, an increase of $6.3 million.  For the year ended December 31, 2005, the Company recorded unrealized losses of $3.0 million and realized losses of $6.4 million compared to the year ended December 31, 2004, which is comprised of unrealized losses of $1.5 million and realized losses of $1.6 million. The Company's strategy in its derivative policy is to provide protection on declining oil and natural gas prices. During 2005 the Company experienced rising oil and natural gas pricing environment, this trend caused the Company to record losses in its derivative transactions. In a declining oil and natural gas pricing environment the Company would in theory record gains in its derivative transaction activities. Oil and gas price risk management (gain) loss, net is comprised of the change in fair value of oil and natural gas derivatives related to our oil and gas production (this line item does not include commodity based derivative transactions related to transactions from marketing activities).

Provision for Income Taxes

The effective income tax rate for the Company's provision for income taxes decreased from 37.9% for the year ended December 31, 2004 to 37.3% for the year ended December 31, 2005 primarily as a result of the domestic production activities deduction.

30



Net Income and Earnings Per Share

Net income for the year ended December 31, 2005 was $41.5 million compared to a net income of $33.2 million for the year ended December 31, 2004, an increase of approximately $8.3 million or 25.0 percent.

Diluted earnings per share for the year ended December 31, 2005 was $2.52 per share compared to $2.00 per share for the year ended December 31, 2004, an increase of $0.52 per share or 26.0 percent.

Year Ended December 31, 2004 Compared with December  31, 2003

Revenues

Total revenues for the year ended December 31, 2004 were a restated $267.8 million compared to a restated $189.5 million for the year ended December 31, 2003, an increase of approximately $78.3 million, or 41.3 percent. The increase was a result of increased drilling revenues, gas sales from natural gas marketing activities, oil and gas sales and well operations and pipeline income.

Oil and Gas Well Drilling Revenue

 

Drilling revenues for the year ended December 31, 2004 were a restated $94.1 million compared to a restated $57.5 million for the year ended December 31, 2003, an increase of approximately $36.6 million or 63.7 percent. Such increase was due to the increased drilling funds raised through the Company's Public Drilling Programs. The four drilling programs of 2004 raised $100 million compared to $78.3 million in 2003. We believe higher oil and natural gas prices and the resulting improved performance of our prior programs are the reasons for the increase in our drilling program sales.

Natural Gas Marketing Activities

 

Natural gas sales from the marketing activities of Riley Natural Gas (RNG), the Company's marketing subsidiary for the year ended December 31, 2004 were $94.6 million compared to $73.1 million for the year ended December 31, 2003, an increase of approximately $21.5 million or 29.4 percent. The increase was the result of significantly higher average natural gas sales prices and higher volumes sold.

Oil and Gas Sales

Oil and gas sales from the Company's producing properties for the year ended December 31, 2004 were $69.5 million compared to $48.4 million for the year ended December 31, 2003, an increase of $21.1 million or 43.6 percent. The increase was due to significantly higher volumes sold at substantially higher average sales prices of oil and natural gas. The volume of natural gas sold for the year ended December 31, 2004 was 10.4 million Mcf at an average price of $5.30 per Mcf compared to 8.7 million Mcf at an average sales price of $4.58 per Mcf for the year ended December 31, 2003. Oil sales for the year ended December 31, 2004 were 381,000 barrels at an average restated sales price of $38.00 per barrel compared to 289,000 barrels at an average sales price of $29.43 per barrel for the year ended December 31, 2003.

Since no acquisitions were made in 2004, the increase in production resulted primarily from the new wells drilled by the Company in 2004, recompletions of Wattenberg Field wells, and completion of behind pipe zones in the Appalachian Basin. Also the three acquisitions made in 2003 contributed to the increase to the extent they were not owned for the full year of 2003, but were in 2004.

Oil and Gas Production

The Company's oil and gas production by area of operations along with average sales price (excluding derivative gains/losses) is presented below:

31



Year Ended December 31, 2004

Year Ended December 31, 2003

Natural Gas

Natural Gas

Oil

Natural Gas

Equivalents

Oil

Natural Gas

Equivalents

(Bbl)

(Mcf)

(Mcfe)

(Bbl)

(Mcf)

(Mcfe)

Appalachian Basin

4,893

1,812,407

1,841,765

3,992

1,921,200

1,945,152

Michigan Basin

5,786

1,728,435

1,763,151

6,627

1,832,737

1,872,499

Rocky Mountains

370,482

6,831,032

9,053,924

278,874

4,958,245

6,631,489

Total

381,161

10,371,874

12,658,840

289,493

8,712,182

10,449,140

Average Price

$38.00

$5.30

$5.49

$29.43

$4.58

$4.63

                Financial results depend upon many factors, particularly the price of natural gas and our ability to market our production effectively. In recent years natural gas and oil prices have been among the most volatile of all commodity prices. These price variations can have a material impact on our financial results. Natural gas prices in Colorado continue to trail prices which we receive for our Appalachian and Michigan gas which are based upon NYMEX.  The Company's management believes the lower prices in the Rocky Mountain Region, including Colorado, resulted from increasing local supplies that exceeded the local demand and pipeline capacity available to move gas from the region. In May, 2003 a pipeline expansion project was completed, leading to improved natural gas prices in the region which reduced the local surplus. There is currently a substantial amount of drilling activity in the Rockies, and if future additions to the pipeline system are not made in a timely fashion it is possible that pipeline constraints could create a local oversupply situation in the future which could mean lower natural gas prices.  Like most other producers in the area we rely on major interstate pipeline companies to construct these facilities, so their timing and construction is not within our control. 

Oil and Gas Derivative Activities

Because of uncertainty surrounding natural gas prices we have used various derivative instruments to manage some of the impact of fluctuations in prices. Through October of 2006 we have in place a series of floors and ceilings on part of our natural gas production. Under the arrangements, if the applicable index rises above the ceiling price, we pay the counterparty, however if the index drops below the floor the counterparty pays us. During the three months ended December 31, 2004 the Company averaged natural gas volumes sold of 872,000 Mcf per month and oil sales of 31,000 barrels per month. The positions in effect as of March 31, 2005 on the Company's share of production (The table below does not include positions related to Riley Marketing activities or derivative contracts entered into by the Company on behalf of the affiliate Partnerships as the Managing General Partner) by area are shown in the following table.

Floors

Ceilings

Monthly

Monthly

Quantity

Contract

Quantity

Contract

Month Set

Month

Mmbtu

Price

Mmbtu

Price

NYMEX Based Derivatives - (Appalachian and Michigan Basin)

5/04

Jan 2005 - Mar 2005

180,000

$5.67

90,000

$7.00

2/04

Apr 2005 - Oct 2005

122,000

$4.28

61,000

$5.00

3/05

Apr 2005 - Oct 2005

39,000

$5.75

19,500

$8.37

1/05

Nov 2005 - Mar 2006

156,000

$5.00

78,000

$8.50

3/05

Apr 2006 -Oct 2006

78,000

$5.50

39,000

$7.40

Colorado Interstate Gas (CIG) Based Derivatives (Piceance Basin)

5/04

Jan 2005 - Mar 2005

60,000

$5.04

30,000

$6.00

2/04

Apr 2005- Oct 2005

33,000

$3.10

16,000

$4.43

3/05

Apr 2005 - Oct 2005

38,000

$4.75

19,000

$8.12

1/05

Nov 2005 - Mar 2006

60,000

$4.50

30,000

$7.15

3/05

Apr 2006 - Oct 2006

42,000

$4.50

21,000

$7.25

32




Colorado Interstate Gas (CIG) Based Derivatives (Wattenberg)

7/04

Jan 2005 - Mar 2005

80,000

$5.00

40,000

$6.20

NYMEX Based Derivatives (NECO)

7/04

Jan 2005 - Mar 2005

150,000

$5.32

-

-   

2/04

Apr 2005 - Oct 2005

150,000

$4.26

75,000

$5.00

1/05

Nov 2005 - Mar 2006

150,000

$5.00

75,000

$8.45

Oil - NYMEX Based Derivatives (Wattenberg)

Bbls

Bbls

8/04

Jan 2005 - Dec 2005

15,000

$32.30

7,500

$40.00

Well Operations, Pipeline & Other Income

Well operations and pipeline income for the year ended December 31, 2004 were a restated $7.7 million compared to a restated $6.9 million for the year ended December 31, 2003, an increase of approximately $800,000 or 11.6 percent. The increase was due to an increase in the number of wells and pipeline systems operated by the Company for our public drilling programs as well as for third parties. Other income for the year ended December 31, 2004 was a restated $1.9 million compared to a restated $3.5 million for the year ended December 31, 2003, a decrease of $1.6 million or 45.7 percent.  Other income in 2003 included $1.0 million of life insurance proceeds. In 2004 the Company, for competitive reasons, lowered the management fee it charges to its drilling partnerships to 1-1/2% of subscriptions, from 2-1/2% of subscriptions.

Costs and Expenses

Costs and expenses for the year ended December 31, 2004 were a restated $210.5 million compared to a restated $152.9 million for the year ended December 31, 2003, an increase of approximately $57.6 million or 37.7 percent. The increase was primarily the result of increased cost of oil and gas well drilling operations, gas purchased for gas marketing activities, oil and gas production costs and depreciation, depletion and amortization.

Oil and Gas Well Drilling Costs

Oil and gas well drilling operations costs for the year ended December 31, 2004 were a restated $77.7 million compared to a restated $46.9 million for the year ended December 31, 2003, an increase of approximately $30.8 million or 65.7 percent. The increase was due to the higher levels of drilling activity from our public drilling programs referred to above. In addition, the gross margin on the drilling activities for the year ended December 31, 2004 was 17.4 percent compared with 18.4 percent for the year ended December 31, 2003, a decrease in gross margin of approximately 1.0 percent. Such decrease was due to significantly increasing well drilling and completion costs, particularly the costs of fracturing and rising steel costs for casing and other well equipment. For the first two partnerships in 2005, the Company raised its turnkey rates charged to its Public Drilling Partnerships to reverse this declining trend in gross margins.

Cost of Gas Marketing Activities

The costs of gas marketing activities for the year ended December 31, 2004 were $92.9 million compared to $72.4 million for the year ended December 31, 2003, an increase of $20.5 million or 28.3 percent. The increase was due to the significantly higher average prices of natural gas purchased and higher volumes purchased for resale. Income before income taxes for the Company's natural gas marketing subsidiary improved from $762,000 for the year ended December 31, 2003 to $1,737,000 for the year ended December 31, 2004. Based on the nature of the Company's gas marketing activities, derivatives did not have a significant impact on the Company's net margins from marketing activities during either period.

Oil and Gas Production and Well Operations Costs


Oil and gas production and well operations costs from the Company's producing properties for the year ended December 31, 2004 were a restated $17.3 million compared to a restated $13.3 million for the year ended December 31, 2003, an increase of approximately $4.0 million or 30.0% percent. Such increase was due to the increased production costs and severance and property taxes on the increased volumes and higher sales prices of natural gas and oil sold, along with the increased number of wells and pipelines operated by the Company. Lifting cost per Mcfe increased from $0.93 per Mcfe to $1.12 per Mcfe due to increased severance and property taxes on the significantly increased oil and gas sales prices along with additional well workovers and production enhancements work performed.

33



General and Administrative Costs

General and administrative expenses for the year ended December 31, 2004 decreased to $4.5 million compared with $5.0 million for the year ended December 31, 2003 a decrease of approximately $469,000 or 9.4 percent. The decrease was primarily due to lower executive compensation costs partially offset by approximately $477,000 of costs of complying with the various provisions of Sarbanes-Oxley, in particular with Section 404 (Internal Controls).

Depreciation, Depletion, and Amortization

Depreciation, depletion, and amortization costs for the year ended December 31, 2004 increased to $18.2 million from approximately $15.3 million for the year ended December 31, 2003, an increase of approximately $2.9 million or 19.0 percent. Such increase was due to the significantly increased production and investment in oil and gas properties by the Company as referred to above.

Interest Expense

Interest expense for the year ended December 31, 2004 was $674,000 compared to $1.2 million for the year ended December 31, 2003, a decrease of $526,000 or 43.8 percent. The impact of the derivative on interest expense was a reduction of $592,700 and $477,600 for the years ended December 31, 2004 and 2003, respectively. Such decrease is due to a lower average outstanding balance of our credit facility offset in part by rising interest rates.  The Company utilizes its daily cash balances to reduce its line of credit to lower its cost of interest. The average outstanding debt balances for the year ended December 31, 2004 was $11.3 million compared to $24.1 million for the year ended December 31, 2003.

