CONFORMED COPY

**UNITED STATES**

**SECURITIES ANDEXCHANGE COMMISSION**

Washington, D.C.20549

**FORM 10-Q**

[X] Quarterly ReportPursuant to Section 13 or 15(d) of

the SecuritiesExchange Act of 1934

For the period endedSeptember 30, 2005

**OR**

[ ] TransitionReport Pursuant to Section 13 of 15(d) of

the SecuritiesExchange Act of 1934

For the transitionperiod from         to

Commission filenumber 0-7246

I.R.S. EmployerIdentification Number 95-2636730

**PETROLEUMDEVELOPMENT CORPORATION**

**(A NevadaCorporation)**

**103 East Main Street**

**Bridgeport, WV 26330**

**Telephone: (304)842-6256**

Indicate by check mark whether the registrant (1) hasfiled all reports required to be filed by Section 13 or 15(d) of the SecuritiesExchange Act of 1934 during the preceding 12 months (or for such shorter periodthat the registrant was required to file such reports), and (2) has beensubject to such filing requirements for the past 90 days.  Yes       No XX       

Indicate the number of shares outstanding of each of theissuer's classes of common stock, as of the latest practicable date: 

16,272,028 shares of the Company's Common Stock ($.01 parvalue) were outstanding as of November 30, 2005.

Indicate by check mark whether the registrant is anaccelerated filer (as definition in Rule 12b-2 of the Exchange Act). Yes  XX  No           

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PETROLEUMDEVELOPMENT CORPORATION AND SUBSIDIARIES

INDEX

|                                                                                                         |                                                                                                                             |          |
|---------------------------------------------------------------------------------------------------------|-----------------------------------------------------------------------------------------------------------------------------|----------|
|                                                                                                         |                                                                                                                             |
|                                                                                                         |                                                                                                                             | Page No. |
|                                                                                                         |                                                                                                                             |          |
| Explanatory Note - 2005 Restatement

PART I - FINANCIAL INFORMATION

Item 1.  Financial Statements | 1                                                                                                                           |
|                                                                                                         |                                                                                                                             |          |
|                                                                                                         | Report of Independent Registered Public Accounting Firm                                                                     | 2        |
|                                                                                                         |                                                                                                                             |          |
|                                                                                                         | Condensed Consolidated Balance Sheets -

September 30, 2005 (Unaudited) and December 31, 2004  (Restated)                   |  3  |
|                                                                                                         |                                                                                                                             |          |
|                                                                                                         |                                                                                                                             |          |
|                                                                                                         | Condensed Consolidated Statements of Income -

Three Months and Nine Months Ended September 30, 2005 

and 2004 (Unaudited) |  5  |
|                                                                                                         |                                                                                                                             |          |
|                                                                                                         |                                                                                                                             |          |
|                                                                                                         | Condensed Consolidated Statements of Cash Flows-Nine  Months

Ended September 30, 2005 and 2004 (Unaudited)                 |  6  |
|                                                                                                         |                                                                                                                             |          |
|                                                                                                         |                                                                                                                             |          |
|                                                                                                         | Notes to Condensed Consolidated Financial Statements                                                                        |  7  |
|                                                                                                         |                                                                                                                             |          |
|  Item 2.                                                                                           | Management's Discussion and Analysis of Financial 

Condition and Results of Operations                                     | 11       |
|                                                                                                         |                                                                                                                             |          |
|  Item 3.                                                                                           | Quantitative and Qualitative Disclosure About Market  Risk                                                                  | 28       |
|                                                                                                         |                                                                                                                             |          |
|  Item 4.                                                                                           | Controls and Procedures                                                                                                     | 30       |
|                                                                                                         |                                                                                                                             |          |
| PART II                                                                                                 | OTHER INFORMATION                                                                                                           | 32       |
|                                                                                                         |                                                                                                                             |          |
|                                                                                                         |                                                                                                                             |          |

----

Explanatory Note -2005 Restatement

As described in our Amended Annual Report on Form 10-K/Afor the year ended December 31, 2004 and our Amended Quarterly Report on Form10-Q/A for the three months ended March 31, 2005, we restated certain financialstatements and other information, including such statements and information foreach of the quarters of 2004 and the quarter ended March 31, 2005. Theserestatements related to our accounting for derivative transactions, certain aspectsof the Company's oil and gas property accounting, asset retirement obligationsand accounting for income taxes.

1

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PART I - FINANCIALINFORMATION

Report ofIndependent Registered Public Accounting Firm

The Board of Directors

Petroleum Development Corporation:

                          We have reviewed the accompanying condensed consolidated balance sheet ofPetroleum Development Corporation and subsidiaries as of September 30, 2005,the related condensed consolidated statements of income for the three-month andnine-month periods ended September 30, 2005 and 2004, and the related condensedconsolidated statements of cash flows for the nine-month periods endedSeptember 30, 2005 and 2004. These condensed consolidated financial statementsare the responsibility of the Company's management.

                          We conducted our review in accordance with the standards of the Public CompanyAccounting Oversight Board (United States).  A review of interim financialinformation consists principally of applying analytical review procedures andmaking inquiries of persons responsible for financial and accountingmatters.  It is substantially less in scope than an audit conducted inaccordance with the standards of the Public Company Accounting Oversight Board(United States), the objective of which is the expression of an opinionregarding the financial statements taken as a whole.  Accordingly, we donot express such an opinion.

                          Based on our review, we are not aware of any material modifications that shouldbe made to the condensed consolidated financial statements referred to abovefor them to be in conformity with U. S. generally accepted accounting principles.

                          We have previously audited, in accordance with standards of Public CompanyAccounting Oversight Board (United States), the consolidated balance sheet ofPetroleum Development Corporation and subsidiaries as of December 31, 2004, andthe related consolidated statements of income, stockholders' equity and cashflows for the year then ended (not presented herein); and in our report datedMarch 30, 2005, except as to the restatement discussed in Note 22 to theconsolidated financial statements which is as of December 2, 2005, we expressedan unqualified opinion on those consolidated financial statements. As discussedin that report, the consolidated financial statements as of December 31, 2004and 2003, and for each of the years in the three year period ended December 31,2004 have been restated and the report also included an explanatory paragraphreferring to a change in accounting for asset retirement obligations in 2003.In our opinion, the information set forth in the accompanying condensed consolidatedbalance sheet as of December 31, 2004 is fairly stated, in all materialrespects, in relation to the consolidated balance sheet from which it has beenderived.

As discussed in notes 21 and 22 to the Company's Form 10-K/Aas of December 31, 2004, the Company has restated the condensed consolidatedbalance sheet as of December 31, 2004 and the condensed consolidated statementsof income and cash flows for the three and nine month periods ended September30, 2004.

KPMG LLP

Pittsburgh, Pennsylvania

January 11, 2006

2

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PETROLEUM DEVELOPMENT CORPORATION ANDSUBSIDIARIES

Condensed Consolidated Balance Sheets

September 30, 2005 and December 31, 2004

|                                                                  |  |                                                                         |  |                                                             |
|------------------------------------------------------------------|--|-------------------------------------------------------------------------|--|-------------------------------------------------------------|
|                                                                  |  |                                                                         |  |                                                             |
|                                                                  |  |                                                                         |  |                                                             |
| ASSETS                                                           |  | 2005                                                                    |  | 2004                                                        |
|                                                                  |  | (Unaudited)                                                             |  | (Restated)                                                  |
|                                                                  |  |                                                                         |  |                                                             |
| Current  assets:                                                 |  |                                                                         |  |                                                             |
|  Cash  and cash equivalents                                 |  |  $       64,801,600                       |  |  $     77,735,300                       |
|    Accounts and notes receivable                            |  |           56,143,500            |  |         36,065,300            |
|    Inventories                                              |  |             7,831,600 |  |           1,657,300 |
|  Prepaid  expenses                                          |  |           25,529,000            |  |           9,878,900 |
|                                                                  |  |                                                                         |  |                                                             |
|       Total current assets                   |  |         154,305,700                       |  |       125,336,800                       |
|                                                                  |  |                                                                         |  |                                                             |
|                                                                  |  |                                                                         |  |                                                             |
|                                                                  |  |                                                                         |  |                                                             |
| Properties and  equipment                                        |  |         343,349,100                       |  |       299,748,700                       |
|  Less accumulated  depreciation, depletion and amortization |  |         105,413,600                       |  |         92,165,400            |
|                                                                  |  |         237,935,500                       |  |       207,583,300                       |
|                                                                  |  |                                                                         |  |                                                             |
| Other assets                                                     |  |             4,390,100 |  |           2,108,200 |
|                                                                  |  |                                                                         |  |                                                             |
|                                                                  |  |  $     396,631,300                                  |  |  $   335,028,300                                  |
|                                                                  |  |                                                                         |  |                                                             |

(Continued)

3

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PETROLEUM DEVELOPMENT CORPORATION ANDSUBSIDIARIES

Condensed Consolidated Balance Sheets,Continued

September 30, 2005 and December 31, 2004

|                                                                                   |  |                                                                                                           |  |                                                                                                           |
|-----------------------------------------------------------------------------------|--|-----------------------------------------------------------------------------------------------------------|--|-----------------------------------------------------------------------------------------------------------|
| LIABILITIES AND STOCKHOLDERS' EQUITY                                              |  | 2005                                                                                                      |  | 2004                                                                                                      |
|                                                                                   |  | (Unaudited)                                                                                               |  | (Restated)                                                                                                |
|                                                                                   |  |                                                                                                           |  |                                                                                                           |
| Current liabilities:                                                              |  |                                                                                                           |  |                                                                                                           |
|    Accounts payable and accrued expenses                                     |  |  $        115,286,600                                                  |  |  $          69,696,600                                       |
|    Advances for future drilling contracts                                    |  |              24,847,500                            |  |              42,497,300                            |
|  Funds  held for future distribution                                         |  |              18,933,200                            |  |              12,911,800                            |
|                                                                                   |  |                                                                                                           |  |                                                                                                           |
|          Total current liabilities             |  |            159,067,300                                       |  |            125,105,700                                       |
|                                                                                   |  |                                                                                                           |  |                                                                                                           |
|                                                                                   |  |                                                                                                           |  |                                                                                                           |
| Long-term debt                                                                    |  |              14,000,000                            |  |              21,000,000                            |
| Other  liabilities                                                                |  |              10,623,500                            |  |                3,927,500                 |
| Deferred  income taxes                                                            |  |              29,660,200                            |  |              22,976,300                            |
| Asset retirement  obligations                                                     |  |                8,187,100                 |  |                7,998,200                 |
|                                                                                   |  |                                                                                                           |  |                                                                                                           |
|                                                                                   |  |                                                                                                           |  |                                                                                                           |
| Stockholders'  equity:                                                            |  |                                                                                                           |  |                                                                                                           |
|  Common  stock par value $0.01 per share;                                    |  |                                                                                                           |  |                                                                                                           |
|     authorized 50,000,000 shares; issued                                |  |                                                                                                           |  |                                                                                                           |
|     and outstanding 16,272,028 shares and                               |  |                                                                                                           |  |                                                                                                           |
|     16,589,824 shares                                                   |  |                   162,700 |  |                   165,800 |
|    Additional paid-in capital                                                |  |              30,211,400                            |  |              37,684,300                            |
|    Retained earnings                                                         |  |            145,576,800                                       |  |            117,052,500                                       |
|    Unamortized stock award                                                   |  |                 (857,700)           |  |                 (882,000)           |
|                                                                                   |  |                                                                                                           |  |                                                                                                           |
|          Total stockholders' equity            |  |            175,093,200                                       |  |            154,020,600                                       |
|                                                                                   |  |                                                                                                           |  |                                                                                                           |
|                                                                                   |  |  $        396,631,300                                                  |  |  $        335,028,300                                                  |
|                                                                                   |  |                                                                                                           |  |                                                                                                           |
|                                                                                   |  |                                                                                                           |  |                                                                                                           |
| See accompanying notes to unaudited condensed  consolidated financial statements. |
|                                                                                   |  |                                                                                                           |  |                                                                                                           |

4

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PETROLEUM DEVELOPMENT CORPORATION ANDSUBSIDIARIES

Condensed Consolidated Statements ofIncome

Three Months and Nine Months EndedSeptember 30, 2005 and 2004

(Unaudited)

|                                                                                   |
|-----------------------------------------------------------------------------------|
|                                                                                   |  | Three Months Ended |  | Nine Months Ended |
|                                                                                   |  | September 30, |  | September 30, |
|                                                                                   |  | 2005 |  | 2004 |  | 2005 |  | 2004 |
|                                                                                   |  |  |  | (Restated) |  |  |  | (Restated) |
| Revenues:                                                                         |  |  |  |  |  |  |  |  |
|  Oil and  gas well drilling operations                                       |  | $       39,710,600 |  |  $       30,394,400 |  |  $       108,118,300 |  |  $       89,347,500 |
|  Gas  sales from marketing activities                                        |  |          14,970,300 |  |           22,630,200 |  |             58,409,400 |  |           69,643,400 |
|  Oil and  gas sales                                                          |  |          28,413,400 |  |           16,580,500 |  |             68,619,900 |  |           49,105,700 |
|  Well  operations and pipeline income                                        |  |            2,483,300 |  |             2,073,800 |  |               6,840,100 |  |             5,823,700 |
|  Other  income                                                               |  |               209,400 |  |                589,000 |  |               9,996,000 |  |             1,334,100 |
|       Total revenues                                          |  |          85,787,000 |  |           72,267,900 |  |           251,983,700 |  |         215,254,400 |
|                                                                                   |  |  |  |  |  |  |  |  |
| Cost and  expenses:                                                               |  |  |  |  |  |  |  |  |
|  Cost of  oil and gas well drilling operations                               |  |          36,177,500 |  |           26,005,400 |  |             95,112,200 |  |           76,328,400 |
|  Cost of  gas marketing activities                                           |  |          14,269,500 |  |           22,047,400 |  |             58,348,400 |  |           68,542,900 |
|  Oil and  gas production and                                                 |  |  |  |  |  |  |  |
|        well operations cost                              |  |            6,455,400 |  |             3,952,400 |  |             15,356,700 |  |           11,894,500 |
|    Exploratory dry hole costs                                                |  |               135,800 |  |  - |  |               5,382,800 |  |  - |
|  General  and administrative expenses                                        |  |            1,645,500 |  |                926,300 |  |               4,529,000 |  |             2,821,400 |
|    Depreciation, depletion and amortization                                  |  |            5,120,000 |  |             4,312,300 |  |             14,822,000 |  |           13,308,000 |
|       Total expenses                                          |  |          63,803,700 |  |           57,243,800 |  |           193,551,100 |  |         172,895,200 |
|                                                                                   |  |  |  |  |  |  |  |  |
|  Income  from operations                                                     |  |          21,983,300 |  |           15,024,100 |  |             58,432,600 |  |           42,359,200 |
|    Interest expense                                                          |  |              142,200 |  |                223,100 |  |                  433,000 |  |                627,100 |
|  Oil and  gas price risk management loss, net                                |  |            9,922,300 |  |             2,378,800 |  |             12,723,000 |  |             4,077,500 |
|                                                                                   |  |  |  |  |  |  |  |  |
|  Income  before income taxes                                                 |  |          11,918,800 |  |           12,422,200 |  |             45,276,600 |  |           37,654,600 |
|  Income  taxes                                                               |  |            4,413,000 |  |             4,506,400 |  |             16,752,300 |  |           13,596,200 |
|                                                                                   |  |  |  |  |  |  |  |  |
|  Net  income                                                                 |  | $         7,505,800 |  |  $         7,915,800 |  |  $         28,524,300 |  |  $       24,058,400 |
|                                                                                   |  |  |  |  |  |  |  |  |
|  Basic  earnings per common share                                            |  | $                  0.46 |  |  $                  0.49 |  |  $                    1.74 |  |  $                  1.50 |
|  Diluted  earnings per share                                                 |  | $                  0.46 |  |  $                  0.47 |  |  $                    1.73 |  |  $                  1.45 |
|                                                                                   |  |  |  |  |  |  |  |  |
| See accompanying notes to unaudited condensed  consolidated financial statements. |

