UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


WASHINGTON,
DC 20549





FORM
10-Q





x  QUARTERLY
REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934





For
the quarterly period ended June 30, 2009


or





o  TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT


OF 1934
FOR THE TRANSITION PERIOD ____________ TO ____________





Commission
File Number   000-51219





PDC
2004-B Limited Partnership


(Exact
name of registrant as specified in its charter)





West Virginia
            20-0547318(State
      or other jurisdiction of incorporation or organization)
            (I.R.S.
      Employer Identification No.)





1775 Sherman Street, Suite
3000, Denver, Colorado  80203


(Address
of principal executive offices)     (zip
code)





(303)
860-5800


(Registrant's
telephone number, including area code)








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 o   
No x





Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such
files).  Yes o    No o





Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer or a smaller reporting company. See
the definition of "large accelerated filer," "accelerated filer" and "smaller
reporting company" in Rule 12b-2 of the Exchange Act:





Large
      accelerated filer     o
            Accelerated
      filer     oNon-accelerated
      filer     o
            Smaller
      reporting company     x





Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).  Yes o  
No x





As of
November 30, 2009 the Partnership had 899.94 units of limited partnership
interest and no units of additional general partnership interest
outstanding.








PDC 2004-B LIMITED PARTNERSHIP


(A
West Virginia Limited Partnership)




INDEX
TO REPORT ON FORM 10-Q





PagePART
      I – FINANCIAL INFORMATIONItem
      1.
            
            Condensed Financial Statements (unaudited)Condensed Balance Sheets
            1Condensed Statements of Operations
            2Condensed Statements of Cash Flows
            3Notes to Unaudited Condensed Financial
      Statements
            4Item
      2.
            
            Management’s Discussion and Analysis of Financial Condition and
      Results of Operations
            14Item
      3.
            
            Quantitative and Qualitative Disclosures About Market
      Risk
            23Item
      4T.
            
            Controls and Procedures
            23PART
      II – OTHER INFORMATIONItem
      1.
            
            Legal Proceedings
            25Item
      1A.
            
            Risk Factors
            25Item
      2.
            
            Unregistered Sales of Equity Securities and Use of
      Proceeds
            25Item
      3.
            
            Defaults Upon Senior Securities
            25Item
      4.
            
            Submission of Matters to a Vote of Security
      Holders
            25Item
      5.
            
            Other Information
            25Item
      6.
            
            Exhibits
            26SIGNATURES
            27


Index


PART I – FINANCIAL INFORMATION





Item
1. Condensed
Financial Statements (unaudited)





PDC
2004-B Limited Partnership


Condensed
Balance Sheets


(unaudited)





June
      30,
            
            
            December
      31,2009
            
            
            
            2008*AssetsCurrent
      assets:Cash
      and cash equivalents
            
            $
            91,810
            
            
            $
            91,612Accounts
      receivable
            
            
            110,452
            
            
            
            147,587Oil
      inventory
            
            
            11,314
            
            
            
            21,608Due
      from Managing General Partner-derivatives
            
            
            809,502
            
            
            
            995,593Due
      from Managing General Partner-other, net
            
            
            558,230
            
            
            
            964,412Total
      current assets
            
            
            1,581,308
            
            
            
            2,220,812Oil
      and gas properties, successful efforts method, at cost
            
            
            20,096,645
            
            
            
            20,106,098Less:  Accumulated
      depreciation, depletion and amortization
            
            
            (8,861,119
            )
            
            
            (8,156,676
            )Oil
      and gas properties, net
            
            
            11,235,526
            
            
            
            11,949,422Due
      from Managing General Partner-derivatives
            
            
            45,662
            
            
            
            319,803Other
      assets
            
            
            13,830
            
            
            
            7,464Total
      noncurrent assets
            
            
            11,295,018
            
            
            
            12,276,689Total
      Assets
            
            $
            12,876,326
            
            
            $
            14,497,501Liabilities and Partners'
      EquityCurrent
      liabilities:Accounts
      payable and accrued expenses
            
            $
            17,702
            
            
            $
            30,331Due
      to Managing General Partner-derivatives
            
            
            71,330
            
            
            
