CONFORMED COPY

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K/A

[]ANNUAL REPORT PURSUANT TO SECTION 13 or 15 (d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2002

Commission File Number 000-49674

[] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transaction period from to

PDC 2001-B LIMITED PARTNERSHIP

(Exact name of registrant as specified in its charter)

West Virginia

(State or other jurisdiction of

incorporation or organization)

55-0779832

(I.R.S. Employer

Identification No.)

103 East Main Street, Bridgeport, West Virginia 26330

(Address of principal executive offices) (zip code)

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

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

General and Limited Partnership Interests

(Title of class)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes X No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]

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

PART I

ITEM 1. BUSINESS

General

PDC 2001-B Limited Partnership ("the Partnership") is a limited partnership formed on September 5, 2001 pursuant to the West Virginia Uniform Limited Partnership Act. Petroleum Development Corporation ("PDC") serves as Managing General Partner of the Partnership.

Since the commencement of operations on September 5, 2001, the Partnership has been engaged in onshore, domestic oil and natural gas exploration exclusively in the Rocky Mountain Region. Eleven limited partners contributed $400,000; a total of 608 additional general partners contributed initial capital of $12,278,577; and PDC (Managing General Partner) contributed $2,757,591 in capital as a participant in accordance with contribution provisions of the Limited Partnership Agreement (the Agreement).

Under the terms of the Agreement, the allocation of revenues is as follows:

	Allocation of Revenues
Additional General and Limited Partners	80 %
Managing General Partner	20 %

Operating and direct costs are allocated and charged to the additional general and limited partners and the Managing General Partner in the same percentages as revenues are allocated. Leasehold, drilling and completion costs, and equipment costs are borne 80% by the additional general and limited partners and 20% by the Managing General Partner.

Employees

The Partnership has no employees, however, PDC has approximately 94 employees which include a staff of geologists, petroleum engineers, landmen and accounting personnel who administer all of the partnership's operations.

Plan of Operations

The Partnership participated in the drilling of nineteen gross wells (16.78 net) during 2001 and will continue to operate and produce its 18 gross (15.91 net) productive wells. The Partnership does not have unexpended initial capital and no additional drilling activity is planned.

See Item 2 herein for information concerning the Partnership's gas wells.

Markets for Oil and Gas

The availability of a market for any oil and gas produced from the operations of the Partnership will depend upon a number of factors beyond the control of the Partnership which cannot be accurately predicted. These factors include the proximity of the Partnership wells to and the capacity of natural gas pipelines, the availability and price of competitive fuels, fluctuations in seasonal supply and demand, and government regulation of supply and demand created by its pricing and allocation restrictions. Oversupplies of gas can be expected to occur from time to time and may result in the Partnership's wells being shut-in or curtailed. Increased imports of oil and natural gas have occurred and are expected to continue. The effects of such imports could adversely impact the market for domestic oil and natural gas. All oil and gas is sold under contracts based market sensitive indexes that vary from month to month. No fixed price contracts are in place. The Partnership sold oil and natural gas to several entities of which three customers, Duke Energy Field Services, Teppco Crude Oil, L.P., and Williams Production RMT Company accounted for 38.9%, 33.5% and 22.2% of the Partnership's total oil and natural gas sales for the year ended December 31, 2002 and 24.3%, 65.5% and 10.2% for 2001, respectively.

Derivatives and Hedging Activities

The Managing General Partner, through its subsidiary Riley Natural Gas, has been in the gas marketing business since 1986 . During that time period, the Managing General Partner has utilized and continues to utilize commodity based derivative instruments as hedges to manage a portion of the Partnership's exposure to price volatility stemming from natural gas production. These instruments consist of costless collars and option contracts traded on the New York Mercantile Exchange. The costless collars and option contracts hedge committed and anticipated natural gas sales, generally forecasted to occur within a 12 month period. The Managing General Partner does not hold or issue derivatives for trading or speculative purposes and permits utilization of hedges only if there is an underlying physical position. The Partnership has not hedged any of its oil production. The Partnership has not hedged any of its oil production. See "Commdity Price Risk" under Item 7A.

Notwithstanding the measure taken by the Managing General Partner to attempt to control price risk, the Partnership remains subject to price fluctuations for natural gas and oil sold in the spot market. The Managing General Partner continues to evaluate the potential for reducing these risks by entering into hedge transactions. In addition, the Managing General Partner may also close out any portion of hedges that may exist from time to time.

Competition

The Partnership competes in marketing its gas and oil with numerous companies and individuals, many of which have financial resources, staffs and facilities substantially greater than those of the Partnership or Petroleum Development Corporation.

