CONFORMED COPY

SECURITIES AND
EXCHANGE COMMISSION

Washington, D.C.  20549

Form 10-K

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

THE SECURITIES
EXCHANGE ACT OF 1934

For the fiscal year
ended December 31, 2004

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

There is no trading market for the registrant's
securities.

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 and 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). During 2002 in accordance with the Partnership Agreement, all
Additional General Partners were converted to Limited Partners.

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

Allocation
  of RevenuesAdditional 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. See Footnote 4 of financial statements for a complete
description of the allocation of Partnership revenue and costs.

Employees

The Partnership has no
employees, however, PDC has approximately 120 employees which include 17 in
finance and data processing, 8 in administration, 12 in exploration and
development, 78 in production and 5 in natural gas marketing.

Plan of Operations

The Partnership
participated in the drilling of 19 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 on 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 accounted for 41.0%, 32.1% and 26.9%
of the Partnership's total oil and natural gas sales for the year ended December 31, 2004, and 52.4%, 18.6% and 26.0% for year ended  December 31, 2003.

2

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 eastern Colorado production, and CIG (Colorado
Interstate Gas Index)-based contracts for other Colorado production and NYMEX
traded oil futures and option contracts for Colorado oil production.  The
contracts hedge committed and anticipated natural gas sales, generally
forecasted to occur within the next 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.  See "Commodity 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 $6,512, $8,100 and $7,200 in 2004, 2003 and 2002, 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.

3

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, 2004. All of the Partnership's wells
drilled and producing are located in Colorado.

Development
  WellsGross Wells
  Net WellsProductive
  Dry
  Total
  Productive
  Dry
  Total18
  1
  19
  15.91
  .87
  16.78


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

Production

See "Management's Discussion and Analysis" on
page 5 for Partnership production.

Reserves

See "Footnote 8" to the Partnership's financial
statements for information related to the Partnership's oil and gas reserves.

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 it believes would
have a materially adverse on affect the Managing General Partner's or
Partnership's business, financial condition, results of operations or
liquidity.

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

NON-APPLICABLE

4



PART II

ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS.

At December 31, 2001, PDC
2001-B Limited Partnership had one Managing General Partner, and a total of 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. During 2002 in accordance with the Partnership Agreement, all
Additional General Partners were converted to Limited Partners. At December 31, 2004, the Partnership had one Managing General Partner and 625 limited
partners who paid for 633.92884 units at $20,000 per unit. No established
public trading market exits for the interests.

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. There is no
established trading market for the securities of the Partnership.

ITEM 6.  SELECTED FINANCIAL DATA.

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

Years
Ended December 31,

|                                                    | 2004       | 2003       | 2002      
|--------------------------------------------------- | ---------- | ---------- | ----------
|Oil and Gas Sales                                   | $1,276,729 | 2,367,138  | 2,292,809 
|Costs and Expenses                                  | 1,067,297  | 1,951,495  | 2,225,605 
|Cumulative Effect of Change in Accounting Principle | -          | (1,586)    | -         
|Net Income                                          | 210,037    | 415,192    | 68,168    
|Allocation of Net Income:                           |            |            |           
|Managing General Partner                            | 42,008     | 83,038     | 13,634    
|Limited and Additional General Partners             | 168,030    | 332,154    | 54,534    
|Per Limited and Additional General Partner Unit     | 265        | 524        | 86        
|Total Assets                                        | 9,903,293  | 10,699,047 | 12,154,226
|Cash Distributions:                                 |            |            |           
|Managing General Partner                            | 205,377    | 373,896    | 334,013   
|Limited and Additional General Partners             | 821,514    | 1,495,589  | 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 working
capital at December 31, 2004 of $208,351.

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

5

Results of Operations

2004 Results Compared to 2003

Oil and gas sales for the year ended December 31, 2004 were $1,276,729 compared to $2,367,138 for the year ended December 31, 2003.  For the year ended December 31, 2004, the Partnership sold 175,493 Mcf
of gas and       9,630 barrels of oil at average sales prices of $5.17 and
$38.29, respectively.  This compared with 545,136 Mcf of gas and 16,277 barrels
of oil sold at average sales prices of $3.44 and $30.21, respectively for the
year ended December 31, 2003. Lifting cost per Mcfe in 2004 amounted to $1.63
as compared to $0.84 for 2003. This increase is partially attributed to the
increase in severance and property taxes. The fixed costs of operations and
well maintenance are allocated to lower production volumes, therefore
increasing lifting costs per Mcfe.  Depreciation,
depletion and amortization decreased from $1,394,310 the year ended December 31, 2003 to $675,384 for the year ended December 31, 2004 as a result of lower volumes of natural gas and oil sold.  While the Partnership experienced a net
income of $210,038, depreciation, depletion and amortization is a non-cash
expense and therefore the Partnership distributed $1,026,891 to the partners
during the year ended December 31, 2004.

