UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549

FORM 10 -K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2008

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 000-07246
 
                  LOGO
PETROLEUM DEVELOPMENT CORPORATION
(Exact name of registrant as specified in its charter)
   
Nevada
95-2636730
(State of Incorporation)
(I.R.S. Employer Identification No.)
   

120 Genesis Boulevard
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:

Title of Each Class
 
Name of Each Exchange on Which Registered
Common Stock, par value $.01 per share
 
NASDAQ Global Select Market

Securities registered pursuant to Section 12(g) of the Act:  None

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 (or for such shorter period that the registrant was required to file such reports), 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 (§229.405 of this chapter) is not contained herein, and will not 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. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer    x
Accelerated filer    ¨
   
Non-accelerated filer    ¨
Smaller reporting company    ¨
 
(Do not check if a smaller reporting company)

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

The aggregate market value of our common stock held by non-affiliates on June 30, 2008, was $965,929,153 (based on the then closing price of $66.49).

As of February 23, 2009 there were 14,868,158 ares of our common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Part III of this Form is incorporated by reference to our definitive proxy statement to be filed pursuant to Regulation 14A for our 2009 Annual Meeting of Shareholders.
 
 
 
 

PETROLEUM DEVELOPMENT CORPORATION
2008 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS


 
PART I
Page
     
Item 1.
1
Item 1A.
16
Item 1B.
25
Item 2.
26
Item 3.
26
Item 4.
26
     
 
PART II
 
     
Item 5.
26
Item 6.
29
Item 7.
30
Item 7A.
47
Item 8.
49
Item 9.
49
Item 9A.
49
Item 9B.
50
     
 
PART III
 
     
Item 10.
50
Item 11.
50
Item 12.
50
Item 13.
51
Item 14.
51
     
 
PART IV
 
     
Item 15.
51
     
52
     
53

 

  PART I

REFERENCES TO THE REGISTRANT

Unless the context otherwise requires, references to “PDC”, “the Company”, “we”, “us”, “our”, “ours”, or “ourselves” in this report refer to the registrant, Petroleum Development Corporation, together with its subsidiaries, proportionate share of its sponsored drilling partnerships and an entity in which it has a controlling interest.

GLOSSARY OF OIL AND NATURAL GAS TERMS

Words defined in the Glossary of Oil and Natural Gas Terms are set in boldface type the first time they appear.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 regarding our business, financial condition, results of operations and prospects.  Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein, which include statements of estimated oil and natural gas production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and our management’s strategies, plans and objectives.  However, these are not the exclusive means of identifying forward-looking statements herein.  Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us.  Consequently, forward-looking statements are inherently subject to risks and uncertainties, including risks and uncertainties incidental to the exploration for, and the acquisition, development, production and marketing of, natural gas and oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements.  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 oil and natural gas;
 
·
the timing and extent of our success in discovering, acquiring, developing and producing natural gas and oil reserves;
 
·
our ability to acquire leases, drilling rigs, supplies and services at reasonable prices;
 
·
the availability and cost of capital to us;
 
·
risks incident to the drilling and operation of natural gas and oil wells;
 
·
future production and development costs;
 
·
the availability of sufficient pipeline and other transportation facilities to carry our production and the impact of these facilities on price;
 
·
the effect of existing and future laws, governmental regulations and the political and economic climate of the United States of America (“U.S.”);
 
·
the effect of natural gas and oil derivatives activities;
 
·
conditions in the capital markets; and
 
·
losses possible from pending or future litigation.

Further, we urge you to carefully review and consider the disclosures made in this report, including the risks and uncertainties that may affect our business as described herein under Item 1A , Risk Factors , and our other filings with the Securities and Exchange Commission (“SEC”).  We caution you not to place undue reliance on forward-looking statements, which speak only as of the date of this report.   We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events.

ITEM 1.  BUSINESS

General

We are an independent energy company engaged in the exploration, development, production and marketing of oil and natural gas.  Since we began oil and natural gas operations in 1969, we have grown through drilling and development activities, acquisitions of producing natural gas and oil wells and the expansion of our natural gas marketing activities.

As of December 31, 2008, we owned interests in approximately 4,712 gross , 3,259 net , wells located primarily in the Rocky Mountain Region and the Appalachian and Michigan Basins with 753 billion cubic feet equivalent, or Bcfe , of net proved reserves , of which 88% was natural gas and 12% was oil.

During 2008, our production was 38.7 Bcfe, averaging 106.1 MMcfe per day, a 38.5% increase over 76.6 MMcfe per day produced in 2007.  We replaced our 2008 production with 106 Bcfe of new proved reserves, net of dispositions, for a reserve replacement rate of 274%.  Reserve replacement through the drillbit was 104 Bcfe, or 268% of production, and reserve replacement through acquisitions was 2 Bcfe, or 6% of production.  Proved reserves grew 9.8% during 2008, from 686 Bcfe to 753 Bcfe, of which 44% were proved developed reserves .


    We make available free of charge on our website at www.petd.com our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to these reports as soon as reasonably practicable after we electronically file these reports with, or furnish them to, the SEC.  We will also make available to any shareholder, without charge, a copy of our Annual Report on Form 10-K, or any other filing, as filed with the SEC, by mail.  For a mailed copy of a report, you may contact Petroleum Development Corporation, Investor Relations, 1775 Sherman Street, Suite 3000, Denver, CO 80203, or call toll free (800) 624-3821.

    In addition to our SEC filings, other information, including our press releases, Bylaws, Committee Charters, Code of Business Conduct and Ethics, Shareholder Communication Policy, Director Nomination Procedures and the Whistleblower Hotline, is also available on our website.  However, the information available on our website is not part of this report and is not hereby incorporated by reference.
 
Business Strategy

Our primary objective is to continue to increase shareholder value through the growth of our reserves, production, net income and cash flow.  To achieve meaningful increases in these key areas, we maintain an active drilling program that focuses on low risk development of our oil and natural gas reserves, limited exploratory drilling and the acquisition of producing properties with significant development potential.

Drill and Develop

   Our acreage holdings include positions in the Rocky Mountain Region and the Appalachian, Michigan and Fort Worth Basins.  In the Rocky Mountain Region, we focus on developmental drilling in Northeastern Colorado, or NECO, the Wattenberg Field (both located in the DJ Basin), the Grand Valley Field, Piceance Basin, and additional limited development in North Dakota.  We drilled 379 gross, 333.4 net, wells in 2008, compared to 349 gross, 276.3 net, wells in 2007.  In addition, we seek to maximize the value of our existing wells through a program of well recompletions and refractures .  During 2008, we recompleted and/or refraced a total of 125 wells compared to 181 in 2007.  In 2009, with a limited inventory of available recompletion opportunities, we plan to recomplete and/or refrac 40 wells in the Appalachian Basin.

   We believe that we will be able to continue to drill a substantial number of new wells on our current undeveloped properties.  As of December 31, 2008, we had leases or other development rights to approximately 224,800 undeveloped acres, of which approximately 188,000 acres, or 83.5%, were in the Rocky Mountain Region.  We plan to drill approximately 166 gross, 144.1 net, wells in 2009, excluding exploratory wells .  To support future development activities, we have conducted exploratory drilling in the past and plan to drill seven wells in 2009, primarily in the Appalachian Basin.  The goal of the exploration program is to develop new areas for us to include in our future development drilling activity.

Strategically Acquire

   Our acquisition efforts focus on producing properties that have a significant undeveloped acreage component.  When weighing potential acquisitions, we prefer properties that have most of their value in producing wells, behind the pipe reserves or high quality proved undeveloped locations.  Historically, acquisitions have offered efficiency improvements through economies of scale in management and administration costs.  During the period December 2006 through October 2007, we completed three acquisitions of assets or companies in our core operating area of the Wattenberg Field in Colorado and acquired assets in southwestern Pennsylvania within close proximity to our existing assets in the Appalachian Basin.  We had no significant acquisitions of properties in 2008.  We expect to continue to evaluate acquisition opportunities.  See Note 14 , Acquisitions , to our accompanying consolidated financial statements included in this report.

Manage Risk

   We seek opportunities to reduce the risk inherent to our business in the oil and natural gas industry by focusing our drilling efforts primarily on lower risk development wells and by maintaining positions in several different geographic regions and markets.  Historically, we have concentrated on development drilling and geographical diversification to reduce risk levels associated with natural gas and oil drilling, production and markets.  Currently, a majority of our proved reserves are located in the Rocky Mountain Region due to our success in that area over the past several years.  However, we benefit from operational diversity in the Rocky Mountain Region by maintaining significant activity and production in three separate areas, including the Grand Valley Field of the Piceance Basin in western Colorado, the Wattenberg Field in north central Colorado and the NECO area.  Additionally, we regularly review opportunities to further diversify into other regions where we can apply our operational expertise.  We believe development drilling will remain the foundation of our drilling activities in the future because it is less risky than exploratory drilling and is likely to generate cash returns more quickly.  We expect that future activities may include some level of exploratory drilling when the economic environment and commodity price models justify such risks.  We view exploratory activities as having the potential to identify new development opportunities at a cost competitive to the current cost of acquiring proven locations.


To help manage the risks associated with the oil and natural gas industry, we maintain a conservative financial approach and proactively employ strategies to reduce the effects of commodity price volatility.  We also believe that successful oil and natural gas marketing is essential to risk management and profitable operations.  To further this goal, we utilize Riley Natural Gas, or RNG, a wholly-owned subsidiary, to manage the marketing of our oil and natural gas and our use of oil and natural gas commodity derivatives as risk management tools.  This allows us to maintain better control over third party risk in sales and derivative activities.  We use oil and natural gas derivatives contracts primarily to reduce the effects of volatile commodity prices.  We currently have derivative contracts in place on a significant portion of our production; however, pursuant to our derivative policy, all volumes for derivatives contracts are limited to 80% of our future production from producing wells at the time we enter into the derivative contracts, with the exception of put contracts for which volumes are not limited.  As of December 31, 2008, we had oil and natural gas hedges in place covering 52% of our expected oil production and 62% of our expected natural gas production in 2009.  Further, while our derivative instruments are utilized to manage the impact of price volatility of our oil and natural gas production, they do not qualify for use of hedge accounting under the terms of SFAS No. 133, requiring us to recognize changes in the fair value of our derivative positions in earnings each reporting period and, therefore, resulting in the potential for significant earnings volatility.  See Note 1 , Summary of Significant Accounting Polices – Derivative Financial Instruments , to our accompanying consolidated financial statements included in this report.
 
Business Segments

We divide our operating activities into four segments:

 
·
oil and gas sales;
 
·
natural gas marketing activities;
 
·
well operations and pipeline income; and
 
·
oil and gas well drilling operations.

See Note 16 , Business Segments , to our accompanying consolidated financial statements included in this report.

Oil and Gas Sales

Our oil and gas sales segment is our largest business segment based on revenue.  This segment reflects revenues and expenses from production and sale of oil and natural gas.  During 2008, approximately 84.8% of our oil and gas sales revenue was generated by the Rocky Mountain Region, 10.9% by the Appalachian Basin and 4.3% by the Michigan Basin.  As of the end of 2008, our total proved reserves were located as follows: Rocky Mountain Region 82%, Appalachian Basin 15% and Michigan 3%.  The majority of our undeveloped acreage is in the Rocky Mountain Region, where we focused our 2008 drilling activities.  This segment represents approximately 133% of our income before income taxes for the year ended December 31, 2008.

Natural Gas Marketing Activities

   Our natural gas marketing activities segment is comprised of our wholly-owned subsidiary, RNG, through which we purchase, aggregate and resell natural gas produced by us and others.  This allows us to diversify our operations beyond natural gas drilling and production.  Through RNG, we have established relationships with many of the natural gas producers in the Appalachian Basin and we have gained significant expertise in the natural gas end-user market.  We do not take speculative positions on commodity prices, and we employ derivative strategies to manage the financial effects of commodity price volatility.  Our natural gas marketing segment represented approximately 1% of our income before income taxes for the year ended December 31, 2008.

Well Operations and Pipeline Income

   We operate approximately 95.5% of the wells in which we own a   working interest .  With respect to wells in which we own an interest of less than 100%, we charge the other working interest owners, including our drilling partnerships, a competitive fee for operating the well and transporting natural gas.  Our well operations and pipeline income segment represented approximately 2% of our income before income taxes for the year ended December 31, 2008.


Oil and Gas Well Drilling Operations

   Our drilling and development segment reflects results of drilling and development activities conducted for affiliated and non-affiliated parties.  Historically, we have engaged in these activities primarily through sponsoring drilling partnerships, which allowed us to share the risks and costs inherent in drilling and development operations with our investor partners.  Beginning with our third sponsored drilling partnership in 2005, we have drilled partnership wells on a “cost-plus” basis, which means that we bill our investor partners for the actual drilling costs plus a fixed drilling fee.  Prior to our cost-plus drilling arrangements, drilling was conducted on a “footage” basis, where the Company bore the risk of changes in costs.  In addition, we have typically purchased a 20% to 37% working interest in the wells developed through these partnerships.  In September 2006, we raised approximately $90 million through investor subscriptions in one drilling partnership, and in August 2007, we raised approximately $90 million through an additional drilling partnership.

   Our oil and gas well drilling segment represented approximately 3% of our income before income taxes for the year ended December 31, 2008.  In January 2008, we announced that we did not plan to sponsor new drilling partnerships in 2008.  However, a portion of the funds available for drilling from the 2007 partnership were advanced and unexpended at the end of 2007.   The majority of these funds were used in 2008 for drilling and completion activities, a portion of which was recognized as income in 2008.  The funds remaining as of December 31, 2008, will be used for completion activities to be conducted in 2009.  Currently, we do not plan to sponsor a drilling partnership in 2009 and anticipate that our oil and gas well drilling segment’s contribution to operating income will decline significantly in 2009.

Areas of Operations

    We focus our exploration, development and production efforts in three primary geographic regions:

 
·
Rocky Mountain Region;
 
·
Appalachian Basin; and
 
·
Michigan Basin.

   During 2008, we generated approximately 85.6% of our production from Rocky Mountain Region wells, 10.2% of our production from Appalachian Basin wells and 4.2% of our production from Michigan Basin wells.  The majority of our undeveloped acreage is in the Rocky Mountain Region and our current drilling plans continue to be focused predominantly in this area.

   Rocky Mountain Region.   In 1999, we began operations in the Rocky Mountain Region.  Our Rocky Mountain Region is divided into four operating areas: (1) Grand Valley Field, (2) Wattenberg Field, (3) NECO area and (4) North Dakota area.  Our Rocky Mountain Region includes approximately 320,000 gross acres of leasehold and 2,408 gross, 1,542 net, oil and natural gas wells in which we own an interest.  The general details of each area within the region are further outlined below:

 
·
Grand Valley Field, Piceance Basin, Garfield County, Colorado.   We commenced operations in the area in late 1999 and currently own an interest in 285 gross, 158.3 net, natural gas wells.  Our leasehold position encompasses approximately 7,900 gross acres with approximately 5,200 net undeveloped acres remaining for development as of December 31, 2008.  We drilled 62 gross, 54.4 net, wells in the area in 2008 and produced approximately 12.5 Bcfe net to our interests.  Development wells drilled in the area range from 7,000 to 9,500 feet in depth and the majority of wells are drilled directionally from multi-well pads ranging from two to eight or more wells per drilling pad.  The primary target in the area is gas reserves, developed from multiple sandstone reservoirs in the Mesaverde Williams Fork formation.  Well spacing is approximately ten acres per well.

 
·
Wattenberg Field, DJ Basin, Weld and Adams Counties, Colorado .  We commenced operations in the area in late 1999 and currently own an interest in 1,390 gross, 875.2 net, oil and natural gas wells.  Our leasehold position encompasses approximately 75,900 gross acres with approximately 24,000 net undeveloped acres remaining for development as of December 31, 2008.  We drilled 149 gross, 122.7 net, wells in the area in 2008 and produced approximately 15.4 Bcfe net to our interests.  Wells drilled in the area range from approximately 7,000 to 8,000 feet in depth and generally target oil and gas reserves in the Niobrara, Codell and J Sand reservoirs.  Well spacing ranges from 20 to 40 acres per well.  Operations in the area, in addition to the drilling of new development wells, include the refrac of Codell and Niobrara reservoirs in existing wellbores whereby the Codell sandstone reservoir is fraced a second time and/or initial   completion attempts are made in the slightly shallower Niobrara carbonate reservoir.


 
·
NECO area. DJ Basin, Yuma County Colorado and Cheyenne County, Kansas .  We commenced operations in the area in 2003 and currently own an interest in 717 gross, 504 net, natural gas wells.  Our leasehold position encompasses approximately 141,600 gross acres with approximately 93,200 net undeveloped acres remaining for development as of December 31, 2008.  We drilled 98 gross, 88.1 net, wells in the area in 2008 and produced approximately 5 Bcfe net to our interests.  Wells drilled in the area range from approximately 1,500 to 3,000 feet in depth and target gas reserves in the shallow Niobrara reservoir.  Well spacing is approximately 40 acres per well.  New drilling operations range from exploratory wells to test undrilled, seismically defined, structural features at the Niobrara horizon to development wells targeting known reserves in existing identified features.

 
·
North Dakota, Burke County .  We commenced operations in the area in 2006 and currently own an interest in 13 gross, 3.7 net, oil and natural gas wells.  We divested the majority of our Bakken project acreage in late 2007 (See Note 13 , Sale of Oil and Gas Properties , to our accompanying consolidated financial statements included in this report).  Our remaining leasehold encompasses two project areas in Burke County and encompasses approximately 75,100 gross acres with approximately 46,300 net undeveloped acres remaining for development as of December 31, 2008.  The eastern area acreage is prospective for development of oil and gas reserves in the Nesson Formation.  Nesson development wells are approximately 6,000 feet in depth with single or multiple horizontal legs to 4,000 feet or more in length for a measured length of 10,000 feet or more per leg.  The westernmost acreage block is undeveloped and includes approximately 23,600 gross, 16,200 net acres.  The western project targets exploratory horizontal drilling to the Midale/Nesson Formation at depths of approximately 6,800 feet with a lateral leg component of up to 6,100 feet.  In 2009, we plan to drill up to four exploratory wells on our acreage with funding from an unrelated third party in exchange for an interest in our acreage position.

   Appalachian Basin.   We have conducted operations in the Appalachian Basin since 1969.  Our leasehold position encompasses approximately 140,300 gross acres with approximately 19,400 net undeveloped acres remaining for development as of December 31, 2008.  We own an interest in approximately 2,090 gross, 1,566.5 net, oil and natural gas wells in West Virginia, Pennsylvania and Tennessee.  We drilled 63 gross/net wells in the area in 2008   and produced approximately 3.9 Bcfe net to our interests.  The majority of our Appalachian leasehold is developed on approximately 40 acre spacing.  Wells located in this area are approximately 4,500 feet deep and target predominantly gas reserves in Devonian and Mississippian aged tight sandstone reservoirs.   We are currently evaluating the potential of the Marcellus Formation in West Virginia and Pennsylvania and have drilled three tests to date in West Virginia, two of which are in line.

   Michigan Basin .   We began operations in the Michigan Basin in 1997 with the bulk of drilling activity occurring prior to 2002.  We own an interest in approximately 210 gross, 146.5 net, oil and natural gas wells that produced 1.6 Bcfe net to our interest in 2008.  Wells in the area range from 1,000 to 2,500 feet in depth and produce gas from the Antrim Shale.  We drilled 2 gross, 1.6 net, exploratory wells in 2008.

   Fort Worth Basin .  In addition to those operating areas above, we have an interest in approximately 12,500 gross, 9,100 net undeveloped acres, in Fort Worth Basin, northeastern Erath County, Texas.  The leasehold acreage is prospective for the development of oil and natural gas reserves in the Barnett Shale formation at depths of approximately 5,000 feet.  Development is typically with a horizontal component of approximately 3,000 feet or more, resulting in an approximate measured length of up to 8,000 feet or more in this area.  In 2008, we commenced drilling operations and drilled three exploratory Barnett wells.  These wells generated less than 1% of our 2008 production.  Based on these results, we recorded impairments of both proved and unproved properties in this area in 2008.  We are currently evaluating our future plans in this area and currently have no drilling activity planned in 2009.


   The table below sets forth our productive wells by operating area at December 31, 2008.
 
   
Productive Wells
 
   
Gas
   
Oil
   
Total
 
Location
 
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
Appalachian Basin
    2,051       1,551.0       39       15.4       2,090       1,566.4  
Michigan Basin
    203       143.8       7       2.7       210       146.5  
Rocky Mountain Region
                                               
Wattenberg
    1,365       856.0       25       19.3       1,390       875.3  
Grand Valley
    285       158.3       -       -       285       158.3  
NECO Area
    717       504.0       -       -       717       504.0  
North Dakota
    4       0.4       9       3.3       13       3.7  
Wyoming
    -       -       3       0.7       3       0.7  
Total Rocky Mountain Region
    2,371       1,518.7       37       23.3       2,408       1,542.0  
Fort Worth Basin
    4       4.0       -       -       4       4.0  
Total Productive Wells
    4,629       3,217.5       83       41.4       4,712       3,258.9  

Operations

Prospect Generation

   Our staff of professional geologists is responsible for identifying areas with potential for economic production of natural gas and oil.  They utilize results from logs, seismic data and other tools to evaluate existing wells and to predict the location of economically attractive new natural gas and oil reserves.  To further this process, we have collected and continue 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 for prospective economic development.

   On the basis of these models, our land department obtains available natural gas and oil leaseholds, farmouts and other development rights in these prospective areas.  In most cases, to secure a lease, we pay a lease bonus and annual rental payments, converting, upon initiation of production, to a royalty .  In addition, overriding royalty payments may be granted to third parties in conjunction with the acquisition of drilling rights initially leased by others.  As of December 31, 2008, we had leasehold rights to approximately 224,800 acres available for development.

Drilling Activities

   The following table summarizes our development and exploratory drilling activity for the last three years.  There is no correlation between the number of productive wells completed during any period and the aggregate reserves attributable to those wells.  Productive wells consist of producing wells and wells capable of commercial production.
 
   
Drilling Activity
 
   
2008
   
2007
   
2006
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
                                     
Development
                                   
Productive (1)
    349       303.8       327       258.9       216       129.8  
Dry
    8       8.0       11       9.7       6       4.6  
Total development
    357       311.8       338       268.6       222       134.4  
                                                 
Exploratory
                                               
Productive (1)
    7       7.0       1       0.2       8       2.8  
Dry
    10       9.6       7       4.5       1       0.5  
Pending determination
    5       5.0       3       3.0       -       -  
Total exploratory
    22       21.6       11       7.7       9       3.3  
Total Drilling Activity
    379       333.4       349       276.3       231       137.7  
 
______________
(1) As of December 31, 2008, 94 of the 356 productive wells were awaiting gas pipeline connection, of which 38 were connected and turned in line by February 13, 2009.


   The following table sets forth the wells we drilled by operating area during the periods indicated.


   
2008
   
2007
   
2006
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
 Appalachian Basin
    63       63.0       8       8.0       -       -  
 Michigan Basin
    2       1.6       3       3.0       1       1.0  
 Rocky Mountain Region
    311       265.8       337       264.3       230       136.7  
 Fort Worth Basin
    3       3.0       1       1.0       -       -  
 Total
    379       333.4       349       276.3       231       137.7  


   We plan to drill approximately 166 gross wells, excluding exploratory wells, in 2009:  12 in the Appalachian Basin and 154 in the Rocky Mountain Region.

   Much of the work associated with drilling, completing and connecting wells, including drilling, fracturing, logging and pipeline construction is performed under our direction by subcontractors specializing in those operations, as is common in the industry.  When judged advantageous, material and services we use in the development process are acquired through competitive bidding by approved vendors.  We also directly negotiate rates and costs for services and supplies when conditions indicate that such an approach is warranted.

Financing of Company Drilling and Development Activities

We conduct development drilling activities for our own account and act as  operator for other oil and gas owners.  When conducting activities for our own account, we have historically funded our operations through our cash flows from operations, capital provided from our long term credit facility and, in 2008, from our senior notes issuance.  In the future, we expect to continue to use these same sources, but may also use other sources of funding, including, but not limited to, asset sales, volumetric production payments, debt securities, convertible debt securities and equity offerings.
 
Drilling and Development Activities Conducted for Company Sponsored Partnerships
  
We began sponsoring drilling partnerships in 1984, and had sponsored one or more every year through 2007.  For many years, our drilling partners were primarily the public and private partnerships we sponsored.  At closing, we contribute a cash investment to purchase an interest in the drilling and development activities of the partnership and then serve as the managing general partner.  As wells produce for a number of years, we continue to serve as operator for 33 partnerships, as well as for other unaffiliated parties.

  When developing wells for our partnerships or others, we enter into a development agreement with the investor partner, pursuant to which we agree to sell some or all of our rights in a well to be drilled to the partnership or other entity.  The partnership or other entity thereby becomes owner of a working interest in the well.  In our financial reporting, we report only our proportionate share of oil and gas reserves, production, oil and gas sales and costs associated with wells in which other investors participate.

   In January 2008, we announced that we did not plan to sponsor new drilling partnerships in 2008 in order to focus our effort on continuing our growth through drilling and exploration.  Currently, we have no plans to sponsor a partnership in 2009.

Purchases of Producing Properties

   In addition to drilling new wells, we continue to pursue opportunities to purchase existing wells and development rights from other owners, as well as greater ownership interests in the wells we operate.  Generally, outside interests purchased include a majority interest in the wells and the right to operate the wells.  In January 2007, we completed the purchase from an unrelated party of approximately 144 oil and gas wells and 8,160 acres of leaseholds in the Wattenberg Field.  Also in January 2007, we purchased the outside partnership interests in 44 partnerships which we sponsored and formed primarily in the late 1980s and 1990s.  These interests constituted the majority of the interests in 718 wells, primarily in the Appalachian and Michigan Basins.  In February 2007, we acquired from an unrelated party 28 producing wells and associated undeveloped acreage in Colorado.  In October 2007, we purchased from unrelated parties a majority working interest of 762 natural gas wells located in southwestern Pennsylvania.  The purchase also included associated pipelines, equipment, real estate and undeveloped acreage.  No significant acquisitions were made in 2008.


  Production, Sales, Prices and Lifting Costs

  The following table sets forth information regarding our production volumes, oil and natural gas sales, average sales price received and average lifting cost incurred for the periods indicated.

   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
Production (1)
                 
Oil (Bbls)
    1,160,408       910,052       631,395  
Natural gas (Mcf)
    31,759,792       22,513,306       13,160,784  
Natural gas equivalent (Mcfe) (2)
    38,722,240       27,973,618       16,949,154  
Oil and Gas Sales (in thousands)
                       
Oil sales
  $ 104,168     $ 55,196     $ 37,460  
Gas sales
    221,734       119,991       77,729  
Royalty litigation provision
     (4,025 )       -        -  
Total oil and gas sales
  $ 321,877     $ 175,187     $ 115,189  
                         
Realized Gain (Loss) on Derivatives, net (in thousands)
                       
Oil derivatives - realized loss
  $ (3,145 )   $ (177 )   $ -  
Natural gas derivatives - realized gain
    12,632       7,350       1,895  
Total realized gain on derivatives, net
  $ 9,487     $ 7,173     $ 1,895  
 Average Sales Price
                       
Oil (per Bbl) (3)
  $ 89.77     $ 60.65     $ 59.33  
Natural gas (per Mcf) (3)
  $ 6.98     $ 5.33     $ 5.91  
Natural gas equivalent (per Mcfe)
  $ 8.42     $ 6.26     $ 6.80  
 Average Sales Price (including realized gain (loss) on derivatives)
                       
Oil (per Bbl)
  $ 87.06     $ 60.46     $ 59.33  
Natural gas (per Mcf)
  $ 7.38     $ 5.66     $ 6.05  
Natural gas equivalent (per Mcfe)
  $ 8.66     $ 6.52     $ 6.91  
                         
Average Production Cost (Lifting Cost) per Mcfe (4)
  $ 1.07     $ 0.90     $ 0.76  
 
_____________
 
(1)
Production is net and determined by multiplying the gross production volume of properties in which we have an interest by the percentage of the leasehold or other property interest we own.
 
(2)
A ratio of energy content of natural gas and oil (six Mcf of natural gas equals one Bbl   of oil) was used to obtain a conversion factor to convert oil production into equivalent Mcf of natural gas.
 
(3)
We utilize commodity based derivative instruments to manage a portion of our exposure to price volatility of our natural gas and oil sales.  This amount excludes realized and unrealized gains and losses on commodity based derivative instruments.
 
(4)
Production costs represent oil and natural gas operating expenses which exclude production taxes.

Oil and Natural Gas Reserves

  All of our natural gas and oil reserves are located in the U.S.  We utilized the services of independent petroleum engineers to estimate our oil and gas reserves.  For the years ended December 31, 2008 and 2007, our reserve estimates for the Appalachian and Michigan Basins are based on reserve reports prepared by Wright & Company and for the Rocky Mountain Region, reserve estimates are based on reserve reports prepared by Ryder Scott Company, L.P.  For the year ended December 31, 2006, our reserve estimates for the Appalachian and Michigan Basins and NECO Area were based on reserve reports prepared by Wright & Company and our reserve estimates for the Rocky Mountain Region, with the exception of the NECO properties, were based on reserve reports prepared by Ryder Scott.  The independent engineers' estimates are made using available geological and reservoir data as well as production performance data.  The estimates are prepared with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X, Rule 4-10(a) and subsequent SEC staff interpretations and guidance.  When preparing our reserve estimates, the independent engineers did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and natural gas production, well test data, historical costs of operations and developments, product prices, or any agreements relating to current and future operations of properties and sales of production.  Our independent reserve estimates are reviewed and approved by our internal engineering staff and management.


   The tables below set forth information regarding our estimated proved reserves.  Reserves cannot be measured exactly, because reserve estimates involve subjective judgments.  The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes.  Neither the present value of estimated future net cash flows nor the standardized measure is intended to represent the current market value of the estimated oil and natural gas reserves we own.

   
Proved Reserves as of December 31,
 
   
2008
   
2007
   
2006
 
Oil ( MBbl )
    15,037       15,338       7,272  
Natural gas ( MMcf )
    662,857       593,563       279,078  
Total proved reserves ( MMcfe )
    753,079       685,591       322,710  
Proved developed reserves (MMcfe)
    329,669       317,884       165,690  
Estimated future net cash flows (in thousands)   (1)
  $  1,056,890     $  1,847,485     $  525,454  
Standardized measure (in thousands)  (1)(2)
  $  356,805     $  753,071     $ 215,662  

______________
 
(1)
Estimated future net cash flow represents the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production costs, future development costs and income tax expense, using prices and costs in effect at December 31for each respective year.  For the weighted average wellhead prices used in our reserve reports, see Note 18 , “Supplemental Oil and Gas Information,” of our consolidated financial statements included in this report.  These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of our commodity hedges in place at December 31for each respective year.  The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses and debt service, or to depreciation, depletion and amortization.
 
(2)
The standardized measure of discounted future net cash flow   is calculated in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 69, which requires the future cash flows to be discounted.  The discount rate used was 10%.  Additional information on this measure, including a description of changes in this measure from year to year, is presented in Note 18 , “Supplemental Oil and Gas Information,” of our consolidated financial statements included in this report.

 
   
Proved Reserves as of
 
   
December 31, 2008
 
   
Oil
(MBbl)
   
Gas
(MMcf)
   
Gas
Equivalent
(MMcfe)
   
Percent
 
Proved developed
                       
Appalachian Basin
    29       73,447       73,621       22 %
Michigan Basin
    40       19,784       20,024       6 %
Rocky Mountain Region
                               
Wattenberg
    5,079       50,005       80,479       25 %
Grand Valley
    173       111,310       112,348       34 %
NECO
    -       42,042       42,042       13 %
North Dakota
    105       114       744       0 %
Wyoming
    8       -       48       0 %
Total Rocky Mountain Region
    5,365       203,471       235,661       72 %
 Fort Worth Basin
    4       339       363       0 %
Total proved developed
    5,438       297,041       329,669       100 %
Proved undeveloped
                               
Appalachian
    -       39,380       39,380       9 %
Rocky Mountain Region
                               
Wattenberg
    9,340       62,284       118,324       28 %
Grand Valley
    259       258,824       260,378       62 %
NECO
    -       5,328       5,328       1 %
Total Rocky Mountain Region
    9,599       326,436       384,030       91 %
Total proved undeveloped
    9,599       365,816       423,410       100 %
Proved reserves
                               
Appalachian
    29       112,827       113,001       15 %
Michigan
    40       19,784       20,024       3 %
Rocky Mountain Region
                               
Wattenberg
    14,419       112,289       198,803       27 %
Grand Valley
    432       370,134       372,726       49 %
NECO
    -       47,370       47,370       6 %
North Dakota
    105       114       744       0 %
Wyoming
    8       -       48       0 %
Total Rocky Mountain Region
    14,964       529,907       619,691       82 %
Fort Worth Basin
    4       339       363       0 %
Total proved reserves
    15,037       662,857       753,079       100 %


Acreage

   The following table sets forth by operating area leased acres as of December 31, 2008.

   
Developed
   
Undeveloped
   
Total
 
Location
 
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
                                     
Appalachian Basin
    117,800       113,000       22,500       19,400       140,300       132,400  
Michigan Basin
    16,800       14,800       10,000       8,400       26,800       23,200  
Rocky Mountain Region
                                               
Wattenberg
    45,800       43,400       30,100       24,000       75,900       67,400  
Grand Valley
    2,700       2,700       5,200       5,200       7,900       7,900  
NECO
    23,200       19,300       118,400       93,200       141,600       112,500  
North Dakota
    8,300       4,800       66,800       46,300       75,100       51,100  
Wyoming
    300       100       19,200       19,200       19,500       19,300  
Total Rocky Mountain Region
    80,300       70,300       239,700       187,900       320,000       258,200  
Fort Worth Basin
    400       400       12,100       9,100       12,500       9,500  
Total Acreage
    215,300       198,500       284,300       224,800       499,600       423,300  


Title to Properties

We believe that we hold good and defensible title to our developed properties, in accordance with standards generally accepted in the oil and natural gas industry.  As is customary in the industry, a preliminary title examination is conducted at the time the undeveloped properties are acquired.  Prior to the commencement of drilling operations, a title examination is conducted and curative work is performed with respect to discovered defects which we deem to be significant.  Title examinations have been performed with respect to substantially all of our producing properties.  Two properties in our Grand Valley Field represent 49% of our total proved reserves.

The properties we own are subject to royalty, overriding royalty and other outstanding interests customary to the industry.  The properties may also be subject to additional burdens, liens or encumbrances customary to the industry, including items such as operating agreements, current taxes, development obligations under natural gas and oil leases, farm-out agreements and other restrictions.  We do not believe that any of these burdens will materially interfere with the use of the properties.

Natural Gas Sales

We generally sell the natural gas that we produce under contracts with indexed monthly pricing provisions.  Virtually all of our contracts include provisions wherein prices change monthly with changes in the market, for which certain adjustments may be made based on 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, our revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase.  We believe that the pricing provisions of our natural gas contracts are customary in the industry.  We also enter into financial derivatives such as puts, collars and swaps in order to reduce the impact of possible price instability regarding the physical sales market.  See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation: Results of Operations - Oil and Gas Price Risk Management, Net, Oil and Gas Derivative Activities and Note 3, Derivative Financial Instruments , to our consolidated financial statements included in this report.

 We sell our natural gas to other gas marketers, utilities, industrial end-users and other wholesale gas purchasers.  During 2008, the natural gas we produced was sold at prices ranging from $2.77 to $13.85 per Mcf, depending upon well location, the date of the sales contract and other factors.  Our weighted net average price of natural gas sold in 2008 was $6.98 per Mcf.

In general, we have been and expect to continue to be able to produce and sell natural gas from our wells without significant curtailment and at competitive prices.  We do experience limited curtailments from time to time due to pipeline maintenance and operating issues.  For instance, we experienced an approximate 10% to 15% curtailment of production volumes, approximately 10,000 Mcf per day, in the Piceance Basin due to limited compression and pipeline capacity throughout most of the fourth quarter in 2008.  This interruption, due to third party infrastructure, was corrected in early 2009.  Open access transportation through the country's interstate pipeline system gives us access to a broad range of markets.  Whenever feasible, we obtain access to multiple pipelines and markets from each of our gathering systems seeking the best available market for our natural gas at any point in time.

Oil Sales

The majority of our wells in the Wattenberg Field in Colorado and our wells in North Dakota produce oil in addition to natural gas.  As of December 31, 2008, oil represented 12% of our total equivalent reserves and accounted for approximately 32% of our oil and gas sales revenue for the year ended December 31, 2008.

We are currently able to sell all the oil that we can produce under existing sales contracts with petroleum refiners and marketers.  We do not refine any of our oil production.  Our crude oil production is sold to purchasers at or near our wells under both short and long-term purchase contracts with monthly pricing provisions.  During 2008, oil we produced sold at prices ranging from $19.82 to $132.38 per Bbl, depending upon the location and quality of oil.  Our weighted net average price per Bbl of oil sold in 2008 was $89.77.

Natural Gas Marketing

Our natural gas marketing activities involve the purchase of natural gas from other producers and the sale of that natural gas along with the natural gas we produce for our own interest and that of our affiliated partnerships.  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 specializes in the purchase, aggregation and sale of natural gas production in our Eastern operating areas.  RNG markets the natural gas we produce and also purchases natural gas in the Appalachian Basin from other producers and resells it to other marketers, utilities or end users.  RNG's employees have extensive knowledge of natural gas markets in our areas of operations.  Such knowledge assists us in maximizing our prices as we market natural gas from PDC-operated wells.  The gas is marketed to other marketers, natural gas utilities, as well as industrial and commercial customers, either directly through our gathering system, or through transportation services provided by regulated interstate pipeline companies.
 
We have entered into various sales, transportation and processing agreements with unrelated third parties which we sell to or who transports our natural gas.  The following table sets forth information about long-term firm sales, processing and transportation agreements for pipeline capacity, which require a demand charge whether volumes are delivered or not.
 
Type of Arrangement
 
Location
 
Average
Annual
Volume
(MMbtu)
 
Expiration
Date
             
Firm sales and processing
 
Grand Valley
 
            23,218,287
 
May 2016
Firm transportation
 
NECO Area
 
              1,825,000
 
December 2010
Firm transportation
 
NECO Area
 
              1,825,000
 
December 2016
Firm transportation (1)
 
Appalachian Basin
 
            12,230,785
 
December 2022
(1) Contract is a precedent agreement and becomes effective when the planned pipeline is placed in service, estimated at this time to be 2012.  Contract is null and void if pipeline is not completed.
 
Commodity Risk Management Activities

We utilize commodity based derivative instruments to manage a portion of our exposure to price volatility with regard to our oil and natural gas sales and marketing activities.  These instruments consist of NYMEX -traded natural gas over-the-counter swaps, futures and option contracts for Appalachian and Michigan production, CIG   and PEPL - based contracts for Colorado natural gas production and NYMEX-traded over-the-counter oil swaps and option contracts for Colorado oil production.  We may utilize derivatives based on other indices or markets where appropriate.  The contracts economically provide price stability for committed and anticipated oil and natural gas purchases and sales, generally forecasted to occur within the next two to three-year period, but no longer than five years beyond the derivative transaction date.  Our policies prohibit the use of oil and natural gas futures, swaps or options for speculative purposes and permit utilization of derivatives only if there is an underlying physical position.

RNG has extensive experience with the use of derivatives to reduce the risk and effect of natural gas price changes.  RNG uses these financial derivatives to coordinate fixed purchases and sales.  We use financial derivatives to establish “floors” and “ceilings” or “collars” on the possible range of the prices realized for the sale of natural gas and oil in addition to fixing prices by using swaps.  RNG also enters into back-to-back fixed-price purchases and sales contracts with counterparties.  These fixed physical contracts meet the SFAS No. 133, Accounting for Derivative Instruments and Certain Hedging Activities , 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 statement of operations.

We are subject to price fluctuations for natural gas sold in the spot market and under market index contracts.  RNG does not always hedge the area basis risk for third party trades with back-to-back fixed price purchases and sales.  We continue to evaluate the potential for reducing these risks by entering into derivative transactions.  In addition, we may 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.  We manage price risk on only a portion of our anticipated production, so the remaining portion of our production is subject to the full fluctuation of market pricing.

Well Operations

As of December 31, 2008, we had an interest in approximately 2,412 wells in the Rocky Mountain Region, 2,090 wells in the Appalachian Basin, and 210 wells in the Michigan Basin.  On average, our interest ownership in these wells was approximately 69.2%.

We are paid a monthly operating fee for the portion of each well we operate that is owned by others, including our sponsored partnerships.  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.  If we purchase well interests belonging to investors in our sponsored partnerships, we then account for the purchased interests as being owned by us, which results in a decrease in well operations income.

Transportation and Gathering

We develop, own and operate gathering systems in some of our areas of operations.  We also continue 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 our existing systems.  Pipelines and related facilities can represent a significant portion of the capital costs of developing wells, particularly in new areas located at a distance from existing pipelines.  We consider these costs in our evaluation of our leasing, development and acquisition opportunities.


Our natural gas and oil are transported through our own and third party gathering systems and pipelines, and we incur processing, gathering and transportation expenses to move our natural gas from the wellhead to a purchaser-specified delivery point.  These expenses vary based on the volume and distance shipped, and the fee charged by the third-party processor or transporter.  Capacity on these gathering systems and pipelines is occasionally limited and at times unavailable because of repairs or improvements, or as a result of priority transportation agreements with other gas transporters.  While our ability to market our natural gas has been only infrequently limited or delayed, if transportation space is restricted or is unavailable, our cash flow from the affected properties could be adversely affected.  In certain instances, we enter into firm transportation agreements to provide for pipeline capacity to flow and sell a portion of our gas volumes.  In order to meet pipeline specifications, we are required, in some cases, to process our gas before we can transport it.  We typically contract with third parties in the Grand Valley and NECO areas of our Rocky Mountain Region and Appalachian Basin for firm transportation of our natural gas.  We also may enter into firm sales agreements to ensure that we are selling to a purchaser who has contracted for pipeline capacity.  These agreements are subject to the same limitations discussed above in this paragraph.

Governmental Regulation

While the prices of oil and natural gas are set by the market, other aspects of our business and the oil and natural gas industry in general are heavily regulated.  The availability of a ready market for oil and natural gas production depends on several factors beyond our control.  These factors include regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of oil and 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 and oppressive control, to reduce the risk to the public and workers from the drilling, completion, production and transportation of oil and natural gas, to prevent waste of oil and natural gas, to protect rights among owners in a common reservoir and to control contamination of the environment.  Pipelines are subject to the jurisdiction of various federal, state and local agencies.  In the western part of the U.S., the federal and state governments own a large percentage of the land and the rights to develop oil and natural gas.  Generally, government leases are subject to additional regulations and controls not commonly seen on private leases.  We take the steps necessary to comply with applicable regulations, both on our own behalf and as part of the services we provide to our drilling partnerships.  We believe that we are 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 summary discussion of the regulation of the U.S. oil and natural gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which our operations may be subject.

Regulation of Oil and Natural Gas Exploration and Production

Our exploration and production business is subject to various federal, state and local laws and regulations on the taxation of oil and natural gas, the development, production and marketing of oil and natural gas and environmental and safety matters.  Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, water discharge, prevention of waste and other matters.  Prior to commencing drilling activities for a well, we 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.  The permits and approvals include those for the drilling of wells.  Additionally, other regulated matters include:

 
·
bond requirements in order to drill or operate wells;
 
·
the location of wells;
 
·
the method of drilling and casing wells;
 
·
the surface use and restoration of well properties;
 
·
the plugging and abandoning of wells; and
 
·
the disposal of fluids.

Our 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, 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 we can produce from our wells and may limit the number of wells or the locations at which we can drill.  Such laws and regulations may increase the costs of planning, designing, drilling, installing, operating and abandoning our oil and natural gas wells and other facilities.  In addition, these laws and regulations, and any others that are passed by the jurisdictions where we have production, could limit the total number of wells drilled or the allowable production from successful wells, which could limit our reserves.  As a result, we are unable to predict the future cost or effect of complying with such regulations.


Regulation of Sales and Transportation of Natural Gas

Historically, the price of natural gas was subject to limitation by federal legislation.  The Natural Gas Wellhead 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.  The Federal Energy Regulatory Commission's, or FERC, jurisdiction over natural gas transportation was unaffected by the Decontrol Act.

We move natural gas through pipelines owned by other companies, and sell natural gas to other companies that also utilize common carrier pipeline facilities.  Natural gas pipeline interstate transmission and storage activities are subject to regulation by the FERC under the Natural Gas Act of 1938, or NGA, and under the Natural Gas Policy Act of 1978, and, as such, rates and charges for the transportation of natural gas in interstate commerce, accounting, and the extension, enlargement or abandonment of its jurisdictional facilities, among other things, are subject to regulation.  Each natural gas pipeline company holds certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of all pipelines, facilities and properties for which certificates are required under the NGA.  Each natural gas pipeline company is also subject to the Natural Gas Pipeline Safety Act of 1968, as amended, which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities.  FERC regulations govern how interstate pipelines communicate and do business with their affiliates.  Interstate pipelines may not operate their pipeline systems to preferentially benefit their marketing affiliates.

Each interstate natural gas pipeline company establishes its rates primarily through the FERC’s ratemaking process.  Key determinants in the ratemaking process are:

 
•
costs of providing service, including depreciation expense;
 
•
allowed rate of return, including the equity component of the capital structure and related income taxes; and
 
•
volume throughput assumptions.

The availability, terms and cost of transportation affect our natural gas sales.  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 greater access to transportation 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.  Historically, producers were able to flow supplies into interstate pipelines on an interruptible basis; however, recently we have seen the increased need to acquire firm transportation on pipelines in order to avoid curtailments or shut-in-gas, which could adversely affect cash flows from the affected area.

Additional proposals and proceedings that might affect the natural gas industry occur frequently in 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.  We cannot determine to what extent our future operations and earnings will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels.

Environmental Regulations

Our 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 tougher 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, our business and prospects could be adversely affected.

We generate wastes that may be subject to the Federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes.  The U.S. Environmental Protection Agency, or EPA, and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous wastes.  Furthermore, certain wastes generated by our 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.


 We currently own or lease numerous properties that for many years have been used for the exploration and production of oil and natural gas.  Although we believe that we have utilized good operating and waste disposal practices, and when necessary, appropriate remediation techniques, prior owners and operators of these properties may not have utilized similar practices and techniques, and hydrocarbons or other wastes may have been disposed of or released on or under the properties that we own or lease 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, or CERCLA, RCRA and analogous state laws, as well as state laws governing the management of oil and natural gas wastes.  Under such laws, we 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 full 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.  As an owner and operator of oil and natural gas wells, we may be liable pursuant to CERCLA and similar state laws.

Our operations may be subject to the Clean Air Act, or 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 our operations.  The EPA and states have been developing regulations to implement these requirements.  We 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 State of Colorado has also indicated it intends to implement new air regulations in 2009, which affect the oil and gas industry, including our operations, related to air emissions.

The Federal Clean Water Act, or CWA, and analogous state laws impose strict controls against the discharge of pollutants, including spills and leaks of oil and other substances.  The CWA also regulates storm water run-off from oil and gas facilities and requires a storm water discharge permit for certain activities.  Spill prevention, control, and countermeasure requirements of the CWA require appropriate containment terms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak.

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, including us, to procure and implement Spill Prevention, Control and Counter-measures plans relating to the possible discharge of oil into surface waters.  The Oil Pollution Act of 1990, or 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.  We are also subject to the CWA 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.  Historically, we have not experienced any significant oil discharge or oil spill problems.

In December 2008, the State of Colorado’s Oil and Gas Conservation Commission finalized new broad-based environmental regulations for the oil and natural gas industry.  These regulations will increase our costs and may ultimately limit some drilling locations.  Our expenses relating to preserving the environment have risen over the past few years and are expected to continue to rise in 2009 and beyond.  Environmental regulations have had no materially adverse effect on our operations to date, but no assurance can be given that environmental regulations or interpretations of such regulations will not, in the future, result in a curtailment of production or otherwise have a materially adverse effect on our business, financial condition or results of operations.  See Note 8 , Commitments and Contingencies – Litigation, Colorado Stormwater Permit , to our accompanying consolidated financial statements included in this report.

Operating Hazards and Insurance

Our exploration and production operations include a variety of operating risks, including, but not limited to, 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 these could result in substantial losses to us 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.  Our 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, damage to property 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 our facilities could adversely affect our ability to conduct our operations.  In accordance with customary industry practice, we maintain 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 our operations and financial condition.  We cannot predict whether insurance will continue to be available at premium levels that justify our purchase or whether insurance will be available at all.  Furthermore, we are not insured against our economic losses resulting from damage or destruction to third party property, such as the Rockies Express pipeline; such an event could result in significantly lower regional prices or our inability to deliver gas.

Competition

We believe that our exploration, drilling and production capabilities and the experience of our management and professional staff generally enable us to compete effectively.  We encounter competition from numerous other oil and natural gas companies, drilling and income programs and partnerships in all areas of operations, including drilling and marketing oil and natural gas and obtaining desirable oil and natural gas leases on producing properties.  Many of these competitors possess larger staffs and greater financial resources than we do, which may enable them to identify and acquire desirable producing properties and drilling prospects more economically.  Our ability to explore for oil and natural gas prospects and to acquire additional properties in the future depends upon our ability to conduct our operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.  We also face 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 2008, our industry experienced continued strong demand for drilling services and supplies which resulted in increasing costs.  In 2009, due to industry slowdown, we are experiencing overall reductions in our operating and drilling costs.  Factors affecting competition in the oil and natural gas industry include price, location of drilling, availability of drilling prospects and drilling rigs, pipeline capacity, quality of production and volumes produced.  We believe that we can compete effectively in the oil and natural gas industry in each of the listed areas.  Nevertheless, our business, financial condition and results of operations could be materially adversely affected by competition.  We also compete with other oil and gas companies as well as companies in other industries for the capital we need to conduct our operations.  Recently, turmoil in the capital markets has made financing more expensive and difficult to obtain.  In the event that we do not have adequate capital to execute our business plan, we may be forced to curtail our drilling and acquisition activities.

Employees

As of December 31, 2008, we had 317 employees, including 205 in production, 8 in natural gas marketing, 28 in exploration and development, 49 in finance, accounting and data processing, and 27 in administration.  Our engineers, supervisors and well tenders are responsible for the day-to-day operation of wells and some pipeline systems.  In addition, we retain subcontractors to perform drilling, fracturing, logging, and pipeline construction functions at drilling sites, with our employees supervising the activities of the subcontractors.  In 2008, the total number of Company employees increased by 61.

Our employees are not covered by a collective bargaining agreement.  We consider relations with our employees to be very good.

ITEM 1A.  RISK FACTORS

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.


Risks Related to the Global Economic Environment

The current global economic environment may increase the magnitude and the likelihood of the occurrence of the negative consequences discussed in many of the risks factors that follow.

In particular, consider the risks related to (1) the rapid deterioration of demand for oil and natural gas resulting from the economic environment and the related negative effects on oil and gas pricing, and (2) the effect of the credit constraints on our business, including the severe reduction in the availability of credit for drilling or to finance acquisitions.  Also consider the interplay between these two risks: decline in oil and gas prices can lead to a reduction in the borrowing base for our credit line, and hence a reduction in our credit available for drilling.  Similarly, further reductions in oil and gas prices could result in some of our assets becoming uneconomic to exploit, which would reduce our reserves, which in turn would reduce our borrowing base and the credit available to us.  These factors could result in less drilling and production by us, and could thereby adversely affect our profitability and could limit our ability to execute our business plan.  These factors could also make it impossible or extremely expensive to extend the term of our revolving credit line.  The global economic environment also increases the counterparty failure risk for both the banks which are parties to our oil and gas derivative holdings and for payments from purchasers of our oil and gas.  Lastly, inability to ascertain the ultimate depth and duration of the economic environment could cause us to refrain from capital expenditures in order to maintain higher liquidity; our uncertainty and caution could result in significantly reduced drilling and hence reduced future production.  All these risks could have a significant adverse effect on our business and our financial results.  Any additional deterioration in the domestic or global economic conditions will further amplify these risks.

Recent disruptions in the global financial markets and the related economic environment may further decrease the demand for oil and gas and the prices of oil and gas, thereby limiting our future drilling and production, and thereby adversely affecting our profitability.

During the second half of 2008 and to date, prices for oil and gas decreased over 70%.  The well-publicized global financial market disruptions and the related economic environment may further decrease demand for oil and gas and therefore lower oil and gas prices. If there is such an additional reduction in demand, the continued production of gas may increase current oversupply and result in still lower gas prices.  There is no certainty how long this low price environment will continue.  We operate in a highly competitive industry, and certain competitors may have lower operating costs in such an environment.  Furthermore, as a result of these disruptions in the financial markets, it is possible that in future years we would not be able to borrow sufficient funds to sustain or increase capital expenditures relative to 2008 expenditures, should we wish to make expenditures at those levels.  Such market conditions may also make it more difficult or impossible for us to finance acquisitions, through either equity or debt; acquisitions have historically been a major source of growth for us.  We may also have difficulty finding partners to develop new drilling prospects and to build the pipeline systems needed to transport our gas.  Inability of third parties to finance and build additional pipelines out of the Rockies and elsewhere could cause significant negative pricing effects.  Any of the above factors could adversely affect our operating results.
 
Risks Related to Our Business and the Natural Gas and Oil Industry

Natural gas and oil prices fluctuate unpredictably and a decline in natural gas and oil prices can significantly affect the value of our assets, our financial results and impede our growth.

Our revenue, profitability and cash flow depend in large part upon the prices and demand for natural gas and oil.  The markets for these commodities are very volatile, and even relatively modest drops in prices can significantly affect our financial results and impede our growth.  Changes in natural gas and oil prices have a significant effect on our cash flow and on the value of our reserves, which can in turn reduce our borrowing base under our senior credit agreement.  Prices for natural gas and oil may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control, including national and international economic and political factors and federal and state legislation. The prices from the fourth quarter of 2008 to date have been too low to economically justify many drilling operations, and it is uncertain how long such low pricing shall persist.

The prices of natural gas and oil are volatile, often fluctuating greatly.  Lower natural gas and oil prices may not only reduce our revenues, but also may reduce the amount of natural gas and oil that we can produce economically.  As a result, we may have to make substantial additional downward adjustments to our estimated proved reserves.  If this occurs or if our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write-down operating assets to fair value, as a non-cash charge to earnings.  We assess impairment of capitalized costs of proved natural gas and oil 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 may be sold.  In 2008, we recorded an impairment charge of $7.5 million primarily related to our Texas Barnett Shale wells, and in 2006, we recorded an impairment charge of $1.5 million related to our Nesson field in North Dakota.  There were no impairments during 2007.  We may incur impairment charges in the future, which could have a material adverse effect on the results of our operations.


A substantial part of our natural gas and oil production is located in the Rocky Mountain Region, making it vulnerable to risks associated with operating primarily in a single geographic area.

Our operations have been focused on the Rocky Mountain Region, which means our current producing properties and new drilling opportunities are geographically concentrated in that area.  Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the affect of any regional events, including fluctuations in prices of natural gas and oil produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, curtailment of production or interruption of transportation, and any resulting delays or interruptions of production from existing or planned new wells.

During the last four months of 2008, natural gas prices in the Rocky Mountain Region fell disproportionately when compared to other markets, due in part to continuing constraints in transporting natural gas from producing properties in the region.  Because of the concentration of our operations in the Rocky Mountain Region, and although, in late 2008 we entered into a significant multi-year basis hedge in order to minimize the price risk of our concentration in the Rocky Mountain Region, such price decreases are more likely to have a material adverse effect on our revenue, profitability and cash flow than those of our more geographically diverse competitors.

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

Natural gas and oil reserve engineering requires subjective estimates of underground accumulations of natural gas and oil and assumptions concerning future natural gas and oil prices, production levels, and operating and development costs over the economic life of the properties.  As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate.  Independent petroleum engineers prepare our estimates of natural gas and oil reserves using pricing, production, cost, tax and other information that we provide.  The reserve estimates are based on certain assumptions regarding future natural gas and oil 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 natural gas and oil attributable to any particular group of properties;
 
·
future depreciation, depletion and amortization rates and amounts;
 
·
impairments in the value of our assets;
 
·
the classifications of reserves based on risk of recovery;
 
·
estimates of the future net cash flows; and
 
·
timing of our capital expenditures.
 
Some of our reserve estimates must be made with limited production history, which renders these reserve estimates less reliable than estimates based on a longer 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 natural gas and oil recovered being different from earlier reserve estimates.

The present value of our estimated future net cash flows from proved reserves is not necessarily the same as the current market value of our estimated natural gas and oil reserves (the SEC 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).  However, factors such as actual prices we receive for natural gas and oil and hedging instruments, the amount and timing of actual production, amount and timing of future development costs, supply of and demand for natural gas and oil, and changes in governmental regulations or taxation also affect our actual future net cash flows from our natural gas and oil properties.

The timing of both our production and incurrence of expenses in connection with the development and production of natural gas and oil 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 (the rate required by the SEC) 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 natural gas and oil properties or the natural gas and oil industry in general.


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

Producing natural gas and oil reservoirs generally is 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 estimated and the rate can change due to other circumstances.  Thus, our future natural gas and oil reserves and production and, therefore, our cash flow and income, are highly dependent on efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves.  We may not be able to develop, discover or acquire additional reserves to replace our current and future production at acceptable costs.  As a result, our future operations, financial condition and results of operations would be adversely affected.

Acquisitions are subject to the uncertainties of evaluating recoverable reserves and potential liabilities.

Acquisitions of producing properties and undeveloped properties have been an important part of our historical growth.  We expect acquisitions will also contribute to our future growth.  Successful acquisitions require an assessment of a number of factors, many of which are beyond our control.  These factors include recoverable reserves, development potential, future natural gas and oil prices, operating costs and potential environmental and other liabilities.  Such assessments are inexact and their accuracy is inherently uncertain.  In connection with our assessments, we perform engineering, geological and geophysical reviews of the acquired properties, which we believe is generally consistent with industry practices.  However, such reviews are not likely to permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities.  We do not inspect every well prior to an acquisition and our ability to evaluate undeveloped acreage is inherently imprecise.  Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise.  In some cases, our review prior to signing a definitive purchase agreement may be even more limited.

Our focus on acquiring producing natural gas and oil properties may increase our potential exposure to liabilities and costs for environmental and other problems existing on acquired properties.  Often we are not entitled to contractual indemnification associated with acquired properties.  Normally, we acquire interests in properties on an “as is” basis with no or limited remedies for breaches of representations and warranties, as was the case in the acquisitions of assets from EXCO Resources Inc. and Castle Gas Company, as well as the acquisition of all shares of Unioil, Inc.  We could incur significant unknown liabilities, including environmental liabilities, or experience losses due to title defects, in our acquisitions for which we have limited or no contractual remedies or insurance coverage.

Additionally, significant acquisitions can change the nature of our operations depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or be in different geographic locations than our existing properties.  For example, in the Castle acquisition, we acquired interests in wells which we will need to operate together with other partners, we acquired pipelines that we will need to operate and expect we will need to commit to drilling in the acquired areas to achieve the expected benefits.  Consequently, we may not be able to efficiently realize the assumed or expected economic benefits of properties that we acquire, if at all.

When drilling prospects, we may not yield natural gas or oil in commercially viable quantities.

A prospect is a property on which our geologists have identified what they believe, based on available information, to be indications of natural gas or oil bearing rocks.  However, our geologists cannot 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 given the available data and technology.  If a well is determined to be dry or uneconomic, which can occur even though it contains some oil or natural 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 natural gas and oil to be profitable.  If we drill a dry hole or unprofitable well on current and future prospects, the profitability of our operations will decline and our value will likely be reduced.  In sum, the cost of drilling, completing and operating any well is often uncertain and new wells may not be productive.  Our recent uneconomic drilling in the Texas Barnett Shale illustrates this risk.

We may not be able to identify enough attractive prospects on a timely basis to meet our development needs, which could limit our future development opportunities.

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 us to continue to grow our reserves and production.  Our ability to identify and acquire new drilling locations depends on a number of uncertainties, including the availability of capital, regulatory approvals, natural gas and oil prices, competition, costs, availability of drilling rigs, drilling results and the ability of our geologists to successfully identify potentially successful new areas to develop.  Because of these uncertainties, our profitability and growth opportunities may be limited by the timely availability of new drilling locations.  As a result, our operations and profitability could be adversely affected.


Drilling for and producing natural gas and oil are high risk activities with many uncertainties that could adversely affect our 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 natural gas and oil can be unprofitable, not only due to dry holes, but also due to curtailments, delays or cancellations 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.  We maintain insurance against various losses and liabilities arising from operations; however, insurance against all operational risks is not available.  Additionally, our 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 effect on our business activities, financial condition and results of operations.
 
Our oil and gas well drilling operations segment has historically received most of its revenue from the partnerships we sponsor, and a reduction or loss of that business could reduce or eliminate the revenue, profit and cash flow associated with those activities.

Our oil and gas well drilling operations segment has, prior to 2008, received most of its revenue from the partnerships we sponsor.  We sponsor oil and natural gas partnerships through a network of non-affiliated FINRA broker dealers.   We did not offer a partnership in 2008 and do not anticipate offering a partnership in 2009.  There can be no assurance that the network of brokers will be available or can be recreated if we wish to use partnerships to raise funds in future years.  In that situation, our operations and profitability could be adversely affected.

Under the “successful efforts” accounting method that we use, unsuccessful exploratory wells must be expensed in the period when they are determined to be non-productive, which reduces our net income in such periods and could have a negative effect on our profitability.

We have conducted exploratory drilling and plan to continue exploratory drilling in 2009 in order to identify additional opportunities for future development.  Under the “successful efforts” method of accounting that we use, the cost of unsuccessful exploratory wells must be charged to expense in the period when they are determined to be unsuccessful.  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, we anticipate that some or all of our exploratory wells may not be productive.  The costs of such unsuccessful exploratory wells could result in a significant reduction in our profitability in periods when the costs are required to be expensed and these increased costs could reduce our net income and have a negative effect on our profitability and ability to repay or refinance our indebtedness.


Increasing finding and development costs may impair our profitability.

In order to continue to grow and maintain our profitability, we must annually add new reserves that exceed our 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, our production, reserves and profitability will decline over time.  Given the relative maturity of most natural gas and oil basins in North America and the high level of activity in the industry, the cost of finding new reserves through exploration and development operations has been increasing.  The acquisition market for natural gas and oil properties has become extremely competitive among producers for additional production and expanded drilling opportunities in North America.  Acquisition values climbed toward historic highs during 2007 and 2008 on a per unit basis, particularly in the Rocky Mountain Region, and these values may continue to increase in the future.  This increase in finding and development costs results in higher depreciation, depletion and amortization rates.  If the upward trend in finding and development costs continues, we will be exposed to an increased likelihood of a write-down in carrying value of our natural gas and oil properties in response to falling commodity prices and reduced profitability of our operations.

Our development and exploration operations require substantial capital, and we 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 ultimately our profitability.

The natural gas and oil industry is capital intensive.  We expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of natural gas and oil reserves.  To date, we have financed capital expenditures primarily with bank borrowings, cash generated by operations and our 2008 public note issuance.  We intend to finance our future capital expenditures with cash flow from operations and our existing and planned financing arrangements.  Our cash flow from operations and access to capital is subject to a number of variables, including:

• our proved reserves;
• the amount of natural gas and oil we are able to produce from existing wells;
• the prices at which natural gas and oil are sold;
• the costs to produce oil and natural gas; and
• our ability to acquire, locate and produce new reserves.

If our revenues or the borrowing base under our credit facility decreases as a result of lower natural gas and oil prices, operating difficulties, declines in reserves or for any other reason, then we may have limited ability to obtain the capital necessary to sustain our operations at current levels.  We may, from time to time, need to seek additional financing.  There can be no assurance as to the availability or terms of any additional financing.

If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower natural gas and oil prices, or we incur operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at planned levels, and our profitability may be adversely affected.

If additional capital is needed, we may not be able to obtain debt or equity financing on favorable terms, or at all.  If cash generated by our operations or sale of drilling 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 the exploration and development of our prospects, which in turn could lead to a possible loss of properties, decline in natural gas and oil reserves and a decline in our profitability.

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

Seasonal weather conditions and lease stipulations designed to protect various wildlife affect natural gas and oil operations in the Rocky Mountains.  In certain areas, including parts of the Piceance Basin in Colorado, drilling and other natural gas and oil activities are restricted or prohibited by lease stipulations, or prevented by weather conditions, for up to six months out of the year.  This limits our 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 our operations and materially increase operating and capital costs and therefore adversely affect our profitability.


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

We operate most of the wells in which we own an interest.  However, there are some wells we do not operate because we participate through joint operating agreements under which we own partial interests in natural gas and oil properties operated by other entities.  If we do not operate the properties in which we own an interest, we do 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 our control, including the operator’s timing and amount of capital expenditures, expertise (including safety and environmental compliance) and financial resources, inclusion of other participants in drilling wells, and use of technology.

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

Market conditions or the unavailability of satisfactory natural gas and oil transportation arrangements may hinder our access to natural gas and oil markets or delay our production.  The availability of a ready market for natural gas and oil production depends on a number of factors, including the demand for and supply of natural gas and oil and the proximity of reserves to pipelines and terminal facilities.  Our ability to market our 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 our business.  We may be required to shut in wells for lack of market or because of inadequacy, unavailability or the pricing associated with natural gas pipeline, gathering system capacity or processing facilities.  If that were to occur, we would be unable to realize revenue from those wells until we made production arrangements to deliver the product to market.  Thus, our profitability would be adversely affected.

Our derivative activities could result in financial losses or reduced income from failure to perform by our counterparties or from changes in prices.

We use derivatives for a portion of our natural gas and oil production from our own wells, our partnerships and for natural gas purchases and sales by our marketing subsidiary to achieve a more predictable cash flow, to reduce exposure to adverse fluctuations in the prices of natural gas and oil, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and purchasers. These arrangements expose us to the risk of financial loss in some circumstances, including when 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 that we receive.  
 
In addition, derivative arrangements may limit the benefit from changes in the prices for natural gas and oil and may require the use of our resources to meet cash margin requirements.  Since our derivatives do not currently qualify for use of hedge accounting, changes in the fair value of derivatives are recorded in our income statements, and our net income is subject to greater volatility than if our derivative instruments qualified for hedge accounting.  For instance, if oil and gas prices rise significantly, it could result in significant non-cash charges each quarter, which could have a material negative effect on our net income.

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 natural gas and oil sales or joint interest billings to a small number of third parties in the energy industry.  This concentration of customers and joint interest owners may affect our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions.  In addition, our natural gas and oil derivatives as well as the derivatives used by our marketing subsidiary expose us to credit risk in the event of nonperformance by counterparties.

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

Increasing terrorist attacks around the world have created many economic and political uncertainties, some of which may materially adversely affect 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 attacks 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 insurance could have a material adverse effect on our operations and financial condition.  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, such as drilling blow-out insurance, 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 that we are subject to are generally 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 our competitors 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 were 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 natural gas and oil industry is intense, which may adversely affect our ability to succeed.

The natural gas and oil industry is intensely competitive, and we compete with other companies that have greater resources.  Many of these companies not only explore for and produce natural gas and oil, 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 natural gas and oil properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than we can.  In addition, these companies may have a greater ability to continue exploration activities during periods of low natural gas and oil 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 we can, which can adversely affect our competitive position.  Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our 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, we may be at a disadvantage in bidding for exploratory prospects and producing natural gas and oil properties.  These factors could adversely affect the success of our operations and our profitability.

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

Our 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 natural gas and oil wells.  Under these laws and regulations, we 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 us 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.

Part of the regulatory environment includes federal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities.  In addition, our activities are subject to the regulation by natural gas and oil-producing states of conservation practices and protection of correlative rights.  These regulations affect our operations, increase our costs of exploration and production and limit the quantity of natural gas and oil that we can produce and market.  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 our ability to explore on or develop our properties.  Additionally, the natural gas and oil regulatory environment could change in ways that might substantially increase our financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability.  Furthermore, these additional costs may put us at a competitive disadvantage compared to larger companies in the industry which can spread such additional costs over a greater number of wells and larger operating staff.

Illustrative of these risks are regulations recently enacted by the State of Colorado which focus on the oil and gas industry.  These multi-faceted proposed regulations significantly enhance requirements regarding oil and gas permitting, environmental requirements, and wildlife protection.  Permitting delays and increased costs could result from these final regulations.


Litigation has been commenced against us pertaining to our royalty practices and payments; the cost of our defending these lawsuits, and any future similar lawsuit, could be significant and any resulting judgments against us could have a material adverse effect upon our financial condition.

In recent years, litigation has commenced against us and several other companies in our industry regarding royalty practices and payments in jurisdictions where we conduct business.  For more information on the suits that currently relate to us, see Item 3 , Legal Proceedings . We intend to defend ourselves vigorously in these cases.  Even if the ultimate outcome of this litigation resulted in our dismissal, defense costs could be significant.  These costs would be reflected in terms of dollar outlay as well as the amount of time, attention and other resources that our management would have to appropriate to the defense.  Although we cannot predict an eventual outcome of this litigation, a judgment in favor of a plaintiff could have a material adverse effect on our financial condition.

Any future failure to maintain effective internal control over financial reporting and/or effective disclosure controls and procedures could have a material adverse effect on the reliability of our financial statements and our ability to file public reports on time, raise capital and meet our debt obligations.

Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2008, and pursuant to this assessment, concluded that we did maintain effective internal control over financial reporting as of December 31, 2008.  However, for each of the years in the three-year period ended December 31, 2007, management’s assessment of the effectiveness of our internal control over financial reporting identified several material weaknesses as disclosed in our Annual Reports on Form 10-K for each of the years in the three-year period then ended and filed with the SEC on March 20, 2008, May 23, 2007, and May 31, 2006, respectively.  The existence of a material weakness means there is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

Any future failure to maintain effective internal control over financial reporting and/or effective disclosure controls and procedures could prevent us from being able to prevent fraud and/or provide reliable financial statements and other public reports.  Such circumstances could harm our business and operating results, cause investors to lose confidence in the accuracy and completeness of our financial statements and reports, and have a material adverse effect on the trading price of our debt and equity securities and our ability to raise capital necessary for our operations.  These failures may also adversely affect our ability to file our periodic reports with the SEC on time.   Being late in filing our periodic reports with the SEC may result in the delisting of our common stock from the NASDAQ Stock Market or a default under our senior credit agreement, the indenture governing our outstanding 12% senior notes due 2018, and any other instruments governing debt that we may incur in the future.  Ultimately, such defaults could lead to the acceleration of our debt obligations, and if an acceleration of our debt obligations were to occur, we may not have sufficient funds to repay those obligations immediately, and we would be forced to seek alternative repayment arrangements either through a bankruptcy or an out of court debt restructuring.  Consequently, a future material weakness could lead to significant and negative changes to our financial condition and the value of our equity and debt securities.


Risks Associated with Our Indebtedness

Our credit facility has substantial restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect our operations.  Our lenders can unilaterally reduce our borrowing availability based on anticipated sustained oil and natural gas prices.

We depend on our revolving credit facility for future capital needs.  The terms of the borrowing agreement require us 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 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 natural gas and oil properties securing their 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 natural gas and oil 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.


The indenture governing our outstanding senior notes and our senior credit agreement impose (and we anticipate that the indentures governing any other debt securities we may issue will also impose) restrictions on us that may limit the discretion of management in operating our business. That, in turn, could impair our ability to meet our obligations.

The indenture governing our outstanding senior notes and our senior credit agreement contain (and we anticipate that the indentures governing any other debt securities we may issue will also contain) various restrictive covenants that limit management’s discretion in operating our business.  In particular, these covenants limit our ability to, among other things:

• incur additional debt;
• make certain investments or pay dividends or distributions on our capital stock, or purchase, redeem or retire capital stock;
• sell assets, including capital stock of our restricted subsidiaries;
• restrict dividends or other payments by restricted subsidiaries;
• create liens;
• enter into transactions with affiliates; and
• merge or consolidate with another company.

These covenants could materially and adversely affect our ability to finance our future operations or capital needs.  Furthermore, they may restrict our ability to expand, to pursue our business strategies and otherwise conduct our business.  Our ability to comply with these covenants may be affected by circumstances and events beyond our control, such as prevailing economic conditions and changes in regulations, and we cannot assure you that we will be able to comply with them.  A breach of any of these covenants could result in a default under the indenture governing our outstanding senior notes and any other debt securities we may issue in the future and/or our senior credit agreement.  If there were an event of default under our indenture and/or the senior credit agreement, the affected creditors could cause all amounts borrowed under these instruments to be due and payable immediately.  Additionally, if we fail to repay indebtedness under our senior credit agreement when it becomes due, the lenders under the senior credit agreement could proceed against the assets which we have pledged to them as security.  Our assets and cash flow might not be sufficient to repay our outstanding debt in the event of a default.  The occurrence of such an event would adversely affect our operations and profitability.

Our senior credit agreement also requires us to maintain specified financial ratios and satisfy certain financial tests.  Our ability to maintain or meet such financial ratios and tests may be affected by events beyond our control, including changes in general economic and business conditions, and we cannot assure you that we will maintain or meet such ratios and tests, or that the lenders under the senior credit agreement will waive any failure to meet such ratios or tests.

In addition, upon a change in control, we are required to offer to buy each senior note for 101% of the principal amount, plus unpaid interest.  A change in control is defined to include:  (i) when a majority of the Board of Directors are not continuing directors; (ii) when one person (or group of related persons) holds direct or indirect ownership of over 50% of our voting stock; or (iii) upon sale, transfer or lease of substantially all of our assets.

We may incur additional indebtedness to facilitate our acquisition of additional properties, which would increase our leverage and could negatively affect our business or financial condition.

Our business strategy includes the acquisition of additional properties that we believe would have a positive effect on our current business and operations.  We expect to continue to pursue acquisitions of such properties and may incur additional indebtedness to finance the acquisitions.  Our incurrence of additional indebtedness would increase our leverage and our interest expense, which could have a negative effect on our business or financial condition.

If we fail to obtain additional financing, we may be unable to refinance our existing debt, expand our current operations or acquire new businesses. This could result in our failure to grow in accordance with our plans, or could result in defaults in our obligations under our senior credit agreement or the indenture relating to our outstanding senior notes.

In order to refinance indebtedness, expand existing operations and acquire additional businesses or properties, we will require substantial amounts of capital.  There can be no assurance that financing, whether from equity or debt financings or other sources, will be available or, if available, will be on terms satisfactory to us.  If we are unable to obtain such financing, we will be unable to acquire additional businesses or properties and may be unable to meet our obligations under our senior credit agreement and the indenture relating to our outstanding senior notes or any other debt securities we may issue in the future.  Such an event would adversely affect our operations and profitability.

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.


ITEM 2.  PROPERTIES

Information regarding our wells, production, proved reserves and acreage are included in Item 1 and in Note 1 , Summary of Significant Accounting Policies , to our consolidated financial statements included in this report.

Substantially all of our oil and natural gas properties have been mortgaged or pledged as security for our credit facility.  See Note 6, Long Term Debt , to our accompanying consolidated financial statements included in this report.

Facilities

We own our 32,000 square feet corporate office building located in Bridgeport, West Virginia.  We lease approximately 5,000 and 17,000 square feet of office space in two buildings near our current corporate office through March 2010 and November 2011, respectively.  We lease 15,700 square feet of office space in downtown Denver, Colorado through March 2012, which effective March 1, 2009, will become our corporate headquarters.

We own or lease field operating facilities in the following locations:

 
·
West Virginia:  Bridgeport, Glenville and West Union
 
·
Michigan:  Ossineke
 
·
Colorado:  Evans, Parachute and Wray
 
·
Pennsylvania:  Indiana and Mahaffey


ITEM 3.  LEGAL PROCEEDINGS

    Information regarding our legal proceedings can be found in Note 8 , Commitments and Contingencies – Litigation and Note 17 , Subsequent Events , to our consolidated financial statements included in this report.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

 
PART II
 

ITEM 5.  MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Our authorized capital stock consists of 100,000,000 shares of common stock, par value $0.01 per share.  Our common stock is traded on the NASDAQ Global Select Market under the ticker symbol PETD.