State Regulations

State regulatory authorities have established rules and regulations requiring permits for well operations, reclamation bonds and reports concerning operations. States also have statutes and regulations concerning the spacing of wells, environmental matters, and conservation, and have established regulations concerning the unitization and pooling of oil and gas properties and maximum rates of production from oil and gas wells. The Partnership believes it has complied in all material respects with applicable state regulations. The Partnership estimates it has spent approximately $7,200 and $85,900 in 2002 and 2001, respectively to comply with federal and state regulations.

Federal Regulations

Regulation of Liquid Hydrocarbons. Liquid hydrocarbons (including crude oil and natural gas liquids) were subject to federal price and allocation controls until January 1981 when controls were effectively eliminated by executive order of the President. As a result, to the extent the Partnership sells oil produced from its properties, those sales are at unregulated market prices.

Although it appears unlikely under present circumstances that controls will be reimposed upon liquid hydrocarbons, it is possible Congress may enact such legislation at a future date.

Natural Gas Regulation. Sale of natural gas by the Partnership is subject to regulation of production, transportation and pricing by governmental regulatory agencies. Generally, the regulatory agency in the state where a producing well is located regulates production activities and, in addition, the transportation of gas sold intrastate. The Federal Energy Regulatory Commission (FERC) regulates the operation and cost of interstate pipeline operators who transport gas. Currently the price of gas sold by the Partnership is not regulated by any state or federal agency.

Proposed Regulation. Numerous proposals concerning energy are being considered by the United States Congress, various state legislatures and regulatory agencies. The possible outcome and effect of these proposals cannot be accurately predicted.

Environmental and Safety Regulation. The Partnership believes that it complies, in all material respects, with all legislation and regulations affecting its operations in the drilling and production of oil and gas wells and the discharge of wastes. To date, compliance with such provisions and regulations has not had a material effect upon the Partnership's expenditures for capital equipment, its operations or its competitive position. The cost of such compliance is not anticipated to be material in the future.

ITEM 2. PROPERTIES

Drilling Activity

The following table sets forth the results of the Partnerships' drilling activity from September 5, 2001 (date of inception) to December 31, 2002. All of the Partnership's wells drilled and producing are located in Colorado.

Development Wells
Gross Wells			Net Wells
Productive	Dry	Total	Productive	Dry	Total
18	1	19	15.91	.87	16.78

The Partnership has not participated in any exploratory wells. No additional drilling activity is planned.

Productive Wells

As outlined in the above table, the Partnership has a total of 18 gross productive wells (15.91 net wells) all of which are located in the Colorado.

A "productive well" is a well producing, or capable of producing, oil and gas in commercial quantities. For purposes of the above table, a "gross well" is one in which the Partnership has a working interest and a "net well" is a gross well multiplied by the Partnership's working interest to which it is entitled under its drilling agreement.

Title to Properties

The Partnership's interests in producing acreage are in the form of assigned direct interests in leases. Such properties are subject to customary royalty interests generally contracted for in connection with the acquisition of properties, and could be subject to liens incident to operating agreements, liens for current taxes and other burdens. The Partnership believes that none of these burdens materially interfere with the use of such properties in the operation of the Partnership's business.

As is customary in the oil and gas industry, little or no investigation of title is made at the time of acquisition of undeveloped properties (other than a preliminary review of local mineral records). Investigations are generally made, including in most cases receiving a title opinion of legal counsel, before commencement of drilling operations. A thorough examination of title has been made with respect to all of the Partnership's producing properties and the Partnership believes that it has generally satisfactory title to such properties.

ITEM 3. LEGAL PROCEEDINGS

The Managing General partner as driller/operator is not party to any legal action that would materially affect the Managing General Partner's or Partnership's operations or financial statements.

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

None.

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND SECURITY HOLDER MATTERS

At December 31, 2001, PDC 2001-B Limited Partnership had one Managing General Partner, 11 Limited Partners who fully paid for 20.0 units at $20,000 per unit of limited partnership interests and a total of 608 Additional General Partners who fully paid for 613.92884 units at $20,000 per unit of additional general partnership interests. No established public trading market exists for the interests. During 2002 in accordance with the Partnership Agreement, all Additional General Partners were converted to Limited Partners. At December 31, 2002, the Partnership had one Managing General Partner and 619 limited partners who paid for 633.92884 units at $20,000 per unit. No established public trading market exits for the intersts.

Limited and additional general partnership interests are transferable, however no assignee of an interest in the Partnership can become a substituted partner without the written consent of the transferor and the Managing General Partner.