Oil and Gas Price Risk Management Loss, Net

                Oil and gas price risk management loss, net for the year ended December 31, 2004 was $3.1 million compared to approximately $800,000 for the year ended December 31, 2003, an increase of $2.3 million. Oil and gas price risk management, net is comprised of both the realized and unrealized portions of the Company's commodity based derivative transactions for its oil and gas production (this line item does not include commodity based derivative transactions related to transactions from marketing activities).  The Company views these transactions as financial instruments and not a part of our oil and gas sales.  The 2004 change is the result of increasing oil and natural gas prices.

Provision for Income Taxes

The effective income tax rate for the Company's provision for income taxes increased from 34.5% for the year ended December 31, 2003 to 37.9% for the year ended December 31, 2004 primarily as a result of significantly increased earnings of the Company during 2004, lower percentage depletion for tax purposes, the benefit in 2003 of officers' life insurance proceeds, and non-conventional source fuel tax credit.

Net Income and Earnings Per Share

Net income for the year ended December 31, 2004 was $33.2 million compared to a net income of $20.4 million for the year ended December 31, 2003, an increase of approximately $12.8 million or 62.7 percent.

Diluted earnings per share for the year ended December 31, 2004 was $2.00 per share compared to $1.25 per share for the year ended December 31, 2003, an increase of $0.75 per share or 60.0 percent.

 

Liquidity and Capital Resources

                The Company funds its operations through a combination of cash flow from operations and use of the Company's credit facility.  Operating cash flow is generated by sales of natural gas and oil from the Company's well interests, natural gas marketing, profits from well drilling and operating activities from the Company's public drilling programs and others, and natural gas gathering and transportation. 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. Such credit arrangements were adequate to meet all cash and liquidity requirements.

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Natural Gas Pricing and Pipeline Capacity

The Company sells natural gas under contracts that are priced based on spot prices or price indexes that reflect current market prices for the commodity.  As a result variations in the market are reflected in the revenue we receive. The price of natural gas has varied substantially over short periods of time in the past, and there is every reason to expect a continuation of that variability in the future.  During 2005 prices for natural gas were close to or above record levels, and future expectations as reflected in the NYMEX futures market are for continuing high price levels for 2006 and beyond.  Strong domestic and international demand for energy and inadequate short term supplies are believed to be key causes of the strong prices.  High prices could encourage the development of new energy sources and reduced consumption as users find more efficient ways to use energy or substitute other energy forms.  High energy prices could also slow global economic growth, further reducing demand.  As a result the energy price outlook could change rapidly from current expectations.  Reduced natural gas prices would reduce the profitability and cash flow from the Company's gas production operations.

Natural gas prices throughout the country tend to be fairly closely related after allowing for differences in the quality and energy content of the gas, the location and distance to market, and other factors.  Sometimes prices in a particular area may vary from historical relationships.  This can occur when a local condition restricts the marketability of the natural gas.  For example limits on pipeline delivery capacity for natural gas can result in lower than normal prices for wells that use the system to deliver gas to market.  This situation occurred in 2002 to 2003 in the Rocky Mountains, when the productive capacity of wells in the region exceeded the amount of gas that could be used by local markets or shipped out of the area.  In order to access the available capacity producers were forced to sell their gas at lower than normal prices with the alternative being to shut wells in.  Since that time, additional pipeline capacity has been added, and further additions are planned in the future, so prices have returned to the historical relationship to other producing regions.  However future delivery constraints could result in lower than anticipated prices or production in any of the Company's producing areas.

Oil Pricing

             Oil prices were near or above record levels for most of 2005.  The Company's oil prices are largely determined by oil prices in the world market.  Global supply and demand and geopolitical factors are the key determinants of oil prices.  The rapid growth of energy use in developing countries, most notably China, is driving a rapid increase in worldwide oil consumption.  Higher prices could result in reduced consumption and/or increasing supplies that could moderate the current high price levels.  Over the past several years oil has been an increasing part of the Company's production mix.  As a result higher oil prices have contributed to the Company's increased revenue from oil and gas sales more than in the past, and the Company would suffer a greater impact if oil prices were to decrease.

 

Oil and Gas Derivative Activities

Because of the uncertainty surrounding natural gas and oil prices we have used various derivative instruments to manage some of the impact of fluctuations in prices. Through October 2007 we have in place a series of floors and ceilings on part of our natural gas production. Under the arrangements, if the applicable index rises above the ceiling price, we pay the counterparty, however if the index drops below the floor the counterparty pays us. See previous pages in this Management's Discussion and Analysis for a schedule of derivative positions.

The Company uses derivative investments to protect prices for its partners' share of production as well as its own production. Actual wellhead prices will vary based on local contract conditions, gathering and other costs and factors. The Company records the fair value of its partners' share of outstanding derivatives and the partners corresponding obligation or benefit in accounts receivable or other liabilities as appropriate.

Drilling Programs

 

             During January, 2005, the Company commenced sales and funded its first 2005 Partnership (PDC 2005-A) at its maximum subscriptions of $40 million, the largest Company sponsored partnership at that time.  The Company commenced the drilling operations of the partnership late in the first quarter and continued to drill for the partnership into the second and third quarters of 2005.

             In April, 2005, the Company commenced sales and funded its second 2005 Partnership (PDC 2005-B) at its maximum allowable subscriptions of $40 million.  The Company commenced drilling operations of this partnership late in the second quarter and drilled for the partnership during the third and fourth quarters of 2005.

In December, 2005, the Company commenced sales and funded its third 2005 partnership, a private limited partnership, Rockies Region Private Limited Partnership with subscriptions of approximately $36 million. Drilling operations commenced in the first quarter of 2006.

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The Company invests, as its equity contribution to each drilling partnership, a sum equal to approximately 22%-32% 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. During 2005 this amounted to an investment of approximately $29.0 million in our drilling partnerships. No assurance can be made that the Company will continue to receive this level of funding from these or future programs. The Company posts, during the subscription period of a partnership, daily the amount of subscriptions that have been sold in the partnership at its website, www.petd.com under the heading of "Drilling Program".

Substantially all of the Company's drilling programs contain a repurchase provision allowing Investors to request that the Company repurchase their partnership units. This repurchase provision is in effect 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), if investors request that the Company  repurchase the units and subject to the Company's financial ability to do so.  The maximum annual 10% repurchase obligation, if requested by the investors, is currently approximately $9.2 million. The Company has adequate liquidity to meet this obligation. During 2005 the Company spent $352,000 under this provision. As of December 31, 2005, outstanding repurchase offers to investing partners totaled $256,400.  In 2006, $70,700 of such outstanding offers were consummated prior to their expiration on or before February 28, 2006.

Drilling Activity

During 2005 the Company and its drilling fund partnerships drilled a total of 132 wells with 2 developmental dry holes. The Company drilled 99 successful wells in its Wattenberg field in the Denver-Julesburg Basin and 33 successful wells in the Piceance Basin in western Colorado. The Company plans to conduct its 2006 partnership drilling activity in these two areas, as well as in the Red Desert Basin in Wyoming.

During 2005 the Company drilled several development wells outside of the public drilling fund partnerships. The Company drilled 57 wells on its northeast Colorado properties and participated in 24 additional wells which were drilled by joint venture partners. Of these 81 wells, 79 were successful. The Company also drilled 20 Wattenberg Field wells for its own account, all 20 were successful.  The Company also drilled a developmental gas well in the Michigan Basin.

                 The total dry hole costs of $11.1 million associated with the six wells described below (five drilled in 2005, one in 2004) were expensed in accordance with the successful efforts method of accounting. All costs for the six wells were incurred 100% by the Company, as no costs were incurred by the drilling fund partnerships. The Company drilled eight new exploratory wells in 2005. In addition, one well, which was drilled in 2004, was determined to be a dry hole in 2005. Three of the eight wells drilled in 2005 were successful and five were dry holes.

                Three of the wells were drilled in North Dakota (two in the Bakken Shale and one non-operated in the Nessen Shale). One Bakken Shale well was successful and the other two wells were in the process of being drilled and completed and had combined expenditures of $1.9 million as of December 31, 2005. If either or both of these wells are determined to be dry holes, those costs will be expensed in the period when the determination is made as required by the successful efforts method of accounting.

                During the fourth quarter of 2005 the Coffeepot Springs #24-34 well located in Colorado was determined to be uneconomic and had a total dry hole cost of $5.42 million along with four unsuccessful shallow exploratory wells were drilled in Kansas for a total dry hole cost of $314,200.

                During the second quarter of 2005, the Fox Federal #1-13 located in Colorado (for which drilling was begun 2004), was determined to be a dry hole at a cost of approximately $5.38 million.

               

Purchase of Oil and Gas Properties

Although the Company made several offers to purchase producing oil and gas properties from other companies during 2005, it was not successful in purchasing any of those properties.  The Company did purchase a number of small interests in its partnerships from investors wishing to liquidate their holdings under the repurchase provision of the partnerships.

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Costs incurred by the Company in oil and gas property acquisition, exploration and development for the year ended December 31, 2005 are presented below:

Acquisition of properties:

  Unproved properties

$16,910,200

  Proved properties

1,608,300

Development costs

68,605,000

Exploration costs

12,942,700

$100,066,200

Common Stock Repurchase

                 On March 18, 2005 the Company publicly announced the authorization by its Board of Directors to repurchase up to 2% of the Company's outstanding common stock (331,796 shares) at fair market value at the date of purchase. At a meeting held June 10, 2005, the Board of Directors of Petroleum Development Corporation approved an amendment of the size of the stock repurchase from 2% to 10% (1,658,980 shares) of the Company's then outstanding common stock. Under the program, management has discretion as to the dates of purchase and amounts of stock to be purchased and whether or not to make purchases. This program expired on December 31, 2005. The following activity has occurred from inception of the plan on March 18, 2005 until December 31, 2005.

Month of Purchase

May, 2005

Average Price Paid per Share

$23.75

Broker/Dealer

McDonald Investments

Number of Shares Purchased

331,796


Remaining Number of Shares to Purchase

1,327,184

                 On January 13, 2006 the Company publicly announced that its Board of Directors has authorized the repurchase of up to 10% (1,627,500 shares) of the Company's common stock during 2006. Stock repurchases under this program may be made in the open market or in private transactions, at times and in amounts that management deems appropriate. The Company may terminate or limit the stock repurchase program at any time. The following activity has occurred since inception of the plan on January 13, 2006 until May 10, 2006.

Month of Purchase

January, 2006

Average Price Paid per Share

$39.33

Broker/Dealer

McDonald Investments

Number of Shares Purchased

258,169


Remaining Number of Shares to Purchase

1,369,331

Working Capital

                Although the working capital of the Company as of December 31, 2005 is a negative $25.8 million this amount included a net current liability of $7.9 million related to the fair value of derivatives. The amount may or may not be realized depending on the change in the fair value of derivatives upon settlement, and if realized will be funded with proceeds from future oil and gas sales. The Company manages its working capital needs by only drawing from its credit facility of $200 million as liabilities come due and cash is required.  At December 31, 2005, the Company has adequate liquidity with the credit facility to meet both its working capital and needs for continued investment in oil and gas well drilling over the next year.

Long-Term Debt

                The Company has a credit facility with J. P. Morgan Chase Bank, NA (formerly Bank One, NA) and BNP Paribas of $200 million subject to and secured by required levels of oil and gas reserves. The current borrowing base, based upon current oil and gas reserves, is $125 million of which the Company has activated $80 million of the facility.  The Company is required to pay a commitment fee of 0.25 to 0.375 percent per annum 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 November 4, 2010.

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                As of December 31, 2005 the outstanding balance was $24,000,000.  Any amounts outstanding under the credit facility 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. At December 31, 2005, the outstanding balance was subject to a prime rate of 7.25%. As of the filing of this Form 10-K, the Company was in compliance with all covenants in the credit agreement, except for timely filing of this December 31, 2005 Form 10-K. The Company has received bank waivers to extend the due date of the December 31, 2005 consolidated financial statements until May 31, 2006, and the filing of the March 31, 2006 consolidated financial statements until June 15, 2006..