5

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PETROLEUM DEVELOPMENT CORPORATION ANDSUBSIDIARIES

Condensed Consolidated Statements of CashFlows

Nine Months Ended September 30, 2005 and2004

(Unaudited)

|                                                                                               |  | 2005                                                                                                                                    |  | 2004(a)                                                                                     |
|-----------------------------------------------------------------------------------------------|--|-----------------------------------------------------------------------------------------------------------------------------------------|--|---------------------------------------------------------------------------------------------|
|                                                                                               |  |                                                                                                                                         |  | (Restated)                                                                                  |
| Cash flows  from operating activities:                                                        |  |                                                                                                                                         |  |                                                                                             |
|  Net  income                                                                             |  |  $    28,524,300                                                                                                         |  |  $    24,058,400                                                             |
|    Adjustments to net income to reconcile to cash                                        |  |                                                                                                                                         |  |                                                                                             |
|     provided by operating activities:                                               |  |                                                                                                                                         |  |                                                                                             |
|    Deferred income taxes                                                                 |  |          6,683,900                                                                                   |  |          7,670,500                                       |
|    Depreciation, depletion and amortization                                              |  |        14,822,000                                                                                              |  |        13,308,000                                                  |
|    Unrealized loss on derivative transactions                                            |  |          9,416,200                                                                                   |  |          2,592,900                                       |
|    Accretion of asset retirement obligation                                              |  |             344,500                                                                   |  |             322,600                       |
|    Exploratory dry hole costs                                                            |  |          5,382,800                                                                                   |  | -                                                                  |
|  Gain  from sale of assets                                                               |  |         (7,869,800)                                                                                       |  |               (5,300)           |
|    Leasehold acreage expired or surrendered                                              |  |              12,900                                                              |  |             291,000                       |
|    Amortization of stock award                                                           |  |             427,100                                                                   |  |                 2,800 |
|    Increase in current assets                                                            |  |       (17,360,800)                                                                                                  |  |        (3,301,300)                                                 |
|    Increase in other assets                                                              |  |         (1,205,200)                                                                                       |  |           (161,800)                                 |
|    Increase (decrease) in current liabilities                                            |  |          6,042,800                                                                                   |  |      (15,078,500)                                                            |
|    (Decrease) increase in other liabilities                                              |  |            (462,600)                                                                       |  |             562,000                       |
|                                                                                               |  |                                                                                                                                         |  |                                                                                             |
|         Total adjustments                                       |  |        16,233,800                                                                                              |  |          6,202,900                                       |
|                                                                                               |  |                                                                                                                                         |  |                                                                                             |
|           Net cash provided by operating activities   |  |        44,758,100                                                                                              |  |        30,261,300                                                  |
|                                                                                               |  |                                                                                                                                         |  |                                                                                             |
| Cash flows  from investing activities:                                                        |  |                                                                                                                                         |  |                                                                                             |
|  Capital  expenditures                                                                   |  |       (53,968,800)                                                                                                  |  |      (26,458,100)                                                            |
|    Proceeds from sale of leases to partnerships                                          |  |          1,575,100                                                                                   |  |          1,178,800                                       |
|    Proceeds from sale of fixed assets                                                    |  |          9,580,700                                                                                   |  |               68,900            |
|                                                                                               |  |                                                                                                                                         |  |                                                                                             |
|           Net cash used in investing activities       |  |       (42,813,000)                                                                                                  |  |      (25,210,400)                                                            |
|                                                                                               |  |                                                                                                                                         |  |                                                                                             |
| Cash flows  from financing activities:                                                        |  |                                                                                                                                         |  |                                                                                             |
|  Net  retirement of long-term debt                                                       |  |         (7,000,000)                                                                                       |  |      (26,000,000)                                                            |
|    Proceeds from stock option exercises                                                  |  |                         - |  |          2,178,600                                       |
|    Repurchase and cancellation of treasury stock                                         |  |         (7,878,800)                                                                                       |  |        (2,749,100)                                                 |
|                                                                                               |  |                                                                                                                                         |  |                                                                                             |
|            Net cash used in financing activities |  |       (14,878,800)                                                                                                  |  |      (26,570,500)                                                            |
|                                                                                               |  |                                                                                                                                         |  |                                                                                             |
| Net decrease  in cash and cash equivalents                                                    |  |       (12,933,700)                                                                                                  |  |      (21,519,600)                                                            |
|                                                                                               |  |                                                                                                                                         |  |                                                                                             |
| Cash and cash  equivalents, beginning of period                                               |  |        77,735,300                                                                                              |  |        80,379,300                                                  |
|                                                                                               |  |                                                                                                                                         |  |                                                                                             |
| Cash and cash  equivalents, end of period                                                     |  |  $    64,801,600                                                                                                         |  |  $    58,859,700                                                             |
|                                                                                               |  |                                                                                                                                         |  |                                                                                             |

            See accompanying notes to unaudited condensed consolidated financialstatements.

a. Only certainindividual line items within cash provided by operating activities have beenrestated. Net cash provided by operating activities is the same as the original10-Q filing.

6

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PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to CondensedConsolidated Financial Statements

September 30, 2005

(Unaudited)

1.     Accounting Policies

Reference is herebymade to Petroleum Development Corporation and Subsidiaries' (the Company)Annual Report on Form 10-K/A for 2004, which contains a summary of significantaccounting policies followed by the Company in the preparation of itsconsolidated financial statements. These policies were also followed inpreparing the quarterly report included herein. 

As described in ourAmended Annual Report on Form 10-K/A for the year ended December 31, 2004 andour Amended Quarterly Report on Form 10-Q/A for the three months ended March31, 2005, we restated certain financial statements and other information,including such statements and information for each of the quarters of 2004 andthe quarter ended March 31, 2005. These restatements related to our accountingfor derivative transactions, certain aspects of the Company's oil and gasproperty accounting, asset retirement obligations and accounting for incometaxes.

2.     Stock Compensation

The Company applies the intrinsic-valuebased method of accounting prescribed by Accounting Principles Board (APB)Opinion No. 25, "Accounting for Stock Issued to Employees", andrelated interpretations including FASB Interpretation No. 44, "Accountingfor Certain Transactions involving Stock Compensation, an interpretation of APBOpinion No. 25", to account for its fixed-plan stock options.  Underthis method, compensation expense is recorded on the date of grant only if thecurrent market price of the underlying stock exceeded the exercise price. FASB Statement No. 123, "Accounting for Stock-Based Compensation" andFASB Statement No. 148, "Accounting for Stock Based Compensation-Transition and Disclosure, an amendment of FASB Statement No. 123",established accounting and disclosure requirements using a fair-value-basedmethod of accounting for stock-based employee compensation plans.  Aspermitted by existing accounting standards, the Company has elected to continueto apply the intrinsic-value-based method of accounting described above, andhas adopted only the disclosure requirements of Statement 123, as amended andStatement 148.  If the fair-value-based method had been applied to alloutstanding and unvested awards in each period, the impact for the nine monthsof 2005 would have been $71,400. There would have been no impact on reportednet income in 2004.

|                                                  |  | Three Months Ended                                                              |  | Nine Months Ended                                                                                     |
|--------------------------------------------------|--|---------------------------------------------------------------------------------|--|-------------------------------------------------------------------------------------------------------|
|                                                  |  | September 30,                                                                   |  | September 30,                                                                                         |
|                                                  |  | 2005                                                                            |  | 2004                                                                                                  |  | 2005 |  | 2004 |
|                                                  |  |                                                                                 |  | (Restated)                                                                                            |  |  |  | (Restated) |
|                                                  |  |                                                                                 |  | ** **                                                                                            |  |  |  | ** ** |
| Net income, as  reported                         |  |  $    7,505,800                                                  |  |  $     7,915,800                                                                  |  | $       28,524,300 |  | $      24,058,400 |
| Stock-based  employee compensation               |  |                                                                                 |  |                                                                                                       |  |  |  |  |
|     expenses included in reported net  |  |                                                                                 |  |                                                                                                       |  |  |  |  |
|     income, net of related tax effects |  |           106,900                       |  |                   600 |  |               269,100 |  |                  1,800 |
| Deduct total  stock-based employee               |  |                                                                                 |  |                                                                                                       |  |  |  |  |
|    compensation expense determined          |  |                                                                                 |  |                                                                                                       |  |  |  |  |
|     under fair-value based method      |  |                                                                                 |  |                                                                                                       |  |  |  |  |
|      for all rewards, net of tax  |  |        (130,700)                                       |  |                 (600)           |  |             (340,500) |  |                (1,800) |
|                                                  |  |                                                                                 |  |                                                                                                       |  |  |  |  |
| Pro forma net  income                            |  |  $    7,482,000                                                  |  |  $     7,915,800                                                                  |  | $       28,452,900 |  | $      24,058,400 |
|                                                  |  |                                                                                 |  |                                                                                                       |  |  |  |  |
| Basic earnings  per share as reported            |  |  $             0.46 |  |  $              0.49                 |  | $                  1.74 |  | $                 1.50 |
|                                                  |  |                                                                                 |  |                                                                                                       |  |  |  |  |
| Pro forma  basic earnings per share              |  |  $             0.46 |  |  $              0.49                 |  | $                  1.73 |  | $                 1.50 |
|                                                  |  |                                                                                 |  |                                                                                                       |  |  |  |  |
| Diluted  earnings per share as reported          |  |  $             0.46 |  |  $              0.47                 |  | $                  1.73 |  | $                 1.45 |
|                                                  |  |                                                                                 |  |                                                                                                       |  |  |  |  |
| Pro forma diluted  earnings per share            |  |  $             0.46 |  |  $              0.47                 |  | $                  1.73 |  | $                 1.45 |

7

----

On December 16, 2004, the FinancialAccounting Standards Board (FASB) issued FASB Statement No. 123R (revised2004), "Share-Based Payment" which is a revision of FASB StatementNo. 123, "Accounting for Stock-Based Compensation".  Statement123R supersedes APB opinion No. 25, "Accounting for Stock Issued toEmployees", and amends FASB Statement No. 95, "Statement of CashFlows".  Generally, the approach in Statement 123R is similar to theapproach described in Statement 123.  However, Statement 123R requires allshare-based payments to employees, including grants of employee stock options,to be recognized in the income statement based on their fair values. Pro-forma disclosure is no longer an alternative.  On April 14, 2005, theSEC amended the effective date of the provisions of this statement.  Theeffect of this amendment by the SEC is that we will have to comply withStatement 123R and use the Fair Value based method of accounting no later thanthe first quarter of 2006.  Management has not determined the impact thatthis statement will have on our consolidated financial statements. 

3.     Basis of Presentation

The Management ofthe Company believes that all adjustments (consisting of only normal recurringaccruals) necessary for a fair statement of the results of such periods havebeen made.  The results of operations for the nine months ended September30, 2005 are not necessarily indicative of the results to be expected for thefull year.

4.     Oil and Gas Properties

Oil and GasProperties are reported on the successful efforts method.

5.    Earnings Per Share

Computation ofearnings per common and common equivalent share are as follows for the threemonths and nine months ended September 30, 2005 and 2004.

|                                             |  | Three Months Ended                                                              |  | Nine Months Ended                                                   |
|---------------------------------------------|--|---------------------------------------------------------------------------------|--|---------------------------------------------------------------------|
|                                             |  | September 30,                                                                   |  | September 30,                                                       |
|                                             |  | 2005                                                                            |  | 2004                                                                |  | 2005 |  | 2004 |
|                                             |  |                                                                                 |  |                                                                     |  |  |  |  |
| Weighted  average common shares outstanding |  |      16,271,593                                                  |  |    16,284,827                                                  |  |       16,433,859 |  |       16,140,358 |
|                                             |  |                                                                                 |  |                                                                     |  |  |  |  |
| Weighted  average common and common         |  |                                                                                 |  |                                                                     |  |  |  |  |
|    equivalent shares outstanding       |  |      16,322,795                                                  |  |    16,694,637                                                  |  |       16,484,787 |  |       16,542,623 |
|                                             |  |                                                                                 |  |                                                                     |  |  |  |  |
|                                             |  |                                                                                 |  | (Restated)                                                          |  |  |  | (Restated) |
|       Net income        |  |  $    7,505,800                                                  |  |  $  7,915,800                                                  |  | $    28,524,300 |  | $    24,058,400 |
|                                             |  |                                                                                 |  |                                                                     |  |  |  |  |
| Basic earnings  per share                   |  |  $             0.46 |  |  $           0.49 |  | $               1.74 |  | $               1.50 |
|                                             |  |                                                                                 |  |                                                                     |  |  |  |  |
| Diluted  earnings per share                 |  |  $             0.46 |  |  $           0.47 |  | $               1.73 |  | $               1.45 |

 6.    Business Segments(Thousands)  

PDC's operatingactivities can be divided into four major segments: drilling and development, naturalgas marketing, oil and gas sales, and well operations and pipelineincome.  The Company drills natural gas wells for Company-sponsoreddrilling partnerships and retains an interest in each well.  Awholly-owned subsidiary, Riley Natural Gas, engages in the marketing of naturalgas to commercial and industrial end-users. The Company owns an interest inover 2,700 wells from which it derives oil and gas working interests. TheCompany charges Company-sponsored partnerships and other third parties competitiveindustry rates for well operations and gas gathering.  All materialinter-company accounts and transactions between segments have beeneliminated.  Segment information for the three and nine months endedSeptember 30, 2005 and 2004 is as follows: (All numbers presented below are inthousands.)