ITEM 6. SELECTED FINANCIAL DATA

The selected financial data presented below has been derived from audited financial statements of the Partnership appearing elsewhere herein.

	Year Ended December 31, 2002	Period from September 5, 2001 (date of inception) to December 31, 2001
Oil and Gas Sales	$2,292,809	307,754
Costs and Expenses	2,225,604	694,762
Net Income (loss)	68,168	(370,453)
Allocation of Net Income (loss):
Managing General Partner	13,634	(10,698)
Limited and Additional General Partners	54,534	(359,755)
Per Limited and Additional General Partner Unit	86	(568)
Total Assets	12,154,226	13,746,489
Cash Distributions:
Managing General Partner	334,013	-
Limited and Additional General Partners	1,336,059	-

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

Liquidity and Capital Resources

The Partnership was funded on September 5, 2001 with initial Limited and Additional General Partner contributions of $12,678,577 and the Managing General Partner's cash contribution of $2,757,591 in accordance with the Agreement. After payment of syndication costs of $1,331,251 and a one-time management fee to the managing general partner of $316,964 the Partnership had available cash of $13,787,953 for Partnership activities.

The Partnership began exploration and development activities subsequent to the funding of the Partnership and completed these activities by December 31, 2001. Nineteen wells have been drilled of which 18 are productive. No additional wells will be drilled.

The Partnership had net working capital at December 31, 2002 of $435,479.

Operations are expected to be conducted with available funds and revenues generated from oil and gas activities. No bank borrowings are anticipated.

Results of Operations

2002 Results Compared with 2001

All of the Partnership's 18 productive wells were producing for most of 2002 resulting in oil and gas sales of $2,292,809 compared to $307,754 in 2001, when the wells of the Partnership were drilled and completed, mostly in the third and fourth quarters. For the year ended December 31, 2002, the Partnership sold 845,069 Mcf of gas and 34,393 barrels of oil at average sales prices of $1.66 and $25.94, respectively. This is compared with 54,612 Mcf of gas and 10,605 barrels of oil sold at average sales prices of $1.94 and $19.01, respectively for the year ended December 31, 2001. Lifting cost per Mcfe in 2002 amounted to $ 0.43 as compared to $0.33 for 2001. Revenue distributions to the partners commenced in the first quarter of 2002. Although the Partnership had a modest net income of $68,168, Deprecation, depletion and amortization is a non-cash expense and the Partnership distributed cash in the amount of $1,670,072 to the partners during 2002.

The Partnership's revenues from oil and natural gas sales will be affected by changes in prices. Oil and natural gas prices are subject to general market conditions which drive the pricing changes.

The principal effects of inflation upon the Partnership relate to the costs required to drill, complete and operate oil and gas wells. The Partnership expects these costs to remain somewhat stable over the next year.

2001 Results

Oil and gas sales commenced during the fourth quarter of 2001 with revenue distribution to the partners commencing in the first quarter of 2002. In accordance with the Partnership agreement, a one-time management fee equal to 2 1/2% of investors' subscriptions was charged to the Partnership in the amount of $316,964 by the Managing General Partner. This fee was paid by the Partnership to the managing general partner of the Partnership upon funding of the Partnership.

Critical Accounting Policies

Certain accounting policies are very important to the portrayal of Partnership's financial condition and results of operations and require management's most subjective or complex judgments. The policies are as follows:

Impairment of Long-Lived Assets

The Partnership assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to undiscounted future cash flows on a field-by-filed basis using expected prices. Prices utilized in each year's calculation for measurement purposes and expected costs are held constant throughout the life of the properties. If net capitalized costs exceed undiscounted future net cash flow, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows.

The judgment used in applying the above policies are based on management's evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results may differ from those estimates. See additional discussions in this Management's Discussion and Analysis

New Accounting Standards

In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations" ("SFAS No. 143"). SFAS No. 143 requires the Partnership to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. The Partnership also records a corresponding asset within oil and gas properties which is depreciated over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation will be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The Partnership is required to adopt SFAS No. 143 on January 1, 2003. At this time, the Partnership does not believe the adoption of this Statement will have a material effect on its financial position, results of operations, cash flows or disclosures.

Item 7 A. Quantitative and Qualitative Disclosure About Market Risk.