2003 Results
Compared to 2002



Oil
and gas sales for the year ended December 31, 2003 were $2,367,138 compared to $2,292,809 for the year ended December 31, 2002. The volume of natural gas sold for the year ended December 31, 2003, was 545,136 Mcf at an average
sales price of $3.44 per Mcf compared to 845,069 Mcf at an average sales price
of $1.69 per Mcf for the year ended December 31, 2002.  Oil sales were 16,277 barrels at an average sales price of $30.21 per barrel for the year ended December 31, 2003 compared to 34,393 barrels at an average sales price of $25.03 per
barrel for the year ended December 31, 2002.  The lifting cost for the year
ended December 31, 2003 was $0.84 per Mcfe compared to $0.43 per Mcfe for the
ended December 31, 2002.  This increase is partially attributed to the increase
in severance and property taxes. The fixed costs of operations and well
maintenance are allocated to lower production volumes, therefore increasing
lifting costs per Mcfe. Depreciation, depletion and amortization decreased from
$1,764,659 for the year ended December 31, 2002 to $1,394,310 for the year
ended December 31, 2003 as a result of lower volumes of natural gas and oil
sold. While the Partnership experienced a net income of $415,192, depreciation,
depletion and amortization is a non-cash expense and therefore the Partnership
distributed $1,869,485 to the partners during the year ended December 31, 2003.

The Partnership's revenues from oil and natural gas sales
will be affected by changes in prices.  As a result of changes in federal
regulations, gas prices are highly dependent on the balance between supply and
demand. The Partnership's gas sales prices are subject to increase and decrease
based on various market sensitive indices.

Critical
Accounting Policies and Estimates

Certain accounting policies
are very important to the portrayal of the Partnership's financial condition
and results of operations and require management's most subjective or complex
judgments. In applying those
policies, our management uses its judgment to determine the appropriate
assumptions to be used in the determination of certain estimates. Those
estimates are based on our historical experience, our observance of trends in
the industry, and information available from other outside sources, as
appropriate. For a more detailed discussion on the application of these and
other accounting policies, see "Note 1 - Summary of significant account
policies" in our financial statements and related notes. The Partnership's
critical accounting policies and estimates are as follows:

Revenue
Recognition

Sales of natural gas are
recognized when natural gas has been delivered to a custody transfer point,
persuasive evidence of a sales arrangement exists, the rights and
responsibility of ownership pass to the purchaser upon delivery, collection of
revenue from the sale is reasonably assured and the sales price is fixed or
determinable.  Natural gas is sold by the Managing General Partner under contracts
with terms ranging from one month to three years.  Virtually all of the
Managing General Partner's contracts pricing provisions are tied to a market
index, with certain adjustments based on, among other factors, whether a well
delivers to a gathering or transmission line, quality of natural gas and
prevailing supply and demand conditions, so that the price of the natural gas
fluctuates to remain competitive with other available natural gas supplies.  As
a result, the Partnership's revenues from the sale of natural gas will suffer
if market prices decline and benefit if they increase.  The Partnership
believes that the pricing provisions of its natural gas contracts are customary
in the industry.

6

The Managing General Partner currently
uses the "Net-Back" method of accounting for transportation arrangements of
natural gas sales.  The Managing General Partner sells gas at the wellhead and
collects a price and recognizes revenues based on the wellhead sales price
since transportation costs downstream of the wellhead are incurred by the
Managing General Partner's customers and reflected in the wellhead price.

Sales of 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 of revenue from the sale
is reasonably assured and the sales price is determinable.  The Partnership is
currently able to sell all the oil that it can produce under existing sales
contracts with petroleum refiners and marketers.  The Partnership does not
refine any of its oil production.  The Partnership's crude oil production is
sold to purchasers at or near the Partnership's wells under short-term purchase
contracts at prices and in accordance with arrangements that are customary in
the oil industry.

Accounting for
Derivatives Contracts at Fair Value

The
Partnership uses derivative instruments to manage its commodity and financial
market risks. Accounting requirements for derivatives and hedging activities
are complex; interpretation of these requirements by standard-setting bodies is
ongoing.

Derivatives
are reported on the Balance Sheets at fair value. Changes in fair value of
derivatives that are not designated as accounting hedges are recorded in
earnings.

The
measurement of fair value is based on actively quoted market prices, if
available. Otherwise, the Partnership seeks indicative price information from
external sources, including broker quotes and industry publications. If pricing
information from external sources is not available, measurement involves
judgment and estimates. These estimates are based on valuation methodologies
considered appropriate by the Partnership's management.

For
individual contracts, the use of different assumptions could have a material
effect on the contract's estimated fair value. In addition, for hedges of
forecasted transactions, the Partnership must estimate the expected future cash
flows of the forecasted transactions, as well as evaluate the probability of
the occurrence and timing of such transactions. Changes in conditions or the
occurrence of unforeseen events could affect the timing of recognition in
earnings for changes in fair value of certain hedging derivatives.