The following table sets forth the range of high and low sales prices for our common stock as reported on the NASDAQ Global Select Market for the periods indicated below.
 
   
High
   
Low
 
2008
           
First Quarter
  $ 73.92     $ 50.75  
Second Quarter
    79.09       66.37  
Third Quarter
    68.76       34.15  
Fourth Quarter
    44.75       11.50  
                 
2007
               
First Quarter
  $ 55.20     $ 40.53  
Second Quarter
    55.24       44.59  
Third Quarter
    51.13       35.73  
Fourth Quarter
    61.91       41.65  


As of February 23, 2009, we had approximately 1,107 shareholders of record.

 We have not paid any dividends on our common stock and currently intend to retain earnings for use in our business.  We do not expect to declare cash dividends in the foreseeable future.

 The following table presents information about our purchases of our common stock during the three months ended December 31, 2008.
 
Period
 
Total Number of
Shares Purchased (1)
   
Average Price Paid per Share
   
Total Number   of Shares Purchased as Part of Publicly Announced Plans or Programs
   
Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
 
                         
October 1 - 31, 2008
    118     $ 20.71       -       -  
November 1-30, 2008
    351       15.74       -       -  
December 1-31, 2008
    827       24.88       -       -  
Total fourth quarter purchases
    1,296       22.02                  

______________
(1)
Pursuant to our stock-based compensation plans, the 1,296 shares purchased during the quarter represent purchases from our employees for their payment of tax liabilities related to the vesting of securities.

On October 16, 2006, our Board of Directors approved a share purchase program authorizing us to purchase up to 10% of our then outstanding common stock (1,477,109 shares) through April 2008.  There were 1,465,089 shares that were authorized but not yet purchased as of December 31, 2007.  Total shares purchased in 2008 pursuant to the program were 64,263 common shares at a cost of $4.4 million ($67.97 average price paid per share), including 63,756 shares from our executive officers at a cost of $4.3 million ($67.98 price paid per share).   Shares purchased from employees, excluding executive officers, were generally purchased at fair market value based on the closing price on the date of purchase and were primarily purchased to satisfy the statutory minimum tax withholding requirement for restricted stock that vested in 2008.  Shares purchased from executive officers were primarily pursuant to a separation agreement with our former president and to satisfy the statutory minimum tax withholding requirements for shares vested in 2008.  The authorization to purchase the remaining 1,400,826 shares effectively expired on April 30, 2008.  All shares purchased in accordance with the program have been subsequently retired.


SHAREHOLDER PERFORMANCE GRAPH

The performance graph below compares the cumulative total return of our common stock over a five year period ended December 31, 2008, with the cumulative total returns for the same period for a Standard Industrial Code Index, or SIC, and the Standard and Poor's, or S&P, 500 Index.  The SIC Code Index is a weighted composite of 158 crude petroleum and natural gas companies.  The cumulative total shareholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on December 31, 2003, and in the S&P 500 Index and the SIC Code Index on the same date.  The results shown in the graph below are not necessarily indicative of future performance.
 

 
 
GRAPH

 
   
Year Ended December 31,
                         
   
2003
   
2004
   
2005
   
2006
   
2007
   
2008
 
PETROLEUM DEVELOPMENT CORPORATION
  $ 100     $ 163     $ 141     $ 182     $ 249     $ 102  
SIC CODE INDEX
    100       127       183       237       334       195  
S&P 500 INDEX
    100       111       116       135       142       90  


ITEM 6.  SELECTED FINANCIAL DATA
 
   
Year Ended December 31,
 
   
2008
   
2007
   
2006
   
2005
   
2004
 
   
(in thousands, except per share data)
 
Revenues:
                             
Oil and gas sales
  $ 321,877     $ 175,187     $ 115,189     $ 102,559     $ 69,492  
Sales from natural gas marketing activities
    140,263       103,624       131,325       121,104       94,627  
Oil and gas well drilling operations (1)
    7,615       12,154       17,917       99,963       94,076  
Well operations and pipeline income
    11,474       9,342       10,704       8,760       7,677  
Oil and gas price risk management gain (loss), net (2)
    127,838       2,756       9,147       (9,368 )     (3,085 )
Other
    293       2,172       2,221       2,180       1,696  
Total revenues
    609,360       305,235       286,503       325,198       264,483  
                                         
Costs and expenses:
                                       
Oil and gas production and well operations costs
    78,209       49,264       29,021       20,400       17,713  
Cost of natural gas marketing activities
    139,234       100,584       130,150       119,644       92,881  
Cost of oil and gas well drilling operations (1)
    2,213       2,508       12,617       88,185       77,696  
Exploration expense
    45,105       23,551       8,131       11,115       -  
General and administrative expense
    37,715       30,968       19,047       6,960       4,506  
Depreciation, depletion and amortization
    104,575       70,844       33,735       21,116       18,156  
Total costs and expenses
    407,051       277,719       232,701       267,420       210,952  
                                         
Gain on sale of leaseholds (3)
    -       33,291       328,000       7,669       -  
                                         
Income from operations
    202,309       60,807       381,802       65,447       53,531  
Interest income
    591       2,662       8,050       898       185  
Interest expense
    (28,132 )     (9,279 )     (2,443 )     (217 )     (238 )
                                         
Income before income taxes
    174,768       54,190       387,409       66,128       53,478  
                                         
Provision for income taxes
    61,459       20,981       149,637       24,676       20,250  
                                         
Net income
  $ 113,309     $ 33,209     $ 237,772     $ 41,452     $ 33,228  
                                         
Basic earnings per common share
  $ 7.69     $ 2.25     $ 15.18     $ 2.53     $ 2.05  
                                         
Diluted earnings per share
  $ 7.63     $ 2.24     $ 15.11     $ 2.52     $ 2.00  
                                         
                                         
   
As of December 31,
 
   
2008
   
2007
   
2006
   
2005
   
2004
 
                                         
Total assets
  $ 1,402,704     $ 1,050,479     $ 884,287     $ 444,361     $ 329,453  
                                         
Working capital (deficit)
  $ 31,266     $ (50,212 )   $ 29,180     $ (16,763 )   $ 231  
                                         
Long-term debt
  $ 394,867     $ 235,000     $ 117,000     $ 24,000     $ 21,000  
                                         
Shareholders' equity
  $ 511,581     $ 395,526     $ 360,144     $ 188,265     $ 154,021  

______________
(1)
In December 2005, we began entering into cost-plus drilling service arrangements, which are recorded on a net basis unlike our footage based arrangements which are recorded on a gross basis.  See Note 1 , “Summary of Significant Accounting Policies,” to our accompanying consolidated financial statements included in this report.  Further, we have not sponsored a drilling program since August 2007, related revenue continued to be recognized through 2008.
(2)
See Note 3 , “Derivative Financial Instruments”, to our accompanying consolidated financial statements included in this report.
(3)
In July 2006, we sold a portion of our undeveloped leasehold located in Grand Valley Field, Garfield County, Colorado.  See Note 13 , “Sale of Oil and Gas Properties,” to our accompanying consolidated financial statements included in this report.


ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis, as well as other sections in this Form 10-K, should be read in conjunction with our accompanying consolidated financial statements and related notes to consolidated financial statements included in this report.  Further, we encourage you to revisit Special Note Regarding Forward-Looking Statements on page 1   of this report.

2008 Overview

The year 2008 was a year of unprecedented events: oil and natural gas prices soared to record and near record highs, respectively, through July; then, in the midst of U.S. credit turmoil and a worldwide economic slump, in December, oil prices fell to their lowest in four years and natural gas prices dropped almost by half.  Our reaction to these events is one of caution.  While we certainly felt the impact of these events, we believe that we were successful in managing our operations in such a manner that we were able to minimize the negative impacts while capitalizing on the positive impacts.  Our strong derivative position eased the impact of the fall in oil and natural gas prices.  We exit 2008 with $7.6 million in net realized derivative gains, $31.4 million in the fourth quarter alone.  Further, we estimate the net fair value of our derivative positions, excluding the derivative positions attributed to our affiliated partnerships, as of December 31, 2008, to be $117.8 million.  See 2009 Outlook and Liquidity and Capital Resources sections below for a discussion of the steps we plan to take in this uncertain economic environment.
 
For the second consecutive year, our net wells drilled increased double digits, up 20.7% in 2008 from 2007, which was up 100.1% from 2006.  The increased drilling activity was fueled by the July 2006 sale of an undeveloped leasehold located in Grand Valley Field, Garfield County, Colorado, providing us with cash proceeds of $353.6 million and our February 2008 senior notes offering with net proceeds of $196 million.  We ended 2008 with interests in 4,712 gross, 3,259 net, wells located in the Rocky Mountain Region and the Appalachian and Michigan Basins.  In 2008, we recompleted 104 wells in the Wattenberg Field and 21 wells in the Appalachian Basin.

The decline in prices during the fourth quarter of 2008 has resulted in $118.4 million in unrealized gains on derivatives for the year ended December 31, 2008.  The $118.4 million in unrealized gains for the year is the fair value of the derivative positions as of December 31, 2008, less the related unrealized amounts recorded in prior periods.  An unrealized gain is a non-cash item and there will be further gains or losses as prices decrease or increase until the positions mature or are closed.  While the required accounting treatment for derivatives that do not qualify for hedge accounting treatment under SFAS No. 133 may result in significant swings in operating results over the life of the derivatives, the combination of the settled derivative contracts and the revenue received from the oil and gas sales at delivery are expected to result in a more predictable cash flow stream than would the sales contracts without the associated derivatives.

The average NYMEX and CIG prices for the next 24 months (forward curve) from the respective dates below are as follows:
 
       
December 31,
   
June 30,
   
December 31,
   
February 13,
 
Commodity
 
Index
 
2007
   
2008
   
2008
   
2009
 
                             
Natural gas:
 
NYMEX
  $ 8.12     $ 12.52     $ 6.62     $ 5.87  
   
CIG
    6.78       8.86       4.49       4.13  
Oil:
 
NYMEX
    90.79       140.15       57.49       53.07  

 
The dramatic commodity price declines from June 30, 2008, through December 31, 2008, relative to our current derivative positions, resulted in the significant unrealized derivative gains in 2008.  If there are further price declines in 2009, unrealized derivatives gains on our current positions are expected to continue.
 

2009 Outlook
 
 We project that our 2009 production will be approximately 44.4 Bcfe or a 15% increase over 2008 production.  Our 2009 capital budget of $120 million to $140 million represents an approximate 60% decrease compared to 2008.  We selected this level of spending with the goal of remaining debt neutral to help maintain adequate liquidity during 2009.  We realize that oil and gas prices may vary considerably from our projections.  We use oil and natural gas derivatives contracts in order to reduce the effects of volatile commodity prices.  As of December 31, 2008, we had oil and natural gas hedges in place covering 52% of our expected oil production and 62% of our expected natural gas production in 2009.
 
For 2009, our drilling plans continue to be focused primarily in the Rocky Mountain Region.  We plan to drill approximately 166 gross wells, excluding exploratory wells, of which 154 are in the Rocky Mountain Region and 12 are in the Appalachian Basin.  We are currently evaluating the exploration potential of the Marcellus Formation in the Appalachian Basin.  Through a combination of lease, farmout and wellbore ownership, we operate over 2,100 wells within the Marcellus “Fairway” area.  We currently have three wells drilled, two of which are in line, and seven additional vertical tests are planned in 2009.

Due to the continued decline in natural gas prices, in early 2009, we temporarily ceased all of our drilling operations in the Piceance Basin, resulting in the demobilization of the three contracted drilling rigs in this area.  We have included in our approved 2009 capital budget $40.4 million for drilling and completion activities in the Piceance Basin.  Should natural gas prices change materially from the projected levels, we will reevaluate our drilling options.
 
Results of Operations

Summary Operating Results

The following table sets forth selected information regarding our results of operations, including production volumes, oil and gas sales, average sales prices received, average sales price including realized derivative gains and losses, average lifting cost, other operating income and expenses for the years ended December 31, 2008, 2007 and 2006.

 
   
Summary Operating Results for the
 
   
  Year Ended December 31,
 
                     
Change
 
   
2008
   
2007
   
2006
     
2008-2007
     
2007-2006
 
Production (1)
                                 
Oil (Bbls)
    1,160,408       910,052       631,395       27.5 %     44.1 %
Natural gas (Mcf)
    31,759,792       22,513,306       13,160,784       41.1 %     71.1 %
Natural gas equivalent (Mcfe) (2)
    38,722,240       27,973,618       16,949,154       38.4 %     65.0 %
Oil and Gas Sales   (in thousands)
                                       
Oil sales
  $ 104,168     $ 55,196     $ 37,460       88.7 %     47.3 %
Gas sales
    221,734       119,991       77,729       84.8 %     54.4 %
Royalty litigation provision
    (4,025)       -       -       *       *  
Total oil and gas sales
  $ 321,877     $ 175,187     $ 115,189       86.0 %     52.1 %
                                         
Realized Gain (Loss) on Derivatives, net (in thousands)
                                       
Oil derivatives - realized loss
  $ (3,145 )   $ (177 )   $ -       *       *  
Natural gas derivatives - realized gain
    12,632       7,350       1,895       71.9 %     *  
Total realized gain on derivatives, net
  $ 9,487     $ 7,173     $ 1,895       32.3 %     *  
 Average Sales Price
                                       
Oil (per Bbl) (3)
  $ 89.77     $ 60.65     $ 59.33       48.0 %     2.2 %
Natural gas (per Mcf) (3)
  $ 6.98     $ 5.33     $ 5.91       31.0 %     -9.8 %
Natural gas equivalent (per Mcfe)
  $ 8.42     $ 6.26     $ 6.80       34.4 %     -7.9 %
 Average Sales Price (including realized gain (loss) on derivatives)
                                       
Oil (per Bbl)
  $ 87.06     $ 60.46     $ 59.33       44.0 %     1.9 %
Natural gas (per Mcf)
  $ 7.38     $ 5.66     $ 6.05       30.5 %     -6.5 %
Natural gas equivalent (per Mcfe)
  $ 8.66     $ 6.52     $ 6.91       32.9 %     -5.6 %
                                         
Average Lifting Cost per Mcfe (4)
  $ 1.07     $ 0.90     $ 0.76       18.9 %     18.4 %
                                         
Other Operating Income (5)   (in thousands)
                                       
Natural gas marketing activities
  $ 1,029     $ 3,040     $ 1,175       -66.2 %     158.7 %
Oil and gas well drilling operations
  $ 5,402     $ 9,646     $ 5,300       -44.0 %     82.0 %
                                         
Costs and Expenses (in thousands)
                                       
Exploration expense
  $ 45,105     $ 23,551     $ 8,131       91.5 %     189.6 %
General and administrative expense
  $ 37,715     $ 30,968     $ 19,047       21.8 %     62.6 %
Depreciation, depletion and amortization
  $ 104,575     $ 70,844     $ 33,735       47.6 %     110.0 %
                                         
Interest Expense (in thousands)
  $ 28,132     $ 9,279     $ 2,443       203.2 %     *  
 
*Percentage change not meaningful or equal to or greater than 250%
Amounts may not calculate due to rounding
_______________
 
(1)
Production is net and determined by multiplying the gross production volume of properties in which we have an interest by the percentage of the leasehold or other property interest we own.
 
(2)
A ratio of energy content of natural gas and oil (six Mcf of natural gas equals one Bbl of oil) was used to obtain a conversion factor to convert oil production into equivalent Mcf of natural gas.
 
(3)
We utilize commodity based derivative instruments to manage a portion of our exposure to price volatility of our natural gas and oil sales.  This amount excludes realized and unrealized gains and losses on commodity based derivative instruments.
 
(4)
Production costs represent oil and gas operating expenses which exclude production taxes.
 
(5)
Includes revenues and operating expenses.


Oil and Gas Sales Activity

Oil and Natural Gas Production and Sales Activity by Area

   
Year Ended December 31,
 
                     
Change
 
   
2008
   
2007
   
2006
     
2008-2007
     
2007-2006
 
Production
                                 
Oil (Bbls)
                                 
Appalachian Basin
    6,623       5,490       1,837       20.6 %     198.9 %
Michigan Basin
    3,469       4,301       4,439       -19.3 %     -3.1 %
Rocky Mountain Region
    1,150,316       900,261       625,119       27.8 %     44.0 %
Total
    1,160,408       910,052       631,395       27.5 %     44.1 %
Natural gas (Mcf)
                                       
Appalachian Basin
    3,902,183       2,711,300       1,451,729       43.9 %     86.8 %
Michigan Basin
    1,609,984       1,678,155       1,399,852       -4.1 %     19.9 %
Rocky Mountain Region
    26,247,625       18,123,851       10,309,203       44.8 %     75.8 %
Total
    31,759,792       22,513,306       13,160,784       41.1 %     71.1 %
Natural gas equivalent (Mcfe)
                                       
Appalachian Basin
    3,941,921       2,744,240       1,462,751       43.6 %     87.6 %
Michigan Basin
    1,630,798       1,703,961       1,426,486       -4.3 %     19.5 %
Rocky Mountain Region
    33,149,521       23,525,417       14,059,917       40.9 %     67.3 %
Total
    38,722,240       27,973,618       16,949,154       38.4 %     65.0 %
 
 
Average Sales Price (excluding derivative gains/losses)
                                 
Oil (per Bbl)
                                 
Appalachian Basin
  $ 88.80     $ 59.08     $ 60.14       50.3 %     -1.8 %
Michigan Basin
    100.79       68.31       61.07       47.5 %     11.9 %
Rocky Mountain Region
    89.73       60.62       59.31       48.0 %     2.2 %
Weighted average price
    89.77       60.65       59.33       48.0 %     2.2 %
Natural gas (per Mcf)
                                       
Appalachian Basin
  $ 9.21     $ 6.99     $ 7.37       31.8 %     -5.2 %
Michigan Basin
    8.41       6.12       6.53       37.4 %     -6.3 %
Rocky Mountain Region
    6.57       5.01       5.62       31.1 %     -10.9 %
Weighted average price
    6.98       5.33       5.91       31.0 %     -9.8 %
Natural gas equivalent (per Mcfe)
                                       
Appalachian Basin
  $ 9.24     $ 7.02     $ 7.39       31.6 %     -5.0 %
Michigan Basin
    8.52       6.20       6.60       37.4 %     -6.1 %
Rocky Mountain Region
    8.32       6.18       6.75       34.6 %     -8.4 %
Weighted average price
    8.42       6.26       6.80       34.5 %     -7.9 %


Our oil and natural gas sales revenues have increased in each of the past two years, primarily due to increased volumes and higher average sales prices in 2008 and increased volumes partially offset by lower average sales prices in 2007.  Increased volumes contributed $90.5 million and $75 million to the increase in oil and gas sales revenues in 2008 and 2007, respectively.  The increases in oil and natural gas volumes over the past two years is attributable to the significant increase in the number of wells drilled for our own account in 2008 and 2007 compared to those drilled in prior years, and to a lesser extent, the acquisition of producing oil and gas properties in the fourth quarter of 2006.  The production volumes and oil and gas sales revenue generated in 2007 from the acquisition of oil and gas properties made in early 2007 and December 2006 and their subsequent development were 6.5 Bcfe and $45.8 million, respectively.


Oil and Natural Gas Pricing.   Financial results depend upon many factors, particularly the price of oil and natural gas and our ability to market our production effectively.  Oil and natural gas prices have been among the most volatile of all commodity prices.  These price variations have a material impact on our financial results.  Oil and natural gas prices also vary by region and locality, depending upon the distance to markets, and the supply and demand relationships in that region or locality.  This can be especially true in the Rocky Mountain Region.  The combination of increased drilling activity and the lack of local markets have resulted in a local market oversupply situation from time to time.  Like most producers in the region, we rely on major interstate pipeline companies to construct these facilities to increase pipeline capacity, rendering the timing and availability of these facilities beyond our control.  Oil pricing is also driven strongly by supply and demand relationships.

The price we receive for a large portion of the natural gas produced in the Rocky Mountain Region is based on a market basket of prices, which generally includes gas sold at CIG prices as well as gas sold at Mid-Continent or other nearby region prices.  The CIG Index, and other indices for production delivered to other Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is NYMEX based.

Although 82.6% of our 2008 natural gas production came from the Rocky Mountain Region, much of our Rocky Mountain natural gas pricing is based upon other indices in addition to CIG.  The table below identifies the pricing basis of our oil and natural gas pricing based on sales volumes for the year ended December 31, 2008.  The pricing basis is the index that most closely relates to the price under which our oil and natural gas is sold.

Energy Market Exposure
as of December 31, 2008
Area
 
Pricing Basis
 
Commodity
 
Percent of
 Oil and Gas
Sales
                 
Piceance/Wattenberg
 
Colorado Interstate Gas (CIG)
 
Gas
   
39%
 
Colorado/North Dakota
 
NYMEX
 
Oil
   
16%
 
NECO
 
Mid Continent (Panhandle Eastern)
 
Gas
   
12%
 
Piceance
 
San Juan Basin/Southern California
 
Gas
   
16%
 
Appalachian
 
NYMEX
 
Gas
   
10%
 
Michigan
 
Mich-Con/NYMEX
 
Gas
   
4%
 
Wattenberg
 
Colorado Liquids
 
Gas
   
2%
 
Other
 
Other
 
Gas/Oil
   
1%
 
             
100%
 


Lifting Costs .   Lifting costs per Mcfe , excluding production taxes which fluctuate with oil and natural gas prices, have increased approximately 18% annually since 2006, an increase of approximately 41% from 2006 to 2008.  The increase is primarily due to general oil field services and wage inflation pressures.  As production volumes increase when we add new wells, we can expect to see modest decreases in lifting costs as we work on improving and stabilizing our lifting costs.  In our Rocky Mountain Region, we traditionally experience higher lifting costs due to severe winter conditions for costs such as snow removal from well and access roads, along with other weather related problems.

Oil and Gas Production and Well Operations Costs .  In addition to increased production and the significant number of new wells operated, the increase in oil and gas production and well operations costs in each of the past two years is also attributable to additional personnel in the production and engineering staffs, increased maintenance and operating cost of the new pipeline and compressor upgrades and improvements, increased production enhancements and workovers associated with the early 2007 and December 2006 acquisitions and significant general oil field services inflation pressures.  Oil and gas production and well operations cost includes our lifting cost, production taxes, the cost to operate wells and pipelines for our sponsored partnerships and other third parties (whose income is included in well operations and pipeline income) and certain production and engineering staff related overhead costs.  In October 2007, in conjunction with the acquisition of oil and gas properties (762 wells) located in southwestern Pennsylvania, we acquired a well services operation.  The costs related to this operation are included in the statement of operations line item Oil and Gas Production and well Operations Costs .


Oil and Gas Price Risk Management, Net

   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
   
(in thousands)
 
Oil and gas price risk management, net:
                 
Realized gain (loss)
                 
Oil
  $ (3,145 )   $ (177 )   $ -  
Natural gas
    12,632       7,350       1,895  
Total realized gain, net
    9,487       7,173       1,895  
Unrealized gain (loss), net
    118,351       (4,417 )     7,252  
    $ 127,838     $ 2,756     $ 9,147  


Oil and gas price risk management, net includes realized gains and losses and unrealized changes in the fair value of oil and natural gas derivatives related to our oil and natural gas production.  Oil and gas price risk management, net does not include commodity based derivative transactions related to transactions from natural gas marketing activities, which are included in sales from and cost of natural gas marketing activities.  See Note 2 , Fair Value of Financial Instruments , and Note 3, Derivative Financial Instruments , to the accompanying consolidated financial statements for additional details of our derivative financial instruments.

Oil and Gas Derivative Activities .   We use various derivative instruments to manage fluctuations in oil and natural gas prices.  We have in place a series of collars, fixed price swaps and basis swaps on a portion of our oil and natural gas production.  Under the collar arrangements, if the applicable index rises above the ceiling price or swap, we pay the counterparty; however, if the index drops below the floor or swap, the counterparty pays us.  Our production volumes for the quarter ended December 31, 2008, were 326,000 Bbls of oil and 9.3 Bcf of natural gas.


The following table identifies our derivative positions (excluding the derivative positions allocated to our affiliated partnerships) related to oil and gas sales activities in effect as of December 31, 2008, on our production by area.  No new positions have been entered into subsequent to December 31, 2008, through the date of this filing.

     
Floors
   
Ceilings
   
Swaps (Fixed Prices)
   
Basis Swaps
     
Commodity/ Index/ Operating Area
   
Quantity (Gas-MMbtu Oil-Bbls)
   
Weighted Average Contract Price
   
Quantity (Gas-MMbtu Oil-Bbls)
   
Weighted Average Contract Price
   
Quantity (Gas-MMbtu Oil-Bbls)
   
Weighted Average Contract Price
   
Quantity (Gas-MMbtu Oil-Bbls)
   
Weighted Average Contract Price
   
Fair Value
a t December 31, 2008
(in thousands)
 
                                                         
Natural Gas
                                                       
CIG
                                                       
Piceance Basin
                                                       
1Q 2009
      -     $ -       -     $ -       2,388,158     $ 8.08       -     $ -     $ 9,340  
2Q 2009
      2,116,233       5.75       2,116,233       8.90       -       -       -       -       4,358  
3Q 2009
      2,116,233       5.75       2,116,233       8.90       -       -       -       -       3,523  
4Q 2009
      1,536,701       6.70       1,536,701       10.25       584,500       9.20                       6,490  
2010
      1,672,131       6.80       1,672,131       10.90       876,751       9.20       4,274,703       1.88       7,788  
2011
      637,795       4.75       637,795       9.45       -       -       4,698,955       1.88       689  
2012
      -       -       -       -       -       -       4,733,113       1.88       (1,907 )
2013
      -       -       -       -       -       -       4,250,630       1.88       (2,846 )
                                                                           
Wattenberg Field
                                                                         
1Q 2009
      -       -       -       -       1,702,203       8.07       -       -       6,640  
2Q 2009
      1,524,639       5.75       1,524,639       8.89       -       -       -       -       3,140  
3Q 2009
      1,524,639       5.75       1,524,639       8.89       -       -       -       -       2,538  
4Q 2009
      1,119,322       6.71       1,119,322       10.26       424,381       9.20       -       -       4,725  
2010
      1,170,071       6.90       1,170,071       10.98       636,571       9.20       2,682,613       1.88       5,410  
2011
      380,112       4.75       380,112       9.45       -       -       2,951,819       1.88       429  
2012
      -       -       -       -       -       -       2,953,958       1.88       (1,190 )
2013
      -       -       -       -       -       -       2,637,419       1.88       (1,766 )
                                                                           
PEPL
                                                                         
NECO
                                                                         
1Q 2009
      -       -       -       -       810,000       8.46       -       -       3,315  
2Q 2009
      720,000       6.14       720,000       10.81       -       -       -       -       1,332  
3Q 2009
      720,000       6.14       720,000       10.81       -       -       -       -       984  
4Q 2009
      580,000       7.81       580,000       12.68       240,000       10.91       -       -       2,669  
2010
      1,410,000       6.59       1,410,000       10.91       1,060,000       7.99       -       -       3,741  
2011
      300,000       6.00       300,000       10.10       -       -       -       -       92  
                                                                           
NYMEX
                                                                         
Appalachian and Michigan Basins
                                                                 
1Q 2009
      260,103       8.40       260,103       13.05       972,279       9.71       -       -       4,469  
2Q 2009
      905,212       7.13       905,212       12.85       429,743       9.09       -       -       2,836  
3Q 2009
      905,212       7.13       905,212       12.85       429,743       9.09       -       -       2,625  
4Q 2009
      868,186       9.00       868,186       15.66       429,457       9.09       -       -       3,367  
2010
      1,547,849       8.22       1,547,849       14.19       1,704,946       9.08       -       -       5,968  
2011
      232,277       6.75       232,277       12.13       800,844       9.60       -       -       1,731  
2012
      -       -       -       -       155,211       9.89       -       -       306  
Total Natural Gas
                                                                      80,796  
                                                                           
Oil
                                                                         
NYMEX
                                                                         
Watenberg Field
                                                                         
1Q 2009
      -       -       -       -       154,188       90.52       -       -       6,428  
2Q 2009
      -               -       -       155,903       90.52       -       -       5,729  
3Q 2009
      -       -       -       -       157,615       90.52       -       -       5,291  
4Q 2009
      -       -       -       -       157,615       90.52       -       -       4,856  
2010
      -       -       -       -       529,664       92.96       -       -       14,702  
Total Oil
                                                                      37,006  
Total Natural Gas and Oil
                                                                    $ 117,802  


Natural Gas Marketing Activities

The increase in sales from natural gas marketing activities in 2008 compared to 2007 is primarily due to an increase in prices and increased unrealized gains on derivative instruments.  The increase in costs of natural gas marketing activities in 2008 compared to 2007 is primarily due to an increase in prices and increased unrealized losses on derivative instruments.

In 2008, prices on sales and purchases were 31.8% higher on average than in 2007, resulting in a $27.8 million increase in sales and costs.  The sales related unrealized gain on derivatives increased by $6.4 million and the cost of sales related unrealized loss on derivatives increased by $6.9 million. Volumes sold and purchased for resale decreased slightly by 2%.

The decrease in sales from natural gas marketing activities in 2007 compared to 2006 is primarily due to a decrease in prices and volumes sold and a decrease in unrealized gains on derivative instruments.  The decrease in costs of natural gas marketing activities in 2007 compared to 2006 is also due to a decrease in prices and volumes purchased and a decrease in unrealized losses on derivative instruments.

In 2007, prices on sales and purchases were 5% lower on average than in 2006, resulting in a $5 million decrease in sales and costs.  In January 2007, we acquired all of the outstanding partnership interests in 44 of our sponsored drilling partnerships.  Natural gas sales and purchases related to the net 423 wells acquired no longer flowed through marketing activities; the result was a decline in sales from and costs of natural gas marketing activities of $12.2 million.  This decline in partnership volumes was offset by an increase in non-partnership volumes sold and purchased amounting to $3.7 million, for a net volume effect of an $8.5 million decrease compared to 2006.  The gain on unrealized sales decreased $14 million from a $12.3 million gain in 2006 to a $1.7 million loss in 2007.  The gain on unrealized costs decreased $13.4 million from an $11.9 million loss in 2006 to a $1.5 million gain in 2007.

Our natural gas marketing segment specializes in the purchase, aggregation and sale of natural gas production in our eastern operating areas.  Through our natural gas marketing segment, we market the natural gas we produce as well as our purchases of natural gas from other producers in the Appalachian Basin, including our affiliated partnerships.  Our derivative activities related to natural gas marketing activities include both physical and cash-settled derivatives.  We offer fixed-price derivative contracts for the purchase or sale of physical gas and enter into cash-settled derivative positions with counterparties in order to offset those same physical positions.  We do not take speculative positions on commodity prices.


Natural Gas Marketing Derivative Activities .

The following table identifies our derivative positions related to our gas marketing activities in effect as of December 31, 2008.
 
     
Floors
   
Ceilings
   
Swaps (Fixed Prices)
   
Basis Swaps
     
Commodity/ Derivative Instrument
   
Quantity (Gas-MMbtu Oil-Bbls)
   
Weighted Average Contract Price
   
Quantity (Gas-MMbtu Oil-Bbls)
   
Weighted Average Contract Price
   
Quantity (Gas-MMbtu Oil-Bbls)
   
Weighted Average Contract Price
   
Quantity (Gas-MMbtu Oil-Bbls)
   
Weighted Average Contract Price
   
Fair Value
a t December 31, 2008
(in thousands)
 
                                                         
Natural Gas
                                                       
Physical Sales
                                                       
1Q 2009
      20,000     $ 6.50       -     $ -       112,400     $ 8.59       290,021     $ 0.37     $ 230  
2Q 2009
      -       -       -       -       43,132       9.20       72,493       0.29       119  
3Q 2009
      -       -       -       -       31,320       9.55       66,578       0.29       88  
4Q 2009
      -       -       -       -       9,293       8.36       38,266       0.51       14  
2010
      -       -       -       -       15,610       8.45       30,410       0.80       19  
                                                                             
Financial Purchases
                                                                         
1Q 2009
      20,000       6.50       -       -       152,400       7.31       -       -       (207 )
2Q 2009
      -       -       -       -       43,132       8.11       -       -       (99 )
3Q 2009
      -       -       -       -       31,191       8.48       -       -       (74 )
4Q 2009
      -       -       -       -       29,293       10.77       -       -       (113 )
  2010
      -       -       -       -       45,610       10.86       -       -       (157 )
                                                                             
Financial Sales
                                                                         
1Q 2009
      -       -       10,000       10.30       580,900       9.13       226,665       0.32       1,879  
2Q 2009
      -               -       -       322,500       9.27       211,272       0.32       1,116  
3Q 2009
      -       -       -       -       250,500       9.39       141,250       0.32       812  
4Q 2009
      -       -       -       -       248,500       8.90       166,050       0.32       540  
2010
      -       -       -       -       695,000       8.71       -       -       1,040  
2011
                              -       150,000       8.44       -       -       125  
                                                                             
Physical Purchases
                                                                         
1Q 2009
      -       -       10,000       10.30       581,395       9.29       46,935       0.32       (1,762 )
2Q 2009
      -       -       -       -       322,995       9.44       46,874       0.32       (1,079 )
3Q 2009
      -       -       -       -       250,995       9.56       46,752       0.32       (788 )
4Q 2009
      -       -       -       -       228,665       9.60       15,584       0.32       (597 )
2010
      -       -       -       -       665,000       9.14       -       -       (1,146 )
2011
      -       -       -       -       150,000       8.61       -       -       (125 )
Total Natural Gas
                                                                    $ (165 )


Oil and Gas Well Drilling

The decrease in oil and gas well drilling operations revenue was due to our decision not to sponsor a drilling partnership in 2008 and our change from footage-based drilling arrangements to cost-plus drilling arrangements, which have differing revenue recognition presentations.

In January 2008, we announced that we did not plan to sponsor new drilling partnerships in 2008.  In August 2007, we completed our only sponsored drilling partnership offering in 2007.  Drilling for the partnership commenced during the third quarter of 2007.  From inception to December 31, 2008, $12.7 million in revenues had been recognized related to the 2007 drilling program.  Advances for future drilling contracts held as of December 31, 2008, will be used for completion activities to be conducted in 2009.  Currently, we do not plan to sponsor a drilling partnership in 2009 or in the foreseeable future. Consequently, we anticipate that our oil and gas drilling segment’s contribution to operating income, which was $5.4 million, $9.6 million and $5.3 million in 2008, 2007 and 2006, respectively, will decline substantially in 2009.  Thereafter, our oil and gas well drilling contribution to operating income will cease unless we undertake new drilling ventures.

Beginning with the last sponsored partnership in 2005 (for which revenue generating activities began in 2006), our partnership wells have been drilled on a “cost-plus” basis, which means that we charge the partnerships for the actual cost of the wells plus an agreed upon mark-up above that cost.  Prior to that partnership, we had conducted most of our third-party drilling activities on a footage basis, pursuant to which we drilled the wells for a fixed price per foot drilled with additional chargeable items as provided for in the drilling agreement.  Our services provided under the cost-plus drilling arrangements are reported net of recovered costs and reflected as revenue in oil and gas well drilling operations, whereas the revenues under the footage-based arrangements were recorded gross of related expenses.  For the year ended December 31, 2006, the oil and gas well drilling segment’s results included $5.4 million in revenues and $10 million in expenses related to footage based arrangements.


Well Operations and Pipeline Income

In January 2007, we acquired all of the outstanding partnership interests in 44 of our sponsored drilling partnerships.  Having acquired 423 net wells pursuant to the acquisition, we no longer record income for operating these wells and related pipelines.  This decrease in revenue was offset in part by an increase in the number of new wells drilled and placed in service and pipeline systems we operate for our sponsored drilling partnerships as well as third parties.  In October 2007, in conjunction with the acquisition of oil and gas properties located in southwestern Pennsylvania, we acquired a well services operation.  The revenues related to this operation are included in the statement of operations line item Well Operations and Pipeline Income .

Gain on Sale of Leaseholds

In July 2006, we entered into a purchase and sale agreement with an unaffiliated party regarding the sale of our undeveloped leasehold located in the Grand Valley Field, Garfield County, Colorado, as filed with the Securities and Exchange Commission, or SEC, as Exhibit 10.3 to Form 10-Q for the period ended September 30, 2006.  Total proceeds from the sale were $353.6 million, of which we recognized a $328 million gain on sale of leasehold in the third quarter of 2006.

In May  2007, we entered into a letter agreement amending the above mentioned purchase and sale agreement, relieving us of our obligation, in its entirety, to either drill 16 wells or pay liquidated damages of $1.6 million per undrilled well.  As a result, we recognized the remaining deferred gain of $25.6 million in the second quarter of 2007.

In December 2007, we sold to the same unaffiliated party a portion of our North Dakota properties for approximately $34.7 million.  The properties, located in Dunn, Williams and McKenzie Counties, North Dakota, include interests in five producing Bakken wells and approximately 72,000 net undeveloped acres.  We recorded a gain on sale of leaseholds of $7.7 million in the fourth quarter of 2007.

Other Costs and Expenses

Exploration Expense

The following table sets forth the major components of exploration expense.

   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
   
(in thousands)
 
                   
Impairment of proved oil and gas properties
  $ 12,825     $ -     $ 1,510  
Amortization/impairment of unproved properties
    12,798       3,291       1,010  
Exploratory dry holes
    7,675       4,187       1,790  
Geological and geophysical costs
    2,121       6,299       2,234  
      35,419       13,777       6,544  
Operating and other
    9,686       9,774       1,587  
Total exploration expense
  $ 45,105     $ 23,551     $ 8,131  


We expanded exploratory drilling activities in 2005 and have generally believed that the additional risk and costs associated with exploratory drilling is justified by the potential to generate additional proved properties.  However, we plan to reduce exploratory drilling in 2009 given the current economic conditions and focus primarily on development activities in our proven fields.

We assess our proved oil and gas properties for possible impairment 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 we reasonably estimate the commodity 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.  We assess our unproved oil and gas properties for possible impairment by field based on our historical experience, current market data, acquisition dates, average lease terms and the probability of being drilled.


We recognized impairment losses on proved oil and gas properties of $12.8 million in 2008, consisting of $7.5 million related to our properties in the Fort Worth Basin, $3 million in our Bakken Field in North Dakota and $2.3 million in our Nesson Field, also in North Dakota.    We also recognized impairment losses of unproved properties of $12.9 million, consisting primarily of $7.3 million related to our unproved properties in the Fort Worth Basin and amortization of approximately $5.6 million related to all of our other areas of operations.  The $7.7 million of exploratory dry holes relates primarily to two Michigan wells, one New York well and one Colorado well.

In 2007, exploration expense includes $2.7 million of liquidated damages associated with the abandonment of an exploration agreement with an unaffiliated party and $1.1 million related to the write-off of the carrying value of the related acreage, $6.3 million in geological and geophysical costs related to seismic evaluation of various exploratory prospects and increased payroll and payroll related costs and other exploratory department costs.

In 2006, exploration expense includes $1.8 million related to one exploratory dry hole, $1.5 million related to an impairment charge on our Nesson Field in North Dakota and $2.2 million in geological and geophysical costs related to the seismic evaluation of our Northeast Colorado properties.

General and Administrative Expense

General and administrative expense has increased for the third consecutive year.  However, 2008 is considered pivotal because the rate of increase is declining and we expect this trend to continue in 2009.  It is this trend that we expect to continue in 2009.  General and administrative expenses have been declining on a per Mcfe basis, from $1.12 per Mcfe in 2006 to $1.11 per Mcfe in 2007 and $0.97 per Mcfe in 2008.

The increase in general and administrative expense in 2008 compared to 2007 was primarily due to increased payroll and payroll related expenses, which includes $4.7 million related to agreements with two former executive officers: $3.2 million related to a separation agreement with our former president and $1.5 million related to an agreement for the retirement of our former chief executive officer.  This increase was partially offset by a $2 million decrease in audit fees and a decrease in various other general and administrative expenses.

The increase in general and administrative expense in 2007 compared to 2006 was primarily due to increased costs related to increased payroll and payroll related expenses, which includes stock-based compensation expense related to the recruitment of professionals and key personnel in 2007.  The increase in management personnel is attributable to the growth we are experiencing, the increase in the cost of recruiting and the higher compensation required to obtain experienced oil and gas personnel.  We also experienced higher financial statement audit costs related to the late filing of our 2006 Form 10-K, higher compliance costs with the various provisions of the Sarbanes-Oxley Act, increased accounting assistance from third party consulting services and increased legal costs.

Depreciation, Depletion and Amortization

DD&A expense includes depreciation and amortization expense related of non-oil and natural gas properties as well as oil and natural gas properties.  DD&A expense for non-oil and natural gas properties was $7.6 million, $4.3 million and $2 million in 2008, 2007 and 2006, respectively.  DD&A expense related to oil and natural gas properties is directly related to reserves and production volumes.  DD&A expense is primarily based upon year-end proved developed producing oil and gas reserves.  These reserves are priced at the price of oil and natural gas as of December 31 each year.  If prices increase, the corresponding volume of oil and gas reserves will increase, resulting in decreases in the rate of DD&A per unit of production.  If prices decrease, as they did from 2007 to 2008, volumes of oil and gas reserves will decrease resulting in increases in the rate of DD&A per unit of production.  See Note 18 , Supplemental Oil and Gas Information – Unaudited , to our accompanying consolidated financial statements, for the average December 31 oil and natural gas prices used to determine year-end reserves and other reserve information.  The cost to acquire acreage, drill, complete and equip new wells have risen significantly over the past five years along with oil and natural gas prices and is a major contributing factor for the increased DD&A rate in the table below:
 

DD&A rates for our oil and gas properties are shown in the table below.

   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
   
(per Mcfe)
 
                   
Appalachian Basin (1)
  $ 1.55     $ 1.32     $ 1.13  
Michigan Basin
    1.35       1.28       0.83  
                         
Rocky Mountain Region:
                       
Wattenberg Field (2)
    3.47       2.99       2.34  
Piceance Basin (3)
    2.04       2.27       1.83  
NECO
    1.45       1.45       1.26  
                         
Weighted average
    2.51       2.37       1.87  
______________
 
(1)
The increase in DD&A rate for the Appalachian Basin in 2008 was due to the higher market price of a fourth quarter 2007 acquisition of 752 wells in southwestern Pennsylvania and the new wells drilled in 2008.
 
(2)
Although the Wattenberg Field development costs and DD&A rates are higher than the other fields, the relative value of its oil production currently more than offsets this cost difference.  The Wattenberg Field has produced volumes in excess of 85% of our total oil production in each of the years in the three-year period ended December 31, 2008.
 
(3)
The decrease in DD&A rates for the Piceance Basin in 2008 compared to 2007 is the result of higher year-end 2008 oil and natural gas reserves, due primarily to the improvements in drilling and completion technology and expanded pipeline and compression capacity.

Non-Operating Income/Expense

Interest Income .  The decreases in our interest income in 2008 and 2007 were the result of lower cash balances earning interest compared to 2006.  In July 2006, we received $353.6 million in cash proceeds from the sale of undeveloped leaseholds.  These proceeds earned interest income until reinvested in oil and gas properties in January 2007.

Interest Expense .  The increases in our interest expense were primarily due to significantly higher average outstanding balances of our credit facility and, in 2008, our 12% senior notes offset in part by lower average interest rates in our bank credit facility.  The average long-term debt in 2008 was $275.9 million compared to $132.5 million in 2007.    Interest expense is net of capitalized interest.  Interest costs capitalized in 2008, 2007 and 2006 were $2.6 million, $3 million and $1.6 million, respectively.  We have historically utilized our daily cash balances to reduce our line of credit borrowings, thereby lowering our interest costs.

Provision for Income Taxes

Our 2008 effective income tax rate was 35.2% in 2008 compared to 38.7% in 2007 and 38.6% in 2006.  This reduced rate reflects second and third quarter discrete benefits of $1.4 million for each period, related principally to the implementation of state tax strategies during each respective quarter.  The impact of these strategies also affected our rate used to establish deferred taxes and resulted in a deferred tax benefit of $1 million in 2008.

Our effective tax rate, excluding the effect of discrete items, for 2008 was 37.3%, which was virtually unchanged from 2007 and slightly less than the 2006 rate of 38.4%.  In 2008, the rate decreased primarily due to a 0.5% reduction in our effective state tax rate due to the benefit being realized from our implemented state tax planning strategies and a 0.7% reduction primarily related to reduced tax penalties.  However, these 2008 rate decreases were offset by our permanent tax deductions resulting in a proportionately smaller effective rate benefit of 0.8% compared to 1.8% in 2007.  In 2006, our permanent tax deduction for percentage depletion resulted in a proportionately smaller tax rate benefit of only 0.1%.


Liquidity and Capital Resources

Cash flow from operations and our bank credit facility are the primary sources of liquidity for us to satisfy our operating expenses and fund our capital expenditures.  We had $180.5 million of available borrowing capacity under our $375 million bank credit facility as of December 31, 2008.  Cash provided by operating activities was $139.1 million for the current year period compared to $60.3 million in the prior year period.  The $78.8 million increase in the current year period was primarily due to higher natural gas and oil prices through mid-2008 and higher volumes of oil and natural gas production and realized derivative gains primarily in the fourth quarter of 2008.  Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding non-cash items which are primarily depreciation, depletion and amortization and unrealized gains and losses on derivative transactions.  See the discussion under Results of Operations .  Cash flow used in investing activities increased $55.6 million, or 21%, from $267.4 million for the year ended 2007 to $323 million in 2008.  Substantially all of our investing activity involved drilling for oil and gas reserves during 2008.  Cash flows provided from financing activities increased $52.6 million, or 54%, from $97.5 million to $150.1 million for the years ended December 31, 2007 and 2008, respectively.  This increase was primarily due to the increase in proceeds from the issuance of our 12% senior notes of $200 million offset by net repayments on our bank credit facility.

Changes in market prices for oil and natural gas, our ability to increase production, the impact of realized gains and losses on our oil and natural gas derivative instruments and changes in costs are the principal determinants of the level of our cash flow from operations.  Oil and natural gas sales for the year ended December 31, 2008, were approximately 85% higher than the prior year, resulting from a 34% increase in average oil and natural gas prices and a 38% increase in oil and natural gas production.  While a decline in oil and natural gas prices would affect the amount of cash from operations that would be generated, we have oil and natural gas derivative positions in place, as of the date of this filing, covering 52% of our expected oil production and 62% of our expected natural gas production in 2009, at average prices of $90.52 per Bbl and $7.25 per Mcf, respectively.  These contracts reduce the impact of price changes for a substantial portion of our 2009 cash from operations.

Our primary use of funds is for capital expenditures.  As a result of the current unstable conditions in the commodity and financial markets, we have significantly reduced our planned 2009 capital expenditures to a range of $120 million to $140 million which represents an approximate 60% decrease from our 2008 capital expenditures.  With this reduction, we estimate our 2009 production will increase by approximately 15% over 2008 in part due to increased production from wells drilled in the latter part of 2008.  We believe, based on the current commodity price environment, our cash flow from operations will fund our reduced 2009 capital spending program allowing us to remain debt neutral during 2009.  We expect to manage capital expenditures within our cash flow from operations in 2009 and for the foreseeable future until commodity prices and capital markets are more favorable.  In order to continue to maintain or grow our production, we will need to commit greater amounts of capital in 2010 and beyond.  If capital is not available or is constrained in the future, we will be limited to our cash flow from operations and liquidity under our credit facility as the sources of funding for our capital expenditures.  Oil and gas produced from our existing properties declines rapidly in the first two years of production.  We could not maintain our current level of oil and gas production and cash flow from operations if capital markets and commodity prices remain in their current depressed state for a prolonged period beyond 2009, which would have a material negative impact on our operations in 2010 and beyond.

We considered the possibility of a reduced available liquidity environment in planning our 2009 drilling program and believe we will have adequate cash flow from operations during the year to execute our planned capital expenditures without drawing additional funds from our credit facility.  Currently, we operate approximately 95% of our properties, allowing us to control the pace of substantially all of our planned capital expenditures.  Consequently, a substantial portion of our planned capital expenditures for 2009 and beyond could be deferred if market conditions worsen.

In addition to deferring capital expenditures to reduce borrowings under our credit facility, other sources of liquidity include the fair value of our oil and natural gas derivative positions, excluding the derivative positions attributed to our affiliated partnerships, of $117.8 million as well as our available cash balance which was $51 million as of December 31, 2008.
 
We have one significant future drilling commitment along with certain volume delivery requirements that will require us to expend $60 million in development drilling on our Wattenberg leases through 2011, provided that our counterparty in the agreement expands two gas processing facilities and maintains certain wellhead pressures by June 30, 2010.  Our 2009 capital expenditure plan includes approximately $50 million related to this commitment.  Failure to meet our drilling commitment would result in a maximum payment to the counterparty of $15 million in 2012; failure to meet our volume delivery commitments by December 31, 2012, would result in a maximum payment to the counterparty of $10 million in 2013.  Failure of the counterparty to complete the required plant expansions results in a waiver of our $60 million capital and volume delivery requirements.
 
 
We have experienced no impediments in our ability to access borrowings under our current bank credit facility. We continue to monitor market events and circumstances and their potential impacts on each of the thirteen lenders that comprise our bank credit facility.  Our $375 million bank credit facility borrowing base is subject to size redeterminations each April and October based upon a quantification of our proved reserves   at each December 31st and June 30th, respectively.  A commodity price deck reflective of the current and future commodity pricing environment is utilized by our lenders to quantify our reserve reports and determine the underlying borrowing base.  We will be subject to a borrowing base redetermination in April 2009.

We increased our borrowing base in July 2008, and again in November 2008, to $300 million and $375 million respectively.  The increases were driven primarily by increases in proved producing reserves from drilling operations.  While we have continued to add producing reserves since our November 2008 redetermination, we believe the significant decrease in commodity prices and turmoil in the credit markets could have a negative impact on our borrowing base at our next redetermination in April 2009.  Our credit facility matures in November 2010, and is payable in full at that time.  We have begun discussions with our bank group with the intent of renewing the credit facility prior to November 1, 2009.  There is no assurance all of the lenders in our credit facility will participate in the renewal and there is no assurance that our borrowing base will not be reduced from its current level as a result of the renewal or the loss of one or more lenders in our credit facility.  Further, costs of capital have increased since we last amended our credit facility and we expect that interest and commitment fees under a new facility will be higher than in our current credit facility.  See Note 6 , Long Term Debt , to the accompanying consolidated financial statements.  At December 31, 2008, we had $180.5 million available for borrowing under our $375 million credit facility.  While we believe our borrowing base could be reduced as a result of redeterminations, we believe that producing reserves added since our last redetermination and our oil and natural gas derivative positions in place could mitigate the risk of a significant decrease in our borrowing base in 2009.  We also believe that while costs of capital have increased for credit facilities like ours, the impact of an increase in interest and commitment fees on our outstanding balance and commitments will not have a material adverse effect on our liquidity in 2009.  Our credit facility matures in November 2010.  If economic conditions deteriorate further in 2009 and 2010, our ability to renew our credit facility and provide adequate liquidity to continue our drilling programs could be negatively impacted in 2010 and beyond.

We are subject to quarterly financial debt covenants on our bank credit facility.  Our key credit facility debt covenants require that we maintain: 1) total debt of less than 3.75 times earnings before interest, taxes, depreciation, amortization and capital expenditures (“EBITDAX”) and 2) an adjusted working capital ratio of at least 1.0 to 1.0.  As of December 31, 2008, our total debt was 1.5 times EBITDAX and our adjusted working capital ratio was 1.6   to 1.0.  Our adjusted working capital ratio is calculated by reducing our current assets and liabilities by any impact of recording the fair value of our oil and gas derivative instruments and adding our available borrowings on our bank credit facilities to our current assets.  In addition, the impact of any current portion of our debt is eliminated from the current liabilities.  Therefore, any change in our available borrowings under our credit facility impacts our working capital ratio.

We believe we have sufficient liquidity and capital resources to conduct our business and remain compliant with our debt covenants throughout 2009 based upon our 2009 cash flow projections, anticipated capital requirements, the discretionary nature of our capital expenditures and available capacity under our bank credit facility.  While current conditions in the financial markets are extremely difficult and illiquid, we have no current plans or requirements to raise capital through these markets. However, we cannot predict with any certainty the impact to our future business of any further disruption or deterioration in the financial markets.  We will continue to closely monitor our liquidity and the credit markets and may choose to access them opportunistically should conditions and capital market liquidity improve.

We filed a shelf registration statement on Form S-3 with the SEC on November 26, 2008. The shelf provides for an aggregate of $500 million, through the sale of debt securities, common stock or preferred stock, either separately or represented by depository shares, warrants and purchase contracts, as well as units that may include any of these securities or securities of other entities.  The shelf registration statement is intended to allow the Company to be proactive in its ability to raise capital should the need arise, and to have the flexibility to raise such funds in one or more offerings, subject to market conditions.  This shelf registration statement was declared effective by the SEC on January 30, 2009.  There are no immediate plans to raise any funds and there is no assurance that we will be able to secure any such funds should the need arise.
 
See Item 7A, Quantitative and Qualitative Disclosure about Market Risk , for our discussion of credit risk.

Contractual Obligations and Contingent Commitments

The table below sets forth our contractual obligations and contingent commitments as of December 31, 2008:

   
Payments due by period
 
Contractual Obligations and Contingent Commitments (1)
 
Total
   
Less than
1 year
   
1-3
years
   
3-5
years
   
More
than
5 years
 
   
(in thousands)
 
Long-Term Debt   (2)
  $ 394,867     $ -     $ 194,500     $ -     $ 200,367  
Interest   on long-term debt (2)
    238,955       33,398       56,352       73,080       76,125  
Operating leases
    5,840       2,687       2,726       383       44  
Asset retirement obligations
    23,086       50       100       100       22,836  
Rig commitments (3)
    15,859       12,091       3,768       -       -  
Capital expenditure commitments (4)
    71,800       -       70,000       -       1,800  
Derivative contracts (5)
    10,486       4,766       (6,197 )     11,917       -  
Partnership derivative contracts (6)
    13,944       3,808       10,136       -       -  
Production tax liability
    43,948       18,226       25,722       -       -  
Firm transportation, sales and processing agreements (7)
    217,495       8,391       37,490       50,333       121,281  
Other liabilities (8)
    8,380       446       1,240       1,240       5,454  
Total
  $ 1,044,660     $ 83,863     $ 395,837     $ 137,053     $ 427,907  

__________
 
(1)
Table does not include deferred income tax obligations to taxing authorities of $190.9 million and maximum annual repurchase obligations to investing partners of $15.9 million as of December 31, 2008 due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.
 
(2)
Amounts presented for long term debt consist of amounts related to our 12% senior notes and our outstanding credit facility. The interest on long term debt includes $222.3 million payable to the holders of our 12% senior notes and $16.7 million related to our outstanding balance of $194.5 million on our credit facility as of December 31, 2008, based on an imputed interest rate of 4.65%.
 
(3)
Drilling rig commitments in the above table reflect our maximum obligation and does not include future adjustments to daily rates as provided for in the agreements as such increases are not predictable and are only included in the above obligation table upon notification to us by the contractor of an increase in the rate . Further, our rig commitment above includes $5.1 million related to a rig sublet to a third party and remains our obligation should the third party default on terms of the sublet agreement.
 
(4)
Primarily represents our capital expenditure commitment related to certain drilling and development agreements.  See Note 8 , Commitments and Contingencies, to our accompanying consolidated financial statements.  These amounts do not include advances for future drilling contracts totaling $1.7 million at December 31, 2008.
 
(5)
Represents our gross liability related to the fair value of derivative positions, including the fair value of derivative contracts we entered into on behalf of our affiliated partnerships as the managing general partner.  We have a related receivable from the partnerships of $1.6 million as of December 31, 2008.
 
(6)
Represents our affiliated partnerships’ share of the fair value of our gross derivative assets at December 31, 2008.
 
(7)
Represents our gross commitment, including amounts for volumes transported or sold on behalf of our affiliated partnerships and other working interest owners.  We will recognize in our financial statements our proportionate share based on our working and net revenue interest.
 
(8)
Includes funds held from revenue distribution to third party investors for plugging liabilities related to wells we operate and deferred officer compensation.

As managing general partner of 33 partnerships ( see Item 1 . Business – Drilling and Development Conducted for Company Sponsored Partnerships) , we have liability for any potential casualty losses in excess of the partnership assets and insurance.   We believe that the casualty insurance coverage we and our subcontractors carry is adequate to meet this potential liability.

For information regarding our legal proceedings, see Note ­8 , Commitments and Contingencies – Litigation, and Note 17 , Subsequent Events , to our accompanying consolidated financial statements included in this report.  From time to time we are a party to various other legal proceedings in the ordinary course of business.  We are not currently a party to any litigation that we believe would have a materially adverse affect on our business, financial condition, results of operations, or liquidity.

Critical Accounting Policies and Estimates

 We have identified the following policies as critical to business operations and the understanding of our results of operations.  This is not a comprehensive list of all of the accounting policies.  In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting principles generally accepted in the U.S., with no need for our judgment in the application.  There are also areas in which our 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 we may use significant judgment in the application; as a result, they are subject to an inherent degree of uncertainty.  In applying those policies, we use our judgment to determine the appropriate assumptions to be used in the determination of certain estimates.  Those estimates are based on historical experience, 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 , to our accompanying consolidated financial statements.  Our critical accounting policies and estimates are as follows:

Revenue Recognition

Oil and natural gas sales .  Sales of oil are recognized when persuasive evidence of a sales arrangement exists, the oil is verified as produced and is delivered to a purchaser, collection of revenue from the sale is reasonably assured and the sales price is determinable.  We are currently able to sell all the oil that we can produce under existing sales contracts with petroleum refiners and marketers.  We do not refine any of our oil production.  Our crude oil production is sold to purchasers at or near our wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry.

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 us under contracts with terms ranging from one month to three years.  Virtually all of our 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, our revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase.  We believe that the pricing provisions of our natural gas contracts are customary in the industry.


 We currently use the “net-back” method of accounting for transportation arrangements of natural gas sales.  We sell gas at the wellhead and collect a price and recognize 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.

Natural gas marketing activities .  Natural gas marketing is reported on the gross accounting method, based on the nature of the agreements between RNG, our suppliers and our customers.  RNG, our marketing subsidiary, purchases gas from PDC and other 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 gains and losses 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.

Oil and gas well drilling operations .  Our drilling segment recognizes revenue from drilling contracts with sponsored drilling programs using the percentage of completion method based upon the percentage of contract costs incurred to date to the estimated total contract costs for each contract.  We utilize this method since reasonably dependable estimates of the total estimated costs can be made and recognized revenues are subject to revisions as a contract progresses, the term of which can range from three to twelve months.  We have offered our drilling services under two types of contractual arrangements, cost-plus or footage-based service contracts, which result in differing risk and reward relationships and, consequently, different revenue reporting policies pursuant to Emerging Issues Task Force, or EITF, Issue No. 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent .

The first cost-plus drilling service arrangement was entered into in late 2005 with drilling activity commencing in the first quarter of 2006.  Due to the fixed-fee-percentage nature of our revenues from these services, we have determined that, in substance, we are acting as an agent, without risk of loss during the performance of the drilling activities.  Accordingly, our services provided under the cost-plus drilling agreements are reported on a net basis.  We entered into our second and third cost-plus drilling arrangements in September 2006 and August 2007 and commenced drilling immediately.  Footage-based contracts provide for the drilling, completion and equipping of wells at footage rates and are generally completed within nine to twelve months after the commencement of drilling.  We provide geological, engineering, and drilling supervision on the drilling and completion process and use subcontractors to perform drilling and completion services at a fixed footage-based rate and accordingly have the risk of loss in performing services under these arrangements.  Accordingly, we report revenue under these agreements gross of related expenses.  Anticipated losses, if any, on uncompleted contracts are recorded at the time that the estimated total costs exceed the estimated total contract revenue.  At December 31, 2007, we had recorded a loss contract reserve of $0.2 million.  There was no loss contract reserve as of December 31, 2008 .

Well operations and pipeline income .  Well operations and pipeline income are 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.  We are paid a monthly operating fee for each well we operate for outside owners including the limited partnerships we sponsor.  The fee covers monthly operating and accounting costs, insurance and other recurring costs.  We may also receive additional compensation for special non-recurring activities, such as reworks and recompletions.

Fair Value of Financial Instruments

We adopted the provisions of Statement of SFAS No. 157, Fair Value Measurements, effective January 1, 2008.  SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures related to fair value measurements. SFAS No. 157 applies broadly to financial and nonfinancial assets and liabilities that are measured at fair value under other authoritative accounting pronouncements, but does not expand the application of fair value accounting to any new circumstances.  In February 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) FAS No. 157-2, Effective Date of FASB Statement No. 157, which delays the effective date of SFAS No. 157 by one year (to January 1, 2009) for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).  Nonfinancial assets and liabilities for which we have not applied the provisions of SFAS No. 157 include those initially measured at fair value, including our asset retirement.

Derivative Financial Instruments .

We use derivative instruments to manage our commodity and financial market risks.  We currently do not use hedge accounting treatment for our derivatives.  Derivatives are reported on our accompanying consolidated balance sheets at fair value on a gross asset and liability basis.  Changes in fair value of derivatives are recorded in oil and gas price risk management, net, in our accompanying consolidated statements of income.

SFAS No. 157 establishes a fair value hierarchy that requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.  The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3).  In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy.  The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy.  Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.  The three levels of inputs that may be used to measure fair value are defined as:

 
 
Level 1 – Quoted prices (unadjusted) in active markets for identical assets or liabilities.  Instruments included in Level 1 consist of our commodity derivatives for New York Mercantile Exchange (“NYMEX”)-based natural gas swaps.

 
 
Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability and (iv) inputs that are derived from observable market data by correlation or other means.

 
 
Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.  Instruments included in Level 3 consist of our commodity derivatives for Colorado Interstate Gas (“CIG”) and Panhandle Eastern Pipeline (“PEPL”)-based natural gas swaps, oil swaps, natural gas basis protection swaps, oil and natural gas options, and physical sales and purchases.

We measure fair value of our derivatives based upon quoted market prices, where available.  Our valuation determination includes: (1) identification of the inputs to the fair value methodology through the review of counterparty statements and other supporting documentation, (2) determination of the validity of the source of the inputs, (3) corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions.  The methods described above may produce a fair value calculation that may not be indicative of future fair values.  Our valuation determination also gives consideration to our nonperformance risk on our own liabilities as well as the credit standing of our counterparties.  We primarily use two investment grade financial institutions as our counterparties to our derivative contracts.  We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position.  Based on our evaluation, we have determined that the impact of the nonperformance of our counterparties on the fair value of our derivative instruments is insignificant.   As of December 31, 2008, no valuation allowance was recorded.   Furthermore, while we believe these valuation methods are appropriate and consistent with that used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.  We estimated the gross net fair value of our commodity based derivatives as of December 31, 2008, to be $153.5 million.

Non-Derivative Financial Assets and Liabilities.

The carrying values of the financial instruments comprising cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximate fair value due to the short-term maturities of these instruments.

The portion of our long-term debt related to our credit facility, approximates fair value due to the variable nature of its related interest rate.  We estimate the fair value of the portion of our long-term debt related to our senior notes to be approximately $127 million or approximately 62.5% of par value as of December 31, 2008.  We determined this valuation based upon measurements of trading activity and quotes provided by brokers and traders participating in the trading of the securities.
 
Oil and Gas Properties

 We account for our 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 capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing oil and natural gas reserves.  Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved oil and gas reserves.


Our estimates of proved reserves are based on quantities of oil and natural gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic conditions.  Annually, we engage independent petroleum engineers to prepare a reserve and economic evaluation of all our properties on a well-by-well basis as of December 31.  Additionally, we adjust our oil and gas reserves for major acquisitions, new drilling and divestitures during the year as needed.  The process of estimating and evaluating oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data.  The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions.  As a result, revisions in existing reserve estimates occur from time to time.  Although every reasonable effort is made to ensure that reserve estimates reported represent our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time.  Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves could have an effect on our net income.

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 our completion as a producing well and we are making sufficient progress assessing our 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 the financial statements, the costs incurred prior to the end of the reporting period are expensed to exploration costs.  If we are unable to make a final determination about the productive status of a well prior to issuance of the 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.  At December 31, 2008 and 2007, suspended well costs included in oil and gas properties on our accompanying consolidated financial statements was $1.2 million and $2.3 million, respectively.

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 exploration 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 our historical experience, acquisition dates and average lease terms.  The valuation of unproved properties is subjective and requires us to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values.

In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets , we assess our oil and gas properties for possible impairment 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 we reasonably estimate the commodity to be sold.  The estimates of future prices may differ from current market prices of oil and natural gas.  Any downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future net cash flows and an impairment of our oil and gas properties.  Although our cash flow estimates 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.

Deferred Income Tax Asset Valuation Allowance
 
Deferred income 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 is established.  The factors which we consider in assessing whether we will realize the value of deferred income tax assets involve judgments and estimates of both amount and timing, which could differ from actual results, achieved in future periods.

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

Accounting for Acquisitions Using Purchase Accounting

We account for acquisitions utilizing the purchase method as prescribed by SFAS No. 141, Business Combinations .  Pursuant to purchase method accounting, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date.  The purchase price allocations are based on appraisals, discounted cash flows, quoted market prices and estimates by management.  In addition, when appropriate, we review comparable purchases and sales of oil and gas properties within the same regions, and use that data as a basis for fair market value; for example, the amount a willing buyer and seller would enter into an exchange for such properties.


In estimating the fair values of assets acquired and liabilities assumed we made various assumptions.  The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved oil and gas properties.  To estimate the fair values of these properties, we prepared estimates of oil and gas reserves.  We estimated future prices to apply to the estimated reserve quantities acquired, and estimated future operating and development costs, to arrive at estimates of future net revenues.  For estimated proved reserves, the future net revenues were discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition.  The market-based weighted average cost of capital rate was subjected to additional project-specific risking factors.  To compensate for the inherent risk of estimating and valuing unproved properties, the discounted future net revenues of probable and possible reserves were reduced by additional risk-weighting factors.

Deferred taxes must be recorded for any differences between the assigned values and tax basis of assets and liabilities.  Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

Recent Accounting Standards

See Note 1 , Summary of Significant Accounting Policies - Recent Accounting Standards , to our accompanying consolidated financial statements.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.

Market-Sensitive Instruments and Risk Management

We are exposed to market risks associated with interest rates, commodity prices and credit exposure.  Management has established risk management processes to monitor and manage these market risks.

Interest Rate Risk

Changes in interest rates affect the amount of interest we earn on our cash, cash equivalents and restricted cash and the interest we pay on borrowings under our bank credit facility.  Our 12% senior notes are fixed rate and, therefore, do not expose us to the cash flow loss due to changes in market interest rate.  However, changes in interest rates do affect the fair value of our senior notes.

Our interest-bearing cash and cash equivalents include our money market accounts, short-term certificates of deposit and checking and savings accounts with various banks.  The amount of our interest-bearing cash and cash equivalents as of December 31, 2008, was $78.8 million with an average annual interest rate of 1.8%.

Based on a sensitivity analysis of the credit facility borrowings as of December 31, 2008, it was estimated that if market interest rates were to average 1% higher (lower) in 2009 than in 2008, our interest expense, net of tax, would increase (decrease) by approximately $1.3 million.

Commodity Price Risk

See Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation, Critical Accounting Policies and Estimates-Accounting for Derivatives Contracts at Fair Value , for further discussion of the accounting for derivative contracts.

We are exposed to the effect of market fluctuations in the prices of oil and natural gas as they relate to our oil and natural gas sales and marketing activities.  Price risk represents the potential risk of loss from adverse changes in the market price of oil and natural gas commodities.  We employ established policies and procedures to manage the risks associated with these market fluctuations using commodity derivatives.  Our policy prohibits the use of oil and natural gas derivative instruments for speculative purposes.

Validation of a contract’s fair value is performed internally and while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values.  While we believe these valuation methods are appropriate and consistent with those used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

Economic Hedging Strategies.   Our results of operations and operating cash flows are affected by changes in market prices for oil and natural gas.  To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative contracts.  As of December 31, 2008, our oil and natural gas derivative instruments consisted of (i) NYMEX-based natural gas contracts for Appalachian and Michigan production, (ii) PEPL-based contracts for NECO production, (iii) CIG-based contracts for other Colorado production and (iv)  NYMEX-based crude oil contracts for our Colorado oil production.


 
·
For swap instruments, we receive a fixed price for the derivative contract and pay a floating market price to the counterparty.  The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

 
·
Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point.  For CIG basis protection swaps, which have negative differentials to NYMEX, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract.

 
·
Collars contain a fixed floor price (put) and ceiling price (call).  If the market price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and market price to the counterparty.  If the market price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and market price from the counterparty.  If the market price is between the call and the put strike price, no payments are due from either party.


With regard to our natural gas marketing activities, we enter into fixed-price physical purchase and sale agreements that are derivative contracts.  In order to offset these fixed-price physical derivatives, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative.  While these derivatives are structured to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price changes in the physical market.  We believe our derivative instruments continue to be effective in achieving the risk management objectives for which they were intended.

The following table presents monthly average NYMEX and CIG closing prices for oil and natural gas in 2008 and 2007, as well as average sales prices we realized for the respective commodity.

   
Year Ended December 31,
 
   
2008
   
2007
 
             
Average Index Closing Price
           
Natural Gas (per MMbtu)
           
CIG
  $ 6.22     $ 3.97  
NYMEX
    9.04       6.89  
                 
Oil (per Barrel)
               
NYMEX
    104.42       69.79  
                 
Average Sales Price
               
Natural Gas
    6.98       5.33  
Oil
    89.77       60.65  

Based on a sensitivity analysis as of December 31, 2008, it was estimated that a 10% increase in oil and natural gas prices, inclusive of basis, over the entire period for which we have derivatives currently in place would have resulted in an increase in fair value of $13.7 million and a 10% decrease in oil and natural gas prices would have resulted in an increase in fair value of $49.4 million.

See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Results of Operations, Oil and Gas Price Risk Management, Net and Natural Gas Marketing Activities , for a detailed discussion of the our open derivative positions related to our oil and gas sales activities and our natural gas marketing activities.  See Note 3 , Derivative Financial Instruments , to our accompanying consolidated financial statements included in this report for a summary of our open derivative positions as of December 31, 2008.

Credit Risk

Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations.  We attempt to reduce credit risk by diversifying our counterparty exposure and entering into transactions with high-quality counterparties.  When exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis.  We have had no counterparty default losses.


Our receivables are from a diverse group of companies, including major energy companies, both upstream and mid-stream, financial institutions and end-users in various industries related to our gas marketing group.  We monitor their creditworthiness through credit reports and rating agency reports.

Our commodity-based derivative contracts expose us to the credit risk of nonperformance by the counterparty to the contracts.  These contracts consist of fixed price swaps, basis swaps and collars.  We primarily use two investment grade financial institutions as our counterparties to our derivative contracts who are also major lenders in our credit facility arrangement.  We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position.  Based on our evaluation, we have determined that the impact of the nonperformance of our counterparties on the fair value of our derivative instruments is insignificant.   As of December 31, 2008, no valuation allowance was recorded.

The recent disruption in the credit market has had a significant adverse impact on a number of financial institutions.  We monitor the creditworthiness of the financial institutions with which we transact, giving consideration to the reports of credit agencies and their related ratings.  While we believe that our monitoring procedures are sufficient and customary, no amount of analysis can guarantee performance in these uncertain times.

Disclosure of Limitations

Because the information above included only those exposures that exist at December 31, 2008, it does not consider those exposures or positions which could arise after that date.  As a result, our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our 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.

Index to financial statements.

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

As reported on Form 8-K filed with the SEC on May 31, 2007, and incorporated herein by reference, the Audit Committee of our Board of Directors recommended, and the Board of Directors ratified, the dismissal of KPMG LLP as our principal accountants on May 24, 2007.

ITEM 9A.  CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, 2008, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Securities Exchange Act Rule 13a-15.  Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2008, to ensure that the information required to be disclosed by the Company in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC rules and forms, and that the information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

We made no changes in our 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 quarter ended December 31, 2008, that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

See Remediation of Material Weaknesses in Internal Control below for a discussion of changes in our internal control over financial reporting that occurred throughout 2008.


Remediation of Material Weaknesses in Internal Control

We, with oversight from the Audit Committee of our Board of Directors, have been addressing the material weaknesses disclosed in our 2007 Form 10-K and Item 4 of our subsequently filed Form 10-Q for each of the quarterly periods in the nine-month period ended September 30, 2008.  We have concluded, based on our assessment, that, through the implementation of the changes in internal controls over financial reporting described below, we have remediated these previously reported material weaknesses as of December 31, 2008.  Management’s annual report on internal control over financial reporting and the audit report on our internal control over financial reporting of our independent registered public accounting firm are included in response to Item 8 of this report on pages F-2 and F-3 included herein.

The remediation initiatives that were undertaken during 2008 include:

 
·
In the first quarter of 2008, we implemented the general ledger, accounts receivable, and joint interest billing modules as part of a new broader financial reporting system.  We have taken the necessary steps to monitor and maintain appropriate internal controls during this period of change.  These steps included providing training related to business process changes and the financial reporting system software to individuals using the financial reporting system to carry out their job responsibilities as well as those who rely on the financial information.  The implementation of the financial reporting system strengthened the overall internal controls due to enhanced automation and integration of related processes.  The design and documentation of internal control process and procedures relating to the new system has been modified to supplement and complement existing internal controls over financial reporting.

 
·
In the third quarter of 2008, we implemented controls over key financial statement spreadsheets that support all significant balance sheet and income statement accounts.  Specifically, we enhanced the spreadsheet policy to provide additional clarification and guidance with regard to risk assessment and enforced controls over: 1) the security and integrity of the data used in the various spreadsheets, 2) access to the spreadsheets, 3) changes to spreadsheet functionality and the related approval process and documentation and 4) increased managements review of the spreadsheets.

 
·
In the third quarter of 2008, key personnel attended an accredited derivative training course and a desktop procedure was implemented to ensure the completeness and accuracy over derivative activities, which supplemented the key controls that previously existed in the process.
    
ITEM 9B.  OTHER INFORMATION

None.
 
PART III
 

ITEM 10.  DIRECTORS , EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information called for by Item 10 is incorporated by reference from information under the captions entitled Corporate Governance , Section 16(a) Beneficial Ownership Reporting Compliance , Election of Directors and Executive Compensation and other relevant portions of our definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of our fiscal year.

ITEM 11.  EXECUTIVE COMPENSATION

The information called for by Item 11 is incorporated by reference from information under the caption entitled Executive Compensation and other relevant portions of our definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of our fiscal year.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information called for by Item 12 is incorporated by reference from information under the caption entitled Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters and other relevant portions of our definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of our fiscal year.


ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

The information called for by Item 13 is incorporated by reference from information under the captions entitled Certain Relationships and Related Transactions and Director Independence   in our definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of our fiscal year.

ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information called for by Item 14 is incorporated by reference from information under caption entitled Principal Accountant Fees and Services   and other relevant portions of our definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of our fiscal year.
 
PART IV
 

ITEM 15.  EXHIBITS , 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 56.

 
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/ Richard W. McCullough
 
Richard W. McCullough,
Chairman, Chief Executive Officer, and President
     
  By
/s/ Gysle R. Shellum
 
 
Gysle R. Shellum,
Chief Financial Officer
 
February 26, 2009

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/ Richard W. McCullough
    Richard W. McCullough
Chairman, Chief Executive Officer, and President (principal executive officer)
February 26, 2009
     
/s/ Gysle R. Shellum
    Gysle R. Shellum
Chief Financial Officer (principal financial officer)
February 26, 2009
     
/s/ Darwin L. Stump
    Darwin L. Stump
Chief Accounting Officer (principal accounting officer)
February 26, 2009
     
/s/ Daniel W. Amidon
    Daniel W. Amidon
General Counsel, Corporate Secretary
February 26, 2009
     
/s/ Steven R. Williams
    Steven R. Williams
Director
February 26, 2009
     
/s/ Jeffrey C. Swoveland
    Jeffrey C. Swoveland
Director
February 26, 2009
     
/s/ Vincent F. D'Annunzio
    Vincent F. D'Annunzio
Director
February 26, 2009
     
/s/ Kimberly Luff Wakim
    Kimberly Luff Wakim
Director
February 26, 2009
     
/s/ David C. Parke
    David C. Parke
Director
February 26, 2009
     
/s/  Anthony J. Crisafio
     Anthony J. Crisafio
Director
February 26, 2009

/s/  Joseph E. Casabona
     Joseph E. Casabona
Director
February 26, 2009
     
/s/  Larry F. Mazza
     Larry F. Mazza
Director
February 26, 2009


GLOSSARY OF OIL AND NATURAL GAS 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 equivalent.