Market-Sensitive Instruments and Risk Management

The Partnership's primary market risk exposure is commodity price risk. This exposure is discussed in detail below:

Commodity Price Risk

Natural gas and oil prices have been unusually volatile for the past 24 months, and the Partnership anticipates continued volatility in the future. Currently, the NYMEX futures reflect a market expectation of gas prices at Henry Hub close to or above record prices per million Btu's (mmbtu). These prices look strong for the remainder of the year with natural gas storage levels at five-year low levels. The Partnership believes that volatility creates the possibility of both periods of low prices and continued high prices.

Earlier this year, Colorado gas prices had been adversely effected by an increase in the negative "basis" between NYMEX and Colorado prices. Pipeline capacity from the area to major markets in California and the Midwest is not adequate to move the new supplies developed over the past several years by oil and gas companies when local demand is at low summer levels. The result has been lower prices and some limited curtailment of production during the summer months. This situation has corrected itself some this winter. Several major pipeline projects are underway and in planning stages that will improve capacity over the next several years. There remains a possibility of greater seasonal volatility in Colorado than some other producing areas, but the Partnership expects the situation to improve over the coming year.

Because of the uncertainty surrounding gas prices the Managing General Partner used hedging agreements to manage some of the impact of fluctuations in prices for the Managing General Partner and its various limited partnership's share of production. Through October of 2003 the Partnership has in place a series of costless collars and option contracts. Under the collar arrangements, if the applicable index rises above the ceiling price, the Partnership pays the counterparty, however if the index drops below the floor the counterparty pays the Partnership. For the period from January 2003 through March 2003, the Partnership has floors in place at $2.75 on 26,667 mmbtu of monthly production and ceilings in place in a range from $3.28 to $4.45 on 8,889 mmbtu of monthly production. For the period April 2003 through October 2003, the Partnership has floors in place in at $2.50 on 17,778 mmbtu of monthly production and ceilings in place at $3.13 on 4,444 mmbtu of monthly production. The fair value of these floors and ceilings as of December 31, 2002 is $8,960.

As of December 31, 2002 the Partnership had option contracts for the sale of 57,778 mmbtu of natural gas with an average ceiling price of $3.47 and for the sale of 204,444 mmbtu of natural gas with an average floor price of $2.60.

Disclosure of Limitations

As the information above incorporates only those exposures that exist at December 31, 2002, it does not consider those exposures or positions which could arise after that date. As a result, the Partnership's ultimate realized gain or loss with respect to commodity price fluctuations will depend on the exposures that arise during the period, the Partnership's hedging strategies at the time and commodity prices at the time.

PART III

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The response to this Item is set forth herein in a separate section of this Report, beginning on Page F-1.

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

FINANCIAL DISCLOSURE.

NONE.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY

The Partnership has no directors or executive officers. The Partnership is managed by Petroleum Development Corporation (the Managing General Partner). Petroleum Development Corporation's common stock is traded in the NASDAQ National Market and Form 10-K for 2002 has been filed with the Securities and Exchange Commission.

ITEM 11. EXECUTIVE COMPENSATION.

NON-APPLICABLE.

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

STOCKHOLDER MATTERS.

NON-APPLICABLE.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Pursuant to the authorization contained in the Limited Partnership Agreement, PDC receives fees for services rendered and reimbursement of certain expenses from the Partnership. The following table presents compensation or reimbursements by the Partnership to PDC or other related parties for the year ended December 31, 2002 and period from September 5, 2001 (date of inception) to December 31, 2001.

	2002	2001
Drilling and completion costs	$ -	13,787,953
Lifting cost	446,991	48,410
Syndication cost and management fee	-	1,648,215
Tax return preparation	5,405	3,695
Direct administrative cost	2,605	1,610

ITEM 14. CONTROLS AND PROCEDURES

Under the supervision and with the participation of the Managing General Partner's management, including the Managing General Partner's Chief Executive Officer and Chief Financial Officer, the Partnership has evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Exchange Act Rule 13a-14(c)) within 90 days of the filing date of this annual report, and, based on their evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these disclosure controls and procedures are effective in all material respects, including those to ensure that information required to be disclosed in reports filed or submitted under the Securities Exchange Act is recorded, processed, summarized, and reported, within the time periods specified in the Commission's rules and forms, and is accumulated and communicated to management, including the Managing General Partner's Chief Executive Officer and Chief Financial Officer, as appropriate to allow for timely disclosure. There have been no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a) (1) Financial Statements

See Index to Financial Statements on F-2

(2) Financial Statement Schedules

See Index to Financial Statements on page F-2. All financial statement schedules are omitted because they are not required, inapplicable, or the information is included in the Financial Statements or Notes thereto.