8

----

|                                                   |  | Three Months Ended                                                                        |  | Nine Months Ended                                                                         |
|---------------------------------------------------|--|-------------------------------------------------------------------------------------------|--|-------------------------------------------------------------------------------------------|
|                                                   |  | September 30,                                                                             |  | September 30,                                                                             |
|                                                   |  | 2005                                                                                      |  | 2004                                                                                      |  | 2005 |  | 2004 |
|                                                   |  |                                                                                           |  | (Restated)                                                                                |  |  |  | (Restated) |
| REVENUES                                          |  |                                                                                           |  |                                                                                           |  |  |  |  |
|    Drilling and Development                  |  |  $        39,710                                       |  |  $        30,394                                       |  |  $      108,118 |  |  $        89,347 |
|  Natural  Gas Marketing                      |  |            15,030                            |  |            22,641                            |  |            58,605 |  |            69,669 |
|  Oil and  Gas Sales                          |  |            28,414                            |  |            16,581                            |  |            68,620 |  |            49,106 |
|  Well  Operations and Pipeline Income        |  |              2,483                 |  |              2,074                 |  |              6,840 |  |              5,824 |
|    Unallocated amounts (1)                   |  |                 150 |  |                 578 |  |              9,801 |  |              1,308 |
|         Total       |  |  $        85,787                                       |  |  $        72,268                                       |  |  $      251,984 |  |  $      215,254 |
|                                                   |  |                                                                                           |  |                                                                                           |  |  |  |  |
| SEGMENT INCOME  (LOSS) BEFORE INCOME TAXES        |  |                                                                                           |  |                                                                                           |  |  |  |  |
|    Drilling and Development                  |  |  $          3,533                            |  |  $          4,389                            |  |  $        13,006 |  |  $        13,019 |
|  Natural  Gas Marketing                      |  |                 759 |  |                 591 |  |                 250 |  |              1,120 |
|  Oil and  Gas Sales(3)                       |  |              9,022                 |  |              7,136                 |  |            25,006 |  |            23,102 |
|  Well  Operations and Pipeline Income        |  |                 393 |  |                 965 |  |              2,626 |  |              2,846 |
|    Unallocated amounts (2)                   |  |                                                                                           |  |                                                                                           |  |  |  |  |
|     General and Administrative expenses |  |            (1,646)                           |  |               (926)           |  |            (4,529) |  |            (2,821) |
|     Interest expense                    |  |               (142)           |  |               (223)           |  |               (433) |  |               (627) |
|     Other (1)                           |  |  -                                                                                   |  |                 490 |  |              9,351 |  |              1,016 |
|         Total       |  |  $        11,919                                       |  |  $        12,422                                       |  |  $        45,277 |  |  $        37,655 |
|                                                   |  |                                                                                           |  |                                                                                           |  |  |  |  |
|                                                   |  | September 30, 2005                                                                        |  | December 31, 2004                                                                         |
|                                                   |  |                                                                                           |  |                                                                                           |  | (Restated) |
| SEGMENT ASSETS                                    |  |                                                                                           |  |                                                                                           |  |  |  |  |
|    Drilling and Development                  |  |                                                                                           |  |  $        41,366                                       |  |  |  |  $        64,348 |
|  Natural  Gas Marketing                      |  |                                                                                           |  |            59,205                            |  |  |  |            31,234 |
|  Oil and  Gas Sales                          |  |                                                                                           |  |          258,974                                       |  |  |  |          211,255 |
|  Well  Operations and Pipeline Income        |  |                                                                                           |  |            24,553                            |  |  |  |            16,518 |
|    Unallocated amounts(2)                    |  |                                                                                           |  |                                                                                           |  |  |  |  |
|       Cash                    |  |                                                                                           |  |                 186 |  |  |  |                 112 |
|       Other                   |  |                                                                                           |  |            12,347                            |  |  |  |            11,561 |
|         Total       |  |                                                                                           |  |  $      396,631                                                  |  |  |  |  $      335,028 |
|                                                   |  |                                                                                           |  |                                                                                           |  |  |  |  |

   (1)Includes gains on sales of assets, interest on investments and partnershipmanagement fees which are not

       allocated in assessing segment performance.

   (2)Items which are not allocated in assessing segment performance.

   (3)Includes $5.4 million in exploratory dry hole costs in the nine months endedSeptember 30, 2005.

9

----

7.  Sale ofUndeveloped Acreage

During the firstquarter of 2005, the Company sold a portion of one of its undeveloped GarfieldCounty, Colorado leases to an unaffiliated entity.  The proceeds of thesale were $6.2 million and the Company's carrying value of the property waszero.  The Company was required to remit $1.0 million to the originallessor, unless it commenced construction of certain facilities adjacent to thisundeveloped property subject to certain timing conditions. The gain of $5.2million was recognized during the first quarter of 2005 and is included in"Other Income" in the accompanying condensed consolidated statements of income.During the second quarter of 2005, the Company commenced construction of thefacilities and recorded income of $1.0 million which is included in "OtherIncome" in the accompanying condensed consolidated statements of income.

8.     Sale of Producing Wells

During the secondquarter of 2005, the Company completed the sale to an unaffiliated entity of111 Pennsylvania wells it purchased from Pemco Gas, Inc. in 1998.  TheCompany received proceeds of $3.4 million and recorded a gain of approximately$1.7 million which is included in "Other Income" in the accompanyingcondensed consolidated statements of income.  

9.     Exploratory Dry Hole

During the secondquarter of 2005, the exploratory Fox Federal #1-13 well was deemed to benon-commercial after well tests were completed and will be plugged andabandoned. Under the successful efforts method of accounting, this cost isrequired to be expensed in the period when such determination is made. Thisamounted to a $5.0 million expense which is included in the accompanyingcondensed consolidated statements of income under Exploratory Dry Hole Costs.Due to the dry hole, the Company reevaluated the Company's adjacent leases andwrote off approximately $383,000 which is included in Exploratory Dry HoleCosts. 

* *

10.   Commitments and Contingencies

The nature of the independentoil and gas industry involves a dependence on outside investor drilling capitaland involves a concentration of gas sales to a few customers.  The Companysells natural gas to various public utilities, natural gas marketers,industrial and commercial customers.

The Company would beexposed to natural gas price fluctuations on underlying purchase and salecontracts should the counterparties to the Company's derivative instruments notperform. Such nonperformance is not anticipated. There were no counterpartydefault losses in the first three quarters of 2005 or the year 2004.

Substantially all ofthe Company's drilling programs contain a repurchase provision where Investorsmay request the Company to repurchase their partnership units at any timebeginning with the third anniversary of the first cash distribution. Theprovision provides that the Company is obligated to purchase an aggregate of10% of the initial subscriptions per calendar year (at a minimum price of fourtimes the most recent 12 month's cash distributions), if investors request theCompany to repurchase such units, subject to the Company's financial ability todo so. The maximum annual 10% repurchase obligation, if requested by investors,is currently approximately $8.4 million. The Company believes it has adequateliquidity to meet this obligation should it arise.

 The Company'sdrilling programs formed since 1996 contain a performance standard which statesthat if certain performance levels are not met, the Company must remit apayment equal to one-half of its share of revenue from such partnership to theinvesting partners.  For the nine months ended September 30, 2005 and2004, the Company paid partnerships a total of $564,200 and $475,000respectively in accordance with the provision.

As Managing General Partner of 10 privatelimited partnerships and 64 public limited partnerships, the Company hasliability for any potential casualty losses in excess of the partnership assetsand insurance. The Company is the sole general partner of each of these variouslimited partnerships. The Company believes its casualty insurance coverage isadequate to meet this potential liability.

10

----

In order to securethe services for drilling rigs, the Company makes commitments to the drillingcontractor which call for penalties for a specified amount of time if theCompany ceases to use such drilling rigs, an event that is not anticipated tooccur.  As of September 30, 2005, the Company has an outstandingcommitment for $25.5 million.

From time to time the Company is a partyto various legal proceedings in the ordinary course of business.  TheCompany is not currently a party to any litigation that it believes would havea materially adverse affect on the Company's business, financial condition,results of operations, or liquidity. 

11. Common Stock Repurchase

On March 18, 2005the Company publicly announced the authorization by its Board of Directors torepurchase up to 2% of the Company's outstanding common stock (331,796 shares)at fair market value at the date of purchase. At a meeting held June 10, 2005,the Board of Directors of Petroleum Development Corporation approved anamendment of the size of the stock repurchase from 2% to 10% (1,658,980 shares)of the Company's then outstanding common stock. Under the program, the Boardhas discretion as to the dates of purchase and amounts of stock to be purchasedand whether or not to make purchases. This program expired on December 31,2005. The following activity has occurred since inception of the plan on March18, 2005 until September 30, 2005.

| Month of Purchase                      | May, 2005            |
|----------------------------------------|----------------------|
| Average Price paid per share           | $23.75               |
| Broker/Dealer                          | McDonald Investments |
| Number of Shares Purchased             | 331,796              |
| Remaining Number of Shares to purchase | 1,327,184            |

Item 2.**    **Management'sDiscussion and Analysis of Financial Condition and Results of Operations

2005 Restatement

As described in our Amended Annual Report on Form 10-K/Afor the year ended December 31, 2004 and our Amended Quarterly Report on Form10-Q/A for the three months ended March 31, 2005, we restated certain financialstatements and other information, including such statements and information foreach of the quarters of 2004 and the quarter ended March 31, 2005. Theserestatements related to our accounting for derivative transactions, certainaspects of the Company's oil and gas  property accounting, asset retirementobligations, and accounting for income taxes. The following discussions havebeen restated for the above mentioned restatement and all numbers restated aremarked as restated.

TheCompany has recorded historically strong revenues, income and cash flow forboth the third quarter and the first nine months of 2005.  High oil andnatural gas prices in combination with record Company production have been thelargest contributors to both income and cash flow.  The high energy priceshave also increased the Company's revenues for sales of Company-ownedproduction. Management also believes that high energy prices have increased theattractiveness of its partnership investment programs to investors resulting ina significant increase in the sale of program interests and as a resultincreased drilling activity, and revenues for the Drilling and Developmentsegment.  The new wells drilled for the partnerships also led to anincrease in revenues for operating wells for the partnerships and others. 

Theincreased level of activities also increased the costs associated with thedrilling and development and well operations activities since more goods,services and other costs were incurred as a result of the higher levels ofactivities.

Theincreased profitability and cash flow from operations allowed the Company tocontinue to invest in capital projects. The majority of the capital investmentwas for oil and gas drilling and development activities. In addition, theCompany repurchased common stock for approximately $7.9 million.

Amore detailed explanation of the various components for the most recent quarterand nine months follows:

11

----

Results of Operations

Three Months Ended September 30, 2005 Compared withSeptember 30, 2004

Revenues

Total revenues for the three months ended September 30,2005 were $85.8 million compared to a restated $72.3 million for the threemonths ended September 30, 2004, an increase of approximately $13.5 million or18.7 percent. Such increase was a result of increased drilling revenues, oiland gas sales and well operations and pipeline income, offset in part by adecrease in gas sales from marketing activities.

* *

Costs and Expenses

Costs and expenses for the three months ended September30, 2005 were $63.8 million compared to a restated $57.2 million for the threemonths ended September 30, 2004, an increase of approximately $6.6 million or11.5 percent. Such increase was primarily the result of increased cost of oiland gas well drilling operations, oil and gas production and well operationscosts, general and administrative costs, and depreciation, depletion andamortization, offset in part by a decrease in the cost of gas marketingactivities. 

Drilling Operations

Drilling revenues for the three months ended September 30, 2005 were $39.7 million compared to $30.4 million for the three months endedSeptember 30, 2004, an increase of approximately $9.3 million or 30.6percent.  Such increase was due to the increased drilling funds raisedthrough the Company's Public Drilling Programs.  The Company started thethird quarter of 2005 with advances for future drilling from June 30, 2005 of$63.9 million compared with advances for future drilling of $42.5 million atthe beginning of the third quarter of 2004. We believe in part that thisincrease in drilling program partnership subscriptions is fueled by theincrease in oil and natural gas prices which has improved the performance ofour prior programs which in turn has helped to increase our current drilling programsales.

Oil and gas well drilling operations costs for the threemonths ended September 30, 2005 were $36.2 million compared to $26.0 millionfor the three months ended September 30, 2004, an increase of approximately$10.2 million or 39.2 percent. Such increase was due to the higher levels ofdrilling activity from our Public Drilling Programs referred to above. The gross margin on the drilling activities for the three months endedSeptember 30, 2005 was 8.9% compared with 14.4% for the three months endedSeptember 3 0, 2004, a decrease in gross margin of 5.5% as a result of therising well fracturing and steel costs for casing and other equipment. For thefirst two partnerships in 2005, the Company raised its footage-based drillingrates it charges to its Public Drilling Partnerships. The third partnership andfuture partnerships will be drilled on a cost plus basis that will mitigatethese fluctuations in drilling margins.

Natural Gas Marketing Activities

Natural gas sales from the marketing activities of RileyNatural Gas (RNG), the Company's gas marketing subsidiary, for the three monthsended September 30, 2005 were $15.0 million compared to a restated $22.6million for the three months ended September 30, 2004, a decrease ofapproximately $7.6 million or 33.6 percent. Such decrease was due to unrealizedlosses on derivative transactions which amounted to approximately $16.3 millionand $1.4 million for the three months ended September 30, 2005 and 2004,respectively, offset in part by higher volumes of natural gas sold andsignificantly higher average sales prices. 