Use of Estimates in
Long-Lived Asset Impairment Testing

Impairment
testing for long-lived assets and intangible assets with definite lives is
required when circumstances indicate those assets may be impaired.  In
performing the impairment test, the Partnership would estimate the future cash
flows associated with individual assets or groups of assets.  Impairment must
be recognized when the undiscounted estimated future cash flows are less than
the related asset's carrying amount.  In those circumstances, the asset must be
written down to its fair value, which, in the absence of market price
information, may be estimated as the present value of its expected future net
cash flows, using an appropriate discount rate.  Although cash flow estimates
used by the Partnership are based on the relevant information available at the
time the estimates are made, estimates of future cash flows are, by nature,
highly uncertain and may vary significantly from actual results.

Oil and Gas Properties

Exploration
and development costs are accounted for by the successful efforts method.

The Partnership assesses
impairment of capitalized costs of proved oil and gas properties by comparing
net capitalized costs to estimated undiscounted future net 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 flows, the measurement of impairment is
based on estimated fair value which would consider future discounted cash
flows.

Property acquisition
costs are capitalized when incurred.  Geological and geophysical costs and
delay rentals are expensed as incurred.  The costs of drilling exploratory
wells are capitalized pending determination of whether the wells have
discovered economically producible reserves.  If reserves are not discovered,
such costs are expensed as dry holes.  Development costs, including equipment
and intangible drilling costs related to both producing wells and developmental
dry holes, are capitalized.

7

Unproved properties
or leases are written-off to expense when it is determined that they will
expire or be abandoned.

Costs of proved
properties, including leasehold acquisition, exploration and development costs
and equipment, are depreciated or depleted by the unit-of-production method
based on estimated proved developed oil and gas reserves.

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



New Accounting Standards

In June 2001, the
Financial Accounting Standard Board issued FASB No. 143, "Accounting for
Asset Retirement Obligations" that requires entities to record the fair
value of a liability for an asset retirement obligation in the period in which
it is incurred and a corresponding increase in the carrying amount of the
related long-lived asset. This statement is effective for fiscal years
beginning after June 15, 2002. The Partnership adopted SFAS No. 143 on January 1, 2003 and recorded a net asset of $6,379 and a related liability of $7,965
(using a 6% discount rate) and a cumulative effect on change in accounting
principle on prior years of $1,586.

ITEM 7A.  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

The Managing General Partner utilizes
commodity-based derivative instruments as hedges to manage a portion of its
exposure to price risk from its oil and natural gas sales.  These instruments
consist of CIG-based contracts traded by JP Morgan for Colorado production. 
These hedging arrangements have the effect of locking in for specified periods
(at predetermined prices or ranges of prices) the prices the Managing General
Partner will receive for the volume to which the hedge relates.  As a result,
while these hedging arrangements are structured to reduce the Partnership's
exposure to changes in price associated with the hedged commodity, they also
limit the benefit the Partnership might otherwise have received from price
changes associated with the hedged commodity.  The Partnership's policy prohibits the use of natural gas future
and option contracts for speculative purposes.



The following tables summarize the open futures and
options contracts for the Partnership as of December 31, 2004 and 2003.

|Commodity                                                     | Type     | Quantity    | Weighted | Total    | Fair    
|------------------------------------------------------------- | -------- | ----------- | -------- | -------- | --------
|                                                              |          | Gas-Mmbtu   | Average  | Contract | Market  
|                                                              |          | Oil-Barrels | Price    | Amount   | Value   
|Total
  Contracts as of December 31, 2004                    
|Natural Gas                                                   | Floors   | 59,117      | 4.00     | -        | 12,365  
|Natural Gas                                                   | Ceilings | 29,558      | 5.20     | -        | (21,122)
|Oil                                                           | Floors   | 5,684       | 32.30    | 183,601  | 4,843   
|Oil                                                           | Ceilings | 2,842       | 40.00    | 113,685  | (15,373)
|                                                             
|Contracts
  maturing in 12 months following December 31, 2004
|Natural Gas                                                   | Floors   | 59,117      | 4.00     | -        | 12,365  
|Natural Gas                                                   | Ceilings | 29,558      | 5.20     | -        | (21,122)
|Oil                                                           | Floors   | 5,684       | 32.30    | 183,601  | 4,843   
|Oil                                                           | Ceilings | 2,842       | 40.00    | 113,685  | (15,373)
|                                                              |          |             |          |          |         
|Prior
  Year Total Contracts as of December 31, 2003         
|Natural Gas                                                   | Floors   | 63,186      | 3.28     | -        | -       
|Natural Gas                                                   | Ceilings | 63,186      | 4.84     | -        | (963)   

8

The maximum term over which the Partnership is hedging
exposure to the variability of cash flows for commodity price risk is 12 months.

The average CIG closing price for natural gas for the years 2004, 2003
and 2002 was $5.17 per Mmbtu, $4.04 per Mmbtu and $1.97 per Mmbtu.  Future
near-term gas prices will be affected by various supply and demand factors such
as weather, government and environmental regulations and new drilling activities
within the industry.