CONFORMED COPY

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	PDC 2001-B Limited Partnership By its Managing General Partner Petroleum Development Corporation
	By /s/ James N. Ryan James N. Ryan, Chairman
	July 23, 2003

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:


Signature	Title	Date

/s/ James N. Ryan James N. Ryan	Chairman, Chief Executive Officer and Director	July 23, 2003

/s/ Steven R. Williams Steven R. Williams	President and Director	July 23, 2003

/s/ Dale G. Rettinger Dale G. Rettinger	Executive Vice President, Treasurer and Director (principal financial and accounting officer	July 23, 2003

/s/ Vincent F. D'Annunzio Vincent F. D'Annunzio	Director	July 23, 2003

FORM 10-K/A CERTIFICATION

I, James N. Ryan, certify that:

1. I have reviewed this amended annual report on Form 10-K/A of PDC 2001-B Limited Partnership;

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

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

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

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

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

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

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

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

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

Date: July 23, 2003

/s/ James N. Ryan

James N. Ryan

Chief Executive Officer of Petroleum Development Corporation

Managing General Partner of PDC 2001-B Limited Partnership

FORM 10-K/A CERTIFICATION

I, Dale G. Rettinger, certify that:

1. I have reviewed this amended annual report on Form 10-K/A of PDC 2001-B Limited Partnership;

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

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

Date: July 23, 2003

/s/ Dale G. Rettinger

Dale G. Rettinger

Chief Financial Officer of Petroleum Development Corporation

Managing General Partner of PDC 2001-B Limited Partnership

PDC 2001-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Financial Statements for Annual Report

on Form 10-K to Securities and Exchange

Commission

Year Ended December 31, 2002 and

Period from September 5, 2001

(Date of Inception)

to December 31, 2001

(With Independent Auditors' Report Thereon)

F-1

PDC 2001-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Index to Financial Statements

Independent Auditors' Report	F-3
Balance Sheets - December 31, 2002 and 2001	F-4
Statements of Operations - Year Ended December 31, 2002 and Period from September 5, 2001 (Date of Inception) to December 31, 2001	F-5
Statements of Partners' Equity - Year Ended December 31, 2002 and Period from September 5, 2001 (Date of Inception) to December 31, 2001	F-6
Statements of Cash Flows - Year Ended December 31, 2002 and Period from September 5, 2001 (Date of Inception) to December 31, 2001	F-7
Notes to Financial Statements	F-8

All financial statement schedules have been omitted because they are not applicable or not required or for the reason that the required information is shown in the financial statements or notes thereto.

F-2

Independent Auditors' Report

To the Partners

PDC 2001-B Limited Partnership:

We have audited the financial statements of PDC 2001-B Limited Partnership (a West Virginia limited partnership) as listed in the accompanying index. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of PDC 2001-B Limited Partnership as of December 31, 2002 and 2001, and the results of its operations and its cash flows for the year ended December 31, 2002 and for the period from September 5, 2001 (date of inception) to December 31, 2001, in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

Pittsburgh, Pennsylvania

March 10, 2003

F-3

PDC 2001-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Balance Sheets

December 31, 2002 and 2001

Assets

Current assets:	2002	2001
Cash	$ 4,136	16,445
Accounts receivable - oil and gas revenues	444,049	259,344
Total current assets	448,185	275,789

Oil and gas properties, successful efforts method (notes 3 and 5):	13,787,953	13,787,953
Less accumulated depreciation, depletion and amortization	2,081,912	317,253

	11,706,041	13,470,700
	$12,154,226	13,476,489

Current Liabilities and Partners' Equity

Current liabilities:
Accrued expenses	$ 12,706	12,025
Total current liabilities	12,706	12,025

Partners' equity	12,141,520	13,734,464
	$12,154,226	13,746,489

See accompanying notes to financial statements.

F-4

PDC 2001-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Statements of Operations

Year Ended December 31, 2002 and

Period from September 5, 2001 (Date of Inception) to December 31, 2001

Revenues:
	2002	2001
Sales of oil and gas	$2,292,809	307,754
Interest income	964	16,555
	2,293,773	324,309
Expenses (note 3):
Management fee	-	316,964
Lifting costs	446,991	48,410
Independent engineering fee	2,314	3,000
Independent audit fee	3,631	3,830
Tax return preparation	5,405	3,695
Direct administrative cost	2,605	1,610
Depreciation, depletion and amortization	1,764,659	317,253
	2,225,605	694,762

Net income (loss)	$ 68,168	(370,453 )

Net income (loss) per limited and additional general partner unit	$ 86	(568)

See accompanying notes to financial statements.