The costs of gas marketing activities for the threemonths ended September 30, 2005 were $14.3 million compared to a restated $22.0million for the three months ended September 30, 2004, a decrease of $7.7million or 35.0 percent. Such decrease was due to unrealized gains onderivative transactions which amounted to approximately $16.3 million and $1.5million for the three months ended September 30, 2005 and 2004, respectively,offset in part by significantly higher average purchase prices and volumes ofnatural gas purchased for resale. Income before income taxes for the Company'snatural gas marketing subsidiary was $759,000 for the three months endedSeptember 30, 2005 compared to an income before income taxes of $591,000 forthe three months ended September 30, 2004. 

12

----

Oil and Gas Sales

Oil and gas sales from the Company's producing propertiesfor the three months ended September 30, 2005 were $28.4 million compared to arestated $16.6 million for the three months ended September 30, 2004 anincrease of $11.8 million or 71.1 percent. The increase was due to increasedvolumes sold at significantly higher average sales prices of oil and naturalgas. The volume of natural gas sold for the three months ended September 30,2005 was 2.7 million Mcf at an average sales price of $8.07 per Mcf compared to2.6 million Mcf at an average restated sales price of $5.13 per Mcf for thethree months ended September 30, 2004. Oil sales were 119,000 barrels at anaverage sales price of $54.66 per barrel for the three months ended September30, 2005 compared to 88,000 barrels at an average restated sales price of$37.65 per barrel for the three months ended September 30, 2004. The increasein natural gas volumes was the result of the Company's increased investment inoil and gas properties, primarily recompletions of existing wells, wellsdrilled in our NECO, Colorado area of operation, and the investment in oil andgas properties we own in our public drilling program partnerships.  

Oil and Gas Production

The Company's oil and natural gas production by area ofoperations along with average sales price is presented below:

|                    |  |                                                                           |  |                                                                           |
|--------------------|--|---------------------------------------------------------------------------|--|---------------------------------------------------------------------------|
|                    |  | Three Months Ended September 30, 2005                                     |  | Three Months Ended September 30, 2004                                     |
|                    |  |                                                                           |  | Natural                                                                   |  | Natural Gas |  |  |  | Natural |  | Natural Gas |
|                    |  | Oil                                                                       |  | Gas                                                                       |  | Equivalents |  | Oil |  | Gas |  | Equivalents |
|                    |  | (Bbl)                                                                     |  | (Mcf)                                                                     |  | (Mcfe)* |  | (Bbl) |  | (Mcf) |  | (Mcfe)* |
|                    |  |                                                                           |  |                                                                           |  |  |  |  |  |  |  |  |
| Appalachian  Basin |  |              1,218 |  |          394,982                       |  |             402,290 |  |              1,589 |  |       458,657 |  |             468,191 |
| Michigan Basin     |  |              1,177 |  |          379,824                       |  |             386,886 |  |              1,301 |  |       445,013 |  |             452,819 |
| Rocky  Mountains   |  |          116,170                       |  |       1,941,513                                       |  |          2,638,533 |  |            85,414 |  |    1,682,360 |  |          2,194,844 |
| Total              |  |          118,565                       |  |       2,716,319                                       |  |          3,427,709 |  |            88,304 |  |    2,586,030 |  |          3,115,854 |
|                    |  |                                                                           |  |                                                                           |  |  |  |  |  |  |  |  |
|                    |  |                                                                           |  |                                                                           |  |  |  | (Restated) |  | (Restated) |  | (Restated) |
| Average Price      |  |  $          54.66            |  |  $            8.07 |  |  $               8.29 |  |  $          37.65 |  |  $         5.13 |  |  $               5.32 |
|                    |  |                                                                           |  |                                                                           |  |  |  |  |  |  |  |  |

*One barrel of oil is equal to the energy equivalent of six Mcf ofnatural gas.

Financialresults depend upon many factors, particularly the price of natural gas and ourability to market our production effectively. In recent years, natural gas andoil prices have been among the most volatile of all commodity prices. Theseprice variations can have a material impact on our financial results. Naturalgas prices in Colorado continue to trail prices which we receive for ourAppalachian and Michigan gas which are based upon NYMEX. The Company'smanagement believes the lower prices in the Rocky Mountain Region, includingColorado, resulted from increasing local supplies that exceeded the localdemand and pipeline capacity available to move gas from the region. In 2003 apipeline expansion project was completed, leading to improved natural gasprices in the region which reduced the local surplus. There is currently asubstantial amount of drilling activity in the Rockies, and if future additionsto the pipeline system are not made in a timely fashion it is possible thatpipeline constraints could create a local oversupply situation in the futurewhich could mean lower natural gas prices.  Like most other producers inthe area we rely on major interstate pipeline companies to construct thesefacilities, so their timing and construction is not within our control.

Oil and Gas Derivative Activities

Because of uncertainty surrounding natural gas prices wehave used various derivative instruments to manage some of the impact offluctuations in prices. Through March of 2007 we have in place a series offloors and ceilings on part of our natural gas and oil production. Under thearrangements, if the applicable index rises above the ceiling price, we pay thecounterparty, however if the index drops below the floor the counterparty paysus. During the three months ended September 30, 2005 the Company averagednatural gas volumes sold of 905,400 Mcf per month and oil sales of 39,500barrels per month. The current positions in effect on the Company's share ofproduction are shown in the following table.

13

----

|  |  | Floors |  | Ceilings |  
Monthly Quantity

Contract

Monthly Quantity

Contract

 
Month  Set

Month

       Mmbtu        

Price

      Mmbtu       

Price

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

Feb-04

Oct  05

33,000

$3.10 

16,000

$4.43 

 
Mar-05

Oct  05

38,000

$4.75 

19,000

$8.12 

 
Jan-05

Nov  2005 - Mar 2006

60,000

$4.50 

30,000

$7.15 

 
Jul-05

Nov  2005 - Mar 2006

27,500

$6.50 

13,750

$8.27 

 
Sep-05

Nov  2005 - Mar 2006

78,700

$9.00 

-

-

 
Mar-05

Apr  2006 - Oct 2006

42,000

$4.50 

21,000

$7.25 

 
Jul-05

Apr  2006 - Oct 2006

27,500

$5.50 

13,750

$7.63 

 
Jul-05

Nov  2006 - Mar 2007

27,500

$6.00 

13,750

$8.40 

 
NYMEX Based  Derivatives - (Appalachian and Michigan Basins)

Feb-04

Oct 05

122,000

$4.28 

61,000

$5.00 

Mar-05

Oct 05

39,000

$5.75 

19,500

$8.37 

Jan-05

Nov 2005 - Mar  2006

156,000

$5.00 

78,000

$8.50 

Sep 05

Nov 2005 - Mar  2006

156,000

$10.50 

-

-

Mar-05

Apr 2006 - Oct  2006

78,000

$5.50 

39,000

$7.40 

Jul-05

Apr 2006 - Oct  2006

61,000

$6.25 

30,000

$8.98 

Jul-05

Nov 2006 - Mar  2007

68,000

$7.00 

34,000

$9.27 

NYMEX Based  Derivatives (NECO) Area

Feb-04

Oct 05

150,000

$4.26 

75,000

$5.00 

Jan-05

Nov 2005 - Mar  2006

150,000

$5.00 

75,000

$8.45 

Panhandle Based  Derivatives (NECO) Area

** **

Sep-05

Nov 2005 - Mar  2006

100,000

$10.00 

-

-

Mar-05

Apr 2006 - Oct  2006

150,000

$5.00 

75,000

$8.62 

Jul-05

Nov 2006 - Mar  2007

150,000

$6.50 

75,000

$8.56 

Oil - NYMEX  Based (Wattenberg)

** **

Bbl

** **

Bbl

Aug-04

Oct 2005 - Dec  2005

15,000

$32.30 

7,500

$40.00 

Oil and Gas Production and Well Operations Costs

Oil and gas production and well operations costs from theCompany's producing properties for the three months ended September 30, 2005were $6.5 million compared to $4.0 million for the three months ended September30, 2004, an increase of $2.5 million or 62.5 percent. Such increase was due toincreased production cost and severance and property taxes on the increasedvolumes and significantly higher average sales prices of natural gas and oilsold, along with the increased number of wells and pipelines operated by theCompany. Lifting cost per Mcfe increased from $1.01 per Mcfe during the threemonths ended September 30, 2004 to $1.37 per Mcfe during the three months endedSeptember 30, 2005 due to increased severance and property taxes on thesignificantly increased oil and gas prices, along with additional wellworkovers and production enhancements work performed.  

Exploratory Dry Hole Cost

During the second quarter of 2005, the exploratory FoxFederal #1-13 well was deemed to be non-commercial after well tests werecompleted and will be plugged and abandoned. Under the successful effortsmethod of accounting, this cost is required to be expensed in the period whensuch determination is made. The majority of the dry hole costs were recorded inthe second quarter with an additional $135,800 expense which is included underexploratory dry hole costs for the three months ended September 30, 2005. Therewere no exploratory dry hole costs in 2004.

Well Operations and Pipeline Income

Well operations and pipeline income for the three monthsended September 30, 2005 was $2.5 million compared to $2.1 million for thethree months ended September 30, 2004, an increase of approximately $400,000 or19.0 percent. Such increase was due to an increase in the number of wells andpipeline systems operated by the Company for our drilling program partnershipsas well as third parties. 

14

Other Income

Other income for the three months ended September 30,2005 was $209,000 compared to $589,000 for the three months ended September 30,2004, a decrease of $380,000. Such decrease was due to lower management feeincome because no partnerships were funded during the quarter ended September30, 2005.

General and Administrative Expenses

General and administrative expenses for the three monthsended September 30, 2005 were $1.6 million compared to $926,000 for the threemonths ended September 30, 2004, an increase of approximately $700,000 or 75.6percent. Such increase was due to the costs of complying with the variousprovisions of Sarbanes Oxley, in particular with Section 404 (InternalControls), increased costs related to the 2004 and first quarter 2005restatements discussed earlier in this document and increased administrativeand payroll costs associated with an expanding company.

Depreciation, Depletion, and Amortization

Depreciation, depletion, and amortization costs for thethree months ended September 30, 2005 increased to $5.1 million from a restated$4.3 million for the three months ended September 30, 2004, an increase ofapproximately $800,000 or 18.6 percent. Such increase was due to the increasedproduction and investment in oil and gas properties by the Company.

Interest Expense

Interest cost for the three months ended September 30,2005 was $142,000 compared to a restated $223,000 for the three months endedSeptember 30, 2004, a decrease of $81,000 or 36.3 percent.  Such decreasewas due to lower average outstanding balances of our credit facility offset inpart by an unrealized gain on an interest rate swap in 2004, increasedaccretion related to asset retirement obligations, and higher interestrates.  The Company utilizes its daily cash balances to reduce its line ofcredit to lower its costs of interest.  The average daily outstanding debtbalance for the three months ended September 30, 2005 was $8.0 million comparedto $11.4 million for the three months ended September 30, 2004. 

Oil and Gas Price Risk Management Loss, Net

For the three monthsended September 30, 2005, the Company recorded unrealized losses of $7.8 millionand realized losses of $2.1 million compared to the three months endedSeptember 30, 2004, which is comprised of a restated unrealized loss of $1.9million and restated realized losses of $463,000. The 2005 change is the resultof increasing natural gas and oil prices. Oil and gas price risk management(gain) loss, net is comprised of the change in fair value of oil and naturalgas derivatives related to our oil and gas production (this line item does notinclude commodity based derivative transactions related to transactions frommarketing activities).

Provision for Income Taxes 

The effective income tax rate for the Company's provisionfor income taxes increased from approximately 36.3 percent to 37.0 percentprimarily because of a reduction in the benefit from percentage depletion,offset in part by additional benefit to be realized for the tax deduction fordomestic production activities.

Net income andEarnings Per Share 

Net income for the threemonths ended September 30, 2005 was $7.5 million compared to a restated netincome of $7.9 million for the three months ended September 30, 2004, adecrease of approximately $400,000 or 5.1 percent.

Diluted earnings pershare for the three months ended September 30, 2005 was $0.46 per sharecompared to a restated $0.47 per share for the three months ended September 30,2004, a decrease of $0.01 per share or 2.1 percent.

15

Nine Months Ended September 30, 2005 Compared withSeptember 30, 2004

Revenues

Total revenues for the nine months ended September 30,2005 were $252.0 million compared to a restated $215.3 million for the ninemonths ended September 30, 2004, an increase of approximately $36.7 million or17.0 percent. Such increase was a result of increased drilling revenues, oiland gas sales, well operations and pipeline income, and other income, offset inpart by a decrease in gas sales from marketing activities. 

Costs and Expenses

Costs and expenses for the nine months ended September30, 2005 were $193.6 million compared to a restated $172.9 million for the ninemonths ended September 30, 2004, an increase of approximately $20.7 million or12.0 percent. Such increase was primarily the result of the increase in theexploratory dry hole costs of $5.4 million in 2005, cost of oil and gas welldrilling operations, oil and gas production costs, general and administrativeexpenses, and depreciation, depletion and amortization, offset in part by adecrease in cost of gas marketing activities. 

Drilling Operations

Drilling revenues for the nine months ended September 30,2005 were $108.1 million compared to $89.3 million for the nine months endedSeptember 30, 2004, an increase of approximately $18.8 million or 21.1percent.  Such increase was due to the increased drilling funds raisedthrough the Company's Public Drilling Programs. During the first nine months of2005 the Company funded two drilling programs with total subscriptions of $80.0million and has commenced drilling of the partnership wells. We believe in partthat this increase in drilling program partnership subscriptions is fueled bythe increase in oil and natural gas prices which have improved the performanceof our prior programs which in turn was helped to increase our current drillingprogram sales.

Oil and gas well drilling operations costs for the ninemonths ended September 30, 2005 were $95.1 million compared to $76.3 millionfor the nine months ended September 30, 2004, an increase of approximately$18.8 million or 24.6 percent. Such increase was due to the higher levels ofdrilling activity from our Public Drilling Programs referred to above. Thegross margin on the drilling activities for the nine months ended September 30,2005 was 12.0 percent compared with 14.6 percent for the nine months endedSeptember 30, 2004, a decrease in gross margin of 2.6 percent as a result ofthe rising well fracturing and steel costs for casing and other wellequipment.  For the first two partnerships in 2005, the Company raised itsfootage-based drilling rates it charges to its Public Drilling Partnerships.The third partnership and future partnerships will be drilled on a cost plusbasis that will mitigate these fluctuations in drilling margins.