Disclosure of Limitations

As the information above
incorporates only those exposures that exist at December 31, 2004, 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 9A. 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 Managing General Partner has evaluated the effectiveness of the
design and operation of its disclosure controls and procedures (as defined in
Exchange Act Rule 13a-14(c)) as of the end of the period covered by this annual
report on Form 10-K, 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 in the fourth quarter and subsequent to the date of their
evaluation.

ITEM  9B.  OTHER INFORMATION



NONE

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

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 2004 has been filed with the Securities and Exchange Commission.



Although the Partnership has no Code of Ethics,
Petroleum Development Corporation, the Managing General Partner of the
Partnership, has a Code of Ethics that applies to its senior executive
officers.  The Code of Ethics is posted on the website of Petroleum Development
Corporation at www.petd.com.

ITEM 11.  EXECUTIVE COMPENSATION.

NON-APPLICABLE.

9









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. See respective drilling prospectus for further information
regarding the Limited Partnership Agreements. The following table presents
compensation or reimbursements by the Partnership to PDC or other related
parties for the years ended December 31, 2004, 2003 and 2002.

|                           | 2004     | 2003    | 2002   
|-------------------------- | -------- | ------- | -------
|Lifting cost               | $379,375 | 542,471 | 446,991
|Tax return preparation     | 5,653    | 7,185   | 5,405  
|Direct administrative cost | 2,536    | 3,331   | 2,605  

ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND
SERVICES

For the years ended
December 31, 2004 and 2003, the Partnership paid KPMG LLP $3,842 and $3,720,
respectively, for professional services for the audit of the Partnership's
financial statements in its Form 10-K and review of financial statements
included in the Partnership's Form 10-Qs.

Pre-Approval Policies and Procedures



The Sarbanes-Oxley Act of
2002 requires that all services provided to the Partnership by its independent
accountants be subject to pre-approval by the Audit Committee or authorized
members of the Committee. Since the Partnership does not have an Audit
Committee, the Managing General Partner's Audit Committee also serves for the
Partnership.  The Audit Committee has adopted policies and procedures for
pre-approval of all audit services and non-audit services to be provided by the
Partnership's independent accountants. Services necessary to conduct the annual
audit must be pre-approved by the Audit Committee or by the authorized Audit Committee
member.

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

(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.



(3)     Exhibits

|4.1  | Form
  of Limited Partnership Agreement (incorporated by reference to Appendix A to
  Form S-1, SEC File No. 333-47622, and Rule 424 final prospectus, dated May 25, 2001, of PDC 2003 Drilling Program, filed with the SEC on May 30, 2001).        
|---- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|14   | Code
  of Ethics of Petroleum Development Corporation (incorporated by reference to
  the posted code on the web site of Petroleum Development Corporation at www.petd.com).                                                                         
|31.1 | Rule
  13a-14(a)/15d-14(c) Certification of Chief Executive Officer of Petroleum
  Development Corporation, the managing general partner of the Limited
  Partnership.


  10                                                                        
|31.2 | Rule
  13a-14(a)/15d-14(c) Certification of Chief Financial Officer of Petroleum
  Development Corporation, the managing general partner of the Limited
  Partnership.                                                                               
|32.1 | Title 18
  U.S.C. Section 1350 (Section 906 of Sarbanes-Oxley Act of 2002)
  Certifications by Chief Executive Officer and Chief Financial Officer of
  Petroleum Development Corporation, the managing general partner of the
  Limited Partnership.
|     |                                                                                                                                                                                                                                                      

11

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/ Steven R. Williams
  Steven R. Williams, Chairman                                             
| | April 15, 2005                                                                                      

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/ Steven R. Williams
  Steven R. Williams       | Chairman, Chief Executive Officer and
  Director                                     | April 15, 2005
|                                                  |                                                                                      |               
|/s/ Darwin L. Stump
  Darwin L. Stump             | Chief Financial Officer and Treasurer
  (principal financial and accounting officer) | April 15, 2005
|                                                  |                                                                                      |               
|/s/ Thomas E. Riley
  Thomas E. Riley             | President and Director                                                               | April 15, 2005
|                                                  |                                                                                      |               
|/s/ Donald B. Nestor
  Donald B. Nestor           | Director                                                                             | April 15, 2005
|                                                  |                                                                                      |               
|/s/ Vincent F. D'Annunzio
  Vincent F. D'Annunzio | Director                                                                             | April 15, 2005

12

PDC 2001-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Financial Statements for Annual Report

on Form 10-K to Securities and Exchange

Commission

Years Ended December 31, 2004, 2003 and 2002

(With Independent Registered Public Accounting Firm's
Report Thereon)

F-1

PDC 2001-B LIMITED
PARTNERSHIP

(A West Virginia
Limited Partnership)

Index to Financial Statements

|Report of Independent Registered Public Accounting Firm                                                             | F-3
|------------------------------------------------------------------------------------------------------------------- | ---
|Balance Sheets - December 31, 2004 and 2003                                                                         | F-4
|Statements of Operations -  Years Ended December 31, 2004,  2003 and 2002                                           | F-5
|Statements of Partners' Equity and Comprehensive Income
  (Loss)
  - Years Ended December 31, 2004,   2003 and 2002 | F-6
|Statements of Cash Flows -  Years Ended December 31, 2004, 2003  and 2002                                           | F-7
|Notes to Financial Statements                                                                                       | F-8

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

F-2

Report
of Independent Registered Public Accounting Firm

To the Partners

PDC 2001-B Limited Partnership:

We have audited the accompanying
balance sheets of PDC 2001-B Limited Partnership (a West Virginia limited
partnership) as of December 31, 2004 and 2003, and the related statements of operations,
partners' equity and comprehensive income (loss), and cash flows for each of
the years in the three-year period ended December 31, 2004. 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 audits.