CIG - Colorado Interstate Gas.

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

DD&A   - Refers to depreciation, depletion and amortization of our 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 we have 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 equivalent, 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 equivalent.

Net acres or wells - Refers to gross acres or wells multiplied, in each case, by the percentage working interest we own.

Net production - Oil and gas production that we own, less royalties and production due others.

NYMEX - New York Mercantile Exchange.

Oil - Crude oil or condensate.

Operator - The individual or company responsible for the exploration, development and/or production of an oil or gas well or lease.
 
 
PEPL - Panhandle Eastern Pipeline.

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) non-property related expenses such as general and administrative expenses, debt service and future income tax expense, or (iii) depreciation, depletion and amortization.

Proved developed non-producing 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 non-producing 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, or 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.

Recompletion - A recompletion occurs when we reenter a well to complete (i.e., perforate) a new formation different from that in which a well has previously been completed.

Refrac, or refracture – A refrac is when we stimulate the present producing zone of a well to increase production, using hydraulic, acid, gravel, etc. fracture techniques.

Reserve replacement - Calculated by dividing the sum of reserve additions from all sources (revisions, extensions, discoveries and other additions and acquisitions) by the actual production for the corresponding period.  The values used for reserve additions are derived directly from the proved reserves table located in Note 18 , Supplemental Oil and Gas information , to our consolidated financial statements included in this report.  We use the reserve replacement ratio as an indicator of our ability to replenish annual production volumes and grow our reserves, thereby providing some information on the sources of future production.  It should be noted that the reserve replacement ratio is a statistical indicator that has limitations.  As an annual measure, the ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions.  Its predictive and comparative value is also limited for the same reasons.  In addition, since the ratio does not imbed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.

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.

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.

 
 Exhibits Index

       
Incorporated by Reference
   
Exhibit Number
 
 
Exhibit Description
 
 
Form
 
SEC File Number
 
 
Exhibit
 
Filing Date
 
Filed Herewith
                         
3.1
 
Second Amended and Restated Certificate of Incorporation of Petroleum Development Corporation.
 
8-K
 
000-07246
 
3.1
 
07/23/2008
   
                         
3.2
 
Bylaws of Petroleum Development Corporation, amended and restated, effective October 11, 2007.
 
8-K
 
000-07246
 
3.2
 
10/17/2007
   
                         
4.1
 
Rights Agreement by and between Petroleum Development Corporation and Transfer Online, Inc., as Rights Agent, dated as of September 11, 2007, including the forms of Rights Certificates and Summary of Stockholder Rights Plan attached thereto as Exhibits A and B.
 
8-K
 
000-07246
 
4.1
 
09/14/2007
   
                         
4.2
 
Indenture dated as of February 8, 2008, by and among Petroleum Development Corporation and The Bank of New York.
 
8-K
 
000-07246
 
4.1
 
02/12/2008
   
                         
4.3
 
First Supplemental Indenture dated as of February 8, 2008, by and among Petroleum Development Corporation and the Bank of New York.
 
8-K
 
000-07246
 
4.2
 
02/12/2008
   
                         
4.4
 
Form of 12% Senior Note due 2018.
 
8-K
 
000-07246
 
4.3
 
02/12/2008
   
                         
10.1
 
Purchase Agreement dated as of February 1, 2008, by and among Petroleum Development Corporation and the Initial Purchasers of 12% senior notes due 2018 named therein.
 
8-K
 
000-07246
 
10.1
 
02/07/2008
   
                         
10.2
 
Registration Rights Agreement dated as of February 8, 2008, by and among Petroleum Development Corporation and the Initial Purchasers of 12% senior notes due 2018 named therein.
 
8-K
 
000-07246
 
10.1
 
02/12/2008
   
                         
10.3
 
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.
 
8-K
 
000-07246
 
10.1
 
11/04/2005
   
                         
10.4
 
First Amendment to Amended and Restated Credit Agreement, dated as of August 9, 2007, by an among Petroleum Development Corporation, certain of its subsidiaries, JPMorgan Chase Bank, N.A., BNP Paribas and Wachovia Bank, N.A.
 
8-K
 
000-07246
 
10.1
 
08/15/2007
   
                         
10.5
 
Second Amendment to Amended and Restated Credit Agreement, dated as of October 16, 2007, by and among Petroleum Development Corporation, certain of its subsidiaries, JPMorgan Chase Bank, N.A., BNP Paribas, Wachovia Bank, N.A., Guaranty Bank, FSB, Bank of Oklahoma and Morgan Stanley Bank.
 
8-K
 
000-07246
 
10.1
 
10/22/2007
   
                         
10.6
 
Third Amendment to Amended and Restated Credit Agreement dated as of July 15, 2008, by and among Petroleum Development Corporation, certain of its subsidiaries, JP Morgan Chase Bank, N.A., BNP Paribas and various other banks.
 
8-K
 
000-07246
 
10.1
 
07/21/2008
   
                         
10.7
 
Fourth Amendment to Amended and Restated Credit Agreement dated as of July 18, 2008, by and among the Company, certain of its subsidiaries, JP Morgan Chase Bank, N.A., BNP Paribas and various other banks.
 
8-K
 
000-07246
 
10.2
 
07/21/2008
   
                         
10.8
 
Fifth Amendment to Amended and Restated Credit Agreement dated as of November 12, 2008, by and among the Company, certain of its subsidiaries, JP Morgan Chase Bank, N.A., various other banks.
 
8-K
 
000-07246
 
10.1
 
11/19/2008
   

 
       
Incorporated by Reference
       
Exhibit Number
 
 
Exhibit Description
 
 
Form
 
SEC File Number
 
 
Exhibit
 
Filing Date
 
Filed Herewith
                         
 
Employment Agreement with Richard W. McCullough, Chief Executive Officer, dated as of December 31, 2008.
                 
X
                         
 
Employment Agreement with Eric R. Stearns, Executive Vice President, dated as of December 31, 2008.
                 
X
                         
 
Employment Agreement with Gysle R. Shellum, Chief Financial Officer, dated as of December 31, 2008.
                 
X
                         
 
Employment Agreement with Barton R. Brookman, Jr., Senior Vice President of Exploration and Production, dated as of December 31, 2008.
                 
X
                         
 
Employment Agreement with Daniel W. Amidon, General Counsel and Corporate Secretary, dated as of December 31, 2008.
                 
X
                         
 
Employment Agreement with Darwin L. Stump, Chief Accounting Officer, dated as of December 31, 2008.
                 
X
                         
10.15*
 
2008 Short-Term Incentive Compensation Terms for Executive Officers.
 
8-K
 
000-07246
     
03/28/2008
   
                         
10.16*
 
2008 Long-Term Incentive Program (as amended for 2008) for Executive Officers.
 
8-K
 
000-07246
 
10.1
 
03/13/2008
   
                         
10.17*
 
Non-Employee Director Compensation for the 2008-2009 Term.
 
8-K
 
000-07246
     
03/13/2008
   
                         
10.18*
 
2008 Base Salary and Short-Term Incentive Cash Bonus Program for Executive Officers.
 
8-K
 
000-07246
     
02/22/2008
   
                         
10.19*
 
2007 Long-Term Incentive Program for Executive Officers.
 
8-K
 
000-07246
 
10.1
 
04/13/2007
   
                         
10.20*
 
2006 Long-Term Equity Compensation Grants to Executive Officers.
 
8-K
 
000-07246
     
04/10/2007
   
                         
10.21*
 
Agreement with Steven R. Williams, Director.
 
10-Q
 
000-07246
 
10.3
 
11/06/2008
   
                         
 
Separation Agreement with Thomas E. Riley, former President.
                 
X
                         
10.23*
 
Indemnification Agreement with Directors and Officers.
 
10-Q
 
000-07246
 
10.1
 
08/09/2007
   
                         
10.24*
 
The Petroleum Development Corporation 401(k) & Profit Sharing Plan.
 
S-8
 
333-137836
 
4.1
 
10/05/2006
   
                         
10.25*
 
2005 Non-Employee Director Restricted Stock Plan amended and restated as of March 8, 2008.
 
10-Q
 
000-07246
 
10.6
 
11/06/2008
   
                         
 
2004 Long-Term Equity Compensation Plan amended and restated as of March 8, 2008.
                 
X
                         
10.27*
 
Non-Employee Director Deferred Compensation Plan.
 
S-8
 
333-118222
 
99.1
 
08/13/2004
   
                         
10.28*
 
1999 Incentive Stock Option and Non-Qualified Stock Plan.
 
S-8
 
333-111825
 
99.1
 
01/09/2004
   
                         
 
Code of Business Conduct and Ethics.
                 
X
                         
 
Subsidiaries.
                 
X
                         
 
Consent of PricewaterhouseCoopers LLP.
                 
X
                         
 
Consent of KPMG LLP.
                 
X
                         
 
Consent of Wright & Company, Inc., Petroleum Consultants.
                 
X
                         
 
Consent of Ryder Scott Company, L.P., Petroleum Consultants.
                 
X

 
       
Incorporated by Reference
       
Exhibit Number
 
 
Exhibit Description
 
 
Form
 
SEC File Number
 
 
Exhibit
 
Filing Date
 
Filed Herewith
                         
 
Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
                 
X
                         
 
Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
                 
X
                         
 
Certifications by Chief Executive Officer and Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002.
                 
X
____________
*Management contract or compensatory plan or arrangement.


PETROLEUM DEVELOPMENT CORPORATION


Index to Consolidated Financial Statements and Financial Statement Schedule


Management's Report on Internal Control Over Financial Reporting
F-2
   
Financial Statements:
 
Reports of Independent Registered Public Accounting Firms
F-3
Consolidated Balance Sheets - December 31, 2008 and 2007
F-5
Consolidated Statements of Operations - Years Ended December 31, 2008, 2007 and 2006
F-6
Consolidated Statements of Cash Flows - Years Ended December 31, 2008, 2007 and 2006
F-7
Consolidated Statements of Shareholders' Equity - Years Ended December 31, 2008, 2007 and 2006
F-8
Notes to Consolidated Financial Statements
F-9
   
Financial Statement Schedule:
 
Schedule II – Valuation and Qualifying Accounts and Reserves
F-48


PETROLEUM DEVELOPMENT CORPORATION


Management's Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) of the Exchange Act.  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.  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 policies or procedures may deteriorate.

Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008, based upon the criteria established in “Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).  Based on this evaluation, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2008.

The effectiveness of Petroleum Development Corporation's internal control over financial reporting as of December 31, 2008, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

 
PETROLEUM DEVELOPMENT CORPORATION
 
 /s/ Richard W. McCullough
 
Richard W. McCullough
 
Chairman and Chief Executive Officer
 
   
 /s/ Gysle R. Shellum
 
Gysle R. Shellum
 
Chief Financial Officer
 


PETROLEUM DEVELOPMENT CORPORATION


Report of Independent Registered Public Accounting Firm


To the Board of Directors and Shareholders
of Petroleum Development Corporation
 
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, shareholders' equity, and cash flows present fairly, in all material respects, the financial position of Petroleum Development Corporation and its subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.  In addition, in our opinion, the 2008 and 2007 information in the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.  Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, 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 these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting.  Our responsibility is to express opinions on these financial statements, on the 2008 and 2007 information in the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinion.
 
As discussed in Note 5 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions in 2007.
 
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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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.
 
/s/ PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania
February 26, 2009


PETROLEUM DEVELOPMENT CORPORATION

 
Report of Independent Registered Public Accounting Firm
 
The Board of Directors and Stockholders
Petroleum Development Corporation:
 
We have audited the accompanying consolidated statements of operations, shareholders’ equity, and cash flows of Petroleum Development Corporation and subsidiaries for the year ended December 31, 2006.  In connection with our audit of these consolidated financial statements, we also have audited the related financial statement schedule.  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 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 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 audit provides a reasonable basis for our opinion.
 
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and the cash flows of Petroleum Development Corporation and subsidiaries for the year ended December 31, 2006, 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 1 to the consolidated financial statements, the Company adopted the provisions of Statement of Financial Accounting Standards No. 123(R), (“Share-Based Payment”), in 2006.
 
As discussed in Note 1 to the consolidated financial statements, the Company changed its method of quantifying errors based on SEC Staff Accounting Bulletin No. 108 (“Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements”) in 2006.
 
 
KPMG LLP
 
Pittsburgh, Pennsylvania
May 22, 2007
 
 
PETROLEUM DEVELOPMENT CORPORATION
Consolidated Balance Sheets
(in thousands, except share and per share data)

December 31,
 
2008
   
2007
 
Assets
           
Current assets:
           
Cash and cash equivalents
  $ 50,950     $ 84,751  
Restricted cash - current
    19,030       14,773  
Accounts receivable, net
    69,688       60,024  
Accounts receivable - affiliates
    16,742       11,537  
Fair value of derivatives - current
    116,881       4,817  
Prepaid expenses and other current assets
    19,146       15,891  
Total current assets
    292,437       191,793  
Properties and equipment, net
    1,033,078       845,864  
Other assets
    77,189       12,822  
Total Assets
  $ 1,402,704     $ 1,050,479  
                 
Liabilities and Shareholders' Equity
               
Current liabilities:
               
Accounts payable
  $ 90,532     $ 88,502  
Accounts payable - affiliates
    40,540       3,828  
Production tax liability
    18,226       21,330  
Federal and state income taxes payable
    1,591       901  
Fair value of derivatives
    4,766       6,291  
Advances for future drilling contracts
    1,675       68,417  
Funds held for distribution
    50,361       39,823  
Net deferred income taxes - current
    28,355       -  
Other accrued expenses
    25,125       12,913  
Total current liabilities
    261,171       242,005  
Long-term debt
    394,867       235,000  
Net deferred income taxes - non current
    162,593       136,490  
Other liabilities
    71,798       40,699  
Total liabilities
    890,429       654,194  
                 
Commitments and contingent liabilities
               
                 
Minority interest in consolidated limited liability company
    694       759  
                 
Shareholders' equity:
               
Preferred shares, par value $.01 per share;  authorized 50,000,000 shares; issued:  none
    -       -  
Common shares, par value $.01 per share; authorized 100,000,000 shares; issued:  14,871,870 in 2008 and 14,907,679 in 2007
    149       149  
Additional paid-in capital
    5,818       2,559  
Retained earnings
    505,906       393,044  
Treasury shares, at cost: 7,066 shares in 2008 and 5,894 in 2007
    (292 )     (226 )
Total shareholders' equity
    511,581       395,526  
Total Liabilities and Shareholders' Equity
  $ 1,402,704     $ 1,050,479  


See accompanying Notes to Consolidated Financial Statements .

F-5

PETROLEUM DEVELOPMENT CORPORATION
Consolidated Statements of Operations
(in thousands, except per share data)
                   
Year Ended December 31,
 
2008
   
2007
   
2006
 
Revenues:
                 
Oil and gas sales
  $ 321,877     $ 175,187     $ 115,189  
Sales from natural gas marketing activities
    140,263       103,624       131,325  
Oil and gas well drilling
    7,615       12,154       17,917  
Well operations and pipeline income
    11,474       9,342       10,704  
Oil and gas price risk management gain, net
    127,838       2,756       9,147  
Other
    293       2,172       2,221  
Total revenues
    609,360       305,235       286,503  
                         
Costs and expenses:
                       
Oil and gas production and well operations cost
    78,209       49,264       29,021  
Cost of natural gas marketing activities
    139,234       100,584       130,150  
Cost of oil and gas well drilling
    2,213       2,508       12,617  
Exploration expense
    45,105       23,551       8,131  
General and administrative expense
    37,715       30,968       19,047  
Depreciation, depletion, and amortization
    104,575       70,844       33,735  
Total costs and expenses
    407,051       277,719       232,701  
                         
Gain on sale of leaseholds
    -       33,291       328,000  
                         
Income from operations
    202,309       60,807       381,802  
Interest income
    591       2,662       8,050  
Interest expense
    (28,132 )     (9,279 )     (2,443 )
                         
Income before income taxes
    174,768       54,190       387,409  
Provision for income taxes
    61,459       20,981       149,637  
                         
Net income
  $ 113,309     $ 33,209     $ 237,772  
                         
Earnings per common share:
                       
Basic
  $ 7.69     $ 2.25     $ 15.18  
Diluted
  $ 7.63     $ 2.24     $ 15.11  
                         
Weighted average common and common equivalent shares outstanding:
                       
Basic
    14,736       14,744       15,660  
Diluted
    14,848       14,841       15,741  


See accompanying Notes to Consolidated Financial Statements .

F-6

PETROLEUM DEVELOPMENT CORPORATION
Consolidated Statements of Shareholders' Equity
(in thousands, except share and per share data)

Year Ended December 31,
 
2008
   
2007
   
2006
 
Common stock, par value $.01 per share - shares issued:
                 
Shares at beginning of year
    14,907,679       14,834,871       16,281,923  
Adjust prior conversion of predecessor shares
    100       -       59,546  
Exercise of stock options
    25,699       38,000       8,000  
Issuance of stock awards, net of forfeitures
    21,863       46,828       112,902  
Retirement of treasury shares
    (83,471 )     (12,020 )     (1,627,500 )
Shares at end of year
    14,871,870       14,907,679       14,834,871  
Treasury stock:
                       
Shares at beginning of year
    (5,894 )     (4,706 )     -  
Purchase of treasury shares
    (83,471 )     (12,020 )     (1,627,500 )
Retirement of treasury shares
    83,471       12,020       1,627,500  
 Non-employee directors' deferred compensation plan
    (1,172 )     (1,188 )     (4,706 )
Shares at end of year
    (7,066 )     (5,894 )     (4,706 )
Common shares outstanding
    14,864,804       14,901,785       14,830,165  
                         
Common stock, $.01 par:
                       
Balance at beginning of year
  $ 149     $ 148     $ 163  
Exercise of stock options
    -       -       -  
Issuance of stock awards, net of forfeitures
    -       1       1  
Retirement of treasury shares
    -       -       (16 )
Balance at end of year
    149       149       148  
Additional paid-in capital:
                       
Balance at beginning of year
    2,559       64       30,423  
Reclassification of unearned compensation  pursuant to the adoption of SFAS No. 123(R)
    -       -       (825 )
Exercise of stock options
    627       183       31  
Issuance of stock awards, net of forfeitures
    -       (1 )     (1 )
Stock based compensation expense
    6,702       2,286       1,516  
Retirement of treasury shares
    (5,101 )     (646 )     (31,150 )
Excess tax benefit of stock based compensation
    1,031       673       70  
Balance at end of year
    5,818       2,559       64  
Retained earnings:
                       
Balance at beginning of year
    393,044       360,102       158,504  
Cumulative effect adjustment for the adoption of SAB 108, net of tax
    -       -       (1,021 )
FIN 48 adoption
    -       (267 )     -  
Retirement of treasury shares
    (447 )     -       (35,153 )
Net income
    113,309       33,209       237,772  
Balance at end of year
    505,906       393,044       360,102  
Unamortized stock award
                       
Balance at beginning of year
    -       -       (825 )
Reclassification of unearned compensation pursuant to the adoption of SFAS No. 123(R)
    -       -       825  
Balance at end of year
    -       -       -  
Treasury stock, at cost:
                       
Balance at beginning of year
    (226 )     (170 )     -  
Purchase of treasury shares
    (5,549 )     (646 )     (66,319 )
Retirement of treasury shares
    5,549       646       66,319  
Non-employee directors' deferred compensation plan
    (66 )     (56 )     (170 )
Balance at end of year
    (292 )     (226 )     (170 )
Total shareholders' equity
  $ 511,581     $ 395,526     $ 360,144  


See accompanying Notes to Consolidated Financial Statements .

F-7

PETROLEUM DEVELOPMENT CORPORATION
Consolidated Statements of Cash Flows
(in thousands)

Year Ended December 31,
 
2008
   
2007
   
2006
 
Cash flows from operating activities:
                 
Net income
  $ 113,309     $ 33,209     $ 237,772  
Adjustments to net income to reconcile to net cash provided by operating activities:
                       
Deferred income taxes
    59,079       12,201       86,431  
Depreciation, depletion and amortization
    104,575       70,844       33,735  
Allowance for doubtful accounts
    180       50       7  
Amortization of debt issuance costs
    1,344       394       -  
Impairment of oil and gas properties
    22,091       1,485       1,519  
Accretion of asset retirement obligation
    1,230       999       515  
Exploratory dry hole costs
    6,504       1,775       1,790  
Loss (gain) from sale of leaseholds/assets
    19       (33,322 )     (327,991 )
Expired and abandoned leases
    3,633       1,786       2,169  
Stock based compensation
    6,702       2,286       1,516  
Unrealized (gains) losses on derivative transactions
    (117,536 )     4,642       (7,620 )
Excess tax benefits from stock-based compensation
    (1,031 )     (673 )     (70 )
Changes in current assets and liabilities:
                       
(Increase) decrease in restricted cash
    (4,257 )     (14,254 )     982  
Increase in accounts receivable
    (9,844 )     (16,506 )     (9,942 )
Increase in accounts receivable - affiliates
    (7,631 )     (2,302 )     (194 )
(Increase) decrease in inventories
    (2,062 )     1,285       1,987  
(Increase) decrease in other current assets
    (5,793 )     4,839       (2,106 )
Increase (decrease) in production  tax liability
    9,857       10,802       (261 )
Increase (decrease) in accounts payable and accrued expenses
    2,790       (10,869 )     13,010  
Increase (decrease) in accounts payable - affiliates
    10,282       (3,099 )     6,116  
(Decrease) increase in advances for future drilling contracts
    (66,742 )     13,645       4,773  
Increase (decrease) in federal and state income taxes payable
    1,721       (27,124 )     19,950  
Increase in funds held for future distribution
    10,538       7,488       (575 )
Other
    143       723       3,877  
Net cash provided by operating activities
    139,101       60,304       67,390  
Cash flows from investing activities:
                       
Capital expenditures
    (323,153 )     (238,988 )     (146,945 )
Acquisition of oil and gas properties, net of cash acquired
    -       (255,661 )     (18,512 )
Investment in drilling partnerships
    -       -       (7,151 )
(Increase) decrease in restricted/designated cash
    (874 )     191,156       (192,416 )
Proceeds from sale of leases to partnerships
    448       1,371       1,798  
Proceeds from sale of leaseholds/assets
    538       34,701       353,600  
Net cash used in investing activities
    (323,041 )     (267,421 )     (9,626 )
Cash flows from financing activities:
                       
Proceeds from credit facility
    419,000       352,000       302,000  
Proceeds from senior notes
    200,101       -       -  
Proceeds from short-term debt
    -       -       20,000  
Payment of credit facility
    (459,500 )     (254,000 )     (209,000 )
Payment of debt issuance costs
    (5,571 )     (1,468 )     (160 )
Proceeds from exercise of stock options
    627       183       31  
Excess tax benefits from stock-based compensation
    1,031       673       70  
Minority interest investment
    -       800       -  
Purchase of treasury stock
    (5,549 )     (646 )     (66,489 )
Net cash provided by financing activities
    150,139       97,542       46,452  
Net (decrease) increase in cash and cash equivalents
    (33,801 )     (109,575 )     104,216  
Cash and cash equivalents, beginning of year
    84,751       194,326       90,110  
Cash and cash equivalents, end of year
  $ 50,950     $ 84,751     $ 194,326  
                         
Supplemental cash flow information:
                       
Cash payments for:
                       
Interest, net of capitalized interest
  $ 19,200     $ 9,535     $ 1,376  
Income taxes, net of refunds
    (530 )     43,785       46,735  
Non-cash investing activities:
                       
Change in deferred tax liability resulting from reallocation of acquisition purchase price
    -       4,188       -  
Change in accounts payable - affiliates related to acquisition of partnerships
    -       668       -  
Change in accounts payable related to purchases of properties and equipment
    8,197       32,820       1,800  
Change in accounts payable - affiliates related to investment in drilling partnership
    -       18,712       (7,151 )
Change in asset retirement obligation, with a corresponding increase to oil and gas properties, net of disposals
    1,153       7,850       3,164  
                         

See accompanying Notes to Consolidated Financial Statements .

F-8

PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Petroleum Development Corporation (“PDC,” “we,” “us” or “the Company”) is an independent energy company engaged primarily in the drilling and development, production and marketing of natural gas and oil.  Since we began oil and gas operations in 1969, we have grown primarily through drilling and development activities, the acquisition of producing natural gas and oil wells and the expansion of our natural gas marketing activities.  As of December 31, 2008, we operate approximately 4,712 wells located in the Appalachian Basin, Michigan Basin, and the Rocky Mountain Region.  Our oil and natural gas wells are located in West Virginia, Tennessee, Pennsylvania, Michigan, North Dakota, Colorado, Kansas, Texas and Wyoming.  We separate our operations into four business segments: oil and gas sales, natural gas marketing activities, well operations and pipeline income and oil and gas well drilling operations.  See Note 16 , Business Segments .

Principles of Consolidation

The consolidated financial statements of PDC include the accounts of our wholly-owned subsidiaries and WWWV, LLC, an entity in which we have a controlling financial interest.  All material intercompany accounts and transactions have been eliminated in consolidation.  We account for our investment in interests in oil and gas limited partnerships under the proportionate consolidation method.  Under this method, our consolidated financial statements include our investments in the partnerships recorded by our working interest in each well thereby accumulating our pro rata share of assets, liabilities and revenues and expenses respectively of the limited partnerships in which we participate.  Our proportionate share of all significant transactions between us and the limited partnerships is eliminated.

Use of Estimates

The preparation of our consolidated financial statements in accordance with generally accepted accounting principles in the United States of America (“U.S.”) requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes.  Actual results could differ from those estimates.  Estimates which are particularly significant to our consolidated financial statements include estimates of oil and gas reserves, future cash flows from oil and gas properties, valuation of derivative instruments and valuation of deferred income tax assets.

Cash Equivalents

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

Restricted Cash

Included in our restricted cash – current as of December 31, 2007, along with interest earned of $0.4 million, is an escrow account funded in June 2007 in the amount of $14.1 million, representing amounts due to the limited partners of our sponsored drilling partnerships as a result of our over withholding estimated production taxes in years prior to 2007.  In October 2008, as part of a pre-filing agreement, we paid the Internal Revenue Service on behalf of the limited partners an estimated tax payment of $4.2 million.  As of December 31, 2008, we had reflected in restricted cash - current $10.6 million, including additional interest of $0.3 million earned in 2008.

Pursuant to a preliminary court approved litigation settlement agreement reached in October 2008, we funded an escrow account in November 2008 in the amount of $8.2 million, of which $5.8 million represented the Company’s share of the settlement and the remainder being that of the affiliated partnerships for which the Company serves as the managing general partner.  As of December 31, 2008, restricted cash – current includes $8.2 million related to this escrow account.  Further, our balance sheet includes a related accounts receivable from our affiliated partnerships of $2.4 million.

We are required by a counterparty to maintain a margin deposit for outstanding derivative contracts.  As of December 31, 2007, cash in the amount of $0.3 million was on deposit and reflected in our consolidated balance sheets as restricted cash - current.  As of December 31, 2008, the margin deposit requirement was insignificant.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


We are required by various government agencies or joint venture agreements to maintain a bond or cash account for the plugging and abandonment of wells.  As of December 31, 2008 and 2007, we had bonds in the form of certificates of deposit for plugging and abandonment of wells totaling $2.2 million and $1.3 million, respectively, which are reflected in other assets.

Accounts Receivable

Our accounts receivable are primarily from purchasers of oil and natural gas and third parties and affiliated partnerships for well pipeline operating services.  Inherent to our industry is the concentration of oil and natural gas sales to a few customers.  This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic, industry or other conditions.

We provide an allowance for doubtful accounts equal to the estimated uncollectible amounts.  In making our estimate, we consider our historical write-offs, relationships and overall creditworthiness of our customers, additional consideration is given to well production data for receivables related to well operations.  It is reasonably possible that our estimate of uncollectible amounts will change periodically.  Accounts receivable are presented on our consolidated balance sheets net of allowance for doubtful accounts of $0.5 million and $0.4 million at December 31, 2008 and 2007, respectively.

Inventories

Materials, supplies and commodity inventories are stated at the lower of average cost or market and removed at carrying value.  Inventory of $4.3 million and $2.2 million as of December 31, 2008 and 2007, respectively, is included in prepaid expenses and other current assets on our consolidated balance sheets.

Derivative Financial Instruments

 We account for derivative financial instruments in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Certain Hedging Activities , as amended.

During 2008, 2007 and 2006, none of our derivative instruments qualified for use of hedge accounting under the terms of SFAS No. 133.  Accordingly, we recognize all derivative instruments as either assets or liabilities on our consolidated balance sheets at fair value, and changes in the derivatives' fair values are recorded on a net basis in our consolidated statements of operations.  Changes in the fair value of derivative instruments related to our oil and gas sales activities are recorded in oil and gas price risk management, net and changes in fair value of derivatives related to our natural gas marketing activities are recorded in sales from and cost of natural gas marketing activities.

We record on our consolidated balance sheets the fair value of derivative instruments entered into by us and allocated to our affiliated partnerships, recording an offsetting receivable from or payable to those partnerships.

See Note 2 , Fair Value of Financial Instruments , and Note 3 , Derivative Financial Instruments , for a discussion of our derivative fair value measurements and a summary fair value table of our open positions as of December 31, 2008 and 2007, respectively.

Properties and Equipment

Oil and Gas Properties.

We account for our 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 capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing oil and natural gas reserves.  Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved oil and gas reserves.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


Our estimates of proved reserves are based on quantities of oil and natural gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic conditions.  Annually, we engage independent petroleum engineers to prepare a reserve and economic evaluation of all our properties on a well-by-well basis as of December 31.  Additionally, we adjust our oil and gas reserves for major acquisitions, new drilling and divestitures during the year as needed.  The process of estimating and evaluating oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data.  The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions.  As a result, revisions in existing reserve estimates occur from time to time.  Although every reasonable effort is made to ensure that reserve estimates reported represent our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates.  Because estimates of reserves significantly affect our depreciation, depletion and amortization (“DD&A”) expense, a change in our estimated reserves could have an effect on our net income.

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 our completion as a producing well and we are making sufficient progress assessing our 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 the financial statements, the costs incurred prior to the end of the reporting period are expensed to exploration costs.  If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are 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 same well is removed from the suspended well status and the proper accounting treatment is recorded.  At December 31, 2008, suspended well costs included in oil and gas properties on our consolidated balance sheet were $1.2 million.  See Note 4 , Properties and Equipment .

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 exploratory 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 our historical experience, acquisition dates and average lease terms.  Impairment costs are recorded in the statements of operations as a component of exploration expense and were as follows for each of the periods indicated:

   
2008
   
2007
   
2006
 
   
(in thousands)
 
Individually significant unproved properties (1)
  $ 9,165     $ 1,484     $ 473  
Insignificant unproved properties
    3,633       1,786       157  
Total
  $ 12,798     $ 3,270     $ 630  

__________
 
(1)
2007 includes liquidated damages of $1.1 million related to the abandonment of an exploration agreement with an unaffiliated party.

The valuation of unproved properties is subjective and requires us to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets , we assess our oil and gas properties for possible impairment quarterly 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 we reasonably estimate the commodity to be sold.  The estimates of future prices may differ from current market prices of oil and natural gas.  Any downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future net cash flows and an impairment of our oil and gas properties.  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.  We recognized impairment losses on proved oil and gas properties of $12.8 million in 2008, consisting of $7.5 million related to our properties in the Fort Worth Basin, $3 million in our Bakken Field in North Dakota and $2.3 million in our Nesson Field also in North Dakota.  In 2006, we recorded an impairment loss of $1.5 million in our Nesson Field.  Impairment charges related to our oil and gas properties are included in our statements of operations as a component of exploration expense. No impairments related to proved oil and natural gas properties were recorded in 2007.

Upon sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net 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.

Other Property and Equipment.

The following table sets forth the estimated useful lives of our other property and equipment.

Pipelines and related facilities
10 - 17 years
Transportation and other equipment
3 - 20 years
Buildings
30 - 40 years

Pipelines, Transportation Equipment and Other Equipment .  Pipelines, transportation equipment and other equipment are carried at cost.  Depreciation is provided principally on the straight-line method over the assets estimated useful lives.  In accordance with SFAS No. 144 , Accounting for the Impairment or Disposal of Long-Lived Assets , long-lived assets, such as property, plant and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.  Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset.  If the carrying amount of an asset exceeds our estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset.  No impairments were recorded in 2008, 2007or 2006.

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

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

Total depreciation expense related to other property and equipment was $7.6 million, $4.3 million and $2 million in 2008, 2007 and 2006, respectively.

Capitalized Interest

Interest costs are capitalized as part of the historical cost of acquiring assets.  Oil and gas investments in unproved properties and major development projects, on which DD&A expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest.  Major construction projects also qualify for interest capitalization until the asset is ready for service.  Capitalized interest is calculated by multiplying our weighted-average interest rate on our debt outstanding by the qualifying costs.  Interest capitalized may not exceed gross interest expense for the period.  As the qualifying asset is moved to the DD&A pool, the related capitalized interest is also transferred and is amortized over the useful life of the asset.  Interest costs of $2.6 million, $3 million and $1.6 million were capitalized in 2008, 2007 and 2006, respectively.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


Production Tax Liability

Production tax liability represents estimated taxes, primarily severance and property, to be paid to the states and counties in which we produce oil and gas.  Our share of these taxes is expensed to oil and gas production and well operations cost.

Advances for Future Drilling Contracts

Advances for future drilling contracts represent funds received from our sponsored drilling partnerships for drilling activities which have not been completed, a portion of which will be recognized as revenue in accordance with our revenue recognition policies.  The amount advanced and outstanding as of December 31, 2008, are primarily related to the drilling partnership sponsored in August 2007 and represents the remaining costs to finish the wells, primarily reclamation.  No partnership was sponsored in 2008.

Income Taxes

We account for income taxes under the asset and liability method.  We recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.  If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance thereby reducing the deferred tax assets to what we consider realizable.  No valuation allowance was recorded at December 31, 2008 or 2007.

Asset Retirement Obligations

 We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the well is completely drilled.  Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the long-lived asset by the same amount as the liability.  Over time, the liabilities are accreted for the change in their present value, through charges to oil and gas production and well operations costs.  The initial capitalized costs are depleted over the useful lives of the related assets, through charges to depreciation, depletion and amortization.  If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost.  Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations.  See Note 7 , Asset Retirement Obligations , for a reconciliation of asset retirement obligation activity.

Minority Interest in Consolidated Limited Liability Company

In May 2007, we contributed $0.8 million for a 50% interest in WWWV, LLC (“LLC”), a limited liability company for which we serve as the managing member.  One-sixth of the entity is owned by a member of our Board of Directors, who paid the same unit price for his interest as was paid by us and unrelated third parties for such interests in the LLC.  The LLC's only asset is an aircraft and the LLC was formed for the purpose of owning and operating the aircraft.

The minority interest portion of pre-tax expense incurred by and belonging to the minority interest holders of the consolidated limited liability company is not material and is included in our consolidated statement of operations as an offset to DD&A expense.

Retirement of Treasury Shares

 We have historically retired all treasury share purchases, with the exception of shares purchased in accordance with our non-employee deferred compensation plan for non-employee directors, see Note 9 , Common Stock .  As treasury shares are retired, we charge any excess of cost over the par value entirely to additional paid-in-capital, to the extent we have amounts in paid-in-capital, with any remaining excess cost being charged to retained earnings.

Revenue Recognition

Oil and natural gas sales .  Sales of oil are recognized when persuasive evidence of a sales arrangement exists, the oil is verified as produced and is delivered to a purchaser, collection of revenue from the sale is reasonably assured and the sales price is determinable.  We are currently able to sell all the oil that we can produce under existing sales contracts with petroleum refiners and marketers.  We do not refine any of our oil production.  Our crude oil production is sold to purchasers at or near our wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


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 us under contracts with terms ranging from one month to three years.  Virtually all of our 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, our revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase.  We believe that the pricing provisions of our natural gas contracts are customary in the industry.

 We currently use the “net-back” method of accounting for transportation arrangements of our natural gas sales.  We sell gas at the wellhead and collect a price and recognize revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the customers and reflected in the wellhead price.

Natural gas marketing activities .  Natural gas marketing is reported on the gross accounting method, based on the nature of the agreements between RNG, our suppliers and our customers.  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 gains and losses 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.

Oil and gas well drilling .  Our drilling segment recognizes revenue from drilling contracts with sponsored drilling programs using the percentage of completion method based upon the percentage of contract costs incurred to date to the estimated total contract costs for each contract.  We utilize this method since reasonably dependable estimates of the total estimated costs can be made and recognized revenues are subject to revisions as a contract progresses, the term of which can range from three to twelve months.  We have offered our drilling services under two types of contractual arrangements, cost-plus or footage-based service contracts, which result in differing risk and reward relationships, and consequently, different revenue reporting policies pursuant to Emerging Issues Task Force (“EITF”) Issue No. 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent .

The first cost-plus drilling service arrangement was entered into in late 2005 with drilling activity commencing in the first quarter of 2006.  Due to the fixed-fee-percentage nature of our revenues from these services, we have determined that, in substance, we are acting as an agent, without risk of loss during the performance of the drilling activities.  Accordingly, our services provided under the cost-plus drilling agreements are reported on a net basis.  We entered into our second and third cost-plus drilling arrangements in September 2006 and August 2007 and commenced drilling immediately.

Footage-based contracts provide for the drilling, completion and equipping of wells at footage rates and are generally completed within nine to twelve months after the commencement of drilling.  We provide geological, engineering, and drilling supervision on the drilling and completion process and use subcontractors to perform drilling and completion services and accordingly we have the risk of loss in performing services under these arrangements.  Accordingly, we report revenue under these agreements gross of related expenses.  Anticipated losses, if any, on uncompleted contracts are recorded at the time that the estimated total costs exceed the estimated total contract revenue.  At December 31, 2007, included as a component of other current liabilities on the consolidated balance sheets, we had recorded a loss contract reserve of $0.2 million.  No loss contract reserve was recorded as of December 31, 2008.

Well operations and pipeline income .  Well operations and pipeline income are 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.  We are paid a monthly operating fee for each well we operate and natural gas transported for outside owners including the limited partnerships we sponsored.  The fee covers monthly operating and accounting costs, insurance and other recurring costs.  We may also receive additional compensation for special non-recurring activities, such as reworks and recompletions.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


Stock-Based Compensation

On January 1, 2006, we adopted SFAS No. 123 (revised 2004), Share-Based Payment (“SFAS No. 123R”), to account for stock-based compensation.  SFAS No. 123R eliminated the use of Accounting Principles Board Opinion (“APB”) No. 25, Accounting for Stock Issued to Employees , and the intrinsic value method of accounting for equity compensation and requires us to recognize the cost of employee services received in exchange for awards of equity instruments based on fair value at the date of grant in our financial statements.  We elected to use the modified prospective method for adoption, and accordingly, prior period financial statements have not been restated.  For all unvested options and other equity based awards outstanding as of January 1, 2006, the previously measured but unrecognized compensation expense, based on the fair value at the original grant date, will be recognized in the financial statements over the remaining requisite service period for each separately vesting portion.  For equity-based compensation awards granted or modified subsequent to January 1, 2006, compensation expense, based on the fair value on the date of grant or modification, will be recognized in the financial statements on a straight-line basis over the vesting period for the entire award.  To the extent compensation cost relates to employees directly involved in oil and natural gas acquisition, exploration and development activities, such amounts are capitalized to properties and equipment.  Amounts not capitalized to properties and equipment are recognized in the appropriate cost and expense line item in the statement of operations.  No amounts for stock-based compensation were capitalized in 2008, 2007 and 2006.

Earnings Per Share

Basic earnings per common share (“EPS”) is computed by dividing net income (the numerator) by the weighted-average number of common shares outstanding for the period (the denominator).  Diluted EPS is similarly computed except that the denominator includes the effect, using the treasury stock method, of our outstanding stock options, unamortized portion of restricted stock and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive.

The following is a reconciliation of the basic and diluted weighted-average shares outstanding for the years ended December 31:

   
2008
   
2007
   
2006
 
   
(in thousands, except per share data)
 
                   
Weighted average common shares outstanding - basic
    14,736       14,744       15,660  
Dilutive effect of share-based compensation: (1)
                       
Unamortized portion of restricted stock
    71       44       22  
Stock options
    35       48       55  
Non employee director deferred compensation
    6       5       4  
Weighted average common and common share equivalents outstanding - diluted
    14,848       14,841       15,741  
                         
(1) Weighted average common share equivalents excluded from diluted earnings per share due to their anti-dilutive affect:
                       
Unamortized portion of restricted stock
    73       18       -  
Stock options
    -       -       24  
Total anti-dilutive common share equivalents
    73       18       24  


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


Recent Accounting Standards

Recently Adopted Accounting Standards

We adopted the provisions of Statement of SFAS No. 157, Fair Value Measurements , effective January 1, 2008.  SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures related to fair value measurements. SFAS No. 157 applies broadly to financial and nonfinancial assets and liabilities that are measured at fair value under other authoritative accounting pronouncements, but does not expand the application of fair value accounting to any new circumstances.  In February 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) FAS No. 157-2, Effective Date of FASB Statement No. 157 , which delays the effective date of SFAS No. 157 by one year (to January 1, 2009) for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).  Nonfinancial assets and liabilities for which we have not applied the provisions of SFAS No. 157 include those initially measured at fair value, including our asset retirement obligations.  As of the adoption date, we have applied the provisions of SFAS No. 157 to our recurring measurements and the impact was not material to our underlying fair values and no amounts were recorded relative to the cumulative effect of a change in accounting.  We are currently evaluating the potential effect that the nonfinancial assets and liabilities provisions of SFAS No. 157 will have on our financial statements when adopted in 2009.   See Note 2 , Fair Value of Financial Instruments .

In October 2008, the FASB issued FSP No. FAS 157-3, Determining the Fair Value of a Financial Asset in a Market That Is Not Active , which applies to financial assets within the scope of accounting pronouncements that require or permit fair value measurements in accordance with SFAS No. 157. This FSP clarifies the application of SFAS No. 157 in a market that is not active and defines additional key criteria in determining the fair value of a financial asset when the market for that financial asset is not active.  FSP No. FAS 157-3 was effective upon issuance and did not have a material impact on our financial statements.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities .  SFAS No. 159 permits entities to choose to measure, at fair value, many financial instruments and certain other items that are not currently required to be measured at fair value.  The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions.  SFAS No. 159 establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities.  The statement will be effective as of the beginning of an entity's first fiscal year beginning after November 15, 2007.  We have not elected to measure additional financial assets and liabilities at fair value.

In April 2007, the FASB issued FSP No. FIN 39-1, Amendment of FASB Interpretation No. 39 (“FIN 39-1”), to amend certain portions of Interpretation 39.  FIN 39-1 replaces the terms “conditional contracts” and “exchange contracts” in Interpretation 39 with the term “derivative instruments” as defined in Statement 133.  FIN 39-1 also amends Interpretation 39 to allow for the offsetting of fair value amounts for the right to reclaim cash collateral or receivable, or the obligation to return cash collateral or payable, arising from the same master netting arrangement as the derivative instruments.  FIN 39-1 applies to fiscal years beginning after November 15, 2007, with early adoption permitted.  The January 1, 2008, adoption of FSP FIN 39-1 had no impact on our financial statements.
 
In June 2006, the FASB issued EITF No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement (That Is, Gross versus Net Presentation) .  EITF 06-3 addresses the income statement presentation of any tax collected from customers and remitted to a government authority and concludes that the presentation of taxes on either a gross basis or a net basis is an accounting policy decision that should be disclosed pursuant to APB No. 22, Disclosures of Accounting Policies .  For taxes that are reported on a gross basis (included in revenues and costs), EITF 06-3 requires disclosure of the amounts of those taxes in interim and annual financial statements, if those amounts are significant.  EITF 06-3 became effective for interim and annual reporting periods beginning after December 15, 2006.  The adoption of the standard, effective January 1, 2007, did not have a significant effect on our consolidated financial statements.  Our existing accounting policy, which was not changed upon the adoption of EITF 06-3, is to present taxes within the scope of EITF 06-3 on a net basis.

In July 2006, the FASB issued FIN No. 48, Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement 109 , which prescribes a comprehensive model for accounting for uncertainty in tax positions.  FIN No. 48 provides that the tax effects from an uncertain tax position can be recognized in the financial statements, only if the position is more likely than not of being sustained on audit by the Internal Revenue Service (“IRS”), based on the technical merits of the position.  We adopted the provisions of FIN No. 48 effective January 1, 2007.  The cumulative effect of applying the provisions of FIN No. 48 has been accounted for as an adjustment to retained earnings in the first quarter of 2007.  The adoption of FIN No. 48 resulted in a $0.3 million cumulative effect adjustment (see Note 5 , Income Taxes , for further discussion).


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


In May 2007, the FASB issued FASB Staff Position FIN No. 48-1, Definition of Settlement in FASB Interpretation No. 48 (“FIN No. 48-1”).  FIN No. 48-1 amends FIN No. 48 to provide guidance on how an entity should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits.  The term “effectively settled” replaces the term “ultimately settled” when used to describe recognition, and the terms “settlement” or “settled” replace the terms “ultimate settlement” or “ultimately settled” when used to describe measurement of a tax position under FIN No. 48.  FIN No. 48-1 clarifies that a tax position can be effectively settled upon the completion of an examination by a taxing authority without being legally extinguished.  For tax positions considered effectively settled, an entity would recognize the full amount of tax benefit, even if the tax position is not considered more likely than not to be sustained based solely on the basis of its technical merits and the statute of limitations remains open.  The adoption of FIN No. 48-1, effective January 1, 2007, did not have an incremental effect on our consolidated financial statements.

In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements .  SAB No. 108 provides guidance on how the effects of prior year misstatements should be considered in quantifying misstatements in the current year financial statements.  SAB No. 108 requires registrants to quantify misstatements using both the income statement (“rollover”) and balance sheet (“iron curtain”) approach and evaluate whether either approach results in a misstatement that, when all relevant quantitative and qualitative factors are considered, is material.  Historically, we evaluated uncorrected misstatements using the “rollover” method which resulted in an accumulation of quantitatively and qualitatively immaterial misstatements to our consolidated financial statements.  SAB No. 108 provides for a one time transitional adjustment to retained earnings for errors which were not deemed material to prior year financial statements, but which is material under guidance of SAB No. 108.  We adopted SAB No. 108 during the fourth quarter of 2006 and recorded a one-time adjustment to reduce retained earnings by $1.0 million.

In December 2004, the FASB issued SFAS No. 123(R), Share-Based Payment .  In March 2005, the SEC issued Staff Accounting Bulletin (“SAB”) No. 107, Share-Based Payment , regarding the interaction between SFAS No. 123(R) and certain SEC rules and regulations.  Effective January 1, 2006, we adopted SFAS No. 123(R). We elected to use the modified prospective method for adoption, which requires compensation expense to be recognized in the statement of operations for all unvested stock options and other equity-based compensation beginning in the first quarter of adoption.  Prior to the adoption of SFAS No. 123(R), we followed the intrinsic value method in accordance with APB No. 25 (as amended) to account for employee stock-based compensation.  The adoption of SFAS No. 123(R) required the unamortized stock award recorded under APB No. 25 related to stock-based compensation awards as of January 1, 2006, in the amount of $0.8 million to be eliminated against additional paid-in-capital.  See Stock-Based Compensation policy above and Note 9, Common Stock , for further discussion of the Company's accounting for share-based compensation awards.

Recently Issued Accounting Standards

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS No. 141R”).  SFAS No. 141R requires an acquirer to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their acquisition-date fair values.  SFAS No. 141R also requires disclosure of the information necessary for investors and other users to evaluate and understand the nature and financial effect of the business combination.  Additionally, SFAS No. 141R requires that acquisition-related costs be expensed as incurred.  The provisions of SFAS No. 141R will become effective for acquisitions completed on or after January 1, 2009; however, the income tax provisions of SFAS No. 141R will become effective as of that date for all acquisitions, regardless of the acquisition date.  SFAS No. 141R amends SFAS No. 109, Accounting for Income Taxes , to require the acquirer to recognize changes in the amount of its deferred tax benefits recognizable due to a business combination either in income from continuing operations in the period of the combination or directly in contributed capital, depending on the circumstances.  SFAS No. 141R further amends SFAS No. 109 and FIN 48, Accounting for Uncertainty in Income Taxes , to require, subsequent to a prescribed measurement period, changes to acquisition-date income tax uncertainties to be reported in income from continuing operations and changes to acquisition-date acquiree deferred tax benefits to be reported in income from continuing operations or directly in contributed capital, depending on the circumstances.  Upon our adoption of SFAS No. 141R effective January 1, 2009, we will recognize expense of $1.4 million in deferred acquisition related costs.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—An Amendment of ARB No. 51 .  SFAS No. 160 states that accounting and reporting for minority interests will be recharacterized as non-controlling interests and classified as a component of equity.  Additionally, SFAS No. 160 establishes reporting requirements that provide sufficient disclosures which clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners.  SFAS No. 160 is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008.  We are evaluating the impact that SFAS No. 160 will have, if any, on our consolidated financial statements and related disclosures when it is adopted in 2009.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—An Amendment of FASB Statement No. 133 , which changes the disclosure requirements for derivative instruments and hedging activities.  Enhanced disclosures are required to provide information about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows.  SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged.  As SFAS No. 161 is disclosure related, we do not expect its adoption to have a material impact on our financial statements.

In January 2009, the SEC published its final rule, Modernization of Oil and Gas Reporting , which modifies the SEC’s reporting and disclosure rules for oil and natural gas reserves.  The most notable changes of the final rule include the replacement of the single day period-end pricing to value oil and natural gas reserves to a 12-month average of the first day of the month price for each month within the reporting period.  The final rule also permits voluntary disclosure of probable and possible reserves, a disclosure previously prohibited by SEC rules.  The revised reporting and disclosure requirements are effective for our Form 10-K for the year ended December 31, 2009.  Early adoption is not permitted.  We are evaluating the impact that adoption of this final rule will have on our consolidated financial statements, related disclosure and management’s discussion and analysis.

NOTE 2 – FAIR VALUE OF FINANCIAL INSTRUMENTS

Derivative Financial Instruments .

Determination of fair value .    We measure fair value based upon quoted market prices, where available.  Our valuation determination includes: (1) identification of the inputs to the fair value methodology through the review of counterparty statements and other supporting documentation, (2) determination of the validity of the source of the inputs, (3) corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions.  The methods described above may produce a fair value calculation that may not be indicative of future fair values.  Our valuation determination also gives consideration to our nonperformance risk on our own liabilities as well as the credit standing of our counterparties.  We primarily use two investment grade financial institutions as our counterparties to our derivative contracts.  We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position.  Based on our evaluation, we have determined that the impact of the nonperformance of our counterparties on the fair value of our derivative instruments is insignificant.   As of December 31, 2008, no valuation allowance was recorded.   Furthermore, while we believe these valuation methods are appropriate and consistent with that used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

Valuation hierarchy .  SFAS No. 157 establishes a fair value hierarchy that requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.  The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3).  In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy.  The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy.  Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.  The three levels of inputs that may be used to measure fair value are defined as:

Level 1 – Quoted prices (unadjusted) in active markets for identical assets or liabilities.  Instruments included in Level 1 consist of our commodity derivatives for New York Mercantile Exchange (“NYMEX”)-based natural gas swaps.

Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability and (iv) inputs that are derived from observable market data by correlation or other means.

Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.  Instruments included in Level 3 consist of our commodity derivatives for Colorado Interstate Gas (“CIG”) and Panhandle Eastern Pipeline (“PEPL”)-based natural gas swaps, oil swaps, natural gas basis protection swaps, oil and natural gas options, and physical sales and purchases.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


The following table presents, for each hierarchy level, our assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis as of December 31, 2008:

   
Level 1
   
Level 3
   
Total
 
   
(in thousands)
 
Assets:
                 
Commodity based derivatives
  $ 19,359     $ 144,677     $ 164,036  
       
Liabilities:
     
Commodity based derivatives
    (658 )     (9,828 )     (10,486 )
                         
Net fair value of commodity based derivatives
  $ 18,701     $ 134,849     $ 153,550  


The following table sets forth a reconciliation of our Level 3 fair value measurements:

   
Year Ended
December 31, 2008
 
   
(in thousands)
 
       
Fair value, net asset (liability), beginning of period
  $ (2,368 )
Unrealized gains (losses) included in statement of operations line item:
       
Cost of natural gas marketing activities
    (1,079 ) 
Unrealized gains (losses) included in balance sheet line item:
       
Accounts receivable - affiliates
    821  
Accounts payable - affiliates
    35,338  
Purchases
       
Oil and gas sales activities
    105,214  
Sales from natural gas marketing activities
    438  
Cost of natural gas marketing activities
    (4,590 ) 
Settlements
       
Oil and gas sales activities
    549  
Sales from natural gas marketing activities
    (129 ) 
Cost of natural gas marketing activities
    655  
Fair value, net asset (liability), end of period
  $ 134,849  
         
         
Change in unrealized gains (losses) relating to assets (liabilities) still held as of December 31, 2008, included in statement of operations line item:
       
Oil and gas price risk management, net
  $ 105,214  
Sales from natural gas marketing activities
    438  
Cost of natural gas marketing activities
    (5,669 ) 
    $ 99,983  

 
See Note 3 , Derivative Financial Instruments , for additional disclosure related to our derivative financial instruments.

Non-Derivative Financial Assets and Liabilities .

The carrying values of the financial instruments comprising cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximate fair value due to the short-term maturities of these instruments.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


The portion of our long-term debt related to our credit facility, approximates fair value due to the variable nature of its related interest rate.  We estimate the fair value of the portion of our long-term debt related to our senior notes to be approximately $127 million or approximately 62.5% of par value as of December 31, 2008.  We determined this valuation based upon measurements of trading activity and quotes provided by brokers and traders participating in the trading of the securities.

NOTE 3 – DERIVATIVE FINANCIAL INSTRUMENTS

 We are exposed to the effect of market fluctuations in the prices of oil and natural gas as they relate to our oil and natural gas sales and natural gas marketing segments.  Price risk represents the potential risk of loss from adverse changes in the market price of oil and natural gas commodities.  We employ established policies and procedures to manage the risks associated with these market fluctuations using commodity derivatives.  Our policy prohibits the use of oil and natural gas derivative instruments for speculative purposes.

Concentration of Credit Risk .    A significant portion of our liquidity is concentrated in derivative instruments that enable us to manage a portion of our exposure to price volatility from producing oil and natural gas.  These arrangements expose us to credit risk from our counterparties.  These contracts consist of fixed price swaps, basis swaps and collars.  We primarily use two investment grade financial institutions as our counterparties to our derivative contracts who are also major lenders in our credit facility arrangement.  We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position.  Based on our evaluation, we have determined that the impact of the nonperformance of our counterparties on the fair value of our derivative instruments is insignificant.   As of December 31, 2008, no valuation allowance was recorded.

As of December 31, 2008, the following counterparties expose us to credit risk.

   
Fair Value of Derivatives
 
   
As of December 31, 2008
 
Counterparty Name
 
Assets
   
Liabilities
   
Net
 
   
(in thousands)
 
                   
JPMorgan Chase Bank, N.A. (1)
  $ 83,291     $ (322 )   $ 82,969  
BNP  Paribas (1)
    79,316       -       79,316  
Various (2)
    1,429       (10,164 )     (8,735 )
                         
Total
  $ 164,036     $ (10,486 )   $ 153,550  
                         
                         
(1) Major lender in our credit facility, see Note 6.
 
(2) Represents a total of 48 counterparties, includes two lenders in our credit faciity.
 

 
Economic Hedging Strategies .  Our results of operations and operating cash flows are affected by changes in market prices for oil and natural gas.  To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative contracts.  As of December 31, 2008, our oil and natural gas derivative instruments were comprised of futures, swaps, basis protection swaps and collars.  These instruments generally consist of NYMEX-traded natural gas futures contracts and option contracts for Appalachian and Michigan production, PEPL-based contracts for NECO production and CIG-based contracts for other Colorado production and NYMEX-based crude oil swaps for our Colorado oil production.

 
·
For swap instruments, we receive a fixed price for the hedged commodity and pay a floating market price to the counterparty.  The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

 
·
Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point.  For CIG basis protection swaps, which have negative differentials to NYMEX, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract.

 
·
Collars contain a fixed floor price (put) and ceiling price (call).  If the market price exceeds the call strike price or falls below the fixed put strike price, we receive the fixed price and pay the market price.  If the market price is between the call and the put strike price, no payments are due from either party.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


We purchase puts and set collars and swaps for our own and affiliated partnerships’ production to protect against price declines in future periods while retaining much of the benefits of price increases.  RNG enters into fixed-price physical purchase and sale agreements that are derivative contracts.  In order to offset these fixed-price physical derivatives, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative.  While these derivatives are structured to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price changes in the physical market.  We believe our derivative instruments continue to be effective in achieving the risk management objectives for which they were intended.

Validation of a contract’s fair value is performed internally and while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values.  At December 31, 2008 and 2007, we had the following open commodity based derivative instruments designed as an economic hedge for a portion of our oil and natural gas production for periods after December 2008:

   
Year Ended December 31,
 
   
2008
   
2007
 
   
(in thousands)
 
Derivative net assets (liabilities)
           
Oil and gas sales activities:
           
Fixed-price natural gas swaps
  $ 55,747     $ -  
Natural gas collars
    50,752       2,969  
Natural gas basis protection swaps
    (4,292 )     -  
Natural gas floors
    -       105  
Fixed-price oil swaps
    51,508       (5,097 )
      153,715       (2,023 )
Natural gas marketing activities:
               
Fixed-price natural gas swaps
    (159 )     649  
Natural gas basis protection swaps
    (13 )     -  
Natural gas collars
    7       -  
      (165 )     649  
Estimated net fair value of derivative instruments
  $ 153,550     $ (1,374 )


In addition to including the gross assets and liabilities related to our share of oil and gas production, the above table and our consolidated balance sheets include the gross assets and liabilities related to derivative contracts we entered into and those that we allocate to our affiliated partnerships as the managing general partner.  See Note 11 , Transactions with Affiliates , for a discussion of our allocation methodology.  For those derivative contracts which we have allocated to the affiliated partnerships, we have on our consolidated balance sheets a corresponding payable to and receivable from the partnerships of $37.5 million and $1.6 million, respectively, as of December 31, 2008, and $1 million and $2.4 million as of December 31, 2007, respectively.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


The following table identifies the fair value of commodity based derivatives as classified in our consolidated balance sheets.

   
December 31,
 
   
2008
   
2007
 
   
(in thousands)
 
Classification in the Condensed Consolidated Balance Sheets:
           
Fair value of derivatives - current asset
  $ 116,881     $ 4,817  
Other assets - long-term asset
    47,155       193  
      164,036       5,010  
                 
Fair value of derivatives - current liability
    4,766       6,291  
Other liabilities - long-term liability
    5,720       93  
      10,486       6,384  
Net fair value of commodity based derivatives - asset (liability)
  $ 153,550     $ (1,374 )


The following changes in the fair value of commodity based derivatives are reflected in our consolidated statements of operations.

   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
Statement of operations line item
 
Realized
   
Unrealized
   
Realized
   
Unrealized
   
Realized
   
Unrealized
 
   
(in thousands, gain/(loss))
 
                                     
Oil and gas price risk management gain (loss), net (1)
  $ 9,487     $ 118,351     $ 7,173     $ (4,417 )   $ 1,895     $ 7,252  
Sales from natural gas marketing activities (2)
    (1,882 )     4,614       3,870       (1,736 )     2,592       12,291  
Cost of natural gas marketing activities (2)
    32       (5,429 )     (482 )     1,511       (1,908 )     (11,923 )

__________
 
(1)
Includes realized and unrealized gains and losses on commodity based derivative instruments related to PDC.
 
(2)
Includes realized and unrealized gains and losses on commodity based derivatives instruments related to RNG only.

NOTE 4 – PROPERTIES AND EQUIPMENT
 
   
December 31,
 
   
2008
   
2007
 
   
(in thousands)
 
Properties and equipment, net:
           
Oil and gas properties (successful efforts method of accounting)
           
Proved
  $ 1,245,316     $ 953,904  
Unproved
    32,768       41,023  
Total oil and gas properties
    1,278,084       994,927  
Pipelines and related facilities
    34,067       22,408  
Transportation and other equipment
    31,693       23,669  
Land and buildings
    14,570       11,303  
Construction in progress (1)
    275       2,929  
      1,358,689       1,055,236  
Accumulated DD&A
    (325,611 )     (209,372 )
                 
    $ 1,033,078     $ 845,864  
 
(1) At December 31, 2007 includes costs primarily related to a new integrated oil and gas financial software system.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


Suspended Well Costs

The following table identifies the capitalized exploratory well costs that are pending the determination of proved reserves and included in oil and gas properties on the consolidated balance sheets.

   
2008
   
2007
   
2006
 
   
(in thousands, except for number of wells)
 
                   
Beginning balance at January 1
  $ 2,300     $ 765     $ 1,918  
Additions to capitalized exploratory well costs pending the determination of proved reserves
    15,644       3,953       12,016  
Reclassifications to wells, facilities and equipment based on the determination of proved reserves
    (10,259 )     (878 )     (13,169 )
Capitalized exploratory well costs charged to expense
    (6,505 )     (1,540 )     -  
Ending balance at December 31
  $ 1,180     $ 2,300     $ 765  
                         
Number of wells pending determination at December 31
    6       3       1  


As of December 31, 2008, none of the wells awaiting the determination of proved reserves have been capitalized for more than one year after the completion of drilling.

NOTE 5 - INCOME TAXES

For each of the years in the three-year period ended December 31, 2008, we utilized our tax election to currently expense approximately $30 million, $44 million and $55 million, respectively, of intangible drilling costs (“IDC”).  This election substantially reduced our current tax expense but resulted in a correspondingly higher deferred tax expense as shown below.  Additionally, in 2006, we had a substantial taxable gain from the sale of undeveloped oil and gas properties, see Note 13 , Sale of Oil and Gas Properties .  We have chosen to use the favorable deferral aspects of the Internal Revenue Code (“IRC”) Section 1031 like-kind exchange (“LKE”) rules   to defer the tax liability on a portion of the gain realized by purchasing replacement properties, see Note 14 , Acquisitions .  Accordingly, our current and deferred provision for income taxes increased proportionately in 2006 due to the current and deferred tax associated with this large taxable gain.  The components of our tax expense consisted of the following:

   
2008
   
2007
   
2006
 
   
(in thousands)
 
Current:
                 
Federal
  $ 6,198     $ 7,579     $ 54,467  
State
    (3,818 )     1,201       8,739  
Total current income taxes
    2,380       8,780       63,206  
Deferred:
                       
Federal
    55,500       11,074       74,003  
State
    3,579       1,127       12,428  
Total deferred income taxes
    59,079       12,201       86,431  
Total income taxes
  $ 61,459     $ 20,981     $ 149,637  

 
PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Income tax expense differed from the amounts computed by applying the U.S. federal income tax rate of 35%.

   
2008
   
2007
   
2006
 
   
(in thousands)
 
                   
Computed "expected" tax
  $ 61,169     $ 18,966     $ 135,594  
State income tax, net
    5,265       1,907       13,744  
Percentage depletion
    (1,150 )     (624 )     (545 )
Domestic production activities deduction
    (249 )     (374 )     -  
Other
    (3,576 )     1,106       844  
    $ 61,459     $ 20,981     $ 149,637  


In order to reduce current income taxes payable, we elected to expense, for income tax purposes, a large amount of IDC in each of the three years presented above.  This expensing election reduces our domestic production activities deduction, which in 2008 and 2007 was statutorily equal to six percent of our qualified production activity income (“QPAI”), to $0.7 million and $1.1 million, respectively.  In 2006, due to our decision to expense $55 million of IDC, our domestic production deduction, which in 2006 was statutorily equal to three percent of QPAI, was zero.  In addition, the amount in “Other” for 2008 was primarily for discrete tax benefit realized upon the implementation of state tax strategies during the second and third quarters.  The amount in “Other” for 2007 was primarily nondeductible tax penalties.

The federal examination of our 2005 and 2006 tax returns is currently ongoing with no significant adjustments noted as of December 31, 2008.

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2008 and 2007, are presented below.

   
2008
   
2007
 
   
(in thousands)
 
Deferred tax assets:
           
Allowance for doubtful accounts
  $ 205     $ 138  
Drilling notes
    27       31  
Allowance for lease impairment
    4,910       912  
Litigation allowance
    -       578  
Deferred revenue related to cash withheld for  future plugging cost
    1,043       1,011  
Deferred compensation
    2,846       2,058  
Asset retirement obligations
    8,519       7,782  
Unrealized loss - derivatives
    -       703  
Employee benefits
    547       456  
State tax credit - carryforward
    309       -  
Other
    57       16  
Total gross deferred tax assets
    18,463       13,685  
Less valuation allowance
    -       -  
Deferred tax assets
    18,463       13,685  
                 
Deferred tax liabilities:
               
Properties and equipment
    (165,212 )     (145,499 )
Unrealized gains - derivatives
    (44,199 )     (55 )
Total gross deferred tax liabilities
    (209,411 )     (145,554 )
Net deferred tax liability
  $ (190,948 )   $ (131,869 )
                 
Classification in the Consolidated Balance Sheets:
               
Net current deferred tax (liabilities) assets*
  $ (28,355 )   $ 4,621  
Net non-current deferred tax liability
    (162,593 )     (136,490 )
Net deferred tax liability
  $ (190,948 )   $ (131,869 )
                 
______________
* Included in other current assets on the consolidated balance sheets.
 


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


As noted above, deferred tax liabilities for properties and equipment increased in 2008 and 2007, primarily as a result of our election to expense $30 million and $44 million of IDC for income tax purposes.

In assessing whether a valuation allowance for the deferred tax assets should be recorded, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized.  The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.  Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, we believe it is more likely than not that we will realize the benefits of these deductible differences.  The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carry-forward period are reduced.

We adopted the provisions of FIN No. 48 effective January 1, 2007.  As a result of adoption, retained earnings decreased by $0.3 million, deferred income taxes payable decreased by $0.9 million, current income taxes payable increased by $0.2 million and the liability for unrecognized tax benefit increased by $1 million.


The following table sets forth a reconciliation of the total amounts of unrecognized tax benefits for 2008:

   
(in thousands)
 
       
Balance, December 31, 2007
  $ 888  
Gross increases for tax positions of prior years
    216  
Gross increases for tax positions of current year
    167  
Balance, December 31, 2008
  $ 1,271  


Interest and penalties related to uncertain tax positions are recognized in income tax expense.  As of January 1, 2008, and December 31, 2008, we have approximately $0.1 and $0.3 million of accrued interest related to uncertain tax positions, respectively.  In addition, at December 31, 2008, $0.3 million of income tax penalties were accrued compared to $0.2 million accrued at January 1, 2008.  The total amount of unrecognized tax benefits that would affect the effective tax rate, if recognized, is $0.9 million as of December 31, 2008 and $0.5 million as of January 1, 2008.  We expect the unrecognized tax benefit at December 31, 2008, to decrease in the next twelve months because of the ongoing IRS examination of our 2005 and 2006 tax years that will be finalized in 2009.  It is currently estimated that the decrease in our unrecognized tax benefits during the next year will be approximately $0.8 million.

The statute of limitations for tax years 2004-2007 remains open for both federal and state taxing jurisdictions.  However, due to the  July 31, 2007, completion date of the federal examination of our 2003 and 2004 tax years, we believe that certain tax positions related to these tax years have been “effectively settled” for federal tax purposes.  Additionally, for the majority of our state tax jurisdictions, the statute of limitations for the 2003 tax year remains open at December 31, 2008.

Our subsidiary, Unioil Inc., which was acquired on December 6, 2006, filed separate tax returns for years prior to the acquisition date.  Unioil’s 2003-2006 tax returns remain open to examination at December 31, 2008.  Any unrecognized tax benefit associated with Unioil's tax returns is included in the above table amount.

NOTE 6 - LONG-TERM DEBT

   
December 31,
 
   
2008
   
2007
 
   
(in thousands)
 
             
Credit facility
  $ 194,500     $ 235,000  
12% Senior notes due 2018, net of discount of $2.6 million
    200,367       -  
Total long-term debt
  $ 394,867     $ 235,000  


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


Credit facility

We have a credit facility co-arranged by JPMorgan Chase Bank, N.A. ("JPMorgan") and BNP Paribas, as amended last on November 12, 2008, dated as of November 4, 2005, with an available commitment of $375 million as of December 31, 2008.  The credit facility, through a series of amendments, includes commitments from: Wachovia Bank N.A.; Bank of America, N.A.; Bank of Oklahoma; Allied Irish Banks p.l.c.; Guaranty Bank, FSB; Royal Bank of Canada; The Royal Bank of Scotland, plc; Calyon New York Branch; Compass Bank; The Bank of Nova Scotia; and BMO Capital Markets Financing, Inc.  The maximum allowable commitment under the current credit facility is $400 million.  The credit facility is subject to and secured by required levels of oil and natural gas reserves.  The credit facility requires an aggregated security of a value no less than 80% of the value of the direct interests included in the borrowing base properties.  Our credit facility borrowing base is subject to size redeterminations each April and October based upon a quantification of our reserves   at December 31st and June 30th, respectively.  A commodity price deck reflective of the current and future commodity pricing environment, as agreed upon by us and our lenders, is utilized to quantify our reserve reports and determine the underlying borrowing base.

We are required to pay a commitment fee of .5% per annum on the unused portion of the activated credit facility.  Interest accrues at an alternative base rate ("ABR") or adjusted LIBOR at our discretion.  The ABR is the greater of JPMorgan's prime rate, an adjusted secondary market rate for a three-month certificate of deposit plus 1% or the federal funds effective rate plus .5%.  ABR borrowings are assessed an additional margin spread up to 1.375% and adjusted LIBOR borrowings are assessed an additional margin spread of 1.625% to 2.375% based upon the outstanding balance as a percentage of the available balance.  The credit agreement requires, among other things, the maintenance of certain working capital and tangible net worth ratios.  No principal payments are required until the credit agreement expires on November 4, 2010.

The credit facility contains covenants customary for agreements of this type, including, but not limited to, limitations on our ability to: (a) incur additional indebtedness and guarantees, (b) create liens and other encumbrances on our assets, (c) consolidate, merge or sell assets, (d) pay dividends and other distributions, (e) make certain investments, loans and advances, (f) enter into sale/leaseback transactions, (g) enter into transactions with our affiliates, (h) change the character of our business, (i) engage in hedging activities unless certain requirements are satisfied, (j) issue certain types of stock, and (k) make certain amendments to our organizational documents.  The credit facility also requires us to execute and deliver specified mortgages and other evidences of security and to deliver specified opinions of counsel and other evidences of title.  In addition, we are required to comply with certain financial tests and maintain certain financial ratios. The financial tests and ratios include requirements to: (a) maintain a minimum ratio of consolidated current assets to consolidated current liabilities, or working capital ratio, and (b) not to exceed a maximum leverage ratio.

As of December 31, 2008, we had drawn $194.5 million from our credit facility compared to $235 million as of December 31, 2007.  The borrowing rate on the outstanding balance was 4.6% as of December 31, 2008 compared to 7.1% as of December 31, 2007.  Amounts outstanding under our credit facility are secured by substantially all of our properties.  We were in compliance with all covenants at December 31, 2008, and expect to remain in compliance throughout 2009.

12% Senior Notes Due 2018

Our outstanding 12% senior notes were issued on February 8, 2008.  The principal amount of the senior notes is $203 million, which is payable at maturity on February 15, 2018.  Interest is payable in cash semi-annually in arrears on each February 15 and August 15.  The senior notes were issued at a price of 98.572% of the principal amount.  In addition, $5.4 million in costs associated with the issuance of the debt has been capitalized as a deferred loan cost.  The original discount and the deferred loan costs are being amortized to interest expense over the term of the debt using the effective interest method.  As a result of recent negative global financial market conditions, we estimate that the fair value of the senior notes was approximately $127 million or approximately 62.5% of par.  We determined this valuation based upon measurements of trading activity and quotes provided by brokers and traders participating in the trading of the securities.

The indenture governing the notes contains customary representations and warranties as well as typical restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt, (b) make certain investments or pay dividends or distributions on our capital stock or purchase or redeem or retire capital stock, (c) sell assets, including capital stock of our restricted subsidiaries, (d) pay dividends or other payments by restricted subsidiaries, (e) create liens that secure debt, (f) enter into transactions with affiliates, and (g) merge or consolidate with another company.  Additionally, we are subject to two incurrence covenants: 1) earnings before interest, taxes, depreciation, amortization and capital expenditures (“EBITDAX”) of at least two times interest expense and 2) total debt of less than 4.0 times EBITDAX.  As of December 31, 2008, our EBITDAX was 8.3 times interest expense and total debt was 1.8 time EBITDAX.  We were in compliance with all covenants as of December 31, 2008, and expect to remain in compliance throughout 2009.

The notes are senior unsecured obligations and rank, in right of payment, equally with all of our existing and future senior unsecured indebtedness and senior to any of our existing and future subordinated indebtedness.  The notes are effectively subordinated to any of our existing or future secured indebtedness to the extent of the assets securing such indebtedness.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


The notes are not initially guaranteed by any of our subsidiaries.  However, subsidiaries may be obligated to guarantee the notes if:

•      a subsidiary is a guarantor under our senior credit facility; and
•      the subsidiary has consolidated tangible assets that constitute 10% or more of our consolidated tangible assets.

Subject to specified exceptions, any subsidiary guarantor will be restricted from entering into certain transactions including the disposition of all or substantially all of its assets or merging with or into another entity.  Subsidiary guarantors may be released from a guarantee under circumstances specified in the indenture.  As of December 31, 2008, none of our subsidiaries were obligated as guarantors of our senior notes.

The indenture provides that at any time, which may be more than once, before February 15, 2011, we may redeem up to 35% of the outstanding notes with proceeds from one or more equity offerings at a redemption price of 112% of the principal amount of the notes redeemed, plus accrued and unpaid interest, as long as:

 
•
at least 65% of the aggregate principal amount of the notes issued on February 8, 2008, remains outstanding after each such redemption; and
•       the redemption occurs within 180 days after the closing of the equity offering.

The notes also provide that we may, at our option, redeem all or part of the notes, at any time prior to February 15, 2013, at the make-whole price set forth in the indenture, and on or after February 15, 2013, at fixed redemption prices, plus accrued and unpaid interest, if any, to the date of redemption.  Further, the indenture provides that upon a change of control, we must give holders of the notes the opportunity to put their notes to us for repurchase at a repurchase price of 101% of the principal amount, plus accrued and unpaid interest.

In connection with the issuance of the notes, we entered into a registration rights agreement with the initial purchasers in which we agreed to file a registration statement with the SEC related to an offer to exchange the notes for other freely tradable notes and to use commercially reasonable efforts to cause the registration statement to become effective on or prior to February 7, 2009.  On April 24, 2008, we filed the related registration statement on Form S-4.  The registration statement was declared effective May 23, 2008.

NOTE 7 - ASSET RETIREMENT OBLIGATIONS

Changes in carrying amounts of the asset retirement obligations associated with our working interest in oil and gas properties are as follows:

   
2008
   
2007
 
   
(in thousands)
 
             
Balance at beginning of year
  $ 20,781     $ 11,966  
Obligations assumed with development activities and acquisitions
    1,189       7,909  
Obligations discharged with disposed properties and asset retirements
    (114 )     (93 )
Accretion expense
    1,230       999  
Balance at end of year
  $ 23,086     $ 20,781  


If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost.  Approximately $0.1 million of the asset retirement obligations were classified as short-term and included in other accrued expenses as of December 31, 2008 and 2007.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


NOTE 8 - COMMITMENTS AND CONTINGENCIES

Drilling and Development Agreements .  We are a party to a pipeline expansion agreement with an unrelated third party, which is also currently the purchaser of the majority of our Wattenberg Field natural gas production.  Pursuant to the agreement, we have agreed to invest a minimum of $65 million to develop specified acreage in the Wattenberg Field, during a three-year period ending December 31, 2009.  Such capital spending will include costs to drill new wells and the cost to recomplete existing wells in this area.  Should we not meet the minimum commitment by December 31, 2009, we will be required to pay liquidated damages of $2 million, prorated based on our actual capital investment made to date.  As of December 31, 2008, our total capital expenditures pursuant to the agreement were $61.3 million, resulting in a maximum potential liquidating damages charge of $0.1 million.