Natural Gas Marketing Activities

Natural gas sales from the marketing activities of RileyNatural Gas (RNG), the Company's marketing subsidiary, for the nine monthsended September 30, 2005 were $58.4 million compared to a restated $69.6 millionfor the nine months ended September 30, 2004, a decrease of approximately $11.2million or 16.1 percent. Such decrease was due to unrealized losses onderivative transactions which amounted to approximately $21.0 million and arestated $3.9 million for the nine months ended September 30, 2005 and 2004,respectively, offset in part by higher volumes of natural gas sold, along withsignificantly higher average sales prices.

The cost of gas marketing activities for the nine monthsended September 30, 2005 was $58.3 million compared to a restated $68.5 millionfor the nine months ended September 30, 2004, a decrease of $10.2 million or14.9 percent. Such decrease was due to unrealized gains on derivativetransactions which amounted to approximately $20.1 million and a restated $3.0million for the nine months ended September 30, 2005 and 2004, respectively,offset in part by higher volumes of natural gas purchased for resale, alongwith higher average purchase prices.  Income before income taxes for theCompany's natural gas marketing subsidiary decreased from a restated $1.1million for the nine months ended September 30, 2004 to $250,000 for the ninemonths ended September 30, 2005.

16

Oil and Gas Sales

Oil and gas sales from the Company's producing propertiesfor the nine months ended September 30, 2005 were $68.6 million compared to arestated $49.1 million for the nine months ended September 30, 2004 an increaseof $19.5 million or 39.7 percent. The increase was due to increased volumessold at significantly higher average sales prices of oil and natural gas. Thevolume of natural gas sold for the nine months ended September 30, 2005 was 8.1million Mcf at an average sales price of $6.52 per Mcf compared to 7.88 millionMcf at an average restated sales price of $5.04 per Mcf for the nine monthsended September 30, 2004. Oil sales were 331,000 barrels at an average salesprice of $47.60 per barrel for the nine months ended September 30, 2004compared to 289,000 barrels at an average restated sales price of $34.78 perbarrel for the nine months ended September 30, 2004. The increase in naturalgas volumes was the result of the Company's increased investment in oil and gasproperties, primarily recompletions of existing wells, wells drilled in ourNECO, Colorado area of operation, and the investment in oil and gas propertieswe own in our public drilling program partnerships. 

Oil and Gas Production

The Company's oil and natural gas production by area of operationsalong with average sales price is presented below:

Nine Months Ended

Nine Months Ended

September 30, 2005

September 30, 2004

Natural 

Natural Gas

Natural 

Natural Gas

Oil

Gas

Equivalents

Oil

Gas

Equivalents

(Bbl)

(Mcf)

(Mcfe)*

(Bbl)

(Mcf)

(Mcfe)*

Appalachian  Basin

           3,073 

       1,238,724 

         1,257,162 

           3,931 

       1,346,915 

        1,370,501 

Michigan Basin

           3,391 

       1,172,638 

         1,192,984 

           4,305 

       1,314,829 

        1,340,659 

Rocky  Mountains

       324,355 

       5,698,298 

         7,644,428 

       280,308 

       5,093,748 

        6,775,596 

Total

       330,819 

       8,109,660 

       10,094,574 

       288,544 

       7,755,492 

        9,486,756 

(Restated)

(Restated)

(Restated)

Average Price

 $        47.60 

 $             6.52 

 $               6.80  

 $        34.78 

 $             5.04 

 $              5.18 

*One barrel of oil is equal to the energy equivalent ofsix Mcf of natural gas.

Financialresults depend upon many factors, particularly the price of natural gas and ourability to market our production effectively. In recent years, natural gas andoil prices have been among the most volatile of all commodity prices. Theseprice variations can have a material impact on our financial results. Naturalgas prices in Colorado continue to trail prices which we receive for ourAppalachian and Michigan gas which are based upon NYMEX. The Company'smanagement believes the lower prices in the Rocky Mountain Region, includingColorado, resulted from increasing local supplies that exceeded the localdemand and pipeline capacity available to move gas from the region. In 2003 apipeline expansion project was completed, leading to improved natural gasprices in the region which reduced the local surplus. There is currently asubstantial amount of drilling activity in the Rockies, and if future additionsto the pipeline system are not made in a timely fashion it is possible thatpipeline constraints could create a local oversupply situation in the futurewhich could mean lower natural gas prices.  Like most other producers inthe area we rely on major interstate pipeline companies to construct thesefacilities, so their timing and construction is not within our control. SeeManagement's Discussion and Analysis for the three months ended September 30,2005 compared with the September 30, 2004 for a complete schedule of currentderivative positions.

Oil and Gas Production and Well Operations Costs

Oil and gas production and well operations costs from theCompany's producing properties for the nine months ended September 30, 2005were $15.4 million compared to $11.9 million for the nine months endedSeptember 30, 2004, an increase of approximately $3.5 million or 29.4 percent.Such increase was due to the increased production costs and severance andproperty taxes on the increased volumes and significantly higher sales pricesof natural gas and oil sold, along with the increased number of wells andpipelines operated by the Company. Lifting cost per Mcfe increased from $1.03per Mcfe during the nine months ended September 30, 2004 to $1.20 per Mcfeduring the nine months ended September 30, 2005, due to increased severance andproperty taxes on the significantly increased oil and gas average sales pricesalong with additional well workovers and production enhancement work performed.

17

Exploratory Dry Hole Cost

During the second quarter of 2005, the exploratory FoxFederal #1-13 well, was deemed to be non-commercial after well tests were completedand will be plugged and abandoned. Under the successful efforts method ofaccounting, this cost is required to be expensed in the period when suchdetermination is made. This amounted to a $5.4 million expense which isincluded under exploratory dry hole costs. There were no exploratory dry holecosts in 2004.

Well Operations and Pipeline Income

Well operations and pipeline income for the nine monthsended September 30, 2005 was $6.8 million compared to $5.8 million for the ninemonths ended September 30, 2004, an increase of approximately $1.0 million or17.2 percent. Such increase was due to an increase in the number of wells andpipeline systems operated by the Company for our drilling program partnershipsas well as third parties.

Other Income

Other income for the nine months ended September 30, 2005was $10.0 million compared to $1.3 million for the nine months ended September30, 2004, an increase of $8.7 million. The increase is a result of a sale of aportion of one of our undeveloped leases in Garfield County, Colorado, which wesold in the first quarter of 2005 (See Footnote 7) for a pre-tax gain of $6.2million, a second quarter gain on sale of some Pennsylvania wells (See Footnote8) in the amount of $1.7 million, management fees collected from the funding oftwo drilling partnerships, and interest earned on higher average cash balancesand higher interest rates. 

General and Administrative Expenses

General and administrative expenses for the nine months endedSeptember 30, 2005 were $4.5 million compared to $2.8 million for the ninemonths ended September 30, 2004, a increase of approximately $1.7 million or60.7 percent. Such increase was due to the cost of complying with the variousprovisions of Sarbanes Oxley, in particular Section 404 (Internal Controls),increased costs related to the 2004 and first quarter 2005 restatementsdiscussed earlier in this document, and increased administrative and payrollcosts associated with an expanding company.

Depreciation, Depletion, and Amortization

Depreciation, depletion, and amortization costs for thenine months ended September 30, 2005 increased to $14.8 million from a restated$13.3 million for the nine months ended September 30, 2004, an increase ofapproximately $1.5 million or 11.3 percent. Such increase was due to increasedproduction and investment in oil and gas properties by the Company.

Interest Expense

Interest costs for the nine months ended September 30,2005 was $433,000 compared to a restated $627,000 for the three months endedSeptember 30, 2004, a decrease of $194,000 or 30.9 percent.  Such decreaseis due to lower average outstanding balances of our credit facility offset inpart by an unrealized gain on an interest rate swap in 2004, increasedaccretion related to asset retirement obligations, and higher interestrates.  The Company utilizes its daily cash balances to reduce its line ofcredit to lower its cost of interest.  The average daily outstanding debtbalance for the nine months ended September 30, 2005 was $3.3 million comparedto $11.9 million for the nine months ended September 30, 2004.

Oil and Gas Price Risk Management Loss, Net

For the nine months ended September 30, 2005, the Companyrecorded unrealized losses of $9.3 million and realized losses of $3.4 millioncompared to the nine months ended September 30, 2004 balance which is comprisedof a restated unrealized loss of $3.1 million and restated realized losses of$933,000. The 2005 change is the result of increasing natural gas and oilprices. Oil and gas price risk management (gain) loss, net is comprised of thechange in fair value of oil and natural gas derivatives related to our oil andgas production (this line item does not include commodity based derivative transactionsrelated to transactions from marketing activities).

18

Provision for Income Taxes 

The effective income tax rate for the Company's provisionfor income taxes increased from approximately 36.1 percent to 37.0 percentprimarily because of a reduction in the benefit from percentage depletion,offset in part by additional benefit to be realized for the tax deduction fordomestic production activities.

Net income andEarnings Per Share 

Net income for the ninemonths ended September 30, 2005 was $28.5 million compared to a restated netincome of $24.1 million for the nine months ended September 30, 2004, anincrease of approximately $4.4 million or 18.3 percent. 

Diluted earnings pershare for the nine months ended September 30, 2005 was $1.73 per share comparedto restated $1.45 per share for the nine months ended September 30, 2004, anincrease of $0.28 per share or 19.3 percent.

Liquidity and Capital Resources

TheCompany funds its operations through a combination of cash flow from operationsand use of the Company's credit facility.  Operational cash flow isgenerated by sales of natural gas and oil from the Company's well interests,natural gas marketing, profits from well drilling and operating activities fromthe Company's public drilling programs and others, and natural gas gatheringand transportation. Cash payments from Company-sponsored partnerships are usedto drill and complete wells for the partnerships, with operating cash flowaccruing to the Company to the extent payments exceed drilling costs.  TheCompany utilizes its revolving credit arrangement to meet the cash flowrequirements of its operating and investment activities.

Oil and Gas Derivative Activities

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

The Company also enters into derivative instruments forits partners' share of production as well as its own production. Actualwellhead prices will vary based on local contract conditions, gathering andother costs and factors.

NaturalGas Pricing and Pipeline Capacity

TheCompany sells natural gas under contracts that are priced based on spot pricesor price indexes that reflect current market prices for the commodity.  Asa result variations in the market are reflected in the revenue we receive. Theprice of natural gas has varied substantially over short periods of time in thepast, and there is every reason to expect a continuation of that variability inthe future.  During the first three quarters prices for natural gas wereclose to or above record levels, and future expectations as reflected in theNYMEX futures market are for continuing high price levels for the balance of2005 and beyond.  Strong domestic and international demand for energy andinadequate short term supplies are believed to be key causes of the strongprices.  High prices could encourage the development of new energy sourcesand reduced consumption as users find more efficient ways to use energy orsubstitute other energy forms.  High energy prices could also slow globaleconomic growth, further reducing demand.  As a result the energy priceoutlook could change rapidly from current expectations.  Reduced naturalgas prices would reduce the profitability and cash flow from the Company's gasproduction operations.

Naturalgas prices throughout the country tend to be fairly closely related afterallowing for differences in the quality and energy content of the gas, thelocation and distance to market, and other factors.  Sometimes prices in aparticular area may vary from historical relationships.  This can occurwhen a local condition restricts the marketability of the natural gas. For example limits on pipeline delivery capacity for natural gas can result inlower than normal prices for wells that use the system to deliver gas tomarket.  This situation occurred in 2002 to 2003 in the Rocky Mountains,when the productive capacity of wells in the region exceeded the amount of gasthat could be used by local markets or shipped out of the area.  In orderto access the available capacity producers were forced to sell their gas atlower than normal prices with the alternative being to shut wells in. Since that time, additional pipeline capacity has been added, and further additionsare planned in the future, so prices have returned to the historicalrelationship to other producing regions.  However future deliveryconstraints could result in lower than anticipated prices or production in anyof the Company's producing areas.

19

Oil Pricing

Oilprices were near or above record levels for most of the first three quarters of2005.  The Company's oil prices are largely determined by oil prices inthe world market.  Global supply and demand and geopolitical factors arethe key determinants of oil prices.  The rapid growth of energy use indeveloping countries, most notably China, is driving a rapid increase inworldwide oil consumption.  Higher prices could result in reducedconsumption and/or increasing supplies that could moderate the current highprice levels.  Over the past several years oil has been an increasing partof the Company's production mix.  As a result higher oil prices have contributedto the Company's increased revenue from oil and gas sales more than in thepast, and the Company would suffer a greater impact if oil prices were todecrease.

Public Drilling Programs

During January, 2005, the Company commenced sales andfunded its first 2005 Partnership (PDC 2005-A) at its maximum subscriptions of$40 million, the largest PDC partnership at that time.  The Companycommenced the drilling operations of the partnership late in the first quarterand will continue to drill for the partnership into the second and thirdquarters of 2005.

In April, 2005, the Company commenced sales and fundedits second 2005 Partnership (PDC 2005-B) at its maximum allowable subscriptionsof $40 million.  The Company commenced drilling operations of this partnershiplate in the second quarter and plans to continue to drill for the partnershipduring the fourth quarter of 2005.

In December, 2005, the Company commenced sales and fundedits third 2005 partnership, a private limited partnership, Rockies Region PrivateLimited Partnership with subscriptions of approximately $36 million. Drillingoperations will commence in the first quarter of 2006.

Substantially all of the Company's drilling programscontain a repurchase provision where Investors may request the Company torepurchase their partnership units at any time beginning with the thirdanniversary of the first cash distribution. The provision provides that theCompany is obligated to purchase an aggregate of 10% of the initialsubscriptions per calendar year (at a minimum price of four times the mostrecent 12 months' cash distributions), only if investors request the Company torepurchase such units subject to the Company's financial ability to doso.  The maximum annual 10% repurchase obligation, if requested by theinvestors, is currently approximately $8.4 million. The Company has adequateliquidity to meet this obligation. During the first nine months of 2005 theCompany has spent $248,100 under this provision. 