We conducted our audits in
accordance with the standards of the Public Company Accounting Oversight Board
(United States).  Those standards require that we plan and perform the 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 audits provide 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,
2004 and 2003, and the results of its operations and its cash flows for each of
the years in the three-year period ended December 31, 2004, in conformity with
U.S. generally accepted accounting principles.

As discussed in note 1 to
the financial statements, the Partnership adopted the provisions of Statement
of Financial Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations", in 2003.



KPMG
LLP

Pittsburgh, Pennsylvania

April 15, 2005

F-3

PDC 2001-B LIMITED
PARTNERSHIP

(A West Virginia
Limited Partnership)

Balance Sheets

December 31, 2004 and 2003

|Assets                                                             |                |           
|------------------------------------------------------------------ | -------------- | ----------
|                                                                   |                |           
|Current assets:                                                    | 2004           | 2003      
|Cash                                                               | $        2,650 | 2,190     
|Accounts receivable - oil and gas revenues                         | 257,917        | 378,747   
|Total current assets                                               | 260,567        | 380,937   
|                                                                   |                |           
|Oil and gas properties, successful efforts method (notes 3 and 6): | 13,795,467     | 13,795,467
|Less accumulated depreciation, depletion
  and amortization        | 4,152,741      | 3,477,357 
|                                                                   |                |           
|                                                                   | 9,642,726      | 10,318,110
|                                                                   | $9,903,293     | 10,699,047
|                                                                   |                |           
|Liabilities and Partners' Equity                                   |                |           
|                                                                   |                |           
|Current liabilities:                                               |                |           
|Accrued expenses                                                   | $52,216        | 13,300    
|Total current
  liabilities                                        | 52,216         | 13,300    
|                                                                   |                |           
|Asset retirement obligation                                        | 8,950          | 8,443     
|                                                                   |                |           
|Partners' equity                                                   | 9,842,127      | 10,677,304
|                                                                   | $9,903,293     | 10,699,047
|                                                                   |                |           

See accompanying notes to financial statements.

F-4

PDC 2001-B LIMITED
PARTNERSHIP

(A West Virginia
Limited Partnership)

Statements of
Operations

Years Ended December 31, 2004, 2003 and 2002

|Revenues:                                                                                                                 |              |           |          
|------------------------------------------------------------------------------------------------------------------------- | ------------ | --------- | ---------
|                                                                                                                          | 2004         | 2003      | 2002     
|Sales of oil and gas                                                                                                      | $1,276,729   | 2,367,138 | 2,292,809
|Interest income                                                                                                           | 606          | 1,135     | 964      
|                                                                                                                          | 1,277,335    | 2,368,273 | 2,293,773
|Expenses (note 3):                                                                                                        |              |           |          
|Lifting costs                                                                                                             | 379,375      | 542,471   | 446,991  
|Independent engineering fee                                                                                               | -            | -         | 2,314    
|Independent audit fee                                                                                                     | 3,842        | 3,720     | 3,631    
|Tax return preparation                                                                                                    | 5,653        | 7,185     | 5,405    
|Direct administrative cost                                                                                                | 3,043        | 3,809     | 2,605    
|Depreciation, depletion and
  amortization                                                                                | 675,384      | 1,394,310 | 1,764,659
|                                                                                                                          | 1,067,297    | 1,951,495 | 2,225,605
|                                                                                                                          |              |           |          
|Income before cumulative effect of
  change in accounting principle                                                       | 210,038      | 416,778   | 68,168   
|                                                                                                                          |              |           |          
|Cumulative effect of change in accounting
  principle                                                                     | -            | (1,586)   | -        
|                                                                                                                          |              |           |          
|Net
  income                                                                                                              | $210,038     | 415,192   | 68,168   
|                                                                                                                          |              |           |          
|Net income per limited and additional
  general partner unit before cumulative effect of
  change in accounting principle | $265         | 526       | 86       
|                                                                                                                          |              |           |          
|Cumulative effect of change in accounting
  principle                                                                     | -            | (2)       | -        
|                                                                                                                          |              |           |          
|Net
  income per limited and additional
  general
  partner unit                                                          | $        265 | 524       | 86       

See accompanying notes to financial statements.