In connection with the acquisition of oil and gas properties in October 2007 from an unaffiliated party, we are obligated to drill 100 wells in the Appalachian Basin by January 2016.  We will retain a majority interest in each well drilled.  For each well we fail to drill, we are obligated to pay to the seller liquidated damages of $25,000 per undrilled well for a total contingent obligation of $2.5 million or reassign to the seller the interest acquired in the number of undrilled well locations.  As of December 31, 2008, we have drilled 28 wells pursuant to this agreement.
 
We have entered into contracts that provide firm transportation, sales and processing charges on pipeline systems which we transport or sale our natural gas and the natural gas of other companies, working interest owners and our affiliated partnerships.  The remaining terms of the contracts range from two to 14 years and require us to pay these transportation and processing charges regardless if the required volumes are delivered or not.  The table below represents our gross future minimum firm transportation, sales and processing charges as of December 31, 2008, for the periods indicated.  We will record in our financial statements only our share based upon our working and net revenue interest in the wells.
 
Year
 
(in thousands)
 
2009
  $ 8,391  
2010
    19,047  
2011
    18,443  
2012
    25,071  
2013
    25,262  
Thereafter
    121,281  
    $
217,495
 
 
In September 2008, we entered into a pipeline and processing plants expansion agreement with an unrelated party, which is currently the purchaser of the majority of our Wattenberg Field natural gas production.  Pursuant to the agreement, we have agreed to make a capital investment of $60 million, for our own benefit, over a three-year period commencing on January 1, 2009, to develop or facilitate production in our Wattenberg Field dedicated to this purchaser.  If the purchaser fails to complete the pipeline and processing plants in accordance with the agreement, then the agreement effectively terminates.  The agreement also provides for certain volume commitments to be obtained by December 31, 2012.  Qualifying capital expenditures include the cost to drill new wells and the cost to recomplete existing wells in this area.  Failure to meet our drilling commitment would result in a maximum payment to the counterparty of $15 million in 2012; failure to meet our volume delivery commitment by December 31, 2012, would result in a maximum payment to the counterparty of $10 million in 2013.

Partnership Repurchase Provision .  Substantially all of our drilling programs contain a repurchase provision where investing partners may request that we purchase their partnership units at any time beginning with the third anniversary of the first cash distribution.  The provision provides that we are 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 repurchase is requested by investors, and subject to our financial ability to do so.  The maximum annual repurchase obligation as of December 31, 2008, was approximately $15.9 million.  We have adequate liquidity to meet this obligation.  During 2008 and 2007, we paid $1.8 million and $1.6 million, respectively, under this provision for the repurchase of partnership units.  As of December 31, 2008, outstanding repurchase offers to investing partners totaled $0.7 million, of which $0.2 million were consummated in 2009 prior to expiration.

Performance Supplements .  Our drilling programs formed from 1996 through the second quarter of 2005 contain a performance supplement that provides for changes in the distribution of partnership profits if certain levels of performance are not met.  The terms of this provision in the partnership agreements are not a guarantee of a rate of return on an investment in the partnership.  Under those specific conditions, such changes can result in our share of an affected partnership’s profits being reduced by up to one half of the amount to which we otherwise would be entitled in the affected period.  In no event would we be obligated to assume a disproportionate share of losses in such partnerships; should the partnerships that contain this provision in the partnership agreements incur a loss, our share of such losses would be unaffected by the terms of this provision.  In accordance with these provisions, our share of partnership profits was reduced by an aggregate of $1 million, $0.6 million, and $1 million during 2008, 2007and 2006, respectively.  As of December 31, 2008 and 2007, based on production through December 31 of the corresponding year, we had accrued $0.3 million and $0.2 million, respectively.

Partnership Casualty Losses.   As Managing General Partner of 33 partnerships, we have liability for any potential casualty losses in excess of the partnership assets and insurance.  We believe the casualty insurance coverage that we and our subcontractors carry is adequate to meet this potential liability.

Drilling Rig Contracts.   In order to secure the services for drilling rigs, we made commitments to the drilling contractors, which call for a minimum commitment of $12,500 daily for a specified amount of time if we cease to use the drilling rigs and a maximum commitment of $40,680 daily for a specified amount of time for daily use of the drilling rigs.  As of December 31, 2008, commitments for these two separate contracts expire in August 2009 and July 2010.  As of December 31, 2008, we have an outstanding minimum commitment for $4.2 million and an outstanding maximum commitment for $15.9 million, which includes $5.1 million related to a rig sublet to a third party and remains our obligation should the third party default on terms of the sublet agreement.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


Litigation .

Colorado royalty .  On May 29, 2007, Glen Droegemueller, individually and as representative plaintiff on behalf of all others similarly situated, filed a class action complaint against the Company in the District Court, Weld County, Colorado alleging that we underpaid royalties on natural gas produced from wells operated by us in parts of the State of Colorado (the “Droegemueller Action”).  The plaintiff sought declaratory relief and to recover an unspecified amount of compensation for underpayment of royalties paid by us pursuant to leases.  We removed the case to Federal Court on June 28, 2007.  On October 10, 2008, the court preliminarily approved a settlement agreement between the plaintiffs and the Company, on behalf of itself and the partnerships for which the Company is the managing general partner.  Based on the settlement terms, the settlement amount payable by the Company is $5.8 million.  Such moneys, in addition to moneys related to the settlement on behalf of the partnerships for which the Company is the managing general partner, were deposited in an escrow account on November 3, 2008.  We have accrued as of December 31, 2008, and included in other accrued expenses in our consolidated balance sheets, a related $5.8 million litigation reserve.  We believe that the amount accrued is adequate to satisfy this obligation.  Notice of the settlement was mailed to members of the class action suit in the fourth quarter of 2008.  The final settlement approval hearing is expected on April 7, 2009.

See Note 17 , Subsequent Events , regarding two West Virginia royalty lawsuits filed in January 2009.

Colorado Stormwater Permit .  On December 8, 2008, we received a Notice of Violation /Cease and Desist Order (the “Notice”) from the Colorado Department of Public Health, related to the stormwater permit for the Garden Gulch Road.  The Company manages this private road for Garden Gulch LLC.  The Company is one of four equal owners of Garden Gulch LLC, all of which are oil and gas companies operating in the Piceance region of Colorado.  The Notice alleges a deficient and/or incomplete stormwater management plan, failure to implement best management practices and failure to conduct required permit inspections.  The Notice requires corrective action and states that the recipient shall cease and desist such alleged violations.  The Notice states that a violation could result in civil penalties up to $10,000 per day.  The Company’s initial response was submitted on February 6, 2009.  No civil penalties have been imposed or requested at this time.  Given the preliminary stage of this proceeding and the inherent uncertainty in litigation, the Company is unable to predict the ultimate outcome of this suit at this time.

We are involved in various other legal proceedings that we consider normal to our business.  Although the results cannot be known with certainty, we believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position or results of operations.

Employment Agreements with Executive Officers .  We have employment agreements with our Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer and other executive officers.  The employment agreements provide for annual base salaries, eligibility for performance bonus compensation, and other various benefits, including retirement and termination benefits.

In the event of termination without cause or if an executive officer terminates employment for good reason, which includes a change in control, the executive officer is entitled to receive a payment in the amount up to three times the sum of his highest base salary during the previous two years of employment immediately preceding the termination date and his highest bonus received during the same two year period.  The executive officer is also entitled to (i) vesting of any unvested equity compensation, (ii) reimbursement for any unpaid expenses, (iii) retirement benefits earned under the current and/or previous agreements, (iv) continued coverage under our medical plan for up to 18 months, and (v) payment of any earned and unpaid bonus amounts.  In addition, the executive officer is entitled to receive any benefits that he would have otherwise been entitled to receive under our 401(k) and profit sharing plan, although those benefits are not increased or accelerated.

In the event that an executive officer is terminated for just cause, we are required to pay the executive officer his base salary through the termination date plus any bonus (only for periods completed and accrued, but not paid), incentive, deferred, retirement or other compensation, and to provide any other benefits, which have been earned or become payable as of the termination date but which have not yet been paid or provided.

In the event that an executive officer voluntarily terminates his employment for other than good reason, he is entitled to receive (i) his base salary, bonus and incremental retirement payment prorated for the portion of the year that the executive officer is employed, (ii) any incentive, deferred or other compensation which has been earned or has become payable, but which has not yet been paid under the schedule originally contemplated in the agreement under which they were granted or in full without discount within 60 days of the termination date at our discretion, (iii) any unpaid expense reimbursement upon presentation by the executive officer of an accounting of such expenses in accordance with our normal practices, and (iv) any other payments for benefits earned under the employment agreement or our plans.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


In the event of death or disability, the executive is entitled to receive (i) his base salary and bonus for the portion of the year the executive officer is employed; (ii) the base salary that would have been earned for six months after termination; (iii) immediate vesting of all equity and option awards; (iv) the payment of deferred retirement compensation based upon the schedule originally contemplated in the deferred retirement compensation agreement or in a lump-sum no later than two and one-half months following the close of the calendar year in which the death or disability occurred; (v) reimbursement for any unpaid expenses; (vi) and benefits earned under the 401(k) and profit sharing plan; and (vii) continued coverage under our medical plan for up to 18 months.

Derivative Contracts .  We would be exposed to oil and natural gas price fluctuations on underlying purchase and sale contracts should the counterparties to our derivative instruments or the counterparties to our gas marketing contracts not perform.  Nonperformance is not anticipated.  There were no counterparty default losses in 2008, 2007 or 2006.

NOTE 9 - COMMON STOCK

Stock-Based Compensation Plans

As approved by the shareholders in June 2004, we maintain a long-term equity compensation plan for our officers and certain key employees (the “2004 Plan”).  In accordance with the plan, awards may be issued in the form of stock options, stock appreciation rights, restricted stock or performance shares.  A total of 750,000 new shares of common stock have been reserved for issuance.  Awards pursuant to the plan vest over periods set at the discretion of the Compensation Committee of our Board of Directors (“Board”) and have a maximum exercisable period of ten years.  As of December 31, 2008, 312,418 common shares remain available for future awards.

As approved by the shareholders, we also maintain a restricted stock plan for non-employee directors.  A total of 100,000 new shares of common stock have been reserved for issuance under the plan.  During 2008, 2007 and 2006, 14,000, 12,710 and 6,551 common shares, respectively, were awarded in accordance with the plan.  Compensation expense for each of the years ended December 31, 2008, 2007 and 2006, related to these restricted shares was $1 million, $0.2 million and $0.1 million, respectively.  As of December 31, 2008, 59,844 common shares remain available for future awards.

In August 1999, the shareholders approved the 1999 Incentive Stock Option and Non-Qualified Stock Option Plan.  A total of 500,000 shares of our common stock were reserved for issuance upon the exercise of stock options.  All shares authorized to be awarded pursuant to this plan were awarded in years prior to 2002.  As of December 31, 2007, options for 11,000 common shares remained outstanding and exercisable; in 2008, these outstanding options were exercised.

The following table provides a summary of the effect of our stock based compensation plans on the results of operations for the periods presented.
 
   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
   
(in thousands)
 
                   
Total stock-based compensation expense (1)
  $ 6,702     $ 2,286     $ 1,516  
Income tax benefit
    (2,557 )     (882 )     (585 )
                         
Net income impact
  $ 4,145     $ 1,404     $ 931  
______________
(1) 2008 includes $1.1 million related to a separation agreement with our former president and $1.5 million related to a retirement agreement with our former chief executive officer.

Stock Option Awards.   As of December 31, 2008, all outstanding stock options were issued pursuant to our 2004 Plan.  Outstanding options expire ten years from the date of grant and become vested and exercisable ratably over a four year period.  We have not granted any new stock option awards since 2006.  In 2008, pursuant to a separation agreement with our former president and an agreement with our former chief executive officer, we modified options to purchase 9,905 shares by accelerating the vesting schedule, none of which would have vested pursuant to the original terms of the award.  The incremental change in fair value per share of the modified awards was immaterial.  The fair value of options modified in 2008 and granted in 2006, were estimated at the date of modification or grant using a Black-Scholes option-pricing model assuming no dividends and the following weighted average assumptions, with the exception of 4,678 shares in 2008, which were estimated to approximate fair value on the date of modification due to the short-term nature of the award:


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


   
Year Ended December 31,
 
   
2008
   
2006
 
             
Expected volatility
   
   43.0%
     
    40.4%
 
Expected term (in years)
   
-
     
  6.0
 
Risk-free interest rate
   
     1.6%
     
      4.2%
 
                 
Weighted-average grant date fair value per share
  $
  18.03
    $
  20.30
 
 
Expected volatilities are based on our historical volatility.  The expected life of an award is estimated using historical exercise behavior data.  The risk-free interest rate is based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the expected life of the award.  We do not expect to pay dividends, nor do we expect to declare dividends in the foreseeable future.

The following table provides a summary of our stock option award activity for the year ended December 31, 2008:

               
Weighted
 
         
Weighted
   
Average
 
   
Number of
   
Average
   
Remaining
 
   
Shares
   
Exercise
   
Contractual
 
   
Underlying
   
Price
   
Term
 
   
Options
   
Per Share
   
(years)
 
Outstanding at December 31, 2007
    51,567     $ 33.55       6.4  
Modified
    9,905       43.03          
Exercised
    (25,699 )     24.41          
Forfeited
    (17,422 )     43.86          
Outstanding at December 31, 2008
    18,351       41.68       6.8  
                         
Vested and expected to vest at December 31, 2008
    18,351       41.68       6.8  
                         
Exercisable at December 31, 2008
    12,736       40.41       6.6  


   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
   
(in thousands, except market price)
 
Total intrinsic value of options exercised
  $ 659     $ 1,691     $ 281  
Total intrinsic value of options outstanding
    -       1,319       1,984  
Total intrinsic value of options exercisable
    -       971       1,934  
Market price per common share as of December 31
    24.07       59.13       43.05  


The intrinsic value of options exercised represents the amount by which the market value of our stock at date of exercise exceeds the exercise price of the option.  The intrinsic values of the options outstanding and exercisable represent the amount by which the closing market price of our common stock at the last trading day of the year exceeds the exercise price of the options.  Total compensation cost related to stock options granted under the 2004 Plan not yet recognized as of December 31, 2008, was $0.1 million.  This cost is expected to be recognized over a weighted average period of 1.5 years.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


Restricted Stock Awards

We have issued restricted stock awards with vesting conditions that are either time-based or market-based.

Time-Based Awards .   The fair value of the time-based awards is amortized ratably over the requisite service period, primarily over four years. Time-based awards for non-employee directors vest on July 1 of the year following the date of grant.  Total intrinsic value is based upon the closing market price of our common stock on the last trading date of the year.  In 2008, pursuant to a separation agreement with our former president and an agreement with our former chief executive officer, we modified time-based awards to vest 25,027 shares by accelerating the vesting schedule, none of which would have vested pursuant to the original terms of the award, resulting in an increase in the original fair value of $0.4 million.
 
The following table sets forth the changes in non-vested time-based awards for the year ended December 31, 2008:

         
Weighted Average
 
         
Grant-Date
 
   
Shares
   
Fair Value
 
Non-vested at December 31, 2007
    201,845     $ 37.97  
Granted/modified
    161,982       57.64  
Vested
    (110,562 )     34.59  
Forfeited
    (35,205 )     45.53  
Non-vested at December 31, 2008
    218,060     $ 52.59  


   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
   
(in thousands, except market price)
 
Total intrinsic value of time-based awards vested
  $ 6,710     $ 2,208     $ 844  
Total intrinsic value of time-based awards non-vested
    5,249       10,161       5,671  
Market price per common share as of December 31
    24.07       59.13       43.05  


Total intrinsic value of time-based awards vested is based on the closing market price of our common stock on the date of vest.  Total intrinsic value of time-based awards not yet vested is based on the closing market price of our common stock on the last trading day of the year.  The total compensation cost related to non-vested time-based awards not yet recognized as of December 31, 2008, was $8.8 million.  This cost is expected to be recognized over a weighted-average period of 2.9 years.

Market-Based Awards .  The fair value of the market-based awards is amortized ratably over the requisite service period, primarily over three years for market-based awards.  The market-based shares vest only upon the achievement of certain per share price thresholds and continuous employment during the vesting period.  All compensation cost related to the market based-awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved.  In 2008, pursuant to a separation agreement with our former president, we modified market-based awards to vest 1,539 shares by accelerating the vesting schedule, none of which would have vested pursuant to the original terms of the award; pursuant to an agreement with our former chief executive officer, we modified market-based awards to vest  37,440 shares by accelerating the vesting schedule, none of which would have vested, nor was expected to vest, pursuant to the original terms of the award.  The incremental change in fair value per share of the modified awards was immaterial.

The weighted average grant date fair value per market-based share, including shares modified pursuant to an agreement with our former chief executive officer, was computed using the Monte Carlo pricing model using the following weighted average assumptions:

   
Year Ended December 31,
 
   
2008
   
2007
 
             
Expected term of award
 
3 years
   
3 years
 
Risk-free interest rate
   
   2.7%
     
    4.7%
 
Volatility
   
   45.6%
     
  44.0%
 
Weighted average grant date fair value per share
  $
 43.61
    $
 36.07
 


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


The following table sets forth the changes in non-vested market-based awards for the year ended December 31, 2008:

         
Weighted Average
 
         
Grant-Date
 
   
Shares
   
Fair Value
 
Non-vested at December 31, 2007
    31,972     $ 36.07  
Granted/modified
    87,384       43.61  
Vested
    (3,078 )     52.00  
Forfeited
    (43,595 )     40.81  
Non-vested at December 31, 2008
    72,683     $ 41.62  


The intrinsic value of market-based awards not yet vested at December 31, 2008 and 2007, was $1.7 million and $1.9 million, respectively, based upon the closing market price of our common stock on the last trading date of the year. The total compensation cost related to non-vested market-based awards not yet recognized as of December 31, 2008, is $1.4 million.  This cost is expected to be recognized over a weighted-average period of 1.1 years.

Treasury Share Purchases

In January 2006, we announced that our Board authorized the purchase of up to 10% (1,627,500 shares) of our common stock during 2006.  Stock purchases under this program were made in the open market or in private transactions, at times and in amounts that we deemed appropriate.  In October 2006, we completed our January 2006 program.  Total shares purchased pursuant to the program were 1,627,500 common shares at a cost of $66.3 million ($40.75 average price paid per share), including 100,000 shares from one of our executive officers at a cost of $4.1 million ($40.66 price paid per share).  All shares purchased in accordance with the program have subsequently been retired.

On October 16, 2006, our board of directors of approved a second 2006 purchase program authorizing us to purchase up to 10% (1,477,109 shares) of our then outstanding common stock through April 2008.  Stock purchases under this program were made in the open market or in private transactions, at times and in amounts that we deem appropriate.  There were 1,465,089 shares that were authorized but not yet purchased as of December 31, 2007.  Total shares purchased in 2008 pursuant to the program were 64,263 common shares at a cost of $4.4 million ($67.97 average price paid per share), including 63,756 shares from our executive officers at a cost of $4.3 million ($67.98 price paid per share).   Shares purchased in 2008 from employees, excluding executive officers, were generally purchased at fair market value based on the closing price on the date of purchase and were primarily purchased to satisfy the statutory minimum tax withholding requirement for restricted stock that vested in 2008.  Shares purchased from executive officers in 2008 were primarily pursuant to a separation agreement with our former president and to satisfy the statutory minimum tax withholding requirements for shares vested in 2008.  Shares purchased in prior years were generally purchased at fair market value based on the closing price on the date of purchase and were primarily purchased to satisfy the statutory minimum tax withholding requirement for shares vesting in prior years.  The authorization to purchase the remaining 1,400,826 shares effectively expired on April 30, 2008.  All shares purchased in accordance with the program have been subsequently retired.

Pursuant to our senior notes indenture entered on February 8, 2008, any future purchases are limited, see   Note 6 , Long-Term Debt .

Shareholders’ Rights Agreement

On September 11, 2007, we entered into a rights agreement, with Transfer Online, Inc., as rights agent.  The rights agreement is designed to improve the ability of our board of directors to protect the interest of our shareholders in the event of an unsolicited takeover attempt.  Our Board declared a dividend of one right for each outstanding share of our common stock.  The right dividend was paid to shareholders of record on September 14, 2007.  A “distribution date,” as defined in the rights agreement, can occur after any individual shareholder exceeds 15% ownership of our outstanding common stock.  After the occurrence of a “distribution date,” the right entitles each registered holder (other than the acquiring shareholder who triggered the “distribution date”), to purchase shares of our common stock (or, in certain circumstances, cash, property or other securities) having a then-current value equal to two times the exercise price of the right (i.e., for the $240 exercise price, the rights holder receives $480 worth of common stock).  The exercise price is subject to adjustment for various corporate actions which affect all shareholders, such as a stock split.  The rights agreement and all rights will expire on September 11, 2017.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


Common and Preferred stock

  Effective July 17, 2008, pursuant to shareholder approval, we amended and restated our Articles of Incorporation to: (1) increase the number of the Company's authorized shares of common stock, par value $0.01, from 50,000,000 shares to 100,000,000 shares, and (2) authorize 50,000,000 shares of Company preferred stock, par value $0.01, which may be issued in one or more series, with such rights, preferences, privileges and restrictions as shall be fixed by our Board of Directors from time to time.  As of December 31, 2008, no preferred stock had been issued.

NOTE 10 - EMPLOYEE BENEFIT PLANS

 We sponsor a qualified retirement plan covering substantially all of our employees.  The plan consists of a 401(k) component and a profit sharing component.  The 401(k) component enables eligible employees to contribute a portion of their compensation through pre-tax payroll deductions in accordance with specific guidelines.  We provide a discretionary matching contribution based on a percentage of the employees' contributions up to certain limits.  Our contribution to the profit sharing component is discretionary.  Our total combined expense for both 401(k) and profit sharing in 2008, 2007 and 2006, was $1.9 million, $1.4 million and $3.1 million, respectively.

 We provide a supplemental retirement benefit of deferred compensation under terms of the various employment agreements with certain executive officers.  During 2008, 2007 and 2006, we charged $0.2 million, $0.4 million and $0.3 million related to this plan to general and administrative expenses, respectively, and we have recorded a related liability in the amount $2.4 million and $2.2 million as of December 31, 2008 and 2007, respectively.

 In addition to the supplemental retirement benefit of deferred compensation, we offer a supplemental healthcare benefit covering certain executive officers and their spouses in accordance with each officer's employment agreement.  Expense incurred during 2008 and 2007 related to this plan was immaterial.  As of December 31, 2008 and 2007, we had a recorded liability of $0.6 million.

 We maintain a non-qualified deferred compensation plan for our non-employee directors.  The amount of compensation deferred by each participant is based on participant elections.  The amounts deferred pursuant to the plan are invested in our common stock, maintained in a rabbi trust and are classified in the balance sheet as treasury shares as a component of shareholders' equity.  The plan may be settled in either cash or shares as requested by the participant.  As of December 31, 2008 and 2007, we had recorded a long-term liability of $0.2 million and $0.3 million, respectively, which is included in other liabilities in our consolidated balance sheets.

NOTE 11 - TRANSACTIONS WITH AFFILIATES

Funds held for future distribution on our consolidated balance sheets represent amounts owed to affiliated partnerships and others for production proceeds received by us on their behalf and undistributed as of December 31, 2008 and 2007.

Amounts due from/to the affiliated partnership are primarily related to derivative positions, unbilled well lease operating expenses, and costs resulting from audit and tax preparation services.

We enter into derivative instruments for our own production as well as for our 33 affiliated partnerships’ production.  We enter into these derivative instruments for us and, as the managing general partner, for the affiliated partnerships jointly by area of operation.  Prior to September 30, 2008, as volumes produced changed, the allocation between us and the affiliated partnerships changed.  As of September 30, 2008, we fixed the allocation of the derivative positions between us and each affiliated partnership.  Fixed quantities of each of the then existing positions were allocated to us and the affiliated partnerships based upon current estimated future production.  For positions entered into subsequent to September 30, 2008, specific designations of the quantities between us and the affiliated partnerships are made at the time the positions are entered into based on estimated future production.  As of December 31, 2008, we have recorded a payable to affiliates of $37.5 million representing their allocated portion of the fair value of our gross derivative assets and a due from affiliates of $1.6 million representing their allocated portion of the fair value of our gross derivative liabilities.

Our natural gas marketing segment manages the marketing of oil and natural gas for our affiliated partnerships in the Appalachian Basin.  Our sales from natural gas marketing activities include $12.4 million, $9.3 million and $17.6 million in 2008, 2007 and 2006, respectively, related to the marketing of oil and natural gas on behalf of our affiliated partnerships.  Included in our cost of natural gas marketing activities is $12.1 million, $9.1 million and $17.3 million for 2008, 2007 and 2006, respectively, related to these sales .


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


We provided oil and gas well drilling services to our affiliated partnerships.  Pursuant to our cost-plus drilling arrangements and our corresponding net presentation, we performed drilling services for our affiliated partnerships totaling $68 million, $68.4 million and $87 million in 2008, 2007 and 2006, for which we recognized $7.6 million, $11.4 million and $12.4 million in oil and gas well drilling operations revenue, respectively.  As part of the oil and gas well drilling services we provide to our affiliated partnerships, we sell to them at cost the oil and gas leases upon which the wells are drilled.  For the years ended December 31, 2008, 2007 and 2006, we sold to our affiliated partnerships leases in the amounts of $0.5 million, $1.4 million and $1.8 million, respectively.  Further, we provide well operations and pipeline services to our affiliated partnerships.  Substantially all of our revenue and expenses related to oil and gas well drilling operations and revenues from well operations and pipeline income are associated with services provided to our affiliated partnerships.

Revenues from oil and gas well drilling operations and costs of oil and gas well drilling operations each include $0.1 million during 2006 related to investments made by executive officers for working interests in wells drilled during in 2006.  Amounts invested by the executive officers during 2007 were immaterial. No amounts were invested by the executive officers during 2008.

Management fees collected from the affiliated partnerships were $1.3 million in each of the years 2007 and 2006.  Management fees are included in other income on our consolidated statements of operations.  In 2008, we did not offer a drilling partnership; therefore, no management fee was collected from an affiliated partnership in 2008.

Through our wholly-owned subsidiary, PDC Securities Incorporated, we act as Dealer-Manager of the drilling partnerships.  PDC Securities receives the applicable commissions and marketing allowances from the Escrow Agent of the drilling program and distributes them to the soliciting broker/dealers who sell the programs.  The commissions and marketing allowances received by PDC Securities are included in other income net of the commissions distributed to the soliciting broker/dealer.  The commissions and marketing allowances retained by PDC Securities were $0.5 million and $0.6 million and those distributed to the soliciting broker/dealers amounted to $8.3 million and $8.8 million for the years ended December 31, 2007 and 2006, respectively.  In 2008, we did not offer a drilling partnership; therefore, no commissions and marketing allowances were received, distributed or retained by PDC Securities.

NOTE 12 - LEASE OBLIGATIONS

 We have entered into operating leases principally for the leasing of natural gas compressors, office space in Denver and Bridgeport, and general office equipment.  The future minimum lease payments under these non-cancelable operating leases as of December 31, 2008, are as follows:

Year
 
(in thousands)
 
2009
  $ 2,687  
2010
    1,645  
2011
    1,081  
2012
    309  
2013
    74  
Thereafter
    44  
    $ 5,840  


Operating lease expense for the years ended December 31, 2008, 2007 and 2006, was $2.5 million, $1.5 million and $0.4 million, respectively.

NOTE 13 - SALE OF OIL AND GAS PROPERTIES

Grand Valley Field Properties

In July 2006, we sold to an unaffiliated company a portion of our undeveloped leasehold located in Grand Valley Field, Garfield County, Colorado.  The sale encompassed 100% of the working interest in approximately 8,700 acres, including approximately 6,400 acres of the Chevron leasehold and 2,300 acres of the Puckett Land Company leasehold.  We retained approximately 475 undeveloped locations on 10 acre spacing on the Grand Valley Field leasehold in addition to all of our producing properties in the field.  The proceeds from the sale were $353.6 million.  We recorded a gain on sale of leaseholds of $328 million and a deferred gain on sale of leaseholds of $25.6 million.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


Pursuant to the purchase and sale agreement, we were obligated to either drill 16 wells on specifically identified acreage over the next three years or pay liquidated damages of $1.6 million per un-drilled well for a total contingent obligation of $25.6 million, which was reflected as a deferred gain on sale of leaseholds on the balance sheet as of December 31, 2006.  In May 2007, we entered into a letter agreement amending the original purchase and sale agreement.  The letter agreement relieved us of the obligation, in its entirety, to either drill 16 wells or pay liquidated damages, resulting in the recognition of the remaining $25.6 million deferred gain on sale of leaseholds in the second quarter of 2007.  Pursuant to the letter agreement, we were obligated to drill six wells on specifically identified acreage.  As of December 31, 2007, we had drilled all six wells, which were drilled on the unaffiliated party's leasehold for its benefit and at its cost.

In conjunction with the purchase and sale agreement described above, we entered into a LKE agreement, in accordance with Section 1031 of the Internal Revenue Code, with a “qualified intermediary.”  Proceeds in the amount of $300 million were transferred directly to the qualified intermediary to be held in trust pursuant to the terms of the LKE agreement.  We had until mid-January 2007 to close any acquisition of suitable like-kind property, allowing us to take advantage of the income tax deferral benefits of a LKE transaction.

In December 2007, we sold to the same unaffiliated party above a portion of our North Dakota properties for approximately $34.7 million.  The properties, located in Dunn, Williams and McKenzie Counties, North Dakota, include interests in five producing Bakken wells and approximately 72,000 net undeveloped acres.  The reduction in our production and proved reserves as a result of this transaction is not material.  We recorded a gain on sale of leaseholds of $7.7 million in the fourth quarter of 2007.  Following the sale, we retain ownership in three producing wells in Dunn County, ten producing wells in Burke County and approximately 60,000 acres of undeveloped leasehold in Burke County.

NOTE 14 – ACQUISITIONS
 
2007 Acquisitions
 
Acquisition of Internal Revenue Code Section 1031 – Like-Kind Exchange Properties
 
During the first quarter of 2007, we completed the acquisition of suitable like-kind properties in accordance with the LKE agreement we entered into in connection with our sale of undeveloped leaseholds located in Grand Valley Field, Garfield County, Colorado in July 2006.  We acquired, for cash, qualifying oil and gas properties totaling $188.9 million, including costs of acquisition, as described below.

EXCO Properties.   On January 5, 2007, we completed the purchase of producing properties and undeveloped drilling locations and acreage in the Wattenberg Field of the DJ Basin, Colorado from EXCO Resources Inc., an unaffiliated party.  The acquisition included substantially all of EXCO’s assets in the area and encompassed 144 oil and natural gas wells (approximating 25.5 Bcfe proved developed reserves as of December 31, 2005) and 8,160 acres of leasehold interests.  The wells and leases acquired are located in Weld, Adams, Larimer, and Broomfield Counties, Colorado.  We operate the assets and hold a majority working interest in the properties .

Company Sponsored Partnerships .  On January 10, 2007, we completed the purchase of the remaining working interests in 44 of our sponsored partnerships.  The transaction resulted in an increase in our ownership in 718 gross (423 net) wells that we currently operate.  The wells are located primarily in the Appalachian Basin and Michigan.

The following table presents the adjusted purchase price for the like-kind exchange property acquisitions described above as of December 31, 2007.

   
EXCO
   
Partnerships
 
   
(in thousands)
 
             
Cash consideration paid
  $ 128,672     $ 57,776  
Plus: direct costs of acquisition
    1,662       1,664  
Less: acquisition cost adjustments
    (119 )     (2,792 )
Total  acquisition cost
  $ 130,215     $ 56,648  


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


The following table presents, as of the respective date of acquisition, the final allocations of the purchase prices based on estimates of fair value.

   
EXCO
   
Partnerships
 
   
(in thousands)
 
             
Current assets acquired
  $ 91     $ -  
Proved oil and gas properties
    117,099       59,081  
Unproved oil and gas properties
    14,960       -  
Asset retirement obligation
    (422 )     (2,433 )
Other liabilities assumed
    (1,513 )     -  
Total  acquisition cost
  $ 130,215     $ 56,648  


The assessment of fair value of proved oil and gas properties acquired was based primarily on projections of expected discounted future cash flows of acquired oil and natural gas reserves.  To compensate for the inherent risk of estimating and valuing unproved properties, the discounted future net revenues of probable reserves were reduced by additional risk-weighting factors in that valuation.

Other.   In January 2007, we acquired from unaffiliated parties other like-kind undeveloped leaseholds in Erath County, Texas for $2.1 million, including costs of acquisition.  Acreage in this area is prospective for development of oil and natural gas reserves in the Barnett Shale.

Other Acquisitions

On February 22, 2007, we acquired, from an unaffiliated party, 28 producing wells and associated undeveloped acreage located in Colorado (Wattenberg Field) for a purchase price of $12 million, which was allocated to oil and gas properties.

On October 30, 2007, with an effective date of October 1, 2007, we purchased from unrelated parties, Castle Gas Company, et.al., a majority working interest in 762 natural gas wells located in southwestern Pennsylvania for approximately $54 million.  We estimated that the acquisition included approximately 47 Bcfe of reserves, or 31 Bcfe of proved reserves and 16 Bcfe of unproved reserves.  The purchase also included associated pipelines, equipment, real estate and undeveloped acreage.

The following table presents the adjusted purchase price for the Castle acquisition described above as of December 31, 2007.

   
(in thousands)
 
       
Cash consideration paid
  $ 53,041  
Plus: direct costs of acquisition
    443  
Plus: acquisition cost adjustments
    583  
Total  acquisition cost
  $ 54,067  


The following table presents, as of the respective date of acquisition, the final allocation of the purchase price based on estimates of fair value.

   
(in thousands)
 
       
Current assets acquired
  $ 185  
Proved oil and gas properties
    55,778  
Unproved oil and gas properties
    217  
Real estate and equipment, and other assets
    2,115  
Non current assets
    783  
Asset retirement obligation
    (4,043 )
Other liabilities assumed
    (968 )
Total  acquisition cost
  $ 54,067  


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


The assessment of fair value of proved oil and gas properties acquired was based primarily on projections of expected discounted future cash flows of acquired oil and natural gas reserves.  To compensate for the inherent risk of estimating and valuing unproved properties, the discounted future net revenues of probable reserves were reduced by additional risk-weighting factors in that valuation.

Pro Forma Financial Information

The results of operations for all of the above acquisitions have been included in our consolidated financial statements from the dates of acquisition.  The pro forma effect of the inclusion in our consolidated statement of operations for the year ended December 31, 2007, of the results of operations for the January and February 2007 acquisitions described above, individually and in the aggregate, was not material.

The following unaudited pro forma financial information presents a summary of our consolidated results of operations for the years ended December 31, 2007 and 2006, assuming the acquisitions of the EXCO properties, our sponsored partnerships and the Castle properties had been completed as of January 1, 2006, including adjustments to reflect the allocation of the purchase price to the acquired net assets.  The pro forma effect of the inclusion of the results of operations for all of the other acquisitions described above, individually and in the aggregate, was not material.

   
Year Ended December 31,
 
   
2007
   
2006
 
   
(in thousands, except per share data)
 
             
Total revenues
  $ 310,351     $ 315,492  
Net income
  $ 34,571     $ 243,105  
Earnings per common share:
               
Basic
  $ 2.34     $ 15.52  
Diluted
  $ 2.33     $ 15.44  


The pro forma results of operations are not necessarily indicative of what our results of operations would have been had the EXCO properties, our sponsored partnerships and the Castle properties been acquired at the beginning of the periods indicated, nor does it purport to represent our results of operations for any future periods.
 
2006 Acquisitions
 
On December 6, 2006, we completed a cash tender offer and purchased approximately 95.5% or 9,112,750 shares of the outstanding common stock of Unioil, an independent energy company with properties in northern Colorado and southern Wyoming.  The acquisition of more than 90% of the outstanding shares of common stock allowed us to effect a short-form merger of Unioil and one of our wholly-owned subsidiaries, resulting in the acquisition of the remaining 428,719 shares of Unioil.  Each share of Unioil common stock not tendered through the offer was converted into the right to receive $1.91 in cash, the same consideration paid for shares in the tender offer.  The total price paid for 100% of Unioil’s outstanding common stock was $18.6 million, including $0.4 million in direct costs of the acquisition.  The final acquisition cost allocation as reflected on our consolidated balance sheets as of December 31, 2007, included $25.8 million in properties and equipment, current assets of $0.7 million, a deferred tax liability of $6.8 million and other liabilities assumed of $1 million.  The pro forma effect of the inclusion of Unioil in our 2006 results of operations was not material.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


NOTE 15 – MAJOR CUSTOMERS

The following table identifies sales to individual customers constituting 10% or more of oil and natural gas sales, including natural gas sales by our natural gas marketing activities segment, and total revenues.

   
Oil and Gas Sales
   
Total Revenues
 
   
Year Ended December 31,
   
Year Ended December 31,
 
   
2008
   
2007
   
2006
   
2008
   
2007
   
2006
 
Customer
                                   
Williams Production RMT Company
    16.3 %     14.1 %     8.7 %     12.4 %     12.9 %     7.5 %
Tepco Crude Oil, LLC
    14.3 %     14.8 %     14.9 %     10.8 %     13.5 %     12.9 %
DCP Midstream, LP
    8.8 %     7.8 %     10.6 %     6.6 %     7.1 %     9.1 %
Sempra Energy Trading
    5.4 %     6.0 %     10.3 %     4.1 %     5.5 %     8.9 %


NOTE 16 - BUSINESS SEGMENTS

We separate our operating activities into four segments:  oil and gas sales, natural gas marketing, well operations and pipeline income and oil and gas well drilling operations.  All material inter-company accounts and transactions between segments have been eliminated.

Oil and Gas Sales.   Our oil and gas sales segment represents revenues and expenses from the production and sale of oil and natural gas.  Segment revenue includes oil and gas price risk management, net.  Segment profit consists of oil and gas sales revenues less its proportionate share of oil and gas production and well operations cost, exploration expense, direct general and administrative expense and DD&A expense.  Segment DD&A expense was $100.2 million, $68.1 million and $31.3 million in 2008, 2007 and 2006, respectively.

Natural Gas Marketing Activities.   Our natural gas marketing segment is composed of our wholly owned subsidiary, RNG, through which we purchase, aggregate and resell natural gas produced by us and others.  Segment profit primarily represents sales from natural gas marketing activities and direct interest income less costs of natural gas marketing activities, direct general and administrative expense.

Well Operations and Pipeline Income.   We charge our affiliated partnerships and other third parties competitive industry rates for well operations and natural gas gathering.  Segment revenue includes monthly operating and gas gathering fees we charge for each well in which we operate that is owned by others, including our sponsored partnerships.  Segment profit consists of well operations and pipeline income revenues less its proportionate share of oil and gas production and well operations cost and direct DD&A expense.  Segment DD&A expense was $1.9 million, $1.2 million and $1.9 million in 2008, 2007, 2006, respectively.

Oil and Gas Well Drilling Operations.   We drill natural gas wells for Company-sponsored drilling partnerships and retain an interest in each well. Our drilling and development segment reflects results of drilling and development activities conducted for affiliated and non-affiliated parties.  Segment profit consists of oil and gas well drilling revenues less cost of oil and gas well drilling.

Other.   This segment includes unallocated corporate general administrative expense, direct DD&A expense, direct interest income and interest expense.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


 Segment information for the years ended December 31, 2008, 2007 and 2006 is presented below.


Year Ended December 31,
 
2008
   
2007
   
2006
 
Revenues:
 
(in thousands)
 
Oil and gas sales
  $ 449,715     $ 177,943     $ 124,336  
Natural gas marketing activities
    140,263       103,624       131,326  
Well operations and pipeline income
    11,474       9,342       10,704  
Oil and gas well drilling operations
    7,615       12,154       17,917  
Unallocated amounts
    293       2,172       2,220  
Total
  $ 609,360     $ 305,235     $ 286,503  
                         
Segment Income Before Income Taxes:
                       
Oil and gas sales
  $ 231,885     $ 42,068     $ 61,868  
Natural gas marketing activities
    1,329       3,822       1,816  
Well operations and pipeline income
    3,933       3,136       2,823  
Oil and gas well drilling operations
    5,402       9,646       5,300  
Unallocated amounts
    (67,781 )     (4,482 )     315,602  
Total
  $ 174,768     $ 54,190     $ 387,409  
                         
Expenditures for Segment Long-Lived Assets:
                       
Oil & gas sales
  $ 309,395     $ 226,801     $ 133,401  
Natural gas marketing activities
    -       -       -  
Well operations and pipeline income
    7,564       6,715       1,419  
Oil and gas well drilling operations
    -       -       -  
Unallocated amounts
    6,194       5,472       12,125  
Total
  $ 323,153     $ 238,988     $ 146,945  
                         
                         
As of December 31,
                       
Segment Assets:
                       
Oil & gas sales
  $ 1,247,687     $ 862,237     $ 394,952  
Natural gas marketing activities
    50,117       40,269       39,899  
Well operations and pipeline income
    50,052       26,156       28,895  
Oil and gas well drilling operations
    2,028       4,959       87,746  
Unallocated amounts
    52,820       116,858       332,795  
Total
  $ 1,402,704     $ 1,050,479     $ 884,287  


NOTE 17 – SUBSEQUENT EVENTS

  West Virginia royalty litigation .   On January 26, 2009, we received notice of a lawsuit filed in West Virginia state court in Barbour County, Beymer and Beymer v. Petroleum Development Corporation and Riley National Gas Company , CA No. 09-C-3 (“Beymer lawsuit”) , alleging a class action for failure to properly pay royalties.  The allegations state that the Company improperly deducted certain charges and costs before applying the royalty percentage.  Punitive damages are requested in addition to breach of contract, tort, and fraud allegations.  On February 25, 2009, we filed to remove the action to federal court.
 
On January 30, 2009, the Company was served with another lawsuit alleging class action related to royalty payments file in West Virginia state court in Harrison County, Gobel, Phares and Cather v. Petroleum Development Corporation , CA No. 09-40-2.  West Virginia oil and gas production constitutes approximately 8% of the Company’s current oil and gas sales.  Given the preliminary stage of these proceedings and the inherent uncertainty in litigation, the Company is unable to predict the ultimate outcome of these suits at this time.
 

PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


NOTE 18 – SUPPLEMENTAL OIL AND GAS INFORMATION – UNAUDITED

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

We incurred costs in oil and gas property acquisition, exploration and development are presented below.


   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
   
(in thousands)
 
Acquisition of properties:
                 
Proved properties
  $ 6,147     $ 257,330     $ 802  
Unproved properties
    6,890       13,701       11,926  
Development costs
    257,656       194,031       114,487  
Exploration costs:
                       
Exploratory drilling
    26,499       12,972       18,660  
Geological and Geophysical
    2,121       6,299       2,234  
Total costs incurred
  $ 299,313     $ 484,333     $ 148,109  


The proved reserves attributable to the development costs in the above table were 125,198 MMcf and 2,354 MBbls   for 2008, 216,383 MMcf and 3,700 MBbls for 2007 and 64,126 MMcf and 2,955 MBbls for 2006.  Of the above development costs incurred for the years ended December 31, 2008, 2007 and 2006, the amounts of $66.2 million, $37.1 million, and $20.1 million, respectively, were incurred to develop proved undeveloped properties from the prior year end.

Property acquisition costs include costs incurred to purchase, lease or otherwise acquire a property.  Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, recompletions and to provide facilities to extract, treat, gather and store oil and gas.  Exploration costs include costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves.

Capitalized Oil and Gas Costs

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

   
December 31,
 
   
2008
   
2007
 
   
(in thousands)
 
             
Proved oil and gas properties
  $ 1,245,316     $ 953,904  
Unproved oil and gas properties
    32,768       41,023  
      1,278,084       994,927  
Less accumulated depreciation, depletion and amortization
    306,142       196,310  
    $ 971,942     $ 798,617  


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


Results of Operations for Oil and Gas Producing Activities

The results of operations for oil and gas producing activities, excluding natural gas marketing activities, are presented below.

   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
   
(in thousands)
 
Revenue:
                 
Oil and gas sales
  $ 321,877     $ 175,187     $ 115,189  
Oil and gas price risk management gain, net
    127,838       2,756       9,147  
      449,715       177,943       124,336  
Expenses:
                       
Production costs
    72,518       44,238       20,855  
Depreciation, depletion and amortization
    100,207       68,086       30,988  
Exploration costs
    45,105       23,551       8,131  
      217,830       135,875       59,974  
Results of operations for oil and gas producing activities before provision for income taxes
    231,885       42,068       64,362  
                         
Provision for income taxes
    86,493       16,280       24,818  
                         
Results of operations for oil and gas producing activities, excludes corporate overhead and interest costs
  $ 145,392     $ 25,788     $ 39,544  
                         
 
Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance and production and severance taxes.  In addition, production costs include administrative expenses and depreciation applicable to support equipment associated with these activities. Depreciation, depletion and amortization expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support equipment.  The provision for income taxes is computed using effective tax rates.

Net Proved Oil and Gas Reserves

We utilized the services of independent petroleum engineers to estimate our oil and gas reserves.  For the years ended December 31, 2008 and 2007, our reserve estimates for the Appalachian and Michigan Basins are based on reserve reports prepared by Wright & Company and for the Rocky Mountain Region, reserve estimates are based on reserve reports prepared by Ryder Scott Company, L.P.  For the year ended December 31, 2006, our reserve estimates for the Appalachian and Michigan Basins and NECO Area were based on reserve reports prepared by Wright & Company and our reserve estimates for the Rocky Mountain Region, with the exception of the NECO properties, were based on reserve reports prepared by Ryder Scott.  These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC.

Proved reserves are the estimated quantities of oil and natural gas that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.  Estimates of proved reserves may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change.  The Company's net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate.

Proved developed reserves are the quantities of oil and natural gas expected to be recovered through existing wells with existing equipment and operating methods.  In some cases, proved undeveloped reserves may require substantial new investments in additional wells and related facilities.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


An analysis of the change in estimated quantities of oil and gas reserves, all of which are located within the U.S., is shown below.

   
Oil
(MBbl)
   
Gas
(MMcf)
   
Total
(MMcfe)
 
Proved Reserves:
                 
Proved reserves, January 1, 2006
    4,538       247,288       274,516  
Revisions of previous estimates
    226       (21,721 )     (20,365 )
Extensions, discoveries and other additions
                       
Michigan Basin
    -       225       225  
Rocky Mountain Region
    2,955       63,901       81,631  
Purchases of reserves
                       
Appalachian Basin
    -       222       222  
Michigan Basin
    -       35       35  
Rocky Mountain Region
    276       3,504       5,160  
Dispositions to partnerships
    (92 )     (1,215 )     (1,767 )
Production
    (631 )     (13,161 )     (16,947 )
Proved reserves, December 31, 2006
    7,272       279,078       322,710  
                         
Revisions of previous estimates
    1,375       14,177       22,427  
Extensions, discoveries and other additions
                       
Appalachian Basin
    -       5,493       5,493  
Michigan Basin
    -       488       488  
Rocky Mountain Region
    3,700       210,402       232,602  
Purchases of reserves
                       
Appalachian Basin
    2       63,014       63,026  
Michigan Basin
    -       6,059       6,059  
Rocky Mountain Region
    4,490       39,239       66,179  
Dispositions to partnerships
    (591 )     (1,874 )     (5,420 )
Production
    (910 )     (22,513 )     (27,973 )
Proved reserves, December 31, 2007
    15,338       593,563       685,591  
                         
Revisions of previous estimates
    (1,538 )     (25,216 )     (34,444 )
Extensions, discoveries and other additions
                       
Appalachian Basin
    -       24,875       24,875  
Rocky Mountain Region
    2,354       100,323       114,447  
Purchases of reserves
                       
Appalachian Basin
    -       83       83  
Michigan Basin
    -       46       46  
Rocky Mountain Region
    106       1,712       2,348  
Dispositions to partnerships
    (63 )     (769 )     (1,147 )
Production
    (1,160 )     (31,760 )     (38,720 )
Proved reserves, December 31, 2008
    15,037       662,857       753,079  
                         
Proved Developed Reserves (1) , as of:
                       
January 1, 2006
    2,848       146,664       163,752  
December 31, 2006
    3,503       144,672       165,690  
December 31, 2007
    5,219       286,570       317,884  
December 31, 2008
    5,438       297,041       329,669  

______________
 
(1)
December 31, 2008, 2007, 2006, and January 1, 2006, reserve amounts reflect the reclassification of our Rocky Mountain Region refrac and behind pipe reserves of 75,863 MMcfe, 49,801 MMcfe, 21,062 MMcfe and 14,762 MMcfe, respectively, from proved developed to proved undeveloped.


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


2008 Activity.    In 2008, we recorded a downward revision of our previous estimate of proved reserves of approximately 34 Bcfe.  The revision was primarily due to a decrease of approximately 50 Bcfe due to lower commodity prices, 26 Bcfe due to increased operating costs, and 15 Bcfe due to adjustments to proved undeveloped reserve values, partially offset be an increase of 55 Bcfe due to asset performance.  New discoveries and extensions of 139 Bcfe in 2008 are due to drilling of 229 net wells and the addition of new proved undeveloped reserves.  Approximately 25 Bcfe were added in the Appalachian Basin, and approximately 114 Bcfe were added in the Rocky Mountain Region with 26 Bcfe in the Wattenberg Field, 80 Bcfe in Grand Valley Field, and 8 Bcfe in the NECO area.  We acquired approximately 2 Bcfe of proved reserves through the purchases of interest in some of our existing properties.  We primarily acquired reserves in the Wattenberg Field with the remaining reserves being split between the Appalachian Basin, Michigan, Piceance, the NECO area and North Dakota.  We sold proved reserves of approximately 1 Bcfe to unaffiliated third parties and to our sponsored partnerships for drilling activity.

2007 Activity .  In 2007, we recorded an upward revision to our previous estimate of proved reserves of approximately 22 Bcfe.  The revision was primarily due to an increase of approximately 25 Bcfe and 12 Bcfe, respectively, due to asset performance and higher commodity prices, partially offset by a decrease of approximately 15 Bcfe due primarily to increased operating costs, adjustments to proved undeveloped reserve values and change in well ownership interests.  New discoveries and extensions of 239 Bcfe in 2007 are due to the drilling of 218 net wells and the addition of new proved undeveloped reserves.  Approximately 233 Bcfe were added in the Rocky Mountain Region, with 43 Bcfe in the Wattenberg Field, 170 Bcfe in Grand Valley Field and 19 Bcfe in the NECO area.  We acquired approximately 135 Bcfe of proved reserves through purchases of oil and natural gas properties.  In the Rocky Mountain Region approximately 66 Bcfe of proved reserves were acquired in the Wattenberg Field, in the Appalachian Basin approximately 75 Bcfe were acquired and approximately 6 Bcfe in the Michigan Basin.  We sold proved reserves of approximately 5 Bcfe to unaffiliated third parties and to our sponsored partnerships for drilling activity.

2006 Activity.   In 2006 we recorded a downward revision to our previous estimate of proved reserves of approximately 20 Bcfe.  The revision was primarily due to a decrease of 3 Bcfe due to asset performance and a decrease of 10 Bcfe due to lower commodity prices and a decrease of approximately 7 Bcfe due to changes in proved undeveloped reserve value, operating expense, and well ownership interests.  New discoveries and extensions in 2006 of approximately 82 Bcfe were primarily due to the drilling of 91 net wells and adding new proved undeveloped reserves in the Rocky Mountain Region.  Approximately 34 Bcfe were added in Wattenberg Field, 33 Bcfe in Grand Valley Field and 12 Bcfe in the NECO area.  We acquired approximately 5 Bcfe of proved reserves through purchases of oil and natural gas properties in Wattenberg Field.  We sold proved reserves of approximately 2 Bcfe to our sponsored partnerships.

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

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


   
2008
   
2007
   
2006
 
   
(in thousands)
 
                   
Future estimated cash flows
  $ 3,867,461     $ 5,257,962     $ 1,804,796  
Future estimated production costs
    (1,325,362 )     (1,374,027 )     (571,346 )
Future estimated development costs
    (1,100,533 )     (876,961 )     (373,460 )
Future estimated income tax expense
    (384,676 )     (1,159,489 )     (334,536 )
Future net cash flows
    1,056,890       1,847,485       525,454  
10% annual discount for estimated timing of cash flows
    (700,085 )     (1,094,414 )     (309,792 )
                         
Standardized measure of discounted future estimated net cash flows
  $ 356,805     $ 753,071     $ 215,662  


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


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


   
2008
   
2007
   
2006
 
   
(in thousands)
 
                   
Sales of oil and gas production net of production costs
  $ (261,692 )   $ (137,725 )   $ (94,337 )
Net changes in prices and production costs
    (479,894 )     157,797       (301,132 )
Extensions, discoveries, and improved recovery, less related costs
    80,859       317,031       46,109  
Sales of reserves
    (2,012 )     (7,846 )     (3,356 )
Purchase of reserves
    4,280       342,792       11,003  
Development costs incurred during the period
    88,008       42,510       20,051  
Revisions of previous quantity estimates
    (79,536 )     92,462       (22,090 )
Changes in estimated income taxes
    239,054       (335,327 )     120,818  
Accretion of discount
    122,409       38,660       62,838  
Timing and other
                       
Timing
    (20,117 )     27,055       (29,672 )
Net changes in future development costs
    (87,625 )     -       -  
                         
Total
  $ (396,266 )   $ 537,409     $ (189,768 )


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

The estimated present value of future cash flows relating to proved reserves is extremely sensitive to prices used at any measurement period.  The average December 31 price used for each commodity at December 31, 2008, 2007 and 2006 is presented below.

   
Average Price
 
As of December 31,
 
Oil
   
Gas
 
2008
  $ 37.85     $ 4.98  
2007
    80.67       6.77  
2006
    57.70       4.96  


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


NOTE 19 - QUARTERLY FINANCIAL DATA (UNAUDITED)

Quarterly financial data for the years ended December 31, 2008 and 2007, are presented below   The sum of the quarters may not equal the total of the year's net income per share due to changes in the weighted average shares outstanding throughout the year.

   
2008
 
   
Quarter Ended
       
   
3/31/2008
   
6/30/2008
   
9/30/2008
   
12/31/2008
   
Year Ended
 
   
(in thousands, except per share data)
 
Revenues:
                             
Oil and gas sales
  $ 71,646     $ 94,549     $ 99,422     $ 56,260     $ 321,877  
Sales from natural gas marketing activities
    23,325       30,941       53,372       32,625       140,263  
Oil and gas well drilling
    3,083       2,887       1,232       413       7,615  
Well operations and pipeline income
    2,352       2,438       3,356       3,328       11,474  
Oil and gas price risk management gain (loss), net
    (42,310 )     (101,798 )     169,402       102,544       127,838  
Other income
    3       34       20       236       293  
Total revenues
    58,099       29,051       326,804       195,406       609,360  
                                         
Costs and expenses:
                                       
Oil and gas production and well operations costs
    18,132       20,815       22,173       17,089       78,209  
Cost of natural gas marketing activities
    22,121       30,117       54,372       32,624       139,234  
Cost of oil and gas well drilling
    78       518       501       1,116       2,213  
Exploration expense
    4,283       3,467       10,212       27,143       45,105  
General and administrative expense
    9,823       9,231       8,106       10,555       37,715  
Depreciation, depletion and amortization
    21,131       22,105       28,645       32,694       104,575  
Total costs and expenses
    75,568       86,253       124,009       121,221       407,051  
                                         
Income (loss) from operations
    (17,469 )     (57,202 )     202,795       74,185       202,309  
Interest income
    271       75       151       94       591  
Interest expense
    (4,932 )     (6,394 )     (7,817 )     (8,989 )     (28,132 )
Income (loss) before income taxes
    (22,130 )     (63,521 )     195,129       65,290       174,768  
                                         
Provision (benefit) for income taxes
    (8,202 )     (22,809 )     68,233       24,237       61,459  
                                         
Net income (loss)
  $ (13,928 )   $ (40,712 )   $ 126,896     $ 41,053     $ 113,309  
                                         
Earnings per common share:
                                       
Basic
  $ (0.95 )   $ (2.76 )   $ 8.59     $ 2.78     $ 7.69  
Diluted
  $ (0.95 )   $ (2.76 )   $ 8.55     $ 2.78     $ 7.63  
                                         
Weighted average common and common equivalent shares outstanding:
                                       
Basic
    14,738       14,742       14,767       14,778       14,736  
Diluted
    14,738       14,742       14,835       14,791       14,848  

 
PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


   
2007
 
   
Quarter Ended
       
   
3/31/2007
   
6/30/2007
   
9/30/2007
   
12/31/2007
   
Year Ended
 
   
(in thousands, except per share data)
 
Revenues:
                             
Oil and gas sales
  $ 34,016     $ 39,246     $ 44,437     $ 57,488     $ 175,187  
Sales from natural gas marketing activities
    21,987       29,924       19,934       31,779       103,624  
Oil and gas well drilling
    4,030       1,739       1,573       4,812       12,154  
Well operations and pipeline income
    3,298       1,292       2,092       2,660       9,342  
Oil and gas price risk management (loss) gain, net
    (5,645 )     3,742       6,345       (1,686 )     2,756  
Other income
    226       2       1,894       50       2,172  
Total revenues
    57,912       75,945       76,275       95,103       305,235  
                                         
Costs and expenses:
                                       
Oil and gas production costs and well operations costs
    9,035       11,628       12,645       15,956       49,264  
Cost of natural gas marketing activities
    21,512       28,780       19,810       30,482       100,584  
Cost of oil and gas well drilling
    564       246       749       949       2,508  
Exploration expense
    2,678       6,780       5,337       8,756       23,551  
General and administrative expense
    7,424       6,886       7,513       9,145       30,968  
Depreciation, depletion and amortization
    13,074       17,429       20,354       19,987       70,844  
Total costs and expenses
    54,287       71,749       66,408       85,275       277,719  
                                         
Gain on sale of leaseholds
    -       25,600       -       7,691       33,291  
                                         
Income from operations
    3,625       29,796       9,867       17,519       60,807  
Interest income
    1,143       454       462       603       2,662  
Interest expense
    (831 )     (1,450 )     (2,544 )     (4,454 )     (9,279 )
                                         
Income before income taxes
    3,937       28,800       7,785       13,668       54,190  
                                         
Income taxes
    1,436       10,749       3,326       5,470       20,981  
                                         
Net income
  $ 2,501     $ 18,051     $ 4,459     $ 8,198     $ 33,209  
                                         
Earnings per common share:
                                       
Basic
  $ 0.17     $ 1.22     $ 0.30     $ 0.56     $ 2.25  
Diluted
  $ 0.17     $ 1.21     $ 0.30     $ 0.55     $ 2.24  
                                         
Weighted average common and common equivalent shares outstanding:
                                       
Basic
    14,726       14,740       14,757       14,758       14,744  
Diluted
    14,854       14,860       14,827       14,859       14,841  


PETROLEUM DEVELOPMENT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Schedule II -VALUATION AND QUALIFYING ACCOUNTS

Description
 
Beginning Balance
January 1
   
Charged to
Costs and Expenses
   
Deductions
   
Ending
Balance
December 31
 
   
(in thousands)
 
                         
2008:
                       
Allowance for doubtful accounts (a)
  $ 357     $ 180     $ -     $ 537  
Valuation allowance for unproved oil and gas properties (b)
  $ 2,365     $ 12,798     $ 2,293     $ 12,870  
2007:
                               
Allowance for doubtful accounts (a)
  $ 415     $ 50     $ 108     $ 357  
Valuation allowance for unproved oil and gas properties (b)
  $ 596     $ 2,183     $ 414     $ 2,365  
2006:
                               
Allowance for doubtful accounts (a)
  $ 409     $ 7     $ 1     $ 415  
Valuation allowance for unproved oil and gas properties (b)
  $ 33     $ 653     $ 90     $ 596  
                                 
(a) Deductions represent the write-off of accounts receivable deemed uncollectible.
(b) Deductions represent amortization of expired or abandoned unproved oil and gas properties.

 
F-48
Exhibit 10.9

Employment Agreement
 
This Employment Agreement (the “Agreement”) is made and entered into this 31st day of December, 2008, effective as of January 1, 2008, by and between Petroleum Development Corporation, a Nevada Corporation (the “Company”), and Richard W. McCullough (the “Employee”).
 
WHEREAS, on the Effective Date (hereinafter defined), the Company employed Employee in the capacity of Chief Financial Officer and, effective as of March 9, 2008, in the capacity of President;
 
WHEREAS, upon the retirement of Steven R. Williams as Chief Executive Officer on June 23, 2008, the Company employed Employee in the additional capacity of Chief Executive Officer;
 
WHEREAS, Employee ceased to be Chief Financial Officer effective as of November 11, 2008 when his successor became Chief Financial Officer;
 
WHEREAS, the Company desires to employ the Employee to perform the duties and services incident to such positions for the Company, and the Employee wishes to be so employed by the Company, all upon the terms and conditions set forth in this Agreement;
 
NOW THEREFORE, in consideration of the premises and mutual covenants and obligations set forth herein and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged and accepted, the parties hereto, intending to be legally bound, agree as follows:
 
1.  
Effective Date and Term
 
a.  
Initial Term.   The effective date of this Agreement will be January 1, 2008 (the “Effective Date”), and the initial term will be for the period beginning on the Effective Date and ending December 31, 2009.
 
b.  
Automatic Extensions .  The Term of this Agreement will be extended for an additional twelve (12) months beginning on December 31, 2008 and on each successive December 31 unless either party provides the other with at least thirty (30) days prior written notice, or unless the contract has been terminated by the parties in accordance with the provisions of Section 7 of this Agreement.  The period of time from the Effective Date until the Termination Date, as defined in Section 7.b., will be the “Term.”
 
c.  
Change of Control .  In the event of a Change of Control, the Term of this Agreement will automatically be extended to the date that is twenty-four (24) months after the date of the Change of Control without any action on the part of the Company or the Employee.  Thereafter, the date of the Change of Control will be treated as the Effective Date for purposes of further automatic 12-month extensions of the Agreement under this
 
 
1
 
 
section.  “Change of Control” of the Company will occur on the earliest of the following events:
 
(i)  
Change in Ownership :  A change in ownership of the Company occurs on the date that any one person, or more than one person acting as a group, acquires ownership of stock of the Company that, together with stock held by such person or group, constitutes more than 50% of the total fair market value or total voting power of the stock of the Company, excluding the acquisition of additional stock by a person or more than one person acting as a group who is considered to own more than 50% of the total fair market value or total voting power of the stock of the Company.
 
(ii)  
Change in Effective Control :  A change in effective control of the Company occurs on the date that either:
 
(A)  
Any one person, or more than one person acting as a group, acquires (or has acquired during the l2-month period ending on the date of the most recent acquisition by such person or persons) ownership of stock of the Company possessing 30% or more of the total voting power of the stock of the Company; or
 
(B)  
A majority of the members of the Board of Directors of the Company (the “Board”) is replaced during any l2-month period by directors whose appointment or election is not endorsed by a majority of the members of the board of directors prior to the date of the appointment or election; provided, that this paragraph (B) will apply only to the Company if no other corporation is a majority shareholder.
 
(iii)  
Change in Ownership of Substantial Assets :  A change in the ownership of a substantial portion of the Company's assets occurs on the date that any one person, or more than one person acting as a group, acquires (or has acquired during the l2-month period ending on the date of the most recent acquisition by such person or persons) assets from the Company that have a total gross fair market value equal to or more than 40% of the total gross fair market value of the assets of the Company immediately prior to such acquisition or acquisitions. For this purpose, “gross fair market value” means the value of the assets of the Company, or the value of the assets being disposed of, determined without regard to any liabilities associated with such assets. It is the intent that this definition be construed consistent with the definition of “Change of Control” as defined under Internal Revenue Code Section 409A and the applicable Treasury Regulations, as amended from time to time.
 
2
 
2.  
Place of Employment
 
The place of employment will be the Company’s headquarters building in Bridgeport, West Virginia or Denver, Colorado unless the Employee and the Company agree to an alternative location.
 
3.  
Position and Responsibilities
 
a.  
Position.   As of the Effective Date, the Employee will serve as the Chief Financial Officer and, as of March 9, 2008, President, and in such positions shall report to the Chief Executive Officer of the Company and be under the general direction and control of the Chief Executive Officer.  Upon the retirement of Steven R. Williams as Chief Executive Officer, Employee will also serve as the Chief Executive Officer of the Company and will report to the Board.
 
b.  
Responsibilities.   The Employee will have obligations, duties, authority and power to do such acts as are customarily done by a person holding the same or equivalent positions in corporations of similar size to the Company.  The Employee shall perform such managerial duties and responsibilities for the Company as may be reasonably be assigned to him by the Chief Executive Officer (while serving in the capacity of Chief Financial Officer or in the capacity of Chief Financial Officer and President), the Chairman of the Board (while serving in the added capacity of Chief Executive Officer) and the Board (while serving in the capacity of Chief Executive Officer and Chairman of the Board), at no additional compensation, shall serve on the Board and in other such positions with any subsidiary corporation of the Company, or any partnership, limited liability company or other entity in which the Company has an interest (herein collectively called “Affiliates”), as the Chief Executive Officer or the Chairman of the Board or the Board as applicable, may from time to time determine.
 
c.  
Dedication of Professional Services .  The Employee shall devote substantially all of his business time, best efforts and attention to promote and advance the business of the Company and its Affiliates to perform diligently and faithfully all the duties, responsibilities and obligations of his positions with the Company.  Employee shall not be employed in any other business activity, other than with the Company and its Affiliates, during the Term, whether or not such activity is pursued for gain, profit or other pecuniary advantage without approval by the Compensation Committee of the Board (“Compensation Committee”); provided, however, that this restriction will not be construed as preventing Employee from investing his or her personal assets in a business which does not compete with the Company or its Affiliates, where the form or manner of such investment will not require services of any significance on the part of Employee in the operation of   the affairs of the business in
 
 
3
 
 
 which such investment is made and in which his participation is solely that of a passive investor.
 
d.  
Adherence to Standards.   Employee shall comply with the written policies, standards, rules and regulations of the Company from time to time established for all executive officers of the Company consistent with Employee's position and level of authority.
 
e.  
Minimum Stock Ownership.   Employee shall comply with the minimum stock ownership requirements for executive officers of the Company by the fifth anniversary of the effective date of his employment by the Company (November 13, 2011 being the fifth anniversary of the effective date of his employment) and until his Termination Date.  These requirements are, for a Chief Financial Officer, a minimum stock ownership equal to two (2) times the Employee’s Base Salary, as defined in Section 4.a. (or such level as adjusted from time to time) and, for a Chief Executive Officer, a minimum stock ownership equal to three (3) times the Employee’s Base Salary (or such level as adjusted from time to time).
 
4.  
Compensation
 
a.  
Base Salary.   The Company shall pay the Employee an annual base salary of $340,000 (the “Base Salary”) commencing on the Effective Date and ending on the Termination Date.  The Base Salary will be payable in accordance with the ordinary payroll practices of the Company.  The Compensation Committee shall review the Base Salary annually, and the Base Salary may be changed by the Compensation Committee in its sole discretion, taking into account the base salaries, aggregate annual cash compensation, and other compensation of individuals holding similar positions at other comparable companies and the performance of the Employee and the Company.
 
b.  
Performance Bonus.   In addition to his Base Salary, the Employee will be eligible to earn an annual performance bonus (the “Bonus”) during the Term based on the achievement of corporate performance objectives as determined by the Compensation Committee in its sole discretion.  The “Target Bonus” will be a specified percentage of the Base Salary, as set forth in the Petroleum Development Corporation Short-Term Incentive Compensation Plan for a given year which may be earned if the Employee meets all of the criteria established by the Compensation Committee.  However, the Bonus may be less than or more than the Target Bonus based on the level of performance of the Employee and the criteria established by and at the sole discretion of, the Compensation Committee.  For 2008, the Target Bonus will be equal to 90% of the Employee’s Base Salary and the maximum percentage will be 180% of the Employee’s Base Salary.  The Bonus will be paid in cash no later than March 15 of the
 
 
4
 
 
 following year.  To the extent practicable, the Bonus will meet the requirements for qualified performance-based compensation under Internal Revenue Code Section 162(m).
 
c.  
Retirement Compensation .  For each complete year worked by the Employee beginning from the effective date of his employment with the Company (November 13, 2006) and each anniversary thereof, the Employee will earn and be entitled to receive an annual retirement payment equal to $7,500 (such annual retirement payment being the “Retirement Payment”) for each of the ten years noted below.  For example, (i) if the Employee is employed for four years and three months, the annual Retirement Payment would be 4 x $7,500 = $30,000, and (ii) if the Employee is employed for five years and eight months, the annual Retirement Payment would be 5 x $7,500 = $37,500.  The annual Retirement Payment will be payable to the Employee, or in the event of the Employee’s death, to his estate, beneficiaries, or designees, on each of the first ten anniversary dates following the date the Employee leaves the service of the Company.  The Retirement Payment will be in addition to any deferred compensation, pension, or other payments the Employee has earned under this and any other previous and subsequent agreements with the Company and any other payments he may be due under the Company’s employee benefit plans.  The Retirement Payment is payable to the Employee even if the Employee's termination is for Just Cause pursuant to Section 7.c.
 
d.  
Equity Compensation Grant.   In addition to cash compensation, the Employee will be eligible to earn equity compensation during the Term.  The amounts and form of all equity compensation awards shall be determined at the sole discretion of the Board or its designee and only in accordance with shareholder approved stock compensation plans.  As of the Effective Date, under the Company’s Long-Term Equity Compensation Plan, the Employee will receive an award equal in value to $510,000, 50% of which will be awarded as restricted stock and 50% of which will be awarded as long-term incentive performance (“LTIP”) shares.  For this purpose, the value of the restricted stock and the LTIP shares will be determined by the Company’s compensation consultants and will be based on the average closing price of the stock of the Company for the month of December, 2007.  The restricted stock will vest at the rate of 25% for each complete year worked by the Employee under this Agreement, beginning on March 7, 2008 and vesting at the rate of 25% on each anniversary thereof.  The performance shares will vest in accordance with the timing and performance targets set forth in the documentation for such LTIP shares.  Future awards will vest on the schedule specified by the Board or its designee at the time of the award.
 
e.  
Succession-Related Grant .  On the date that Employee assumes the position of Chief Executive Officer of the Company, the Employee will
 
 
5
 
 
receive a one-time award of restricted stock equal in value to $700,000.  For this purpose, the value of the restricted stock will be determined by the Company’s compensation consultants and will be based on the average closing price of the stock of the Company for the month of December, 2007.  The restricted stock will vest at the rate of 20% for each complete year worked by the Employee under this Agreement, beginning from the Effective Date.
 
 
f.  
Other Compensation.   The Employee will continue to be eligible to participate in all other cash or stock compensation plans or programs maintained by the Company, as in effect from time to time, in which other senior executives of the Company are allowed to participate.
 
g.  
Recoupment of Certain Compensation.   If the Company has to restate all or a portion of its financial statements due to the material noncompliance of the Company with any financial reporting requirement under the securities laws, the Employee shall, for the affected years, reimburse the Company for any excess bonus paid to the Employee pursuant to Section 4.b.  The reimbursements shall be equal to the difference between the bonus paid to him for the affected years and the bonus that would have been paid to the Employee had the financial results been properly reported.  Such reimbursement shall be paid to the Company within ninety days after the Company notifies the Employee of the amount owed to the Company.
 
5.  
Employee Benefits
 
a.  
Participation in Company Benefit Plans.   During the Term, the Company shall provide the Employee with coverage under all employee pension and welfare benefit programs, plans and practices commensurate with his positions in the Company and to the extent permitted under the respective employee benefit plan.
 
b.  
Vacation.   The Employee will be entitled to twenty (20) days of paid vacation in each calendar year, to be taken at such times as is reasonably determined by the Employee to be consistent with the Employee’s responsibilities under this Agreement.
 
c.  
Expense Reimbursement.   The Employee is authorized to incur reasonable expenses in carrying out his duties and responsibilities under this Agreement, including, without limitation, expenses related to travel, meals, entertaining, and similar items related to such duties and responsibilities.  The Company shall reimburse the Employee for all such expenses on presentation by Employee from time to time of appropriately itemized and approved (consistent with the Company’s policy) accounts of such expenditures.  The Company shall reimburse the Employee for reasonable dues and expenses of membership in such club or clubs as the
 
 
6
 
 
Board reasonably deems necessary for the Employee to entertain on behalf of the Company and for costs associated with continuing education and professional dues if approved in advance by the Chief Executive Officer (by the Board after Employee becomes Chief Executive Officer).  All expense reimbursements for a calendar year will be paid in the normal course, but no later than March 15 of the following calendar year.
 
 
d.  
Life and Disability Insurance.   The Company will reimburse the Employee for the cost of life insurance on the Employee in the face amount of one million dollars ($1,000,000) with a person or persons named by the Employee as either the owner or the beneficiary as the Employee directs, and for the cost of a disability policy consistent with what is provided to other executive officers of the Company.  All reimbursements for a calendar year will be paid in the normal course, but no later than March 15 of the following calendar year.
 
e.  
Health Insurance.   The Company agrees that it will include the Employee under any hospital, surgical, or group health plan or policy adopted generally for the benefit of its employees.  The payment of the premiums for the Employee and his dependents will be determined in accordance with the rules and regulations adopted by the Company for its employees.  In addition to including the Employee and his dependents in such plan, the Company shall pay all reasonable hospital, surgical, medical, dental, and prescription expenses of the Employee and his dependents not covered by such a plan.  In the event the Company has no group health plan, the Company agrees to pay all reasonable premiums on any health insurance policy obtained by the Employee to provide such coverage.
 
f.  
Automobile.   During the Term, the Employee will be entitled to use of a Company automobile or payment of a car allowance in accordance with a plan approved by the Board or its designee.
 
6.  
Confidential Material and Employee Obligations .
 
a.  
Confidential Material.   The Employee shall not, directly or indirectly, either during the Term or thereafter, disclose to anyone (except in the regular course of the Company's business or as required by law), or use in any manner, any information acquired by the Employee during his employment by the Company with respect to any clients or customers of the Company or any confidential, proprietary or secret aspect of the Company's operations or affairs unless such information has become public knowledge other than by reason of actions, direct or indirect, of the Employee. Information subject to the provisions of this paragraph will include, without limitation:
 
(i)  
Brokers, broker/dealer firms, law firms used to prepare Company and partnership registration statements, due diligence
 
 
7
 
 
investigations, or other parties involved with the registration, review, or offering of the Company’s securities and drilling programs;
 
 
(ii)  
Names, addresses, and other information regarding investors in the Company’s drilling programs;
 
(iii)  
Names, addresses and other information regarding investors who participate with the Company in the drilling, completion or operation of oil and gas wells as joint venture partners, working interest owners, or in any other form of ownership;
 
(iv)  
Lists of or information about personnel seeking employment with or who are currently employed by the Company;
 
(v)  
Maps, logs, drilling reports and any other information regarding past, planned or possible future leasing, drilling, acquisition, or other operations that the Company has completed or is investigating or has investigated for possible inclusion in future activities;
 
(vi)  
Any other information or contacts relating to the Company's drilling, development, fund-raising, purchasing, engineering, marketing, merchandising, and selling activities.
 
b.  
Return of Confidential Material.   All maps, logs, data, drawings and other records and written and digital material prepared or compiled by the Employee or furnished to the Employee during the Term will be the sole and exclusive property of the Company and none of such material may be retained by the Employee upon termination of his employment.  The aforementioned materials include materials on the Employee’s personal computer.  Employee shall return to the Company or destroy all such materials on or prior to the Termination Date.  Notwithstanding the foregoing, the Employee will be under no obligation to return or destroy public information.
 
c.  
Non-Compete .  The Employee shall not directly, either during the Term or for a period of one (1) year thereafter, engage in any Competitive Business in West Virginia, Pennsylvania, Colorado, Utah, Wyoming, North Dakota, Michigan, Ohio, Kentucky, Texas and Tennessee; provided, however, that the ownership of less than five percent (5%) of the outstanding capital stock of a corporation whose shares are traded on a national securities exchange or on the over-the-counter market shall not be deemed engaging any Competitive Business.  "Competitive Business" shall mean the oil and natural gas industry, including oil and gas leasing, drilling, and other operations, syndication and marketing of partnership or other investments related to oil and natural gas operations, or any other business activities that are the same as or similar to the Company’s business operations as its business exists on the Effective Date or on the Termination Date.
 