F-5

PDC 2001-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Statements of Partners' Equity

Year Ended December 31, 2002 and

Period from September 5, 2001 (Date of Inception) to December 31, 2001

	Limited and additional general partners	Managing general Partner	Accumulated Other Comprehensive Income	Total
Partners' initial capital contributions	$12,678,577	2,757,591	-	15,436,168
Syndication costs	(1,331,251)	-		(1,331,251)

Net loss	(359,755 )	(10,698 )		(370,453 )
Balance, December 31, 2001	10,987,571	2,746,893		13,734,464

Distribution to partners	(1,336,059)	(334,013)		(1,670,072)

Comprehensive income:
Net income	54,534	13,634		68,168
Change in fair value of outstanding hedging positions			8,960
Reclassification adjustment for settled contracts included in net income			-
Other comprehensive income			8,960	8,960
Comprehensive income				77,128

Balance, December 31, 2002	$9,706,046	2,426,514	8,960	12,141,520

See accompanying notes to financial statements.

F-6

PDC 2001-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Statements of Cash Flows

Year Ended December 31, 2002 and

Period from September 5, 2001 (Date of Inception) to December 31, 2001

	2002	2001
Cash flows from operating activities:
Net income (loss)	$68,168	(370,453)
Adjustments to reconcile net income (loss) to net cash used by operating activities:
Depreciation, depletion and amortization	1,764,659	317,253
Changes in operating assets and liabilities:
Increase in accounts receivable - oil and gas revenues	(175,745)	(259,344)
Increase in accrued expenses	681	12,025

Net cash provided from (used by) operating activities	1,657,763	(300,519 )

Cash flows from investing activities:
Expenditures for oil and gas properties	-	(13,787,953 )

Net cash used by investing activities	-	(13,787,953 )

Cash flows from financing activities:
Limited and additional general partner contributions	-	12,678,577
Managing General Partner contribution	-	2,757,591
Syndication cost paid	-	(1,331,251)
Distributions to partners	1,670,072	-

Net cash (used by) provided from financing activities	(1,670,072 )	14,104,917

Net (decrease) increase in cash	(12,309)	16,445
Cash at beginning of period	16,445	-
Cash at end of period	$ 4,136	16,445

See accompanying notes to financial statements.

F-7

PDC 2001-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

December 31, 2002

(1) Summary of Significant Accounting Policies

Partnership Financial Statement Presentation Basis

The financial statements include only those assets, liabilities and results of operations of the partners which relate to the business of PDC 2001-B Limited Partnership (the Partnership). The statements do not include any assets, liabilities, revenues or expenses attributable to any of the partners' other activities.

Oil and Gas Properties

The Partnership follows the successful efforts method of accounting for the cost of exploring for and developing oil and gas reserves. Under this method, costs of development wells, including equipment and intangible drilling costs related to both producing wells and developmental dry holes, and successful exploratory wells are capitalized and amortized on an annual basis to operations by the units-of-production method using estimated proved developed reserves determined at year end by an independent petroleum engineer, Wright & Company, Inc. If a determination is made that an exploratory well has not discovered economically producible reserves, then its costs are expensed as dry hole costs.

The Partnership assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to undiscounted future cash flows on a field-by-field basis using expected prices. Prices utilized in each year's calculation for measurement purposes and expected costs are held constant throughout the estimated life of the properties. If net capitalized costs exceed undiscounted future net cash flow, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows.

Based on the Managing General Partner's experience, management believes site restoration, dismantlement and abandonment costs, net of salvage to be immaterial in relation to operating costs. These costs are being expensed when incurred.

Revenue Recognition

Sales of natural gas and oil are recognized when sold.

Income Taxes

Since the taxable income or loss of the Partnership is reported in the separate tax returns of the partners, no provision has been made for income taxes on the Partnership's books.

Under federal income tax laws, regulations and administrative rulings, certain types of transactions may be accorded varying interpretations. Accordingly, the Partnership's tax return and, consequently, individual tax returns of the partners may be changed to conform to the tax treatment resulting from a review by the Internal Revenue Service.

Derivatives Financial Instruments

The Managing General Partner utilizes commodity based derivative instruments as hedges to manage a portion of the Partnership's exposure to price volatility stemming from natural gas production. These instruments consist of costless collars and option contracts traded on the New York Mercantile Exchange. The costless collars and option contracts hedge committed and anticipated natural gas sales generally forecasted to occur within a 12 month period. The Partnership does not hold or issue derivatives for trading or speculative purposes.