Contractual Obligations and Contingent Commitments

Contractual obligations and contingent commitments and due dates are as follows:

Payments due by period

Contractual Obligations

Less than

1-3

3-5

More than

and Contingent Commitments

    Total    

   1 year  

  years  

  years  

  5 years  

Long-Term Debt

 $      24,000,000

 $                     -

 $                    -

$24,000,000

 $                      -

Operating Leases

1,432,200

356,300

589,100

458,800

28,000

Asset Retirement Obligations

8,333,200

50,000

100,000

100,000

8,083,200

Drilling Rig Commitment

59,627,400

20,221,000

31,922,000

7,484,400

 -

Derivative Agreements (1)

22,062,500

18,424,400

3,638,100

 -

 -

Partnership Performance Supplement (2)

4,808,400

1,256,700

3,099,500

409,800

42,400

Other Liabilities

3,722,600

40,000

250,000

250,000

3,182,600

Total

 $    123,986,300

 $     40,348,400

 $   39,598,700

 $   32,703,000

 $     11,336,200

(1)                 Amount represents gross liability related to fair value of derivatives. Includes fair value of derivatives for Riley Natural Gas, Petroleum Development Corporation's share of oil and gas production and derivatives contracts entered into by the Company on behalf of the affiliate Partnerships as the Managing General Partner. The Company has a corresponding receivable from the Partnerships of $5,351,500 as of December 31, 2005.

(2)                 Represents maximum amount the Company would be required to pay to investing partners if certain levels of Partnership performance are not met as of December 31, 2005. See Note 10 to the consolidated financial statements.

Long-term debt in the above table does not include interest as interest rates are variable and principal balances fluctuate significantly from period to period.  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 cost efficiencies.  Management believes that the Company has adequate capital to meet its operating requirements.

Commitments and Contingencies

As Managing General Partner of 75 partnerships (See Item 1. Business - Drilling and Development) the Company has liability for any potential casualty losses in excess of the partnership assets and insurance. The Company's management believes its and its subcontractors' casualty insurance coverage is adequate to meet this potential liability.

Critical Accounting Policies and Estimates


We have identified the following policies as critical to our business operations and the understanding of our results of operations. This is not a comprehensive list of all of our accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting principles generally accepted in the United States, with no need for management's judgment in their application. There are also areas in which management's judgment in selecting any available alternative would not produce a materially different result. However, certain of our accounting policies are particularly important to the portrayal of our financial position and results of operations and may require the application of significant judgment by our management; as a result, they are subject to an inherent degree of uncertainty. In applying those policies, our management uses its judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on our historical experience, our observation of trends in the industry, and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other accounting policies, see "Note 1 - Summary of significant accounting policies" in our financial statements and related notes. Our critical accounting policies and estimates are as follows:

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Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Petroleum Development Corporation (PDC) and its wholly owned subsidiaries, Riley Natural Gas (RNG) and PDC Securities Incorporated. All material intercompany accounts and transactions have been eliminated in consolidation. The Company accounts for its investment in interests in oil and gas limited partnerships under the proportionate consolidation method. Under this method, the Company's financial statements include its pro rata share of assets, liabilities and revenues and expenses respectively of the Company sponsored limited partnerships in which it participates. The Company's proportionate share of all significant transactions between the Company and the Company sponsored limited partnerships is eliminated.

Revenue Recognition

The Company's drilling segment recognizes revenue from our drilling contracts with our sponsored drilling programs using the percentage of completion method. These contracts include the sale of equipment and the providing of services at footage rates and are completed within nine to twelve months after the commencement of drilling. The Company provides geological, engineering, and drilling supervision for the drilling and completion process and uses subcontractors to perform drilling and completion services. Revenues are recognized under the percentage of completion method based upon the percentage of contract costs incurred to date to the estimated total contract costs for each contract. The Company utilizes this method because reasonably dependable estimates of the total estimated costs can be made. Because the revenue recognized depends on estimates of the final contract costs, which are assessed periodically during the term of the contract, recognized revenues are subject to revisions as the contract progresses. Anticipated losses, if any, on uncompleted contracts are recorded at the time that our estimated costs exceed the estimated contract revenue. In 2005, the Company recorded a loss of $800,000 on uncompleted drilling contracts as part of Cost of Oil and Gas Well Drilling Operations. The Company did not experience any contract losses in 2004 or 2003.

Natural gas marketing is recorded on the gross accounting method.  RNG, our marketing subsidiary, purchases gas from many small producers and bundles the gas together to sell in larger amounts to purchasers of natural gas for a price advantage.  RNG has latitude in establishing price and discretion in supplier and purchaser selection.  Natural gas marketing revenues and expenses reflect the full cost and revenue of those transactions because RNG takes title to the gas it purchases from the various producers and bears the risks and rewards of that ownership.  Both the realized and unrealized portions of the RNG commodity based derivative transactions for natural gas marketing activities are included in gas sales from marketing activities or cost of gas marketing activities, as applicable.

Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable.  Natural gas is sold by the Company under contracts with terms ranging from one month to three years.  Virtually all of the Company's contracts 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 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 currently uses the "Net-Back" method of accounting for transportation arrangements of our natural gas sales.  The Company sells gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by our customers and reflected in the wellhead price.

Sales of oil are recognized when persuasive evidence of a sales arrangement exists, the oil is verified as produced and is delivered in a stock tank, collection of revenue from the sale is reasonably assured and the sales price is determinable.  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 that are customary in the oil industry.

Well operations and pipeline income is recognized when persuasive evidence of an arrangement exists, services have been rendered, collection of revenues is reasonably assured and the sales price is fixed or determinable.  The Company is paid a monthly operating fee for each well it operates for outside owners, including the limited partnerships sponsored by the Company. The fee 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.

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Valuation of Accounts Receivable

Management reviews accounts receivable to determine which are doubtful of collection.  In making the determination of the appropriate allowance for doubtful accounts, management considers the Company's history of write-offs, relationships and overall credit worthiness of its customers, and well production data for receivables related to well operations.

Accounting for Derivatives Contracts at Fair Value

The Company uses derivative instruments to manage its commodity and financial market risks. Accounting requirements for derivatives and hedging activities are complex; interpretation of these requirements by standard-setting bodies is ongoing. The Company currently does not use hedge accounting treatment for its derivatives.

Derivatives are reported on the Consolidated Balance Sheets at fair value. Changes in fair value of derivatives are recorded in earnings in the consolidated statements of income as none of the Company's derivatives qualified for hedge accounting under the provisions of FAS No. 133.

The measurement of fair value is based on actively quoted market prices, if available. Otherwise, the Company seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, measurement involves judgment and estimates. These estimates are based on valuation methodologies considered appropriate by the Company's management. For individual contracts, the use of different assumptions could have a material effect on the contract's estimated fair value.

Use of Estimates in Long-Lived Asset Impairment Testing

Impairment testing for long-lived assets and intangible assets with definite lives is required when circumstances indicate those assets may be impaired. In performing an impairment test, the Company estimates the future cash flows associated with individual assets or groups of assets. Impairment is recognized when the undiscounted estimated future cash flows are less than the related asset's carrying amount. In those circumstances, the asset must be written down to its fair value, which, in the absence of market price information, may be estimated as the present value of its expected future net cash flows, using an appropriate discount rate. Although cash flow estimates used by the Company are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.

Oil and Gas Properties

The Company accounts for its oil and gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and development dry hole costs are depreciated or depleted by the unit-of-production method based on estimated proved developed producing oil and gas reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved oil and gas reserves. The Company obtains new reserve reports from independent petroleum engineers annually as of December 31st of each year. The Company adjusts oil and gas reserves for any major acquisitions, new drilling and divestitures during the year as needed.

Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to expense if the well is determined to be nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing its reserves and economic and operating viability. If an in-progress exploratory well is found to be unsuccessful (referred to as a dry hole) prior to the issuance of our financial statements, the costs are expensed to exploratory dry hole costs. If we are unable to make a final determination about the productive status of a well prior to issuance of our financial statements, the well is classified as "Suspended Well Costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time when we are able to make a final determination of a well's productive status, the well is removed from the suspended well status and the proper accounting treatment is recorded. The determination of an exploratory well's ability to produce is made within one year from the completion of drilling activities.

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The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved oil and gas properties with individually significant acquisition costs are periodically assessed, and any impairment in value is charged to expense. The amount of impairment recognized on unproved properties which are not individually significant is determined by amortizing the costs of such properties within appropriate fields based on the Company's historical experience, acquisition dates and average lease terms. Amortization of remaining lease costs for all other insignificant properties is recorded over the average remaining lives of the leases. The valuation of unproved properties is subjective and requires management of the Company to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values.

Upon sale or retirement of significant portions of or complete fields of depreciable or depletable property, the book value thereof, less proceeds or salvage value, is credited or charged to income.  Upon sale of individual wells, the proceeds are credited to property costs.

The Company assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which management reasonably estimates such products to be sold. These estimates of future product prices may differ from current market prices of oil and gas. Any downward revisions to management's estimates of future production or product prices could result in an impairment of the Company's oil and gas properties in subsequent periods. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows.

Deferred Tax Asset Valuation Allowance

Deferred tax assets are recognized for deductible temporary differences, net operating loss carry-forwards, and credit carry-forwards if it is more likely than not that the tax benefits will be realized.  To the extent a deferred tax asset is not expected to be realized under the preceding criteria, a valuation allowance has been established.

The judgments used in applying the above policies are based on management's evaluation of the relevant facts and circumstances as of the date of the financial statements.  Actual results may differ from those estimates. 

Recently Adopted Accounting Standards

 

The FASB issued FIN 46R, "Consolidation of Variable Interest Entities", in January 2003 and amended the interpretation in December 2003. A variable interest entity (VIE) is an entity in which voting equity investors lack the characteristics of having a controlling financial interest or where the existing capital at risk is insufficient to permit the entity to finance its activities without receiving additional financial support from other parties.  FIN 46R requires the consolidation of entities which are determined to be VIEs where the reporting company determines itself to be the primary beneficiary (the entity that will absorb a majority of the VIE's expected losses, receive a majority of the VIE's residual return, or both).  The amended interpretation was effective for the first interim annual reporting period ending after March 15, 2004, with the exception of special purpose entities for which the statement was effective for periods ending after December 15, 2003.  We have completed a review of our partnership investments and have determined that the partnerships are not VIEs.  

In June 2005, the EITF reached a consensus on EITF Issue No. 04-5, "Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights". This consensus applies to voting right entities not within the scope of FASB Interpretation No. 46R, "Consolidation of Variable Interest Entities", in which the investor is the general partner in a limited partnership or functional equivalent. The EITF consensus is that the general partner in a limited partnership is presumed to control that limited partnership regardless of the extent of the general partner's ownership interest and, therefore, should include the limited partnership in its consolidated financial statements unless the limited partners have substantive participating or kick-out rights. Pursuant to the partnership agreements the presumption of control by the Company, the general partner, is overcome because the investor partners have substantive ability to dissolve (liquidate) the limited partnership or otherwise remove the general partner through substantive kick-out rights that can be exercised by a vote of simple majority of the investor partner units not held by the general partners without having to show cause. On the basis of this assessment, the partnership interests of the Company continue to be proportionately consolidated as disclosed above.

41



On April 4, 2005, the FASB issued FASB Staff Position (FSP) FAS 19-1 "Accounting for Suspended Well Costs."  This staff position amends FASB Statement No. 19 "Financial Accounting and Reporting by Oil and Gas Producing Companies" and provides guidance about exploratory well costs to companies which use the successful efforts method of accounting.  The position states that exploratory well costs should continue to be capitalized if: 1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and 2) sufficient progress is made in assessing the reserves and the well's economic and operating feasibility.  If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management's evaluation of capitalized exploratory well costs. In addition, the FSP requires annual disclosure of: 1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, 2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and 3) an aging of exploratory well costs suspended for greater than one year with the number of wells it related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. The Company adopted (FSP) FAS 19-1 during the third quarter of 2005. The application of this FSP did not have a significant impact on the Company's financial position or results of operations.

Recently Issued Accounting Standards

On December 16, 2004, the FASB issued SFAS No. 123(R) "Accounting for Share-Based Payments" and has issued several subsequent Staff Positions clarifying this guidance.  This guidance replaced previously existing requirements under SFAS No. 123 and APB No. 25.  Under SFAS No. 123(R), an entity must recognize the compensation cost related to employee services received in exchange for all forms of share-based payments to employees, including employee stock options, as an expense in its income statement.  The compensation cost of awards will generally be measured based on the grant-date fair value of the award.  The Company will be required to adopt SFAS No. 123(R) in the first quarter of 2006.  The Company intends to use the modified prospective method for adoption of SFAS No. 123(R) as permitted by the guidance.