            -Total
      current liabilities
            
            
            89,032
            
            
            
            30,331Due
      to Managing General Partner-derivatives
            
            
            695,880
            
            
            
            100,327Asset
      retirement obligations
            
            
            166,129
            
            
            
            161,487Total
      liabilities
            
            
            951,041
            
            
            
            292,145Commitments
      and contingent liabilitiesPartners'
      equity:Managing
      General Partner
            
            
            2,388,928
            
            
            
            2,844,942Limited
      Partners - 899.94 units issued and outstanding
            
            
            9,536,357
            
            
            
            11,360,414Total
      Partners' equity
            
            
            11,925,285
            
            
            
            14,205,356Total
      Liabilities and Partners' Equity
            
            $
            12,876,326
            
            
            $
            14,497,501





*Derived
from audited December 31, 2008 balance sheet contained in the Partnership’s Form
10-K for the year ended December 31, 2008.





See
accompanying notes to unaudited condensed financial statements.


- 1 -
 Index


PDC 2004-B Limited Partnership


Condensed
Statements of Operations


(unaudited)





Three
      months ended June 30,
            
            
            Six
      months ended June 30,2009
            
            
            2008
            
            
            2009
            
            
            2008Revenues:Oil
      and gas sales
            
            $
            306,926
            
            
            $
            1,480,313
            
            
            $
            653,360
            
            
            $
            2,433,949Oil
      and gas price risk management loss, net
            
            
            (368,114
            )
            
            
            (849,553
            )
            
            
            (418,944
            )
            
            
            (1,248,379
            )Total
      revenues
            
            
            (61,188
            )
            
            
            630,760
            
            
            
            234,416
            
            
            
            1,185,570Operating
      costs and expenses:Production
      and operating costs
            
            
            139,995
            
            
            
            295,585
            
            
            
            265,025
            
            
            
            487,272Direct
      costs - general and administrative
            
            
            116,295
            
            
            
            12,556
            
            
            
            258,321
            
            
            
            19,360Depreciation,
      depletion and amortization
            
            
            347,088
            
            
            
            394,122
            
            
            
            704,443
            
            
            
            732,811Accretion
      of asset retirement obligations
            
            
            2,321
            
            
            
            2,195
            
            
            
            4,642
            
            
            
            4,390Total
      operating costs and expenses
            
            
            605,699
            
            
            
            704,458
            
            
            
            1,232,431
            
            
            
            1,243,833Loss
      from operations
            
            
            (666,887
            )
            
            
            (73,698
            )
            
            
            (998,015
            )
            
            
            (58,263
            )Interest
      income
            
            
            6,663
            
            
            
            9,516
            
            
            
            13,772
            
            
            
            19,739Net
      loss
            
            $
            (660,224
            )
            
            $
            (64,182
            )
            
            $
            (984,243
            )
            
            $
            (38,524
            )Net
      loss allocated to partners
            
            $
            (660,224
            )
            
            $
            (64,182
            )
            
            $
            (984,243
            )
            
            $
            (38,524
            )Less:  Managing
      General Partner interest in net loss
            
            
            (132,045
            )
            
            
            (12,837
            )
            
            
            (196,849
            )
            
            
            (7,705
            )Net
      loss allocated to Investor Partners
            
            $
            (528,179
            )
            
            $
            (51,345
            )
            
            $
            (787,394
            )
            
            $
            (30,819
            )Net
      loss per Investor Partner unit
            
            $
            (587
            )
            
            $
            (57
            )
            
            $
            (875
            )
            
            $
            (34
            )Investor
      Partner units outstanding
            
            
            899.94
            
            
            
            899.94
            
            
            
            899.94
            
            
            
            899.94





See
accompanying notes to unaudited condensed financial statements.