(Continued)

F-8

PDC 2001-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

December 31, 2002

All derivatives are recognized on the Partnership balance sheet at their fair value. On the date the derivative contract is entered into, the Managing General Partner designates the derivative as either a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability ("cash flow" hedge), or a non-hedging derivative. The Managing General Partner formally documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated as cash-flow hedges to specific firm commitments or forecasted transactions. The Managing General Partner also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. When it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, the Partnership discontinues hedge accounting prospectively. No hedging activities were discontinued during 2002.

Changes in fair value of a derivative that is highly effective and that is designated and qualifies as a cash-flow hedge are recorded in accumulated other comprehensive income, until earnings are affected by the variability in cash flows of the designated hedged item. Changes in the fair value of non-hedging derivatives are reported in current-period earnings. The Partnership discontinues hedge accounting prospectively when it is determined that the derivative is no longer effective in offsetting changes in the cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised. Additionally, if the derivative is dedesignated as a hedging instrument, because it is unlikely that a forecasted transaction will occur, a hedged firm commitment no longer meets the definition of a firm commitment, or the Partnership determines that designation of the derivative as a hedging instrument is no longer appropriate, hedge accounting will discontinue.

By using derivative financial instruments to hedge exposures to changes in commodity prices, the Managing General Partner exposes the Partnership to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Partnership, which creates credit/repayment risk. The Managing General Partner minimizes the credit/repayment risk in derivative instruments by entering into transactions with high-quality counterparties.

Use of Estimates

The Partnership has made a number of estimates and assumptions relating to the reporting of assets and liabilities and revenues and expenses and the disclosure of contingent assets and liabilities to prepare these financial statements in conformity with generally accepted accounting principles. Actual results could differ from those estimates. Estimates which are particularly significant to the financial statements include estimates of oil and gas reserves and future cash flows from oil and gas properties which are used in assessing impairment of long-lived assets.

New Accounting Standards

F-9

PDC 2001-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

December 31, 2002

(2) Organization

The Partnership was organized as a limited partnership on September 5, 2001, in accordance with the laws of the State of West Virginia for the purpose of engaging in the drilling, completion and operation of oil and gas development and exploratory wells in the Rocky Mountain Region.

Purchasers of partnership units subscribed to and fully paid for 20 units of limited partner interest and 613.92884 units of additional general partner interests at $20,000 per unit (Investor Partners). Petroleum Development Corporation has been designated the Managing General Partner of the Partnership. Although costs, revenues and cash distributions allocable to the limited and additional general partners are shared pro rata based upon the amount of their subscriptions, including the Managing General Partner to the extent of its capital contributions, there are significant differences in the federal income tax effects and liability associated with these different types of units in the Partnership.

Upon completion of the drilling phase of the Partnership's wells, all additional general partners units are converted into units of limited partner interests and thereafter become limited partners of the Partnership. Limited partners do not have any rights to convert their units into units of additional general partner interests in the Partnership.

In accordance with the terms of the Partnership Agreement (the Agreement), the Managing General Partner manages all activities of the Partnership and acts as the intermediary for substantially all Partnership transactions.

(3) Transactions with Managing General Partner and Affiliates

The Partnership's transactions with the Managing General Partner include the following:

	Year Ended December 31, 2002	Period from September 5, 2001 (date of inception)to December 31, 2001
Drilling and completion costs	$ -	13,787,953
Offering and organization costs (includes reimbursements of syndication cost and management fee)	-	1,648,215
Lifting costs	446,991	48,410
Tax return preparation	5,405	3,695
Direct administrative cost	2,605	1,610

(Continued)

F-10

PDC 2001-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

(4) Allocation

The table below summarizes the participation of the Managing General Partner and the Investor Partners, taking account of the Managing General Partner's capital contribution equal to a minimum of 20% of the Initial Operating Capital, in the costs and revenues of the Partnership.

Partnership Costs	Investor Partners(5)(6 )	Managing General Partner(5)(6)
Broker-dealer Commissions and Expenses(1)	100%	0%
Management Fee(2)	100%	0%
Lease Costs	0%	100%
Tangible Well Costs	0%	100%
Intangible Drilling and Development Costs	100%	0%
Total Drilling and Completion Costs	80%	20%
Operating Costs(3)	80%	20%
Direct Costs(4)	80%	20%
Administrative Costs	0%	100%

Partnership Revenues
Sale of Oil and Gas Production	80%	20%
Sale of Productive Properties	80%	20%
Sale of Equipment	0%	100%
Sale of Undeveloped Leases .	80%	20%
Interest Income	80%	20%

____________________

(1) Organization and Offering Costs, net of the Dealer Manager commissions, discounts, due diligence expenses, and wholesaling fees of the Partnership were paid by the Managing General Partner and not from Partnership funds. In addition, Organization and Offering Costs in excess of 10-1/2% of Subscriptions were paid by the Managing General Partner, without recourse to the Partnership.