 
8
 
d.  
No Solicitation.   The Employee shall not, directly or indirectly, either during the Term or for a period of one (1) year thereafter (i) solicit, directly or indirectly, the services of any person who was a full-time employee of the Company, its subsidiaries, divisions, or affiliates, or otherwise induce such employee to terminate or reduce employment, or (ii) solicit the business of any person who was a client or customer of the Company, its subsidiaries, divisions, or affiliates, in each case at any time during the last year of the Term. For purposes of this Agreement, the term “person” includes natural persons, corporations, business trusts, associations, sole proprietorships, unincorporated organizations, partnerships, joint ventures, limited liability companies or partnerships, and governments, or any agencies, instrumentalities, or political subdivisions thereof.
 
e.  
Remedies.   Employee acknowledges and agrees that the Company's remedy at law for a breach or a threatened breach of the provisions herein would be inadequate, and in recognition of this fact, in the event of a breach or threatened breach by Employee of any of the provisions of this Agreement, it is agreed that the Company will be entitled to equitable relief in the form of specific performance, a temporary restraining order, a temporary or permanent injunction or any other equitable remedy which may then be available, without posting bond or other security.  Employee acknowledges that the granting of a temporary injunction, a temporary restraining order or other permanent injunction merely prohibiting Employee from engaging in any business activities would not be an adequate remedy upon breach or threatened breach of this Agreement, and consequently agrees upon any such breach or threatened breach to the granting of injunctive relief prohibiting Employee from engaging in any activities prohibited by this Agreement.  No remedy herein conferred is intended to be exclusive of any other remedy, and each and every such remedy will be cumulative and will be in addition to any other remedy given hereunder now or hereinafter existing at law or in equity or by statute or otherwise.
 
7.  
Termination of the Agreement
 
a.  
Notice of Termination.   Either the Employee or the Board may terminate this Agreement at any time and in his or their sole discretion upon no less than thirty (30) days written Notice of Termination to the other party.  “Notice of Termination” means a written notice which shall indicate the specified termination provision in this Agreement relied upon (Section 7.c., Section 7.d., Section 7.e., Section 7.f, Section 7.g. or Section 7.h.) and shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of Employee's employment under the provision so indicated; provided, however, no such purported termination will be effective without such Notice of Termination; provided further, however, any purported termination by the Company or by Employee
 
 
9
 
 
must be communicated by a Notice of Termination to the other party hereto in accordance with  Section 9 (“Notices”) of this Agreement.
 
b.  
Termination Date .  The “Termination Date” means the date specified in the Notice of Termination. The Termination Date may not be less than thirty (30) days after the date such Notice of Termination is given.
 
c.  
Termination by the Company for Just Cause .
 
(i)  
The Company may terminate the Employee for “Just Cause” (as defined in Section 7.c.ii), provided that the Company shall:
 
(A)  
Give the Employee Notice of Termination as specified in Section 7.a., and
 
(B)  
Pay the Employee, within thirty (30) days after his Termination Date, his Base Salary through the Termination Date at the rate in effect at the time the Notice of Termination is given plus any Bonus(only for periods completed and accrued, but not paid), incentive, deferred, or other compensation, and provide any other benefits, which have been earned or become payable as of the Termination Date, pursuant to the terms of this or any other agreement, or compensation or benefit plan, but which have not yet been paid or provided.
 
(ii)  
For purposes of this Agreement “Just Cause” means a good faith determination of the Board that the Employee:
 
(A)  
Failed to substantially perform his duties with the Company (other than a failure resulting from his incapacity due to physical or mental illness) after a written demand for substantial performance has been delivered to him by the Board, which demand specifically identifies the manner in which the Board believes he has not substantially performed his duties, and the Employee has failed to cure such deficiency within thirty (30) days of the receipt of such notice;
 
(B)  
Has engaged in conduct the consequences of which are materially adverse to the Company, monetarily or otherwise; or
 
(C)  
Has pleaded guilty to or been convicted of a felony or a crime involving moral turpitude or dishonesty;
 
(D)  
Has engaged in conduct which demonstrates Employee’s gross unfitness to serve the Company as Chief Financial
 
 
10
 
 
Officer, President or Chief Executive Officer, as the case may be; or
 
(E)  
Has materially breached the terms of this Agreement.
 
(iii)  
(A)No act, or failure to act, on the Employee's part shall be grounds for termination with Just Cause unless he has acted or failed to act with an absence of good faith or without a reasonable belief that his action or failure to act was in or at least not opposed to the best interests of the Company.
 
 
(B)
The Employee will not be deemed to have been terminated with Just Cause under (ii)(B), (C), (D) or (E), unless there will have been delivered to the Employee a letter setting forth the reasons for the Company’s termination of the Employee for Just Cause.
 
d.  
Termination by the Company Without Just Cause.   If the Company terminates this Agreement prior to its expiration (including extensions as provided in Section 1.b.) for any reason other than for Just Cause or the death or Disability (as defined in Section 7.e.) of the Employee, the Company shall:
 
(i)  
Within thirty (30) days after the Termination Date, pay to the Employee a lump sum severance payment equal to three times the sum of: a) the Employee's highest Base Salary during the previous two years of employment immediately preceding the Termination Date, plus b) the highest Bonus paid or payable to the Employee for a year within the same two year period of employment immediately preceding the Termination Date,
 
(ii)  
Pay to the Employee any unpaid expense reimbursement upon presentation by the Employee of an accounting of such expenses in accordance with normal Company practices, but no later than March 15 of the year following the year of termination,
 
(iii)  
Immediately vest any unvested Company stock options and restricted stock (excluding all LTIP shares),
 
(iv)  
Pay any deferred income or Retirement Compensation (under Section 4.c.) or other benefit payments due under this or any other agreements or plans, provided such payments shall be made under the schedule originally contemplated in the agreement under which they were granted,
 
(v)  
Make any other payments or provide any benefits earned under this or any other employment agreement or plan, including the Company’s Long-Term Incentive Plan, and
 
 
11
 
(vi)  
Continue coverage of the Employee and any dependents covered at the time of termination under the Company’s group health plans at the Company’s cost for a period equal to the lesser of (i) 18 months or (ii) such period as the Employee is eligible to participate in another employer’s health plan.
 
e.  
Termination in the Event of Death or Disability.   This Agreement will be terminated by the Company in the event of the death of Employee and may be terminated by the Company in the event of the Disability (as hereinafter defined) of the Employee upon proper notification to the Employee (or his estate in the event of his death), provided the Company shall pay to the Employee (or to the estate of the Employee in the event of termination due to the death of the Employee) the compensation and other benefits described in Section 4.a. of this Agreement which would have been earned for (6) months after the Termination Date and any amounts earned under Section 4.b. of this Agreement prorated for the period up to the Termination Date.  “Disability” means being eligible to receive a disability benefit under the Federal Social Security Act.  All amounts payable under this Section 7.e. will be paid in a lump sum as soon as practicable, but no later than two and one-half (2-1/2) months following the close of the calendar year in which the death or Disability occurred.
 
f.  
Termination by the Employee for Good Reason .
 
(i)  
If the Employee terminates this Agreement for Good Reason (as defined in Section 7.f.ii.), provided that such Employee’s termination of employment occurs within ninety days of the Good Reason, the Company shall:
 
(A)  
Within thirty (30) days after the Termination Date, pay to the Employee a lump sum severance payment equal to three times the sum of: a) the Employee's highest Base Salary during the previous two years of employment immediately preceding the Termination Date, plus b) the highest Bonus paid or payable to the Employee for a year within the same two year period of employment immediately preceding the Termination Date.
 
(B)  
Pay to the Employee any unpaid expense reimbursement upon presentation by the Employee of an accounting of such expenses in accordance with normal Company practices, but no later than March 15 of the year following the year of termination,
 
(C)  
Immediately vest any unvested Company stock options and restricted stock (excluding all LTIP shares),
 
12
 
(D)  
Pay any deferred income or Retirement Compensation (under Section 4.c.) or other benefit payments due under this or any other agreements or plans, provided such payments shall be made under the schedule originally contemplated in the agreement under which they were granted,
 
(E)  
Make any other payments or provide any benefits earned under this or any other employment agreement or plan, including the Company’s Long-Term Incentive Plan, and
 
(F)  
Continue coverage of the Employee and any dependents covered at the time of termination under the Company’s group health plans at the Company’s cost for a period equal to the lesser of (i) 18 months or (ii) such period as the Employee is eligible to participate in another employer’s health plan.
 
(ii)  
“Good Reason” means the occurrence of any of the following events without Employee's prior express written consent:
 
(A)  
A material diminution in the Employee’s Base Salary;
 
(B)  
A material diminution in the Employee’s authority, duties, or responsibilities;
 
(C)  
A material diminution in the authority, duties, or responsibilities of the supervisor to whom the Employee is required to report, including a requirement that the Employee report to a corporate officer or employee instead of reporting directly to the board of directors of a corporation (or similar governing body with respect to an entity other than a corporation);
 
(D)  
A material diminution in the budget over which the Employee retains authority;
 
(E)  
A material diminution in reward opportunities under the annual Performance Bonus of Section 4.b. of this Agreement;
 
(F)  
A material change in the geographic location at which the Employee must perform the services; or
 
(G)  
Any other action or inaction that constitutes a material breach by the Company of this Agreement.
 
 
13
 
Employee must provide notice to the Company of the condition described in paragraphs (A)-(G) of this section within ninety (90) days, upon the notice of which the Company will have a period of thirty (30) days during which it may remedy the condition and not be required to pay the amount
 
g.  
Termination by the Employee for other than Good Reason.   The Employee may terminate this Agreement for other than Good Reason upon proper notification as provided in Section 7.a.  In such event the Company shall pay to the Employee:
 
(i)  
Within thirty (30) days after his Termination Date, in a lump sum, the compensation provided in Section 4 at the rate in effect at the time of the Notice of Termination.  The Base Salary and Bonus will be prorated for the portion of the year that the Employee is employed by the Company; provided, however, that if the Employee’s termination occurs prior to March 31 of the year the Employee will not be entitled to a prorated Bonus for the year;
 
(ii)  
Any incentive, deferred or other compensation which has been earned or has become payable pursuant to the terms of this or any other agreement or compensation or benefit plan as of the Termination Date, but which has not yet been paid, provided such payments will be made under the schedule originally contemplated in the agreement under which they were granted;
 
(iii)  
Any unpaid expense reimbursement upon presentation by the Employee of an accounting of such expenses in accordance with normal Company practices but not later than March 15 of the year following the year of termination; and
 
(iv)  
Any other payments for benefits earned under this or any other employment agreement or plan.
 
h.  
Termination by the Employee following Change of Control .
 
(i)  
If the Employee terminates this Agreement within two years following a Change of Control of the Company (as defined in Section 1.c.) the Company shall:
 
(A)  
Within thirty (30) days after the Termination Date, pay to the Employee a lump sum severance payment equal to three times the sum of: a) the Employee's highest Base Salary during the previous two years of employment immediately preceding the Termination Date, plus b) the highest Bonus paid or payable to the Employee for a year within the same two year period of employment immediately preceding the Termination Date, provided,
 
 
14
 
 
however, if the Agreement is terminated before March 15, 2009, the "highest Bonus" amount to be used for this provision will be the maximum performance bonus in effect for 2008 (180% of the Employee's Base Salary).
 
(B)  
Pay to the Employee any unpaid reimbursement upon presentation by the Employee of an accounting of such expenses in accordance with normal Company practices, but not later than March 15 of the year following the year of termination,
 
(C)  
Immediately vest any unvested Company stock options and restricted stock (excluding all LTIP shares),
 
(D)  
Pay any deferred income or Retirement Compensation (under Section 4.c.) or retirement payment or other benefit payments due under this or any other agreements or plans, provided such payments will be made under the schedule originally contemplated in the agreement under which they were granted,
 
(E)  
Make any other payments or provide any benefits earned under this or any other employment agreement or plan, including the Company’s Long-Term Incentive Plan, and
 
(F)  
Continue coverage of the Employee under the Company’s group health plans at the Company’s cost for a period equal to the lesser of (i) 18 months or (ii) such period as the Employee is receiving COBRA health continuation coverage from the Company.
 
i.  
Code Section 409A Compliance .
 
Except with respect to amounts paid pursuant to a schedule in a plan or arrangement outside of this Employment Agreement, it is intended that amounts payable under this Section 7 not be considered non-qualified deferred compensation subject to Internal Revenue Code Section 409A.  Employee is a Specified Employee under Internal Revenue Code Section 409A, therefore, to the extent such amounts are considered non-qualified deferred compensation payable upon a separation from service under Internal Revenue Code Section 409A, payment of those amounts so deferred under Internal Revenue Code Section 409A may not be made until at least six (6) months following the Employee’s separation from service of the Company (or, if earlier, the date of death of Employee).
 
8.  
Life Insurance.   The Company may, at any time after the execution of this Agreement, maintain any outstanding life insurance policies and apply for and procure as owner and for its own benefit new life insurance on Employee, in such
 
 
15
 
 
amounts and in such form or forms as the Company may determine.  Employee shall, at the request of the Company, submit to such medical examinations, supply such information, and execute such documents as may be required by the insurance company or companies to whom the Company has applied for such insurance.  Employee hereby represents that to his knowledge he is in excellent physical and mental condition.
 
 
 
9.  
Notices. For the purposes of this Agreement, notices and all other communications provided for in the Agreement shall be in writing and will be deemed to have been duly given when personally delivered, by facsimile transmission or sent by certified mail, return receipt requested, postage prepaid, or by expedited  (overnight) courier with established national reputation, shipping prepaid or billed to sender, in either case addressed to the respective addresses last given by each party to the other  (provided that all notices to the Company must be directed to the attention of the Secretary of the Company ) or to such other address as either party may have furnished  to the other in writing  in  accordance  herewith.  All notices and communication will be deemed to have been received on the date of delivery thereof, or on the second day after deposit thereof with an expedited courier service, except that notice of change of address will be effective only upon receipt.
 
 
  Company at:  
Petroleum Development Corporation
     
Attention:  Secretary
     
120 Genesis Boulevard
     
P.O. Box 26
     
Bridgeport WV 26330
       
 
  Employee at:  
Richard McCullough
     
218 Aaron Smith Drive
     
Bridgeport, WV 26330

10.  
Successors. This Agreement will be binding on the Company and any successor to any of its businesses or assets.  Without limiting the effect of the prior sentence, the Company shall use its best efforts to require any successor or assign (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company to expressly assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession or assignment had taken place. As used in this Agreement, “Company” means the Company as hereinbefore defined and any successor or assign to its business and/or assets as aforesaid which assumes and agrees to perform this Agreement or which is otherwise obligated under this Agreement by the first sentence of this Section, entitled Successors, by operation of law or otherwise.
 
11.  
Binding Effect.   This Agreement will inure to the benefit of and be enforceable by Employee's personal and legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees.  If Employee should die
 
 
16
 
 
while any amounts would still be payable to him hereunder if he had continued to live, all such amounts, unless otherwise provided herein, will be paid in accordance with the terms of this Agreement to Employee's estate.
 
12.  
Integration, Modification and Waiver.   This Agreement constitutes the sole employment agreement between the parties, and any prior employment agreement, written or oral, is terminated.  No provision of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing and signed by Employee and such officer of the Company as may be specifically designated by the Board.  No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with, any condition or provision of this Agreement to be performed by such other party will be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time.
 
13.  
Headings.   Headings used in this Agreement are for convenience only and will not be used to interpret or construe its provisions.
 
14.  
Waiver of Breach.   The waiver of either the Company or Employee of a breach of any provision of this Agreement will not operate or be construed as a waiver of any subsequent breach by either the Company or Employee.
 
15.  
Amendments.   No amendments or variations of the terms and conditions of this Agreement will be valid unless the same is in writing and signed by all of the parties hereto.
 
16.  
Survival of Obligations.   The provisions of Section 6 of this Agreement will continue to be binding upon the Employee and Company in accordance with their terms, notwithstanding the termination of the Employee’s employment with the Company for any reason or the expiration of this Agreement.
 
17.  
Severability.   The invalidity or unenforceability of any provision of this Agreement, whether in whole or in part, shall not in any way affect the validity and/or enforceability of any other provision contained herein.  Any invalid or unenforceable provision shall be deemed severable to the extent of any such invalidity or unenforceability.  It is expressly understood and agreed that while the Company and Employee consider the restrictions contained in this Agreement reasonable for the purpose of preserving for the Company the good will, other proprietary rights and intangible business value of the Company, if a final judicial determination is made by a court having jurisdiction that the time or territory or any other restriction contained in this Agreement is an unreasonable or otherwise unenforceable restriction against Employee, the provisions of such clause will not be rendered void but will be deemed amended to apply as to maximum time and territory and to such other extent as such court may judicially determine or indicate to be reasonable.
 
 
17
 
18.  
Governing Law.   This Agreement will be construed and enforced pursuant to the laws of the State of West Virginia giving effect to its conflict of laws.
 
19.  
Arbitration.   Any controversy or claim arising out of or relating to this Agreement or any transactions provided for herein, or the breach thereof, other than a claim for injunctive relief, will be settled by arbitration in accordance with the commercial Arbitration Rules of the American Arbitration Association (the “Rules”) in effect at the time demand for arbitration is made by any party.  The evidentiary and procedural rules in such proceedings will be kept to the minimum level of formality that is consistent with the Rules. The Company shall name one arbitrator, Employee shall name a second and the two arbitrators so chosen shall name a neutral, third arbitrator, who will serve as the sole arbitrator of the controversy or claim.  The third arbitrator must be experienced in the matters in dispute.  If the third and sole arbitrator is not agreed upon, the American Arbitration Association will name him or her.  Arbitration will occur in Bridgeport, West Virginia, or such other location agreed to by the Company and Employee.  The award made by the third arbitrator will be final and binding, and judgment may be entered in any court of law having competent jurisdiction. The award is subject to confirmation, modification, correction, or vacation only as explicitly provided in Title 9 of the United States Code.  The prevailing party will be entitled to an award of pre- and post-award interest as well as reasonable attorneys' fees incurred in connection with the arbitration and any judicial proceedings related thereto.
 
20.  
Executive Officer Status.   Employee acknowledges that he may be deemed to be an “executive officer” of the Company for purposes of the Securities Act of 1933, as amended (the “1933 Act”), and the Securities Exchange Act of 1934, as amended (the “1934 Act”) and, if so, he shall comply in all respects with all the rules and regulations under the 1933 Act and the 1934 Act applicable to him in a timely and non-delinquent manner. In order to assist the Company in complying with its obligations under the 1933 Act and 1934 Act, Employee shall provide to the Company such information about Employee as the Company shall reasonably request including, but not limited to, information relating to personal history and stockholdings.  Employee shall immediately report to the General Counsel of the Company or other designated officer of the Company all changes in beneficial ownership of any shares of the Company Common Stock deemed to be beneficially owned by Employee and/or any members of Employee's immediate family.
 
21.  
Pronouns.   All pronouns and any variations thereof will be deemed to refer to the masculine, feminine, neuter, singular, or plural, as the identity of the person or entity may require. As used in this Agreement: (1) words of the masculine gender shall mean and include corresponding neuter words or words of the feminine gender, (2) words in the singular shall mean and include the plural and vice versa, and (3) the word “may” gives sole discretion without any obligation to take any action.
 
 
18
 
22.  
Counterparts.    This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original, but all of which together will constitute but one document.
 
23.  
Exhibits.   Any Exhibits attached hereto are incorporated herein by reference and are an integral part of this Agreement.
 
IN WITNESS WHEREOF, the Company and the Employee have duly executed this Employment Agreement as of the date first above written.
 
 
           
 
Company
   
Executive
 
   
Petroleum Development Corporation
     
           
           
           
 
By:
/s/ Kimberly Wakim 
   
/s/ Richard W. McCullough
   
Kimberly Wakim
   
Richard W. McCullough
 
Position:
Chair of the
     
   
Compensation Committee
     

 
19
Exhibit 10.10
 
Employment Agreement
 
This Employment Agreement (the “Agreement”) is made and entered into this 31st day of December, 2008, by and between Petroleum Development Corporation, a Nevada Corporation (the “Company”), and Eric R. Stearns (the “Employee”).
 
WHEREAS, the Company currently employs the Employee in the capacity of Executive Vice President and, prior to March 9, 2008, had employed the Employee in the capacity of Executive Vice President of Exploration and Development;
 
WHEREAS, the Company desires to employ the Employee to perform the duties and services incident to such position for the Company, and the Employee wishes to be so employed by the Company, all upon the terms and conditions set forth in this Agreement;
 
NOW THEREFORE, in consideration of the premises and mutual covenants and obligations set forth herein and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged and accepted, the parties hereto, intending to be legally bound, agree as follows:
 
1.  
Effective Date and Term
 
a.  
Initial Term .  The effective date of this Agreement will be January 1, 2008 (the “Effective Date”), and the initial term will be for the period beginning on the Effective Date and ending December 31, 2009.
 
b.  
Automatic Extensions.   The Term of this Agreement will be extended for an additional twelve (12) months beginning on December 31, 2008 and on each successive December 31 unless either party provides the other with at least thirty (30) days prior written notice, or unless the contract has been terminated by the parties in accordance with the provisions of Section 7 of this Agreement.  The period of time from the Effective Date until the Termination Date, as defined in Section 7.b., will be the “Term.”
 
c.  
Change of Control .  In the event of a Change of Control, the Term of this Agreement will automatically be extended to the date that is twenty-four (24) months after the date of the Change of Control without any action on the part of the Company or the Employee.  Thereafter, the date of the Change of Control will be treated as the Effective Date for purposes of further automatic 12-month extensions of the Agreement under this section.  “Change of Control” of the Company will occur on the earliest of the following events:
 
(i)  
Change in Ownership : A change in ownership of the Company occurs on the date that any one person, or more than one person acting as a group, acquires ownership of stock of the Company that, together with stock held by such person or group, constitutes more than 50% of the total fair market value or total voting power of the stock of the Company, excluding the acquisition of
 
 
1
 
 
 additional stock by a person or more than one person acting as a group who is considered to own more than 50% of the total fair market value or total voting power of the stock of the Company.
 
(ii)  
Change in Effective Control : A change in effective control of the Company occurs on the date that either:
 
(A)  
Any one person, or more than one person acting as a group, acquires (or has acquired during the l2-month period ending on the date of the most recent acquisition by such person or persons) ownership of stock of the Company possessing 30% or more of the total voting power of the stock of the Company; or
 
(B)  
A majority of the members of the Board of Directors of the Company (the “Board”) is replaced during any l2-month period by directors whose appointment or election is not endorsed by a majority of the members of the board of directors prior to the date of the appointment or election; provided, that this paragraph (B) will apply only to the Company if no other corporation is a majority shareholder.
 
(iii)  
Change in Ownership of Substantial Assets : A change the ownership of a substantial portion of the Company's assets occurs on the date that any one person, or more than one person acting as a group, acquires (or has acquired during the l2-month period ending on the date of the most recent acquisition by such person or persons) assets from the Company that have a total gross fair market value equal to or more than 40% of the total gross fair market value of the assets of the Company immediately prior to such acquisition or acquisitions. For this purpose, “gross fair market value” means the value of the assets of the Company, or the value of the assets being disposed of, determined without regard to any liabilities associated with such assets.
 
It is the intent that this definition be construed consistent with the definition of “Change of Control” as defined under Internal Revenue Code Section 409A and the applicable Treasury Regulations, as amended from time to time.
 
2.  
Place of Employment
 
The place of employment will be the Company’s headquarters building in Bridgeport, West Virginia unless the Employee and the Company agree to an alternative location.
 
2
 
3.  
Position and Responsibilities
 
a.  
Position .  The Employee served as the Executive Vice President of Exploration and Development until March 9, 2008.  For periods on or after March 9, 2008, the Employee will serve as Executive Vice President.  In such capacities, the Employee will report to the Chief Executive Officer of the Company and be under the general direction and control of the Chief Executive Officer.
 
b.  
Responsibilities.   The Employee will have obligations, duties, authority and power to do such acts as are customarily done by a person holding the same or equivalent positions in corporations of similar size to the Company.  The Employee shall perform such managerial duties and responsibilities for the Company as may reasonably be assigned to him by the Chief Executive Officer and, at no additional compensation, shall serve in other such positions with any subsidiary corporation of the Company, or any partnership, limited liability company or other entity in which the Company has an interest (herein collectively called “Affiliates”), as the Chief Executive Officer may from time to time determine.
 
c.  
Dedication of Professional Services.   The Employee shall devote substantially all of his business time, best efforts and attention to promote and advance the business of the Company and its Affiliates to perform diligently and faithfully all the duties, responsibilities and obligations of his positions with the Company.  Employee shall not be employed in any other business activity, other than with the Company and its Affiliates, during the Term, whether or not such activity is pursued for gain, profit or other pecuniary advantage without approval by the Compensation Committee of the Board (“Compensation Committee”); provided, however, that this restriction will not be construed as preventing Employee from investing his or her personal assets in a business which does not compete with the Company or its Affiliates, where the form or manner of such investment will not require services of any significance on the part of Employee in the operation of the affairs of the business in which such investment is made and in which his participation is solely that of a passive investor.
 
d.  
Adherence to Standards.   Employee shall comply with the written policies, standards, rules and regulations of the Company from time to time established for all executive officers of the Company consistent with Employee's position and level of authority.
 
e.  
Minimum Stock Ownership.   Employee shall comply with the Company’s minimum stock ownership requirements for executive officers of the Company, such requirement being that by March 9, 2009 (the fifth anniversary of the date such minimum stock ownership requirements were
 
 
3
 
 
adopted by the Board) and until his Termination Date, Employee shall have a minimum stock ownership equal to two (2) times the Employee’s Base Salary, as defined in Section 4.a (or such level as adjusted from time to time).
 
4.  
Compensation
 
a.  
Base Salary.   The Company shall pay the Employee an annual base salary of $305,000 (the “Base Salary”) commencing on the Effective Date and ending on the Termination Date.  The Base Salary will be payable in accordance with the ordinary payroll practices of the Company.  The Compensation Committee shall review the Base Salary annually, and the Base Salary may be changed by the Compensation Committee in its sole discretion, taking into account the base salaries, aggregate annual cash compensation, and other compensation of individuals holding similar positions at other comparable companies and the performance of the Employee and the Company.
 
b.  
Performance Bonus.   In addition to his Base Salary, the Employee will be eligible to earn an annual performance bonus (the “Bonus”) during the Term based on the achievement of corporate performance objectives as determined by the Compensation Committee in its sole discretion.  The “Target Bonus” will be a specified percentage of the Base Salary, as set forth in the Petroleum Development Corporation Short-Term Incentive Compensation Plan for a given year which may be earned if the Employee meets all of the criteria established by the Compensation Committee.  However, the Bonus may be less than or more than the Target Bonus based on the level of performance of the Employee and the criteria established by and at the sole discretion of, the Compensation Committee.  For 2008, the Target Bonus will be equal to 62.5% of the Employee’s Base Salary and the maximum percentage will be 125% of the Employee’s Base Salary.  The Bonus will be paid in cash no later than March 15 of the following year.  To the extent practicable, the Bonus will meet the requirements for qualified performance-based compensation under Internal Revenue Code Section 162(m).
 
c.  
Retirement Compensation .  Pursuant to prior employment agreements, the Employee, as of the Effective Date, has earned a right to ten (10) annual payments of $30,000 (total $300,000).  For each additional complete year of employment with the Company, the Employee will earn and be entitled to receive an additional annual retirement payment equal to $7,500 (the “Retirement Payment”).  In the event the Employee terminates employment with the Company prior to the last day of a year pursuant to Sections 7.d., 7.f. or 7.h., the Employee will also earn an additional Retirement Payment equal to $7,500.  The Retirement Payment will be payable to the Employee, or in the event of the Employee’s death, to his estate, beneficiaries, or designees, on each of the first ten anniversary
 
 
4
 
 
dates following the date the Employee leaves the service of the Company.  The Retirement Payment will be in addition to any deferred compensation, pension, or other payments the Employee has earned under this and any other previous and subsequent agreements with the Company and any other payments he may be due under the Company’s employee benefit plans.  The Retirement Payment is payable to the Employee, even if the Employee's termination is for Just Cause pursuant to Section 7.c.
 
d.  
Equity Compensation Grant.   In addition to cash compensation, the Employee will be eligible to earn equity compensation during the Term.  The amounts and form of all equity compensation awards shall be determined at the sole discretion of the Board or its designee and only in accordance with shareholder approved stock compensation plans.  As of the Effective Date, under the Company’s Long-Term Equity Compensation Plan, the Employee will receive an award equal in value to $442,250, 50% of which will be awarded as restricted stock and 50% of which will be awarded as long-term incentive performance (“LTIP”) shares.  For this purpose, the value of the restricted stock and the LTIP shares will be determined by the Company’s compensation consultants and will be based on the average closing price of the stock of the Company for the month of December, 2007.  The restricted stock will vest at the rate of 25% for each complete year worked by the Employee under this Agreement, beginning on March 7, 2008 and vesting at the rate of 25% on each anniversary thereof.  The performance shares will vest in accordance with the timing and performance targets set forth in the documentation for such LTIP shares.  Future awards will vest on the schedule specified by the Board or its designee at the time of the award.
 
e.  
Succession-Related Grant .  On the date that Employee assumes the position of Executive Vice President of the Company (March 9, 2008), the Employee will receive a one-time award of restricted stock equal in value to $450,000.  For this purpose, the value of the restricted stock will be determined by the Company’s compensation consultants and will be based on the average closing price of the stock of the Company for the month of December, 2007.  The restricted stock will vest at the rate of 20% for each complete year worked by the Employee under this Agreement, beginning from the Effective Date.
 
f.  
Other Compensation.   The Employee will continue to be eligible to participate in all other cash or stock compensation plans or programs maintained by the Company, as in effect from time to time, in which other senior executives of the Company are allowed to participate.
 
g.  
Recoupment of Certain Compensation.   If the Company has to restate all or a portion of its financial statements due to the material noncompliance of the Company with any financial reporting requirement under the securities laws, the Employee shall, for the affected years, reimburse the
 
 
5
 
 
Company for any excess bonus paid to the Employee pursuant to Section 4.b.  The reimbursements shall be equal to the difference between the bonus paid to him for the affected years and the bonus that would have been paid to the Employee had the financial results been properly reported.  Such reimbursement shall be paid to the Company within ninety days after the Company notifies the Employee of the amount owed to the Company.
 
5.  
Employee Benefits
 
a.  
Participation in Company Benefit Plans.   During the Term, the Company shall provide the Employee with coverage under all employee pension and welfare benefit programs, plans and practices commensurate with his positions in the Company and to the extent permitted under the respective employee benefit plan.
 
b.  
Vacation.   The Employee will be entitled to twenty (20) days of paid vacation in each calendar year, to be taken at such times as is reasonably determined by the Employee to be consistent with the Employee’s responsibilities under this Agreement.
 
c.  
Expense Reimbursement.   The Employee is authorized to incur reasonable expenses in carrying out his duties and responsibilities under this Agreement, including, without limitation, expenses related to travel, meals, entertaining, and similar items related to such duties and responsibilities.  The Company shall reimburse the Employee for all such expenses on presentation by Employee from time to time of appropriately itemized and approved (consistent with the Company’s policy) accounts of such expenditures.  The Company shall reimburse the Employee for reasonable dues and expenses of membership in such club or clubs as the Board reasonably deems necessary for the Employee to entertain on behalf of the Company and for costs associated with continuing education and professional dues if approved in advance by the Chief Executive Officer.  All expense reimbursements for a calendar year will be paid in the normal course, but no later than March 15 of the following calendar year.
 
d.  
Life and Disability Insurance.   The Company will reimburse the Employee for the cost of life insurance on the Employee in the face amount of one million dollars ($1,000,000) with a person or persons named by the Employee as either the owner or the beneficiary as the Employee directs, and for the cost of a disability policy consistent with what is provided to other executive officers of the Company.  All reimbursements for a calendar year will be paid in the normal course, but no later than March 15 of the following calendar year.
 
e.  
Health Insurance.   The Company shall include the Employee under any hospital, surgical, or group health plan or policy adopted generally for the
 
 
6
 
benefit of its employees.  The payment of the premiums for the Employee and his dependents will be determined in accordance with the rules and regulations adopted by the Company for its employees.  In addition to including the Employee and his dependents in such plan, the Company shall pay all reasonable hospital, surgical, medical, dental, and prescription expenses of the Employee and his dependents not covered by such a plan.  If the Company has no group health plan, the Company agrees to pay all reasonable premiums on any health insurance policy obtained by the Employee to provide such coverage.
 
f.  
Automobile.   During the Term, the Employee will be entitled to use of a Company automobile or payment of a car allowance in accordance with a plan approved by the Board or its designee.
 
6.  
Confidential Material and Employee Obligations.
 
a.  
Confidential Material.   The Employee shall not, directly or indirectly, either during the Term or thereafter, disclose to anyone (except in the regular course of the Company's business or as required by law), or use in any manner, any information acquired by the Employee during his employment by the Company with respect to any clients or customers of the Company or any confidential, proprietary or secret aspect of the Company's operations or affairs unless such information has become public knowledge other than by reason of actions, direct or indirect, of the Employee. Information subject to the provisions of this paragraph will include, without limitation:
 
(i)  
Brokers, broker/dealer firms, law firms used to prepare Company and partnership registration statements, due diligence investigations, or other parties involved with the registration, review, or offering of the Company’s securities and drilling programs;
 
(ii)  
Names, addresses, and other information regarding investors in the Company’s drilling programs;
 
(iii)  
Names, addresses and other information regarding investors who participate with the Company in the drilling, completion or operation of oil and gas wells as joint venture partners, working interest owners, or in any other form of ownership;
 
(iv)  
Lists of or information about personnel seeking employment with or who are currently employed by the Company;
 
(v)  
Maps, logs, drilling reports and any other information regarding past, planned or possible future leasing, drilling, acquisition, or other operations that the Company has completed or is
 
7
 
 
investigating or has investigated for possible inclusion in future activities;
 
(vi)  
Any other information or contacts relating to the Company's drilling, development, fund-raising, purchasing, engineering, marketing, merchandising, and selling activities.
 
b.  
Return of Confidential Material.   All maps, logs, data, drawings and other records, electronic data and written material prepared or compiled by the Employee or furnished to the Employee during the Term will be the sole and exclusive property of the Company and none of such material may be retained by the Employee upon termination of his employment.  Notwithstanding the foregoing, the Employee will be under no obligation to return public information.   Notwithstanding the foregoing, the Employee will be under no obligation to return public information.
 
c.  
No Solicitation.   The Employee shall not, directly or indirectly, either during the Term or for a period of one (1) year thereafter (i) solicit, directly or indirectly, the services of any person who was a full-time employee of the Company, its subsidiaries, divisions, or affiliates, or otherwise induce such employee to terminate or reduce employment, or (ii) solicit the business of any person who was a client or customer of the Company, its subsidiaries, divisions, or affiliates, in each case at any time during the last year of the Term. For purposes of this Agreement, the term “person” includes natural persons, corporations, business trusts, associations, sole proprietorships, unincorporated organizations, partnerships, joint ventures, limited liability companies or partnerships, and governments, or any agencies, instrumentalities, or political subdivisions thereof.
 
d.  
Non-Compete.   The Employee shall not directly, either during the Term or for a period of one (1) year thereafter, engage in any Competitive Business in West Virginia, Pennsylvania, Colorado, Utah, Wyoming, North Dakota, Michigan, Ohio, Kentucky, Texas and Tennessee; provided, however, that the ownership of less than five percent (5%) of the outstanding capital stock of a corporation whose shares are traded on a national securities exchange or on the over-the-counter market shall not be deemed engaging any Competitive Business.  "Competitive Business" shall mean the oil and natural gas industry, including oil and gas leasing, drilling, and other operations, syndication and marketing of partnership or other investments related to oil and natural gas operations, or any other business activities that are the same as or similar to the Company’s business operations as its business exists on the Effective Date or on the Termination Date.
 
e.  
Remedies.   Employee acknowledges and agrees that the Company's remedy at law for a breach or a threatened breach of the provisions herein would be inadequate, and in recognition of this fact, in the event of a
 
8
 
 
breach or threatened breach by Employee of any of the provisions of this Agreement, it is agreed that the Company will be entitled to equitable relief in the form of specific performance, a temporary restraining order, a temporary or permanent injunction or any other equitable remedy which may then be available, without posting bond or other security.  Employee acknowledges that the granting of a temporary injunction, a temporary restraining order or other permanent injunction merely prohibiting Employee from engaging in any business activities would not be an adequate remedy upon breach or threatened breach of this Agreement, and consequently agrees upon any such breach or threatened breach to the granting of injunctive relief prohibiting Employee from engaging in any activities prohibited by this Agreement.  No remedy herein conferred is intended to be exclusive of any other remedy, and each and every such remedy will be cumulative and will be in addition to any other remedy given hereunder now or hereinafter existing at law or in equity or by statute or otherwise.
 
7.  
Termination of the Agreement
 
a.  
Notice of Termination.   Either the Employee or the Board may terminate this Agreement at any time and in his or their sole discretion upon no less than thirty (30) days written Notice of Termination to the other party.  “Notice of Termination” means a written notice which indicates the specified termination provision in this Agreement relied upon (Section 7.c., Section 7.d., Section 7.e., Section 7.f, Section 7.g. or Section 7.h.) and sets forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of Employee's employment under the provision so indicated; provided, however, no such purported termination will be effective without such Notice of Termination; provided further, however, any purported termination by the Company or by Employee must be communicated by a Notice of Termination to the other party hereto in accordance with  Section 9 (“Notices”) of this Agreement.
 
b.  
Termination Date.   The "Termination Date" shall mean the date specified in the Notice of Termination. The Termination Date shall not be less than thirty (30) days from the date such Notice of Termination is given; provided, however, that if within fifteen (15) days after any Notice of Termination is given the party receiving such Notice of Termination notifies the other party that a dispute exists concerning the termination, the Date of Termination shall be the date finally determined by either mutual written agreement of the parties or by the final judgment, order or decree of a court of competent jurisdiction (the time for appeal there from having expired and no appeal having been taken).
 
 
9
 
c.  
Termination by the Company for Just Cause.
 
(i)  
The Company may terminate the Employee for “Just Cause” (as defined in Section 7.c.ii), provided that the Company shall:
 
(A)  
Give the Employee Notice of Termination as specified in Section 7.a., and
 
(B)  
Pay the Employee, within thirty (30) days after his Termination Date, his Base Salary through the Termination Date at the rate in effect at the time the Notice of Termination is given plus any Bonus(only for periods completed and accrued, but not paid), incentive, deferred, or other compensation, and provide any other benefits, which have been earned or become payable as of the Termination Date, pursuant to the terms of this or any other agreement, or compensation or benefit plan, but which have not yet been paid or provided.
 
(ii)  
For purposes of this Agreement “Just Cause” means a good faith determination of the Board that the Employee:
 
(A)  
Failed to substantially perform his duties with the Company (other than a failure resulting from his incapacity due to physical or mental illness) after a written demand for substantial performance has been delivered to him by the Board, which demand specifically identifies the manner in which the Board believes he has not substantially performed his duties;
 
(B)  
Has engaged in conduct the consequences of which are materially adverse to the Company, monetarily or otherwise; or
 
(C)  
Has pleaded guilty to or been convicted of a felony; or
 
(D)  
Has materially breached the terms of this Agreement.
 
No act, or failure to act, on the Employee's part shall be grounds for termination with Just Cause unless he has acted or failed to act with an absence of good faith or without a reasonable belief that his action or failure to act was in or at least not opposed to the best interests of the Company.  The Employee will not be deemed to have been terminated with Just Cause under (ii)(B), (C) or (D), unless there will have been delivered to the Employee a letter setting forth the reasons for the Company’s termination of the Employee for Just Cause and the Employee has failed to cure such
 
10
 
reason for termination within thirty (30) days of the receipt of such notice.
 
d.  
Termination by the Company Without Just Cause.   If the Company terminates this Agreement prior to its expiration (including extensions as provided in Section 1.b.) for any reason other than for Just Cause or the death or Disability (as defined in Section 7.e.) of the Employee, the Company shall:
 
(i)  
Within thirty (30) days of the Termination Date, pay to the Employee a lump sum severance payment equal to three times the sum of: a) the Employee's highest Base Salary during the previous two years of employment immediately preceding the Termination Date, plus b) the highest Bonus paid or payable to the Employee for a year within the same two year period of employment immediately preceding the Termination Date,
 
(ii)  
Pay to the Employee any unpaid expense reimbursement upon presentation by the Employee of an accounting of such expenses in accordance with normal Company practices, but no later than March 15 of the year following the year of termination,
 
(iii)  
Immediately vest any unvested Company stock options and restricted stock (excluding all LTIP shares, including the 2007 and 2008 LTIP shares),
 
(iv)  
Pay any deferred income or Retirement Compensation (under Section 4.c.) or other benefit payments due under this or any other agreements or plans, provided such payments will be made under the schedule originally contemplated in the agreement under which they were granted,
 
(v)  
Make any other payments or provide any benefits earned under this or any other employment agreement or plan, including the Company’s Long-Term Incentive Plan, and
 
(vi)  
Continue coverage of the Employee and any dependents covered at the time of termination under the Company’s group health plans at the Company’s cost for a period equal to the lesser of (i) 18 months or (ii) such period as the Employee is eligible to participate in another employer’s health plan.
 
e.  
Termination in the Event of Death or Disability.   This Agreement will be terminated by the Company in the event of the death of the Employee and may be terminated by the Company in the event of the Disability (as hereinafter defined) of the Employee upon proper notification to the Employee (or his estate in the event of his death), provided the Company shall pay to the Employee (or to the estate of the Employee in the event of
 
 
11
 
 
termination due to the death of the Employee) the compensation and other benefits described in Section 4.a. of this Agreement which would have been earned for (6) months after the Termination Date and any amounts earned under Section 4.b. of this Agreement prorated for the period up to the Termination Date.  “Disability” means being eligible to receive a disability benefit under the Federal Social Security Act.  All amounts payable under this Section 7.e. will be paid in a lump sum as soon as practicable, but no later than two and one-half (2-1/2) months following the close of the calendar year in which the death or Disability occurred.
 
f.  
Termination by the Employee for Good Reason .
 
(i)  
If the Employee terminates this Agreement for Good Reason (as defined in Section 7.f.ii.), provided that such Employee’s termination of employment occurs within two years of the Good Reason, the Company shall:
 
(A)  
Within thirty (30) days of the Termination Date, pay to the Employee a lump sum severance payment equal to three times the sum of: a) the Employee's highest Base Salary during the previous two years of employment immediately preceding the Termination Date, plus b) the highest Bonus paid or payable to the Employee for a year within the same two year period of employment immediately preceding the Termination Date,
 
(B)  
Pay to the Employee any unpaid expense reimbursement upon presentation by the Employee of an accounting of such expenses in accordance with normal Company practices, but no later than March 15 of the year following the year of termination,
 
(C)  
Immediately vest any unvested Company stock options and restricted stock (excluding all LTIP shares, including the 2007 and 2008 LTIP shares),
 
(D)  
Pay any deferred income or Retirement Compensation (under Section 4.c.) or other benefit payments due under this or any other agreements or plans, provided such payments will be made under the schedule originally contemplated in the agreement under which they were granted,
 
(E)  
Make any other payments or provide any benefits earned under this or any other employment agreement or plan, including the Company’s Long-Term Incentive Plan, and
 
12
 
(F)  
Continue coverage of the Employee and any dependents covered at the time of termination under the Company’s group health plans at the Company’s cost for a period equal to the lesser of (i) 18 months or (ii) such period as the Employee is eligible to participate in another employer’s health plan.
 
(ii)  
“Good Reason” means the occurrence of any of the following events without Employee's prior express written consent:
 
(A)  
A material diminution in the Employee’s Base Salary;
 
(B)  
A material diminution in the Employee’s authority, duties, or responsibilities;
 
(C)  
A material diminution in the authority, duties, or responsibilities of the supervisor to whom the Employee is required to report, including a requirement that the Employee report to a corporate officer or employee instead of reporting directly to the board of directors of a corporation (or similar governing body with respect to an entity other than a corporation);
 
(D)  
A material diminution in the budget over which the Employee retains authority;
 
(E)  
A material diminution in reward opportunities under the annual Performance Bonus of Section 4.b. of this Agreement;
 
(F)  
A material change in the geographic location at which the Employee must perform the services; or
 
(G)  
Any other action or inaction that constitutes a material breach by the Company of this Agreement.
 
Employee must provide notice to the Company of the condition described in paragraphs (A)-(G) of this section within ninety (90) days, upon the notice of which the Company will have a period of thirty (30) days during which it may remedy the condition and not be required to pay the amount
 
g.  
Termination by the Employee for other than Good Reason.
 
The Employee may terminate this Agreement for other than Good Reason upon proper notification as provided in Section 7.a.  In such event the Company shall pay to the Employee:
 
13
 
 
(i)  
Within thirty (30) days after his Termination Date, in a lump sum, the compensation provided in Section 4 at the rate in effect at the time of the Notice of Termination.  The Base Salary, Bonus and incremental Retirement Payments will be prorated for the portion of the year that the Employee is employed by the Company; provided, however, that if the Employee’s termination occurs prior to March 31 of the year the Employee will not be entitled to a prorated Bonus for the year;
 
(ii)  
Any incentive, deferred or other compensation which has been earned or has become payable pursuant to the terms of this or any other agreement or compensation or benefit plan as of the Termination Date, but which has not yet been paid, provided such payments will be made under the schedule originally contemplated in the agreement under which they were granted;
 
(iii)  
Any unpaid expense reimbursement upon presentation by the Employee of an accounting of such expenses in accordance with normal Company practices but not later than March 15 of the year following the year of termination; and
 
(iv)  
Any other payments for benefits earned under this or any other employment agreement or plan.
 
h.  
Termination by the Employee following Change of Control .
 
(i)  
If the Employee terminates this Agreement within two years following a Change of Control of the Company (as defined in Section 1.c.), the Company shall:
 
(A)  
Within thirty (30) days of the Termination Date, pay to the Employee a lump sum severance payment equal to three times the sum of: a) the Employee's highest Base Salary during the previous two years of employment immediately preceding the Termination Date, plus b) the highest Bonus paid or payable to the Employee for a year within the same two year period of employment immediately preceding the Termination Date,
 
(B)  
Pay to the Employee any unpaid reimbursement upon presentation by the Employee of an accounting of such expenses in accordance with normal Company practices, but not later than March 15 of the year following the year of termination,
 
(C)  
Immediately vest any unvested Company stock options and restricted stock (excluding LTIP shares),
 
 
14
 
(D)  
Pay any deferred income or Retirement Compensation (under Section 4.c.) or retirement payment or other benefit payments due under this or any other agreements or plans, provided such payments will be made under the schedule originally contemplated in the agreement under which they were granted,
 
(E)  
Make any other payments or provide any benefits earned under this or any other employment agreement or plan, including the Company’s Long-Term Incentive Plan, and
 
(F)  
Continue coverage of the Employee under the Company’s group health plans at the Company’s cost for a period equal to the lesser of (i) 18 months or (ii) such period as the Employee is receiving COBRA health continuation coverage from the Company.
 
i.  
Code Section 409A Compliance .
 
Except with respect to amounts paid pursuant to a schedule in a plan or arrangement outside of this Employment Agreement, it is intended that amounts payable under this Section 7 not be considered non-qualified deferred compensation subject to Internal Revenue Code Section 409A.  Employee is a Specified Employee under Internal Revenue Code Section 409A, therefore, to the extent such amounts are considered non-qualified deferred compensation payable upon a separation from service under Internal Revenue Code Section 409A, payment of those amounts so deferred under Internal Revenue Code Section 409A may not be made until at least six (6) months following the Employee’s separation from service of the Company (or, if earlier, the date of death of Employee).
 
8.  
Life Insurance.   The Company may, at any time after the execution of this Agreement, maintain any outstanding life insurance policies and apply for and procure as owner and for its own benefit new life insurance on Employee, in such amounts and in such form or forms as the Company may determine.  Employee shall, at the request of the Company, submit to such medical examinations, supply such information, and execute such documents as may be required by the insurance company or companies to whom the Company has applied for such insurance.  Employee hereby represents that to his knowledge he is in excellent physical and mental condition.
 
9.  
Notices.   For the purposes of this Agreement, notices and all other communications provided for in the Agreement shall be in writing and will be deemed to have been duly given when personally delivered, by facsimile transmission or sent by certified mail, return receipt requested, postage prepaid, or by expedited  (overnight) courier with established national reputation, shipping prepaid or billed to sender, in either case addressed to the respective addresses last
 
 
15
 
 
given by each party to the other  (provided that all notices to the Company must be directed to the attention of the Secretary of the Company ) or to such other address as either party may have furnished  to the other in writing  in  accordance  herewith.  All notices and communication will be deemed to have been received on the date of delivery thereof, or on the second day after deposit thereof with an expedited courier service, except that notice of change of address will be effective only upon receipt.
 
 
Company at:
 
Petroleum Development Corporation
     
120 Genesis Boulevard
     
P.O. Box 26
     
Bridgeport WV 26330
       
 
Employee at:
 
Eric R. Stearns
     
753 Brightridge Drive
     
Bridgeport WV 26330

10.  
Successors.   This Agreement will be binding on the Company and any successor to any of its businesses or assets.  Without limiting the effect of the prior sentence, the Company shall use its best efforts to require any successor or assign (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company to expressly assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession or assignment had taken place. As used in this Agreement, “Company” means the Company as hereinbefore defined and any successor or assign to its business and/or assets as aforesaid which assumes and agrees to perform this Agreement or which is otherwise obligated under this Agreement by the first sentence of this Section, entitled Successors, by operation of law or otherwise.
 
11.  
Binding Effect.   This Agreement will inure to the benefit of and be enforceable by Employee's personal and legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees.  If Employee should die while any amounts would still be payable to him hereunder if he had continued to live, all such amounts, unless otherwise provided herein, will be paid in accordance with the terms of this Agreement to Employee's estate.
 
12.  
Integration, Modification and Waiver.   This Agreement constitutes the sole employment agreement between the parties, and any prior employment agreement, written or oral, is terminated.  No provision of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing and signed by Employee and such officer of the Company as may be specifically designated by the Board.  No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with, any condition or provision of this Agreement to be performed by such other party will
 
 
16
 
 
be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time.
 
13.  
Headings.   Headings used in this Agreement are for convenience only and may not be used to interpret or construe its provisions.
 
14.  
Waiver of Breach.   The waiver of either the Company or Employee of a breach of any provision of this Agreement will not operate or be construed as a waiver of any subsequent breach by either the Company or Employee.
 
15.  
Amendments.   No amendments or variations of the terms and conditions of this Agreement will be valid unless the same is in writing and signed by all of the parties hereto.
 
16.  
Survival of Obligations.   The provisions of Section 6 of this Agreement will continue to be binding upon the Employee and Company in accordance with their terms, notwithstanding the termination of the Employee’s employment with the Company for any reason or the expiration of this Agreement.
 
17.  
Severability.   The invalidity or unenforceability of any provision of this Agreement, whether in whole or in part, shall not in any way affect the validity and/or enforceability of any other provision contained herein.  Any invalid or unenforceable provision shall be deemed severable to the extent of any such invalidity or unenforceability.  It is expressly understood and agreed that while the Company and Employee consider the restrictions contained in this Agreement reasonable for the purpose of preserving for the Company the good will, other proprietary rights and intangible business value of the Company, if a final judicial determination is made by a court having jurisdiction that the time or territory or any other restriction contained in this Agreement is an unreasonable or otherwise unenforceable restriction against Employee, the provisions of such clause will not be rendered void but will be deemed amended to apply as to maximum time and territory and to such other extent as such court may judicially determine or indicate to be reasonable.
 
18.  
Governing Law.   This Agreement will be construed and enforced pursuant to the laws of the State of West Virginia.
 
19.  
Arbitration.   Any controversy or claim arising out of or relating to this Agreement or any transactions provided for herein, or the breach thereof, other than a claim for injunctive relief, will be settled by arbitration in accordance with the commercial Arbitration Rules of the American Arbitration Association (the “Rules”) in effect at the time demand for arbitration is made by any party.  The evidentiary and procedural rules in such proceedings will be kept to the minimum level of formality that is consistent with the Rules.  The Company shall name one arbitrator, Employee shall name a second and the two arbitrators so chosen shall name a neutral, third arbitrator, who will serve as the sole arbitrator of the controversy or claim.  The third arbitrator will be experienced in the matters in
 
 
17
 
 
dispute.  If the third and sole arbitrator is not agreed upon, the American Arbitration Association will name him or her.  Arbitration will occur in Bridgeport, West Virginia, or such other location agreed to by the Company and Employee.  The award made by the third arbitrator will be final and binding, and judgment may be entered in any court of law having competent jurisdiction. The award is subject to confirmation, modification, correction, or vacation only as explicitly provided in Title 9 of the United States Code.  The prevailing party will be entitled to an award of pre- and post-award interest as well as reasonable attorneys' fees incurred in connection with the arbitration and any judicial proceedings related thereto.
 
20.  
Executive Officer Status.   Employee acknowledges that he may be deemed to be an “executive officer” of the Company for purposes of the Securities Act of 1933, as amended (the “1933 Act”), and the Securities Exchange Act of 1934, as amended (the “1934 Act”) and, if so, he shall comply in all respects with all the rules and regulations under the 1933 Act and the 1934 Act applicable to him in a timely and non-delinquent manner. In order to assist the Company in complying with its obligations under the 1933 Act and 1934 Act, Employee shall provide to the Company such information about Employee as the Company shall reasonably request including, but not limited to, information relating to personal history and stockholdings.  Employee shall immediately report to the General Counsel of the Company or other designated officer of the Company all changes in beneficial ownership of any shares of the Company Common Stock deemed to be beneficially owned by Employee and/or any members of Employee's immediate family.
 
21.  
Pronouns.   All pronouns and any variations thereof will be deemed to refer to the masculine, feminine, neuter, singular, or plural, as the identity of the person or entity may require. As used in this Agreement: (1) words of the masculine gender shall mean and include corresponding neuter words or words of the feminine gender, (2) words in the singular shall mean and include the plural and vice versa, and (3) the word “may” gives sole discretion without any obligation to take any action.
 
22.  
Counterparts.    This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original, but all of which together will constitute but one document.
 
23.  
Exhibits.   Any Exhibits attached hereto are incorporated herein by reference and are an integral part of this Agreement.
 
 
18
 

 
IN WITNESS WHEREOF, the Company and the Employee have duly executed this Employment Agreement as of the date first above written.
 
           
 
Company
     
Executive
   
  Petroleum Development Corporation
     
           
           
 
By:
/s/ Kimberly Wakim 
   
/s/ Eric R. Stearns
   
Kimberly Wakim
   
Eric R. Stearns
 
Position:
Chair of the
     
   
Compensation Committee
     

 
19
Exhibit 10.11
 
Employment Agreement
 
This Employment Agreement (the “Agreement”) is made and entered into this 31st day of December, 2008 by and between Petroleum Development Corporation, a Nevada Corporation (the “Company”), and Gysle R. Shellum ( “Shellum”).
 
WHEREAS, the Company wishes to employ Shellum as Chief Financial Officer and to perform the duties and services incident to such position for the Company, and Shellum wishes to be so employed by the Company, all upon the terms and conditions set forth in this Agreement;
 
NOW THEREFORE, in consideration of the premises and mutual covenants and obligations set forth herein and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged and accepted, the parties hereto, intending to be legally bound, agree as follows:
 
1.  
Effective Date and Term
 
a.  
Initial Term.   The effective date of this Agreement shall be November 11, 2008 (the “Effective Date”), and the initial term shall be for the period beginning on the Effective Date and ending December 31, 2010.
 
b.  
Automatic Extensions.   The Term of this Agreement shall be extended for an additional 12 months beginning on December 31, 2009 and on each successive December 31 unless either party provides the other with at least thirty (30) days prior written notice, or unless the contract has been terminated by the parties in accordance with the provisions of Section 7 of this Agreement.  The period of time from the Effective Date until the Termination Date, as defined in Section 7.b., shall be the “Term.”
 
2.  
Place of Employment
 
The place of employment shall be the Company’s offices in Denver, Colorado, unless Shellum and the Company mutually agree to an alternative location.  Shellum acknowledges that there may be substantial business travel associated with Shellum’s position.
 
3.  
Position and Responsibilities
 
a.  
Position.   Shellum shall serve as Chief Financial Officer of the Company and shall initially report to the Chief Executive Officer of the Company (the “Chief Executive Officer”) and be under the general direction and control of the Chief Executive Officer.
 
b.  
Responsibilities.   Shellum shall have obligations, duties, authority and power to do such acts as are customarily done by a person holding the same or an equivalent position in corporations of similar size to the Company.  Shellum shall perform such managerial duties and
 
 
1
 
   
responsibilities for the Company as may be reasonably be assigned to him  and, at no additional compensation,  if requested, shall serve on the Board of Directors of the Company (the "Board") and in other such positions with any subsidiary corporation of the Company, or any partnership, limited liability company or other entity in which the Company has an interest (herein collectively called “Affiliates”), as  may from time to time be requested.
 
c.  
Dedication of Professional Services.   Shellum shall devote substantially all of Shellum’s business time, best efforts and attention to promote and advance the business of the Company and its Affiliates to perform diligently and faithfully all the duties, responsibilities and obligations of Shellum’s position with the Company.  Shellum shall not be employed in any other business activity, other than with the Company and its Affiliates, during the Term, whether or not such activity is pursued for gain, profit or other pecuniary advantage without approval by the Compensation Committee of the Board (the “Compensation Committee”); provided, however, that this restriction shall not be construed as preventing Shellum from investing Shellum’s personal assets in a business which does not compete with the Company or its Affiliates, where the form or manner of such investment will not require services of any significance on the part of Shellum in the operation of the affairs of the business in which such investment is made and in which Shellum’s participation is solely that of a passive investor.
 
d.  
Adherence to Standards.   Shellum shall comply with the written policies, standards, rules and regulations of the Company from time to time established for all employees or executive officers of the Company consistent with Shellum's position and level of authority.
 
e.  
Minimum Stock Ownership.   Shellum shall comply with the Company’s minimum stock ownership requirements for officers (other than the Chief Executive Officer); such requirements being that by the fifth anniversary of the date of hire and until Shellum’s Termination Date, Shellum shall maintain a minimum stock ownership equal to two times Shellum’s Base Salary, as defined in Section 4.a.
 
4.  
Compensation
 
a.  
Base Salary.   The Company shall pay Shellum an annual base salary of $235,000 (the “Base Salary”) commencing on the Effective Date and ending on the Termination Date.  The Base Salary shall be payable in accordance with the ordinary payroll practices of the Company.  The Base Salary shall be reviewed annually by the Compensation Committee and may be changed by the Compensation Committee in its sole discretion, taking into account the base salaries, aggregate annual cash compensation, and other compensation of individuals holding similar positions at other
 
2
 
 
comparable companies, the performance of Shellum and the Company, and other relevant factors.
 
b.  
Performance Bonus.   Shellum shall be eligible to earn an annual performance bonus (the “Bonus”) during the Term based on criteria established by the Compensation Committee in its sole discretion each year, to be paid by March 15 of the following year. For 2009, the target bonus will be 50% of Shellum’s base salary, and the exceptional performance bonus will be 100% of such base salary.
 
c.  
Equity Compensation Grant.   As a long term incentive, on the Effective Date under the Company’s Long-Term Equity Compensation Plan, Shellum shall participate in any equity compensation program provided to all executive officers, based on criteria established by the Compensation Committee in its sole discretion each year.  Initially, Shellum will be granted a restricted stock award equal to 100% of Base Salary, to vest pro rata over 4 years; the valuation date for such award will be based on the closing price of the Company’s stock on November 28, 2008.
 
d.  
Other Compensation.   Shellum shall continue to be eligible to participate in all other cash or stock compensation plans or programs maintained by the Company, as in effect from time to time, in which other senior executives of the Company are allowed to participate.
 
e.  
Recoupment of Certain Compensation.   If the Company has to restate all or a portion of its financial statements due to the material noncompliance of the Company with any financial reporting requirement under the securities laws, the Employee shall, for the affected years, reimburse the Company for any excess bonus paid to the Employee pursuant to Section 4.b.  The reimbursements shall be equal to the difference between the bonus paid to him for the affected years and the bonus that would have been paid to the Employee had the financial results been properly reported.  Such reimbursement shall be paid to the Company within ninety days after the Company notifies the Employee of the amount owed to the Company.
 
5.  
Employee Benefits
 
a.  
Participation in Company Benefit Plans.   During the Term, the Company shall provide Shellum with coverage under all employee pension and welfare benefit programs, plans and practices commensurate with Shellum’s positions in the Company and to the extent permitted under the respective employee benefit plan.
 
b.  
Vacation.   Shellum will be entitled to four (4) weeks of paid vacation in each calendar year, to be taken at such times as is reasonably determined by Shellum to be consistent with Shellum’s responsibilities under this
 
3
 
 
Agreement and the Company’s vacation policy applicable to all employees.
 
c.  
Automobile.   During the Term, Shellum shall be entitled to an annual automobile allowance as approved by the Compensation Committee and updated from time to time at its discretion.
 
d.  
Relocation Expense.   Shellum shall  be entitled to relocation expense for his move to the Denver Colorado area, subject to the terms and conditions of the Company’s relocation policy.  In addition Shellum will be granted a $30,000 stipend to cover the anticipated commute schedule prior to such relocation.
 
6.  
Restrictive Covenants.
 
a.  
Confidential Information.   Shellum hereby acknowledges that in connection with Shellum’s employment by the Company, Shellum will be exposed to and may obtain certain Confidential Information (as defined below) (including, without limitation, procedures, memoranda, notes, records and customer and supplier lists whether such information has been or is made, developed or compiled by Shellum or otherwise has been or is made available to him) regarding the business and operations of the Company and its subsidiaries or affiliates.  Shellum further acknowledges that such Confidential Information is unique, valuable, considered trade secrets and deemed proprietary by the Company.  For purposes of the Agreement, “Confidential Information” includes, without limitation, any information heretofore or hereafter acquired, developed or used by any of the Company or their direct or indirect subsidiaries relating to Business Opportunities or Intellectual Property or other geological, geophysical, economic, financial or management aspects of the business, operations, properties or prospects of the Company or their direct or indirect subsidiaries, whether oral or in written form (including electronic).  Shellum agrees that all Confidential Information is and will remain the property of the Company or their direct or indirect subsidiaries, as the case may be.  Shellum further agrees, except for disclosures occurring in the good faith performance of Shellum’s duties for the Company or their direct or indirect subsidiaries, during the Term and for a period of three (3) years after the Termination Date, to hold in the strictest confidence all Confidential Information, and not to, directly or indirectly, duplicate, sell, use, lease, commercialize, disclose or otherwise divulge to any person or entity any portion of the Confidential Information or use any Confidential Information, directly or indirectly, for Shellum’s own benefit or profit or allow any person, entity or third party, other than the Company or their direct or indirect subsidiaries and authorized executives of the same, to use or otherwise gain access to any Confidential Information.  Shellum will have no obligation under this Agreement with respect to any information that becomes generally available to the public other than as a result of a
 
 
4
 
 
disclosure by Shellum or Shellum’s agent or other representative or becomes available to Shellum on a non-confidential basis from a source other than the Company or their direct or indirect subsidiaries.  Further, Shellum will have no obligation under this Agreement to keep confidential any of the Confidential Information to the extent that a disclosure of it is required by law or is consented to by the Company; provided, however, that if and when such a disclosure is required by law, Shellum promptly will provide the Company with notice of such requirement, so that the Company may seek an appropriate protective order.
 
 
b.  
Return of Property.   Shellum agrees to deliver promptly to the Company, upon termination of Shellum’s employment hereunder, or at any other time when the Company so requests, all documents and property relating to the business of the Company or their direct or indirect subsidiaries, including without limitation: all geological and geophysical reports and related data such as maps, charts, logs, seismographs, seismic records and other reports and related data, calculations, summaries, memoranda and opinions relating to the foregoing, production records, electric logs, core data, pressure data, lease files, well files and records, land files, abstracts, title opinions, title or curative matters, contract files, notes, records, drawings, manuals, correspondence, financial and accounting information, customer lists, statistical data and compilations, patents, copyrights, trademarks, trade names, inventions, formulae, methods, processes, agreements, contracts, manuals, electronic data,  or any documents,  whether written or digital and whether prepared or compiled by Shellum or furnished to Shellum during the Term, relating to the business of the Company or their direct or indirect subsidiaries and all copies thereof and therefrom; provided, however, that Shellum will be permitted to retain copies of any documents or materials of a personal nature or otherwise related to Shellum’s rights under this Agreement. The aforementioned materials include materials on Shellum’s personal computers, which materials shall be destroyed in a manner satisfactory to the Company.
 
c.  
Non-Compete Obligations.
 
(i)  
Non-Compete Obligations During Employment Term.  Shellum agrees that during the Term:
 
(A)  
Shellum will not, other than through the Company, engage or participate in any manner, whether directly or indirectly through any family member or as an employee, employer, consultant, agent, principal, partner, more than one percent shareholder, officer, director, licensor, lender, lessor or in any other individual or representative capacity, in any business or activity which is engaged in leasing, acquiring, exploring, producing, gathering or marketing hydrocarbons and related products; provided that the foregoing shall not
 
 
5
 
 
be deemed to restrain the participation by Shellum’s spouse in any capacity set forth above in any business or activity engaged in any such activity and provided further that the Company may, in good faith, take such reasonable action with respect to Shellum’s performance of Shellum’s duties, responsibilities and authorities as set forth in this Agreement as it deems necessary and appropriate to protect its legitimate business interests with respect to any actual or apparent conflict of interest reasonably arising from or out of the participation by Shellum’s spouse in any such competitive business or activity; and
 
 
(B)  
all investments made by Shellum (whether in Shellum’s own name or in the name of any family members or other nominees or made by Shellum’s controlled affiliates), which relate to the leasing, acquisition, exploration, production, gathering or marketing of hydrocarbons and related products will be made solely through the Company; and Shellum will not (directly or indirectly through any family members or other persons), and will not permit any of Shellum’s controlled affiliates to: (1) invest or otherwise participate alongside the Company or its direct or indirect subsidiaries in any Business Opportunities, or (2) invest or otherwise participate in any business or activity relating to a Business Opportunity, regardless of whether any of the Company or its direct or indirect subsidiaries ultimately participates in such business or activity, in either case, except through the Company.  Notwithstanding the foregoing, nothing in this Section 6 shall be deemed to prohibit Shellum or any family member from owning, or otherwise having an interest in, less than one percent (1%) of any publicly-owned entity or three percent (3%) or less of any private equity fund or similar investment fund that invests in any business or activity engaged in any of the activities set forth above, provided that Shellum has no active role with respect to any investment by such fund in any entity.
 
(ii)  
Non-Compete Obligations After Termination Date .  Shellum agrees that Shellum will not engage or participate in any manner, whether directly or indirectly through any family member or other person or as an employee, employer, consultant, agent principal, partner, more than one percent shareholder, officer, director, licensor, lender, lessor or in any other individual or representative capacity:
 
 
6
 
(A)  
during the one-year period following the Termination Date, in any business or activity which is engaged in leasing, acquiring, exploring, producing, gathering or marketing hydrocarbons and related products within (1) any county or parish in which the Company owns any oil and gas interests or conducts operations on the Termination Date or in which the Company has owned any oil and gas interests or conducted operations at any time during the six months immediately preceding the Termination Date or (2)  any county or parish adjacent to any county or parish described in clause (1); and
 
(B)  
during the two-year period following the Termination Date, in any business or activity which is in direct competition with the business of the Company or its direct or indirect subsidiaries in the leasing, acquiring, exploring, producing, gathering or marketing of hydrocarbons and related products within the boundaries of, or within a two-mile radius of the boundaries of, any mineral property interest of any of the Company or its direct or indirect subsidiaries (including, without limitation, a mineral lease, overriding royalty interest, production payment, net profits interest, mineral fee interest or option or right to acquire any of the foregoing, or an area of mutual interest as designated pursuant to contractual agreements between the Company and any third party) or any other property on which any of the Company or its direct or indirect subsidiaries has an option, right, license or authority to conduct or direct exploratory activities, such as three-dimensional seismic acquisition or other seismic, geophysical and geochemical activities (but not including any preliminary geological mapping), as of the Termination Date or as of the end of the six-month period following such Termination Date; provided that, this subsection (ii) will not preclude Shellum from making investments in securities of oil and gas companies which are registered on a national stock exchange, if the aggregate amount owned by Shellum and all family members and affiliates does not exceed 5% of such company’s outstanding securities.
 
(iii)  
Notwithstanding the foregoing, nothing in this Section 6.c. shall be deemed to restrain the participation by Shellum’s spouse in any capacity set forth above in any business or activity described above.
 
d.  
Non-Solicitation.   During the Term and for a period of twenty-four (24) months after the Termination Date, Shellum will not, whether for
 
7
 
 
Shellum’s own account or for the account of any other person (other than the Company or its direct or indirect subsidiaries), intentionally solicit, endeavor to entice away from the Company or its direct or indirect subsidiaries, or otherwise interfere with the relationship of the Company or its direct or indirect subsidiaries with, (i) any person who is employed by the Company or its direct or indirect subsidiaries (including any independent sales representatives or organizations), or (ii) any client or customer of the Company or its direct or indirect subsidiaries.
 
e.  
Assignment of Developments.   Shellum assigns and agrees to assign without further compensation to the Company and its successors, assigns or designees, all of Shellum’s right, title and interest in and to all Business Opportunities and Intellectual Property (as those terms are defined below), and further acknowledges and agrees that all Business Opportunities and Intellectual Property constitute the exclusive property of the Company.
 
For purposes of this Agreement, “Business Opportunities” means all business ideas, prospects, proposals or other opportunities pertaining to the lease, acquisition, exploration, production, gathering or marketing of hydrocarbons and related products and the exploration potential of geographical areas on which hydrocarbon exploration prospects are located, which are developed by Shellum during the Term, or originated by any third party and brought to the attention of Shellum during the Term, together with information relating thereto (including, without limitation, geological and seismic data and interpretations thereof, whether in the form of maps, charts, logs, seismographs, calculations, summaries, memoranda, opinions or other written or charted means).
 
For purposes of this Agreement, “Intellectual Property” shall mean all ideas, inventions, discoveries, processes, designs, methods, substances, articles, computer programs and improvements (including, without limitation, enhancements to, or further interpretation or processing of, information that was in the possession of Shellum prior to the date of this Agreement), whether or not patentable or copyrightable, which do not fall within the definition of Business Opportunities, which Shellum discovers, conceives, invents, creates or develops, alone or with others, during the Term, if such discovery, conception, invention, creation or development (i) occurs in the course of Shellum’s employment with the Company, or (ii) occurs with the use of any of the time, materials or facilities of the Company or its direct or indirect subsidiaries, or (iii) in the good faith judgment of the Board, relates or pertains in any material way to the purposes, activities or affairs of the Company or its direct or indirect subsidiaries.
 
f.  
Injunctive Relief.   Shellum acknowledges that a breach of any of the covenants contained in this Section 6 may result in material, irreparable injury to the Company for which there is no adequate remedy at law, that
 
 
8
 
 
it will not be possible to measure damages for such injuries precisely and that, in the event of such a breach or threat of breach, the Company will be entitled to obtain a temporary restraining order and/or a preliminary or permanent injunction restraining Shellum from engaging in activities prohibited by this Section 6 or such other relief as may be required to specifically enforce any of the covenants in this Section 6.  To the extent that the Company seeks a temporary restraining order (but not a preliminary or permanent injunction), Shellum agrees that a temporary restraining order may be obtained ex parte.
 
g.  
Adjustment of Covenants.   The parties consider the covenants and restrictions contained in this Section 6 to be reasonable.  However, if and when any such covenant or restriction is found to be void or unenforceable and would have been valid had some part of it been deleted or had its scope of application been modified, such covenant or restriction will be deemed to have been applied with such modification as would be necessary and consistent with the intent of the parties to have made it valid, enforceable and effective.
 
h.  
Forfeiture Provision .
 
(i)  
Detrimental Activities .  If Shellum engages in any activity that violates any covenant or restriction contained in this Section 6, in addition to any other remedy the Company may have at law or in equity, (A) Shellum will be entitled to no further payments or benefits from the Company under this Agreement or otherwise, except for any payments or benefits required to be made or provided under applicable law, (B) all unexercised stock options, restricted stock and other forms of equity compensation held by or credited to Shellum will terminate effective as of the date on which Shellum engages in that activity, unless terminated sooner by operation of another term or condition of this Agreement or other applicable plans and agreements, and (C) any exercise, payment or delivery pursuant to any equity compensation award that occurred within one year prior to the date on which Shellum engages in that activity may be rescinded within one year after the first date that a majority of the members of the Board first became aware that Shellum engaged in that activity.  In the event of any such rescission, Shellum will pay to the Company the amount of any gain realized or payment received as a result of the rescinded exercise, payment or delivery, in such manner and on such terms and conditions as may be required.
 
(ii)  
Right of Set-Off .  Shellum consents to a deduction from any amounts the Company owes Shellum from time to time (including amounts owed as wages or other compensation, fringe benefits, or vacation pay, as well as any other amounts owed to Shellum by the
 
 
9
 
 
Company), to the extent of the amounts Shellum owes the Company under Section 6 above.  Whether or not the Company elects to make any set-off in whole or in part, if the Company does not recover by means of set-off the full amount Shellum owes, calculated as set forth above, Shellum agrees to pay immediately the unpaid balance to the Company.  In the discretion of the Board, reasonable interest may be assessed on the amounts owed, calculated from the later of (A) the date Shellum engages in the prohibited activity and (B) the applicable date of exercise, payment or delivery.
 
7.  
Termination of the Agreement
 
a.  
Notice of Termination.   Either Shellum or the Board may terminate this Agreement at any time and in Shellum’s or their sole discretion upon no less than thirty (30) days written Notice of Termination to the other party.  "Notice of Termination" shall mean a written notice which shall indicate the specified termination provision in this Agreement relied upon (Section 7.c., Section 7.d., Section 7.e., Section 7.f., Section 7.g. or Section 7.h.) and shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of Shellum's employment under the provision so indicated; provided, however, no such purported termination shall be effective without such Notice of Termination; provided further, however, any purported termination by the Company or by Shellum shall be communicated by a Notice of Termination to the other party hereto in accordance with  Section 8 (“Notices”) of this Agreement.
 
b.  
Termination Date.   The “Termination Date” shall mean the date specified in the Notice of Termination. The Termination Date shall not be less than thirty (30) days after the date such Notice of Termination is given.
 
c.  
Termination by the Company for Just Cause .
 
(i)  
The Company may terminate Shellum for “Just Cause” (as defined in Section 7.c.ii), provided that the Company shall:
 
(A)  
Give Shellum Notice of Termination as specified in Section 7.a., and
 
(B)  
Pay Shellum, within thirty (30) days after this Termination Date, Shellum’s Base Salary through the Termination Date at the rate in effect at the time the Notice of Termination is given plus a good faith estimate by the Company of any unpaid Bonus (in full for any completed annual period and prorated for months completed in the current annual period), incentive, deferred, retirement or other compensation, and provide any other benefits, which have
 
10
 
 
been earned or become payable as of the Termination Date, pursuant to the terms of this or any other agreement, or compensation or benefit plan, but which have not yet been paid or provided.
 
(ii)  
For purposes of this Agreement “Just Cause” shall be a reasonable determination of the Board that Shellum:
 
(A)  
Failed to substantially perform Shellum’s duties with the Company (other than a failure resulting from Shellum’s incapacity due to physical or mental illness) after a written demand for substantial performance has been delivered to him by the Board, which demand specifically identifies the manner in which the Board believes Shellum has not substantially performed Shellum’s duties, and Shellum has failed to cure such deficiency within thirty (30) days of the receipt of such notice;
 
(B)  
Has engaged in conduct the consequences of which are materially adverse to the Company, monetarily or otherwise;
 
(C)  
Has pleaded guilty to or been convicted of a felony or a crime involving moral turpitude or dishonesty; or
 
(D)  
Has materially breached the terms of this Agreement.
 