DrillingActivity 

Throughthe first nine months of 2005 the Company drilled along with its publicdrilling fund partnerships a total of 121 wells with only one developmental dryhole. The Company drilled 96 successful wells in its Wattenberg field in theDenver-Julesberg Basin and 25 successful wells in the Piceance Basin in westernColorado, all of the wells that the Company drills in these two areas are inconjunction with its public drilling fund partnerships. The Company plans toconduct the remainder of its 2005 partnership drilling activity in these twoareas.

Throughthe first nine months of 2005, the Company also drilled for its own account 53gross (34 net) wells in its northeast Colorado properties (NECO). The wells arebeing drilled on locations created by the regulatory approval of the reductionin well spacing from 80 to 40 acres on the properties the Company acquired inYuma County, Colorado in 2003. 

ExploratoryWells

Duringthe second quarter of 2005, the exploratory Fox Federal #1-13 well, was deemed tobe non-commercial after well tests were completed and will be plugged andabandoned.  Under the successful efforts method of accounting, this costis required to be expensed in the period when such determination is made. This amounted to a $5.0 million expense which is included in the IncomeStatement under Exploratory Dry Hole Costs.

TheCompany's second exploratory well, the Coffeepot Springs #24-34 has beendrilled to total depth, completed in three zones, tested and has been deemed tobe productive under the successful efforts method of accounting. The Companyhas a 100% working interest in this well. The cost of this well, which isapproximately $5.2 million as of November 30, 2005 will be capitalized anddepreciated over the life of the well using the units of productiondepreciation method.

20

Earlyin the third quarter the Company commenced the drilling of a horizontal Bakkenexploratory well, the Fedora #34-22H in Dunn County, North Dakota which hasbeen drilled to total depth, completed and placed in production in lateSeptember, 2005. The Company has a 100% working interest in this well. The costof this well, which is approximately $4.1 million as of November 30, 2005, willbe capitalized and depreciated over the life of the well using units ofproduction depreciation method.

Allof the costs of the above three exploratory wells were incurred 100% by theCompany as no costs were incurred by the drilling fund partnerships.

Purchase of Oiland Gas Properties

Althoughthe Company made several offers to purchase producing oil and gas propertiesfrom other companies during the first nine months of 2005, it was notsuccessful in purchasing any of those properties.  The Company didpurchase a number of small interests in its partnerships from investors wishingto liquidate their holdings under the repurchase provision of the partnerships.

Costsincurred by the Company in oil and gas acquisitions, exploration and developmentfor the nine months ended September 30, 2005 are presented below:

Property  acquisition cost:

    Proved undeveloped properties

 $        5,926,900 

    Producing properties

              273,900 

Development costs

         34,983,000 

Exploration  costs

           8,777,500 

 $      49,961,300 

Common StockRepurchase Program

On March 18, 2005 the Company publicly announced theauthorization by its Board of Directors to repurchase up to 2% of the Company'soutstanding common stock (331,796 shares) at fair market value at the date ofpurchase. At a meeting held June 10, 2005, the Board of Directors of PetroleumDevelopment Corporation approved an amendment of the size of the stockrepurchase from 2% to 10% (1,658,980 shares) of the Company's then outstandingcommon stock. Under the program, the Board has discretion as to the dates ofpurchase and amounts of stock to be purchased and whether or not to makepurchases. This program is scheduled to expire on December 31, 2005. Thefollowing activity has occurred since inception of the plan on March 18, 2005until September 30, 2005.

Month of Purchase

May, 2005

Average Price paid per share

$23.75

Broker/Dealer

McDonald Investments

Number of Shares Purchased

331,796

Remaining Number of Shares to purchase

1,327,184

WorkingCapital 

Althoughthe Working Capital of the Company as of September 30, 2005 is a negative $4.8million this amount included a net liability of $9.4 million related to thefair value of derivatives.  Such amount may or may not be realizeddepending on the change in the fair value of derivatives between September 30,2005 and settlement, and will not require additional expenditures of cash sinceit will be funded with proceeds from future oil and gas sales.

21

Long-TermDebt

TheCompany has a $200 million credit facility agented by JP Morgan Securities Inc.and BNP Paribas subject to and secured by adequate levels of oil and gasreserves. The maximum available borrowing base is $125.0 million as of April 1,2005, of which the Company has activated $80 million of the facility.  TheCompany is required to pay a commitment fee of 1⁄4 percent annually on the unusedportion of the activated credit facility. Interest accrues at prime, with LIBOR(London Interbank Market Rate) alternatives available at the discretion of theCompany and subject to a pricing grid which defines the spread over LIBOR. Noprincipal payments are required until the credit agreement expires on November4, 2010.

Asof September 30, 2005, the outstanding balance was $14,000,000.  Anyamounts outstanding under the credit facility are secured by substantially allproperties of the Company.  The credit agreement requires, among otherthings, the existence of satisfactory levels of natural gas reserves andmaintenance of certain financial and negative covenants customary for afacility of this size. At September 30, 2005, the outstanding balance wassubject to a prime rate of 6.75%. The Company has been granted a waiver throughJanuary 12, 2006 for the delivery of its quarterly reporting requirements forthe quarter ended September 30, 2005.

ContractualObligations

Contractualobligations and due dates are as follows:

`

Payments due by period

Less than

1-3 

3-5

More than

Contractual  Obligations

Total

1 year

years

years

5 years

Long-Term Debt

$        14,000,000 

$                     - 

$                     - 

 $    14,000,000 

$                     - 

Operating  Leases

               658,700 

            243,000 

            307,200 

              74,500 

              34,000 

Asset  Retirement Obligation

            8,187,100 

              50,000 

            100,000 

            100,000 

         7,937,100 

Drilling Rig  Commitment

          25,533,200 

         5,621,000 

       11,242,000 

         8,670,200 

                    - 

Derivative  Agreements

          48,576,000 

       41,417,000 

         7,159,000 

                       - 

                       - 

Other  Liabilities

            3,485,900 

              40,000 

            250,000 

            250,000 

         2,945,900 

Total

$      100,440,900 

 $    47,371,000 

 $    19,058,200 

 $    23,094,700 

 $    10,917,000 

Long-term debt in the above table does not includeinterest as interest rates are variable and principal balances fluctuatesignificantly from period to period.  The Company continues to pursue capital investmentopportunities in producing natural gas properties as well as its plan toparticipate in its sponsored natural gas drilling partnerships. Management believes that the Company has adequate capital to meet its operatingrequirements.

Commitments andContingencies

AsManaging General Partner of 10 private partnerships and 64 public partnerships,the Company has liability for any potential casualty losses in excess of thepartnership assets and insurance. The Company is generally the sole generalpartner of each of these various limited partnerships.  The Companybelieves its casualty insurance coverage is adequate to meet this potentialliability.

Factors That MayAffect Future Results and Financial Conditions

Inthe course of its normal business the Company is subject to a number of risksthat could potentially adversely impact its revenues, expenses and financialcondition.  The following is a discussion of some of the more significantrisks. 

* *

*Drillingof oil and natural gas wells is highly speculative and may be unprofitable orresult in the loss of the entire investment in a well and the lease on which itis located.*  To theextent the Company drills unsuccessful developmental wells its futureprofitability will be reduced on production from the field where the well islocated, since the investment in the well will be included in the investment inthe field and depreciated on the unit-of-production method.  Recently theCompany has begun drilling several planned exploratory wells that could lead tosignificant future development opportunities.  Under the SuccessfulEfforts method used by the Company, the costs of exploratory dry holes aretaken as an expense in the period when it is determined that they arenon-productive.  As a result exploratory dry holes, if any additional aredrilled, will result in an immediate reduction in net income for that period. 

22

* *

*Reductionsin prices of oil and natural gas reduce the profitability of the Company'sproduction operations.* Revenue from the sale of oil and gas increases when prices increase anddeclines when prices decrease.  These price changes can occur rapidly andare not predictable nor within the control of the Company. 

* *

*Changesin prices of oil and natural gas may also affect sales of drilling programs.*  Recent energy price increases havecoincided with increased sales of the Company's partnership investments, andincreased profitability from those operations.  It is likely thatdeclining prices could have the opposite effect, reducing partnership sales andprofitability.  Because the Company has not been able to meet the demandfor oil and gas investments from its Broker/Dealer network, thoseBroker/Dealers have been seeking investments from other oil and gas programsponsors.  These new competitors could potentially take business from theCompany, particularly in a declining price market for oil and gas.  

* *

*Increasesin prices of oil and natural gas have increased the cost of drilling, the costof potential acquisitions and other factors affecting the performance of theCompany in both the short and long term.* In the current high price environment most oil and gascompanies have increased their expenditures for drilling new wells.  Thishas resulted in increased demand and higher prices for leases, oilfield servicesand well equipment.  Similarly higher energy prices have increased theprice purchasers are willing to pay for producing properties and increasedcompetition for the properties that are available.  These factors make itmore difficult to add to the Company's production, and increase the cost ofadditions.  To the extent that new reserves and production are added atthese higher prices, the risk to the Company of decreased profitability fromfuture decreases in oil and gas prices is increased.

* *

*TheCompany's derivative activities could result in reduced revenue compared to thelevel the Company would experience if no derivative instruments were in place*.* *The Company usesderivative instruments to reduce the impact of price movements onrevenue.  While these derivative instruments protect the Company againstthe impact of declining prices, they also may limit the positive impact ofprice increases.  As a result the Company may have lower revenues whenprices are increasing than might otherwise be the case.

* *

*Thehigh level of drilling activity could result in an oversupply of natural gas ona regional or national level resulting in much lower commodity prices. *Recently the natural gas market been characterizedby excess demand compared to the supplies available.  The high level ofdrilling, combined with reduction in demand resulting from high prices couldresult in an oversupply of natural gas.  On a local level increasingsupplies could exceed available pipeline capacity.  In both cases theresult would probably be lower prices for the natural gas the Company producesand reduced profitability for the Company.

* *

*TheCompany owns interests in and operates more than 2,600 wells and drills manynew wells each year.**Environmentalhazards and unpredictable costs associated with those wells could have anegative impact on the performance of the Company.*While many of the wellsthe Company drills are relatively low risk development wells, the Company alsoplans to drill exploratory wells to test new areas in coming months. Under the terms of the Company's drilling agreements with its partnerships theCompany also bears the risk for the investor partners interests in new wellsthrough an indemnification agreement.  The costs associated with problemsencountered in drilling, completing and operating wells can be significant, andcould adversely affect the profitability of the Company if such problems areencountered. 

* *

*Changesin the Tax Code could reduce the attractiveness of the Company's partnershipinvestments and reduce the revenues and profitability of thoseoperations. *Thepartnership interests sold by the Company offer investors significant taxbenefits under current tax regulations.  If the Congress changes the Codeand eliminates or reduces those benefits investments in the partnerships wouldbe less attractive to investors and fewer investors might invest.

* *

*Increasinginterest rates could increase the cost of the Company's borrowing. *Higher interest rates would increase theinterest costs of the Company's borrowing, and would make additional borrowingless attractive.  This could also make potential acquisitions and otheractivities funded with borrowed money less profitable, potentially reducing therate of growth of production and reserves. Consequently, the Company'sprofitability could be reduced.

23

CriticalAccounting Policies and Estimates

Wehave identified the following policies as critical to our business operations andthe understanding of our results of operations.  This listing is not acomprehensive list of all of our accounting policies.  In many cases, theaccounting treatment of a particular transaction is specifically dictated byaccounting principles generally accepted in the United States, with no need formanagement's judgment in their application.  There are also areas in whichmanagement's judgment in selecting any available alternative would not producea materially different result.  However, certain of our accountingpolicies are particularly important to the portrayal of our financial positionand results of operations and may require  the application of significantjudgment by our management; as a result, they are subject to an inherent degreeof uncertainty.  In applying those policies, our management uses itsjudgment to determine the appropriate assumptions to be used in thedetermination of certain estimates.  Those estimates are based on ourhistorical experience, our observance of trends in the industry, andinformation available from other outside sources, as appropriate.  For amore detailed discussion on the application of these and other accountingpolicies, see "Note 1 - Summary of significant accounting policies" in ourannual financial statements and related notes on Form 10-K/A.  Ourcritical accounting policies and estimates are as follows:

Revenue Recognition

TheCompany's drilling segment recognizes revenue from our drilling contracts withour publicly registered drilling programs using the percentage of completionmethod. These contracts are footage rate based and completed within nine totwelve months after the commencement of drilling. The Company providesgeological, engineering, and drilling supervision on the drilling and completionprocess and uses subcontractors to perform drilling and completion services.The percentage of completion method measures the percentage of contract costsincurred to date to the estimated total contract costs for each contract. TheCompany utilizes this method because reasonably dependable estimates of thetotal estimated costs can be made. Because the revenue recognized depends onestimates of the final contract costs, which are assessed continually duringthe term of the contract, recognized revenues are subject to revisions as thecontract progresses. Anticipated losses, if any, on uncompleted contracts wouldbe recorded at the time that our estimated costs exceeded the contract revenue.The Company has not experienced any contract losses in 2005 or 2004.

Naturalgas marketing is recorded on the gross accounting method.  Riley NaturalGas ("Riley"), our marketing subsidiary, purchases gas from many smallproducers and bundles the gas together to sell in larger amounts to purchasersof natural gas for a price advantage.  Riley has latitude in establishingprice and discretion in supplier and purchaser selection.  Natural gasmarketing revenues and expenses reflect the full cost and revenue of thosetransactions because Riley takes title to the gas it purchases from the variousproducers and bears the risks and enjoys the benefits of that ownership. Boththe realized and unrealized portions of the Riley commodity-based derivativetransactions for natural gas sales from marketing activities are included ingas sales from marketing activities or cost of gas marketing activities, asapplicable.

Salesof natural gas are recognized when natural gas has been delivered to a custodytransfer point, persuasive evidence of a sales arrangement exists, the rightsand responsibility of ownership pass to the purchaser upon delivery, collectionof revenue from the sale is reasonably assured and the sales price is fixed ordeterminable.  Natural gas is sold by the Company under contracts withterms ranging from one month to three years.  Virtually all of theCompany's contracts pricing provisions are tied to a market index, with certainadjustments based on, among other factors, whether a well delivers to agathering or transmission line, quality of natural gas and prevailing supplyand demand conditions, so that the price of the natural gas fluctuates toremain competitive with other available natural gas supplies.  As aresult, the Company's revenues from the sale of natural gas will suffer ifmarket prices decline and benefit if they increase.  The Company believesthat the pricing provisions of its natural gas contracts are customary in theindustry.

