8-K/A

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

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FORM 8-K/A

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES AND EXCHANGE ACT OF 1934

Date of report (Date of earliest event reported) March 2, 2007

Petroleum Development Corporation

(Exact Name of Registrant as Specified in Charter)

              Nevada                                           0-7246                                        95-2636730

(State or Other Jurisdiction                       (Commission                                (IRS Employer

           of Incorporation)                                    File Number)                                Identification No.)

120 Genesis Boulevard, Bridgeport, WV  26330

(Address of Principal Executive Offices)

Registrant's telephone number, including area code: 304-842-3597

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

[ ] Written communications pursuant to Rule 425 under Securities Act (17 CFR 230.425)

[ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

[ ] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

[ ] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

no change

(Former Name or Former Address, if Changed Since Last Report)

Item 8.01.      Other Events

Petroleum Development Corporation hereby amends previous Form 8-K filed on February 21, 2007 to provided updated information.

A transcript of the presentation is attached as Exhibit 99.1.

EXHIBIT INDEX

Item 9.01.  Financial Statements and Exhibits.

(c)  Exhibits.

99.1         PowerPoint Presentation:  NASDAQ Oil and Gas Conference - London, England

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

PETROLEUM DEVELOPMENT CORPORATION

Date:       March 2, 2007

By:          /s/ Richard McCullough

                Richard McCullough

                Chief Financial Officer

EX-99

Petroleum Development Corporation

NASDAQ Oil and Gas Conference

London, England

Presenter:  Steven R. Williams, CEO

March 6, 2007

Forward-Looking Statements

This information contains predictions, estimates and other 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. Although the Company believes that its expectations are based on reasonable assumptions, it can give no assurance that its goals will be achieved.  Important factors that could cause actual results to differ materially from those included in the forward-looking statements include the timing and extent of changes in commodity prices for oil and gas, the need to develop and replace reserves, environmental risks, drilling and operating risks, risks related to exploration and development, uncertainties about the estimates of reserves, competition, government regulation and the ability of the Company to meet its stated business goals.

Contact Information:

Investor Relations

Petroleum Development Corporation

120 Genesis Blvd.  PO Box 26

Bridgeport, West Virginia 26330

Phone: 304.842.6256  Fax: 304.842.0913  www.petd.com

Increasing Production

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Increasing Proved Reserves

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5-year Stock Performance

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Factors Contributing to Success

•         Consistent, scaleable results

•         Lower risk projects

•         Diversification - with focus areas

•         Quality workforce and operations

•         Flexibility to pursue options

§         Development

§         Acquisitions

§         Exploration

Core Operating Areas

        Rocky Mountains

2006 Proved Reserves: 266 Bcfe

2006 Production: 14.1 Bcfe

2007 Production: 24 Bcfe*

        Michigan Basin

2006 Proved Reserves: 21.2 Bcfe

2006  Production: 1.4 Bcfe

2007 Production: 1.8 Bcfe*

        Appalachian Basin

2006 Proved Reserves: 36.0 Bcfe

2006 Production:  1.5 Bcfe

2007 Production: 2.6 Bcfe*

        *Estimated

        {Graphic}

Core Operating Areas

        Active Development Areas

        {Graphic}

Core Operating Areas

        Rocky Mountains

                Added interests through

                1031 Exchange and other purchase

        Michigan Basin

                Added interests through

                1031 Exchange

        Appalachian Basin

                Added interests through 1031 Exchange

2006 Summary

•         Capital Expenditures were $155 Million

•         Company bought back 1.6 million shares (10% of outstanding)

•         Production grew from 13.7 Bcfe in 2005 to 17 Bcfe in 2006 (23% increase)

•         Proved reserves grew 17.5% from 275 Bcfe @ YE 2005 to 323 Bcfe @ YE 2006