The Company has determined that the impact of SFAS No. 123(R) and related guidance will not be material to its financial statements.  In accordance with SFAS No. 123, the Company has historically disclosed the impact on the Company's net income and earnings per share had the fair value based method been adopted.  Had the Company adopted SFAS No. 123(R) in prior periods, the impact of that standard on periods presented in these Consolidated Financial Statements would have approximated the impact of SFAS No. 123 as described in the disclosure of pro forma net income and earnings per share presented in Note 1.

In December 2004, the FASB issued FAS 153, "Exchange of Nonmonetary Assets", an amendment of APB Opinion 29, "Accounting for Nonmonetary Transactions". This amendment eliminates the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. Under FAS 153, if a nonmonetary exchange of similar productive assets meets a commercial-substance criterion and fair value is determinable, the transaction must be accounted for at fair value resulting in recognition of any gain or loss. This statement is effective for nonmonetary transactions in fiscal periods that begin after June 15, 2005. The adoption of this statement will not have a material impact on our results of operations or financial position.

In June 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error Corrections" - a replacement of APB Opinion No. 20 and FASB Statement No. 3, which replaces Accounting Principles Board Opinion No. 20, "Accounting Changes", and SFAS No. 3, "Reporting Accounting Changes in Interim Financial Statements", and changes the requirements for the accounting for and reporting of a change in accounting principle. SFAS No. 154 requires retrospective application for voluntary changes in accounting principle unless it is impracticable to do so, and it applies to all voluntary changes in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Consequently, we will adopt the provisions of SFAS 154 for our fiscal year beginning January 1, 2006. We currently believe that adoption of the provisions of SFAS No. 154 in 2006 will not have a material impact on our consolidated financial statements.

Item 7A. 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:

42



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, 2005 is $68.5 million with an average interest rate of 3.5%. As of December 31, 2005, the Company had long-term debt of $24,000,000 subject to a prime interest rate of 7.25%.

Commodity Price Risk

The Company utilizes commodity based derivative instruments to manage a portion of its exposure to price risk from its oil and natural gas sales and marketing activities.  These instruments consist of NYMEX-traded natural gas futures contracts and option contracts for Appalachian and Michigan production, Panhandle-based contracts traded by BNP Paribas and NYMEX-traded contracts for NECO production and CIG-based contracts traded by JP Morgan for other Colorado production. These derivative instruments 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 derivative relates and, in the case of RNG, the cost of gas supplies purchased for marketing activities.  As a result, while these derivatives are structured to reduce the Company's exposure to changes in price associated with the derivative commodity, they also limit the benefit the Company might otherwise have received from price changes associated with the derivative commodity.  Riley Natural Gas also enters into fixed-price physical purchase and sale agreements that are derivative contracts. The Company's policy prohibits the use of oil and natural gas future and option contracts for speculative purposes.

The following tables summarize the open derivative and fixed-price purchase and sale contracts for Riley Natural Gas and Petroleum Development Corporation as of December 31, 2005 and 2004.

Riley Natural Gas

Open Derivative Positions

Quantity

Weighted

Total Contract

Commodity

Type

Gas-Mmbtu

Average Price

Amount

Fair Value

Total Positions as of December 31, 2005

Natural Gas

Cash Settled Futures/Swaps Purchases

1,025,500

 $                9.05

$9,283,010

 $       1,983,352

Natural Gas

Cash Settled Futures/Swaps Sales

3,149,000

 $                7.95

$25,018,610

 $     (8,688,840)

Natural Gas

Cash Settled Basis Swap Purchases

450,000

 $                0.91

$409,500

 $        (157,663)

Natural Gas

Cash Settled Basis Swap Sales

240,000

 $                0.50

$120,000

 $              3,700

Natural Gas

Physical Purchases

2,819,000

 $                8.32

$23,456,726

 $       7,858,489

Natural Gas

Physical Sales

585,222

 $              10.72

$6,272,822

 $        (670,419)

Natural Gas

Physical Basis Purchases

240,000

 $                0.45

$108,000

 $              8,300

Natural Gas

Physical Basis Sales

450,000

 $                0.94

$420,750

 $          168,913

43



Positions maturing in 12 months following December 31, 2005

Natural Gas

Cash Settled Futures/Swaps Purchases

1,025,500

 $                9.05

$9,283,010

 $       1,983,352

Natural Gas

Cash Settled Futures/Swaps Sales

2,709,000

 $                8.12

$21,991,390

 $     (7,185,253)

Natural Gas

Cash Settled Basis Swap Purchases

450,000

 $                0.91

$409,500

 $        (157,663)

Natural Gas

Cash Settled Basis Swap Sales

220,000

 $                0.50

$110,000

 $              4,900

Natural Gas

Physical Purchases

2,379,000

 $                8.71

$20,717,126

 $       5,966,998

Natural Gas

Physical Sales

585,222

 $              10.72

$6,272,822

 $        (670,419)

Natural Gas

Physical Basis Purchases

220,000

 $                0.45

$99,000

 $              6,100

Natural Gas

Physical Basis Sales

450,000

 $                0.94

$420,750

 $          168,913

Prior Year Total Positions as of December 31, 2004

Natural Gas

Cash Settled Sale

3,260,000

 $                5.60

$18,249,250

 $     (1,982,964)

Natural Gas

Cash Settled Purchase

1,130,000

 $                6.77

$7,644,540

 $        (486,490)

Natural Gas

Cash Settled Sale Option

530,000

 $                5.30

-     

 $          134,242

Natural Gas

Cash Settled Purchase Option

265,000

 $                7.00

-     

 $          (85,541)

Natural Gas

Physical Contract Sale

1,136,230

 $                6.96

$7,908,865

 $       1,268,721

Natural Gas

Physical Contract Purchase

3,223,000

 $                5.82

$18,747,564

 $       1,882,984

The maximum term for the derivative contracts listed above is 34 months.

Petroleum Development Corporation

Open Derivative Positions

Quantity

Gas-Mmbtu

Weighted

Total Contract

Commodity

Type

Oil-Barrels

Average Price

Amount

Fair Value

Total Positions as of December 31, 2005

Natural Gas

Cash Settled Option Sales

5,665,000

$8.17

$46,273,550

 $   (12,531,796)

Natural Gas

Cash Settled Option Purchases

14,030,000

$6.36

$89,210,000

 $       2,660,289

Positions maturing in 12 months following December 31, 2005

Natural Gas

Cash Settled Option Sales

4,930,000

$8.07

$39,802,550

 $   (10,411,106)

Natural Gas

Cash Settled Option Purchases

12,560,000

$6.38

$80,165,000

 $       2,251,533

Prior Year Total Positions as of December 31, 2004

Natural Gas

Purchase

120,000

$6.63

$796,150

 $          (45,680)

Natural Gas

Sale Option

7,400,000

$4.46

-     

 $          917,553

Natural Gas

Purchase Option

3,475,000

$5.42

-     

 $     (3,138,210)

Crude Oil

Sale Option

360,000

$32.30

-     

 $          306,702

Crude Oil

Purchase Option

180,000

$40.00

-     

 $        (973,638)

The maximum term for the derivative contracts listed above is 15 months.

In addition to including the gross assets and liabilities related to the Company's share of oil and gas production, the above tables and the accompanying consolidated balance sheets include the gross assets and liabilities related to derivative contracts entered into by the Company on behalf of the affiliate Partnerships as the Managing General Partner. The accompanying consolidated balance sheets include the negative fair value of derivatives and a corresponding receivable from the Partnerships of $5,351,500 as of December 31, 2005 and $1,418,000 as of December 31, 2004. In addition to the short-term fair value of derivatives shown on the accompanying consolidated balance sheets there are long-term assets and long-term liabilities which total to a net long-term liability of approximately $1,323,100 as of December 31, 2005 and which total a net long-term asset of approximately $1,248,000 as of December 2004, respectively related to the fair value of derivatives included in accompanying balance sheets.

By using derivative financial instruments to manage 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. There were no counterparty defaults during the years ended December 31, 2005, 2004 and 2003.

44



The average NYMEX closing prices for natural gas for the years 2005, 2004, and 2003 were $8.62 Mmbtu, $6.14 Mmbtu, and $5.39 Mmbtu. The average NYMEX closing prices for oil for the years 2005, 2004 and 2003 were $55.34 bbl, $41.44 bbl and $30.98 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.

Disclosure of Limitations

Because the information above incorporates only those exposures that exist at December 31, 2005, 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.

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 9A. Controls and Procedures

(a)     Evaluation of Disclosure Controls and Procedures

The Company has evaluated, under the supervision and with the participation of the Company's management, including the Company's Chief Executive Officer, President and Chief Financial Officer, the effectiveness of the design and operations of the Company's disclosure controls and procedures pursuant to Securities Exchange Act of 1934, as amended (the Exchange Act) Rules 13a-15(e) and 15-d-15(e) as of December 31, 2005.  In the course of the evaluation, the Company considered the material weaknesses in the Company's internal control over financial reporting and other internal control matters discussed below and has concluded that the Company did not maintain effective disclosure controls and procedures as of December 31, 2005. 

(b)     Changes and Remediation in the Company's Internal Control Over Financial Reporting

 

There have not been any changes in the Company's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during the most recent fiscal quarter that have materially affected or are reasonably likely to materially affect the Company's internal control over financial reporting, except for changes in the fourth quarter of 2005 as noted below. 

 

•         The Company has increased the Company's technical expertise through development of training programs and acquiring accounting research software during the fourth quarter of 2005.  Training will be on-going, however programs provided during 2005 included oil and gas accounting, general accounting and SEC financial reporting.

•         The Company has enhanced the documentation of the Company's policies and procedures and related templates and analyses that support the Company's application of accounting principles in the several areas, including derivative accounting, oil and gas properties, and asset retirement obligations during the fourth quarter of 2005.

 

In addition, during the third quarter of fiscal 2005 and subsequently in 2006 the Company made the following changes and remediation:

At the direction of the Company's board of directors and audit committee, the Company has spent and continues to spend a significant amount of time and resources to improve the Company's control environment.  The Company is committed to instilling strong internal control policies and procedures and ensuring that the "tone at the top" fully supports accuracy and completeness in all financial reporting.  In support of this position, the Company's progress toward improving internal control over financial reporting has been openly communicated with the Company's Audit Committee, and the Company has undertaken to improve the design and effectiveness of the Company's internal control over financial reporting. The initiatives developed by the Company were both organizational and process focused.  Organizational changes made during 2005 and through the date of this filing include, among others:

45



•         The Company has enhanced the corporate accounting and reporting functions in the third quarter of 2005 by creating and filling several new positions with professionals highly experienced in oil and gas accounting. Two new professionals hold degrees in accounting and are Certified Public Accountants. One additional Certified Public Accountant was hired in early 2006, and a financial reporting director will be hired during 2006.

•         The Company engaged a team of highly experienced advisors in early 2006 to assist with various accounting research, projects and monitoring activities.  They assist the Company with accounting and reporting issues including, but not limited to, derivatives, oil and gas activities, new accounting standards or rules, SEC reporting and on-going monitoring of changes that may impact the Company's application of accounting principles.

•         The Company has strengthened its Sarbanes-Oxley Act Section 404 compliance department through the addition of a leadership position and other experienced resources in the third quarter of 2005. The Company believes the strengthening of this department will significantly improve the design, effectiveness and monitoring of internal control over financial reporting.

The Company has also implemented or is planning to implement several process changes to improve the documentation supporting certain accounting and reporting activities as well as to improve the documentation of the Company's application of accounting principles.

•         The Company has evaluated and selected a third-party integrated oil and gas accounting software system, which the Company plans to implement during 2006.

The Company believes the measures taken to date and planned for the future will address the reported material weaknesses and intends to complete the remediation efforts during 2006.  In addition, the Company will continue to develop and implement other initiatives during 2006 that will further improve both the effectiveness and efficiency of the Company's internal control over financial reporting.