TheCompany currently uses the "Net-Back" method of accounting for transportation arrangementsof our natural gas sales.  The Company sells gas at the wellhead andcollects a price and recognizes revenues based on the wellhead sales pricesince transportation costs downstream of the wellhead are incurred by ourcustomers and reflected in the wellhead price. 

Salesof oil are recognized when persuasive evidence of a sales arrangement exists,the oil is verified as produced and is delivered in a stock tank, collection ofrevenue from the sale is reasonably assured and the sales price is determinable. The Company is currently able to sell all the oil that it can produce underexisting sales contracts with petroleum refiners and marketers.  TheCompany does not refine any of its oil production.  The Company's crudeoil production is sold to purchasers at or near the Company's wells undershort-term purchase contracts at prices and in accordance with arrangementsthat are customary in the oil industry.

24

Welloperations and pipeline income is recognized when persuasive evidence of anarrangement exists, services have been rendered, collection of revenues isreasonably assured and the sales price is fixed or determinable.  TheCompany is paid a monthly operating fee for each well it operates for outsideowners including the limited partnerships sponsored by the Company.  Thefee is competitive with rates charged by other operators in the area.  Thefee covers monthly operating and accounting costs, insurance and otherrecurring costs.  The Company may also receive additional compensation forspecial non-recurring activities, such as reworks and recompletions.

Valuation ofAccounts Receivable 

Management reviews accounts receivable todetermine which are doubtful of collection.  In making the determinationof the appropriate allowance for doubtful accounts, management considers theCompany's history of write-offs, relationships and overall credit worthiness ofits customers, and well production data for receivables related to welloperations. 

Accounting forDerivatives Contracts at Fair Value

The Company usesderivative instruments to manage its commodity and financial market risks.Accounting requirements for derivatives are complex; interpretation of theserequirements by standard-setting bodies is ongoing. The Company currently doesnot use hedge accounting treatment for its derivatives.

Derivatives arereported on the Condensed Consolidated Balance Sheets at fair value. Changes infair value of derivatives that are recorded in earnings in the consolidatedstatements of income as none of the Company's derivatives qualified for hedgeaccounting under the provisions of FAS 133.   

The measurement offair value is based on actively quoted market prices, if available. Otherwise, theCompany seeks indicative price information from external sources, includingbroker quotes and industry publications. If pricing information from externalsources is not available, measurement involves judgment and estimates. Theseestimates are based on valuation methodologies considered appropriate by theCompany's management. For individual contracts, the use of differentassumptions could have a material effect on the contract's estimated fairvalue. 

Use of Estimates in Long-Lived Asset Impairment Testing

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

Oiland Gas Properties

Explorationand development costs are accounted for by the successful efforts method.

The Company assesses impairment ofcapitalized costs of proved oil and gas properties by comparing net capitalizedcosts to estimated undiscounted future net cash flows on a field-by-field basisusing expected prices. Prices utilized in each year's calculation formeasurement purposes and expected costs are held constant throughout theestimated life of the properties. If net capitalized costs exceed undiscountedfuture net cash flows, the measurement of impairment is based on estimated fairvalue which would consider future discounted cash flows.

Propertyacquisition costs are capitalized when incurred.  Geological andgeophysical costs and delay rentals are expensed as incurred.  The costsof drilling exploratory wells are capitalized pending determination of whetherthe wells have discovered economically producible reserves.  If reservesare not discovered, such costs are expensed as dry holes. Development costs,including equipment and intangible drilling costs related to both producingwells and developmental dry holes are capitalized.

25

Unprovedproperties or leases are written-off to expense when it is determined that theywill expire or be abandoned.

Costsof proved developed properties, exploration and development costs andequipment, are depreciated or depleted by the unit-of-production method basedon estimated proved developed producing oil and gas reserves. Propertyacquisition costs are depreciated or depleted on the unit-of-production methodbased on estimated proved oil and gas reserves. The Company obtains new reservereports from an independent petroleum engineer annually as of December 31stof each year. The Company adjusts for any major acquisitions, new drilling anddivestures during the year as needed.

Uponsale or retirement of complete fields of depreciable or depletable property,the book value thereof, less proceeds or salvage value, is credited or chargedto income.  Upon sale of a partial unit of property, the proceeds arecredited to accumulated depreciation and depletion.

Deferred TaxAsset Valuation Allowance

Deferredtax assets are recognized for deductible temporary differences, net operatingloss carry forwards, and credit carry forwards if it is more likely than not thatthe tax benefits will be realized.  To the extent a deferred tax assetcannot be recognized under the preceding criteria, a valuation of allowance hasbeen established.

Thejudgments used in applying the above policies are based on management's evaluationof the relevant facts and circumstances as of the date of the financialstatements.  Actual results may differ from those estimates.

New Accounting Standards

TheFASB issued FIN 46, "Consolidation of Variable Interest Entities", inJanuary 2003 and amended the interpretation in December 2003. A variableinterest entity (VIE) is an entity in which its voting equity investors lackthe characteristics of having a controlling financial interest or where theexisting capital at risk is insufficient to permit the entity to finance itsactivities without receiving additional financial support from otherparties.  FIN 46 requires the consolidation of entities which aredetermined to be VIEs when the reporting company determines itself to be the primarybeneficiary (the entity that will absorb a majority of the VIE's expectedlosses, receive a majority of the VIE's residual returns, or both).  Theamended interpretation was effective for the first interim or annual reportingperiod ending after March 15, 2004, with the exception of special purposeentities for which the statement was effective for periods ending afterDecember 15, 2003.  We have completed a review of our partnershipinvestments and have determined that those entities do not qualify as VIEs.

OnDecember 16, 2004, the Financial Accounting Standards Board (FASB) issued FASBStatement No. 123R (revised 2004), "Share-Based Payment" which is arevision of FASB Statement No. 123, "Accounting for Stock-BasedCompensation".  Statement 123R supersedes APB opinion No. 25,"Accounting for Stock Issued to Employees", and amends FASB StatementNo. 95, "Statement of Cash Flows".  Generally, the approach inStatement 123R is similar to the approach described in Statement 123. However, Statement 123R requires all share-based payments to employees,including grants of employee stock options, to be recognized in the incomestatement based on their fair values.  Pro-forma disclosure is no longeran alternative.  The provisions of this statement become effective for ourfirst quarter 2006.  Management has not determined the impact that thisstatement will have on our consolidated financial statements.

RecentlyIssued Accounting Pronouncements

OnMarch 30, 2005, the FASB issued FASB Interpretation No. 47, "Accounting forConditional Asset Retirement Obligations" (FIN No. 47). This interpretationclarifies that the term "conditional asset retirement obligation" as used inStatement No. 143 refers to a legal obligation to perform an asset retirementactivity in which the timing and/or method of settlement are conditional on afuture event that may or may not be within the control of the entity incurringthe obligation. The obligation to perform the asset retirement activity isunconditional even though uncertainty exists about the timing and/or method ofsettlement. Thus, the timing and/or method of settlement may be conditional ona future event. Accordingly, an entity is required to recognize a liability forthe fair value of a conditional asset retirement obligation if the fair valueof the liability can be reasonably estimated. Uncertainty about the timingand/or method of settlement of a conditional asset retirement obligation shouldbe factored into the measurement of the liability, rather than the timing of recognitionof the liability, when sufficient information exits. FIN No. 47 will beeffective for the Company no later than the end of the fiscal year endedDecember 31, 2005. The Company does not expect any impact on the Company'sfinancial position or results of operations upon adoption of FIN No. 47.

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OnApril 4, 2005, the FASB issued FASB Staff Position (FSP) FAS 19-1 "Accountingfor Suspended Well Costs."  This staff position amends FASB Statement No.19 "Financial Accounting and Reporting by Oil and Gas Producing Companies" andprovides guidance about exploratory well costs to companies which use thesuccessful efforts method of accounting.  The position states thatexploratory well costs should continue to be capitalized if: 1) a sufficientquantity of reserves are discovered in the well to justify its completion as aproducing well and 2) sufficient progress is made in assessing the reserves andthe well's economic and operating feasibility.  If the exploratory wellcosts do not meet both of these criteria, these costs should be expensed, netof any salvage value. Additional annual disclosures are required to provideinformation about management's evaluation of capitalized exploratory wellcosts. In addition, the FSP requires annual disclosure of: 1) net changes fromperiod to period of capitalized exploratory well costs for wells that arepending the determination of proved reserves, 2) the amount of exploratory wellcosts that have been capitalized for a period greater than one year after thecompletion of drilling and 3) an aging of exploratory well costs suspended forgreater than one year with the number of wells it related to. Further, thedisclosures should describe the activities undertaken to evaluate the reservesand the projects, the information still required to classify the associatedreserves as proved and the estimated timing for completing the evaluation. TheCompany adopted FAS 19-1 during the third quarter of 2005 and will adopt theannual disclosures requirements in the Company's 10-K as of December 31, 2005.The application of this FSP did not have a significant impact on the Company'sfinancial position or results of operations. 

InJune 2005, the FASB issued SFAS No. 154, *Accounting Changes and ErrorCorrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3,*whichreplaces Accounting Principles Board Opinion No. 20, *Accounting Changes,*and SFAS No. 3, *Reporting Accounting Changes in Interim FinancialStatements,* and changes the requirements for the accounting for andreporting of a change in accounting principle. SFAS No. 154 requiresretrospective application for voluntary changes in accounting principle unlessit is impracticable to do so, and it applies to all voluntary changes inaccounting principle. It also applies to changes required by an accountingpronouncement in the unusual instance that the pronouncement does not includespecific transition provisions. When a pronouncement includes specifictransition provisions, those provisions should be followed. SFAS No. 154 iseffective for accounting changes and corrections of errors made in fiscal yearsbeginning after December 15, 2005. Consequently, we will adopt the provisionsof SFAS 154 for our fiscal year beginning January 1, 2006. We currently believethat adoption of the provisions of SFAS No. 154 will not have a material impacton our consolidated financial statements.

InJune 2005, the EITF reached a consensus on EITF Issue No. 04-5, *DeterminingWhether a General Partner, or the General Partners as a Group, Controls aLimited Partnership or Similar Entity When the Limited Partners Have CertainRights.* This consensus applies to voting right entities not within thescope of FASB Interpretation No. 46(R), *Consolidation of Variable InterestEntities,*in which the investor is the general partner in a limitedpartnership or functional equivalent. The EITF consensus is that the generalpartner in a limited partnership is presumed to control that limitedpartnership regardless of the extent of the general partner's ownershipinterest and, therefore, should include the limited partnership in itsconsolidated financial statements. The general partner may overcome thispresumption of control and not consolidate the entity if the limited partnershave either: (a) the substantive ability to dissolve (liquidate) the limitedpartnership or otherwise remove the general partner through substantivekick-out rights that can be exercised without having to show cause; or (b)substantive participating rights in managing the partnership. This guidancebecame immediately effective upon ratification by the FASB on June 2, 2005, forall newly formed limited partnerships and for existing limited partnerships forwhich the partnership agreements have been modified. For general partners inall other limited partnerships, the guidance is effective no later than thebeginning of the first reporting period in fiscal years beginning afterDecember 15, 2005. We do not expect the adoption of this guidance to have amaterial impact on our consolidated financial statements.

DisclosureRegarding Forward Looking Statements 

ThisForm 10-Q contains "forward-looking statements" within the meaning of Section27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act").All statements other than statements of historical facts included in andincorporated by reference into this Form 10-Q are forward-looking statements.These forward-looking statements are subject to certain risks, trends anduncertainties that could cause actual results to differ materially from thoseprojected. Among those risks, trends and uncertainties are the Company'sestimate of the sufficiency of its existing capital sources, its ability toraise additional capital to fund cash requirements for future operations, theuncertainties involved in estimating quantities of proved oil and natural gasreserves, in successfully drilling productive wells and in prospect developmentand property acquisitions and in projecting future rates of production, thetiming of development expenditures and drilling of wells, and the operatinghazards attendant to the oil and gas business. In particular, carefulconsideration should be given to cautionary statements made in this Form 10-Qand in the various reports the Company has filed with the Securities andExchange Commission. The Company undertakes no duty to update or revise theseforward-looking statements. 

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Whenused in the Form 10-Q, the words, "expect," "anticipate," "intend," "plan,""believe," "seek," "estimate" and similar expressions are intended to identifyforward-looking statements, although not all forward-looking statements containthese identifying words. Because these forward-looking statements involve risksand uncertainties, actual results could differ materially from those expressedor implied by these forward-looking statements for a number of importantreasons, including those discussed under "Management's Discussions and Analysisof Financial Condition and Results of Operations" and elsewhere in this Form10-Q. 

Item 3.    Quantitative and Qualitative DisclosureAbout Market Rate Risk

Interest Rate Risk

There have been no material changes in the reportedmarket risks faced by the Company since December 31, 2004.

Commodity Price Risk

The Company utilizes commodity-based derivativeinstruments to manage a portion of its exposure to price risk from its oil andnatural gas sales and marketing activities. These instruments consist ofNYMEX-traded natural gas futures contracts and option contracts for Appalachianand Michigan production and CIG-based contracts traded by JP Morgan forColorado production and purchase and sales contracts with customers deemed tobe derivatives used by its natural gas marketing company, Riley Natural Gas.These derivative instruments have the effect of locking in for specifiedperiods (at predetermined prices or ranges of prices) the prices the Companywill receive for the volume to which the derivative relates and, in the case ofRNG, the cost of gas supplies purchased for marketing activities. As a result,while these derivative instruments are structured to reduce the Company'sexposure to changes in price associated with the commodity, they also limit thebenefit the Company might otherwise have received from price changes associatedwith the commodity. The Company's policy prohibits the use of oil and naturalgas future and option contracts for speculative purposes.

The following tables summarize the open derivative andpurchase and sale contracts for Riley Natural Gas and PDC as of September 30,2005 and September 30, 2004.