F-5

PDC 2001-B LIMITED PARTNERSHIP

(A West Virginia
Limited Partnership)

Statements of
Partners' Equity

And Comprehensive
Income (Loss)

Years Ended December 31, 2004, 2003 and 2002

|                                                                                | Limited
  and Additional
  General
  Partners | Managing
  General
  Partner | Accumulated
  Other
  Comprehensive
  Income (Loss) | Total      
|------------------------------------------------------------------------------- | --------------------------------------------- | ---------------------------- | --------------------------------------------------- | -----------
|                                                                                |                                               |                              |                                                     |            
|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 
|                                                                                |                                               |                              |                                                     |            
|Distribution to
  partners                                                      | (1,495,589)                                   | (373,896)                    |                                                     | (1,869,485)
|                                                                                |                                               |                              |                                                     |            
|Comprehensive
  income:                                                         |                                               |                              |                                                     |            
|Net income                                                                      | 332,154                                       | 83,038                       |                                                     | 415,192    
|Change in fair
  value of  outstanding
  hedging
   positions                   |                                               |                              | (5,406)                                             |            
|Reclassification
  adjustment  for settled
  contracts
  included in net income |                                               |                              | (4,517)                                             |            
|Other
  comprehensive loss                                                      |                                               |                              | (9,923)                                             | (9,923)    
|Comprehensive
  income                                                          |                                               |                              |                                                     | 405,269    
|                                                                                |                                               |                              |                                                     |            
|Balance December 31, 2003                                                       | 8,542,611                                     | 2,135,656                    | (963)                                               | 10,677,304 
|                                                                                |                                               |                              |                                                     |            
|Distribution to
  partners                                                      | (821,514)                                     | (205,377)                    |                                                     | (1,026,891)
|                                                                                |                                               |                              |                                                     |            
|Comprehensive
  income:                                                         |                                               |                              |                                                     |            
|Net income                                                                      | 168,030                                       | 42,008                       |                                                     | 210,038    
|Change in fair
  value of  outstanding
  hedging
   positions                   |                                               |                              | (40,958)                                            |            
|Reclassification
  adjustment  for settled
  contracts
  included in net income |                                               |                              | 22,634                                              |            
|Other
  comprehensive loss                                                      |                                               |                              | (18,324)                                            | (18,324)   
|Comprehensive
  income                                                          |                                               |                              |                                                     | 191,714    
|                                                                                |                                               |                              |                                                     |            
|Balance December 31, 2004                                                       | $7,889,127                                    | 1,972,287                    | (19,287)                                            | 9,842,127  



See accompanying
notes to financial statements.

F-6

PDC 2001-B LIMITED
PARTNERSHIP

(A West Virginia
Limited Partnership)

Statements of Cash
Flows

Years Ended December 31, 2004, 2003 and 2002

|                                                                                    | 2004        | 2003        | 2002       
|----------------------------------------------------------------------------------- | ----------- | ----------- | -----------
|Cash flows from operating activities:                                               |             |             |            
|Net income                                                                          | $210,038    | 415,192     | 68,168     
|Adjustments to reconcile net income
  to
  net cash used by
  operating activities: |             |             |            
|Depreciation, depletion and
  amortization                                          | 675,384     | 1,394,310   | 1,764,659  
|Cumulative effect of change in
  accounting principle                               | -           | 1,586       | -          
|Accretion of asset retirement
  obligation                                          | 507         | 478         | -          
|Changes in
  operating assets and liabilities:                                      |             |             |            
|Decrease
  (increase) in accounts receivable - oil and gas
  revenues               | 138,040     | 56,342      | (175,745)  
|Increase
  (decrease) in accrued expenses                                           | 3,382       | (369)       | 681        
|                                                                                    |             |             |            
|Net
  cash provided from operating activities                                       | 1,027,351   | 1,867,539   | 1,657,763  
|                                                                                    |             |             |            
|Cash flows from financing activities:                                               |             |             |            
|Distributions to
  partners                                                         | (1,026,891) | (1,869,485) | (1,670,072)
|                                                                                    |             |             |            
|Net
  cash used by financing activities                                             | (1,026,891) | (1,869,485) | (1,670,072)
|                                                                                    |             |             |            
|Net increase (decrease) increase in cash                                            | 460         | (1,946)     | (12,309)   
|Cash at beginning of period                                                         | 2,190       | 4,136       | 16,445     
|Cash at end of period                                                               | $2,650      | 2,190       | 4,136      

See accompanying notes to financial statements.

F-7

PDC 2001-B LIMITED
PARTNERSHIP

(A West Virginia
Limited Partnership)

Notes to Financial
Statements

December 31, 2004, 2003 and 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. Petroleum
Development Corporation ("PDC") serves as Managing General Partner of
the Partnership.

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  December 31, 2004 and 2003 by the Managing General Partner's petroleum
engineers and at December 31, 2002 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 flows, the measurement of impairment is
based on estimated fair value which would consider future discounted cash
flows.