(c)     Management's Report on Internal Control Over Financial Reporting

 

The Company's management is responsible for establishing and maintaining adequate internal control over financial reporting, as that term is defined under Rule 13a-15(f) promulgated under the Exchange Act.  In order to evaluate the effectiveness of the Company's internal control over financial reporting as of December 31, 2005, as required by Section 404 of the Sarbanes-Oxley Act of 2002, management conducted an assessment, including testing, using the criteria set forth in Internal Control - Integrated Framework issued by the committee of Sponsoring Organization of the Treadway Commission (the "COSO Framework").  Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  In addition, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or the degree of compliance with policies or procedures may deteriorate.

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.  The Company's assessment as of December 31, 2005, identified the following material weaknesses:

The Company did not have effective policies and procedures, and was not adequately staffed with accounting personnel possessing an appropriate level of technical expertise in U.S. generally accepted accounting principles, as further described below:

•         The Company did not have effective policies and procedures, or personnel with sufficient technical expertise, to properly account for derivative transactions in accordance with generally accepted accounting principles. Specifically, the Company's policies and procedures relating to derivatives transactions were not designed effectively to ensure that each of the requirements for hedge accounting was evaluated appropriately with respect to the Company's commodity based derivatives. Additionally, the Company's policies and procedures relating to the derivative transactions entered into on behalf of affiliated partnerships were not adequate to ensure these transactions were recorded properly in the financial statements. As a result, a misstatement was identified in the fair value of derivatives and the oil and gas price risk management loss accounts that was corrected prior to the issuance of the Company's 2005 consolidated financial statements. This deficiency results in more than a remote likelihood that a material misstatement of the Company's annual or interim consolidated financial statements would not be prevented or detected.

46



•         The Company did not have effective policies and procedures, or personnel with sufficient technical expertise, to ensure compliance with appropriate accounting principles for its oil and gas properties. Specifically, the Company's policies and procedures were not designed effectively to ensure that the calculation of depreciation and depletion and the determination of impairments were performed in accordance with the applicable authoritative accounting guidance. As a result, misstatements were identified in the accumulated depreciation, depletion and amortization and the depreciation, depletion and amortization expense accounts that were corrected prior to the issuance of the Company's 2005 consolidated financial statements. This deficiency results in more than a remote likelihood that a material misstatement of the Company's annual or interim consolidated financial statements would not be prevented or detected. 

•         The Company did not have effective policies and procedures, or personnel with sufficient technical expertise, to ensure proper accounting and disclosure for income taxes. Specifically, the Company's policies and procedures did not provide for appropriate control documentation or supervisory review of permanent and temporary differences, or assessment of tax reserves to ensure that they were properly reflected and disclosed in the Company's financial statements. As a result, misstatements were identified in the deferred income tax liability and income tax expense accounts that were corrected prior to the issuance of the Company's 2005 consolidated financial statements. This deficiency results in more than a remote likelihood that a material misstatement of the Company's annual or interim consolidated financial statements would not be prevented or detected. 

•          The Company did not have effective policies and procedures, or personnel with sufficient technical expertise, to ensure that its accounting for asset retirement obligations complied with generally accepted accounting principles. Specifically, the Company's policies and procedures regarding the estimate of the fair value of the asset retirement obligations were not designed effectively to ensure that it was estimated in accordance with FAS No. 143, Asset Retirement Obligations. This deficiency results in more than a remote likelihood that a material misstatement of the Company's annual or interim consolidated financial statements would not be prevented or detected.

•         The Company did not have effective policies and procedures, or personnel with sufficient technical expertise, to provide for adequate monitoring and assessment of the application of accounting principles, standards or rules as it relates to proportionate consolidation in a timely manner. As a result of this control deficiency, the Company did not appropriately eliminate its proportionate share of transactions with the Company sponsored limited partnerships, which resulted in the restatement of the Company's financial statements for the first three quarters of 2005, the years ended December 31, 2004, 2003, 2002, and 2001 and each of the quarters in 2004 and 2003. 

Management has concluded that, as a result of the material weaknesses noted above, the Company did not maintain effective internal control over financial reporting as of December 31, 2005 based on criteria set forth in the COSO Framework. 

The Company's independent registered public accounting firm, KPMG LLP, has issued an audit report on management's assessment of the Company's internal control over financial reporting as of December 31, 2005.  Their report follows this section of the Form 10-K.

47



Report of Independent Registered Public Accounting Firm

 

The Board of Directors and Stockholders

Petroleum Development Corporation:

We have audited management's assessment, included in the accompanying Management's Report on Internal Control Over Financial Reporting (Item 9A(c)), that Petroleum Development Corporation (the Company) did not maintain effective internal control over financial reporting as of December 31, 2005 because of the effect of the material weaknesses identified in management's assessment based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. Management has identified and included in its assessment the following material weaknesses as of December 31, 2005:

The Company did not have effective policies and procedures, and was not adequately staffed with accounting personnel possessing an appropriate level of technical expertise in U.S. generally accepted accounting principles, as further described below:

48



  • The Company did not have effective policies and procedures, or personnel with sufficient technical expertise, to ensure compliance with appropriate accounting principles for its oil and gas properties. Specifically, the Company's policies and procedures were not designed effectively to ensure that the calculation of depreciation and depletion and the determination of impairments were performed in accordance with the applicable authoritative accounting guidance. As a result, misstatements were identified in the accumulated depreciation, depletion and amortization and the depreciation, depletion and amortization expense accounts in the Company's preliminary 2005 consolidated financial statements. This deficiency results in more than a remote likelihood that a material misstatement of the Company's annual or interim consolidated financial statements would not be prevented or detected. 
  • The Company did not have effective policies and procedures, or personnel with sufficient technical expertise, to ensure proper accounting and disclosure for income taxes. Specifically, the Company's policies and procedures did not provide for appropriate control documentation or supervisory review of permanent and temporary differences, or assessment of tax reserves to ensure that they were properly reflected and disclosed in the Company's financial statements. As a result, misstatements were identified in the deferred income tax liability and income tax expense accounts in the Company's preliminary 2005 consolidated financial statements. This deficiency results in more than a remote likelihood that a material misstatement of the Company's annual or interim consolidated financial statements would not be prevented or detected. 
  • The Company did not have effective policies and procedures, or personnel with sufficient technical expertise, to ensure that its accounting for asset retirement obligations complied with generally accepted accounting principles. Specifically, the Company's policies and procedures regarding the estimate of the fair value of the asset retirement obligations were not designed effectively to ensure that it was estimated in accordance with FAS No. 143, Asset Retirement Obligations. This deficiency results in more than a remote likelihood that a material misstatement of the Company's annual or interim consolidated financial statements would not be prevented or detected.
  • The Company did not have effective policies and procedures, or personnel with sufficient technical expertise, to provide for adequate monitoring and assessment of the application of accounting principles, standards or rules as it relates to proportionate consolidation in a timely manner. As a result of this control deficiency, the Company did not appropriately eliminate its proportionate share of transactions with the Company sponsored limited partnerships, which resulted in the restatement of the Company's financial statements for the first three quarters of 2005, the years ended December 31, 2004, 2003, 2002, and 2001 and each of the quarters in 2004 and 2003. 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Petroleum Development Corporation and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of income, stockholders' equity and cash flows for each of the years in the three-year period ended December 31, 2005. The aforementioned material weaknesses were considered in determining the nature, timing and extent of audit tests applied in our audit of the 2005 consolidated financial statements, and this report does not affect our report dated May 24, 2006, which expressed an unqualified opinion on those consolidated financial statements.

In our opinion, management's assessment that Petroleum Development Corporation did not maintain effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, because of the effect of the material weaknesses described above on the achievement of the objectives of the control criteria, Petroleum Development Corporation did not maintain effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

KPMG LLP

Pittsburgh, Pennsylvania

May 24, 2006

 

49



Item 9B.  Other Information

 

None.

 

PART III

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

Steven R. Williams

55

Chairman and Chief Executive Officer,

and Director

January 2004
March 1983

Thomas E. Riley

53

President

Director

December 2004

January 2004

Darwin L. Stump

51

Chief  Financial Officer and Treasurer

November 2003

Eric R. Stearns

48

Executive Vice President Exploration and Production

December 2005

Gregory  A. Morgan

47

Secretary

September 2004

Vincent F. D'Annunzio

54

Director

February 1989

Jeffrey C. Swoveland

51

Director

March 1991

Donald B. Nestor

57

Director

March 2000

Kimberly Luff Wakim

47

Director

January 2003

David C. Parke

39

Director

November 2003

Steven R. Williams was elected Chairman and Chief Executive Officer in January 2004. Mr. Williams served as President from March 1983 until December 2004 and has been a Director of the Company since March 1983. 

Thomas E. Riley was elected Director in January 2004 by the Board of Directors and assumed the position of President in December 2004.  Previously Mr. Riley was appointed Executive Vice President of Production, Natural Gas Marketing and Business Development in November 2003. Prior thereto, Mr. Riley served as Vice President Gas Marketing and Acquisitions of the Company since April 1996. Prior to joining the Company, Mr. Riley was president of Riley Natural Gas Company, a natural gas marketing company which the Company acquired in April 1996.

Darwin L. Stump was appointed Chief Financial Officer and Treasurer in November 2003. Mr. Stump has been an officer of the Company since April 1995 and held the position of Corporate Controller since 1980. Mr. Stump, a CPA, was a senior accountant with Main Hurdman, Certified Public Accountants prior to joining the Company.

Eric R. Stearns was appointed Executive Vice President of Exploration and Production in December 2005. Prior to that he was Executive Vice President of Exploration and Development since November 2003, having previously served as Vice President of Exploration and Development since April 1995. Mr. Stearns joined the Company as a geologist in 1985 after working for Hywell, Incorporated and for Petroleum Consultants.

Gregory A. Morgan has been a member of the law firm of Young, Morgan & Cann, Clarksburg, West Virginia since 1986. Mr. Morgan is not active in the day-to-day business of the Company, but his law firm provides legal services to the Company.

Vincent F. D'Annunzio 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.

Donald B. Nestor 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.

50



Kimberly Luff Wakim, an Attorney and Certified Public Accountant, is a Partner with the law firm Thorp, Reed & Armstrong LLP.  Ms. Wakim joined Thorp Reed & Armstrong LLP in 1990.

David C. Parke was elected Director by the Board of Directors in November 2003. In 2003, Mr. Parke joined Mufson/Howe/Hunter & Company LLC, an investment banking firm as a founder and Director.  From 1992-2003, Mr. Parke was with the corporate finance department of Investec, Inc. and its predecessor Pennsylvania Merchant Group Ltd., investment banking companies. Prior to joining Pennsylvania Merchant Group, Mr. Parke served in the corporate finance departments of Wheat First Butcher & Singer, now part of Wachovia Securities, and Legg Mason, Inc.

     The Company's By-Laws provide that the directors of the Company shall be divided into three classes and that, at each annual meeting of stockholders of the Company, successors to the class of directors whose term expires at the annual meeting will be elected for a three-year term. The classes are staggered so that the term of one class expires each year. Mr. Williams, Mr. Nestor and Ms. Wakim are members of the class whose term expires in 2006. Mr. D'Annunzio and Mr. Riley are members of the class whose term expires in 2007. Mr. Swoveland and Mr. Parke are members of the class whose term expires in 2008. 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 the person was selected as an officer.

     On January 24, 2003, the Company adopted a Code of Business Conduct and Ethics Policy meeting the specified standards applicable to the Chief Executive Officer and Chief Financial Officer. The policy also covers all the corporate officers. The policy is posted on the Company's website at www.petd.com.  The Company will provide a copy of the Code to any person, without charge, upon request to the Company's Secretary at the Company's principal executive offices or by telephone at 800-624-3821.

                The Company has determined that all of its directors, other than Messrs. Williams and Riley are independent under NASDAQ rule 4200.

The Audit Committee of the Board of Directors is comprised entirely of independent directors as defined by the NASDAQ rule 4200(a)(15).  Donald B. Nestor, CPA, a partner in the certified public accounting firm of Toothman Rice PLLC, chairs the committee; other audit committee members are Mr. Jeffrey C. Swoveland and Ms. Kimberly Luff Wakim.  The Board of Directors has determined that Mr. Nestor and the other Audit Committee members qualify as audit committee financial experts and are independent of management.

The Nominating and Governance and Compensation Committees are also comprised entirely of independent directors of the Company. Vincent F. D'Annunzio chairs the Nominating and Governance Committee, and David C. Parke chairs the Compensation Committee.