Riley Natural Gas

Open Derivatives Contracts

Commodity

Type

Quantity

Weighted 

Total

Gas-Mmbtu

Average

Contract

Fair

Oil-Barrels

Price

Amount

Value

Total  Contracts as of September 30, 2005 

Natural Gas

Cash  Settled Sale

3,444,000 

$7.08

 $          24,392,650 

 $            (18,292,508)

Natural Gas

Cash  Settled Purchase

980,000 

$8.12

 $            7,953,380 

 $                4,635,487 

Natural Gas

Cash  Settled Sale Option

80,000 

$5.56

 $                          - 

 $                              1 

Natural Gas

Cash  Settled Purchase Option

40,000 

$7.06

 $                          - 

 $                 (253,652)

Natural Gas

Physical  Contract Sale

493,388 

$7.79

 $            3,843,514 

 $              (3,133,759)

Natural Gas

Physical  Contract Purchase

3,111,300 

$7.32

 $          22,785,381 

 $              16,897,291 

Contracts  maturing in 12 months following September 30, 2005 

Natural Gas

Cash  Settled Sale

2,724,000 

$7.28

 $          19,834,820 

 $            (15,485,473)

Natural Gas

Cash  Settled Purchase

870,000 

$8.20

 $            7,129,880 

 $                4,266,891 

Natural Gas

Cash  Settled Sale Option

80,000 

$5.56

 $                          - 

 $                              1 

Natural Gas

Cash  Settled Purchase Option

40,000 

$7.06

 $                          - 

 $                 (253,652)

Natural Gas

Physical  Contract Sale

469,413 

$7.79

 $            3,657,341 

 $              (3,049,437)

Natural Gas

Physical  Contract Purchase

2,481,300 

$7.62

 $          18,901,381 

 $              14,160,744 

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Prior  Year Total Contracts as of September 30, 2004   

Natural Gas

Cash  Settled Sale

3,920,000 

$5.51

 $          21,616,540 

 $              (5,842,600)

Natural Gas

Cash  Settled Purchase

1,150,000 

$6.11

 $            7,029,540 

 $                   706,260 

Natural Gas

Cash  Settled Sale Option

660,000 

$5.20

 $                          - 

 $                              - 

Natural Gas

Cash  Settled Purchase Option

330,000 

$6.97

 $                          - 

 $                 (124,075)

Natural Gas

Physical  Contract Sale

951,399 

$7.63

 $            7,263,314 

 $                     58,859 

Natural Gas

Physical  Contract Purchase

3,893,900 

$5.74

 $          22,339,079 

 $                4,569,306 

The  maximum term over which RNG is managing exposure to the variability of cash  flows for commodity price risk

is  37 months.

Petroleum Development  Corporation

Open Derivatives Contracts

Commodity

Type

Quantity

Weighted 

Total

Gas-Mmbtu

Average

Contract

Fair

Oil-Barrels

Price

Amount

Value

Total  Contracts as of September 30, 2005 

Natural  Gas

Purchase

11,754 

$6.82

 $                 80,182 

 $                     85,389 

Natural  Gas

Sale  Option

7,776,180 

$6.43

 $                          - 

 $                   909,974 

Natural  Gas

Purchase  Option

3,053,590 

$8.19

 $                          - 

 $            (11,334,641)

Crude  Oil

Sale  Option

38,889 

$32.30

 $                          - 

 $                              3 

Crude  Oil

Purchase  Option

19,445 

$40.00

 $                          - 

 $                 (506,298)

Contracts  maturing in 12 months following September 30, 2005 

Natural Gas

Purchase

11,754 

$6.82

 $                 80,182 

 $                     85,389 

Natural Gas

Sale Option

6,135,088 

$6.45

 $                          -  

 $                   602,627 

Natural Gas

Purchase  Option

2,233,044 

$8.02

 $                          - 

 $              (9,194,020)

Crude Oil

Sale Option

38,889 

$32.30

 $                          - 

 $                              3 

Crude Oil

Purchase  Option

19,445 

$40.00

 $                          - 

 $                 (506,298)

Prior Year  Total Contracts as of September 30, 2004   

Natural Gas

Purchase

11,679 

$4.82

 $                 56,254 

 $                     22,202 

Natural Gas

Sale Option

4,887,080 

$4.64

 $                          - 

 $                   247,949 

Natural Gas

Purchase  Option

1,974,075 

$5.57

 $                          - 

 $              (2,691,500)

Crude Oil

Sale

28,740 

$31.63

 $               909,046 

 $                 (489,155)

Crude Oil

Sale Option

172,440 

$32.30

 $            5,569,812 

 $                     50,025 

Crude Oil

Purchase  Option

86,220 

$40.00

 $            3,448,800 

 $                 (649,544)

The maximum  term over which PDC is managing exposure to the variability of cash flows for  commodity price risk

is 18 months.

See"Working Capital" in Management's Discussions of Liquidity andCapital Resources for the effect of these contracts on the Company's ConsolidatedBalance Sheet.

Theaverage NYMEX closing price for natural gas for the nine months of 2005 and theyear 2004 was $7.16 Mmbtu and $6.14 Mmbtu. The average NYMEX closing price foroil for the nine months of 2005 and the year 2004 was $53.40 bbl and $41.44bbl.  Future near-term gas prices will be affected by various supply anddemand factors such as weather, government and environmental regulation and newdrilling activities within the industry.

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Item 4.          Controlsand Procedures

***(a)******       *****Evaluation ofdisclosure controls and procedures**

The Company maintains disclosure controlsand procedures that are designed to ensure that information required to bedisclosed in the Company's reports under the Exchange Act is recorded,processed, summarized and reported within the time periods specified in theSEC's rules and forms, and that such information is accumulated andcommunicated to management, including the Company's Chief Executive Officer andChief Financial Officer, and the Company's Audit Committee and Board ofDirectors, as appropriate, to allow timely decisions regarding requireddisclosure. The Company's management, with participation of the Company's ChiefExecutive Officer and Chief Financial Officer, has conducted an evaluation ofthe effectiveness of the Company's disclosure controls and procedures (asdefined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of theend of the period covered by this quarterly report on Form 10-Q. 

As previously disclosed in the Company'sAmended Annual Report on Form 10-K/A for the year ended December 31, 2004, andin its amended quarterly report on Form 10-Q/A for the quarter ended March 31,2005, the Company determined that, as of December 31, 2004 and March 31, 2005,there were material weaknesses affecting its internal control over financialreporting and, as a result of those weaknesses, the Company's disclosurecontrols and procedures were not effective. Based upon the evaluation of theeffectiveness of the Company's disclosure controls and procedures as ofSeptember 30, 2005, the Company's Chief Executive Officer and Chief FinancialOfficer concluded that the Company disclosure controls and procedures were noteffective. 

*Remediationof Material Weaknesses in Internal Control*

As previously disclosed in the Company'sAmended Annual Report on Form 10-K/A for the year ended December 31, 2004, andin its amended quarterly report on Form 10-Q/A for the quarter ended March 31,2005, the Company determined that, as of the end of the fiscal 2004, there werematerial weaknesses in its internal control over financial reporting relatingto improper accounting of (1) derivatives transactions, (2) oil and gasproperty, (3) asset retirement obligations, and (4) provision for income taxes.The Company's management and Audit Committee have dedicated significantresources to assessing the underlying issues giving rise to the aforementionedaccounting errors and to ensure that proper steps have been and are being takento improve our internal controls.  We have assigned the highest priorityto the correction of the related control deficiencies and have taken and willcontinue to take action to fully correct them.  Management is committed toinstilling strong control policies and procedures and ensuring that the 'toneat the top' is committed to accuracy and completeness in all financialreporting.  The Company's Audit Committee will continually be updated asto the progress and status of the remediation initiatives to ensure they areadequately implemented.  As of the date of this filing, while we havecorrected the financial statements, we have not completed the remediation ofthese material weaknesses; however, we believe that the remediation initiativesoutlined below, when completed, will be sufficient to eliminate the materialweaknesses in internal control over financial reporting as discussedabove.  

Asof the date of this filing, the remediation initiatives management has and willcontinue to implement include:  
- The     Company is implementing a training initiative to increase the Company's     technical expertise.  The programs offered through this training     initiative will include basic and advanced oil and natural gas accounting     training programs, as well as general accounting, financial reporting     (including SEC reporting), and income tax training programs.  Also,     related to this initiative, the Company has purchased licenses for     accounting research software. Additionally, the CFO or a qualified     designee will be responsible for the periodic review of the documentation     and calculations related to oil and gas properties.

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- The     Company currently does not use hedge accounting treatment; however, in the     future when using hedge accounting, the Company will implement additional     controls with respect to accounting for derivative transactions in     accordance with SFAS No. 133.  These controls include thorough and     formal documentation of all potential derivative transactions prior to     initiation of the transaction.  This documentation will include the     hedging relationship, the entity's risk management objective and strategy     for undertaking the hedge, including identification of the hedging     instrument, the hedged item, the nature of the risk being hedged, and the     method of assessing the hedging instrument's effectiveness.  The     Company is in the process of evaluating derivative accounting software to     be implemented to calculate the impact of derivative contracts on the     financial statements.  The Company will also seek the input of its     independent derivative expert to assist with the selection of the     derivative accounting software.  Additionally, the CFO or a qualified     designee will be responsible for the periodic review of the documentation     and calculations of derivative transactions.  The Company also has     utilized a derivative expert to assist the Company in evaluating its     current derivative transactions to ensure that they have been properly     reported and will utilize derivative experts in the future as needed.
- The     Company has re-evaluated and corrected its documentation, policies and     procedures, and templates with respect to accounting for its oil and gas     properties in compliance with generally accepted accounting principles.      The design and effective operation of proper policies and procedures as     well as the correction of these documents will ensure the accuracy of oil     and gas property valuation in accordance with generally accepted     accounting principles.  This includes documented procedures to     identify significant components of oil and gas property calculations     including field designation, reserves and applicable set-up costs.      This documentation also includes correcting the carry-forward schedules     utilized to calculate the depreciation, depletion and amortization with     the correct information and identification of the components of the     calculation.  Additionally, the CFO or a qualified designee will be     responsible for the periodic review of the documentation and accounting     for oil and gas properties, including related calculations. Also, the     Company plans to utilize an independent specialist to review the Company's     accounting for oil and natural gas properties, including the Company's     documentation as well as templates. The specialist will be an accounting     firm with significant oil and natural gas accounting and income tax     experience and SEC experience and will also be utilized in identifying and     implementing new accounting standards and review of our income tax reporting     procedures.
- The     Company has reevaluated and corrected its documentation, policies and     procedures, and templates with respect to its accounting for asset     retirement obligations. The specialist discussed in the previous paragraph     will also be utilized to help verify these practices and implement any new     requirements.
- The     Company has reevaluated and corrected its documentation, policies and     procedures, and templates with respect to its accounting for income taxes     and the related disclosures in its financial statements. The Company will     utilize a qualified independent tax expert to periodically review the     calculation of income taxes and the related disclosures for reporting     purposes and to identify and help implement any new rules or regulations.

**{b}Changes in Internal Control Over Financial Reporting**

** **

There was no change in our internalcontrol over financial reporting during the quarter ended September 30, 2005,that materially affects, or is reasonably likely to materially affect, ourinternal control over financial reporting. However, subsequent to September 30,2005, we are in the process of implementing the remedial actions describedabove.

Although we have taken steps as referredto above to correct the material weaknesses, they were not remediated as ofDecember 31, 2005.

Effective January 1, 2006 the Companyreorganized the structure of its accounting department to provide a betterdistribution of responsibilities and the work load associated with theCompany's accounting and financial reporting. As a part of the reorganization,several additional positions were created in the accounting department. TheController's position was eliminated and new positions for a Director ofAccounting Operations and a Director of Financial Reporting were created. TheCompany's controller was slated to become the Director of Financial Reporting,however, she chose to resign her position with the Company but is continuing toact as a consultant and will continue to perform the same duties untilappropriate replacements are trained. The CFO will oversee the responsibilitiesof the Director of Financial Reporting until a qualified candidate has beenhired to fill the position. The Company is currently seeking qualifiedaccountants to fill certain of the new positions. The Company believes that thereorganization, when completed, will allow it to better meet its currentfinancial and accounting obligations and to grow to fill future needs.

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PARTII - OTHER INFORMATION

Item 1.  Legal Proceedings

The Company is not a party to any legal actions thatwould materially affect the Company's operations or financial statements.

Item 2.  Changes in Securities, Use of Proceedsand Issuer Purchases of Equity Securities

ISSUER PURCHASES OF EQUITY SECURITIES

(d)

(c)

Maximum Number  

Total Number

(or  Approximate 

of Shares 

Dollar Value)  of 

(a)

Purchased as 

Shares that  May 

Total Number 

(b)

Part of  Publicly 

Yet Be  Purchased 

Of Shares 

Average Price

Announced  Plans 

Under the  Plans

Period

Purchased

Paid per Share  

or Programs 

or Programs 

May  1 - May 31, 2005

331,796 

$23.75 

331,796 

1,327,184 

Total  

331,796 

$23.75 

331,796 

1,327,184 

On March 18, 2005the Company publicly announced the authorization by its Board of Directors topurchase up to 2% of the Company's outstanding common stock (331,796) at fairmarket value at the date of purchase. At a meeting held June 10, 2005, theBoard of Directors of Petroleum Development Corporation approved an amendmentof the size of the stock repurchase from 2% to 10% (1,658,980 shares) of theCompany's outstanding common stock. Under the program, the Board has discretionas to the dates of purchase and amounts of stock to be purchased and whether ornot to make purchases. This program is scheduled to expire on December 31,2005. See Note 11 to the financial statements above.

Item 6.  Exhibits

(a)        Exhibits

Exhibit Name

Exhibit

Number

Location

Acknowledgement of Independent Registered

   Public Accounting Firm

23.1

Filed herewith

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

  Executive Officer

31.1

Filed herewith.

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

  Financial Officer

31.2

Filed herewith.

Title 18 U.S.C. Section 1350 (Section 906 of Sarbanes- 

32

Filed herewith.

Oxley Act of 2002) Certifications by Chief Executive

Officer and Chief Financial Officer of Petroleum

Development Corporation

32

SIGNATURES

            Pursuant to the requirements of the Securities Exchange Act of 1934 theregistrant has duly caused this report to be signed on its behalf by theundersigned thereunto duly authorized.

Petroleum Development Corporation

 (Registrant)

Date:    January 11, 2006

/s/ Steven R.  Williams                   

Steven R. Williams

Chief Executive Officer and President

Date:    January 11, 2006

/s/ Darwin L.  Stump                   

Darwin L. Stump

Chief Financial Officer

33 |
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