Revenue Recognition

Sales of natural gas are recognized when
natural gas has been delivered to a custody transfer point, persuasive evidence
of a sales arrangement exists, the rights and responsibility of ownership pass
to the purchaser upon delivery, collection of revenue from the sale is
reasonably assured and the sales price is fixed or determinable.  Natural gas
is sold by the Managing General Partner under contracts with terms ranging from
one month to three years.  Virtually all of the Managing General Partner's
contracts pricing provisions are tied to a market index, with certain
adjustments based on, among other factors, whether a well delivers to a
gathering or transmission line, quality of natural gas and prevailing supply
and demand conditions, so that the price of the natural gas fluctuates to
remain competitive with other available natural gas supplies.  As a result, the
Partnership's revenues from the sale of natural gas will suffer if market
prices decline and benefit if they increase.  The Partnership believes that the
pricing provisions of its natural gas contracts are customary in the industry.

The Managing General Partner currently
uses the "Net-Back" method of accounting for transportation arrangements of
natural gas sales.  The Managing General Partner sells gas at the wellhead and
collects a price and recognizes revenues based on the wellhead sales price
since transportation costs downstream of the wellhead are incurred by the
Managing General Partner's customers and reflected in the wellhead price.

(Continued)

F-8

PDC 2001-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

Sales of 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 of revenue from the sale
is reasonably assured and the sales price is determinable.  The Partnership is
currently able to sell all the oil that it can produce under existing sales
contracts with petroleum refiners and marketers.  The Partnership does not
refine any of its oil production.  The Partnership's crude oil production is
sold to purchasers at or near the Partnership's wells under short-term purchase
contracts at prices and in accordance with arrangements that are customary in
the oil industry.

Income Taxes

Since the taxable
income or loss of the Partnership is reported in the separate tax returns of
the partners, 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.

Derivative 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 CIG (Colorado Interstate Gas Index). 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.

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 2004
or 2003.

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 probable that a
forecasted transaction will not occur, or the Partnership determines that
designation of the derivative as a hedging instrument is no longer appropriate,
hedge accounting will be discontinued.

(Continued)

F-9
PDC 2001-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

By using derivative financial instruments to hedge exposures
to changes in commodity prices, the Managing General Partner exposes the
Partnership to credit 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 risk.  The Managing General Partner minimizes the credit 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 accounting principles generally accepted in the United States of America.  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

In June 2001, the
Financial Accounting Standard Board issued FASB No. 143, "Accounting for
Asset Retirement Obligations" that requires entities to record the fair
value of a liability for an asset retirement obligation in the period in which
it is incurred and a corresponding increase in the carrying amount of the
related long-lived asset. This statement is effective for fiscal years
beginning after June 15, 2002. The Partnership adopted FASB No. 143 on January 1, 2003 and recorded a net asset of $6,379 and a related liability of $7,965
(using a 6% discount rate) and a cumulative effect of change in accounting
principle on prior years of $1,586.

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

(Continued)

F-10

PDC 2001-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

(3)      Transactions
with Managing General Partner and Affiliates

Pursuant
to the authorization contained in the Agreement, PDC receives fees for services
rendered and reimbursement of certain expenses from the Partnership.  See
respective drilling prospectus for further information regarding the Agreement.
The following table presents compensation or reimbursements by the Partnership
to PDC or other related parties for years ended December 31, 2004, 2003 and 2002.

Years
Ended December 31,

2004
  2003
  2002Lifting costs
  $379,375
  542,471
  446,991Tax return
  preparation
  5,653
  7,185
  5,405Direct
  administrative cost
  2,536
  3,331
  2,605


(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 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, if any,
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.

F-11

PDC 2001-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

(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 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.

(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, was 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 2004 PDC purchased a total of 2.5 units of
partnership interest for a total ownership of 3.7717 units as of December 31, 2004 which represents a .595% ownership of the original Investor Partners
share of limited and general partnership units. Therefore, costs and revenues
and distributions for those purchased units are allocated to PDC in accordance
with the Investor Partners allocation percentages disclosed in this table.

(5)  Derivative Financial Instruments

The Managing General Partner utilizes
commodity-based derivative instruments as hedges to manage a portion of its
exposure to price risk from its oil and natural gas sales.  These instruments
consist of CIG-based contracts traded by JP Morgan for Colorado production. 
These hedging arrangements have the effect of locking in for specified periods
(at predetermined prices or ranges of prices) the prices the Managing General
Partner will receive for the volume to which the hedge relates.  As a result,
while these hedging arrangements are structured to reduce the Partnership's
exposure to changes in price associated with the hedged commodity, they also
limit the benefit the Partnership might otherwise have received from price
changes associated with the hedged commodity.  The Partnership's policy prohibits the use of natural gas future
and option contracts for speculative purposes.



The following tables
summarize the open futures and options contracts for the Partnership as of December 31, 2004 and 2003.

