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)  February 22, 2005

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.)

103 East Main Street; Bridgeport, WV    26330

(Address of Principal Executive Offices)

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

no change

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

  

Item 701.                Regulation FD Disclosure.

On February 18, 2005, Thomas E. Riley, President of  the Company made a presentation at the C.K. Cooper & Co. Small-Cap Oil and Gas Conference held in Palm Desert, CA.  The transcript of Mr. Riley's presentation follows.

Slide 1

C. K. Cooper & Company
Small Cap Oil & Gas Conference
February 18, 2005

Slide 2

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.

Slide 3

Financial Highlights

4      2004 Earnings Release - Tuesday, March 15, 2005

4      Conference Call - Thursday, March 17, 2005 at 11:00 AM EST

4      Record 2004 results anticipated

4      Revenue

4      Net income

4      Adjusted cash flow*

4      Year-end long-term debt at $21 million down from $53 million

4      Total capital expenditures of $ $26.5 million for 9 months

4      Includes PDC investment in first three 2004 partnerships of $14.4 million

4      Investment in fourth partnership was $7.7 million (4th Qtr)

4      Additional 4th Qtr investments in non-partnership drilling and recompletions

*Adjusted Cash Flow is Net Income plus non-cash charges (Depreciation, Depletion and Amortization and Deferred Income Taxes)

Slide 4

Major Sources and Uses of Cash

4      Sources (9 months)

4      Adjusted Cash Flow* from Operations- $47.9 million

4      Uses (9 months)

4      Drilling and development- $26.5 million

4      Debt retirement- $26 million

4      Stock Repurchase- $2.7 million

*Adjusted Cash Flow is Net Income plus non-cash charges (Depreciation, Depletion and Amortization and Deferred Income Taxes)       

Slide 5

2005 Capital Budget

4      2005 Capital Budget is set at $108 million

4      $80 million for exploration and development

4      $10 million for lease acquisition

4      $18 million for infrastructure projects

4      Wattenberg and Grand Valley Fields

4      Continue development in conjunction with public drilling partnerships

4      $115 million of partnership units to be offered

4      Continue recompletion program (non-partnership activity)

4      NECO (Eastern D-J Basin)

4      Non-partnership activity

4      Continue drilling infill wells

4      70-75 wells planned

4      Sand Wash Basin

4      Non-partnership activity

4      Legacy Project - testing will resume in late second quarter on exploratory well

4      Coffeepot Springs Project - 13,500 feet exploratory well underway

Slide 6

Revenue

4      Third Quarter Revenue of $73.2 million compared to $47.2 million in 2003

4      $218.1 million for 9 months vs. $143.4 million in 2003

4      Revenue reflects higher O&G prices, increased production and drilling activity

Slide 7

Net Income

4      Third Quarter Net Income of $8.7 million compared to $5.2 million in 2003

4      $25.7 million for 9 months compared to $14.6 million
in 2003

4      Third Quarter EPS of $0.52 compared to $0.31 in 2003 (diluted)

4      $1.56 for 9 months vs. $0.90 in 2003

4      73.3% increase in EPS

Slide 8

Adjusted Cash Flow

4      Third Quarter 2004 Adjusted Cash Flow of $16.1 million compared to $11.1 million
in 2003

4      Nine month adjusted cash flow $47.9 million in 2004 vs.
$30.2 million in 2003

4      Adjusted Cash Flow is  income before deferred income taxes, depreciation, depletion and amortization

4      Management believes Adjusted Cash Flow is a useful measure in estimating the value of the Company's operations

Slide 9

Other Recent News

4      Sale of portion of undeveloped lease in 2005

4      Located in Garfield County, CO (Piceance Basin)

4      Results in additional net income of approximately $0.20 per fully diluted share in first quarter 2005

4      Consisted of half leasehold interest (checkerboard)

4      Requires purchaser to drill a number of wells over a period of time or lease will revert to PDC

4      Will help evaluate remaining lease position

Slide 10

2004 Operating Highlights

4      Production 3.1 Bcfe in third quarter

4      9 month production of 9.5 Bcfe

4      Rocky Mountain Region production was the major factor in the increase

4      158 wells drilled in 2004 vs. 110 in 2003

4      97 successful wells and four dry holes in Wattenberg field (90 in 2003)

4      36 successful wells in the Piceance Basin (20 in 2003)

4      One Sand Wash Basin exploratory well

4      42 additional Codell recompletions in 2004

4      20 NECO infill development wells

Slide 11

Production

4      Third Quarter 2004 production of 3.1 Bcfe

4      Up 9% from 2.86 Bcfe in  third quarter of 2003

4      Year to date production of 9.49 Bcfe vs. 7.31 Bcfe in 2003

4      82% natural gas

4      Year-to-year comparison reflects positive impact of investment activities

4      Acquisitions

4      Recompletions

4      Drilling

Slide 12

Core Operating Areas

Rocky Mountains

2004  9 Month Production: 6.8 Bcfe

2003 Proved Reserves: 131.6 Bcfe

2003 Production: 6.6 Bcfe

2002 Production: 3.5 Bcfe

Michigan Basin

2004 9 Month Production: 1.3 Bcfe

2003 Proved Reserves: 25.6 Bcfe

2003  Production:  1.9 Bcfe

2002 Production: 2.2 Bcfe

Appalachian Basin

2004 9 Month Production: 1.4 Bcfe

2003 Proved Reserves: 42.0 Bcfe

2003 Production:  1.9 Bcfe

2002 Production: 2.1 Bcfe

Slide 13

Quarterly Production Trends

Appalachian

Michigan

Rocky Mountain

                1st           2nd         3rd          4th          1st           2nd         3rd          4th          1st           2nd         3rd          4th          1st           2nd         3rd                 4th          1st           2nd         3rd          4th          1st           2nd         3rd