(E)  
Following a Change in Control, Subsection (A) above shall be deleted from this definition of “Just Cause”.
 
d.  
Termination by the Company Without Just Cause.   In the event the Company terminates this Agreement prior to its expiration (including extensions as provided in Section 1.b) for any reason other than for Just Cause or the death or Disability (as defined in Section 7.e.) of Shellum, the Company shall:
 
(i)  
Pay to Shellum within thirty (30) days after the Termination Date a lump sum severance payment equal to two times the sum of:
 
(A)  
Shellum’s highest Base Salary during the previous two years of employment immediately preceding the Termination Date, plus
 
(B)  
the highest Bonus paid to Shellum during the same two-year period,
 
(ii)  
Pay to Shellum any unpaid expense reimbursement upon presentation by Shellum of an accounting of such expenses in
 
11
 
 
accordance with normal Company practices, but no later than March 15 of the year following the year of termination,
 
(iii)  
Vest any unvested Company stock options or restricted stock (excluding LTIP shares under the Company’s Long-Term Incentive Plan),
 
(iv)  
Make any other payments or provide any benefits earned under this or any other employment agreement or plan, including the Company’s Long-Term Incentive Plan (including LTIP shares under the Company’s Long-Term Incentive Plan), and
 
(v)  
Continue coverage of Shellum and any dependents covered at the time of termination under the Company’s group health plans at the Company’s cost throughout the period of time that Shellum is eligible for federal COBRA health continuation coverage.
 
e.  
Termination in the Event of Death or Disability.   This Agreement shall terminate in the event of the death of Shellum or may be terminated by the Company in the event of a Disability (as hereinafter defined) of Shellum upon proper notification to Shellum (or Shellum’s estate in the event of Shellum’s death), provided the Company shall pay to Shellum (or to the estate of Shellum in the event of termination due to the death of Shellum) the Base Salary described in Section 4.a. of this Agreement which would have been earned for six (6) months after the Termination Date.  The benefits provided under this Section 7.e. shall be no less favorable to Shellum in terms of amounts, deductibles and costs to him, if any, than such benefits provided by the Company to him and shall not be interpreted so as to limit any benefits to which Shellum, as a terminated employee of the Company, or Shellum’s family may be entitled under the Company’s life insurance, medical, hospitalization or disability plans following Shellum’s Termination Date or under applicable law, and any other benefits or payments earned by Shellum under Shellum’s or any other agreement or plan.  “Disability” means the inability of Shellum to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, as provided in Internal Revenue Code Section 409A(a)(2)(C) and Treas. Reg. § 1.409A-3(i)(4).  All amounts payable under this Section 7.e. shall be paid in a lump-sum as soon as practicable, but in no event later than two-and-one-half (2-1/2) months following the close of the calendar year in which the death or Disability occurred.
 
12
 
f.  
Termination by Shellum for Good Reason .
 
(i)  
In the event Shellum terminate this Agreement for Good Reason (as defined in Section 7.f.ii), provided such Shellum’s termination occurs within ninety days of the Good Reason, the Company shall:
 
(A)  
Pay to Shellum within thirty (30) days after the Termination  Date, a lump sum severance payment equal to two times the sum of:
 
a.  
Shellum’s highest Base Salary during the previous two years of employment immediately preceding the Termination Date, plus
 
b.  
the highest Bonus paid to Shellum during the same two-year period,
 
(B)  
Pay to Shellum any unpaid expense reimbursement upon presentation by Shellum of an accounting of such expenses in accordance with normal Company practices, but no later than March 15 of the year following the year of termination,
 
(C)  
Vest any unvested Company stock options or restricted stock (excluding LTIP shares under the Company’s Long-Term Incentive Plan),
 
(D)  
Make any other payments or provide any benefits earned under this or any other employment agreement or plan, including the Company’s Long-Term Incentive Plan (including LTIP shares under the Company’s Long-Term Incentive Plan), and
 
(E)  
Continue coverage of Shellum and any dependents covered at the time of termination under the Company’s group health plans at the Company’s cost throughout the period of time that Shellum is eligible for federal COBRA health continuation coverage.
 
(ii)  
"Good Reason" shall mean the occurrence of any of the following events without Shellum's prior express written consent:
 
(A)  
A material diminution in Shellum’s Base Salary;
 
(B)  
A  material diminution in reward opportunities under the annual Bonus;
 
13
 
(C)  
Any other action or inaction that constitutes a material breach by the Company of this Agreement.
 
Shellum must provide notice to the Company of the condition described in paragraphs (A)-(C) of this section within ninety (90) days, upon the notice of which the Company will have a period of thirty (30) days during which it may remedy the condition and not be required to pay the amount.
 
g.  
Termination by Shellum for other than Good Reason.   Shellum may terminate this Agreement for other than Good Reason upon proper Notice of Termination as provided in Section 7.a.  In such event the Company shall pay to Shellum:
 
(i)  
Within thirty (30) days after Shellum’s Termination Date, in a lump-sum, the compensation provided in Section 4 at the rate in effect at the time of the Notice of Termination. If Shellum’s termination occurs prior to the end of the year, Shellum shall not be entitled to any Bonus for the year;
 
(ii)  
Any incentive, deferred or other compensation which has been earned or has become payable pursuant to the terms of this or any other agreement or compensation or benefit plan as of the Termination Date, but which has not yet been paid, provided such payments shall be made under the schedule originally contemplated in the agreement under which they were granted, but if no such payment schedule is provided, the payments shall be made no later than March 15 of the year following the year of termination;
 
(iii)  
Any unpaid expense reimbursement upon presentation by Shellum of an accounting of such expenses in accordance with normal Company practices, but not later than March 15 of the year following the year of termination; and
 
(iv)  
Any other payments for benefits earned under this Agreement, which shall in no event be paid later than March 15 of the year following the year of termination.
 
h.  
Termination  following Change of Control .
 
(i)  
If either (1) the Company terminates Shellum’s employment within two years following a Change of Control of the Company (as defined in Section 7.h.ii.) or (2)  Shellum gives notice to the Company of termination of this Agreement during the thirty (30) day period beginning one hundred twenty  (120) days immediately following a Change in Control, then the Company shall:
 
14
 
(A)  
Pay to Shellum within thirty (30) days after the Termination Date, a lump sum severance payment equal to three  times the sum of:
 
a.  
Shellum’s highest Base Salary during the  previous two years of employment immediately preceding the Termination Date, plus
 
b.  
the highest Bonus paid to Shellum during the  same two-year period.
 
(B)  
Pay to Shellum any unpaid expense reimbursement upon presentation by Shellum of an accounting of such expenses in accordance with normal Company practices, but no later than March 15 of the year following the year of termination,
 
(C)  
Vest any unvested Company stock options or restricted stock (excluding LTIP shares under the Company’s Long-Term Incentive Plan),
 
(D)  
Make any other payments or provide any benefits earned under this or any other employment agreement or plan, including the Company’s Long-Term Incentive Plan (including LTIP shares under the Company’s Long-Term Incentive Plan), and
 
(E)  
Continue coverage of Shellum and any dependents covered at the time of termination under the Company’s group health plans at the Company’s cost throughout the period of time that Shellum is eligible for federal COBRA health continuation coverage.
 
(ii)  
"Change of Control" of the Company shall occur on the earliest of the following events:
 
(A)  
Change in Ownership : A change in ownership of the Company occurs on the date that any one person, or more than one person acting as a group, acquires ownership of stock of the Company that, together with stock held by such person or group, constitutes more than 50% of the total fair market value or total voting power of the stock of the Company, excluding the acquisition of additional stock by a person or more than one person acting as a group who is considered to own more than 50% of the total fair market value or total voting power of the stock of the Company.
 
15
 
(B)  
Change in Effective Control : A change in effective control of the Company occurs on the date that either:
 
a.  
Any one person, or more than one person acting as a group, acquires (or has acquired during the l2-month period ending on the date of the most recent acquisition by such person or persons) ownership of stock of the Company possessing 35% or more of the total voting power of the stock of the Company; or
 
b.  
A majority of the members of the Board of Directors of the Company (the “Board”) is replaced during any l2-month period by directors whose appointment or election is not endorsed by a majority of the members of the board of directors prior to the date of the appointment or election; provided, that this paragraph (b) shall apply only to the Company if no other corporation is a majority shareholder.
 
(C)  
Change in Ownership of Substantial Assets : A change in the ownership of a substantial portion of the Company's assets occurs on the date that any one person, or more than one person acting as a group, acquires (or has acquired during the l2-month period ending on the date of the most recent acquisition by such person or persons) assets from the Company that have a total gross fair market value equal to or more than 40% of the total gross fair market value of the assets of the Company immediately prior to such acquisition or acquisitions. For this purpose, “gross fair market value” means the value of the assets of the Company, or the value of the assets being disposed of, determined without regard to any liabilities associated with such assets.
 
It is the intent that this definition be construed consistent with the definition of “Change of Control” as defined under Internal Revenue Code Section 409A and the applicable Treasury Regulations, as amended from time to time.
 
i.  
Internal Revenue Code Section 409A Compliance .
 
Except with respect to amounts paid pursuant to a schedule in a plan or arrangement outside of this Agreement, it is intended that amounts payable under this Section 7 not be considered non-qualified deferred compensation subject to Internal Revenue Code Section 409A.  Shellum is a Specified Employee under Internal Revenue Code Section 409A,
 
16
 
therefore, to the extent such amounts are considered non-qualified deferred compensation payable upon a separation from service under Internal Revenue Code Section 409A, payment of those amounts so deferred under Internal Revenue Code Section 409A may not be made until at least six (6) months following Shellum’s separation from service of the Company (or, if earlier, the date of death of Shellum).
 
j.  
Release.   Prior to the payment by the Company of the amounts due under subsections (d), (f) or (h) above, Employee shall execute the release attached hereto as Exhibit A.
 
8.  
Notices. For the purposes of this Agreement, notices and all other communications provided for in the Agreement shall be in writing and shall be deemed to have been duly given when personally delivered, by facsimile transmission or sent by certified mail, return receipt requested, postage prepaid, or by expedited  (overnight) courier with established national reputation, shipping prepaid or billed to sender, in either case addressed to the respective addresses last given by each party to the other  (provided that all notices to the Company shall be directed to the attention of the Secretary of the Company ) or to such other address as either party may have furnished  to the other in writing  in  accordance  herewith.  All notices and communication shall be deemed to have been received on the date of delivery thereof, or on the second day after deposit thereof with an expedited courier service, except that notice of change of address shall be effective only upon receipt.
 
 
Company at:
 
Petroleum Development Corporation
     
120 Genesis Boulevard
     
P.O. Box 26
     
Bridgeport WV 26330
       
 
Shellum at:
 
Gysle R. Shellum
     
6708 Robin Willow Court
     
Dallas, Texas 75248

9.  
Life Insurance.   The Company may, at any time after the execution of this Agreement, maintain any outstanding life insurance policies and apply for and procure as owner and for its own benefit new life insurance on Shellum, in such amounts and in such form or forms as the Company may determine.  Shellum shall, at the request of the Company, submit to such medical examinations, supply such information, and execute such documents as may be required by the insurance company or companies to whom the Company has applied for such insurance.  Shellum hereby represents that to Shellum’s knowledge Shellum is in excellent physical and mental condition.
 
10.  
Successors. This Agreement shall be binding on the Company and any successor to any of its businesses or assets.  Without limiting the effect of the prior sentence, the Company shall use its best efforts to require any successor or assign
 
 
17
 
 
(whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company to expressly assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession or assignment had taken place. As used in this Agreement, "Company" shall mean the Company as hereinbefore defined and any successor or assign to its business and/or assets as aforesaid which assumes and agrees to perform this Agreement or which is otherwise obligated under this Agreement by the first sentence of this Section, entitled Successors, by operation of law or otherwise.
 
11.  
Binding Effect.   This Agreement shall inure to the benefit of and be enforceable by Shellum's personal and legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees.  If Shellum should die while any amounts would still be payable to him hereunder if Shellum had continued to live, all such amounts, unless otherwise provided herein, shall be paid in accordance with the terms of this Agreement to Shellum's estate.
 
12.  
Integration, Modification and Waiver.   This Agreement constitutes the sole employment agreement between the parties, and any prior employment agreement, written or oral, is terminated.  No provision of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing and signed by Shellum and such officer of the Company as may be specifically designated by the Board.  No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with, any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time.
 
13.  
Headings.   Headings used in this Agreement are for convenience only and shall not be used to interpret or construe its provisions.
 
14.  
Waiver of Breach.   The waiver of either the Company or Shellum of a breach of any provision of this Agreement shall not operate or be construed as a waiver of any subsequent breach by either the Company or Shellum.
 
15.  
Amendments.   No amendments or variations of the terms and conditions of this Agreement shall be valid unless the same is in writing and signed by all of the parties hereto.
 
16.  
Survival of Obligations.   The provisions of Section 6 of this Agreement shall continue to be binding upon Shellum and Company in accordance with their terms, notwithstanding the termination of Shellum’s employment with the Company for any reason or the expiration of this Agreement.
 
17.  
Severability.   The invalidity or unenforceability of any provision of this Agreement, whether in whole or in part, shall not in any way affect the validity and/or enforceability of any other provision contained herein.  Any invalid or
 
 
18
 
 
unenforceable provision shall be deemed severable to the extent of any such invalidity or unenforceability.  It is expressly understood and agreed that while the Company and Shellum consider the restrictions contained in this Agreement reasonable for the purpose of preserving for the Company the good will, other proprietary rights and intangible business value of the Company, if a final judicial determination is made by a court having jurisdiction that the time or territory or any other restriction contained in this Agreement is an unreasonable or otherwise unenforceable restriction against Shellum, the provisions of such clause shall not be rendered void but shall be deemed amended to apply as to maximum time and territory and to such other extent as such court may judicially determine or indicate to be reasonable.
 
18.  
Governing Law.   This Agreement shall be construed and enforced pursuant to the laws of the Commonwealth of Pennsylvania, without giving effect to its conflict of laws.
 
19.  
Executive Officer Status.   Shellum acknowledges that Shellum may be deemed to be an "executive officer" of the Company for purposes of the Securities Act of 1933, as amended (the "1933 Act"), and the Securities Exchange Act of 1934, as amended (the "1934 Act") and, if so, Shellum shall comply in all respects with all the rules and regulations under the 1933 Act and the 1934 Act applicable to him in a timely and non-delinquent manner. In order to assist the Company in complying with its obligations under the 1933 Act and 1934 Act, Shellum shall provide to the Company such information about Shellum as the Company shall reasonably request including, but not limited to, information relating to personal history and stockholdings.  Shellum shall immediately report to the General Counsel of the Company or other designated officer of the Company all changes in beneficial ownership of any shares of the Company Common Stock deemed to be beneficially owned by Shellum and/or any members of Shellum's immediate family.
 
20.  
Pronouns.   All pronouns and any variations thereof shall be deemed to refer to the masculine, feminine, neuter, singular, or plural, as the identity of the person or entity may require. As used in this Agreement: (1) words of the masculine gender shall mean and include corresponding neuter words or words of the feminine gender, (2) words in the singular shall mean and include the plural and vice versa, and (3) the word "may" gives sole discretion without any obligation to take any action.
 
21.  
Counterparts.   This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original, but all of which together shall constitute but one document.
 
22.  
Exhibits.   Any Exhibits attached hereto are incorporated herein by reference and are an integral part of this Agreement.
 
 
19
 
23.  
Withholding of Taxes. The Company will withhold from any amounts payable under the Agreement, all federal, state, local or other taxes as legally will be required to be withheld.
 
24.  
Consent to Jurisdiction and Service of Process .
 
a.  
Section 6  Disputes.   In the event of any dispute, controversy or claim between the Company and Shellum arising out of or relating to the interpretation, application or enforcement of the provisions of Section 6, the Company and Shellum agree and consent to the personal jurisdiction of the state and local courts of Allegheny County, Pennsylvania and/or the United States District Court for the Western District of Pennsylvania for resolution of the dispute, controversy or claim, and that those courts, and only those courts, will have jurisdiction to determine any dispute, controversy or claim related to, arising under or in connection with Section 6 of this Agreement. The Company and Shellum also agree that those courts are convenient forums for the parties to any such dispute, controversy or claim and for any potential witnesses and that process issued out of any such court or in accordance with the rules of practice of that court may be served by mail or other forms of substituted service to the Company at the address of its principal executive offices and to Shellum at him last known address as reflected in the Company’s records.
 
b.  
Disputes Other Than Under Section 6.   In the event of any dispute relating to this Agreement, other than a dispute relating solely to Section 6, the parties will use their best efforts to settle the dispute, claim, question, or disagreement. To this effect, they will consult and negotiate with each other in good faith and, recognizing their mutual interests, attempt to reach a just and equitable solution satisfactory to both parties. If such a dispute cannot be settled through negotiation, the parties agree first to try in good faith to settle the dispute by mediation administered by the American Arbitration Association under its Commercial Mediation Rules before resorting to arbitration, litigation, or some other dispute resolution procedure. If the parties do not reach such solution through negotiation or mediation within a period of sixty (60) days, then, upon notice by either party to the other, all disputes, claims, questions, or differences will be finally settled by arbitration administered by the American Arbitration Association in accordance with the provisions of its Commercial Arbitration Rules. The arbitrator will be selected by agreement of the parties or, if they do not agree on an arbitrator within thirty (30) days after either party has notified the other of him or its desire to have the question settled by arbitration, then the arbitrator will be selected pursuant to the procedures of the American Arbitration Association (the “AAA”) in Pittsburgh, Pennsylvania. The determination reached in such arbitration will be final and binding on all parties. Enforcement of the determination by such arbitrator may be sought in any court of competent jurisdiction. Unless otherwise agreed by the parties, any such arbitration will take place
 
 
20
 
 
in Pittsburgh, Pennsylvania, and will be conducted in accordance with the Commercial Arbitration Rules of the AAA.
 
 
IN WITNESS WHEREOF, the Company and Shellum have duly executed this Agreement as of the date first above written.
 

 
           
   
Petroleum Development Corporation
   
Gysle R. Shellum
           
           
           
 
By:
/s/ Kimberly Wakim 
   
/s/ Gysle R. Shellum
   
Kimberly Wakim
   
Gysle R. Shellum
 
Position:
Chair of the
     
   
Compensation Committee
     

 

DM3\885727.2
 
21
 

EXHIBIT A
 
GENERAL RELEASE OF CLAIMS
 
This General Release ("Release") is entered into as of this ____ day of _________, 2008, by and between Petroleum Development Corporation (the “Company”), and __________________, an employee of the Company (the “Employee”) (collectively, the “Parties”).
 
WHEREAS, Employee and the Company are parties to an Employment Agreement (the "Agreement") dated _________________, 2008, governing the terms and conditions applicable if Employee’s employment is terminated for various reasons;
 
WHEREAS, pursuant to the terms of the Agreement, the Company has agreed to provide Employee certain benefits and payments under the terms and conditions specified therein, provided that Employee has executed and not revoked a general release of claims in favor of the Company;
 
WHEREAS, Employee’s employment with the Company is being terminated effective [enter date]; and
 
WHEREAS, the Parties wish to terminate their relationship amicably and to resolve, fully and finally, all actual and potential claims and disputes relating to Employee’s employment with and termination from the Company and all other relationships between Employee and the Company, up to and including the date of execution of this Release.
 
NOW, THEREFORE, in consideration of these Recitals and the promises and mutual covenants contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are expressly acknowledged, the Parties, intending to be legally bound, agree as follows:
 
1.  
Termination of Employment.   Employee’s employment with the Company shall terminate on [enter date] (the "Termination Date").
 
2.  
Severance Benefits.   Pursuant to the terms of the Agreement, and in consideration of Employee’s release of claims and the other covenants and agreements contained herein and therein, and provided that Employee has signed this Release and delivered it to the Company and has not exercised any revocation rights as provided in Section 6 below, the Company shall provide the severance benefits described in Section 7 of the Agreement (the "Benefits") in the time and manner provided therein; provided, however, that the Company's obligations will be excused if Employee breaches any of the provisions of the Agreement including, without limitation, Sections 7, 8 and 9 hereof.  Employee acknowledges and agrees that the Benefits constitute consideration beyond that which, but for the mutual covenants set forth in this Release and the covenants contained in the Agreement, the Company otherwise would not be obligated to provide, nor would Employee otherwise be entitled to receive.
 
 
22
 
3.  
Effective Date.   Provided that it has not been revoked pursuant to Section 6 hereof, this Release will become effective on the eighth (8th) day after the date of its execution by Employee (the "Effective Date").
 
4.  
Effect of Revocation.   Employee acknowledges and agrees that if Employee revokes this Release pursuant to Section 6 hereof, Employee will have no right to receive the Benefits.
 
5.  
General Release.   In consideration of the Company’s obligations, Employee hereby releases, acquits and forever discharges Company and each of its subsidiaries and affiliates and each of their respective officers, employees, directors, successors and assigns from any and all claims, actions or causes of action in any way related to his employment with the Company or the termination thereof, whether arising from tort, statute or contract, including but not limited to, claims of defamation, claims arising under the Employee Retirement Income Security Act of 1974, as amended, the Age Discrimination in Employment Act of 1967, as amended by the Older Workers Benefit Protection Act of 1990, Title VII of the Civil Rights Act of 1964, as amended, the Americans with Disabilities Act, the Family and Medical Leave Act, the discrimination and wage payment laws of Colorado and any other federal, state or local statutes or ordinances of the United States, it being Employee’s intention and the intention of the Company to make this release as broad and as general as the law permits.  Employee understands that this Agreement does not waive any rights or claims that may arise after his execution of it and does not apply to claims arising under the terms of this Agreement.
 
6.  
Review and Revocation Period.   Employee acknowledges that the Company has advised Employee that Employee may consult with an attorney of Employee’s own choosing (and at Employee’s expense) prior to signing this Release and that Employee has been given at least twenty-one (21) days during which to consider the provisions of this Release, although Employee may sign and return it sooner. Employee further acknowledges that Employee has been advised by the Company that after executing this Release, Employee will have seven (7) days to revoke this Release, and that this Release shall not become effective or enforceable until such seven (7) day revocation period has expired.  Employee acknowledges and agrees that if Employee wishes to revoke this Release, Employee must do so in writing, and that such revocation must be signed by Employee and received by the Chairman of the Board of the Company (or the Chairman of the Compensation Committee) no later than 5:00 p.m. Eastern Time on the seventh (7th) day after Employee has executed this Release. Employee acknowledges and agrees that, in the event that Employee revokes this Release, Employee will have no right to receive any benefits hereunder, including the Benefits. Employee represents that Employee has read this Release and understands its terms and enters into this Release freely, voluntarily and without coercion.
 
7.  
Confidentiality, Non-Compete and Non-Solicitation.   Employee reaffirms his commitments in Sections 6.a., 6.c. and 6.d. of the Agreement.
 
 
23
 
8.  
Cooperation in Litigation.   At the Company's reasonable request, Employee shall use his good faith efforts to cooperate with the Company, its Affiliates, and each of its and their respective attorneys or other legal representatives ("Attorneys") in connection with any claim, litigation or judicial or arbitral proceeding which is material to the Company and is now pending or may hereinafter be brought against the Released Parties by any third party; provided, that, Employee’s cooperation is essential to the Company's case.  Employee’s duty of cooperation will include, but not be limited to (a) meeting with the Company's and/or its Affiliates' Attorneys by telephone or in person at mutually convenient times and places in order to state truthfully Employee’s knowledge of matters at issue and recollection of events; (b) appearing at the Company's, its Affiliates' and/or their Attorneys' request (and, to the extent possible, at a time convenient to Employee that does not conflict with the needs or requirements of Employee’s then-current employer) as a witness at depositions or trials, without necessity of a subpoena, in order to state truthfully Employee’s knowledge of matters at issue; and (c) signing at the Company's, its Affiliates' and/or their Attorneys' request declarations or affidavits that truthfully state matters of which Employee has knowledge.  The Company shall reimburse Employee for the reasonable expenses incurred by him in the course of his cooperation hereunder and shall pay to Employee per diem compensation in an amount equal to the daily prorated portion of the Employee’s base salary immediately prior to the Termination Date.  The obligations set forth in this Section 8 shall survive any termination or revocation of this Release.
 
9.  
Non-Admission of Liability.   Nothing in this Release will be construed as an admission of liability by Employee or the Released Parties; rather, Employee and the Released Parties are resolving all matters arising out of the employer-employee relationship between Employee and the Company and all other relationships between Employee and the Released Parties.
 
10.  
Binding Effect.   This Release will be binding upon the Parties and their respective heirs, administrators, representatives, executors, successors and assigns, and will inure to the benefit of the Parties and their respective heirs, administrators, representatives, executors, successors and assigns.
 
11.  
Governing Law.   This Release will be governed by and construed and enforced in accordance with the laws of the Commonwealth of Pennsylvania applicable to agreements negotiated, entered into and wholly to be performed therein.
 
12.  
Severability.   Each of the respective rights and obligations of the Parties hereunder will be deemed independent and may be enforced independently irrespective of any of the other rights and obligations set forth herein.  If any provision of this Release should be held illegal or invalid, such illegality or invalidity will not affect in any way other provisions hereof, all of which will continue, nevertheless, in full force and effect.
 
 
24
 
13.  
Counterparts.   This Release may be signed in counterparts and each counterpart will be deemed to be an original but together all such counterparts will be deemed a single agreement.
 
14.  
Entire Agreement; Modification.   This Release constitutes the entire understanding between the Parties with respect to the subject matter hereof and may not be modified without the express written consent of both Parties.  This Release supersedes all prior written and/or oral and all contemporaneous oral agreements, understandings and negotiations regarding its subject matter.  This Release may not be modified or canceled in any manner except by a writing signed by both Parties.
 
15.  
Acceptance.   Employee may confirm his acceptance of the terms and conditions of this Release by signing and returning two (2) original copies of this Release to the Chairman of the Board of the Company, no later than 5:00 p.m. Eastern Time twenty-one (21) days after Employee’s receipt of notice of termination.
 
EMPLOYEE ACKNOWLEDGES AND REPRESENTS THAT EMPLOYEE HAS FULLY AND CAREFULLY READ THIS RELEASE PRIOR TO SIGNING IT AND UNDERSTANDS ITS TERMS. EMPLOYEE FURTHER ACKNOWLEDGES AND AGREES THAT EMPLOYEE HAS BEEN, OR HAS HAD THE OPPORTUNITY TO BE, ADVISED BY INDEPENDENT LEGAL COUNSEL OF EMPLOYEE’S OWN CHOICE AS TO THE LEGAL EFFECT AND MEANING OF EACH OF THE TERMS AND CONDITIONS OF THIS RELEASE, AND IS ENTERING INTO THIS RELEASE FREELY AND VOLUNTARILY AND NOT IN RELIANCE ON ANY PROMISES OR REPRESENTATIONS OTHER THAN AS SET FORTH IN THIS RELEASE.
 
IN WITNESS WHEREOF, the Company and the Employee have duly executed this Release as of the date first above written.
 
           
 
Company
     
[Full Name]
   
Petroleum Development Corporation
     
           
           
 
By:
       
   
[Full Name]
   
Gysle R. Shellum
 
Position:
Chair of the
     
   
Compensation Committee
     

 
25
Exhibit 10.12
 
Employment Agreement
 
This Employment Agreement (the “Agreement”) is made and entered into this  31st day of December, 2008 by and between Petroleum Development Corporation, a Nevada Corporation (the “Company”), and Barton R. Brookman ( “Brookman”).
 
WHEREAS, the Company wishes to employ Brookman as Senior Vice President of Exploration and Production and to perform the duties and services incident to such position for the Company, and Brookman wishes to be so employed by the Company, all upon the terms and conditions set forth in this Agreement;
 
NOW THEREFORE, in consideration of the premises and mutual covenants and obligations set forth herein and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged and accepted, the parties hereto, intending to be legally bound, agree as follows:
 
1.  
Effective Date and Term
 
a.  
Initial Term.   The effective date of this Agreement shall be January 1, 2008 (the “Effective Date”), and the initial term shall be for the period beginning on the Effective Date and ending December 31, 2009.
 
b.  
Automatic Extensions.   The Term of this Agreement shall be extended for an additional 12 months beginning on December 31, 2008 and on each successive December 31 unless either party provides the other with at least thirty (30) days prior written notice, or unless the contract has been terminated by the parties in accordance with the provisions of Section 7 of this Agreement.  The period of time from the Effective Date until the Termination Date, as defined in Section 7.b., shall be the “Term.”
 
2.  
Place of Employment
 
The place of employment shall be the Company’s offices in Denver, Colorado, unless Brookman and the Company mutually agree to an alternative location.  Brookman acknowledges that there may be substantial business travel associated with Brookman’s position.
 
3.  
Position and Responsibilities
 
a.  
Position.   Brookman shall serve as Senior Vice President of Exploration and Production of the Company and shall initially report to the Chief Executive Officer of the Company (the “Chief Executive Officer”) and be under the general direction and control of the Chief Executive Officer.
 
b.  
Responsibilities.   Brookman shall have obligations, duties, authority and power to do such acts as are customarily done by a person holding the same or an equivalent position in corporations of similar size to the Company.  Brookman shall perform such managerial duties and
 
 
1
 
 
responsibilities for the Company as may be reasonably be assigned to him by the Chief Executive Officer and, at no additional compensation,  if requested, shall serve on the Board of Directors of the Company (the "Board") and in other such positions with any subsidiary corporation of the Company, or any partnership, limited liability company or other entity in which the Company has an interest (herein collectively called “Affiliates”), as the Chief Executive Officer may from time to time determine.
 
c.  
Dedication of Professional Services.   Brookman shall devote substantially all of Brookman’s business time, best efforts and attention to promote and advance the business of the Company and its Affiliates to perform diligently and faithfully all the duties, responsibilities and obligations of Brookman’s position with the Company.  Brookman shall not be employed in any other business activity, other than with the Company and its Affiliates, during the Term, whether or not such activity is pursued for gain, profit or other pecuniary advantage without approval by the Compensation Committee of the Board (the “Compensation Committee”); provided, however, that this restriction shall not be construed as preventing Brookman from investing Brookman’s personal assets in a business which does not compete with the Company or its Affiliates, where the form or manner of such investment will not require services of any significance on the part of Brookman in the operation of the affairs of the business in which such investment is made and in which Brookman’s participation is solely that of a passive investor.
 
d.  
Adherence to Standards.   Brookman shall comply with the written policies, standards, rules and regulations of the Company from time to time established for all employees or executive officers of the Company consistent with Brookman's position and level of authority.
 
e.  
Minimum Stock Ownership.   Brookman shall comply with the Company’s minimum stock ownership requirements for officers (other than the Chief Executive Officer) such requirements being that by the fifth anniversary of the date that Brookman became Senior Vice President of Exploration and Production and until Brookman’s Termination Date, Brookman shall maintain a minimum stock ownership equal to two times Brookman’s Base Salary, as defined in Section 4.a.
 
4.  
Compensation
 
a.  
Base Salary.   The Company shall pay Brookman an annual base salary of $250,000 (the “Base Salary”) commencing on the Effective Date and ending on the Termination Date.  The Base Salary shall be payable in accordance with the ordinary payroll practices of the Company.  The Base Salary shall be reviewed annually by the Compensation Committee and may be changed by the Compensation Committee in its sole discretion,
 
 
2
 
 
taking into account the base salaries, aggregate annual cash compensation, and other compensation of individuals holding similar positions at other comparable companies, the performance of Brookman and the Company, and other relevant factors.
 
b.  
Succession-Related Grant.   On the date that Brookman assumes the position of Senior Vice President of Exploration and Production of the Company, Brookman will receive a one-time award of restricted stock equal in value to $250,000.  For this purpose, the value of the restricted stock will be determined by the Company’s compensation consultants and will be based on the average closing price of the stock of the Company for the month of December, 2007.  The restricted stock will vest at the rate of 20% for each complete year worked by Brookman under this Agreement, beginning from the Effective Date.
 
c.  
Performance Bonus.   Brookman shall be eligible to earn an annual performance bonus (the “Bonus”) during the Term based on criteria established by the Compensation Committee in its sole discretion each year.
 
d.  
Special Restricted Stock Grant.   Brookman shall receive a grant of one thousand five hundred shares of restricted stock of the Company on January 1, 2009.  The restricted stock will vest on January 1, 2010, provided Brookman is then in the employ of the Company.
 
e.  
Equity Compensation Grant.   As a long term incentive, on the Effective Date under the Company’s Long-Term Equity Compensation Plan, Brookman shall participate in any equity compensation program provided to all executive officers, based on criteria established by the Compensation Committee in its sole discretion each year.
 
f.  
Other Compensation.   Brookman shall continue to be eligible to participate in all other cash or stock compensation plans or programs maintained by the Company, as in effect from time to time, in which other senior executives of the Company are allowed to participate.
 
g.  
Recoupment of Certain Compensation.   If the Company has to restate all or a portion of its financial statements due to the material noncompliance of the Company with any financial reporting requirement under the securities laws, the Employee shall, for the affected years, reimburse the Company for any excess bonus paid to the Employee pursuant to Section 4.c.  The reimbursements shall be equal to the difference between the bonus paid to him for the affected years and the bonus that would have been paid to the Employee had the financial results been properly reported. Such reimbursement shall be paid to the Company within ninety days after the Company notifies the Employee of the amount owed to the Company.
 
3
 
5.  
Employee Benefits
 
a.  
Participation in Company Benefit Plans.   During the Term, the Company shall provide Brookman with coverage under all employee pension and welfare benefit programs, plans and practices commensurate with Brookman’s positions in the Company and to the extent permitted under the respective employee benefit plan.
 
b.  
Vacation.   Brookman will be entitled to four (4) weeks of paid vacation in each calendar year, to be taken at such times as is reasonably determined by Brookman to be consistent with Brookman’s responsibilities under this Agreement and the Company’s vacation policy applicable to all employees.
 
c.  
Automobile.   During the Term, Brookman shall be entitled to an annual automobile allowance as approved by the Compensation Committee and updated from time to time at its discretion.
 
6.  
Restrictive Covenants
 
a.  
Confidential Information.   Brookman hereby acknowledges that in connection with Brookman’s employment by the Company, Brookman will be exposed to and may obtain certain Confidential Information (as defined below) (including, without limitation, procedures, memoranda, notes, records and customer and supplier lists whether such information has been or is made, developed or compiled by Brookman or otherwise has been or is made available to him) regarding the business and operations of the Company and its subsidiaries or affiliates.  Brookman further acknowledges that such Confidential Information is unique, valuable, considered trade secrets and deemed proprietary by the Company.  For purposes of the Agreement, “Confidential Information” includes, without limitation, any information heretofore or hereafter acquired, developed or used by any of the Company or their direct or indirect subsidiaries relating to Business Opportunities or Intellectual Property or other geological, geophysical, economic, financial or management aspects of the business, operations, properties or prospects of the Company or their direct or indirect subsidiaries, whether oral or in written form (including electronic).  Brookman agrees that all Confidential Information is and will remain the property of the Company or their direct or indirect subsidiaries, as the case may be.  Brookman further agrees, except for disclosures occurring in the good faith performance of Brookman’s duties for the Company or their direct or indirect subsidiaries, during the Term and for a period of three (3) years after the Termination Date, to hold in the strictest confidence all Confidential Information, and not to, directly or indirectly, duplicate, sell, use, lease, commercialize, disclose or otherwise divulge to any person or entity any portion of the Confidential Information or use any Confidential Information, directly or
 
 
4
 
 
indirectly, for Brookman’s own benefit or profit or allow any person, entity or third party, other than the Company or their direct or indirect subsidiaries and authorized executives of the same, to use or otherwise gain access to any Confidential Information.  Brookman will have no obligation under this Agreement with respect to any information that becomes generally available to the public other than as a result of a disclosure by Brookman or Brookman’s agent or other representative or becomes available to Brookman on a non-confidential basis from a source other than the Company or their direct or indirect subsidiaries.  Further, Brookman will have no obligation under this Agreement to keep confidential any of the Confidential Information to the extent that a disclosure of it is required by law or is consented to by the Company; provided, however, that if and when such a disclosure is required by law, Brookman promptly will provide the Company with notice of such requirement, so that the Company may seek an appropriate protective order.
 
 
b.  
Return of Property.   Brookman agrees to deliver promptly to the Company, upon termination of Brookman’s employment hereunder, or at any other time when the Company so requests, all documents and property relating to the business of the Company or their direct or indirect subsidiaries, including without limitation: all geological and geophysical reports and related data such as maps, charts, logs, seismographs, seismic records and other reports and related data, calculations, summaries, memoranda and opinions relating to the foregoing, production records, electric logs, core data, pressure data, lease files, well files and records, land files, abstracts, title opinions, title or curative matters, contract files, notes, records, drawings, manuals, correspondence, financial and accounting information, customer lists, statistical data and compilations, patents, copyrights, trademarks, trade names, inventions, formulae, methods, processes, agreements, contracts, manuals, electronic data,  or any documents,  whether written or digital and whether prepared or compiled by Brookman or furnished to Brookman during the Term, relating to the business of the Company or their direct or indirect subsidiaries and all copies thereof and therefrom; provided, however, that Brookman will be permitted to retain copies of any documents or materials of a personal nature or otherwise related to Brookman’s rights under this Agreement. The aforementioned materials include materials on Brookman’s personal computers, which materials shall be destroyed in a manner satisfactory to the Company.
 
 
5
 
c.  
Non-Compete Obligations.
 
(i)  
Non-Compete Obligations During Employment Term.  Brookman agrees that during the Term:
 
(A)  
Brookman will not, other than through the Company, engage or participate in any manner, whether directly or indirectly through any family member or as an employee, employer, consultant, agent, principal, partner, more than one percent shareholder, officer, director, licensor, lender, lessor or in any other individual or representative capacity, in any business or activity which is engaged in leasing, acquiring, exploring, producing, gathering or marketing hydrocarbons and related products; provided that the foregoing shall not be deemed to restrain the participation by Brookman’s spouse in any capacity set forth above in any business or activity engaged in any such activity and provided further that the Company may, in good faith, take such reasonable action with respect to Brookman’s performance of Brookman’s duties, responsibilities and authorities as set forth in this Agreement as it deems necessary and appropriate to protect its legitimate business interests with respect to any actual or apparent conflict of interest reasonably arising from or out of the participation by Brookman’s spouse in any such competitive business or activity; and
 
(B)  
all investments made by Brookman (whether in Brookman’s own name or in the name of any family members or other nominees or made by Brookman’s controlled affiliates), which relate to the leasing, acquisition, exploration, production, gathering or marketing of hydrocarbons and related products will be made solely through the Company; and Brookman will not (directly or indirectly through any family members or other persons), and will not permit any of Brookman’s controlled affiliates to: (1) invest or otherwise participate alongside the Company or its direct or indirect subsidiaries in any Business Opportunities, or (2) invest or otherwise participate in any business or activity relating to a Business Opportunity, regardless of whether any of the Company or its direct or indirect subsidiaries ultimately participates in such business or activity, in either case, except through the Company.  Notwithstanding the foregoing, nothing in this Section 6 shall be deemed to prohibit Brookman or any family member from owning, or otherwise having an interest in, less than one percent (1%) of any publicly-
 
 
6
 
owned entity or three percent (3%) or less of any private equity fund or similar investment fund that invests in any business or activity engaged in any of the activities set forth above, provided that Brookman has no active role with respect to any investment by such fund in any entity.
 
 
 
(ii)  
Non-Compete Obligations After Termination Date.  Brookman agrees that Brookman will not engage or participate in any manner, whether directly or indirectly through any family member or other person or as an employee, employer, consultant, agent principal, partner, more than one percent shareholder, officer, director, licensor, lender, lessor or in any other individual or representative capacity:
 
(A)  
during the one-year period following the Termination Date, in any business or activity which is engaged in leasing, acquiring, exploring, producing, gathering or marketing hydrocarbons and related products within (1) any county or parish in which the Company owns any oil and gas interests or conducts operations on the Termination Date or in which the Company has owned any oil and gas interests or conducted operations at any time during the six months immediately preceding the Termination Date or (2)  any county or parish adjacent to any county or parish described in clause (1); and
 
(B)  
during the two-year period following the Termination Date, in any business or activity which is in direct competition with the business of the Company or its direct or indirect subsidiaries in the leasing, acquiring, exploring, producing, gathering or marketing of hydrocarbons and related products within the boundaries of, or within a two-mile radius of the boundaries of, any mineral property interest of any of the Company or its direct or indirect subsidiaries (including, without limitation, a mineral lease, overriding royalty interest, production payment, net profits interest, mineral fee interest or option or right to acquire any of the foregoing, or an area of mutual interest as designated pursuant to contractual agreements between the Company and any third party) or any other property on which any of the Company or its direct or indirect subsidiaries has an option, right, license or authority to conduct or direct exploratory activities, such as three-dimensional seismic acquisition or other seismic, geophysical and geochemical activities (but not including any preliminary geological mapping), as of the Termination Date or as of the end of the six-month period following such Termination Date;
 
 
7
 
 
 provided that, this subsection (ii) will not preclude Brookman from making investments in securities of oil and gas companies which are registered on a national stock exchange, if the aggregate amount owned by Brookman and all family members and affiliates does not exceed 5% of such company’s outstanding securities.
 
(iii)  
Notwithstanding the foregoing, nothing in this Section 6.c. shall be deemed to restrain the participation by Brookman’s spouse in any capacity set forth above in any business or activity described above.
 
d.  
Non-Solicitation.   During the Term and for a period of twenty-four (24) months after the Termination Date, Brookman will not, whether for Brookman’s own account or for the account of any other person (other than the Company or its direct or indirect subsidiaries), intentionally solicit, endeavor to entice away from the Company or its direct or indirect subsidiaries, or otherwise interfere with the relationship of the Company or its direct or indirect subsidiaries with, (i) any person who is employed by the Company or its direct or indirect subsidiaries (including any independent sales representatives or organizations), or (ii) any client or customer of the Company or its direct or indirect subsidiaries.
 
e.  
Assignment of Developments.   Brookman assigns and agrees to assign without further compensation to the Company and its successors, assigns or designees, all of Brookman’s right, title and interest in and to all Business Opportunities and Intellectual Property (as those terms are defined below), and further acknowledges and agrees that all Business Opportunities and Intellectual Property constitute the exclusive property of the Company.
 
For purposes of this Agreement, “Business Opportunities” means all business ideas, prospects, proposals or other opportunities pertaining to the lease, acquisition, exploration, production, gathering or marketing of hydrocarbons and related products and the exploration potential of geographical areas on which hydrocarbon exploration prospects are located, which are developed by Brookman during the Term, or originated by any third party and brought to the attention of Brookman during the Term, together with information relating thereto (including, without limitation, geological and seismic data and interpretations thereof, whether in the form of maps, charts, logs, seismographs, calculations, summaries, memoranda, opinions or other written or charted means).
 
For purposes of this Agreement, “Intellectual Property” shall mean all ideas, inventions, discoveries, processes, designs, methods, substances, articles, computer programs and improvements (including, without limitation, enhancements to, or further interpretation or processing of,
 
 
8
 
information that was in the possession of Brookman prior to the date of this Agreement), whether or not patentable or copyrightable, which do not fall within the definition of Business Opportunities, which Brookman discovers, conceives, invents, creates or develops, alone or with others, during the Term, if such discovery, conception, invention, creation or development (i) occurs in the course of Brookman’s employment with the Company, or (ii) occurs with the use of any of the time, materials or facilities of the Company or its direct or indirect subsidiaries, or (iii) in the good faith judgment of the Board, relates or pertains in any material way to the purposes, activities or affairs of the Company or its direct or indirect subsidiaries.
 
f.  
Injunctive Relief.   Brookman acknowledges that a breach of any of the covenants contained in this Section 6 may result in material, irreparable injury to the Company for which there is no adequate remedy at law, that it will not be possible to measure damages for such injuries precisely and that, in the event of such a breach or threat of breach, the Company will be entitled to obtain a temporary restraining order and/or a preliminary or permanent injunction restraining Brookman from engaging in activities prohibited by this Section 6 or such other relief as may be required to specifically enforce any of the covenants in this Section 6.  To the extent that the Company seeks a temporary restraining order (but not a preliminary or permanent injunction), Brookman agrees that a temporary restraining order may be obtained ex parte.
 
g.  
Adjustment of Covenants.   The parties consider the covenants and restrictions contained in this Section 6 to be reasonable.  However, if and when any such covenant or restriction is found to be void or unenforceable and would have been valid had some part of it been deleted or had its scope of application been modified, such covenant or restriction will be deemed to have been applied with such modification as would be necessary and consistent with the intent of the parties to have made it valid, enforceable and effective.
 
h.  
Forfeiture Provision.
 
(i)  
Detrimental Activities .  If Brookman engages in any activity that violates any covenant or restriction contained in this Section 6, in addition to any other remedy the Company may have at law or in equity, (A) Brookman will be entitled to no further payments or benefits from the Company under this Agreement or otherwise, except for any payments or benefits required to be made or provided under applicable law, (B) all unexercised stock options, restricted stock and other forms of equity compensation held by or credited to Brookman will terminate effective as of the date on which Brookman engages in that activity, unless terminated sooner by operation of another term or condition of this Agreement or
 
 
9
 
 
other applicable plans and agreements, and (C) any exercise, payment or delivery pursuant to any equity compensation award that occurred within one year prior to the date on which Brookman engages in that activity may be rescinded within one year after the first date that a majority of the members of the Board first became aware that Brookman engaged in that activity.  In the event of any such rescission, Brookman will pay to the Company the amount of any gain realized or payment received as a result of the rescinded exercise, payment or delivery, in such manner and on such terms and conditions as may be required.
 
(ii)  
Right of Set-Off .  Brookman consents to a deduction from any amounts the Company owes Brookman from time to time (including amounts owed as wages or other compensation, fringe benefits, or vacation pay, as well as any other amounts owed to Brookman by the Company), to the extent of the amounts Brookman owes the Company under Section 6 above.  Whether or not the Company elects to make any set-off in whole or in part, if the Company does not recover by means of set-off the full amount Brookman owes, calculated as set forth above, Brookman agrees to pay immediately the unpaid balance to the Company.  In the discretion of the Board, reasonable interest may be assessed on the amounts owed, calculated from the later of (A) the date Brookman engages in the prohibited activity and (B) the applicable date of exercise, payment or delivery.
 
7.  
Termination of the Agreement
 
a.  
Notice of Termination.   Either Brookman or the Board may terminate this Agreement at any time and in Brookman’s or their sole discretion upon no less than thirty (30) days written Notice of Termination to the other party.  "Notice of Termination" shall mean a written notice which shall indicate the specified termination provision in this Agreement relied upon (Section 7.c., Section 7.d., Section 7.e., Section 7.f., Section 7.g. or Section 7.h.) and shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of Brookman's employment under the provision so indicated; provided, however, no such purported termination shall be effective without such Notice of Termination; provided further, however, any purported termination by the Company or by Brookman shall be communicated by a Notice of Termination to the other party hereto in accordance with  Section 8 (“Notices”) of this Agreement.
 
b.  
Termination Date.   The “Termination Date” shall mean the date specified in the Notice of Termination. The Termination Date shall not be less than thirty (30) days after the date such Notice of Termination is given.
 
 
10
 
c.  
Termination by the Company for Just Cause.
 
(i)  
The Company may terminate Brookman for “Just Cause” (as defined in Section 7.c.ii), provided that the Company shall:
 
(A)  
Give Brookman Notice of Termination as specified in Section 7.a., and
 
(B)  
Pay Brookman, within thirty (30) days after this Termination Date, Brookman’s Base Salary through the Termination Date at the rate in effect at the time the Notice of Termination is given plus a good faith estimate by the Company of any unpaid Bonus (in full for any completed annual period and prorated for months completed in the current annual period), incentive, deferred, retirement or other compensation, and provide any other benefits, which have been earned or become payable as of the Termination Date, pursuant to the terms of this or any other agreement, or compensation or benefit plan, but which have not yet been paid or provided.
 
(ii)  
For purposes of this Agreement “Just Cause” shall be a reasonable determination of the Board that Brookman:
 
(A)  
Failed to substantially perform Brookman’s duties with the Company (other than a failure resulting from Brookman’s incapacity due to physical or mental illness) after a written demand for substantial performance has been delivered to him by the Board, which demand specifically identifies the manner in which the Board believes Brookman has not substantially performed Brookman’s duties, and Brookman has failed to cure such deficiency within thirty (30) days of the receipt of such notice;
 
(B)  
Has engaged in conduct the consequences of which are materially adverse to the Company, monetarily or otherwise;
 
(C)  
Has pleaded guilty to or been convicted of a felony or a crime involving moral turpitude or dishonesty; or
 
(D)  
Has materially breached the terms of this Agreement.
 
(E)  
Following a Change in Control, Subsection (A) above shall be deleted from this definition of “Just Cause”.
 
d.  
Termination by the Company Without Just Cause.   In the event the Company terminates this Agreement prior to its expiration (including
 
 
11
 
 
extensions as provided in Section 1.b) for any reason other than for Just Cause or the death or Disability (as defined in Section 7.e.) of Brookman, the Company shall:
 
(i)  
Pay to Brookman within thirty (30) days after the Termination Date, a lump sum severance payment equal to two times the sum of:
 
(A)  
Brookman’s highest Base Salary during the previous two years of employment immediately preceding the Termination Date, plus
 
(B)  
the highest Bonus paid to Brookman during the same two-year period,
 
(ii)  
Pay to Brookman any unpaid expense reimbursement upon presentation by Brookman of an accounting of such expenses in accordance with normal Company practices, but no later than March 15 of the year following the year of termination,
 
(iii)  
Vest any unvested Company stock options or restricted stock (excluding LTIP shares under the Company’s Long-Term Incentive Plan),
 
(iv)  
Make any other payments or provide any benefits earned under this or any other employment agreement or plan, including the Company’s Long-Term Incentive Plan (including LTIP shares under the Company’s Long-Term Incentive Plan), and
 
(v)  
Continue coverage of Brookman and any dependents covered at the time of termination under the Company’s group health plans at the Company’s cost throughout the period of time that Brookman is eligible for federal COBRA health continuation coverage.
 
e.  
Termination in the Event of Death or Disability.   This Agreement shall terminate in the event of the death of Brookman or may be terminated by the Company in the event of a Disability (as hereinafter defined) of Brookman upon proper notification to Brookman (or Brookman’s estate in the event of Brookman’s death), provided the Company shall pay to Brookman (or to the estate of Brookman in the event of termination due to the death of Brookman) the Base Salary described in Section 4.a. of this Agreement which would have been earned for six (6) months after the Termination Date.  The benefits provided under this Section 7.e. shall be no less favorable to Brookman in terms of amounts, deductibles and costs to him, if any, than such benefits provided by the Company to him and shall not be interpreted so as to limit any benefits to which Brookman, as a terminated employee of the Company, or Brookman’s family may be entitled under the Company’s life insurance, medical, hospitalization or
 
 
12
 
 
disability plans following Brookman’s Termination Date or under applicable law, and any other benefits or payments earned by Brookman under Brookman’s or any other agreement or plan.  “Disability” means the inability of Brookman to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, as provided in Internal Revenue Code Section 409A(a)(2)(C) and Treas. Reg. § 1.409A-3(i)(4).  All amounts payable under this Section 7.e. shall be paid in a lump-sum as soon as practicable, but in no event later than two-and-one-half (2-1/2) months following the close of the calendar year in which the death or Disability occurred.
 
f.  
Termination by Brookman for Good Reason.
 
(i)  
In the event Brookman terminate this Agreement for Good Reason (as defined in Section 7.f.ii), provided such Brookman’s termination occurs within ninety days of the Good Reason, the Company shall:
 
(A)  
Pay to Brookman within thirty (30) days after the Termination  Date, a lump sum severance payment equal to two times the sum of:
 
1.  
Brookman’s highest Base Salary during the previous two years of employment immediately preceding the Termination Date, plus
 
2.  
the highest Bonus paid to Brookman during the same two-year period,
 
(B)  
Pay to Brookman any unpaid expense reimbursement upon presentation by Brookman of an accounting of such expenses in accordance with normal Company practices, but no later than March 15 of the year following the year of termination,
 
(C)  
Vest any unvested Company stock options or restricted stock (excluding LTIP shares under the Company’s Long-Term Incentive Plan),
 
(D)  
Make any other payments or provide any benefits earned under this or any other employment agreement or plan, including the Company’s Long-Term Incentive Plan (including LTIP shares under the Company’s Long-Term Incentive Plan), and
 
13
 
(E)  
Continue coverage of Brookman and any dependents covered at the time of termination under the Company’s group health plans at the Company’s cost throughout the period of time that Brookman is eligible for federal COBRA health continuation coverage.
 
(ii)  
"Good Reason" shall mean the occurrence of any of the following events without Brookman's prior express written consent:
 
(A)  
A material diminution in Brookman’s Base Salary;
 
(B)  
A material diminution in reward opportunities under the annual Bonus;
 
(C)  
Any other action or inaction that constitutes a material breach by the Company of this Agreement.
 
Brookman must provide notice to the Company of the condition described in paragraphs (A)-(C) of this section within ninety (90) days, upon the notice of which the Company will have a period of thirty (30) days during which it may remedy the condition and not be required to pay the amount.
 
g.  
Termination by Brookman for other than Good Reason.   Brookman may terminate this Agreement for other than Good Reason upon proper Notice of Termination as provided in Section 7.a.  In such event the Company shall pay to Brookman:
 
(i)  
Within thirty (30) days after Brookman’s Termination Date, in a lump-sum, the compensation provided in Section 4 at the rate in effect at the time of the Notice of Termination. If Brookman’s termination occurs prior to the end of the year, Brookman shall not be entitled to any Bonus for the year;
 
(ii)  
Any incentive, deferred or other compensation which has been earned or has become payable pursuant to the terms of this or any other agreement or compensation or benefit plan as of the Termination Date, but which has not yet been paid, provided such payments shall be made under the schedule originally contemplated in the agreement under which they were granted, but if no such payment schedule is provided, the payments shall be made no later than March 15 of the year following the year of termination;
 
(iii)  
Any unpaid expense reimbursement upon presentation by Brookman of an accounting of such expenses in accordance with
 
 
14
 
 
normal Company practices, but not later than March 15 of the year following the year of termination; and
 
(iv)  
Any other payments for benefits earned under this Agreement, which shall in no event be paid later than March 15 of the year following the year of termination.
 
h.  
Termination following Change of Control.
 
(i)  
If either (1) the Company terminates Brookman’s employment within two years following a Change of Control of the Company (as defined in Section 7.h.ii.) or (2)  Brookman gives notice to the Company of termination of this Agreement during the thirty (30) day period beginning one hundred twenty  (120) days immediately following a Change in Control, then the Company shall:
 
(A)  
Pay to Brookman within thirty (30) days after the Termination Date, a lump sum severance payment equal to three times the sum of:
 
1.  
Brookman’s highest Base Salary during the previous two years of employment immediately preceding the Termination Date, plus
 
2.  
the highest Bonus paid to Brookman during the same two-year period.
 
(B)  
Pay to Brookman any unpaid expense reimbursement upon presentation by Brookman of an accounting of such expenses in accordance with normal Company practices, but no later than March 15 of the year following the year of termination,
 
(C)  
Vest any unvested Company stock options or restricted stock (excluding LTIP shares under the Company’s Long-Term Incentive Plan),
 
(D)  
Make any other payments or provide any benefits earned under this or any other employment agreement or plan, including the Company’s Long-Term Incentive Plan (including LTIP shares under the Company’s Long-Term Incentive Plan), and
 
(E)  
Continue coverage of Brookman and any dependents covered at the time of termination under the Company’s group health plans at the Company’s cost throughout the period of time that Brookman is eligible for federal COBRA health continuation coverage.
 
 
15
 
(ii)  
"Change of Control" of the Company shall occur on the earliest of the following events:
 
(A)  
Change in Ownership: A change in ownership of the Company occurs on the date that any one person, or more than one person acting as a group, acquires ownership of stock of the Company that, together with stock held by such person or group, constitutes more than 50% of the total fair market value or total voting power of the stock of the Company, excluding the acquisition of additional stock by a person or more than one person acting as a group who is considered to own more than 50% of the total fair market value or total voting power of the stock of the Company.
 
(B)  
Change in Effective Control: A change in effective control of the Company occurs on the date that either:
 
1.  
Any one person, or more than one person acting as a group, acquires (or has acquired during the l2-month period ending on the date of the most recent acquisition by such person or persons) ownership of stock of the Company possessing 35% or more of the total voting power of the stock of the Company; or
 
2.  
A majority of the members of the Board of Directors of the Company (the “Board”) is replaced during any l2-month period by directors whose appointment or election is not endorsed by a majority of the members of the board of directors prior to the date of the appointment or election; provided, that this paragraph (b) shall apply only to the Company if no other corporation is a majority shareholder.
 
(C)  
Change in Ownership of Substantial Assets: A change in the ownership of a substantial portion of the Company's assets occurs on the date that any one person, or more than one person acting as a group, acquires (or has acquired during the l2-month period ending on the date of the most recent acquisition by such person or persons) assets from the Company that have a total gross fair market value equal to or more than 40% of the total gross fair market value of the assets of the Company immediately prior to such acquisition or acquisitions. For this purpose, “gross fair market value” means the value of the assets of the Company, or the value of the assets being disposed of,
 
 
16
 
 
determined without regard to any liabilities associated with such assets.
 
It is the intent that this definition be construed consistent with the definition of “Change of Control” as defined under Internal Revenue Code Section 409A and the applicable Treasury Regulations, as amended from time to time.
 
i.  
Internal Revenue Code Section 409A Compliance .
 
Except with respect to amounts paid pursuant to a schedule in a plan or arrangement outside of this Agreement, it is intended that amounts payable under this Section 7 not be considered non-qualified deferred compensation subject to Internal Revenue Code Section 409A.  Brookman is a Specified Employee under Internal Revenue Code Section 409A, therefore, to the extent such amounts are considered non-qualified deferred compensation payable upon a separation from service under Internal Revenue Code Section 409A, payment of those amounts so deferred under Internal Revenue Code Section 409A may not be made until at least six (6) months following Brookman’s separation from service of the Company (or, if earlier, the date of death of Brookman).
 
j.  
Release.   Prior to the payment by the Company of the amounts due under subsections (d), (f) or (h) above, Employee shall execute the release attached hereto as Exhibit A.
 
8.  
Notices. For the purposes of this Agreement, notices and all other communications provided for in the Agreement shall be in writing and shall be deemed to have been duly given when personally delivered, by facsimile transmission or sent by certified mail, return receipt requested, postage prepaid, or by expedited  (overnight) courier with established national reputation, shipping prepaid or billed to sender, in either case addressed to the respective addresses last given by each party to the other  (provided that all notices to the Company shall be directed to the attention of the Secretary of the Company ) or to such other address as either party may have furnished  to the other in writing  in  accordance  herewith.  All notices and communication shall be deemed to have been received on the date of delivery thereof, or on the second day after deposit thereof with an expedited courier service, except that notice of change of address shall be effective only upon receipt.
 
 
Company at:
 
Petroleum Development Corporation
     
120 Genesis Boulevard
     
P.O. Box 26
     
Bridgeport WV 26330
 
     
 
Brookman at:
 
Barton R. Brookman
     
6125 Maroon Peak Place
     
Castle Rock, CO 80108
 
 
17

 
9.  
Life Insurance.   The Company may, at any time after the execution of this Agreement, maintain any outstanding life insurance policies and apply for and procure as owner and for its own benefit new life insurance on Brookman, in such amounts and in such form or forms as the Company may determine.  Brookman shall, at the request of the Company, submit to such medical examinations, supply such information, and execute such documents as may be required by the insurance company or companies to whom the Company has applied for such insurance.  Brookman hereby represents that to Brookman’s knowledge Brookman is in excellent physical and mental condition.
 
10.  
Successors. This Agreement shall be binding on the Company and any successor to any of its businesses or assets.  Without limiting the effect of the prior sentence, the Company shall use its best efforts to require any successor or assign (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company to expressly assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession or assignment had taken place. As used in this Agreement, "Company" shall mean the Company as hereinbefore defined and any successor or assign to its business and/or assets as aforesaid which assumes and agrees to perform this Agreement or which is otherwise obligated under this Agreement by the first sentence of this Section, entitled Successors, by operation of law or otherwise.
 
11.  
Binding Effect.   This Agreement shall inure to the benefit of and be enforceable by Brookman's personal and legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees.  If Brookman should die while any amounts would still be payable to him hereunder if Brookman had continued to live, all such amounts, unless otherwise provided herein, shall be paid in accordance with the terms of this Agreement to Brookman's estate.
 
12.  
Integration, Modification and Waiver.   This Agreement constitutes the sole employment agreement between the parties, and any prior employment agreement, written or oral, is terminated.  No provision of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing and signed by Brookman and such officer of the Company as may be specifically designated by the Board.  No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with, any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time.
 
13.  
Headings.   Headings used in this Agreement are for convenience only and shall not be used to interpret or construe its provisions.
 
 
18
 
14.  
Waiver of Breach.   The waiver of either the Company or Brookman of a breach of any provision of this Agreement shall not operate or be construed as a waiver of any subsequent breach by either the Company or Brookman.
 
15.  
Amendments.   No amendments or variations of the terms and conditions of this Agreement shall be valid unless the same is in writing and signed by all of the parties hereto.
 
16.  
Survival of Obligations.   The provisions of Section 6 of this Agreement shall continue to be binding upon Brookman and Company in accordance with their terms, notwithstanding the termination of Brookman’s employment with the Company for any reason or the expiration of this Agreement.
 
17.  
Severability.   The invalidity or unenforceability of any provision of this Agreement, whether in whole or in part, shall not in any way affect the validity and/or enforceability of any other provision contained herein.  Any invalid or unenforceable provision shall be deemed severable to the extent of any such invalidity or unenforceability.  It is expressly understood and agreed that while the Company and Brookman consider the restrictions contained in this Agreement reasonable for the purpose of preserving for the Company the good will, other proprietary rights and intangible business value of the Company, if a final judicial determination is made by a court having jurisdiction that the time or territory or any other restriction contained in this Agreement is an unreasonable or otherwise unenforceable restriction against Brookman, the provisions of such clause shall not be rendered void but shall be deemed amended to apply as to maximum time and territory and to such other extent as such court may judicially determine or indicate to be reasonable.
 
18.  
Governing Law.   This Agreement shall be construed and enforced pursuant to the laws of the Commonwealth of Pennsylvania, without giving effect to its conflict of laws.
 
19.  
Executive Officer Status.   Brookman acknowledges that Brookman may be deemed to be an "executive officer" of the Company for purposes of the Securities Act of 1933, as amended (the "1933 Act"), and the Securities Exchange Act of 1934, as amended (the "1934 Act") and, if so, Brookman shall comply in all respects with all the rules and regulations under the 1933 Act and the 1934 Act applicable to him in a timely and non-delinquent manner. In order to assist the Company in complying with its obligations under the 1933 Act and 1934 Act, Brookman shall provide to the Company such information about Brookman as the Company shall reasonably request including, but not limited to, information relating to personal history and stockholdings.  Brookman shall immediately report to the General Counsel of the Company or other designated officer of the Company all changes in beneficial ownership of any shares of the Company Common Stock deemed to be beneficially owned by Brookman and/or any members of Brookman's immediate family.
 
 
19
 
20.  
Pronouns.   All pronouns and any variations thereof shall be deemed to refer to the masculine, feminine, neuter, singular, or plural, as the identity of the person or entity may require. As used in this Agreement: (1) words of the masculine gender shall mean and include corresponding neuter words or words of the feminine gender, (2) words in the singular shall mean and include the plural and vice versa, and (3) the word "may" gives sole discretion without any obligation to take any action.
 
21.  
Counterparts.   This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original, but all of which together shall constitute but one document.
 
22.  
Exhibits.   Any Exhibits attached hereto are incorporated herein by reference and are an integral part of this Agreement.
 
23.  
Withholding of Taxes. The Company will withhold from any amounts payable under the Agreement, all federal, state, local or other taxes as legally will be required to be withheld.
 
24.  
Consent to Jurisdiction and Service of Process
 
a.  
Section 6  Disputes.   In the event of any dispute, controversy or claim between the Company and Brookman arising out of or relating to the interpretation, application or enforcement of the provisions of Section 6, the Company and Brookman agree and consent to the personal jurisdiction of the state and local courts of Allegheny County, Pennsylvania and/or the United States District Court for the Western District of Pennsylvania for resolution of the dispute, controversy or claim, and that those courts, and only those courts, will have jurisdiction to determine any dispute, controversy or claim related to, arising under or in connection with Section 6 of this Agreement. The Company and Brookman also agree that those courts are convenient forums for the parties to any such dispute, controversy or claim and for any potential witnesses and that process issued out of any such court or in accordance with the rules of practice of that court may be served by mail or other forms of substituted service to the Company at the address of its principal executive offices and to Brookman at him last known address as reflected in the Company’s records.
 
b.  
Disputes Other Than Under Section 6.   In the event of any dispute relating to this Agreement, other than a dispute relating solely to Section 6, the parties will use their best efforts to settle the dispute, claim, question, or disagreement. To this effect, they will consult and negotiate with each other in good faith and, recognizing their mutual interests, attempt to reach a just and equitable solution satisfactory to both parties. If such a dispute cannot be settled through negotiation, the parties agree first to try in good faith to settle the dispute by mediation administered by the American
 
 
20
 
 
Arbitration Association under its Commercial Mediation Rules before resorting to arbitration, litigation, or some other dispute resolution procedure. If the parties do not reach such solution through negotiation or mediation within a period of sixty (60) days, then, upon notice by either party to the other, all disputes, claims, questions, or differences will be finally settled by arbitration administered by the American Arbitration Association in accordance with the provisions of its Commercial Arbitration Rules. The arbitrator will be selected by agreement of the parties or, if they do not agree on an arbitrator within thirty (30) days after either party has notified the other of him or its desire to have the question settled by arbitration, then the arbitrator will be selected pursuant to the procedures of the American Arbitration Association (the “AAA”) in Pittsburgh, Pennsylvania. The determination reached in such arbitration will be final and binding on all parties. Enforcement of the determination by such arbitrator may be sought in any court of competent jurisdiction. Unless otherwise agreed by the parties, any such arbitration will take place in Pittsburgh, Pennsylvania, and will be conducted in accordance with the Commercial Arbitration Rules of the AAA.
 
IN WITNESS WHEREOF, the Company and Brookman have duly executed this Agreement as of the date first above written.
 

 
         
 
Petroleum Development Corporation
   
Barton R. Brookman
         
         
         
By:
/s/ Kimberly Wakim 
   
/s/ Barton R. Brookman
 
Kimberly Wakim
   
Barton R. Brookman
Position:
Chair of the
     
 
Compensation Committee
     

 

21
 


EXHIBIT A
 
GENERAL RELEASE OF CLAIMS
 
This General Release ("Release") is entered into as of this ____ day of _________, 2008, by and between Petroleum Development Corporation (the “Company”), and __________________, an employee of the Company (the “Employee”) (collectively, the “Parties”).
 
WHEREAS, Employee and the Company are parties to an Employment Agreement (the "Agreement") dated _________________, 2008, governing the terms and conditions applicable if Employee’s employment is terminated for various reasons;
 
WHEREAS, pursuant to the terms of the Agreement, the Company has agreed to provide Employee certain benefits and payments under the terms and conditions specified therein, provided that Employee has executed and not revoked a general release of claims in favor of the Company;
 
WHEREAS, Employee’s employment with the Company is being terminated effective [enter date]; and
 
WHEREAS, the Parties wish to terminate their relationship amicably and to resolve, fully and finally, all actual and potential claims and disputes relating to Employee’s employment with and termination from the Company and all other relationships between Employee and the Company, up to and including the date of execution of this Release.
 
NOW, THEREFORE, in consideration of these Recitals and the promises and mutual covenants contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are expressly acknowledged, the Parties, intending to be legally bound, agree as follows:
 
1.   Termination of Employment .  Employee’s employment with the Company shall terminate on [enter date] (the "Termination Date").
 
2.   Severance Benefits .  Pursuant to the terms of the Agreement, and in consideration of Employee’s release of claims and the other covenants and agreements contained herein and therein, and provided that Employee has signed this Release and delivered it to the Company and has not exercised any revocation rights as provided in Section 6 below, the Company shall provide the severance benefits described in Section 7 of the Agreement (the "Benefits") in the time and manner provided therein; provided, however, that the Company's obligations will be excused if Employee breaches any of the provisions of this Agreement including, without limitation, Sections 7, 8 and 9 hereof.  Employee acknowledges and agrees that the Benefits constitute consideration beyond that which, but for the mutual covenants set forth in this Release and the covenants contained in the Agreement, the Company otherwise would not be obligated to provide, nor would Employee otherwise be entitled to receive.
 
3.   Effective Date .  Provided that it has not been revoked pursuant to Section 6 hereof, this Release will become effective on the eighth (8th) day after the date of its execution by Employee (the "Effective Date").
 
22
4.   Effect of Revocation .  Employee acknowledges and agrees that if Employee revokes this Release pursuant to Section 6 hereof, Employee will have no right to receive the Benefits.
 
5.   General Release .  In consideration of the Company’s obligations, Employee hereby releases, acquits and forever discharges Company and each of its subsidiaries and affiliates and each of their respective officers, employees, directors, successors and assigns from any and all claims, actions or causes of action in any way related to his employment with the Company or the termination thereof, whether arising from tort, statute or contract, including but not limited to, claims of defamation, claims arising under the Employee Retirement Income Security Act of 1974, as amended, the Age Discrimination in Employment Act of 1967, as amended by the Older Workers Benefit Protection Act of 1990, Title VII of the Civil Rights Act of 1964, as amended, the Americans with Disabilities Act, the Family and Medical Leave Act, the discrimination and wage payment laws of Colorado and any other federal, state or local statutes or ordinances of the United States, it being Employee’s intention and the intention of the Company to make this release as broad and as general as the law permits.  Employee understands that this Agreement does not waive any rights or claims that may arise after his execution of it and does not apply to claims arising under the terms of this Agreement.
 
6.   Review and Revocation Period .  Employee acknowledges that the Company has advised Employee that Employee may consult with an attorney of Employee’s own choosing (and at Employee’s expense) prior to signing this Release and that Employee has been given at least twenty-one (21) days during which to consider the provisions of this Release, although Employee may sign and return it sooner. Employee further acknowledges that Employee has been advised by the Company that after executing this Release, Employee will have seven (7) days to revoke this Release, and that this Release shall not become effective or enforceable until such seven (7) day revocation period has expired.  Employee acknowledges and agrees that if Employee wishes to revoke this Release, Employee must do so in writing, and that such revocation must be signed by Employee and received by the Chairman of the Board of the Company (or the Chairman of the Compensation Committee) no later than 5:00 p.m. Eastern Time on the seventh (7th) day after Employee has executed this Release. Employee acknowledges and agrees that, in the event that Employee revokes this Release, Employee will have no right to receive any benefits hereunder, including the Benefits. Employee represents that Employee has read this Release and understands its terms and enters into this Release freely, voluntarily and without coercion.
 
7.   Confidentiality, Non-Compete and Non-Solicitation .  Employee reaffirms his commitments in Sections 6.a., 6.c. and 6.d. of the Agreement.
 
8.   Cooperation in Litigation .  At the Company's reasonable request, Employee shall use his good faith efforts to cooperate with the Company, its Affiliates, and each of its and their respective attorneys or other legal representatives ("Attorneys") in connection with any claim, litigation or judicial or arbitral proceeding which is material to the Company and is now pending or may hereinafter be brought against the Released Parties by any third party; provided, that, Employee’s cooperation is essential to the Company's case.  Employee’s duty of cooperation will include, but not be limited to (a) meeting with the Company's and/or its Affiliates' Attorneys by telephone or in person at mutually convenient times and places in order to state truthfully Employee’s knowledge of matters at issue and recollection of events; (b) appearing at the Company's, its Affiliates' and/or their Attorneys' request (and, to the extent possible, at a time convenient to Employee that does not conflict with the needs or requirements of Employee’s then-current employer) as a witness at depositions or trials, without necessity of a subpoena, in order
 
 
23
to state truthfully Employee’s knowledge of matters at issue; and (c) signing at the Company's, its Affiliates' and/or their Attorneys' request declarations or affidavits that truthfully state matters of which Employee has knowledge.  The Company shall reimburse Employee for the reasonable expenses incurred by him in the course of his cooperation hereunder and shall pay to Employee per diem compensation in an amount equal to the daily prorated portion of the Employee’s base salary immediately prior to the Termination Date.  The obligations set forth in this Section 8 shall survive any termination or revocation of this Release.
 
9.   Non-Admission of Liability .  Nothing in this Release will be construed as an admission of liability by Employee or the Released Parties; rather, Employee and the Released Parties are resolving all matters arising out of the employer-employee relationship between Employee and the Company and all other relationships between Employee and the Released Parties.
 
10.   Binding Effect .  This Release will be binding upon the Parties and their respective heirs, administrators, representatives, executors, successors and assigns, and will inure to the benefit of the Parties and their respective heirs, administrators, representatives, executors, successors and assigns.
 
11.   Governing Law .  This Release will be governed by and construed and enforced in accordance with the laws of the Commonwealth of Pennsylvania applicable to agreements negotiated, entered into and wholly to be performed therein.
 
12.   Severability .  Each of the respective rights and obligations of the Parties hereunder will be deemed independent and may be enforced independently irrespective of any of the other rights and obligations set forth herein.  If any provision of this Release should be held illegal or invalid, such illegality or invalidity will not affect in any way other provisions hereof, all of which will continue, nevertheless, in full force and effect.
 
13.   Counterparts .  This Release may be signed in counterparts and each counterpart will be deemed to be an original but together all such counterparts will be deemed a single agreement.
 
14.   Entire Agreement; Modification .  This Release constitutes the entire understanding between the Parties with respect to the subject matter hereof and may not be modified without the express written consent of both Parties.  This Release supersedes all prior written and/or oral and all contemporaneous oral agreements, understandings and negotiations regarding its subject matter.  This Release may not be modified or canceled in any manner except by a writing signed by both Parties.
 
15.   Acceptance .  Employee may confirm his acceptance of the terms and conditions of this Release by signing and returning two (2) original copies of this Release to the
 
24
 
Chairman of the Board of the Company, no later than 5:00 p.m. Eastern Time twenty-one (21) days after Employee’s receipt of notice of termination.
 
EMPLOYEE ACKNOWLEDGES AND REPRESENTS THAT EMPLOYEE HAS FULLY AND CAREFULLY READ THIS RELEASE PRIOR TO SIGNING IT AND UNDERSTANDS ITS TERMS. EMPLOYEE FURTHER ACKNOWLEDGES AND AGREES THAT EMPLOYEE HAS BEEN, OR HAS HAD THE OPPORTUNITY TO BE, ADVISED BY INDEPENDENT LEGAL COUNSEL OF EMPLOYEE’S OWN CHOICE AS TO THE LEGAL EFFECT AND MEANING OF EACH OF THE TERMS AND CONDITIONS OF THIS RELEASE, AND IS ENTERING INTO THIS RELEASE FREELY AND VOLUNTARILY AND NOT IN RELIANCE ON ANY PROMISES OR REPRESENTATIONS OTHER THAN AS SET FORTH IN THIS RELEASE.
 
IN WITNESS WHEREOF, the Company and the Employee have duly executed this Release as of the date first above written.
 
         
 
Petroleum Development Corporation
   
[Full Name]
         
         
         
By:
       
 
[Full Name]
     
Position:
Chair of the
     
 
Compensation Committee
     
 
 
25
Exhibit 10.13
 
Employment Agreement
 
This Employment Agreement (the “Agreement”) is made and entered into this 31st day of December, 2008, effective as of January 1, 2008, by and between Petroleum Development Corporation, a Nevada Corporation (the “Company”), and Daniel W. Amidon (the “Employee”).
 