•         Lease sale of $354 Million

•         $90 Million in Partnership subscriptions

Acquisitions Summary

•         During December 2006 and January 2007, closed $209 Million in acquisitions ($18 Million non-1031)

•         3P reserves acquired total an estimated 153 Bcfe (84% proved)

•         Acquisitions primarily in existing operating areas

§         Wattenberg Field, DJ Basin Colorado

§         Appalachian and Michigan Basins

•         From $300 Million in 1031 funds, estimated incremental $20 Million in current taxes

Acquisitions Summary (continued)

•         Purchases in Wattenberg Field focus on continued development through re-fracs, Niobrara completions and new locations

•         Purchased remaining interests in 44 older PDC partnerships, increasing working interest percentages in 718 existing wells primarily in Appalachia and Michigan

•         Initial undeveloped acreage position in Barnett Shale play

§         Entry into area similar to PDC initial venture into Rockies area in 1999

Strategic Focus in 2007 and Beyond

•         Development operations in core areas

§         Accelerate development on 1031 property additions

•         Seek strategic acquisitions

•         Develop management, technical and support teams for future needs

•         Seek high potential exploration opportunities

•         Maintain focus on increasing long-term shareholder value

2007 Projected Drilling, Production & Reserves

2007 Operation and Production Forecast

                                                                                                        2006       2007E    % Increase

        Gross Exit Rate Production (MMCFE/d)                  121          182          50%

        Net Company Exit Rate Production (MMCFE/d)            53            100          88%

        Net Company Production (Bcfe)                                       17            28            65%

•         Drill 419 wells (34 non-operated)

•         164 re-fracs and/or re-completions

•         Total drill & complete (D&C) cost estimated $203 Million

•         Capital increase of approximately 70% over 2006

Grand Valley Field, Piceance Basin, Colorado

•         148 wells drilled to date

•         YE 2006 daily gross production 45 MMcfed

•         YE 2006 net daily production 13 MMcfed

•         5,120 Acres available for drilling on 10 acre Spacing

•         470 locations

§         263 PUD locations

•         137 Planned for Partnership drilling (PDC WI 37%)

•         126 100% WI  PDC

§         207 remaining other locations

Grand Valley Field, Piceance Basin, Colorado

•         1.3 Bcfe per well

•         1.04 net Bcfe @80% NRI

•         D&C cost of $2.0 Million / well

•         Development cost of $ 1.92 / Mcfe

•         Wells drilled directionally from multi-well pads

Grand Valley Field, Piceance Basin, Colorado

        2007 Drilling

•         Drill 56 wells

•         42 Partnership (PDC 37% WI)

•         14 PDC (100% WI)

•         29.54 Net wells

•         30.7 Bcfe added by drilling

•         $59 Million D&C cost

        2007 Field Total

•         6.9 Bcfe net production for 2007

•         89% increase over 2006

Wattenberg Field, DJ Basin, Colorado

•         976 wells (drilled and purchased)

•         2006 gross exit rate 40 MMcfed

•         2006 net exit rate 18.6 MMcfed

•         9,000 acres available for drilling

•         540 locations

§         220 40 acre PUD locations

§         70 20 acre rule 318-A locations

§         250 remaining other locations

§         800 Codell and/or Niobrara re-fracs

•         PDC and Partnership development

Wattenberg Field, DJ Basin, Colorado

•         0.3 Bcfe per well (includes re-frac)

•         0.24 net Bcfe @80% NRI

•         D&C cost of $490K per well plus $180K for re-frac

•         Development cost of $ 2.79/Mcfe or $16.75/Boe

•         Producing and undeveloped properties from Unioil and EXCO

Wattenberg Field, DJ Basin, Colorado

        2007 Drilling

•         Drill 204 wells

§         100 Partnership (PDC 37% WI)

§         104 PDC (100% WI)