Appalachian         0.628       0.615       0.606       0.651       0.659       0.59         0.652       0.623       0.597       0.564       0.549       0.571       0.541       0.523                0.532       0.534       0.509       0.476       0.492       0.467       0.464       0.438       0.468

Michigan               0.135       0.171       0.28         0.375       0.519       0.548       0.607       0.642       0.625       0.627       0.629       0.603       0.582       0.555                0.54         0.519       0.496       0.457       0.459       0.461       0.451       0.437       0.452

Rocky Mountains                0              0              0              0.037       0.171       0.348       0.504       0.527       0.51         0.542       0.685       0.75         0.837                0.902       0.852       0.905       0.978       1.535       1.907       2.21         2.332       2.248       2.195

Slide 14

Sustaining Growth

4      Strong partnership sales will continue to fund drilling revenue in second and third quarters

4      $26.5 million partnership drilling carryover at end of third quarter

4      Fourth 2004 partnership closed with $35 million in subscriptions in early October

4      Total partnership sales of $100 million in 2004, up from record $78.3 million in 2003. $115 million planned for 2005

4      First 2005 partnership closed with $40 million in subscriptions in early February

4      Favorable year-to-year production comparison likely to continue

4      Futures prices currently reflect expectations for continuing high prices through 2005

4      Strong balance sheet allows ample funding for additional drilling and acquisitions if available

Slide 15

PDC Overview

4      Business Segments

4      Oil and gas well drilling

4      Oil and gas production and sales

4      Natural gas marketing

4      Well operations

Slide 16

Oil and Gas Well Drilling

4      "Service" business

4      Raise money through public partnerships

4      140 NASD broker/dealers

4      Sold by financial planners

4      $100 million sold in 2004

4      $115 million planned for 2005

4      First 2005 partnership received orders for $40 million in 48 hours

4      73 partnerships and over 28,000 investors

4      PDC earns profit for managing drilling and completion activity

4      Other benefits

4      Scale economies

4      Prospect access

4      "Growth accelerator"

4      Only PDC interest in partnership is included in PDC financial reports

Slide 17

Oil and Gas Production

4      Production from PDC interest in wells

4      Includes production from over 2700 wells in three production regions

4      For 2004 70% of production is in Rocky Mountain region

4      Rockies also focus of drilling and acquisition efforts

4      PDC owns average working interest of approximately 50% overall (ranging from 10-100%)

4      80%+ natural gas

4      2003 reserves 199 Bcfe, 76% proved developed

4      2003 production 10.4 Bcfe

4      2004 9 month production 9.49 Bcfe

Slide 18

Natural Gas Marketing

4      "Service" business

4      Subsidiary Riley Natural Gas markets gas for approximately 100 Appalachian Basin producers

4      Also provides marketing services for PDC in all operating areas

4      Contracts

4      Nominations

4      Balancing

4      Narrow margin business, although margins have improved

Slide 19

Well Operations

4      "Service" Business

4      Charge for operating portion of well not owned by PDC

4      Stable predictable business- bills get paid before owners

4      Growing with addition of partnership well operations

4      Operating over 2700 wells

Slide 20

PDC Colorado Development Areas

[Map of CO area]

Slide 21

2004 Drilling Results/2005 Drilling Plans

4      Rockies: Plan development drilling in Wattenberg Field, Denver Basin and Grand Valley Field, Piceance Basin

4      158 wells drilled through 12/31/04

4      4 dry holes

4      Estimate approximately 120 to 130  wells to be drilled in 2005

4      Drilled exploratory Sand Wash Basin test in Moffat County, CO

4      Several additional exploratory wells planned in Sand Wash Basin in NW Colorado and SW Wyoming

4      Continue search for additional development opportunities in the Rocky Mountain Region

Slide 22

Wattenberg Field

4      Through December 2004, drilled over 380 successful wells and only six dry holes.

4      27 Successful wells drilled to date in 2005 with zero dry holes.

4      Estimate approximately 87 wells to be drilled in calendar 2005

4      Current prospect inventory of more than 100 drilling locations.

4      Ongoing lease evaluation and acquisition program to secure additional drilling prospects.

Slide 23

Grand Valley Field

4      Through December 2004 PDC drilled over 90 successful wells with one dry hole.

4      6 successful wells drilled to date in 2005.

4      Estimate approximately 40 wells to be drilled in calendar 2005.

4      Approximately 14,000 acres available to develop.

4      Several hundred undeveloped locations.  Many more with increased well density.

Slide 24

NECO Down-Spacing

4      Decreasing Niobrara spacing to 40 acres from 80 acres creating approximately 100 additional developmental infill locations.

4      Approximately 20 wells were drilled in the fourth quarter 2004 and early 2005.

4      Estimate approximately 70 - 75 wells to be drilled in calendar 2005 if production results continue to meet expectations.

Slide 25

Sand Wash Basin

4      Located in Moffat county approximately 40 miles northwest of Craig, CO

4      Legacy Project

4      Well TD'ed October 27 at 12,778'

4      Preliminary testing conducted in late December and early January

4      Testing suspended due to Federal lease restrictions preventing use of heavy equipment in winter and spring months

4      Testing will resume late second quarter

4      Coffeepot Springs Project

4      Testing Upper Cretaceous Sands to a depth of         approximately 13,500'

4      Estimated Well cost is approximately $2.5 million

4      Spudded Coffeepot Springs February 3, 2005.

Slide 26

C. K. Cooper & Company
Small Cap Oil & Gas Conference
February 18, 2005

NASDAQ: PETD

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  February 22,  2005             

By  /s/ Darwin L. Stump                                  

        Darwin L. Stump

        Chief Financial Officer