The independent directors conduct meetings without the presence of management at each scheduled Board meeting. Kimberly Luff Wakim serves as Chairperson of these meetings having been selected as lead independent director by the Board.

Shareholders wishing to communicate with the Board of Directors or a committee may do so by writing to the attention of the Board or Committee at the corporate headquarters or by emailing the Board at board@petd.com, with "Board" or appropriate committee in the subject line.

51



Item 11.  Executive Compensation

Summary Compensation Table

The following table sets forth in summary form the compensation received during each of the Company's last three fiscal years by the Chief Executive Officer and by each other executive officer of the Company whose salary and bonus exceeded $100,000 in 2005 (the "Named Executives").

 Annual Compensation 

Long Term Compensation

Other

Restricted

Securities

Annual

Stock

underlying

All Other

Name and

Bonus

Compen-

Awards

Options

Compen-

Principal Position

Year

Salary($)

(1)($)

sation($)(2)

($)(3)

   (#)(4)   

sation($)(5)

Steven R. Williams

2005

318,000

271,597

11,886

-

-

146,666

Chief Executive Officer

2004

300,000

300,000

37,567

302,030

5,870

135,834

 and Director

2003

166,485

1,312,385

6,241

-

-

101,726

Thomas E. Riley

2005

252,000

141,135

4,638

-

-

106,666

President

2004

240,000

140,000

5,624

200,239

3,890

100,834

  and Director

2003

153,400(6)

121,370

1,565

   -       

-

 21,726

Eric R. Stearns

2005

231,000

129,374

11,406

-

-

102,666

Executive Vice President

2004

220,000

140,000

9,678

188,796

3,670

 97,834

2003

132,567(6)

121,370

1,084

-

-

 20,726

Darwin L. Stump

2005

210,000

98,713

9,398

-

-

106,666

Chief Financial Officer

2004

200,000

140,000

12,773

177,577

3,450

 97,834

  and Treasurer

2003

112,733(6)

121,370

1,074

-

-

 12,777

(1)       Includes bonuses earned in the reported fiscal year and paid in the following fiscal year.

(2)       Amounts disclosed in this column consist of use of a company vehicle, life insurance, disability insurance, and medical reimbursement as provided for in the Named Executive's employment contract. 

(3)       Amounts disclosed in this column consist of the value of restricted stock awards based upon the closing price of our common stock on the date of grant which was $37.15 on December 13, 2004.  During 2004 the number of shares awarded to Messrs. Williams, Riley, Stearns and Stump amounted to 8,130, 5,390, 5,080 and 4,780 shares, respectively.  These shares vest in four equal installments on the first, second, third and fourth anniversaries of the grant date.

(4)       Amounts in this column represent the number of options granted on December 13, 2004 to the named individuals. The fair value of these options at date of grant was $16.75 using the Black-Scholes option pricing model with an exercise price of $37.15. These options vest in four equal installments on the first, second, third and fourth anniversaries of the grant date.

52



(5)       This amount includes contributions made by the Company under the Company's Employee Profit Sharing Plan and 401(k) plan.  In 2005, 2004 and 2003 the Company contributed $420,000, $300,000 and $250,000, respectively, to the Employee Profit Sharing Plan. Of the contributions for 2005 and 2004, Messrs. Williams, Riley, Stearns and Stump were each credited $13,666 and $9,834, respectively. Of the contributions for 2003, Messrs., Williams, Riley and Stearns were each credited $9,726 and Mr. Stump was credited $8,634. The Company provided a matching of 401(k) contribution based upon all employees respective contributions.  The total Company matching contributions were $450,653, $382,700 and $305,515 in 2005, 2004 and 2003. For 2005, Messrs. Williams, Riley and Stump were each credited with matching contributions of $18,000, Mr. Stearns was credited with a matching contribution of $14,000. For 2004, Messrs. Williams and Riley were each credited with matching contributions of $16,000, Messrs. Stearns and Stump were credited with matching contributions of $13,000. For 2003, Messrs. Williams and Riley were each credited with matching contributions of $12,000, Messrs. Stearns and Stump were credited with matching contributions of $11,000 and $4,143, respectively. This amount also includes retirement compensation for the named individuals which provides for an amount per year worked under their employment agreements for 10 years following their termination of service. The total amounts earned during 2005 and 2004 to be paid over the ten-year period following such individuals' termination amounted to $115,000 and $110,000, respectively for Mr. Williams, and $75,000 for Messrs. Riley, Stearns and Stump for each year. For 2003 such amount was $80,000 for Mr. Williams. See "Retirement Arrangements" discussed below for a description of these arrangements.

(6)           This amount includes compensation for Messrs. Riley, Stearns and Stump earned during 2003 while each was an officer of the Company prior to becoming an Executive Officer in November 2003.

Aggregated Option Exercises in Last Fiscal Year and Fiscal Year-End Option Values

The following table provides certain information with respect to options exercised during 2005 by the persons named in the Summary Compensation Table under the Company's stock option plans, the number of options outstanding as of December 31, 2005 and the year-end value of such options, with respect to options granted pursuant to the Company's employee stock compensation plans.

Value of Unexercised

Number

Number of Options

In-The-Money Options

of Shares

Value

 at Year-end

at Year-End(1)($)

Exercised

Realized ($)*

Exercisable

Unexercisable

Exercisable

Unexercisable*

Steven R. Williams

-

-

1,467

4,403

-

-

Thomas E. Riley

-

-

972

2,918

-

-

Eric R. Stearns

-

-

917

2,753

-

-

Darwin L. Stump

-

-

862

2,588

-

-

*Market value of the underlying securities at exercise or year-end, as applicable, minus the exercise price.

(1) On December 31, 2005, the closing sales price of the Common Stock was $33.34 per share; the exercise price of these options is $37.15 per share.

Employment and Other Agreements and Arrangements

The Company entered into employment agreements with Messrs. Williams, Riley, Stearns and Stump effective January 1, 2004. The initial term of the agreements is for two years and they are automatically extended for an additional 12 months beginning on the first anniversary of the effective date and on each successive anniversary unless either party cancels. The employment agreements provided for a base annual salary for Mr. Williams, Mr. Riley, Mr. Stearns and Mr. Stump in the amounts of $300,000, $240,000, $220,000 and $200,000, respectively for 2004. For 2005 the Compensation Committee established base salaries for Mr. Williams, Mr. Riley, Mr. Stearns and Mr. Stump in the amounts of $318,000, $252,000, $231,000 and $210,000, respectively. Each employment agreement provides for an annual performance bonus, based upon a combination of written objective criteria approved by the Compensation Committee, determined prior to the beginning of each calendar year and upon the discretion of the Compensation Committee. The maximum amounts of the entire annual performance bonus were $300,000 for Mr. Williams and $140,000 for Messrs. Riley, Stearns and Stump in 2004. Each of the executives earned the maximum bonus in 2004. For 2005 the Compensation Committee set maximum annual performance amounts for Mr. Williams, Mr. Riley, Mr. Stearns and Mr. Stump of $413,400, $201,600, $184,800 and $168,000, respectively. Bonus earned in 2005 was $271,597 for Mr. Williams, $141,135 for Mr. Riley, $129,374 for Mr. Stearns and $98,713 for Mr. Stump.

In the event of a change in control of the Company, each Named Executive has the right to elect to terminate his employment under his employment agreement and receive severance compensation equal to three times the sum of 1) his highest base salary in the previous two years of employment plus 2) highest bonus paid to the named Executive during the same two year period.

Each employment agreement contains a standard non-disclosure covenant. Each employment agreement also provides that the Named Executive is prohibited during the term of his employment and for a period of one year following his termination from engaging in any business that is competitive with the Company's oil and gas drilling business.

Retirement Arrangements

 

The Company provides supplemental retirement benefits under terms of the various employment agreements with the Company's executive officers. The January 1, 2004 agreements provide for retirement benefits for each executive officer for a ten year period following the date of termination of service. During the life of each respective agreement, $110,000 for Mr. Williams and $75,000 for each of Messrs. Riley, Stearns and Stump are allocated yearly to their respective retirement account. The allocated amounts are accumulated over the life of the respective agreements. Following termination of service the aggregate fund will be disbursed to the individual officer in equal installments over ten years. Mr. Williams' agreement has an escalator provision which provides an increase in the annual contribution allocated to his retirement amount equal to $5,000 per year. In 2004, the allocation to Mr. Williams supplemental retirement account was $110,000; in 2005, the allocation increased to $115,000 for his account; in 2006, the allocation will increase to $120,000. At December 31, 2005, the executive officers had accumulated the following amounts in their respective retirement accounts, Mr. Williams $225,000; Mr. Riley $150,000; Mr. Stearns $150,000 and Mr. Stump $150,000. These accounts will continue to accumulate retirement funds during the terms of the respective employment agreements.

 

53


Under his previous employment agreement, Mr. Williams also earned supplemental retirement benefits. The prior agreement requires the Company to pay Mr. Williams an annual sum of $40,000 per year for the ten year period following his retirement from the Company (an aggregate of $400,000), in addition to benefit discussed above. This benefit was fully vested on December 31, 2003.

Stock Option Plans

Under the Company's incentive stock option plans, options to purchase shares of Common Stock of the Company may be granted to certain officers and key employees of the Company, which options are intended to qualify as incentive stock options under the provisions of the Internal Revenue Code. The options may be exercised six months after the date of grant. Options will expire ten years from the date of grant if not exercised. A dissolution or liquidation of the Company or a merger or consolidation in which the Company is not the surviving corporation will cause each outstanding option to terminate, provided that each optionee, in such event, will have the right immediately prior to said dissolution or liquidation or merger or consolidation to exercise his option in whole or in part without regard to any installment vesting provisions with respect to such options. No additional options may be granted under these earlier plans.

As approved by the shareholders at the annual meeting in 2004, the Company has a Long-Term Equity Compensation Plan which allows for the awarding of Non-qualified stock options, Incentive Stock Options, Stock Appreciation Rights, Restricted Stock, Performance shares and Performance units. The number of shares allocated to this plan is 750,000 shares.  During 2004, a total of 23,380 shares of restricted stock and 16,880 options were granted to the executives named previously. As of April 30, 2006, 664,075 shares remain in the plan, for future grants.

Key-Man Life Insurance

The Company maintains key-man life insurance policies on the life of Mr. Williams in the amount of $4.0 million, and in the amount of $1.0 million for Messrs. Riley, Stearns and Stump. The Company is the beneficiary of each policy.

Employee 401(k) and Profit Sharing Plan

In 1987, the Company established a retirement plan qualified under Section 401(k) of the Internal Revenue Code. The plan is funded by employee contributions and a company matching contribution. Administrative costs of the plan are borne by the Company. The employees choose from eight investment programs and, therefore, the amount of an individual's plan assets depends on the amount of their contributions and the performance by their chosen investments.

In 1992, the Company began a Profit Sharing Retirement plan to supplement the 401(k) Plan. Contributions are dependent on corporate profitability and are at the discretion of the Board of Directors of the Company. The Company filed and qualified the plan with the Internal Revenue Service.  

Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth certain information regarding ownership of the Company's Common Stock as of April 30, 2006 by (a) each person known by the Company to own beneficially more than 5% of the outstanding shares of Common Stock; (b) each director of the Company; (c) each Named Executive; (d) all directors and executive officers as a group.

54



Beneficial Ownership (1)

Name and Address

Number

Percent

Barclays Global Investors, NA

45 Fremont Street

San Francisco, CA 94105

2,477,121

(2)

15.40%

Fidelity Management

82 Devonshire Street

Boston, MA 02109

2,415,600

(3)

15.00%

Kayne Anderson Rudnick

Investment Management LLC

1800 Avenue of the Stars 2nd Floor

Los Angeles, CA 90067

1,281,289

(4)

8.00%

Steinberg Asset Management LLC

12 East 49th Street

New York, NY 10017

1,104,781

(5)

6.90%

Steven R. Williams

103 East Main Street

Bridgeport, WV 26330

421,101

(6)

2.60%

Thomas E. Riley

103 E. Main Street

Bridgeport, WV 26330

109,700

(7)

*

Eric R. Stearns

103 E. Main Street

Bridgeport, WV 26330

61,438

(8)

*

Darwin L. Stump

103 E. Main Street

Bridgeport, WV 26330

30,473

(9)

*

Vincent F. D'Annunzio

18,646

*

Jeffrey C. Swoveland

13,721

*

Donald B. Nestor

2,522

*

Kimberly Luff Wakim

2,965

*

David C. Parke

2,450

*

All directors and executive officers as a

663,016

4.10%

group (9 persons)

55


* Less than 1%

(1)     Includes shares over which the person currently holds or shares voting or investment power. Unless otherwise indicated in the footnotes to this table, the persons named in this table have sole voting and investment power with respect to the shares beneficially owned.