(2) Represents a one-time fee paid to the Managing General Partner on the day the Partnership is funded equal to 2-1/2% of total investor subscriptions.

(3) Represents Operating costs incurred after the completion of productive wells, including monthly per-well charges paid to the Managing General Partner.

(4) The Managing General Partner receives monthly reimbursement from the Partnership for their direct costs incurred by the Managing General Partner on behalf of the Partnership.

(5) To the extent that Investor Partners receive preferred cash distributions, the allocations for Investor Partners will be increased accordingly and the allocation for the Managing General Partner will likewise be decreased.

F-11

PDC 2001-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

(6) The allocation of profits, losses and cash distributions of the Managing General Partner might be increased, and the allocation of profits, losses, and cash distributions of the Investor Partners might be decreased in the event that the Managing General Partner were to invest more than the Managing General Partner's minimum required Capital Contribution to cover tangible equipment and lease costs. The Managing General Partner will pay for the Partnership's share of all Leases and tangible well equipment. The entire Capital Contribution of the Investor Partners, after payment of brokerage commissions, due diligence reimbursement, and the Management Fee, will be utilized to pay for intangible drilling costs. In the event that the Intangible Drilling Costs exceed the funds of the Investor Partners available for payment of Intangible Drilling Costs (herein "excess IDC"), a portion of the Capital Contribution of the Managing General Partner may be used to pay such excess IDC. If the cost of Leases and tangible well equipment were to exceed the Managing General Partner's Capital Contribution of 21-3/4% of the aggregate Capital Contribution of the Investor Partners, then the Managing General Partner will increase its Capital Contribution to fund such additional capital requirements and the Managing General Partner's allocation of profits, losses, and cash distributions will be increased to equal the percentage arrived at by dividing the Capital Contribution made by the Managing General Partner by the Capital Available for Investment; the allocation of the Investor Partners will be decreased accordingly.

(7) In accordance with the repurchase provision of the partnership prospectus, PDC may repurchase units from the investor partners, which is entirely voluntary on the part of the partners. During 2002 there were no units purchased by PDC.

(5) Costs Relating to Oil and Gas Activities

The Partnership is engaged solely in oil and gas activities, all of which are located in the continental United States. Information regarding aggregate capitalized costs and results of operations for these activities is located in the basic financial statements. Costs capitalized for these activities are as follows:

	December 31,
	2002	2001
Lease acquisitions at cost	$383,794	383,794
Intangible development costs	11,030,362	11,030,362
Well equipment	2,373,797	2,373,797
	$13,787,953	13,787,953

The following costs were incurred for the Partnership's oil and gas activities:

	Year Ended December 31, 2002	Period from September 5, 2001 (date of inception) to December 31, 2001
Costs incurred:
Property acquisition costs	$ -	383,794
Development costs	-	13,404,159
	$ -	13,787,953

F-12

PDC 2001-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

(6) Income Taxes

As a result of the differences in the treatment of certain items for income tax purposes as opposed to financial reporting purposes, primarily depreciation, depletion and amortization of oil and gas properties and the recognition of intangible drilling costs as an expense or capital item, the income tax basis of oil and gas properties differs from the basis used for financial reporting purposes. At December 31, 2002 and 2001, the income tax basis of the Partnership's oil and gas properties was $2,052,572 and $2,726,042, respectively.

(7) Supplemental Reserve Information (Unaudited)

Proved oil and gas reserves of the Partnership have been estimated by an independent petroleum engineer, Wright & Company, Inc. These reserves have been prepared in compliance with the Securities and Exchange Commission rules based on year end prices, adjusted for hedging contracts. A copy of the reserve report has been made available to all partners. All of the partnership's reserves are proved developed. An analysis of the change in estimated quantities of proved developed oil and gas reserves is shown below:

	Natural gas (mcf)	Oil (bbls)
Proved developed reserves as of
September 5, 2001 (date of inception)	-	-
Extensions, discoveries and other additions	5,226,095	282,536
Production	(54,612 )	(10,605 )
Proved developed reserves as of December 31, 2001	5,171,483	271,931

Revisions of prior estimates	2,211,414	(45,290)
Production	(845,069 )	(34,393 )
Proved developed reserves as of December 31, 2002	6,537,828	192,248

F-13

PDC 2001 B LP 10-K/A