F-12

PDC 2001-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

|Commodity                                                     | Type     | Quantity    | Weighted | Total    | Fair    
|------------------------------------------------------------- | -------- | ----------- | -------- | -------- | --------
|                                                              |          | Gas-Mmbtu   | Average  | Contract | Market  
|                                                              |          | Oil-Barrels | Price    | Amount   | Value   
|Total
  Contracts as of December 31, 2004                    
|Natural Gas                                                   | Floors   | 59,117      | 4.00     | -        | 12,365  
|Natural Gas                                                   | Ceilings | 29,558      | 5.20     | -        | (21,122)
|Oil                                                           | Floors   | 5,684       | 32.30    | 183,601  | 4,843   
|Oil                                                           | Ceilings | 2,842       | 40.00    | 113,685  | (15,373)
|                                                             
|Contracts
  maturing in 12 months following December 31, 2004
|Natural Gas                                                   | Floors   | 59,117      | 4.00     | -        | 12,365  
|Natural Gas                                                   | Ceilings | 29,558      | 5.20     | -        | (21,122)
|Oil                                                           | Floors   | 5,684       | 32.30    | 183,601  | 4,843   
|Oil                                                           | Ceilings | 2,842       | 40.00    | 113,685  | (15,373)
|                                                              |          |             |          |          |         
|Prior
  Year Total Contracts as of December 31, 2003         
|Natural Gas                                                   | Floors   | 63,186      | 3.28     | -        | -       
|Natural Gas                                                   | Ceilings | 63,186      | 4.84     | -        | (963)   

The maximum term
over which the Partnership is hedging exposure to the variability of cash flows
for commodity price risk is 12 months.

(6)     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,
|----------------------------------- | ------------
|                                    | 2004        
|Lease acquisitions
  at cost        | 383,794     
|Intangible
  development costs      | 11,030,362  
|Well equipment                      | 2,373,797   
|Capitalized asset
  retirement cost | 7,514       
|                                    | $13,795,467 
|                                    |             

There were no cost
incurred for the Partnership's oil and gas activities for the years ended December 31, 2004, 2003, and 2002.

(7)        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, 2004 and 2003, the income tax basis of the
Partnership's oil and gas properties was $1,266,077 and $1,589,922,
respectively.

F-13

PDC 2001-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

(8)           Supplemental
Reserve Information (Unaudited)

Proved
oil and gas reserves of the Partnership have been estimated December 31, 2004 and 2003 by the Managing General Partner's petroleum engineers and at December 31, 2002 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. 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:

Oil (BBL)2004
  2003
  2002Proved
  developed reserves:Beginning
  of year
  187,000
  192,000
  272,000Revisions
  of previous estimates
  (9,000)
  11,000
  (46,000)New
  Discoveries and extensionsRocky Mountain Region
  -
  -
  -Production
  (10,000)
  (16,000)
  (34,000)End
  of year
  168,000
  187,000
  192,000


Gas (MCF)2004
  2003
  2002Beginning
  of year
  4,192,000
  6,538,000
  5,171,000Revisions
  of previous estimates
  (1,282,000)
  (1,801,000)
  2,212,000New
  Discoveries and extensionsRocky Mountain Region
  -
  -
  -Production
  (175,000)
  (545,000)
  (845,000)End
  of year
  2,735,000
  4,192,000
  6,538,000


(9)    Standardized Measure of Discounted
Future Net Cash Flows and Changes Therein Relating to Proved Oil

and Gas
Reserves (Unaudited)

Summarized in the following
table is information for the Partnership with respect to the standardized
measure of discounted future net cash flows relating to proved oil and gas
reserves.  Future cash inflows are computed by applying year-end prices of oil
and gas relating to the Partnership proved reserves to the year-end quantities
of those reserves.  Future production, development, site restoration and
abandonment costs are derived based on current costs assuming continuation of
existing economic conditions.

|                                                       | As
  of December 31,
|------------------------------------------------------ | --------------------
|                                                       | 2004                
|Future estimated revenues                              | $24,085,000         
|Future estimated production costs                      | (6,589,000)         
|Future estimated development costs                     | (1,203,000)         
|Future net cash flows                                  | 16,293,000          
|10% annual discount for estimated timing of cash flows | (7,951,000)         
|Standardized measure of discounted future              |                     
|estimated net cash flows                               | $8,342,000          

F-14

PDC 2001-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

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

Years Ended December 31,

|                                                         | 2004         | 2003        |  | 2002       
|-------------------------------------------------------- | ------------ | ----------- |  | -----------
|Sales of oil and gas production, net of production costs | $(898,000)   | (1,825,000) |  | (1,846,000)
|Net changes in prices and production costs               | 2,769,000    | 6,694,000   |  | 6,170,000  
|Extensions, discoveries, and improved recovery,          |              |             |  |            
|less related cost                                        | -            | -           |  | -          
|Dispositions from partnership                            | -            | -           |  | -          
|Development costs incurred during the period             | -            | -           |  | -          
|Revisions of previous quantity estimates                 | (4,761,000)  | (3,400,000) |  | 2,469,000  
|Accretion of discount                                    | 1,517,000    | (993,000)   |  | (3,433,000)
|                                                         | $(1,373,000) | 476,000     |  | 3,360,000  
|                                                         |              |             |  |            

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

F-15