(2)     According to the Schedule 13G filed by Barclay Global Investors, NA with the Securities and Exchange Commission on January 26, 2006.

(3)     According to the Schedule 13G filed by Fidelity Management with the Securities and Exchange Commission on January 10, 2006.

(4)     According to Schedule 13G filed by Kayne Anderson Rudnick Investment Management, LLC with the Securities and Exchange Commission on February 6, 2006.

(5)     According to the Schedule 13F-HR filed by Steinberg Asset Management, LLC with the Securities and Exchange Commission on April 17, 2006.

(6)     Mr. Williams: includes 1,467 shares subject to options exercisable within 60 days of April 30, 2006.

(7)     Mr. Riley: includes 972 shares subject to options exercisable within 60 days of April 30, 2006.

(8)     Mr. Stearns: includes 917 shares subject to options exercisable within 60 days of April 30, 2006.

(9)     Mr. Stump: includes 862 shares subject to options exercisable within 60 days of April 30, 2006.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires the Company's officers and directors, and persons who own more than 10% of a Company's equity securities, to file reports of ownership and changes in ownership with the Securities and Exchange Commission. Officers, directors and holders of more than 10% of the Common Stock are required by regulations promulgated by the Commission pursuant to the Exchange Act to furnish the Company with copies of all Section 16(a) forms they file. The Company assists officers and directors, and will assist beneficial owners, if any, of more than 10% of the Common Stock, in complying with the reporting requirements of Section 16(a) of the Exchange Act.

Based solely on its review of the copies of such forms received by it, the Company believes that since January 1, 2005, all Section 16(a) filing requirements applicable to its directors, officers and greater than 10% beneficial owners were met.

The Company has the following common stock options outstanding under the stock option plans authorized for issuance:


Equity Compensation Plan Information

April 30, 2006

Plan Category

Number of securities to

be issued upon exercise

of outstanding options,

warrants and rights

(a)

Weighted-average

exercise price of

outstanding options,

warrants and rights

(b)

Number of securities

remaining available for

future issuance under

equity compensation

plans (excluding 

securities reflected  in

column (a))

(c)

Equity compensation plans

 approved by security holders

94,234

$18.82

664,075

Equity compensation plans not

 approved by security holders


 0


 0


 0

Total

94,234

 $18.82

664,075

Item 13.  Certain Relationships and Related Transactions

During the year ended December 31, 2005, there was no transaction or series of transactions to which we were or are a party in which the amount involved exceeded or exceeds $60,000 and in which any director, executive officer, holder of more than 5% of our common stock or any member of the immediate family of any of the foregoing persons had or will have a direct or indirect material interest.

Item 14.  Principal Accountant Fees and Services

KPMG Fees

The following table presents the aggregate fees billed to the Company by KPMG LLP (KPMG) for services in 2005 and 2004 as of March 31, 2006:

56


2005

2004

Audit Fees

$  1,743,010

$   708,524

Audit Related Fees

      140,977

309,127

Total Audit and Audit Related Fees

$1,883,987

$1,017,651

Tax Fees

0

4,000

All Other Fees

               0

               0

Total Fees

$ 1,883,987

$1,021,651

Audit Fees

The aggregate audit fees billed for professional services rendered by KPMG LLP for the audit of our annual financial statements and the audit of the Company's internal controls over financial reporting for the fiscal years ended December 31, 2005 and 2004, including reviews of the condensed financial statements included in our quarterly reports on Form 10-Q for the fiscal years ended December 31, 2005 and 2004, were $1,743,010 and $708,524.

 

Audit Related Fees

The aggregate of audit related fees relating to registration statements filed with the Securities and Exchange Commission amounted to $24,900 for the year ended December 31, 2004. Also included as audit related fees are the annual audits of the financial statements for the fiscal years ended December 31, 2005 and 2004 of sixty-five and sixty-two limited partnerships, respectively, for which the Company acts as managing general partner. The aggregate billings for those professional services was $284,227 for the year ended December 31, 2004, the services for the year ended December 31, 2005 have not been billed as of March 31, 2006. The total of audit related fees for the year ended December 31, 2005 was for due diligence services provided for a contemplated transaction.

 

Tax Fees

Tax Fees include tax compliance services for the fiscal year ended December 31, 2004 provided for the partnerships formed in such year for which the Company acts as managing general partner, in the amount of $4,000.

 

Pre-Approval Policies and Procedures

The Sarbanes-Oxley Act of 2002 requires that all services provided to the Company by its Independent Registered Public Accounting Firm be subject to pre-approval by the Audit Committee or authorized members of the Committee. The Audit Committee has adopted policies and procedures for pre-approval of all audit services and non-audit services to be provided by the Company's Independent Registered Public Accounting Firm. Services necessary to conduct the annual audit must be pre-approved by the Audit Committee annually at a meeting. Permissible non-audit services to be performed by the independent accountant may also be approved on an annual basis by the Audit Committee if they are of a recurring nature. Permissible non-audit services to be conducted by the independent accountant which are not eligible for annual pre-approval must be pre-approved individually by the full Audit Committee or by an authorized Audit Committee member. Actual fees incurred for all services performed by the independent accountant will be reported to the Audit Committee after the services are fully performed. The duties of the Committee are described in the Audit Committee Charter, which is available at the Company's website under Corporate Governance.

Item 15.  Exhibits and Financial Statement Schedules

(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.

57



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/ Steven R. Williams       

   Steven R. Williams, Chairman

May  31, 2006

                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/ Steven R. Williams

    Steven R. Williams

Chairman, Chief Executive Officer and Director

May 31, 2006

/s/ Darwin L. Stump

    Darwin L. Stump

Chief Financial Officer and Treasurer

(principal financial and accounting officer)

May 31, 2006

 

/s/ Thomas E. Riley

    Thomas E. Riley

President and Director

May 31, 2006

/s/ Donald B. Nestor

    Donald B. Nestor

Director, Chairman of Audit Committee

May 31, 2006

/s/ Vincent F. D'Annunzio

    Vincent F. D'Annunzio

Director

May 31, 2006

/s/ Jeffrey C. Swoveland

    Jeffrey C. Swoveland

Director

May 31, 2006

 

/s/ Kimberly Luff Wakim

    Kimberly Luff Wakim

Director

May 31, 2006

 

/s/ David C. Parke

    David C. Parke

Director

May 31, 2006

 

58



Exhibits Index

(a) Exhibits


 

Exhibit Name

Exhibit

Number

Location

Articles of Incorporation

3.1

Incorporated by reference to Exhibit 3.1 to Form S-2 SEC File No. 333-36369 filed on September 25, 1997

By Laws

3.2

Incorporated by reference to Exhibit 3.2 to Form 8-K SEC File No. 0-07246 filed on September 8, 2003

Amended and restated Credit Agreement, dated as of November 4, 2005, Petroleum Development Corporation, as borrower, and JPMorgan Chase Bank, N.A. and BNP Paribas, as lenders.

10.1

Incorporated by reference to Exhibit 10.2 to Form 8-K dated November 4, 2005.

Employment Agreement with Steven R. Williams, Chief Executive Officer and Chairman, dated as of March 7, 2003 and amended December 29, 2005

10.2

Incorporated by reference in Exhibit 10.2 to Form 10-K filed on March 7, 2003 and amended by reference of Form 8-K filed January 4, 2006

Employment Agreement with Darwin L. Stump, Chief Financial Officer, dated as of January 5, 2004 and amended December 29, 2005

10.3

Incorporated by reference to Exhibit 99.4 Form 8-K dated January 5, 2004 and  Exhibit 99.4 to Form 8-K dated January 4, 2006

Employment Agreement with Thomas E. Riley, President, dated as of January 5, 2004 and amended December 29, 2005

10.4

Incorporated by reference to Exhibit 99.6 Form 8-K dated January 5, 2004 and Exhibit 99.2 to Form 8-K dated January 4, 2006

Employment Agreement with Eric R. Stearns, Executive Vice President, dated as of January 5, 2004 and amended December 29, 2005

2005 Non-Employee Director Restricted Stock Plan

10.5

10.6

Incorporated by reference to Exhibit 99.5 Form 8-K dated January 5, 2004 and Exhibit 99.3 to Form 8-K dated January 4, 2006.

Incorporated by reference to Exhibit 99.1 to Form S-8, SEC file No. 333-126444 filed on July 7, 2005

2004 Long-Term Equity Compensation Plan

10.7

Incorporated by reference to Exhibit 99.1 to Form S-8, SEC File No. 333-118215, filed on August 13, 2004

Non-Employee Director Deferred Compensation Plan

10.8

Incorporated by reference Exhibit 99.1 to Form S-8, SEC File No. 333-118222, filed on August 13, 2004

1999 Incentive Stock Option and Non-Qualified Stock

10.9

Incorporated by reference to Exhibit 99.1 to form S-8, SEC File No. 333-111825, filed on January 9, 2004

1997 Employee Incentive Stock Option Plan

10.10

Incorporated by reference to Exhibit 99.1 to Form S-8, SEC File No. 333-111824, filed on January 9, 2004

Tom Carpenter Employment Agreement Stock Option Plan

10.11

Incorporated by reference to Exhibit 99.1 to Form S-8, SEC File No. 333-111823, filed on January 9, 2004

Code of Business Conduct and Ethics

14

Incorporated by reference to Exhibit 3.1 to

Form 10-K for the year ended December 31, 2002, SEC File No. 0-07246 filed on March 7, 2003

Subsidiaries

21

Riley Natural Gas Company, a West Virginia Corporation

21

PDC Securities Incorporated, a West Virginia Corporation

Consent of Independent Registered Public Accounting Firm

23.1

Filed herewith.

Consent of Independent Petroleum Engineers

Consent of Independent Petroleum Engineers

23.2

23.3

Filed herewith.

Filed herewith

Rule 13a-14(a)/15d-14(a) Certification by  Chief

  Executive Officer

31.1

Filed herewith.

Rule 13a-14(a)/15d-14(a) Certification by Chief

  Financial Officer

31.2

Filed herewith.

Title 18 U.S.C. Section 1350 (Section 906 of Sarbanes-Oxley Act of 2002)  Certifications by Chief Executive Officer and Chief Financial Officer

32.1

Filed herewith.

59



GLOSSARY OF TERMS

The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this Form 10-K.

Bbl.  One barrel, or 42 U.S. gallons of liquid volume.

Bcf.  One billion cubic feet.

Bcfe.  One billion cubic feet of natural gas equivalents.

Completion.  The installation of permanent equipment for the production of oil or gas.

Credit Facility.  A line of credit provided by a group of banks, secured by oil and gas properties.

DD&A.  Refers to depreciation, depletion and amortization of the Company's property and equipment.

Development well.  A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole.  A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well.

Exploratory well.  A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new productive reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Extensions and discoveries.  As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates.

Gross acres or wells.  Refers to the total acres or wells in which the Company has a working interest.

Horizontal drilling.  A drilling technique that permits the operator to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons.

MBbls.  One thousand barrels.

Mcf.  One thousand cubic feet.

Mcfe.  One thousand cubic feet of natural gas equivalents, based on a ratio of 6 Mcf for each barrel of oil, which reflects the relative energy content.

MMbtu.  One million British thermal units.  One British thermal unit is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

MMcf.  One million cubic feet.

MMcfe.  One million cubic feet of natural gas equivalents.

Natural gas liquids.  Liquid hydrocarbons that have been extracted from natural gas, such as ethane, propane, butane and natural gasoline.

Net acres or wells.  Refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by the Company.

Net production.  Oil and gas production that is owned by the Company, less royalties and production due others.

NYMEX.  New York Mercantile Exchange, the exchange on which commodities, including crude oil and natural gas futures contracts, are traded.

60



Oil.  Crude oil or condensate.

Operator.  The individual or company responsible for the exploration, development and production of an oil or gas well or lease.

Present value of proved reserves.  The present value of estimated future revenues, discounted at 10% annually, to be generated from the production of proved reserves determined in accordance with Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment, (ii) nonproperty related expenses such as general and administrative expenses, debt service and future income tax expense, or (iii) depreciation, depletion and amortization.