WHEREAS, on July 2, 2007, the Company employed Employee in the capacity of General Counsel and Corporate Secretary;
 
WHEREAS, the Company desires to employ the Employee to perform the duties and services incident to such position for the Company, and the Employee wishes to be so employed by the Company, all upon the terms and conditions set forth in this Agreement;
 
NOW THEREFORE, in consideration of the premises and mutual covenants and obligations set forth herein and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged and accepted, the parties hereto, intending to be legally bound, agree as follows:
 
1.  
Effective Date and Term
 
a.  
Initial Term.   The effective date of this Agreement will be January 1, 2008 (the “Effective Date”), and the initial term will be for the period beginning on the Effective Date and ending December 31, 2009.
 
b.  
Automatic Extensions.   The Term of this Agreement will be extended for an additional twelve (12) months beginning on December 31, 2008 and on each successive December 31 unless either party provides the other with at least thirty (30) days prior written notice, or unless the contract has been terminated by the parties in accordance with the provisions of Section 7 of this Agreement.  The period of time from the Effective Date until the Termination Date, as defined in Section 7.b., will be the “Term.”
 
c.  
Change of Control.   In the event of a Change of Control, the Term of this Agreement will automatically be extended to the date that is twenty-four (24) months after the date of the Change of Control without any action on the part of the Company or the Employee.  Thereafter, the date of the Change of Control will be treated as the Effective Date for purposes of further automatic 12-month extensions of the Agreement under this section.  "Change of Control" of the Company will occur on the earliest of the following events:
 
(i)  
Change in Ownership : A change in ownership of the Company occurs on the date that any one person, or more than one person acting as a group, acquires ownership of stock of the Company that, together with stock held by such person or group, constitutes more than 50% of the total fair market value or total voting power of the stock of the Company, excluding the acquisition of additional stock by a person or more than one person acting as a
 
 
 
group who is considered to own more than 50% of the total fair market value or total voting power of the stock of the Company.
 
(ii)  
Change in Effective Control : A change in effective control of the Company occurs on the date that either:
 
(A)  
Any one person, or more than one person acting as a group, acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such person or persons) ownership of stock of the Company possessing 30% or more of the total voting power of the stock of the Company; or
 
(B)  
A majority of the members of the Board of Directors of the Company (the “Board”) is replaced during any 12-month period by directors whose appointment or election is not endorsed by a majority of the members of the board of directors before the date of the appointment or election; provided, that this paragraph (B) will apply only to the Company if no other corporation is a majority shareholder.
 
(iii)  
Change in Ownership of Substantial Assets : A change in the ownership of a substantial portion of the Company's assets occurs on the date that any one person, or more than one person acting as a group, acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such person or persons) assets from the Company that have a total gross fair market value equal to or more than 40% of the total gross fair market value of the assets of the Company immediately before such acquisition or acquisitions. For this purpose, “gross fair market value” means the value of the assets of the Company, or the value of the assets being disposed of, determined without regard to any liabilities associated with such assets.
 
It is the intent that this definition be construed consistent with the definition of “Change of Control” as defined under Internal Revenue Code Section 409A and the applicable Treasury Regulations, as amended from time to time.
 
2.  
Place of Employment
 
The place of employment will be the Company’s headquarters building in Bridgeport, West Virginia or Denver, Colorado unless the Employee and the Company agree to an alternative location.
 
3.  
Position and Responsibilities
 
a.  
Position.   The Employee will serve as the General Counsel and Corporate Secretary and shall report to the Chief Executive Officer or President of
 
 
 
 
the Company (“Chief Executive Officer”) and be under the general direction and control of the Chief Executive Officer or President.
 
 
b.  
Responsibilities.   The Employee will have obligations, duties, authority and power to do such acts as are customarily done by a person holding the same or equivalent position in corporations of similar size to the Company. The Employee shall perform such managerial duties and responsibilities for the Company as may be reasonably be assigned to him by the Chief Executive Officer or President and, at no additional compensation, shall serve on the Board and in other such positions with any subsidiary corporation of the Company, or any partnership, limited liability company or other entity in which the Company has an interest (herein collectively called “Affiliates”), as the Chief Executive Officer or President may from time to time determine.
 
c.  
Dedication of Professional Services.   The Employee shall devote substantially all of his business time, best efforts and attention to promote and advance the business of the Company and its Affiliates to perform diligently and faithfully all the duties, responsibilities and obligations of his position with the Company. Employee shall not be employed in any other business activity, other than with the Company and its Affiliates, during the Term, whether or not such activity is pursued for gain, profit or other pecuniary advantage without approval by the Compensation Committee of the Board (“Compensation Committee”); provided, however, that this restriction will not be construed as preventing Employee from investing his or her personal assets in a business which does not compete with the Company or its Affiliates, where the form or manner of such investment will not require services of any significance on the part of Employee in the operation of the affairs of the business in which such investment is made and in which his participation is solely that of a passive investor.
 
d.  
Adherence to Standards.   Employee shall comply with the written policies, standards, rules and regulations of the Company from time to time established for all officers of the Company consistent with Employee's position and level of authority.
 
e.  
Minimum Stock Ownership.   Employee shall make a good faith effort to comply with the minimum stock ownership requirements for executive officers of the Company (other than the Chief Executive Officer), such requirement being that by the fifth anniversary of the Effective Date and until his Termination Date, Employee shall have a minimum stock ownership equal to two (2) times the Employee’s Base Salary, as defined in Section 4.a.
 
 
 
4.  
Compensation
 
a.  
Base Salary.   The Company shall pay the Employee an annual base salary of $227,500 (the “Base Salary”) commencing on the Effective Date and ending on the Termination Date.  The Base Salary will be payable in accordance with the ordinary payroll practices of the Company.  The Compensation Committee shall review the Base Salary annually, and the Base Salary may be changed by the Compensation Committee in its sole discretion, taking into account the base salaries, aggregate annual cash compensation, and other compensation of individuals holding similar positions at other comparable companies and the performance of the Employee and the Company.
 
b.  
Performance Bonus.   In addition to his Base Salary, the Employee will be eligible to earn an annual performance bonus (the “Bonus”) during the Term based on the achievement of corporate performance objectives as determined by the Compensation Committee in its sole discretion each year, to be paid by March 15 of the following year.  The “Target Bonus” will be a specified percentage of the Base Salary, as set forth in the Petroleum Development Corporation Short-Term Incentive Compensation Plan for a given year which may be earned if the Employee meets all of the criteria established by the Compensation Committee.  However, the Bonus may be less than or more than the Target Bonus based on the level of performance of the Employee and the criteria established by, and at the sole discretion of, the Compensation Committee.  For 2008, the Target Bonus shall be equal to 50% of the Employee’s Base Salary and the maximum percentage will be 100% of the Employee’s Base Salary.  The Bonus will be paid in cash no later than March 15 of the following year.  To the extent practicable, the Bonus will meet the requirements for qualified performance-based compensation under Internal Revenue Code Section 162(m).
 
c.  
Equity Compensation Grant.   In addition to cash compensation, the Employee will be eligible to earn equity compensation during the Term.  The amounts and form of all equity compensation awards shall be determined at the sole discretion of the Board or its designee and only in accordance with shareholder approved stock compensation plans.  As of the Effective Date, under the Company’s Long-Term Equity Compensation Plan, the Employee will receive an award equal in value to $227,500, 50% of which will be awarded as restricted stock and 50% of which will be awarded as long-term incentive performance (“LTIP”) shares.  For this purpose, the value of the restricted stock and the LTIP shares will be determined by the Company’s compensation consultants and will be based on the average closing price of the stock of the Company for the month of December, 2007.  The restricted stock will vest at the rate of 25% for each complete year worked by the Employee, beginning on March 7, 2008 and on each anniversary thereof.  The
 
 
 
 
performance shares will vest in accordance with the timing and performance targets set forth in the documentation for such LTIP shares.  Future awards will vest on the schedule specified by the Board or its designee at the time of the award
 
d.  
Succession-Related Grant .  The Employee will receive a one-time award of restricted stock equal in value to $250,000.  For this purpose, the value of the restricted stock will be determined by the Company’s compensation consultants and will be based on the average closing price of the stock of the Company for the month of December, 2007.  The restricted stock will vest at the rate of 20% for each complete year worked by the Employee under this Agreement, beginning from the Effective Date.
 
e.  
Other Compensation.   The Employee will continue to be eligible to participate in all other cash or stock compensation plans or programs maintained by the Company, as in effect from time to time, in which other senior officers of the Company are allowed to participate.
 
f.  
Recoupment of Certain Compensation.   If the Company has to restate all or a portion of its financial statements due to the material noncompliance of the Company with any financial reporting requirement under the securities laws, the Employee shall, for the affected years, reimburse the Company for any excess bonus paid to the Employee pursuant to Section 4.b.  The reimbursements shall be equal to the difference between the bonus paid to him for the affected years and the bonus that would have been paid to the Employee had the financial results been properly reported.  Such reimbursement shall be paid to the Company within ninety days after the Company notifies the Employee of the amount owed to the Company.
 
5.  
Employee Benefits
 
a.  
Participation in Company Benefit Plans.   During the Term, the Company shall provide the Employee with coverage under all employee pension and welfare benefit programs, plans and practices commensurate with his positions in the Company and to the extent permitted under the respective employee benefit plan.
 
b.  
Vacation.   The Employee will be entitled to twenty (20) days of paid vacation in each calendar year, to be taken at such times as is reasonably determined by the Employee to be consistent with the Employee’s responsibilities under this Agreement.
 
c.  
Expense Reimbursement .  The Employee is authorized to incur reasonable expenses in carrying out his duties and responsibilities under this Agreement, including, without limitation, expenses related to travel, meals, entertaining, professional development and certification
 
 
 
 
requirements, health club membership and similar items related to such duties and responsibilities.  The Company shall reimburse the Employee for all such expenses on presentation by Employee from time to time of appropriately itemized and approved (consistent with the Company’s policy) accounts of such expenditures.  The Company shall reimburse the Employee for reasonable dues and expenses of membership in such club or clubs as the Board reasonably deems necessary for the Employee to entertain on behalf of the Company and for costs associated with continuing education and professional dues if approved in advance by the Chief Executive Officer.  All expense reimbursements for a calendar year will be paid in the normal course, but no later than March 15 of the following calendar year.
 
 
 
d.  
Life and Disability Insurance.   The Company will reimburse the Employee for the cost of life insurance on the Employee in the face amount of one million dollars ($1,000,000) with a person or persons named by the Employee as either the owner or the beneficiary as the Employee directs, and for the cost of a disability policy consistent with what is provided to other officers of the Company.  All reimbursements for a calendar year will be paid in the normal course, but no later than March 15 of the following calendar year.
 
e.  
Health Insurance.   The Company agrees that it will include the Employee under any hospital, surgical, or group health plan or policy adopted generally for the benefit of its employees.  The payment of the premiums for the Employee and his dependents will be determined in accordance with the rules and regulations adopted by the Company for its employees.  In addition to including the Employee and his dependents in such plan, the Company shall pay all reasonable hospital, surgical, medical, dental, and prescription expenses of the Employee and his dependents not covered by such a plan.  In the event the Company has no group health plan, the Company agrees to pay all reasonable premiums on any health insurance policy obtained by the Employee to provide such coverage.
 
f.  
Automobile .  During the Term, the Employee will be entitled to use of a Company automobile or payment of a car allowance in accordance with a plan approved by the Board or its designee.
 
6.  
Confidential Material and Employee Obligations.
 
a.  
Confidential Material.   The Employee shall not, directly or indirectly, either during the Term or thereafter, disclose to anyone (except in the regular course of the Company's business or as required by law), or use in any manner, any information acquired by the Employee during his employment by the Company with respect to any clients or customers of the Company or any confidential, proprietary or secret aspect of the Company's operations or affairs unless such information has become
 
 
 
public knowledge other than by reason of actions, direct or indirect, of the Employee. Information subject to the provisions of this paragraph will include, without limitation:
 
 
(i)  
Brokers, broker/dealer firms, law firms used to prepare Company and partnership registration statements, due diligence investigations, or other parties involved with the registration, review, or offering of the Company’s securities and drilling programs;
 
(ii)  
Names, addresses, and other information regarding investors in the Company’s drilling programs;
 
(iii)  
Names, addresses and other information regarding investors who participate with the Company in the drilling, completion or operation of oil and gas wells as joint venture partners, working interest owners, or in any other form of ownership;
 
(iv)  
Lists of or information about personnel seeking employment with or who are currently employed by the Company;
 
(v)  
Maps, logs, drilling reports and any other information regarding past, planned or possible future leasing, drilling, acquisition, or other operations that the Company has completed or is investigating or has investigated for possible inclusion in future activities;
 
(vi)  
Any other information or contacts relating to the Company's drilling, development, fund-raising, purchasing, engineering, marketing, merchandising, and selling activities.
 
b.  
Return of Confidential Material.   All maps, logs, data, drawings and other records and written and digital material prepared or compiled by the Employee or furnished to the Employee during the Term will be the sole and exclusive property of the Company and none of such material may be retained by the Employee upon termination of his employment.  The aforementioned materials include materials on the Employee’s personal computer.  Employee shall return to the Company or destroy all such materials on or prior to the Termination Date.  Notwithstanding the foregoing, the Employee will be under no obligation to return or destroy public information.
 
c.  
Non-Compete .  The Employee shall not directly, either during the Term or for a period of one (1) year thereafter, engage in any Competitive Business in West Virginia, Pennsylvania, Colorado, Utah, Wyoming, North Dakota, Michigan, Ohio, Kentucky, Texas and Tennessee; provided, however, that the ownership of less than five percent (5%) of the outstanding capital stock of a corporation whose shares are traded on a national securities
 
 
 
 
exchange or on the over-the-counter market shall not be deemed engaging any Competitive Business.  "Competitive Business" shall mean the oil and natural gas industry, including oil and gas leasing, drilling, and other operations, syndication and marketing of partnership or other investments related to oil and natural gas operations, or any other business activities that are the same as or similar to the Company’s business operations as its business exists on the Effective Date or on the Termination Date.
 
d.  
No Solicitation .  The Employee shall not, directly or indirectly, either during the Term or for a period of one (1) year thereafter (i) solicit, directly or indirectly, the services of any person who was a full-time employee of the Company, its subsidiaries, divisions, or affiliates, or otherwise induce such employee to terminate or reduce employment, or (ii) solicit the business of any person who was a client or customer of the Company, its subsidiaries, divisions, or affiliates, in each case at any time during the last year of the Term. For purposes of this Agreement, the term "person" includes natural persons, corporations, business trusts, associations, sole proprietorships, unincorporated organizations, partnerships, joint ventures, limited liability companies or partnerships, and governments, or any agencies, instrumentalities, or political subdivisions thereof.
 
e.  
Remedies.   Employee acknowledges and agrees that the Company's remedy at law for a breach or a threatened breach of the provisions herein would be inadequate, and in recognition of this fact, in the event of a breach or threatened breach by Employee of any of the provisions of this Agreement, it is agreed that the Company will be entitled to equitable relief in the form of specific performance, a temporary restraining order, a temporary or permanent injunction or any other equitable remedy which may then be available, without posting bond or other security.  Employee acknowledges that the granting of a temporary injunction, a temporary restraining order or other permanent injunction merely prohibiting Employee from engaging in any business activities would not be an adequate remedy upon breach or threatened breach of this Agreement, and consequently agrees upon any such breach or threatened breach to the granting of injunctive relief prohibiting Employee from engaging in any activities prohibited by this Agreement.  No remedy herein conferred is intended to be exclusive of any other remedy, and each and every such remedy will be cumulative and will be in addition to any other remedy given hereunder now or hereinafter existing at law or in equity or by statute or otherwise.
 
7.  
Termination of the Agreement
 
a.  
Notice of Termination.   Either the Employee or the Board may terminate this Agreement at any time and in his or their sole discretion upon no less than thirty (30) days written Notice of Termination to the other party.  
 
 
 
"Notice of Termination" means a written notice which shall indicate the specified termination provision in this Agreement relied upon (Section 7.c., Section 7.d., Section 7.e., Section 7.f, Section 7.g. or Section 7.h.) and shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of Employee's employment under the provision so indicated; provided, however, no such purported termination will be effective without such Notice of Termination; provided further, however, any purported termination by the Company or by Employee must be communicated by a Notice of Termination to the other party hereto in accordance with Section 9 (“Notices”) of this Agreement.
 
b.  
Termination Date.   The “Termination Date” means the date specified in the Notice of Termination. The Termination Date may not be less than thirty (30) days after the date such Notice of Termination is given.
 
c.  
Termination by the Company for Just Cause.
 
(i)  
The Company may terminate the Employee for “Just Cause” (as defined in Section 7.c.ii), provided that the Company shall:
 
(A)  
Give the Employee Notice of Termination as specified in Section 7.a., and
 
(B)  
Pay the Employee, within thirty (30) days after his Termination Date, his Base Salary through the Termination Date at the rate in effect at the time the Notice of Termination is given plus any Bonus (only for periods completed and accrued, but not paid), incentive, deferred, or other compensation, and provide any other benefits, which have been earned or become payable as of the Termination Date, pursuant to the terms of this or any other agreement, or compensation or benefit plan, but which have not yet been paid or provided.
 
(ii)  
For purposes of this Agreement “Just Cause” means that the Employee:
 
(A)  
Failed to substantially perform his duties with the Company (other than a failure resulting from his incapacity due to physical or mental illness) after a written demand for substantial performance has been delivered to him by the Board, which demand specifically identifies the manner in which the Board believes he has not substantially performed his duties, and the Employee has failed to cure such deficiency within thirty (30) days of the receipt of such notice;
 
 
(B)  
Has engaged in conduct the consequences of which are materially adverse to the Company, monetarily or otherwise;
 
(C)  
Has pleaded guilty to or been convicted of a felony or a crime involving moral turpitude or dishonesty; or
 
(D)  
Has materially breached the terms of this Agreement.
 
(iii)  
(A) 
No act, or failure to act, on the Employee's part shall be grounds for termination with Just Cause unless he has acted or failed to act with an absence of good faith or without a reasonable belief that his action or failure to act was in or at least not opposed to the best interests of the Company.
 
 
(B) 
The Employee will not be deemed to have been terminated with Just Cause under (ii)(B), (C), or (D), unless there will have been delivered to the Employee a letter setting forth the reasons for the Company’s termination of the Employee for Just Cause.
 
d.  
Termination by the Company Without Just Cause.   If the Company terminates this Agreement prior to its expiration (including extensions as provided in Section 1.b.) for any reason other than for Just Cause or the death or Disability (as defined in Section 7.e.) of the Employee, the Company shall:
 
(i)  
Within thirty (30) days after the Termination Date, pay to the Employee a lump sum severance payment equal to three times the sum of: a) the Employee’s highest Base Salary during the previous two years of employment immediately preceding the Termination Date, plus b) the highest Bonus paid or payable to the Employee for a year within the same two year period of employment immediately preceding the Termination Date,
 
(ii)  
Pay to the Employee any unpaid expense reimbursement upon presentation by the Employee of an accounting of such expenses in accordance with normal Company practices, but no later than March 15 of the year following the year of termination,
 
(iii)  
Immediately vest any unvested Company stock options and restricted stock (excluding all LTIP shares which provide otherwise as part of such grant),
 
(iv)  
Pay any deferred income or other benefit payments due under this or any other agreements or plans, provided such payments shall be made under the schedule originally contemplated in the agreement under which they were granted,
 
 
 
(v)  
Make any other payments or provide any benefits earned under this or any other employment agreement or plan, including the Company’s Long-Term Incentive Plan, and
 
(vi)  
Continue coverage of the Employee and any dependents covered at the time of termination under the Company’s group health plans at the Company’s cost for a period equal to the lesser of (i) 18 months or (ii) such period as the Employee is eligible to participate in another employer’s health plan.
 
e.  
Termination in the Event of Death or Disability.   This Agreement will be terminated by the Company in the event of the death of Employee and may be terminated by the Company in the event of the Disability (as hereinafter defined) of the Employee upon proper notification to the Employee (or his estate in the event of his death).  The Company shall pay to the Employee (or to the estate of the Employee in the event of termination due to the death of the Employee) the compensation and other benefits described in Section 4.a. of this Agreement which would have been earned for (6) months after the Termination Date and any amounts earned under Section 4.b. of this Agreement prorated for the period up to the Termination Date.  "Disability" means being eligible to receive a disability benefit under the Federal Social Security Act.  All amounts payable under this Section 7.e. will be paid in a lump sum as soon as practicable, but no later than two and one-half (2-1/2) months following the close of the calendar year in which the death or Disability occurred.
 
 
f.
Termination by the Employee for Good Reason .
 
(i)  
If the Employee terminates this Agreement for Good Reason (as defined in Section 7.f.ii.), provided that such Employee’s termination of employment occurs within ninety (90) days of the Good Reason, the Company shall:
 
(A)  
Within thirty (30) days after the Termination Date, pay to the Employee a lump sum severance payment equal to three times the sum of: a) the Employee’s highest Base Salary during the previous two years of employment immediately preceding the Termination Date, plus b) the highest Bonus paid or payable to the Employee for a year within the same two year period of employment immediately preceding the Termination Date,
 
(B)  
Pay to the Employee any unpaid expense reimbursement upon presentation by the Employee of an accounting of such expenses in accordance with normal Company practices, but no later than March 15 of the year following the year of termination,
 
 
 
(C)  
Immediately vest any unvested Company stock options and restricted stock (excluding all LTIP shares which provide otherwise as part of such grant),
 
(D)  
Pay any deferred income or other benefit payments due under this or any other agreements or plans, provided such payments shall be made under the schedule originally contemplated in the agreement under which they were granted,
 
(E)  
Make any other payments or provide any benefits earned under this or any other employment agreement or plan, including the Company’s Long-Term Incentive Plan, and
 
(F)  
Continue coverage of the Employee and any dependents covered at the time of termination under the Company’s group health plans at the Company’s cost for a period equal to the lesser of (i) 18 months or (ii) such period as the Employee is eligible to participate in another employer’s health plan.
 
(ii)  
"Good Reason" means the occurrence of any of the following events without Employee's prior express written consent:
 
(A)  
A material diminution in the Employee’s Base Salary;
 
(B)  
A material diminution in the Employee’s authority, duties or responsibilities;
 
(C)  
A material diminution in the authority, duties or responsibilities of the supervisor to whom the Employee is required to report, including a requirement that the Employee report to a corporate officer or employee instead of reporting directly to the Board;
 
(D)  
A material diminution in the budget over which the Employee retains authority;
 
(E)  
A material diminution in reward opportunities under the annual Performance Bonus of Section 4.b. of this Agreement;
 
(F)  
A material change in the geographic location at which the Employee must perform the services; or
 
(G)  
Any other action or inaction that constitutes a material breach by the Company of this Agreement.
 
 
 
Employee must provide notice to the Company of the condition described in paragraphs (A)-(G) of this section within ninety (90) days, upon the notice of which the Company will have a period of thirty (30) days during which it may remedy the condition and not be required to pay the amount.
 
g.  
Termination by the Employee for other than Good Reason .  The Employee may terminate this Agreement for other than Good Reason upon proper notification as provided in Section 7.a.  In such event the Company shall pay to the Employee:
 
(i)  
Within thirty (30) days after his Termination Date, in a lump sum, the compensation provided in Section 4 at the rate in effect at the time the Notice of Termination. The Base Salary and Bonus will be prorated for the portion of the year that the Employee is employed by the Company; provided, however, that if the Employee’s termination occurs prior to March 31 of the year the Employee will not be entitled to a prorated Bonus for the year;
 
(ii)  
Any incentive, deferred or other compensation which has been earned or has become payable pursuant to the terms of this or any other agreement or compensation or benefit plan as of the Termination Date, but which has not yet been paid, provided such payments will be made under the schedule originally contemplated in the agreement under which they were granted;
 
(iii)  
Any unpaid expense reimbursement upon presentation by the Employee of an accounting of such expenses in accordance with normal Company practices, but not later than March 15 of the year following the year of termination; and
 
(iv)  
Any other payments for benefits earned under this or any other employment agreement or plan.
 
h.  
Termination by the Employee following Change of Control .
 
(i)  
If the Employee terminates this Agreement within two years following a Change of Control of the Company (as defined in Section 1.c.) the Company shall:
 
(A)  
Within thirty (30) days after the Termination Date, pay to the Employee a lump sum severance payment equal to three times the sum of: a) the Employee's highest Base Salary during the previous two years of employment immediately preceding the Termination Date, plus b) the highest Bonus paid or payable to the Employee for a year within the same two year period of employment immediately preceding the Termination Date,
 
 
(B)  
Pay to the Employee any unpaid reimbursement upon presentation by the Employee of an accounting of such expenses in accordance with normal Company practices, but not later than March 15 of the year following the year of termination,
 
(C)  
Immediately vest any unvested Company stock options and restricted stock (excluding all LTIP shares which provide otherwise as part of such grant),
 
(D)  
Pay any deferred income or retirement payment or other benefit payments due under this or any other agreements or plans, provided such payments will be made under the schedule originally contemplated in the agreement under which they were granted,
 
(E)  
Make any other payments or provide any benefits earned under this or any other employment agreement or plan, including the Company’s Long-Term Incentive Plan, and
 
(F)  
Continue coverage of the Employee under the Company’s group health plans at the Company’s cost for a period equal to the lesser of (i) 18 months or (ii) such period as the Employee is receiving COBRA health continuation coverage from the Company.
 
i.  
No Obligation to Mitigate.   Employee shall not be required to seek other employment or income to reduce any amounts payable to the Employee by the Company under this Section.  Further, the amount of any payment or benefit provided for by this Section shall not be reduced by any compensation earned by the Employee, with the exception of COBRA payments as covered in section 7.h(i.)(F) as the result of employment by another employer, retirement benefits, by offset against any amount claimed to be owed by the Employee to the Company, or otherwise.
 
j.  
Code Section 409A Compliance.   Except with respect to amounts paid pursuant to a schedule in a plan or arrangement outside of this Employment Agreement, it is intended that amounts payable under this Section 7 not be considered non-qualified deferred compensation subject to Internal Revenue Code Section 409A.  Employee is a Specified Employee under Internal Revenue Code Section 409A, therefore, to the extent such amounts are considered non-qualified deferred compensation payable upon a separation from service under Internal Revenue Code Section 409A, payment of those amounts so deferred under Internal Revenue Code Section 409A may not be made until at least six (6) months following the Employee’s separation from service of the Company (or, if earlier, the date of death of Employee).
 
 
 
8.  
Life Insurance .  The Company may, at any time after the execution of this Agreement, maintain any outstanding life insurance policies and apply for and procure as owner and for its own benefit new life insurance on Employee, in such amounts and in such form or forms as the Company may determine.  Employee shall, at the request of the Company, submit to such medical examinations, supply such information, and execute such documents as may be required by the insurance company or companies to whom the Company has applied for such insurance.  Employee hereby represents that to his knowledge he is in excellent physical and mental condition.
 
9.  
Notices .  For the purposes of this Agreement, notices and all other communications provided for in the Agreement shall be in writing and will be deemed to have been duly given when personally delivered, by facsimile transmission or sent by certified mail, return receipt requested, postage prepaid, or by expedited  (overnight) courier with established national reputation, shipping prepaid or billed to sender, in either case addressed to the respective addresses last given by each party to the other  (provided that all notices to the Company must be directed to the attention of the Chief Executive Officer of the Company ) or to such other address as either party may have furnished to the other in writing in accordance herewith.  All notices and communication shall be deemed to have been received on the date of delivery thereof, or on the second day after deposit thereof with an expedited courier service, except that notice of change of address shall be effective only upon receipt.
 
 
Company at:
 
Petroleum Development Corporation
     
120 Genesis Boulevard
     
P.O. Box 26
     
Bridgeport WV 26330
       
 
Employee at:
 
Daniel W. Amidon
     
29 Terraceview Avenue
     
Pittsburgh, PA  15243
 
10.  
Successors. This Agreement will be binding on the Company and any successor to any of its businesses or assets.  Without limiting the effect of the prior sentence, the Company shall use its best efforts to require any successor or assign (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company to expressly assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession or assignment had taken place. As used in this Agreement, "Company" means the Company as hereinbefore defined and any successor or assign to its business and/or assets as aforesaid which assumes and agrees to perform this Agreement or which is otherwise obligated under this Agreement by the first sentence of this Section, entitled Successors, by operation of law or otherwise.
 
 
 
11.  
Binding Effect.   This Agreement will inure to the benefit of and be enforceable by Employee's personal and legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees.  If Employee should die while any amounts would still be payable to him hereunder if he had continued to live, all such amounts, unless otherwise provided herein, will be paid in accordance with the terms of this Agreement to Employee's estate.
 
12.  
Integration, Modification and Waiver.   This Agreement constitutes the sole employment agreement between the parties, and any prior employment agreement, written or oral, is terminated, except for specific equity grant agreements.  No provision of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing and signed by Employee and such officer of the Company as may be specifically designated by the Board.  No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with, any condition or provision of this Agreement to be performed by such other party will be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time.
 
13.  
Headings.   Headings used in this Agreement are for convenience only and will not be used to interpret or construe its provisions.
 
14.  
Waiver of Breach.   The waiver of either the Company or Employee of a breach of any provision of this Agreement will not operate or be construed as a waiver of any subsequent breach by either the Company or Employee.
 
15.  
Amendments.   No amendments or variations of the terms and conditions of this Agreement will be valid unless the same is in writing and signed by all of the parties hereto.
 
16.  
Survival of Obligations.   The provisions of Section 6 of this Agreement will continue to be binding upon the Employee and Company in accordance with their terms, notwithstanding the termination of the Employee’s employment with the Company for any reason or the expiration of this Agreement.
 
17.  
Severability.   The invalidity or unenforceability of any provision of this Agreement, whether in whole or in part, shall not in any way affect the validity and/or enforceability of any other provision contained herein.  Any invalid or unenforceable provision shall be deemed severable to the extent of any such invalidity or unenforceability.  It is expressly understood and agreed that while the Company and Employee consider the restrictions contained in this Agreement reasonable for the purpose of preserving for the Company the good will, other proprietary rights and intangible business value of the Company, if a final judicial determination is made by a court having jurisdiction that the time or territory or any other restriction contained in this Agreement is an unreasonable or otherwise unenforceable restriction against Employee, the provisions of such clause will not be rendered void but will be deemed amended to apply as to maximum time and
 
 
 
territory and to such other extent as such court may judicially determine or indicate to be reasonable.
 
18.  
Governing Law.   This Agreement will be construed and enforced pursuant to the laws of the State of West Virginia without giving effect to its conflict of laws.
 
19.  
Arbitration.   Any controversy or claim arising out of or relating to this Agreement or any transactions provided for herein, or the breach thereof, other than a claim for injunctive relief, will be settled by arbitration in accordance with the commercial Arbitration Rules of the American Arbitration Association (the "Rules") in effect at the time demand for arbitration is made by any party.  The evidentiary and procedural rules in such proceedings will be kept to the minimum level of formality that is consistent with the Rules. The Company shall name one arbitrator, Employee shall name a second and the two arbitrators so chosen shall name a neutral, third arbitrator, who will serve as the sole arbitrator of the controversy or claim.  The third arbitrator must be experienced in the matters in dispute.  If the third and sole arbitrator is not agreed upon, the American Arbitration Association will name him or her.  Arbitration will occur in Bridgeport, West Virginia, or such other location agreed to by the Company and Employee.  The award made by the third arbitrator will be final and binding, and judgment may be entered in any court of law having competent jurisdiction. The award is subject to confirmation, modification, correction, or vacation only as explicitly provided in Title 9 of the United States Code.  The prevailing party will be entitled to an award of pre- and post-award interest as well as reasonable attorneys' fees incurred in connection with the arbitration and any judicial proceedings related thereto.
 
20.  
Executive Officer Status.   Employee acknowledges that he may be deemed to be an "executive officer" of the Company for purposes of the Securities Act of 1933, as amended (the "1933 Act"), and the Securities Exchange Act of 1934, as amended (the "1934 Act") and, if so, he shall comply in all respects with all the rules and regulations under the 1933 Act and the 1934 Act applicable to him in a timely and non-delinquent manner. In order to assist the Company in complying with its obligations under the 1933 Act and 1934 Act, Employee shall provide to the Company such information about Employee as the Company shall reasonably request including, but not limited to, information relating to personal history and stockholdings.  Employee shall immediately report to the Chief Executive Officer of the Company or other designated officer of the Company all changes in beneficial ownership of any shares of the Company Common Stock deemed to be beneficially owned by Employee and/or any members of Employee's immediate family.
 
21.  
Pronouns.   All pronouns and any variations thereof will be deemed to refer to the masculine, feminine, neuter, singular, or plural, as the identity of the person or entity may require. As used in this Agreement: (1) words of the masculine gender shall mean and include corresponding neuter words or words of the feminine gender, (2) words in the singular shall mean and include the plural and vice versa,
 
 
 
and (3) the word "may" gives sole discretion without any obligation to take any action.
 
 
22.  
Counterparts.    This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original, but all of which together will constitute but one document.
 
23.  
Exhibits.   Any Exhibits attached hereto are incorporated herein by reference and are an integral part of this Agreement.
 
IN WITNESS WHEREOF, the Company and the Employee have duly executed this Employment Agreement as of the date first above written.
 
           
 
 Company
Petroleum Development Corporation
   
Employee
           
           
           
 
By:
/s/ Kimberly Wakim 
   
/s/ Daniel W. Amidon
   
Kimberly Wakim
   
Daniel W. Amidon
 
Position:
Chair of the
     
   
Compensation Committee
     
 
 
 Exhibit 10.14
\
Employment Agreement

This Employment Agreement (the “Agreement”) is made and entered into this 31st day of December, 2008, effective as of January 1, 2008, by and between Petroleum Development Corporation, a Nevada Corporation (the “Company”), and Darwin L. Stump (the “Employee”).
 
WHEREAS, the Company employs the Employee as Chief Accounting Officer to perform the duties and services incident to such position for the Company, and the Employee wishes to be so employed by the Company, all upon the terms and conditions set forth in this Agreement;
 
NOW THEREFORE, in consideration of the premises and mutual covenants and obligations set forth herein and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged and accepted, the parties hereto, intending to be legally bound, agree as follows:
 
1.  
Effective Date and Term
 
a.  
Initial Term .  The effective date of this Agreement will be January 1, 2008 (the “Effective Date”), and the initial term will be for the period beginning on the Effective Date and ending December 31, 2009.
 
b.  
Automatic Extensions .  The Term of this Agreement will be extended for an additional twelve (12) months beginning on December 31, 2008 and on each successive December 31 unless either party provides the other with at least thirty (30) days prior written notice, or unless the contract has been terminated by the parties in accordance with the provisions of Section 7 of this Agreement.  The period of time from the Effective Date until the Termination Date, as defined in Section 7.b., will be the “Term.”
 
c.  
Change of Control .  In the event of a Change of Control, the Term of this Agreement will automatically be extended to the date that is twenty-four (24) months after the date of the Change of Control without any action on the part of the Company or the Employee.  Thereafter, the date of the Change of Control will be treated as the Effective Date for purposes of further automatic 12-month extensions of the Agreement under this section.  "Change of Control" of the Company will occur on the earliest of the following events:
 
(i)  
Change in Ownership : A change in ownership of the Company occurs on the date that any one person, or more than one person acting as a group, acquires ownership of stock of the Company that, together with stock held by such person or group, constitutes more than 50% of the total fair market value or total voting power of the stock of the Company, excluding the acquisition of additional stock by a person or more than one person acting as a
 
 
1
 
 
group who is considered to own more than 50% of the total fair market value or total voting power of the stock of the Company.
 
(ii)  
Change in Effective Control : A change in effective control of the Company occurs on the date that either:
 
(A)  
Any one person, or more than one person acting as a group, acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such person or persons) ownership of stock of the Company possessing 30% or more of the total voting power of the stock of the Company; or
 
(B)  
A majority of the members of the Board of Directors of the Company (the “Board”) is replaced during any 12-month period by directors whose appointment or election is not endorsed by a majority of the members of the board of directors prior to the date of the appointment or election; provided, that this paragraph (B) will apply only to the Company if no other corporation is a majority shareholder.
 
(iii)  
Change in Ownership of Substantial Assets : A change in the ownership of a substantial portion of the Company's assets occurs on the date that any one person, or more than one person acting as a group, acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such person or persons) assets from the Company that have a total gross fair market value equal to or more than 40% of the total gross fair market value of the assets of the Company immediately prior to such acquisition or acquisitions. For this purpose, “gross fair market value” means the value of the assets of the Company, or the value of the assets being disposed of, determined without regard to any liabilities associated with such assets.
 
It is the intent that this definition be construed consistent with the definition of “Change of Control” as defined under Internal Revenue Code Section 409A and the applicable Treasury Regulations, as amended from time to time.
 
2.  
Place of Employment
 
The place of employment will be the Company’s headquarters building in Bridgeport, West Virginia unless the Employee and the Company agree to an alternative location.
 
3.  
Position and Responsibilities
 
a.  
Position .   The Employee shall serve as the Chief Accounting Officer of the Company and shall report to the Chief Financial Officer of the
 
 
2
 
 
 Company and be under the general direction and control of the Chief Financial Officer of the Company.
 
b.  
Responsibilities .  The Employee will have obligations, duties, authority and power to do such acts as are customarily done by a person holding the same or an equivalent position in corporations of similar size to the Company. The Employee shall perform such managerial duties and responsibilities for the Company as may be reasonably be assigned to him by the Chief Financial Officer of the Company and, at no additional compensation, shall serve on the Board and in other such positions with any subsidiary corporation of the Company, or any partnership, limited liability company or other entity in which the Company has an interest (herein collectively called “Affiliates”), as the Chief Financial Officer of the Company may from time to time determine.
 
c.  
Dedication of Professional Services .  The Employee shall devote substantially all of his business time, best efforts and attention to promote and advance the business of the Company and its Affiliates to perform diligently and faithfully all the duties, responsibilities and obligations of his position with the Company.  Employee shall not be employed in any other business activity, other than with the Company and its Affiliates, during the Term, whether or not such activity is pursued for gain, profit or other pecuniary advantage without approval by the Compensation Committee of the Board; provided, however, that this restriction will not be construed as preventing Employee from investing his or her personal assets in a business which does not compete with the Company or its Affiliates, where the form or manner of such investment will not require services of any significance on the part of Employee in the operation of the affairs of the business in which such investment is made and in which his participation is solely that of a passive investor.
 
d.  
Adherence to Standards .  Employee shall comply with the written policies, standards, rules and regulations of the Company from time to time established for all executive officers of the Company consistent with Employee's position and level of authority.
 
e.  
Minimum Stock Ownership .  Employee shall comply with the minimum stock ownership requirements for executive officers of the Company by March 9, 2009 (the fifth anniversary of the date such minimum stock ownership requirements were adopted by the Board) and until his Termination Date, Employees shall have a minimum stock ownership equal to two (2) times the Employee’s Base Salary, as defined in Section 4.a. (or such level as adjusted from time to time).
 
 
3
 
4.  
Compensation
 
a.  
Base Salary .  The Company shall pay the Employee an annual base salary of $227,500 (the “Base Salary”) commencing on the Effective Date and ending on the Termination Date.  The Base Salary will be payable in accordance with the ordinary payroll practices of the Company.  The Compensation Committee shall review the Base Salary annually, and the Base Salary may be changed by the Compensation Committee in its sole discretion, taking into account the base salaries, aggregate annual cash compensation, and other compensation of individuals holding similar positions at other comparable companies and the performance of the Employee and the Company.
 
b.  
Performance Bonus .  In addition to his Base Salary, the Employee will be eligible to earn an annual performance bonus (the “Bonus”) during the Term as determined by the Compensation Committee in its sole discretion.  The Bonus shall be paid in cash no later than March 15 of the following year.
 
c.  
Retirement Compensation .  Pursuant to prior employment agreements, the Employee, as of the Effective Date has earned a right to ten (10) annual payments of $30,000 (total $300,000).  For each additional complete year of employment with the Company, commencing on January 1, 2008 the Employee will earn and be entitled to receive an annual retirement payment equal to $7,500 (the “Retirement Payment”).  The Retirement Payment will be payable to the Employee, or in the event of the Employee’s death, to his estate, beneficiaries, or designees, on each of the first ten anniversary dates following the date the Employee leaves the service of the Company.  The Retirement Payment will be in addition to any deferred compensation, pension, or other payments the Employee has earned under this and any other previous and subsequent agreements with the Company and any other payments he may be due under the Company’s employee benefit plans.
 
d.  
Equity Compensation Grant .  In addition to cash compensation, the Employee will be eligible to earn equity compensation during the Term.  The amounts and form of all equity compensation awards shall be determined at the sole discretion of the Board or its designee and only in accordance with shareholder approved stock compensation plans.
 
e.  
Other Compensation .  The Employee will continue to be eligible to participate in all other cash or stock compensation plans or programs maintained by the Company, as in effect from time to time, in which other senior executives of the Company are allowed to participate.
 
f.  
Recoupment of Certain Compensation .  If the Company has to restate all or a portion of its financial statements due to the material noncompliance
 
4
 
of the Company with any financial reporting requirement under the securities laws, the Employee shall, for the affected years, reimburse the Company for any excess bonus paid to the Employee pursuant to Section 4.b.  The reimbursements shall be equal to the difference between the bonus paid to him for the affected years and the bonus that would have been paid to the Employee had the financial results been properly reported.  Such reimbursement shall be paid to the Company within ninety days after the Company notifies the Employee of the amount owed to the Company.
 
5.  
Employee Benefits
 
a.  
Participation in Company Benefit Plans .  During the Term, the Company shall provide the Employee with coverage under all employee pension and welfare benefit programs, plans and practices commensurate with his positions in the Company and to the extent permitted under the respective employee benefit plan.
 
b.  
Vacation .  The Employee will be entitled to twenty (20) days of paid vacation in each calendar year, to be taken at such times as is reasonably determined by the Employee to be consistent with the Employee’s responsibilities under this Agreement.
 
c.  
Expense Reimbursement .  The Employee is authorized to incur reasonable expenses in carrying out his duties and responsibilities under this Agreement, including, without limitation, expenses related to travel, meals, entertaining, and similar items related to such duties and responsibilities.  The Company shall reimburse the Employee for all such expenses on presentation by Employee from time to time of appropriately itemized and approved (consistent with the Company’s policy) accounts of such expenditures.  The Company shall reimburse the Employee for reasonable dues and expenses of membership in such club or clubs as the Board reasonably deems necessary for the Employee to entertain on behalf of the Company and for costs associated with continuing education and professional dues if approved in advance by the Chief Financial Officer and Treasurer of the Company.  All expense reimbursements for a calendar year will be paid in the normal course, but no later than March 15 of the following calendar year.
 
d.  
Life and Disability Insurance .  The Company will reimburse the Employee for the cost of life insurance on the Employee in the face amount of one million dollars ($1,000,000) with a person or persons named by the Employee as either the owner or the beneficiary as the Employee directs, and for the cost of the Employee's current disability policy with scheduled adjustments.  All reimbursements for a calendar year will be paid in the normal course, but no later than March 15 of the following calendar year.
 
 
5
 
e.  
Health Insurance .  The Company agrees that it will include the Employee under any hospital, surgical, or group health plan or policy adopted generally for the benefit of its employees.  The payment of the premiums for the Employee and his dependents will be determined in accordance with the rules and regulations adopted by the Company for its employees.  In addition to including the Employee and his dependents in such plan, the Company shall pay all reasonable hospital, surgical, medical, dental, and prescription expenses of the Employee and his dependents not covered by such a plan.  In the event the Company has no group health plan, the Company agrees to pay all reasonable premiums on any health insurance policy obtained by the Employee to provide such coverage.
 
f.  
Automobile .  During the Term, the Employee will be entitled to use of a Company automobile or payment of a car allowance in accordance with a plan approved by the Board or its designee.
 
6.  
Confidential Material and Employee Obligations .
 
a.  
Confidential Material .  The Employee shall not, directly or indirectly, either during the Term or thereafter, disclose to anyone (except in the regular course of the Company's business or as required by law), or use in any manner, any information acquired by the Employee during his employment by the Company with respect to any clients or customers of the Company or any confidential, proprietary or secret aspect of the Company's operations or affairs unless such information has become public knowledge other than by reason of actions, direct or indirect, of the Employee. Information subject to the provisions of this paragraph will include, without limitation:
 
(i)  
Brokers, broker/dealer firms, law firms used to prepare Company and partnership registration statements, due diligence investigations, or other parties involved with the registration, review, or offering of the Company’s securities and drilling programs;
 
(ii)  
Names, addresses, and other information regarding investors in the Company’s drilling programs;
 
(iii)  
Names, addresses and other information regarding investors who participate with the Company in the drilling, completion or operation of oil and gas wells as joint venture partners, working interest owners, or in any other form of ownership;
 
(iv)  
Lists of or information about personnel seeking employment with or who are currently employed by the Company;
 
(v)  
Maps, logs, drilling reports and any other information regarding past, planned or possible future leasing, drilling, acquisition, or
 
6
 
 
other operations that the Company has completed or is investigating or has investigated for possible inclusion in future activities;
 
 
(vi)  
Any other information or contacts relating to the Company's drilling, development, fund-raising, purchasing, engineering, marketing, merchandising, and selling activities.
 
b.  
Return of Confidential Material .  All maps, logs, data, drawings and other records, electronic data and written material prepared or compiled by the Employee or furnished to the Employee during the Term will be the sole and exclusive property of the Company and none of such material may be retained by the Employee upon termination of his employment.  Notwithstanding the foregoing, the Employee will be under no obligation to return public information.
 
c.  
Non-Compete .  The Employee shall not directly, either during the Term or for a period of one (1) year thereafter, engage in any Competitive Business in West Virginia, Pennsylvania, Colorado, Utah, Wyoming, North Dakota, Michigan, Ohio, Kentucky, Texas and Tennessee; provided, however, that the ownership of less than five percent (5%) of the outstanding capital stock of a corporation whose shares are traded on a national securities exchange or on the over-the-counter market shall not be deemed engaging any Competitive Business.  "Competitive Business" shall mean the oil and natural gas industry, including oil and gas leasing, drilling, and other operations, syndication and marketing of partnership or other investments related to oil and natural gas operations, or any other business activities that are the same as or similar to the Company’s business operations as its business exists on the Effective Date or on the Termination Date.
 
d.  
No Solicitation .  The Employee shall not, directly or indirectly, either during the Term or for a period of one (1) year thereafter (i) solicit, directly or indirectly, the services of any person who was a full-time employee of the Company, its subsidiaries, divisions, or affiliates, or otherwise induce such employee to terminate or reduce employment, or (ii) solicit the business of any person who was a client or customer of the Company, its subsidiaries, divisions, or affiliates, in each case at any time during the last year of the Term. For purposes of this Agreement, the term "person" includes natural persons, corporations, business trusts, associations, sole proprietorships, unincorporated organizations, partnerships, joint ventures, limited liability companies or partnerships, and governments, or any agencies, instrumentalities, or political subdivisions thereof.
 
e.  
Remedies .  Employee acknowledges and agrees that the Company's remedy at law for a breach or a threatened breach of the provisions herein would be inadequate, and in recognition of this fact, in the event of a
 
 
7
 
 
breach or threatened breach by Employee of any of the provisions of this Agreement, it is agreed that the Company will be entitled to equitable relief in the form of specific performance, a temporary restraining order, a temporary or permanent injunction or any other equitable remedy which may then be available, without posting bond or other security.  Employee acknowledges that the granting of a temporary injunction, a temporary restraining order or other permanent injunction merely prohibiting Employee from engaging in any business activities would not be an adequate remedy upon breach or threatened breach of this Agreement, and consequently agrees upon any such breach or threatened breach to the granting of injunctive relief prohibiting Employee from engaging in any activities prohibited by this Agreement.  No remedy herein conferred is intended to be exclusive of any other remedy, and each and every such remedy will be cumulative and will be in addition to any other remedy given hereunder now or hereinafter existing at law or in equity or by statute or otherwise.
 
7.  
Termination of the Agreement
 
a.  
Notice of Termination .  Either the Employee or the Board may terminate this Agreement at any time and in his or their sole discretion upon no less than thirty (30) days written Notice of Termination to the other party.  "Notice of Termination" means a written notice which shall indicate the specified termination provision in this Agreement relied upon (Section 7.c., Section 7.d., Section 7.e., Section 7.f, Section 7.g. or Section 7.h.) and shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of Employee's employment under the provision so indicated; provided, however, no such purported termination will be effective without such Notice of Termination; provided further, however, any purported termination by the Company or by Employee will be communicated by a Notice of Termination to the other party hereto in accordance with  Section 9 (“Notices”) of this Agreement.
 
b.  
Termination Date .  The "Termination Date" shall mean the date specified in the Notice of Termination. The Termination Date shall not be less than thirty (30) days from the date such Notice of Termination is given; provided, however, that if within fifteen (15) days after any Notice of Termination is given the party receiving such Notice of Termination notifies the other party that a dispute exists concerning the termination, the Date of Termination shall be the date finally determined by either mutual written agreement of the parties or by the final judgment, order or decree of a court of competent jurisdiction (the time for appeal there from having expired and no appeal having been taken).
 
8
 
c.  
Termination by the Company for Just Cause .
 
(i)  
The Company may terminate the Employee for “Just Cause” (as defined in Section 7.c.ii), provided that the Company shall:
 
(A)  
Give the Employee Notice of Termination as specified in Section 7.a., and
 
(B)  
Pay the Employee, within thirty (30) days after his Termination Date, his Base Salary through the Termination Date at the rate in effect at the time the Notice of Termination is given plus any Bonus (only for periods completed and accrued, but not paid), incentive, deferred, or other compensation, and provide any other benefits, which have been earned or become payable as of the Termination Date, pursuant to the terms of this or any other agreement, or compensation or benefit plan, but which have not yet been paid or provided.
 
(ii)  
For purposes of this Agreement “Just Cause” means a good faith determination of the Board that the Employee:
 
(A)  
Failed to substantially perform his duties with the Company (other than a failure resulting from his incapacity due to physical or mental illness) after a written demand for substantial performance has been delivered to him by the Board, which demand specifically identifies the manner in which the Board believes he has not substantially performed his duties;
 
(B)  
Has engaged in conduct the consequences of which are materially adverse to the Company, monetarily or otherwise; or
 
(C)  
Has pleaded guilty to or been convicted of a felony; or
 
(D)  
Has materially breached the terms of this Agreement.
 
No act, or failure to act, on the Employee's part shall be grounds for termination with Just Cause unless he has acted or failed to act with an absence of good faith or without a reasonable belief that his action or failure to act was in or at least not opposed to the best interests of the Company.  The Employee will not be deemed to have been terminated with Just Cause under (ii)(B), (C) or (D), unless there will have been delivered to the Employee a letter setting forth the reasons for the Company’s termination of the Employee for Just Cause and the Employee has failed to cure such reason for termination within thirty (30) days of the receipt of such notice.
 
 
9
 
d.  
Termination by the Company Without Just Cause .  If the Company terminates this Agreement prior to its expiration (including extensions as provided in Section 1.b.) for any reason other than for Just Cause or the death or Disability (as defined in Section 7.e.) of the Employee, the Company shall:
 
(i)  
Within thirty (30) days of the Termination Date, pay to the Employee a lump sum severance payment equal to three (3) times the sum of: a) the Employee’s highest Base Salary during the previous two years of employment immediately preceding the Termination Date, plus b) the highest Bonus paid to the Employee for a year within the same two year period of employment immediately preceding the Termination Date,
 
(ii)  
Pay to the Employee any unpaid expense reimbursement upon presentation by the Employee of an accounting of such expenses in accordance with normal Company practices, but no later than March 15 of the year following the year of termination,
 
(iii)  
Immediately vest any unvested Company stock options and restricted stock (excluding all LTIP shares),
 
(iv)  
Pay any deferred income or Retirement Compensation (under Section 4.c.) or other benefit payments due under this or any other agreements or plans, provided such payments shall be made under the schedule originally contemplated in the agreement under which they were granted,
 
(v)  
Make any other payments or provide any benefits earned under this or any other employment agreement or plan, including the Company’s Long-Term Incentive Plan, and
 
(vi)  
Continue coverage of the Employee and any dependents covered at the time of termination under the Company’s group health plans at the Company’s cost for a period equal to the lesser of (i) 18 months or (ii) such period as the Employee is eligible to participate in another employer’s health plan.
 
e.  
Termination in the Event of Death or Disability .  This Agreement will be terminated by the Company in the event of the death of Employee and may be terminated by the Company in the event of the Disability (as hereinafter defined) of the Employee upon proper notification to the Employee (or his estate in the event of his death), provided the Company shall pay to the Employee (or to the estate of the Employee in the event of termination due to the death of the Employee) the compensation and other benefits described in Section 4.a. of this Agreement which would have been earned for  (6) months after the Termination Date and any amounts
 
 
10
 
 
earned under Section 4.b. of this Agreement pro-rated for the period up to the Termination Date.  “Disability” means being eligible to receive a disability benefit under the Federal Social Security Act.  All amounts payable under this Section 7.e. will be paid in a lump sum as soon as practicable, but no later than two and one-half (2-1/2) months following the close of the calendar year in which the death or Disability occurred.
 
f.  
Termination by the Employee for Good Reason .
 
(i)  
If the Employee terminates this Agreement for Good Reason (as defined in Section 7.f.ii), provided that such Employee’s termination occurs within two years of the Good Reason, the Company shall:
 
(A)  
Within thirty (30) days of the Termination Date, pay to the Employee a lump sum severance payment equal to three (3) times the sum of: a) the Employee’s highest Base Salary during the previous two years of employment immediately preceding the Termination Date, plus b) the highest Bonus paid to the Employee for a year within the same two year period of employment immediately preceding the Termination Date,
 
(B)  
Pay to the Employee any unpaid expense reimbursement upon presentation by the Employee of an accounting of such expenses in accordance with normal Company practices, but no later than March 15 of the year following the year of termination,
 
(C)  
Immediately vest any unvested Company stock options and restricted stock (excluding all LTIP shares),
 
(D)  
Pay any deferred income or Retirement Compensation (under Section 4.c.) or other benefit payments due under this or any other agreements or plans, provided such payments shall be made under the schedule originally contemplated in the agreement under which they were granted,
 
(E)  
Make any other payments or provide any benefits earned under this or any other employment agreement or plan, including the Company’s Long-Term Incentive Plan, and
 
(F)  
Continue coverage of the Employee and any dependents covered at the time of termination under the Company’s group health plans at the Company’s cost for a period equal to the lesser of (i) 18 months or (ii) such period as the
 
11
 
 
Employee is eligible to participate in another employer’s health plan.
 
(ii)  
"Good Reason" means the occurrence of any of the following events without Employee's prior express written consent:
 
(A)  
A material diminution in the Employee’s Base Salary;
 
(B)  
A material diminution in the Employee’s authority, duties or responsibilities;
 
(C)  
A material diminution in the authority, duties or responsibilities of the supervisor to whom the Employee is required to report, including a requirement that the Employee report to a corporate officer or employee instead of reporting directly to the Board;
 
(D)  
A material diminution in the budget over which the Employee retains authority;
 
(E)  
A material diminution in reward opportunities under the annual Performance Bonus of Section 4.b. of this Agreement;
 
(F)  
A material change in the geographic location at which the Employee must perform services; or
 
(G)  
Any other action or inaction that constitutes a material breach by the Company of this Agreement.
 
Employee must provide notice to the Company of the condition described in paragraphs (A)-(G) of this section within ninety (90) days, upon the notice of which the Company will have a period of thirty (30) days during which it may remedy the condition and not be required to pay the amount.
 
g.  
Termination by the Employee for other than Good Reason .  The Employee may terminate this Agreement for other than Good Reason upon proper notification as provided in Section 7.a.  In such event the Company shall pay to the Employee:
 
(i)  
Within thirty (30) days after this Termination Date, in a lump sum, the compensation provided in Section 4 at the rate in effect at the time of the Notice of Termination. The Base Salary and Bonus will be prorated for the portion of the year that the Employee is employed by the Company; provided, however, that if the Employee’s termination occurs prior to March 31 of the year the Employee will not be entitled to a prorated Bonus for the year;
 
 
12
 
(ii)  
Any incentive, deferred or other compensation which has been earned or has become payable pursuant to the terms of this or any other agreement or compensation or benefit plan as of the Termination Date, but which has not yet been paid, provided such payments will be made under the schedule originally contemplated in the agreement under which they were granted;
 
(iii)  
Any unpaid expense reimbursement upon presentation by the Employee of an accounting of such expenses in accordance with normal Company practices, but not later than March 15 of the year following the year of termination; and
 
(iv)  
Any other payments for benefits earned under this or any other employment agreement or plan.
 
h.  
Termination by the Employee following Change of Control .
 
(i)  
If the Employee terminates this Agreement within two years following a Change of Control of the Company (as defined in Section 1.c.) the Company shall:
 
(A)  
Within thirty (30) days of the Termination Date, pay to the Employee a lump sum severance payment equal to three times the sum of: a) the Employee's highest Base Salary during the previous two years of employment immediately preceding the Termination Date, plus b) the highest Bonus paid to the Employee for a year within the same two year period of employment immediately preceding the Termination Date,
 
(B)  
Pay to the Employee any unpaid reimbursement upon presentation by the Employee of an accounting of such expenses in accordance with normal Company practices, but not later than March 15 of the year following the year of termination,
 
(C)  
Immediately vest any unvested Company stock options and restricted stock (excluding all LTIP shares),
 
(D)  
Pay any deferred income or Retirement Compensation (under Section 4.c.) or retirement payment or other benefit payments due under this or any other agreements or plans, provided such payments will be made under the schedule originally contemplated in the agreement under which they were granted,
 
 
13
 
(E)  
Make any other payments or provide any benefits earned under this or any other employment agreement or plan, including the Company’s Long-Term Incentive Plan, and
 
(F)  
Continue coverage of the Employee under the Company’s group health plans at the Company’s cost for a period equal to the lesser of (i) 18 months or (ii) such period as the Employee is receiving COBRA health continuation coverage from the Company.
 
i.  
Code Section 409A Compliance .  Except with respect to amounts paid pursuant to a schedule in a plan or arrangement outside of this Employment Agreement, it is intended that amounts payable under this Section 7 not be considered non-qualified deferred compensation subject to Internal Revenue Code Section 409A.  Employee is a Specified Employee under Internal Revenue Code Section 409A, therefore, to the extent such amounts are considered non-qualified deferred compensation payable upon a separation from service under Internal Revenue Code Section 409A, payment of those amounts so deferred under Internal Revenue Code Section 409A may not be made until at least six (6) months following the Employee’s separation from service of the Company (or, if earlier, the date of death of Employee).
 
8.  
Life Insurance .  The Company may, at any time after the execution of this Agreement, maintain any outstanding life insurance policies and apply for and procure as owner and for its own benefit new life insurance on Employee, in such amounts and in such form or forms as the Company may determine.  Employee shall, at the request of the Company, submit to such medical examinations, supply such information, and execute such documents as may be required by the insurance company or companies to whom the Company has applied for such insurance.  Employee hereby represents that to his knowledge he is in excellent physical and mental condition.
 
9.  
Notices . For the purposes of this Agreement, notices and all other communications provided for in the Agreement shall be in writing and will be deemed to have been duly given when personally delivered, by facsimile transmission or sent by certified mail, return receipt requested, postage prepaid, or by expedited  (overnight) courier with established national reputation, shipping prepaid or billed to sender, in either case addressed to the respective addresses last given by each party to the other  (provided that all notices to the Company must be directed to the attention of the Secretary of the Company ) or to such other address as either party may have furnished to the other in writing in accordance  herewith.  All notices and communication will be deemed to have been received on the date of delivery thereof, or on the second day after deposit thereof with an expedited courier service, except that notice of change of address will be effective only upon receipt.
 
 
14
 
Company at:                          Petroleum Development Corporation
Attention: Chairman of the Board
120 Genesis Boulevard
P.O. Box 26
Bridgeport, WV 26330

Employee at:                          Darwin Stump
206 Ruffed Grouse Drive
Bridgeport, WV 26330

10.  
Successors . This Agreement will be binding on the Company and any successor to any of its businesses or assets.  Without limiting the effect of the prior sentence, the Company shall use its best efforts to require any successor or assign (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company to expressly assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession or assignment had taken place. As used in this Agreement, "Company" means the Company as hereinbefore defined and any successor or assign to its business and/or assets as aforesaid which assumes and agrees to perform this Agreement or which is otherwise obligated under this Agreement by the first sentence of this Section, entitled Successors, by operation of law or otherwise.
 
11.  
Binding Effect .  This Agreement will inure to the benefit of and be enforceable by Employee's personal and legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees.  If Employee should die while any amounts would still be payable to him hereunder if he had continued to live, all such amounts, unless otherwise provided herein, will be paid in accordance with the terms of this Agreement to Employee's estate.
 
12.  
Integration, Modification and Waiver .  This Agreement constitutes the sole employment agreement between the parties, and any prior employment agreement, written or oral, is terminated.  No provision of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing and signed by Employee and such officer of the Company as may be specifically designated by the Board.  No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with, any condition or provision of this Agreement to be performed by such other party will be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time.
 
13.  
Headings .  Headings used in this Agreement are for convenience only and will not be used to interpret or construe its provisions.
 
14.  
Waiver of Breach .  The waiver of either the Company or Employee of a breach of any provision of this Agreement will not operate or be construed as a waiver of any subsequent breach by either the Company or Employee.
 
 
15
 
15.  
Amendments .  No amendments or variations of the terms and conditions of this Agreement will be valid unless the same is in writing and signed by all of the parties hereto.
 
16.  
Survival of Obligations .  The provisions of Section 6 of this Agreement will continue to be binding upon the Employee and Company in accordance with their terms, notwithstanding the termination of the Employee’s employment with the Company for any reason or the expiration of this Agreement.
 
17.  
Severability .  The invalidity or unenforceability of any provision of this Agreement, whether in whole or in part, shall not in any way affect the validity and/or enforceability of any other provision contained herein.  Any invalid or unenforceable provision shall be deemed severable to the extent of any such invalidity or unenforceability.  It is expressly understood and agreed that while the Company and Employee consider the restrictions contained in this Agreement reasonable for the purpose of preserving for the Company the good will, other proprietary rights and intangible business value of the Company, if a final judicial determination is made by a court having jurisdiction that the time or territory or any other restriction contained in this Agreement is an unreasonable or otherwise unenforceable restriction against Employee, the provisions of such clause will not be rendered void but will be deemed amended to apply as to maximum time and territory and to such other extent as such court may judicially determine or indicate to be reasonable.
 
18.  
Governing Law .  This Agreement will be construed and enforced pursuant to the laws of the State of West Virginia.
 
19.  
Arbitration .  Any controversy or claim arising out of or relating to this Agreement or any transactions provided for herein, or the breach thereof, other than a claim for injunctive relief, will be settled by arbitration in accordance with the commercial Arbitration Rules of the American Arbitration Association (the "Rules") in effect at the time demand for arbitration is made by any party.  The evidentiary and procedural rules in such proceedings will be kept to the minimum level of formality that is consistent with the Rules. The Company shall name one arbitrator, Employee shall name a second and the two arbitrators so chosen shall name a neutral, third arbitrator, who will serve as the sole arbitrator of the controversy or claim.  The third arbitrator must be experienced in the matters in dispute.  If the third and sole arbitrator is not agreed upon, the American Arbitration Association will name him or her.  Arbitration will occur in Bridgeport, West Virginia, or such other location agreed to by the Company and Employee.  The award made by the third arbitrator will be final and binding, and judgment may be entered in any court of law having competent jurisdiction. The award is subject to confirmation, modification, correction, or vacation only as explicitly provided in Title 9 of the United States Code.  The prevailing party will be entitled to an award of pre- and post-award interest as well as reasonable attorneys' fees incurred in connection with the arbitration and any judicial proceedings related thereto.
 
16
 
20.  
Executive Officer Status .  Employee acknowledges that he may be deemed to be an "executive officer" of the Company for purposes of the Securities Act of 1933, as amended (the "1933 Act"), and the Securities Exchange Act of 1934, as amended (the "1934 Act") and, if so, he shall comply in all respects with all the rules and regulations under the 1933 Act and the 1934 Act applicable to him in a timely and non-delinquent manner. In order to assist the Company in complying with its obligations under the 1933 Act and 1934 Act, Employee shall provide to the Company such information about Employee as the Company shall reasonably request including, but not limited to, information relating to personal history and stockholdings.  Employee shall immediately report to the General Counsel of the Company or other designated officer of the Company all changes in beneficial ownership of any shares of the Company Common Stock deemed to be beneficially owned by Employee and/or any members of Employee's immediate family.
 
21.  
Pronouns .  All pronouns and any variations thereof will be deemed to refer to the masculine, feminine, neuter, singular, or plural, as the identity of the person or entity may require. As used in this Agreement: (1) words of the masculine gender shall mean and include corresponding neuter words or words of the feminine gender, (2) words in the singular shall mean and include the plural and vice versa, and (3) the word "may" gives sole discretion without any obligation to take any action.
 
22.  
Counterparts .   This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original, but all of which together will constitute but one document.
 
23.  
Exhibits .  Any Exhibits attached hereto are incorporated herein by reference and are an integral part of this Agreement.
 
17


IN WITNESS WHEREOF, the Company and the Employee have duly executed this Employment Agreement as of the date first above written.
 
 
 
         
Company
   
Executive
 
 
Petroleum Development Corporation
     
         
         
         
By:
 /s/ Kimberly Wakim       /s/ Darwin L. Stump
 
Kimberly Wakim
   
Darwin L. Stump
Position:
Chair of the
     
 
Compensation Committee
     
 
 
18
Exhibit 10.22

Separation Agreement

This Separation Agreement (the “Agreement”) is made and entered into this 8 th day of February, 2008 by and between Petroleum Development Corporation, a Nevada Corporation (the “Company”), and Thomas E. Riley (the “Employee”) (collectively, the “Parties”).

WHEREAS, the Parties acknowledge that on December 20, 2007 the Board of Directors of the Company (the “Board”) selected a successor for Steven R. Williams upon his retirement as Chief Executive Officer and authorized the successor to determine what changes he wanted to make to the executive leadership team of the Company.

WHEREAS, after further evaluation of these changes, the Company has determined that the Employee would best serve the Company in the role of Executive Vice President;

WHEREAS, the Parties acknowledge that the Employee does not wish to serve in the capacity of Executive Vice President of the Company;

WHEREAS, Employee desires to terminate his employment with the Company pursuant to the “Good Reason” provisions of his Employment Agreement and has given written notice of his intention to terminate his employment with the Company unless he continues in the capacity of President of the Company;

WHEREAS, the Company has advised the Employee that it does not intend to reconsider the actions taken with respect to Employee;

WHEREAS, the Parties desire to entire into a definitive agreement to set forth the terms of Employee’s separation from the Company;

NOW THEREFORE, in consideration of the premises and mutual covenants and obligations set forth herein and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged and accepted, the parties hereto, intending to be legally bound, agree as follows:

1.     Termination Date.   Employee resigns his employment and his position as President and as a member of the Board effective as of March 9, 2008 (the “Termination Date”). The Parties acknowledge that his resignation is due to “Good Reason” as defined under his Employment Agreement.

2.     Nondisparagement.   Employee agrees not to make negative comments or otherwise disparage the Company or its officers, directors, employees, shareholders or agents, in any manner likely to be harmful to them or their business, business reputation or personal reputation. The Company agrees that the members of the Board and officers of the Company as of the date hereof will not, while employed by the Company or serving as a director of the Company, as the case may be, make negative comments about the Employee or otherwise disparage the Employee in any manner that is likely to be harmful to the Employee’s business or personal reputation. The foregoing shall not be violated by truthful statements in response to legal process or required governmental testimony or filings, and the foregoing limitation on the Company’s directors and officers will not be violated by statements that they in good faith believe are necessary or
 
1
 
appropriate to make in connection with performing their duties for or on behalf of the Company.  Either Party will be entitled to execute the remedies provided for in Section 6.e. of the Employment Agreement.

3.      References.   The President of the Company shall provide employment references when requested by Employee and all such references shall characterize Employee’s separation as voluntary.

4.      Compensation and Benefits.

(a)  
The Company shall pay to Employee the following amounts:

(1)   
Separation Compensation. Within thirty (30) days after the Termination Date or seven (7) days after the Revocation Date (as defined in Section 11 below) without revocation, whichever is greater, the Company shall pay to the Employee a lump sum amount of $1,877,343, such amount is acknowledged by the Parties as being in full satisfaction of the amount due to Employee pursuant to Section 7(d) of his Employment Agreement; providing for three times the sum of: (a) the Employee’s highest Base Salary during the previous two years of employment immediately preceding the Termination Date, plus (b) the highest Bonus paid to the Employee during the same two year period.

(2)   
Compensation and Bonus .  Employee will be entitled to receive his full compensation earned in 2008 prior to the Termination Date paid in accordance with the Company’s normal payroll practices.  Such payment is based on a Base Salary of $315,000 for 2008.  Employee will also be entitled to receive the benefit earned by him under the Short-Term Incentive Compensation program for 2007.  The parties agree that such amount under the Short-Term Incentive Compensation program shall be $310,781, payable at the same time as the amounts noted in Section 4(a)(1) above. If the earnings part of the 2007 bonus calculation under the percent (50%) for the other executive officers (“Excess Amount”), Employee will receive a lump sum payment within thirty days after such determination, equal to four (4) times the amount of the additional bonus amount attributable to the Excess Amount.

(3)   
Expense Reimbursement.   Company shall pay to the Employee any unpaid expense reimbursement for periods on or prior to the Termination Date upon presentation by the Employee of an accounting of such expenses in accordance with normal Company practices. Employee agrees to submit all unpaid expense reimbursements to the Company by April 10, 2008. In no event shall such expense reimbursements be made later than April 30, 2008. The Parties acknowledge that Employee will not be entitled to any expense reimbursements (including, but not limited to, reimbursements for costs of premiums on Employee’s one million dollar life insurance policy

 
2
 
 
and reimbursements for the cost of the Employee’s current disability policy) for any expenses incurred on or after the Termination Date.

(4)   
Option to Purchase Automobile and Computer.   Employee shall have an option to purchase the automobile and computer currently furnished to him by the Company for $13,185 and $500, respectively. The computer shall be cleaned of all Company information by Company’s IT department prior to delivery. Full payment shall be due to the Company on or before February 28, 2008.

(5)   
Stock Options and Restricted Stock.   Company agrees that all unvested Company stock options and restricted stock shall be vested on the Termination Date.  Company acknowledges that Four Thousand Six Hundred and Seventy Eight (4,678) stock options shall become fully vested and Sixteen Thousand One Hundred Twenty Three (16,123) shares of restricted stock shall become fully vested.

(6)   
Performance Shares.   Company shall deliver to Employee as soon as practicable after the Termination Date, Three Thousand Seventy Eight (3,078) shares of Company stock in satisfaction of amounts due to Employee under Section 2.3 of the Company’s 2007 Long-Term Incentive Program. Employee acknowledges that such shares are his full entitlement from the Seven Thousand Six Hundred Ninety-Four (7,694) performance shares award under the 2007 Long-Term Incentive Program.

(7)   
Retirement Payment.   Company shall pay Employee the Retirement Payment earned under Section 4.c. of the Employment Agreement. The Retirement Payment shall be paid in ten (10) annual installments on the first business day of January each year, beginning January 2, 2009. The annual retirement payment shall be $37,500, which amount is acknowledged by the Parties as being equal to $7,500 times the number of completed years of service under his Employment Agreement with credit for a full year of service for 2008 (i.e., five years).

(8)   
COBRA Coverage.   Company shall continue coverage of the Employee and any dependents covered at the time of termination under the Company’s group health plans at the Company’s cost for a period equal to the lesser of (i) 18 months or (ii) such period as the Employee is eligible to participate in another employer’s health plan.

(9)   
Tax Withholding.   Company will be entitled to withhold from the benefits and payments described in this Agreement, all income and employment taxes as directed by Employee, as long as such request meets the minimum required to be withheld under applicable law. For all vested stock awards, the Company will withhold the designated income and employment tax amount in shares of Company Stock.

 
3
 
 
(10)   
Stock Purchase.   The Company shall purchase from the Employee Fifty Thousand (50,000) shares of Employee’s Company Stock. Such stock purchase will be made on the Termination Date. The amount paid for such shares will be based on the closing market price of the shares on February 8, 2008. In order to comply with the Exchange Act exemption provided by Rule 16b-3, the Board shall adopt a resolution providing that the repurchase of the shares will be in accordance with the terms set forth in this Section and expressly providing that this resolution has been adopted to comply with Rule 16b-3.

(b)  
Code Section 409A Compliance .  Company represents that this Agreement is complaint with Internal Revenue Code Section 409A (“Code Section 409A”) and shall be construed to amend the Employment Agreement entered into between the Parties in December, 2003 to comply with Code Section 409A. For purposes of this Agreement and the Employment Agreement:
 
(1)  
"Change of Control" shall have the meaing provided under Treas. Reg. § 1.409-A-3(i)(5).
 
(2)  
“Good Reason” shall have the meaning provided under Treas. Reg . § 1.409A-1(n). However, the Parties acknowledge that the Company’s thirty (30) day cure period is waived due to the fact that the Company does not intend to reconsider the actions taken with respect to Employee.

(3)  
Employee is considered a “specified employee” as such term is defined under Code Section 409A(a)(2)(B). Payment of those amounts considered nonqualified deferred compensation under Code Section 409A, including those amounts payable under Section 4(a)(7) of this Agreement, shall not be made until at least six (6) months following the Employee’s separation from service of the Company (or, if earlier, the date of death of Employee).

(4)  
It is intended that amounts payable under paragraphs (1), (2), (3), (5), (6) and (8) of Section 4(a) shall not be considered nonqualified deferred compensation under Code Section 409A.

5.      Qualified Retirement Plan.   As of the date hereof, Employee had a vested account balance in the Company’s qualified retirement plan. Employee shall be entitled to such vested account balance under the Company’s qualified retirement plan upon processing the appropriate distribution forms following his separation. Such vested account balance shall include Employee’s share of the 2007 Company contribution and Employee’s 401(k) deferrals through his Termination Date, all as adjusted for earnings to the date of distribution.
 
6.      Confidential Material and Employee Obligations.   Employee acknowledges the validity of the confidentiality, non-solicitation and non-compete provisions found in Section 6 of his Employment Agreement and the remedies called for therein. Employee agrees to abide by the terms of Section 6 of his Employment Agreement, provided that if, during the period specified in

 
4
 
 
Section 6d. of his Employment Agreement Employee notifies the Company of either an employment or business opportunity he intends to pursue, the Company has five (5) days to object. If the Company fails to object within the five (5) day period, Employee is free to pursue the employment or business opportunity, provided further that any objection by the Company shall not be unreasonable.
 
7.       Return of Property.  On or before the Termination Date, Employee will return to the Company all of the Company’s property in his possession. The Company’s property includes, without limitation, privileged information, reports, files, memoranda, correspondence, door and file keys, identification cards, credit cards, computer access codes, computer programs, software and hardware, customer and client lists or information and other property or material which he prepared or helped to prepare or to which he had access including any reproductions thereof.
 
8.      Cooperation with Investigations.   Employee agrees to cooperate fully with the Company and its attorneys in connection with any investigation or litigation relating to any Company matter in which Employee was involved, provided advice or has knowledge and will be reimbursed for Employee’s expenses and time at a mutually agreed rate. The Company will consult with Employee and make reasonable efforts to schedule any of Employee’s time required under this Section 8 so as not to materially disrupt Employee’s business and personal affairs, and the Company will reimburse Employee for reasonable direct expenses incurred by him in so complying. The Company agrees to promptly notify Employee, unless precluded by law, in the event the Company has knowledge that Employee is named or will be involved in any legal or regulatory proceeding, and the Company will designate an individual at the Company who will serve as Employee’s point of contact in the matter.
 
9.      Other.

(a)  
This Agreement shall be construed and enforced pursuant to the laws of the State of West Virginia without giving effects to its conflict of laws. If any provision hereof is declared to be unenforceable by a court of law, such provision shall be fully severable, and this Agreement shall be construed and enforced as if such unenforceable provision had never comprised a part hereof, the remaining provisions hereof shall remain in full force and effect, and the court construing the Agreement shall add as a part hereof a provision as similar in terms and effect to such unenforceable  provision as may be enforceable, in lieu of the unenforceable provision.

(b)  
This Agreement sets forth the entire agreement between the parties hereto, and fully supersedes any and all prior oral or written agreements between the parties pertaining to the subject matter hereof.