•         140 Net wells

•         164 re-completions and re-fracs

•         33.9 Bcfe added by drilling

•         $93 Million D&C cost

        2007 Field Total

•         11.2 Bcfe net production for 2007

•         68% increase over 2006

NECO Field Area, Eastern DJ Basin, Colorado

•         268 operated wells

•         2006 exit rate 10.7 MMcfed

•         2006 net exit rate 8.5 MMcfed

•         29,160 acres available for drilling

•         8 defined structures (3D and 2D seismic)

•         107 PUD locations

•         250 potential locations

NECO Field Area, Eastern DJ Basin, Colorado

•         0.28 Bcfe per well

•         0.22 net Bcfe @80% NRI

•         D&C cost of $234K per well

•         Development cost of $1.06/Mcfe

NECO Field Area, Eastern DJ Basin, Colorado

        2007 Plan

•         Drill 141 wells, PDC 100% WI

•         31 Bcfe added by drilling

•         $33 Million D&C cost

•         4.5 Bcfe net production for 2007

•         44% increase over 2006

•         Acquiring 50 square miles of additional 3D seismic

•         Potential addition of 100-200 locations

•         Anticipate incremental 5 MMcf/d takeaway capacity in area from Cheyenne-Plains pipeline project

Horizontal Bakken and Nesson Projects, Western Williston Basin, North Dakota

        Bakken

•         6 wells drilled to date (3.8 net)

§         4 in production

•         Gross production 350 Boe/d

•         Net Company production 275 Boe/d

•         54,285 Acres available for drilling

        Nesson

•         10 wells drilled to date (2.7 net)

§         7 in production

•         Gross production 420 Boe/d

•         Net Company production 130 Boe/d

•         35,331 Acres available for drilling

Horizontal Bakken and Nesson Projects, Western Williston Basin, North Dakota

                                                        Bakken                 Nesson

        Reserves per well                 200 MBoe              95 MBoe

        Net reserves                          160 MBoe              76 MBoe

        D&C Costs                            $4.5 Million           $2.9 Million

        Development Costs             $28 / Boe                $38 /Boe

•         PDC and other operators working to determine:

§         Optimum horizontal well design, length, orientation and number of legs

§         Efficient stimulation design

§         Define where it works and why

•         Achieving answers impacts future success

Horizontal Bakken and Nesson Projects, Western Williston Basin, North Dakota

                                                                Bakken         Nesson

        2007 Drilling                          6                      7

        Net Wells (PDC37%)                   2.2                   2.6

        Reserves Added by Drilling       355 MBoe      197 MBoe

        D&C Cost                                      $10 Million    $7.5 Million

        2007E Net Production                  138 MBoe      103 MBoe

        Increase from 2006                       28%                77%

Appalachian and Michigan Operation Areas

                                                                                Appalachian Michigan

Operated Wells                                            1455                        204

2006 YE Proved Reserves                           35.1 Bcfe                19.6 Bcfe

2007 Acquisition Proved Reserves*         30.1 Bcfe                4.6 Bcfe

        % of 2006 YE Proved                           85%                        23%       

2007E Production E*                                   2.6 Bcfe                  1.8 Bcfe

Increase from 2006*                                     86%                        20%

        *  2007 Reserve and production increase due to purchase of Partnership interests

Recap

•         2007 will be a busy year

§         Drilling 419 wells

§         Re-frac and/or re-completions on 164 wells

•         Production increasing to 100 MMcfe (net) per day by year end

§         88% increase over year end 2006

§         Annualized rate of 36 Bcfe

•         Proved reserves increase by >50% during year

Reserves (Projected)

                                YE 2006                YE 2007E

        Total              323                 >500

        Producing     148                 270

•         129 Bcfe Proved Reserves added through 1031 acquisitions (1/17/07)

•         YE 2007 PDP reserves an increase of 82% over YE 2006

Increasing Production - Projected 2007

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Petroleum Development Corporation

NASDAQ Oil and Gas Conference

London, England

Presenter:  Steven R. Williams, CEO

March 6, 2007