Proved developed nonproducing reserves.  Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells.

Proved developed producing reserves.  Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods.

Proved developed reserves.  The combination of proved developed producing and proved developed nonproducing reserves.

Proved reserves.  The estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made.  Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

Proved undeveloped reserves (PUD).  Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Royalty.  An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage.  Royalties may be either landowner's royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

 

SEC.  The United States Securities and Exchange Commission.

Standardized measure of discounted future net cash flows.  Present value of proved reserves, as adjusted to give effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment, and (ii) estimated future income taxes.

Undeveloped acreage.  Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether such acreage contains proved reserves.

Working interest.  An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.  The share of production to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to the extent of any royalty burden.

Workover.  Operations on a producing well to restore or increase production.

 

61



PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Index to Financial Statements and Financial Statement Schedule

1.

Financial Statements:

     Report of Independent Registered Public Accounting Firm

F-2

     Consolidated Balance Sheets - December 31, 2005 and 2004

F-3 & 4

     Consolidated Statements of Income -

      Years Ended December 31, 2005, 2004 and 2003

F-5

     Consolidated Statements of Stockholders' Equity -

      Years Ended December 31, 2005, 2004 and 2003

F-6

     Consolidated Statements of Cash Flows -

      Years Ended December 31, 2005, 2004 and 2003

F-7

     Notes to Consolidated Financial Statements

F-8 -F-37

2.

Financial Statement Schedule:

Schedule II - Valuation and Qualifying Accounts and Reserves

F-38

F-1




PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

 

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Petroleum Development Corporation:

We have audited the accompanying consolidated balance sheets of Petroleum Development Corporation and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of income, stockholders' equity, and cash flows for each of the years in the three-year period ended December 31, 2005. In connection with our audits of the consolidated financial statements, we also have audited the related financial statement schedule II.  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 the standards of the Public Company Accounting Oversight Board (United States).  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, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U. S. generally accepted accounting principles.  Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 22 to the consolidated financial statements, the Company restated its 2004 and 2003 consolidated financial statements.

As discussed in Note 1 to the consolidated financial statements, the Company adopted the provisions of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, in 2003.

We also have audited, in accordance with the standards of Public Company Accounting Oversight Board (United States), the effectiveness of Petroleum Development Corporation's internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated May 15, 2006, expressed an unqualified opinion on management's assessment of, and an adverse opinion on the effective operation of, internal control over financial reporting as of December 31, 2005.

KPMG LLP

Pittsburgh, Pennsylvania

May 24, 2006

F-2




PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets

December 31, 2005 and 2004

     Assets

2005

2004

Current assets:

  Cash and cash equivalents

 $        90,110,100

 $       77,070,400

  Restricted cash

             1,500,600

               664,900

  Accounts receivable

           49,779,500

          33,834,700

  Accounts receivable affiliates

             7,233,800

            2,230,600

  Inventories

             5,054,900

            1,657,300

  Fair value of derivatives

           10,381,800

            3,266,100

  Other current assets

             4,640,500

            6,612,800

     Total current assets

         168,701,200

        125,336,800

Properties and equipment:

  Oil and gas properties (successful

    efforts accounting method)

         365,379,600

        282,837,200

  Pipelines

           11,511,600

            9,515,000

  Transportation and other equipment

             6,382,800

            4,453,700

  Land and buildings

             3,980,800

   2,942,800

  Construction in progress

             1,509,300

      -       

         388,764,100

        299,748,700

  Less accumulated depreciation,

    depletion and amortization

         111,605,900

          92,165,400

         277,158,200

        207,583,300

  Other assets

             3,225,500

     2,108,200

Total Assets

 $      449,084,900

 $     335,028,300

(Continued)

F-3




PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

 Consolidated Balance Sheets

December 31, 2005 and 2004

Liabilities and Stockholders' Equity

2005

2004

Current liabilities:

  Accounts payable

 $       65,004,100

 $      43,182,900

  Production tax liability

          30,144,500

         17,510,500

 Fair value of derivatives

          18,424,400

6,716,400

  Other accrued expenses

            4,140,500

           2,286,800

  Advances for future drilling contracts

          49,999,400

         42,497,300

 Federal and state income taxes payable

            8,473,200

      -       

  Funds held for future distribution

          18,346,300

         12,911,800

             Total current liabilities

        194,532,400

       125,105,700

Long-term debt

          24,000,000

         21,000,000

Other liabilities

            7,115,500

           3,927,500

Deferred income taxes

          26,888,500

         22,976,300

Asset retirement obligation

            8,283,200

           7,998,200

             Total liabilities

        260,819,600

       181,007,700

Commitments and contingencies (Note 10)

Stockholders' equity:

  Common stock, par value $.01 per share;

   authorized 50,000,000 shares; issued and

   outstanding 16,281,923 and 16,589,824 shares

               162,800

              165,800

  Additional paid-in capital

          30,422,900

         37,684,300

  Retained earnings

        158,504,200

       117,052,500

  Unamortized stock award

              (824,600)

             (882,000)

              Total stockholders' equity

        188,265,300

       154,020,600

Total Liabilities and Stockholders' Equity

 $     449,084,900

 $    335,028,300

                   See accompanying Notes to Consolidated Financial Statements.

F-4




PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets

December 31, 2005 and 2004

2005

2004

2003

(Restated)

(Restated)

Revenues:

  Oil and gas well drilling operations

 $      99,962,900

 $      94,076,000

 $       57,509,600

  Gas sales from marketing activities

       121,104,100

         94,626,800

          73,131,700

  Oil and gas sales

       102,559,200

         69,492,100

          48,393,800

  Well operations and pipeline income

           8,759,600

           7,676,900

            6,907,100

  Other income

         10,747,300

           1,880,700

            3,528,500

               Total revenues

       343,133,100

       267,752,500

        189,470,700

Costs and expenses:

  Cost of oil and gas well drilling operations

         88,184,900

         77,696,200

          46,945,900

  Cost of gas marketing activities

       119,643,700

         92,881,200

          72,361,400

  Oil and gas production and well operations costs

         19,934,700

         17,277,200

          13,251,300

 Exploratory dry hole costs

         11,115,100

              -    

              -    

  General and administrative expenses

           6,960,300

           4,505,600

            4,974,400

  Depreciation, depletion and amortization

         21,116,200

         18,155,900

          15,312,800

               Total costs and expenses

       266,954,900

       210,516,100

        152,845,800

  Income from operations

         76,178,200

         57,236,400

          36,624,900

  Interest expense

              682,300

              673,700

            1,195,300

  Oil and gas price risk management loss, net

           9,368,100

           3,084,600

               812,400

   Income before income taxes and  cumulative

     effect of change in accounting principle

         66,127,800

         53,478,100

          34,617,200

Income taxes

         24,676,100

         20,250,500

          11,933,500

   Net income before cumulative effect of

      change in accounting principle

         41,451,700

         33,227,600

          22,683,700

Cumulative effect of change in accounting

  principle (net of taxes of $1,392,000)

              -    

              -    

          (2,271,300)

Net income

 $      41,451,700

 $      33,227,600

 $       20,412,400

Basic earnings per common share before

  accounting change

 $                 2.53

 $                 2.05

 $                  1.45

Cumulative effect of change in accounting

  principle

              -    

              -    

 $                (0.15)

Basic earnings per common share

 $                 2.53

 $                 2.05

 $                  1.30

Diluted earnings per share before accounting

  change

 $                 2.52

 $                 2.00

 $                  1.39

Cumulative effect of change in accounting

  principle

              -    

              -    

 $                (0.14)

Diluted earnings per common and common

  equivalent share

 $                 2.52

 $                 2.00

 $                  1.25

See accompanying Notes to Consolidated Financial Statements.

F-5





PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Consolidated Statements of Stockholders' Equity

Years Ended December 31, 2005, 2004, and 2003


Common Stock Issued

Treasury Stock

Number of

Additional

Retained

at Cost

Unamortized

Shares

Amount

Paid-In-Capital

Earnings

(Restated)

Stock Award

Total

Balance, December 31, 2002

 15,734,767

 $   157,300

 $      29,340,500

 $    63,412,500

 $              -

 $    (23,700)

 $  92,886,600

Amortization of stock award

       -     

      -     

       -     

       -     

       -     

8,900

8,900

Repurchase of treasury stock

       -     

       -     

       -     

       -     

        (748,700)

       -     

(748,700)

Treasury stock retirement

     (106,334)

(1,100)

(747,600)

       -     

         748,700

       -     

       -     

Net income

       -     

      -     

       -     

20,412,400

       -     

       -     

20,412,400

Balance, December 31, 2003

 15,628,433

156,200

28,592,900

83,824,900

       -     

(14,800)

112,559,200

Issuance of common stock

   Exercise of employee stock options

   1,100,000

11,000

4,981,700

       -     

       -     

       -     

4,992,700

Stock award

        23,380

200

870,700

       -     

       -     

(870,900)

      -     

Amortization of stock award

       -     

      -     

       -     

       -     

       -     

3,700

3,700

Repurchase of treasury stock

       -     

       -     

       -     

       -     

     (4,157,400)

       -     

(4,157,400)

Treasury stock retirement

     (161,989)

(1,600)

(4,155,800)

       -     

      4,157,400

       -     

       -     

Income tax benefit from the exercise of stock options

       -     

      -     

7,394,800

       -     

       -     

       -     

7,394,800

Net income

       -     

      -     

       -     

33,227,600

       -     

       -     

33,227,600

Balance, December 31, 2004

 16,589,824

165,800

37,684,300

117,052,500

       -     

(882,000)

154,020,600

Issuance of common stock

   Exercise of employee stock options

          3,000

100

11,500

      -     

       -     

      -     

            11,600

Stock award

        20,895

200

602,600

      -     

       -     

(602,800)

      -     

Amortization of stock award

       -     

       -     

       -     

      -     

       -     

660,200

          660,200

Repurchase of treasury stock

       -     

       -     

       -     

      -     

(7,878,800)

      -     

(7,878,800)

Treasury stock retirement

(331,796)

        (3,300)

         (7,875,500)

      -     

      7,878,800

Net income

       -     

      -     

      -     

41,451,700

      -     

      -     

41,451,700

Balance, December 31, 2005

16,281,923

 $   162,800

 $      30,422,900

 $  158,504,200

 $              -

 $  (824,600)

$188,265,300

See accompanying Notes to Consolidated Financial Statements.

F-6




PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Consolidated Statements of Cash Flows

Years Ended December 31, 2005, 2004, and 2003


Cash flows from operating activities:

2005

2004

2003

  Net income

$41,451,700

$33,227,600

$20,412,400 

  Adjustment to reconcile net income to cash provided

     by operating activities:

   Deferred income taxes

3,350,600

9,887,300 

8,462,300 

   Depreciation, depletion and amortization

21,116,200

18,155,900 

15,312,800 

   Accretion of asset retirement obligation

465,200

436,000 

379,200 

   Exploratory dry hole costs

11,115,100

-    

-    

   Unrealized loss (gain) on derivative transactions

3,225,900

535,200 

(1,110,200)

   Cumulative effect of change in accounting principle

-    

-    

2,271,300 

   Gain from sale of assets

(7,875,800)

(32,000)

(202,500)

   Expired and abandoned leases

47,600

300,800 

1,383,000 

   Amortization of stock award

660,200

3,700 

8,900 

   Change in assets and liabilities:

     Increase in accounts receivable

(11,276,400)

(10,492,600)

(7,197,800)

 (Increase) decrease in accounts receivable affiliates

(5,003,200)

(343,200)

10,700

     (Increase) decrease in restricted cash

(835,700)

1,201,500

894,100

     (Increase) decrease in inventories

(3,397,600)

357,000 

(1,383,600)

     Decrease (increase) in other current assets

3,482,100

4,776,200 

(1,095,900)

     (Increase) decrease in other assets

(651,600)

(48,800)

1,696,200 

     Increase in production tax liability

12,634,000

8,441,100 

3,974,800 

     Increase in accounts payable and accrued expenses

22,453,500

10,355,800 

13,018,300 

     Increase (decrease) in advances for future drilling contracts

7,502,100

(7,961,500)

13,175,000 

 Increase in federal and state income taxes payable

8,473,200

-    

-    

     Increase in funds held for future distribution

5,434,500

 4,500,900 

 4,493,000 

         Total adjustments

70,919,900

40,073,300