(c)  
All notices, requests, demands or other communications under the Agreement will be in writing and shall be deemed to have been duly given when delivered in person or deposited in the United States mail, postage prepaid, by registered or certified mail, return receipt requested, to the party to whom such notice is being given as follows:

 
5
 
 
 
As to Thomas E. Riley:
 
Thomas E. Riley
P. O.  Box 4471
Clarksburg, West Virginia 26302
       
 
As to the Company:
 
Petroleum Development Corporation
120 Genesis Boulevard
Bridgeport, West Virginia 26330

10.      Waiver and Release.   In consideration of the Company’s obligations as set forth above.  Employee hereby releases, acquits and forever discharges Company and each of its subsidiaries and affiliates and each of their respective officers, employees, directors, successors and assigns from any and all claims, actions or causes of action in any way related to her employment with the Company or the termination thereof, whether arising from tort, statute or contract, including but not limited to, claims of defamation, claims arising under the Employee Retirement Income Security Act of 1974, as amended, the Age Discrimination in Employment Act of 1967, as amended by the Older Workers Benefit Protection Act of 1990, Title VII of the Civil Rights Act of 1964, as amended, the Americans with Disabilities Act, the Family and Medical Leave Act, the discrimination and wage payment laws of West Virginia and any other federal, state or local statutes or ordinances of the United States, it being Employee’s intention and the intention of the Company to make this release as broad and as general as the law permits.  Employee understands that this Agreement does not waive any rights or claims that may arise after his execution of it and does not apply to claims arising under the terms of this Agreement.

11.       Knowing and Voluntary Consent.    Employee agrees that the consideration to which he is entitled as a result of this Agreement exceeds the consideration to which Employee would otherwise have been entitled, and is sufficient to make this Agreement fully enforceable.

Employee acknowledges that he was provided a period of at least twenty-one (21) days to consider this Agreement and that his signature on this Agreement prior to the expiration of the twenty-one (21) days shall constitute a waiver of the remainder of the twenty-one (21) day consideration period. Employee further acknowledges that he has a period of seven days following the date that he signs below to revoke this Agreement by delivering a written revocation to the Company at the address below by the end of business on the seventh day of the revocation period (“Revocation  Date”).  In the event of revocation, the Company’s obligations under this Agreement will be void.

Employee acknowledges that he has been encouraged, and has had a full opportunity, to consult with an attorney of his choosing in reviewing this Agreement, and Employee has had a reasonable time within which to review and consider it. Employee acknowledges that: (a) this Agreement is written in terms and set, forth conditions in a manner which he understands; (b) he has carefully read and understands all of the terms and conditions of this Agreement; (c) he agrees with the terms and conditions of this Agreement; (d) the payment to be made to him pursuant to this Agreement is not something to which he is entitled except as consideration for this Agreement; and (e) he enters into this Agreement knowingly and voluntarily.

 
6
 
 
IN WITNESS WHEROF, the Company and the Employee have duly executed this Separation Agreement as of this 8 th day of February, 2008.

Company
 
Employee
     
Petroleum Development Corporation
   
By:  /s/ Steven R. Williams
 
/s/ Thomas E. Riley
   
Thomas E. Riley
 
 
7
Exhibit 10.26

PETROLEUM DEVELOPMENT CORPORATION
 

 
2004 LONG-TERM EQUITY COMPENSATION PLAN
 

 
AMENDED AND RESTATED AS OF MARCH 8, 2008

 
 
 

TABLE OF CONTENTS
 
 


     
ARTICLE 1.
ESTABLISHMENT, OBJECTIVES AND DURATION
1
     
ARTICLE 2.
DEFINITIONS
1
     
ARTICLE 3.
ADMINISTRATION
4
     
ARTICLE 3.
SHARES SUBJECT TO THE PLAN AND MAXIMUM AWARDS
4
     
ARTICLE 4.
ELIGIBILITY AND PARTICIPATION
5
     
ARTICLE 5.
STOCK OPTIONS
6
     
ARTICLE 6.
STOCK APPRECIATION RIGHTS
6
     
ARTICLE 7.
RESTRICTED STOCK
8
     
ARTICLE 8.
PERFORMANCE UNITS AND PERFORMANCE SHARES
9
     
ARTICLE 9.
PERFORMANCE MEASURES
11
     
ARTICLE 10.
BENEFICIARY DESIGNATION
12
     
ARTICLE 11.
DEFERRALS
13
     
ARTICLE 12.
RIGHTS OF EMPLOYEES
13
     
ARTICLE 13.
AMENDMENT, MODIFICATION, TERMINATION AND ADJUSTMENTS
13
     
ARTICLE 14.
PAYMENT OF PLAN AWARDS AND CONDITIONS THEREON
13
     
ARTICLE 15.
CHANGE IN CONTROL
14
     
ARTICLE 16.
TAX PROVISIONS
15
     
ARTICLE 17.
INDEMNIFICATION
17
     
ARTICLE 18.
SUCCESSORS
18
     
ARTICLE 19.
LEGAL CONSTRUCTION
18
     
ARTICLE 20.
   

 
i 
 

PETROLEUM DEVELOPMENT CORPORATION
 
2004 LONG-TERM EQUITY COMPENSATION PLAN
 
AMENDED AND RESTATED AS OF MARCH 8, 2008
 
ARTICLE 1.  
ESTABLISHMENT, OBJECTIVES AND DURATION
 
1.1   ESTABLISHMENT OF THE PLAN.  Petroleum Development Corporation, a Nevada corporation (hereinafter referred to as the "Company"), hereby amends and restates its incentive compensation plan known as the “2004 Petroleum Development Corporation Long-Term Equity Compensation Plan" (hereinafter referred to as the "Plan"), as set forth in this document.  The Plan permits the grant of Nonqualified Stock Options, Incentive Stock Options, Stock Appreciation Rights,  Restricted Stock, Performance Shares and Performance Units.
 
Subject to approval by the Company's stockholders, the Plan as amended and restated shall become effective as of March 8, 2008 (the "Restatement Effective Date").  The Plan was originally effective as of April 26, 2004 (the "Effective Date").  The Plan shall remain in effect as provided in Section 1.3 hereof.
 
1.2   OBJECTIVES OF THE PLAN.  The objectives of the Plan are to optimize the profitability and growth of the Company through incentives which are consistent with the Company's goals and which link the personal interests of Participants to those of the Company's stockholders; to provide Participants with an incentive for excellence in individual performance; and to promote teamwork among Participants.
 
1.3   DURATION OF THE PLAN.  The Plan shall commence on the Effective Date, as described in Section 1.1 hereof, and shall remain in effect, subject to the right of the Board of Directors to amend or terminate the Plan at any time pursuant to Article 14 hereof, until all Shares subject to it shall have been purchased or acquired according to the Plan's provisions.  However, in no event may an Award be granted under the Plan on or after April 25, 2014.
 
ARTICLE 2.  
DEFINITIONS
 
Whenever used in the Plan, the following terms shall have the meanings set forth below, and when the meaning is intended, the initial letter of the word shall be capitalized:
 
2.1   "AFFILIATE" shall have the meaning ascribed to such term in Rule 12b-2 of the General Rules and Regulations of the Exchange Act.
 
2.2   "AWARD" means, individually or collectively, a grant under this Plan of Nonqualified Stock Options, Incentive Stock Options, Stock Appreciation Rights, Restricted Stock, Performance Shares or Performance Units.
 
2.3   "AWARD AGREEMENT" means an agreement entered into by the Company and each Participant setting forth the terms and provisions applicable to Awards granted under this Plan.
 
 
2.4   "BENEFICIAL OWNER" or "BENEFICIAL OWNERSHIP" shall have the meaning ascribed to such term in Rule 13d-3 of the General Rules and Regulations under the Exchange Act.
 
2.5   "BOARD" or "BOARD OF DIRECTORS" means the Board of Directors of the Company.
 
2.6   "CODE" means the Internal Revenue Code of 1986, as amended from time to time.
 
2.7   "COMMITTEE" means any committee appointed by the Board to administer the Plan, as specified in Article 3 herein.
 
2.8   "COMPANY" means Petroleum Development Corporation, a Nevada corporation, including any and all Subsidiaries and Affiliates, and any successor thereto as provided in Article 19 herein.
 
2.9   "COVERED EMPLOYEE" means a Participant who, as of the date of vesting and/or payout of an Award, as applicable, is one of the group of "covered employees," as defined in the regulations promulgated under Code Section 162(m), or any successor statute.
 
2.10   "DIRECTOR" means any individual who is a member of the Board of Directors of the Company or any Subsidiary or Affiliates.
 
2.11   "DISABILITY" shall have the meaning ascribed to such term in the Participant's governing long-term disability plan, or if no such plan exists, at the discretion of the Committee.
 
Notwithstanding the preceding, with respect  to any Award subject to Code Section 409A, a Participant shall be considered Disabled if the Participant —
 
(i)  
is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, or
 
(ii)  
is, by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, receiving income replacement benefits for a period of not less than three (3) months under an accident and health plan covering Employees of the Company.
 
2.12   "EFFECTIVE DATE" shall have the meaning ascribed to such term in Section 1.1 hereof.
 
2.13   "EMPLOYEE" means any full-time, active employee of the Company or its Subsidiaries or Affiliates.  Directors who are not employed by the Company shall not be considered Employees under this Plan.
 
2
 
2.14   "EXCHANGE ACT" means the Securities Exchange Act of 1934, as amended from time to time, or any successor act thereto.
 
2.15   "FAIR MARKET VALUE" shall be determined on the basis of the closing sale price at which Shares have been sold regular way on the principal securities exchange on which the Shares are traded or, if there is no such sale on the relevant date, then on the last previous day on which there was such a sale.
 
2.16   "FREESTANDING SAR" means an SAR that is granted independently of any Options, as described in Article 7 herein.
 
2.17   "INCENTIVE STOCK OPTION" or "ISO" means an option to purchase Shares granted under Article 6 herein and which is designated as an Incentive Stock Option and which is intended to meet the requirements of Code Section 422.
 
2.18   "INSIDER" shall mean an individual who is, on the relevant date, an officer, director or ten percent (10%) beneficial owner of any class of the Company's equity securities that is registered pursuant to Section 12 of the Exchange Act, all as defined under Section 16 of the Exchange Act.
 
2.19   "NON-EMPLOYEE DIRECTOR" shall mean a Director who is not also an Employee.
 
2.20   "NON-QUALIFIED STOCK OPTION" or "NQSO" means an option to purchase Shares granted under Article 6 herein and which is not intended to meet the requirements of Code Section 422.
 
2.21   "OPTION" means an Incentive Stock Option or a Nonqualified Stock Option, as described in Article 6 herein.
 
2.22   "OPTION PRICE" means the price at which a Share may be purchased by a Participant pursuant to an Option.
 
2.23   "PARTICIPANT" means an Employee who has been selected to receive an Award or who has outstanding an Award granted under the Plan.
 
2.24   "PERFORMANCE-BASED EXCEPTION" means the performance-based exception from the tax deductibility limitations of Code Section 162(m).
 
2.25   "PERFORMANCE SHARE" means an Award granted to a Participant, as described in Article 9 herein.
 
2.26   "PERFORMANCE UNIT" means an Award granted to a Participant, as described in Article 9 herein.
 
2.27   "PERIOD OF RESTRICTION" means the period during which the transfer of Shares of Restricted Stock is limited in some way  (based on the passage of time, the achievement of performance goals or upon the occurrence of other events as determined by the
 
3
 
Committee, at its discretion), and the Shares  are subject to a substantial risk of forfeiture, as provided in Article 8 herein.
 
2.28   "PERSON" shall have the meaning ascribed to such term in Section 3(a)(9) of the Exchange Act and used in Sections 13(d)  and 14(d) thereof, including a "group" as defined in Section 13(d)  thereof.
 
2.29   "RESTATEMENT EFFECTIVE DATE" shall have the meaning ascribed to such term in Section 1.1.
 
2.30   "RESTRICTED STOCK" means an Award granted to a Participant pursuant to Article 8 herein.
 
2.31   "RETIREMENT" shall have the meaning ascribed to such term in the Company's tax-qualified profit sharing plan.
 
2.32   "SHARES" means the shares of common stock of the Company.
 
2.33   "SPECIFIED EMPLOYEE"                                                                means, with respect to the Company or any of its Subsidiaries, and determined as of the date of an individual's separation from service from the Company (1) any officer during the prior twelve (12) month period with annual compensation in excess of $145,000 (as adjusted from time to time under the Code), (2) a 5-percent owner of the Company's outstanding equity stock during the prior twelve (12) month period or (3) a 1-percent owner of the Company's outstanding equity stock during the prior (12) month period with annual compensation in excess of $150,000 (as adjusted from time under Code), provided that the Company or any of its Subsidiaries is publicly-traded within the meaning of Section 409A of the Code on the date of determination.
 
2.34   "STOCK APPRECIATION RIGHT" or "SAR" means an Award, granted alone or, in connection with a related Option, designated as an SAR, pursuant to the terms of Article 7 herein.
 
2.35   "SUBSIDIARY" means any corporation, partnership, joint venture or other entity in which the Company has a majority voting interest (including all divisions, affiliates and related entities).
 
2.36   "TANDEM SAR" means an SAR that is granted in connection with a related Option pursuant to Article 7 herein, the exercise of which shall require forfeiture of the right to purchase a Share under the related Option (and when a Share is purchased under the Option, the Tandem SAR shall similarly be canceled).
 
ARTICLE 3.  
ADMINISTRATION
 
3.1   THE COMMITTEE.  The Plan shall be administered by the Compensation Committee of the Board consisting of not less than two Directors who meet the "Non-Employee Director" requirements of Rule 16b-3 promulgated by the Securities and Exchange Commission under the Exchange Act, the "Independent Director" requirements of Nasdaq Marketplace Rule
 
4
 
 4350(c), and the requirements of Code Section 162(m), or by any other committee appointed by the Board, provided the members of such committee meet such requirements.
 
3.2   AUTHORITY OF THE COMMITTEE.  Except as limited by law or by the Articles of Incorporation or Bylaws of the Company, and subject to the provisions herein, the Committee shall have full power to select Employees who shall participate in the Plan;  determine the sizes and types of Awards; determine the terms and conditions of Awards in a manner consistent with the Plan;  construe and interpret the Plan and any agreement or instrument entered into under the Plan; establish, amend or waive rules and regulations for the Plan's administration; and (subject to the provisions of Article 14 herein) amend the terms and conditions of any outstanding Award to the extent such terms and conditions are within the discretion of the Committee as provided in the Plan.  Further, the Committee shall make all other determinations which may be necessary or advisable for the administration of the Plan. As permitted by law, the Committee may delegate its authority as identified herein.
 
3.3   DECISIONS BINDING. All determinations and decisions made by the Committee pursuant to the provisions of the Plan and all related orders and resolutions of the Board shall be final, conclusive and binding on all persons, including the Company, its stockholders, Employees, Participants and their estates and beneficiaries.
 
ARTICLE 4.  
SHARES SUBJECT TO THE PLAN AND MAXIMUM AWARDS
 
4.1   NUMBER OF SHARES AVAILABLE FOR GRANTS.  Subject to Sections 4.2 and 4.3 herein, the maximum number of Shares with respect to which Awards may be granted to Participants under the Plan shall be seven hundred fifty thousand (750,000).  Shares issued under the Plan may be either authorized but unissued Shares (subject to a maximum of seven hundred fifty thousand (750,000) Shares), treasury Shares or any combination thereof.
 
Unless and until the Committee determines that an Award to a Covered Employee shall not be designed to comply with the Performance-Based Exception, the following rules shall apply to grants of such Awards under the Plan, subject to Sections 4.2 and 4.3.
 
(a)  
STOCK OPTIONS AND SARS:  The maximum aggregate number of Shares that may be subject to Stock Options, with or without Tandem SARs, or Freestanding SARs, granted in any one fiscal year to any one Participant shall be one hundred thousand (100,000).
 
(b)  
RESTRICTED STOCK:  The maximum aggregate grant with respect to Awards of Restricted Stock which are intended to qualify for the Performance-Based Exception, and which are granted in any one fiscal year to any one Participant shall be fifty thousand (50,000) Shares.
 
(c)  
PERFORMANCE SHARES/PERFORMANCE UNITS:  The maximum aggregate payout (determined as of the end of the applicable performance period) with respect to Awards of Performance Shares or Performance Units which are intended to comply with the Performance-Based Exception, and which are granted in any one fiscal year to any one 
 
5
 
 
Participant shall be equal to the Fair Market Value of fifty thousand (50,000) Shares.
 
 
4.2   LAPSED AWARDS.  If any Award granted under this Plan is canceled, terminates, expires or lapses for any reason (with the exception of the termination of a Tandem SAR upon exercise of the related Option, or the termination of a related Option upon exercise of the corresponding Tandem SAR), any Shares subject to such Award again shall be available for the grant of an Award under the Plan.
 
4.3   ADJUSTMENTS.  In the event of any change in corporate capitalization such as a stock split or stock dividend, or a corporate transaction such as any merger, consolidation, separation, including a spin-off, or other distribution of stock or property of the Company, any reorganization  (whether or not such reorganization comes within the definition of such term in Code Section 368 or any partial or complete liquidation of the Company, such adjustment shall be made in the number and class of Shares which are reserved and may be delivered under Section 4.1, in the number and class of and/or price of Shares subject to outstanding Awards granted under the Plan, and in the Award limits set forth in subsections 4.1(a), 4.l(b) and 4.l(c), as may be determined to be appropriate and equitable by the Committee, in its sole discretion, to prevent dilution or enlargement of rights; provided, however, that the number of Shares subject to any Award shall always be a whole number.
 
ARTICLE 5.  
ELIGIBILITY AND PARTICIPATION
 
5.1   ELIGIBILITY.  Persons eligible to participate in this Plan include officers and certain key salaried Employees of the Company with potential to contribute to the success of the Company or its Subsidiaries, including Employees who are members of the Board.
 
5.2   ACTUAL PARTICIPATION.  Subject to the provisions of the Plan, the Committee may, from time to time, select from all eligible Employees those to whom Awards shall be granted, and shall determine the nature and amount of each Award.
 
ARTICLE 6.  
STOCK OPTIONS
 
6.1   GRANT OF OPTIONS.  Subject to the terms and provisions of the Plan, Options may be granted to Participants in such number, and upon such terms, and at any time and from time to time as shall be determined by the Committee.
 
6.2   AWARD AGREEMENT.  Each Option grant shall be evidenced by an Award Agreement that shall specify the Option Price, the duration of the Option, the number of Shares to which the Option pertains, and such other provisions as the Committee shall determine.  The Award Agreement also shall specify whether the Option is intended to be an ISO within the meaning of Code Section 422, or an NQSO, whose grant is intended not to fall under the provisions of Code Section 422.
 
6.3   OPTION PRICE.  The Option Price for each grant of an Option under this Plan shall be at least equal to one hundred percent (100%) of the Fair Market Value of a Share on the date the Option is granted.  Notwithstanding the foregoing, no ISO shall be granted to any person who, immediately prior to the grant, owns stock possessing more than ten percent (10%) of the
 
6
 
total combined voting power of all classes of stock of the Company, unless the Option Price is at least one hundred ten percent (110%) of the Fair Market Value of a Share on the date of grant of the Option.
 
6.4   DURATION OF OPTIONS.  Each Option granted to a Participant shall expire at such time as  the Committee shall determine at the time of grant; provided, however, that no Option shall be exercisable later than the tenth anniversary following the date of its grant and provided further that no Option shall be exercisable later than the fifth anniversary following the date of its grant for an ISO granted to a Participant, who at the time of such grant owns stock possessing more than 10% of the total combined voting power of all classes of stock of the Company.
 
6.5   EXERCISE OF OPTIONS.  Options granted under this Article 6 shall be exercisable at such times and be subject to such restrictions and conditions as the Committee shall in each instance approve, which need not be the same for each grant or for each Participant.
 
6.6   PAYMENT.  Options granted under this Article 6 shall be exercised by the delivery of a written notice of exercise to the Company, setting forth the number of Shares with respect to which the Option is to be exercised, accompanied by full payment for the Shares.
 
The Option Price upon exercise of any Option shall be payable to the Company in full either:  (a) in cash or its equivalent; or  (b) by tendering previously acquired Shares having an aggregate Fair Market Value at the time of exercise equal to the total Option Price (provided that the Shares which are tendered must have been held by the Participant for at least six months prior to their tender to satisfy the Option Price); or (c) by a combination of (a) and (b).
 
The Committee may also allow cashless exercise as permitted under Federal Reserve Board's Regulation T, subject to applicable securities law restrictions, or by any other means which the Committee determines to be consistent with the Plan's purpose and applicable law.
 
Subject to any governing rules or regulations, as soon as practicable after receipt of a written notification of exercise and full payment, the Company shall deliver to the Participant, in the Participant's name, Share certificates in an appropriate amount based upon the number of Shares purchased under the Option(s).
 
6.7   RESTRICTIONS ON SHARE TRANSFERABILITY.  The Committee may impose such restrictions on any Shares acquired pursuant to the exercise of an Option granted under this Article 6 as it may deem advisable, including, without limitation, restrictions under applicable federal securities laws, under the requirements of any stock exchange or market upon which such Shares are then listed and/or traded, and under any blue sky or state securities laws applicable to such Shares.
 
6.8   TERMINATION OF EMPLOYMENT.  Each Participant's Option Award Agreement shall set forth the extent to which the Participant shall have the right to exercise the Option following termination of the Participant's employment with the Company.  Such provisions shall be determined in the sole discretion of the Committee but shall conform to the limitations established in Section 6.4, shall be included in the Award Agreement entered into
 
7
 
with each Participant, need not be uniform among all Options issued pursuant to this Article 6, and may reflect distinctions based on the reasons for termination of employment.
 
6.9   NONTRANSFERABILITY OF OPTIONS.
 
(a)  
INCENTIVE STOCK OPTIONS.  No ISO granted under the Plan may be sold, transferred, pledged, assigned or otherwise alienated or hypothecated, other than by will or by the laws of descent and distribution.  Further, all ISOs granted to a Participant under the Plan shall be exercisable during his or her lifetime only by such Participant or the Participant's legal representative (to the extent permitted under Code Section 422).
 
(b)  
NONQUALIFIED STOCK OPTIONS.  Except as otherwise provided in a Participant's Award Agreement, no NQSO granted under this Article 6 may be sold, transferred, pledged, assigned or otherwise alienated or hypothecated, other than by will or by the laws of descent and distribution.  Further, except as otherwise provided in a Participant's Award Agreement, all NQSOs granted to a Participant under this Article 6 shall be exercisable during his or her lifetime only by such Participant or the Participant's legal representative.
 
ARTICLE 7.  
STOCK APPRECIATION RIGHTS
 
7.1   GRANT OF SARS.  Subject to the terms and conditions of the Plan, SARs may be granted to Participants at any time and from time to time as shall be determined by the Committee.  The Committee may grant Freestanding SARs, Tandem SARs or any combination of these forms of SAR.
 
The Committee shall have complete discretion in determining the number of SARs granted to each Participant (subject to Article 4 herein) and, consistent with the provisions of the Plan, in determining the terms and conditions pertaining to such SARs.
 
The grant price of a Freestanding SAR shall equal the Fair Market Value of a Share on the date of grant of the SAR.  The grant price of Tandem SARs shall equal the Option Price of the related Option.
 
7.2   EXERCISE OF TANDEM SARS.  Tandem SARs may be exercised for all or part of the Shares subject to the related Option upon the surrender of the right to exercise the equivalent portion of the related Option.  A Tandem SAR may be exercised only with respect to the Shares for which its related Option is then exercisable.
 
Notwithstanding any other provision of this Plan to the contrary, with respect to a Tandem SAR granted in connection with an ISO:  (i) the Tandem SAR will expire no later than the expiration of the underlying ISO; (ii) the value of the payout with respect to the Tandem SAR may be for no more than 100% of the difference between the Option Price of the underlying ISO and the Fair Market Value of the Shares subject to the underlying ISO at the time
 
8
 
the Tandem SAR is exercised; and (iii) the Tandem SAR may be exercised only when the Fair Market Value of the Shares subject to the ISO exceeds the Option Price of the ISO.
 
7.3   EXERCISE OF FREESTANDING SARS.  Freestanding SARs may be exercised upon whatever terms and conditions the Committee, in its sole discretion, imposes upon them.
 
7.4   SAR AGREEMENT.  Each SAR grant shall be evidenced by an Award Agreement that shall specify the grant price, the term of the SAR, and such other provisions as the Committee shall determine.
 
7.5   TERM OF SARS.  The term of an SAR granted under the Plan shall be determined by the Committee, in its sole discretion; provided, however, that such term shall not exceed ten years.
 
7.6   PAYMENT OF SAR AMOUNT.  Upon exercise of an SAR, a Participant shall be entitled to receive payment from the Company in an amount determined by multiplying:
 
(a)  
the difference between the Fair Market Value of a Share on the date of exercise over the grant price; by
 
(b)  
the number of Shares with respect to which the SAR is exercised.
 
At the discretion of the Committee, the payment upon SAR exercise may be in cash, in Shares of equivalent value or in some combination thereof.  The Committee's determination regarding the form of SAR payout shall be set forth in the Award Agreement pertaining to the grant of the SAR.
 
7.7   TERMINATION OF EMPLOYMENT.  Each SAR Award Agreement shall set forth the extent to which the Participant shall have the right to exercise the SAR following termination of the Participant's employment with the Company and/or its Subsidiaries.  Such provisions shall be determined in the sole discretion of the Committee, shall be included in the Award Agreement entered into with Participants, need not be uniform among all SARs issued pursuant to the Plan and may reflect distinctions based on the reasons for termination of employment.
 
7.8   NONTRANSFERABILITY OF SARS.  Except as otherwise provided in a Participant's Award Agreement, no SAR granted under the Plan may be sold, transferred, pledged, assigned or otherwise alienated or hypothecated, other than by will or by the laws of descent and distribution.  Further, except as otherwise provided in a Participant's Award Agreement, all SARs granted to a Participant under the Plan shall be exercisable during his or her lifetime only by such Participant or the Participant's legal representative.
 
ARTICLE 8.  
RESTRICTED STOCK
 
8.1   GRANT OF RESTRICTED STOCK.  Subject to the terms and provisions of the Plan, the Committee, at any time and from time to time, may grant Shares of Restricted Stock to Participants in such amounts as the Committee shall determine.
 
9
 
8.2   RESTRICTED STOCK AGREEMENT.  Each Restricted Stock grant shall be evidenced by a Restricted Stock Award Agreement that shall specify the Period(s) of Restriction, the number of Shares of Restricted Stock granted and such other provisions as the Committee shall determine.
 
8.3   TRANSFERABILITY.  Except as provided in this Article 8, the Shares of Restricted Stock granted under the Plan may not be sold, transferred, pledged, assigned or otherwise alienated or hypothecated until the end of the applicable Period of Restriction established by the Committee and specified in the Restricted Stock Award Agreement, or upon earlier satisfaction of any other conditions, as specified by the Committee in its sole discretion and as set forth in the Restricted Stock Award Agreement. All rights with respect to the Restricted Stock granted to a Participant under the Plan shall be available during his or her lifetime only to such Participant or the Participant's legal representative.
 
8.4   OTHER RESTRICTIONS.  Subject to Article 10 herein, the Committee shall impose such other conditions and/or restrictions on any Shares of Restricted Stock granted pursuant to the Plan as it may deem advisable including, without limitation, a requirement that Participants pay a stipulated purchase price for each Share of Restricted Stock, restrictions based upon the achievement of specific performance goals (Company-wide, divisional and/or individual), time-based restrictions on vesting following the attainment of the performance goals and/or restrictions under applicable federal or state securities laws.
 
The Company may retain the certificates representing Shares of Restricted Stock in the Company's possession until such time as all conditions and/or restrictions applicable to such Shares have been satisfied.
 
Except as otherwise provided in this Article 8, Shares of Restricted Stock covered by each Restricted Stock grant made under the Plan shall become freely transferable by the Participant after the last day of the applicable Period of Restriction.
 
8.5   VOTING RIGHTS.  Participants holding Shares of Restricted Stock granted hereunder may be granted the right to exercise full voting rights with respect to those Shares during the Period of Restriction.
 
8.6   DIVIDENDS AND OTHER DISTRIBUTIONS.  During the Period of Restriction, Participants holding Shares of Restricted Stock granted hereunder may be credited with regular cash dividends paid with respect to the underlying Shares while they are so held.  The Committee may apply any restrictions to the dividends that the Committee deems appropriate.  Without limiting the generality of the preceding sentence, if the grant or vesting of Restricted Shares granted to a Covered Employee is designed to comply with the requirements of the Performance-Based Exception, the Committee may apply any restrictions it deems appropriate to the payment of dividends declared with respect to such Restricted Shares, such that the dividends and/or the Restricted Shares maintain eligibility for the Performance-Based Exception.  Notwithstanding the foregoing, for any Award that is governed by Code Section 409A regarding non-qualified deferred compensation, the Committee  shall establish the schedule of any payments of dividends in accordance with the requirements of Code Section 409A or any guidance promulgated thereunder.
 
10
 
8.7   TERMINATION OF EMPLOYMENT.  Each Restricted Stock Award Agreement shall set forth the extent to which the Participant shall have the right to receive unvested Restricted Shares following termination of the Participant's employment with the Company.  Such provisions shall be determined in the sole discretion of the Committee, shall be included in the Award Agreement entered into with each Participant, need not be uniform among all Shares of Restricted Stock issued pursuant to the Plan and may reflect distinctions based on the reasons for termination of employment; provided, however, that except in the cases of terminations by reason of death or Disability, the vesting of Shares of Restricted Stock which qualify for the Performance-Based Exception and which are held by Covered Employees shall occur at the time they otherwise would have vested, but for the employment termination.
 
ARTICLE 9.  
PERFORMANCE UNITS AND PERFORMANCE SHARES
 
9.1   GRANT OF PERFORMANCE UNITS/SHARES.  Subject to the terms of the Plan, Performance Units and/or Performance Shares may be granted to Participants in such amounts and upon such terms, and at any time and from time to time, as shall be determined by the Committee.
 
9.2   VALUE OF PERFORMANCE UNITS/SHARES.  Each Performance Unit shall have an initial value that is established by the Committee at the time of grant.  Each Performance Share shall have an initial value equal to the Fair Market Value of a Share on the date of grant.  The Committee shall set performance goals in its discretion which, depending on the extent to which they are met, will determine the number and/or value of Performance Units/Shares that will be paid out to the Participant.  For purposes of this Article 9, the time period during which the performance goals must be met shall be called a "Performance Period."
 
9.3   EARNING OF PERFORMANCE UNITS/SHARES.  Subject to the terms of this Plan, after the applicable Performance Period has ended, the holder of Performance Units/Shares shall be entitled to receive payout on the number and value of Performance Units/Shares earned by the Participant over the Performance Period, to be determined as a function of the extent to which the corresponding performance goals have been achieved.
 
9.4   FORM AND TIMING OF PAYMENT OF PERFORMANCE UNITS/SHARES.  Payment of earned Performance Units/Shares shall be made in a single lump sum following the close of the applicable Performance Period.  Subject to the terms of this Plan, the Committee, in its sole discretion, may pay earned Performance Units/Shares in the form of cash or in Shares (or in a combination thereof) which have an aggregate Fair Market Value equal to the value of the earned Performance Units/Shares at the close of the applicable Performance Period.  Such Shares may be granted subject to any restrictions deemed appropriate by the Committee.  The determination of the Committee with respect to the form of payout of such Awards shall be set forth in the Award Agreement pertaining to the grant of the Award.
 
At the discretion of the Committee, Participants may be entitled to receive any dividends declared with respect to Shares which have been earned in connection with grants of Performance Units and/or Performance Shares, but not yet distributed to Participants (such dividends shall be subject to the same accrual, forfeiture and payout restrictions as apply to dividends earned with respect to Shares of Restricted Stock, as set forth in Section 8.6 herein). 
 
11
 
 In addition, Participants may, at the discretion of the Committee, be entitled to exercise their voting rights with respect to such Shares.
 
9.5   TERMINATION OF EMPLOYMENT DUE TO DEATH, DISABILITY OR RETIREMENT.  Unless determined otherwise by the Committee and set forth in the Participant's Award Agreement, in the event the employment of a Participant is terminated by reason of death, Disability or Retirement during a Performance Period, the Participant shall receive a payout of the Performance Units/Shares which is prorated, as specified by the Committee in its discretion.
 
Payment of earned Performance Units/Shares shall be made at a time specified by the Committee in its sole discretion and set forth in the Participant's Award Agreement.  Notwithstanding the foregoing, with respect to Covered Employees who retire during a Performance Period, payments shall be made at the same time as payments are made to Participants who did not terminate employment during the applicable Performance Period.
 
9.6   TERMINATION OF EMPLOYMENT FOR OTHER REASONS.  In the event  that a Participant's employment terminates for any reason other than those reasons set forth in Section 9.5 herein, all Performance Units/Shares shall be forfeited by the Participant to the Company unless determined otherwise by the Committee, as set forth in the Participant's Award Agreement.
 
9.7   NONTRANSFERABILITY.  Except as otherwise provided in a Participant's Award Agreement, Performance Units/Shares may not be sold, transferred, pledged, assigned or otherwise alienated or hypothecated, other than by will or by the laws of descent and distribution.  Further, except as otherwise provided in a Participant's Award Agreement, a Participant's rights under the Plan shall be exercisable during the Participant's lifetime only by the Participant or the Participant's legal representative.
 
ARTICLE 10.  
PERFORMANCE MEASURES
 
Unless and until the Committee proposes for stockholder vote and the Company’s stockholders approve a change in the general performance measures set forth in this Article 10, the attainment of which may determine the degree of payout and/or vesting with respect to Awards to Covered Employees which are designed to qualify for the Performance-Based Exception, the performance measure(s) to be used for purposes of such grants shall be chosen from among net income either before or after taxes, market share, profits, share price, earnings per share, total stockholder return, return on assets, return on equity, operating income, return on capital or investment, or economic value added (including, but not limited to, any or all of such measures in comparison to the Company's competitors, the industry or some other comparator group).
 
The Committee shall have the discretion to adjust the determinations of the degree of attainment of the preestablished performance goals; provided, however, that Awards which are designed to qualify for the Performance-Based Exception, and which are held by Covered Employees, may not be adjusted upward (the Committee shall retain the discretion to adjust such Awards downward).
 
12
 
     In the event that applicable tax and/or securities laws change to permit Committee discretion to alter the governing performance measures without obtaining stockholder approval of such changes, the Committee shall have sole discretion to make such changes without obtaining stockholder approval.  In addition, in the event that the Committee determines that it is advisable to grant Awards which shall not qualify for the Performance-Based Exception, the Committee may make such grants without satisfying the requirements of Code Section 162(m).
 
ARTICLE 11.  
BENEFICIARY DESIGNATION
 
Each Participant under the Plan may, from time to time, name any beneficiary or beneficiaries (who may be named contingently or successively) to whom any benefit under the Plan is to be paid in case of his or her death before he or she receives any or all of such benefit.  Each such designation shall revoke all prior designations by the same Participant, shall be in a form prescribed by the Company, and will be effective only when filed by the Participant in writing with the Company during the Participant's lifetime.  In the absence of any such designation, the Participant's beneficiary shall be paid to the Participant's estate.
 
ARTICLE 12.  
DEFERRALS
 
The Committee may permit or require a Participant to defer such Participant's receipt of the payment of cash or the delivery of Shares that would otherwise be due to such Participant by virtue of the exercise of an Option or SAR, the lapse or waiver of restrictions with respect to Restricted Stock, or the satisfaction of any requirements or goals with respect to Performance Units/Shares.  If any such deferral election is required or permitted, the Committee shall, in its sole discretion, establish rules and procedures for such payment deferrals, provided, however, all deferrals shall be made in accordance with all applicable requirements of Code Section 409A or any guidance promulgated thereunder.
 
ARTICLE 13.  
RIGHTS OF EMPLOYEES
 
13.1   EMPLOYMENT.  Nothing in the Plan shall interfere with or limit in any way the right of the Company to terminate any Participant's employment at any time, nor confer upon any Participant any right to continue in the employ of the Company.
 
13.2   PARTICIPATION.  No Employee shall have the right to be selected to receive an Award under this Plan or, having been so selected, to be selected to receive a future Award.
 
ARTICLE 14.  
AMENDMENT, MODIFICATION, TERMINATION AND ADJUSTMENTS
 
14.1   AMENDMENT, MODIFICATION, AND TERMINATION.  Subject to the terms of the Plan, the Board, upon recommendation of the Committee, may at any time and from time to time, alter, amend, suspend or terminate the Plan in whole or in part.
 
14.2   ADJUSTMENT OF AWARDS UPON THE OCCURRENCE OF CERTAIN UNUSUAL OR NONRECURRING EVENTS.  The Committee may make adjustments in the terms and conditions of, and the criteria included in, Awards in recognition of unusual or nonrecurring events (including, without limitation, the events described in Section 4.3 hereof)
 
13
 
affecting the Company or the financial statements of the Company or of changes in applicable laws, regulations or accounting principles, whenever the Committee determines that such adjustments are appropriate in order to prevent dilution or enlargement of the benefits or potential benefits intended to be made available under the Plan; provided that unless the Committee determines otherwise, no such adjustment shall be authorized to the extent that such authority would be inconsistent with the Plan or Awards meeting the requirements of Code Section 162(m), as from time to time amended.
 
14.3   AWARDS PREVIOUSLY GRANTED.  Notwithstanding any other provision of the Plan to the contrary (but subject to Section 14.2 hereof), no termination, amendment or modification of the Plan shall adversely affect in any material way any Award previously granted under the Plan without the written consent of the Participant holding such Award.
 
14.4   COMPLIANCE WITH CODE SECTION 162(m). At all times when Code Section 162(m) is applicable, all Awards granted under this  Plan shall comply with the requirements of Code Section 162(m); provided, however, that in the event the Committee determines that such compliance is not desired with respect to any Award or Awards available for grant under the Plan, then compliance with Code Section 162(m) will not be required.  In addition, in the event that changes are made to Code Section 162(m) to permit greater flexibility with respect to any Award or Awards available under the Plan, the Committee may, subject to this Article 14, make any adjustments it deems appropriate.
 
ARTICLE 15.  
PAYMENT OF PLAN AWARDS AND CONDITIONS THEREON
 
15.1   EFFECT OF COMPETITIVE ACTIVITY. Anything contained in the Plan to the contrary notwithstanding, if the employment of any Participant shall terminate, for any reason other than death, while any Award to such Participant is outstanding hereunder, and such Participant has not yet received the Shares covered by such Award or otherwise received the full benefit of such Award, such Participant, if otherwise entitled thereto, shall receive such Shares or benefit only if, during the entire period from the date of such Participant's termination to the date of such receipt, such Participant shall have earned out such Award by:  (i) making himself or herself available, upon request, at reasonable times and upon a reasonable basis, to consult with, supply information to, and otherwise cooperate with the Company or any Subsidiary or Affiliate thereof with respect to any matter that shall have been handled by him or her or under his or her supervision while he or she was in the employ of the Company or of any Subsidiary or Affiliate thereof; and (ii) refraining from engaging in any activity that is directly or indirectly in competition with any activity of the Company or any Subsidiary or Affiliate thereof.
 
15.2   NONFULFILLMENT OF COMPETITIVE ACTIVITY CONDITIONS; WAIVERS UNDER THE PLAN.  In the event of a Participant's nonfulfillment of any condition set forth in Section 15.1 hereof, such Participant's rights under any Award shall be forfeited and canceled forthwith; provided, however, that the nonfulfillment of such condition may at any time (whether before, at the time of, or subsequent to termination of employment) be waived by the Committee upon its determination that in its sole judgment there shall not have been and will not be any substantial adverse effect upon the Company or any Subsidiary or Affiliate thereof by reason of the nonfulfillment of such condition.
 
14
 
15.3   EFFECT OF INIMICAL CONDUCT.  Anything contained in the Plan to the contrary notwithstanding, all rights of a Participant under any Award shall cease on and as of the date on which it has been determined by the Committee that such Participant at any time (whether before or subsequent to termination of such Participant's employment) acted in manner inimical to the best interests of the Company or any Subsidiary or Affiliate thereof.
 
ARTICLE 16.  
CHANGE IN CONTROL
 
16.1   DEFINITION.  For purposes of this Plan, a "Change in Control" of the Company is deemed to have occurred as of the first day that any one or more of the following conditions shall have been satisfied:
 
(a)  
the "Beneficial Ownership" of securities representing more than thirty-three percent (33%) of the combined voting power of the Company is acquired by any "person" as defined in Section 13(d) and 14(d) of the Exchange Act (other than the Company, any trustee or other fiduciary holding securities under an employee benefit plan of the Company, or any corporation owned, directly or indirectly, by the stockholders of the Company in substantially the same proportions as their ownership of stock of the Company); or
 
(b)  
the stockholders of the Company approve a definitive agreement to merge or consolidate the Company with or into another corporation or to sell or otherwise dispose of all or substantially all of its assets, or adopt a plan of liquidation; or
 
(c)  
during any period of three consecutive years, individuals who at the beginning of such period were members of the Board cease for any reason to constitute at least a majority thereof (unless the election, or the nomination for election by the Company's stockholders, of each new director was approved by a vote of at least a majority of the directors then still in office who were directors at the beginning of such period or whose election or nomination was previously so approved).
 
Notwithstanding the foregoing, with respect to any Award subject to Code Section 409A, a "Change in Control" of the Company is deemed to have occurred as of the first day that any one or more of the following conditions shall have been satisfied:
 
(d)  
Change in Ownership:  A change in ownership of the Company occurs on the date that any one person, or more than one person acting as a group, acquires ownership of stock of the Company that, together with stock held by such person or group, constitutes more than fifty percent (50%) of the total fair market value or total voting power of the stock of the Company, excluding the acquisition of additional stock by a person or more than one person acting as a group who is considered  to own more than fifty percent (50%) of the total fair market value or total voting power of the stock of the Company.
 
15
 
(e)  
Change in Effective Control:  A change in effective control of the Company occurs only on either of the following dates:
 
(1)  
The date any one person, or more than one person acting as a group, acquires (or has acquired during the twelve (12) month period ending in the date of the most recent acquisition by such person or persons) ownership of stock of the Company possessing 30% or more of the total voting power of the stock of the Company; or
 
(2)  
The date a majority of the members of the Board is replaced during any (12) month period by directors whose appointment or election is not endorsed by a majority of the members of the board of directors before the date of the appointment or election; provided that this paragraph (e) shall apply only to the company for which no other corporation is a majority shareholder.
 
(f)  
Change in Ownership of Substantial Assets:  A change in the ownership of a substantial portion of the Company's assets occurs on the date that any one person, or more than one person acting as a group, acquires (or has acquired during the twelve (12) month period ending on the date of the most recent acquisition by such person or persons) assets from the Company that have a total gross fair market value equal to or more than forty percent (40%) of the total gross fair market value of the assets of the Company, or the value of the assets being disposed of, determined without regard to any liabilities associated with such assets.
 
It is the intent that this definition be construed consistent with the definition of "Change of Control" as defined under Internal Revenue Code Section 409A and the applicable Treasury Regulations, as amended from time to time.
 
16.2   TREATMENT OF OUTSTANDING AWARDS.  Subject to Section 16.3 herein, upon the occurrence of a Change in Control:
 
(a)  
any and all Options and SARs granted hereunder shall become immediately exercisable and shall remain exercisable throughout their entire term;
 
(b)  
any restriction periods and restrictions imposed on Restricted Stock which are not performance-based shall lapse;
 
(c)  
the target payout opportunities attainable under all outstanding Awards of performance-based Restricted Stock, Performance Units and Performance Shares shall be deemed to have been fully earned for the entire Performance Period(s) as of the effective date of the Change in Control.  The vesting of all Awards denominated in Shares shall be accelerated as of the effective date of the Change in Control, and there shall be paid out to
 
16
 
 
Participants within 30 days following the effective date of the Change in Control a pro rata number of Shares (or their cash equivalents) based upon an assumed achievement of all relevant targeted performance goals and upon the length of time within the Performance Period which has elapsed prior to the Change in Control.  Awards denominated in cash shall be paid pro rata to participants in cash within 30 days following the effective date of the Change in Control, with the proration determined as a function of the length of time within the Performance Period which has elapsed prior to the Change in Control, and based on an assumed achievement of all relevant targeted performance goals.
 
 
16.3   TERMINATION, AMENDMENT AND MODIFICATIONS OF CHANGE-IN-CONTROL PROVISIONS.  Notwithstanding any other provision of the Plan or any Award Agreement provision, the provisions of this Article 16 may not be terminated, amended or modified on or after the date of an event which is likely to give rise to a Change in Control to affect adversely any Award theretofore granted under the Plan without the prior written consent of the Participant with respect to said Participant's outstanding Awards.
 
ARTICLE 17.  
TAX PROVISIONS
 
17.1   TAX WITHHOLDING.  The Company shall have the power and the right to deduct or withhold, or require a Participant to remit to the Company, an amount sufficient to satisfy federal, state and local taxes, domestic or foreign, required by law or regulation to be withheld with respect to any taxable event arising as a result of this Plan.
 
17.2   SHARE WITHHOLDING.  With respect to withholding required upon the exercise of Options or SARs, upon the lapse of restrictions on Restricted Stock, or upon any other taxable event arising as a result of Awards granted hereunder, Participants may elect, subject to the approval of the Committee, to satisfy the withholding requirement, in whole or in part, by having the Company withhold Shares having a Fair Market Value on the date the tax is to be determined equal to the minimum statutory total tax which could be imposed on the transaction.  All such elections shall be irrevocable, made in writing, and signed by the Participant, and shall be subject to any restrictions or limitations that the Committee, in its sole discretion, deems appropriate.
 
17.3   REQUIREMENT OF NOTIFICATION OF CODE SECTION 83(b) ELECTION.  If any Participants shall make an election under Section 83(b) of the Code (to include in gross income in the year of transfer the amounts specified in Code Section 83(b)) or under a similar provisions of the laws of a jurisdiction outside the United States, such Participant shall notify the Company of such election within ten (10) days of filing notice of the election with the Internal Revenue Service or other government authority, in addition to any filing and notification required pursuant to regulations issued under Code Section 83(b) or other applicable provision.
 
17.4   REQUIREMENT OF NOTIFICATION UPON DISQUALIFYING DISPOSITION UNDER CODE SECTION 421(b).  If any Participant shall make any disposition of shares of stock delivered pursuant to the exercise of an Incentive Stock Option under the
 
17
circumstances described in Code Section 421(b) (relating to certain disqualifying dispositions), such Participant shall notify the Company of such disposition within ten (10) days thereof.
 
ARTICLE 18.  
INDEMNIFICATION
 
Each person who is or shall have been a member of the Committee, or of the Board, shall be indemnified and held harmless by the Company against and from any loss, cost, liability or expense that may be imposed upon or reasonably incurred by him or her in connection with or resulting from any claim, action, suit or proceeding to which he or she may be a party or in which he or she may be involved by reason of any action taken or failure to act under the Plan and against and from any and all amounts paid by him or her in settlement thereof, with the Company's approval, or paid by him or her in satisfaction of any judgment in any such action, suit or proceeding against him or her, provided he or she shall give the Company an opportunity, at its own expense, to handle and defend the same before he or she undertakes to handle and defend it on his or her own behalf.  The foregoing right of indemnification shall not be exclusive of any other rights of indemnification to which such persons may be entitled under the Company's Articles  of Incorporation or Bylaws, as a matter of law or otherwise, or any power that the Company may have to indemnify them or hold them harmless.
 
ARTICLE 19.  
SUCCESSORS
 
All obligations of the Company under the Plan with respect to Awards granted hereunder shall be binding on any successor to the Company, whether the existence of such successor is the result of a direct or indirect purchase, merger, consolidation or otherwise, of all or substantially all of the business or assets of the Company.
 
ARTICLE 20.  
LEGAL CONSTRUCTION
 
20.1   GENDER AND NUMBER.  Except where otherwise indicated by the context, any masculine term used herein also shall include the feminine, the plural shall include the singular, and the singular shall include the plural.
 
20.2   SEVERABILITY.  In the event any provision of the Plan shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of the Plan, and the Plan shall be construed and enforced as if the illegal or invalid provision had not been included.
 
20.3   REQUIREMENTS OF LAW.  The granting of Awards and the issuance of Shares under the Plan shall be subject to all applicable laws, rules and regulations, and to such approvals by any governmental agencies or national securities exchanges as may be required.
 
20.4   SECURITIES LAW COMPLIANCE.  With respect to Insiders, transactions under this Plan are intended to comply with all applicable conditions of Rule 16b-3 or its successors under the Exchange Act.  To the extent any provision of the Plan or action by the Committee fails to so comply, it shall be deemed null and void, to the extent permitted by law and deemed advisable by the Committee.
 
18
 
20.5   SECTION 409A COMPLIANCE.  Notwithstanding any other provision of this Plan to the contrary, all Awards under this Plan that are subject to Code Section 409A shall be designed and administered in a manner that does not result in the imposition of tax or penalties under Section 409A of the Code.  Accordingly, Awards under this Plan that are subject to Code Section 409A shall comply with the following requirements, as applicable.
 
(a)  
Distribution to Specified Employees Upon Separation from Service.  To the extent that payment under an Award which is subject to Code Section 409A is due to a Specified Employee on account of the Specified Employee's separation from service from the Company or its Affiliate or Subsidiary, such payment shall be delayed until the first day of the seventh month following such separation from service (or as soon as practicable thereafter).  The Committee, in its discretion, may provide in the Award document for the payment of interest at a rate set by the Committee for such six-month period.
 
(b)  
No Acceleration of Payment.  To the extent that an Award is subject to Code Section 409A, payment under such Award shall not be accelerated from the date(s) specified in the Award documents as of the date of grant.
 
(c)  
Subsequent Delay in Payment.  To the extent that an Award is subject to Code Section 409A, payment under such Award shall not be deferred beyond the dates specified in the Award document as of the date of grant, unless the Committee makes the decision to delay payment at least one year prior to the scheduled payment date, and payment is delayed at least five years.
 
20.6   GOVERNING LAW.  To the extent not preempted by federal law, the Plan, and all agreements hereunder, shall be construed in accordance with and governed by the laws of the State of West Virginia.
 
 
19
Exhibit 14.1

Petroleum Development Corporation
 
Code Of Business Conduct And Ethics
 
As Adopted April 27, 2004
 
This Code of Business Conduct and Ethics covers a wide range of business practices and procedures.  It does not cover every issue that may arise, but it sets out basic principles to guide all directors, officers,   and employees of the Company.  All of our directors, officers, and employees must conduct themselves accordingly and seek to avoid even the appearance of improper behavior.  The Code should also be provided to and followed by the Company’s agents and representatives, including consultants.
 
If a law conflicts with a policy in this Code, you must comply with the law.  If you have any questions about these conflicts, you should ask your supervisor or the Company’s Chief Financial Officer (CFO) how to handle the situation.
 
Those who violate the standards in this Code will be subject to disciplinary action, up to and including termination of employment or other association with the Company.   If you are in a situation which you believe may violate or lead to a violation of this Code, follow the guidelines described in Sections 13 and 14 of this Code.
 
1.  
Compliance with Laws, Rules, and Regulations
 
Obeying the law, both in letter and in spirit, is the foundation on which this Company’s ethical standards are built.  All directors, officers, and employees of the Company must respect and obey the laws and regulations of the cities, states, and countries in which we operate.  Although not all directors, officers, or employees are expected to know the details of these laws and regulations, it is important to know enough to determine when to seek advice from supervisors, managers, or other appropriate personnel.
 
2.  
Conflicts of Interest
 
A “conflict of interest” exists when the private interest of a director, officer, or employee interferes in any way with the interests of the Company.  A conflict situation can arise when a director, officer, or employee takes actions or has interests that may make it difficult to perform his or her duties for the Company objectively and effectively.  Conflicts of interest also arise when a director, officer, or employee, or a member of his or her family, receives improper personal benefits as a result of his or her position with the Company.  Loans and guarantees by the Company may also create conflicts of interest, and certain loans to and guarantees of obligations of directors and executive officers are prohibited by federal securities laws.
 
Conflicts of interest arise when a director, officer, or employee of the Company works simultaneously for a competitor, customer, or supplier.  No director, officer, or employee may work for a competitor as a consultant or board member except as specifically approved in accordance with Section 12 of this Code.  The best policy is to avoid any direct or indirect business connection with our customers, suppliers, or competitors, except on behalf of the 
 
 
 
Company.  Conflicts of interest may not always be clear-cut, so if you have a question, you should consult with higher levels of management or the Company’s CFO.  Any director, officer, or employee who becomes aware of a conflict or potential conflict should bring it to the attention of a supervisor, manager, or other appropriate personnel or consult the procedures described in Sections 13 and 14 of this Code.
 
3.  
Insider Trading
 
Directors, officers, and employees who have access to or become aware of confidential information are not permitted to use or share that information for stock trading purposes or for any other purpose except the conduct of our business.  All non-public information about the Company, as well as non-public information about our customers and suppliers, should be considered confidential information.  To use non-public information for personal financial benefit or to “tip” others who might make an investment decision on the basis of this information is not only unethical but also illegal.  To assist with compliance with laws against insider trading, the Company has adopted a specific policy governing trading in securities of the Company by the Company’s directors, officers, and employees.  This policy has been distributed to every director, officer, and employee.  If you have any questions, please consult with the Company’s CFO.
 
4.  
Corporate Opportunities
 
Directors, officers, and employees are prohibited from taking for themselves personally, or diverting to other persons, opportunities that are discovered through the use of corporate property, information, or position without the consent of the Board of Directors.  No director, officer, or employee may use corporate property, information, or position for personal gain, and no director, officer, or employee may compete with the Company directly or indirectly during his or her tenure with the Company.  Directors, officers, and employees owe a duty to the Company to advance its legitimate interests when the opportunity to do so arises.
 
5.  
Confidentiality
 
All directors, officers, and employees of the Company must maintain the confidentiality of confidential information entrusted to them by the Company, its customers or suppliers, or others, except when disclosure is authorized by the Board of Directors an Executive Officer of the Company, or required by laws or regulations.  Confidential information includes all non-public information that might be of use to competitors, or harmful to the Company, its customers or suppliers, or others, if disclosed.  It also includes information that customers or suppliers have entrusted to us.  The obligation to preserve confidential information continues even after your employment or other association with the Company ends
 
6.  
Competition and Fair Dealing
 
We seek to outperform our competition fairly and honestly.  Stealing proprietary information, possessing trade secret information that was obtained without the owner’s consent, or inducing such disclosures by past or present directors, officers, or employees of other companies is prohibited.  Each director, officer, and employee of the Company should endeavor to respect the rights of and deal fairly with the Company’s customers, suppliers, competitors, and
 
 
2
 
employees.  No director, officer, or employee should take unfair advantage of anyone through manipulation, concealment, abuse of privileged information, misrepresentation of material facts, or any other intentional unfair-dealing practice.
 
The purpose of business entertainment and gifts in a commercial setting is to create good will and sound working relationships, not to gain unfair advantage with customers.  No gift or entertainment should ever be offered, given, provided, or accepted by any officer, director, employee, or other agent of the Company, or any of their family members, unless it: (1) is not a cash gift, (2) is consistent with customary business practices, (3) is not excessive in value, (4) cannot be construed as a bribe or payoff, and (5) does not violate any laws or regulations.  Please discuss with your supervisor or the Company’s CFO any gifts or proposed gifts which you are not certain are appropriate.  See also Section 10 of this Code concerning gifts and other payments to government representatives.
 
7.  
Discrimination and Harassment
 
The diversity of the Company’s employees, consultants, and contractors is a tremendous asset.  We are firmly committed to providing equal opportunity in all aspects of employment and contractual relations and will not tolerate any unlawful discrimination or workplace harassment of any kind or violent, coercive, or threatening behavior.  Examples include derogatory comments based on racial or ethnic characteristics and unwelcome sexual advances.
 
8.  
Record-Keeping
 
The Company requires honest and accurate recording and reporting of information to make responsible business decisions.  For example, only the true and actual number of hours worked should be reported.
 
Many employees regularly use business expense accounts, which must be documented and recorded accurately.  If you are not sure whether a certain expense is legitimate, ask your supervisor or your CFO.  Business expense accounts should not be used for personal expenses.
 
All of the Company’s books, records, accounts, and financial statements must be maintained in reasonable detail, must appropriately reflect the Company’s transactions, and must conform both to applicable legal requirements and to the Company’s system of internal controls.  Unrecorded or “off the books” funds or assets may not be maintained unless permitted by applicable law or regulation.
 
Business records and communications often become public, and we should avoid exaggeration, derogatory remarks, guesswork, or inappropriate characterizations of people and companies that can be misunderstood.  This applies equally to e-mail, internal memos, and formal reports.  Records should always be retained or destroyed according to the Company’s record retention policies.  In accordance with those policies, in the event of litigation or governmental investigation, or any threat of litigation or governmental investigation, please consult the Company’s CFO.
 
 
3
 
9.  
Protection and Proper Use of Company Assets
 
All directors, officers, and employees should endeavor to protect the Company’s assets and ensure their efficient use.  Theft, carelessness, and waste have a direct effect on the Company’s profitability.  Any suspected incident of fraud or theft should be immediately reported to your supervisor or the CFO for investigation.  Company equipment should not be used for non-Company business, though incidental personal use may be permitted.The obligation of directors, officers, and employees to protect the Company’s assets includes the obligation to protect the Company’s proprietary information.  Proprietary information includes intellectual property such as trade secrets, patents, trademarks, and copyrights, as well as business, marketing and service plans, engineering and manufacturing ideas, designs, databases, records, salary information, and any unpublished financial data and reports.  Unauthorized use or distribution of this information violates Company policy.  It could also be illegal and result in civil or criminal penalties.
 
10.  
Payments to Government Personnel
 
The U.S. Foreign Corrupt Practices Act prohibits giving anything of value, directly or indirectly, to officials of foreign governments or foreign political candidates to obtain or retain business.  No illegal payments may be made to government officials of any country.
 
In addition, the U.S. government has a number of laws and regulations regarding business gratuities which may be accepted by U.S. government personnel.  The promise, offer, or delivery to an official or employee of the U.S. government of a gift, favor, or other gratuity in violation of these rules would not only violate Company policy but could also be a criminal offense.  State and local governments, as well as foreign governments, may have similar rules.  The Company’s CFO can provide guidance to you in this area.
 
11.  
Additional Provisions for CEO and Senior Financial Officers
 
In addition to the other provisions of this Code, the Company’s chief executive officer and senior financial officers, including the Company’s chief financial officer and principal accounting officer, are subject to the following additional specific policies:
 
a.  
The CEO and all senior financial officers are responsible for full, fair, accurate, timely, and understandable disclosure in the periodic reports required to be filed by the Company with the SEC.  Accordingly, it is the responsibility of the CEO and each senior financial officer promptly to bring to the attention of the Company’s Audit Committee any material information of which he or she may become aware that affects the disclosures made by the Company in its public filings or otherwise assist the Audit Committee in fulfilling its responsibilities .
 
b.  
The CEO and each senior financial officer shall promptly bring to the attention of the Audit Committee any information he or she may have concerning (1) significant deficiencies in the design or operation of internal controls which could adversely affect the Company’s ability to record, process, summarize, and report financial data or (2) any fraud, whether or not material, that involves management
 
 
4
 
 
or other employees who have a significant role in the Company’s financial reporting, disclosures, or internal controls.
 
c.  
The CEO and each senior financial officer shall promptly bring to the attention of the CEO and to the Audit Committee any information he or she may have concerning any violation of this Code, including any actual or apparent conflicts of interest between personal and professional relationships, involving any management or other employees who have a significant role in the Company’s financial reporting, disclosures, or internal controls.
 
d.  
The CEO and each senior financial officer shall promptly bring to the attention of the CEO and to the Audit Committee any information he or she may have concerning evidence of a material violation of the securities or other laws, rules, or regulations applicable to the Company and the operation of its business, by the Company or any agent thereof, or of violation of this Code.
 
12.  
Waivers of the Code of Business Conduct and Ethics
 
Any waiver of this Code for directors or executive officers may be made only by the Board of Directors and will be promptly disclosed as required by law or stock market regulation.  Waivers for other personnel may be made by such committees of the Board or officers to which the Board may delegate such authority from time to time.
 
13.  
Procedures if You Are Unsure if a Violation Has Occurred
 
We must all work to ensure prompt and consistent action against violations of this Code.  However, in some situations it is difficult to know if a violation has occurred.  Since we cannot anticipate every situation that will arise, it is important that we have a way to approach a new question or problem.  These are the steps to keep in mind:
 
·  
Make sure you have all the facts .  To reach the right solutions, we must be as fully informed as possible.
 
·  
Ask yourself: What specifically am I being asked to do? Does it seem unethical or improper?   This will enable you to focus on the specific question you are faced with, and the alternatives you have.  Use your judgment and common sense; if something seems unethical or improper, it probably is.
 
·  
Clarify your responsibility and role .  In most situations, there is shared responsibility.  Are your colleagues informed?  It may help to get others involved and discuss the problem.
 
·  
Discuss the problem with your supervisor .  This is the basic guidance for all situations.  In many cases, your supervisor will be more knowledgeable about the question, and will appreciate being brought into the decision-making process.  Remember that it is your supervisor’s responsibility to help solve problems.
 
 
5
 
·  
Seek help from Company resources .  In the rare case where it may not be appropriate to discuss an issue with your supervisor, or where you do not feel comfortable approaching your supervisor with your question, you may discuss it with the CFO.  If you do not feel comfortable discussing the issue with those persons as well, you may report the issue as described in Section 14.
 
·  
Consider other applicable Company policies.  If there is a specific Company policy relevant to the situation, in addition to this Code, review that policy and consider how it would apply to the situation and any reporting or other procedures set forth in that policy.
 
·  
You may report ethical violations in confidence and without fear of retaliation .  If your situation requires that your identity be kept secret, your anonymity will be protected.  The Company does not permit retaliation of any kind for good faith reports of ethical violations.
 
·  
Always ask first, act later : If you are unsure of what to do in any situation, seek guidance before you act .
 
14.  
Reporting any Illegal or Unethical Behavior
 
Employees must read the Company’s Complaint Procedures for Accounting and Auditing Matters , which describes the procedures adopted by the Company’s Audit Committee for the receipt, retention, and treatment of complaints received by the Company regarding accounting, internal accounting controls, or auditing matters. Any employee may submit a good faith concern regarding questionable accounting or auditing matters without fear of dismissal or retaliation of any kind.
 
Except for complaints or concerns submitted under the Audit Committee’s procedures, if you suspect that a violation of this Code has occurred or is occurring, and after considering the procedures described in Section 13 of the Code, you should immediately report the suspected violation or concern to the Compliance Officer designated by the Board of Directors.  As of the date of this Code, the Compliance Officer is:
 
Richard McCullough
Chief Financial Officer
Petroleum Development Corporation
P.O. Box 26
Bridgeport, WV 26330
(800) 624-3821
rmccullough@petd.com
 
If you wish to report a complaint anonymously, the Company maintains a whistleblower hotline.  You can confidentially report your concerns through a third-party reporting service that reports directly to designated outside directors of the Company by calling (866) 886-1354.
 
 
6
 
You may submit reports via U.S. mail, courier, FedEx, or similar delivery service, phone, e-mail, or in person.  You may submit complaints or concerns confidentially and anonymously.  If you wish to make a report anonymously in writing, please type your report, including the date but not your name, and deliver it via mail, courier, FedEx, or other delivery service in an envelope marked CONFIDENTIAL.  Alternatively, you may submit an anonymous report by e-mail; to do so, please be sure to send your report from an e-mail address that does not identify the sender.
 
If you submit a report that is not anonymous, you may be contacted to confirm information or to obtain further information.
 
15.  
Investigation and Corrective Action
 
Upon receipt of a complaint under this Code, the Company will promptly investigate the complaint and will involve agencies and resources outside the Company if and when such outside involvement appears advisable or necessary.  The Company will exercise discretion regarding the confidentiality of the report and investigation to the extent consistent with the need for a thorough investigation and response and taking into consideration the Company’s disclosure obligations and requirements.
 
The Board of Directors or the Audit Committee shall conduct, or designate appropriate persons (within or outside of the Company) to conduct, any investigation concerning alleged violations of this Code by the CEO or any of the Company’s senior financial officers.  The CFO or other appropriate personnel designated by the Board or the Audit Committee will conduct, or designate appropriate persons to conduct, any investigation concerning alleged violations by other officers and employees.  Directors, officers, and employees are expected to cooperate in internal investigations of alleged misconduct.
 
At the conclusion of any such investigation involving the CEO or any of the Company’s senior financial officers, the person leading the investigation will report to the Audit Committee or the full Board of Directors the results of the investigation and any remedial measures such investigator recommends.  At the conclusion of any such investigation involving other officers or employees, such investigator shall make such a report to the CFO or the CEO, as appropriate.
 
The Company will take all actions deemed appropriate by the Board of Directors, Audit Committee, CEO, or Compliance Officer, as applicable, as a result of any such investigation.  If it is determined that a director, officer, or employee of the Company has violated this Code, such action may include disciplinary action up to and including termination of employment.  If it is determined that a non-employee has violated this Code, the Company will take appropriate corrective action, which could include severing the Company’s relationship with such non-employee.  Such actions shall be reasonably designed to deter wrongdoing and to promote accountability for adherence to this Code, and may include written notices to the individual involved of the determination that there has been a violation, censure, demotion or re-assignment of the individual involved, suspension with or without pay or benefits, or termination of the individual’s employment.  In determining what action is appropriate in a particular case, the Board of Directors or other appropriate designated person shall take into account all relevant information, including the nature and severity of the violation, whether the violation was a single
 
 
7
 
occurrence or repeated occurrences, whether the violation appears to have been intentional or inadvertent, whether the individual in question had been advised prior to the violation as to the proper course of action, and whether or not the individual in question had committed other violations in the past.
 
Any and all complaints and related information received under this Code will be retained for seven years from the date of the complaint, or such other period of time as may be required by law.
 
16.  
Whistleblower Protections.
 
Federal and state laws prohibit retaliatory action by public companies against their employees who take certain lawful actions when they suspect wrongdoing on the part of their employer.  In furtherance of the Company’s obligations under federal law, as well as to preserve the integrity of this Code, neither the Company nor any of our directors, officers, employees, contractors, subcontractors, or agents may discharge, demote, suspend, threaten, harass, or in any other manner punish, discriminate, or otherwise retaliate against an employee because of any lawful act done by the employee to:
 
a.  
provide information, cause information to be provided to, or otherwise assist in an investigation by a federal regulatory or law enforcement agency, any member of Congress or committee of Congress, or any person with supervisory authority over the employee (or such other person working for the Company who has the authority to investigate, discover, or terminate misconduct), where such information or investigation relates to any conduct that the employee reasonably believes constitutes a violation of federal mail fraud, wire fraud, bank fraud, or securities fraud laws, any SEC rule or regulation, or any other federal law relating to fraud against shareholders;
 
b.  
file, cause to be filed, testify, participate in, or otherwise assist in a proceeding relating to alleged violations of any of the federal fraud or securities laws described in (a) above; or
 
c.  
report, or cause to be reported, any complaint under this Code.
 
The Company is committed to maintaining an environment in which people feel free to report all suspected incidents of inaccurate financial reporting or fraud.  No retaliatory action will be taken against any person who in good faith reports any conduct which he or she reasonably believes may violate this Code.  In addition, no retaliatory action will be taken against any individual who in good faith assists or participates in an investigation, proceeding, or hearing relating to a complaint about the Company’s auditing or financial disclosures, or who files, causes to be filed, testifies, or otherwise assists in such a proceeding.   However, a person who files a report or provides evidence which he or she knows to be false or without a reasonable belief in the truth and accuracy of such information will not be protected by the above policy statement and may be subject to disciplinary action, including termination of employment or other association with the Company.
 

 
8
 

Exhibit A
 
Petroleum Development Corporation
 
PROCEDURES FOR CONFIDENTIAL SUBMISSION OF INFORMATION, QUESTIONS, COMPLAINTS, OR CONCERNS RELATING TO ACCOUNTING OR AUDITING MATTERS
 
The Audit Committee of the Board of Directors of Petroleum Development Corporation (the “Company”) has adopted the following procedures for the submission of information, questions, complaints, or concerns regarding the Company’s accounting, internal accounting controls, or auditing matters.  Please contact the Company’s Chief Financial Officer (CFO), Richard McCullough, if you have questions that are not answered in these procedures.
 
The Company will post these procedures on its website and will periodically include a summary of these procedures in its filings with the Securities and Exchange Commission.
 
Submission Of Complaints Or Concerns
 
Manner of Submission .  Information, questions, complaints, or concerns about the Company’s accounting, internal accounting controls, or auditing matters may be submitted to the Audit Committee by any of the following means:By sending a written description of the information, question, complaint, or concern, by U.S. mail, courier, FedEx, or similar delivery service, or by e-mail, to the CFO at:
 
Richard McCullough
Chief Financial Officer
Petroleum Development Corporation
P.O. Box 26
Bridgeport, WV 26330
(800) 624-3821
rmccullough@petd.com
 
By contacting any member of the Company’s Audit Committee, by U.S. mail, courier, FedEx, or similar delivery service at the Company’s headquarters, or by e-mail (board@petd.com).
 
Confidentiality and Anonymity .  Confidentiality is a priority, and all reports will be treated confidentially to the fullest extent possible.  Submissions of information, questions, complaints, or concerns will not be traced and submissions may be made anonymously.  To ensure the anonymous submission via e-mail, please do not send the submission from an e-mail address that identifies the sender.  For submissions that are not anonymous, you may be contacted to confirm information or to obtain additional information.
 
 
 
 

Receipt And Retention Of Submissions
 
Receipt .  The CFO or, in the absence of the CFO, the Company’s Controller will check the e-mail address provided above on no less than a weekly basis.  The CFO will promptly forward copies of all submissions to the Audit Committee.  The Audit Committee members will promptly forward all submissions they receive to the CFO and will evaluate the actions taken by the Company in response to all submissions.
 
Retention .  All submissions will be maintained in a confidential file.  Access to the confidential file will be restricted to members of the CFO’s office designated by the CFO and members of the Audit Committee.  All submissions will be maintained in such file for a minimum of seven years following receipt of such submissions.
 
Treatment Of And Response To Submissions
 
Review and Response .  The CFO will promptly review all submissions and report such submissions to the Audit Committee in executive session, with the CFO’s assessment of the submission and, to the extent relevant, recommended course of action.  In appropriate circumstances, the CFO will have the authority, in his discretion, to bring any submission immediately to the attention of the Audit Committee or to the Chairman of the Audit Committee.  All submissions being reviewed at an Audit Committee meeting will be physically present at the meeting and available for Audit Committee inspection.  The Audit Committee will determine the appropriate means of addressing the submissions and delegate that task to the appropriate member of senior management, or take such other action as it deems necessary or appropriate to address the submission, including obtaining outside counsel or other advisors to assist the Audit Committee.
 
Follow-up .  The CFO will be available for follow-up inquiries from persons submitting information, questions, complaints, or concerns.  If, after the follow-up discussion, the person submitting the information, question, complaint, or concern concludes that appropriate action has not been taken, he or she may report the matter directly to a member of the Audit Committee.
 
Documentation of Response .  Receipt of all submissions that are not anonymous will be acknowledged by the Company either orally or in writing, unless the person making the submission requests otherwise.  The CFO will maintain a record of the response to each submission, including the date of the acknowledgment and any other actions taken.  Such records will be maintained in the confidential file with the submissions for a period of seven years.
 
No Retaliation .  Retaliation against any person who in good faith makes a submission about any accounting, internal accounting controls, or auditing matters, including illegal or unethical conduct, will not be tolerated and will be a cause for discipline, including possible loss of employment.  A person may report retaliation by the same means described in these Procedures for reporting information, questions, complaints, or concerns or under the Company’s Code of Ethics.
 
 
2
Exhibit 21.1





 
Subsidiaries of Petroleum Development Corporation
 
       
       
 
Company Name
 
State or Country in which Incorporated or Organized
       
 
Riley Natural Gas Company
 
West Virginia
 
PDC Securities Incorporated
 
West Virginia
 
Unioil
 
Nevada
 
PDC, LLC
 
West Virginia
 
PA PDC, LLC
 
Delaware
       
 
 
Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Forms S-3 (No. 333-155745) and S-8 of Petroleum Development Corporation of our report dated February 26, 2009 relating to the financial statements, financial statement schedule and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

 
/s/ PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania
February 26, 2009
 
 
Exhibit 23.2

Consent of Independent Registered Public Accounting Firm


The Board of Directors
Petroleum Development Corporation:


We consent to the incorporation by reference in the registration statements on Form S-3 File Number 333-155745 and Form S-8 File Number 333-137836 (2006 PDC 401(k) and Profit Sharing Plan); File Number 333-126444 (2005 Non-Employee Director Restricted Stock Plan); File Number 333-118215 (2004 Long-Term Equity Compensation Plan); File Number 333-157554 (Non-Employee Director Deferred Compensation Plan); and File Number 333-111825 (PDC Stock Option Plans) of our report dated May 22, 2007, with respect to the consolidated statements of operations, shareholders' equity, and cash flows for the year ended December 31, 2006, and the related financial schedule, which report appears in the December 31, 2008, annual report on Form 10-K of Petroleum Development Corporation.

Our report dated May 22, 2007 on the consolidated financial statements refers to a change in accounting for share based payments and a change in the method of quantifying errors in 2006.


/s/ KPMG LLP
Pittsburgh, Pennsylvania
February 26, 2009
 
 
  Exhibit No. 23.3
 
 
Consent of Independent Petroleum Engineers
 
 
As independent petroleum and natural gas consultants, we hereby consent to the reference of our name in the Annual Report on Form 10-K, for the year ended December 31, 2008 of Petroleum Development Corporation, and to the incorporation of our name by reference into Petroleum Development Corporation's effective registration statements under the Securities Act of 1933, as amended.  We have no interest of a substantial or material nature in Petroleum Development Corporation, or in any affiliate. We have not been employed on a contingent basis, and we are not connected with Petroleum Development Corporation, or any affiliate as a promoter, underwriter, voting trustee, director, officer, employee, or affiliate.
 
 
/s/ D. Randall Wright
 
   D. Randall Wright, President
 
Wright & Company
   
Brentwood, TN
 
February 26, 2009
 
 
 
Exhibit No. 23.4
 
 
Consent of Independent Petroleum Engineers
 
 
We hereby consent to the reference of our name in the Annual Report on Form 10-K, for the year ended December 31, 2008 of Petroleum Development Corporation, and to the incorporation of our name by reference into Petroleum Development Corporation's effective registration statements under the Securities Act of 1933, as amended. 
 
 
/s/ Ryder Scott Company, LP
 
   
 
Ryder Scott Company, LP
   
Houston, TX
 
February 26, 2009
 
 
 
Exhibit 31.1
CERTIFICATION
 
I, Richard W. McCullough, certify that:

 
1.
I have reviewed this Annual Report on Form 10-K of Petroleum Development Corporation.

 
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 
4.
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

 
a.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 
b.
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

 
c.
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 
d.
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

 
5.
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditor and the audit committee of the registrant's board of directors (or persons performing the equivalent functions);

 
a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

 
b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.


Date:  February 26, 2009
/s/ Richard W. McCullough
 
 
Richard W. McCullough
 
 
Chief Executive Officer
 
 
 
Exhibit 31.2
CERTIFICATION
 
I, Gysle R. Shellum, certify that:

 
1.
I have reviewed this Annual Report on Form 10-K of Petroleum Development Corporation.

 
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 
4.
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

 
a.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 
b.
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

 
c.
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 
d.
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

 
5.
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditor and the audit committee of the registrant's board of directors (or persons performing the equivalent functions);

 
a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

 
b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.


Date:  February 26, 2009
/s/ Gysle R. Shellum
 
 
Gysle R. Shellum
 
 
Chief Financial Officer
 
 
 
Exhibit 32.1
CERTIFICATION

In connection with the Annual Report of Petroleum Development Corporation (the “Company”) on Form 10-K for the period ended December 31, 2008, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned certify pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

 
(1)
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
 
(2)
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

 /s/ Richard W. McCullough
 
February 26, 2009
Richard W. McCullough
 
Chairman, Chief Executive Officer, and President
 
   
   
 /s/ Gysle R. Shellum
 
February 26, 2009
Gysle R. Shellum
 
Chief Financial Officer
 
   
A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Petroleum Development Corporation and will be retained by Petroleum Development Corporation and furnished to the Securities and Exchange Commission or its staff upon request.