- 2 -
 Index


PDC 2004-B Limited Partnership


Condensed
Statements of Cash Flows


(unaudited)





Six
      months ended June 30,2009
            
            
            2008Cash
      flows from operating activities:Net
      loss
            
            $
            (984,243
            )
            
            $
            (38,524
            )Adjustments
      to reconcile net loss to net cash provided by operating
      activities:Depreciation,
      depletion and amortization
            
            
            704,443
            
            
            
            732,811Accretion
      of asset retirement obligations
            
            
            4,642
            
            
            
            4,390Unrealized
      loss on derivative transactions
            
            
            1,127,115
            
            
            
            930,624Changes
      in operating assets and liabilities:Decrease
      (increase) in accounts receivable
            
            
            37,135
            
            
            
            (42,905
            )Increase
      in accounts receivable - other
            
            
            -
            
            
            
            (37,461
            )Decrease
      (increase) in oil inventory
            
            
            10,294
            
            
            
            (24,531
            )Increase
      in other assets
            
            
            (6,366
            )
            
            
            (1,098
            )(Decrease)
      increase in accounts payable and  accrued
    expenses
            
            
            (12,629
            )
            
            
            101,797Decrease
      (increase) in due from Managing General Partner - other,
    net
            
            
            406,182
            
            
            
            (379,286
            )Net
      cash provided by operating activities
            
            
            1,286,573
            
            
            
            1,245,817Cash
      flows from investing activities:Capital
      expenditures for oil and gas properties
            
            
            -
            
            
            
            (6,234
            )Refund
      of capital expenditures for oil and gas properties
            
            
            9,453
            
            
            
            -Net
      cash provided by investing activities
            
            
            9,453
            
            
            
            (6,234
            )Cash
      flows from financing activities:Distributions
      to Partners
            
            
            (1,295,828
            )
            
            
            (1,234,775
            )Net
      cash used in financing activities
            
            
            (1,295,828
            )
            
            
            (1,234,775
            )Net
      increase in cash and cash equivalents
            
            
            198
            
            
            
            4,808Cash
      and cash equivalents, beginning of period
            
            
            91,612
            
            
            
            43,507Cash
      and cash equivalents, end of period
            
            $
            91,810
            
            
            $
            48,315





See
accompanying notes to unaudited condensed financial statements.


- 3 -
 Index


PDC 2004-B LIMITED PARTNERSHIP


NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS


June 30,
2009


(unaudited)


Note 1 −
General and Basis of
Presentation





The PDC
2004-B Limited Partnership (the “Partnership” or the “Registrant”) was organized
as a limited partnership on July 28, 2004, in accordance with the laws of the
State of West Virginia for the purpose of engaging in the exploration and
development of oil and natural gas properties.  Upon completion of the
sale of Partnership units on July 28, 2004, the Partnership was funded and
commenced its business operations.  The Partnership owns natural gas
and oil wells located in Colorado, and from the wells, the Partnership produces
and sells natural gas and oil.





Purchasers
of partnership units subscribed to and fully paid for 4.77 units of limited
partner interests and 895.17 units of additional general partner interests at
$20,000 per unit.  In accordance with the terms of the Limited
Partnership Agreement (the “Agreement”), Petroleum Development Corporation, a
Nevada Corporation, is the Managing General Partner of the Partnership
(hereafter, the “Managing General Partner,” “MGP” or “PDC”) and has a 20%
Managing General Partner ownership in the Partnership.  Upon
completion of the drilling phase of the Partnership's wells, all additional
general partners units were converted into units of limited partner interests
and thereafter became limited partners of the Partnership.  Throughout
the term of the Partnership, revenues, costs, and cash distributions are
allocated 80% to the limited and additional general partners (collectively, the
“Investor Partners”), which are shared pro rata based upon the portion of units
owned in the Partnership, and 20% to the Managing General Partner.





As of
June 30, 2009, there were 664 Investor Partners.  As of June 30, 2009,
the Managing General Partner has repurchased 17.02 units of the total 899.94
outstanding units of Partnership interests from Investor Partners at an average
price of $9,955 per unit and, as a result, participates in the sharing of
revenues, costs and cash distributions as both an Investor Partner and as the
Managing General Partner.





The
Managing General Partner is authorized, under the terms of the Drilling and
Operating Agreement (the “D&O Agreement”), to conduct and manage the
Partnership’s business.





The
accompanying interim unaudited condensed financial statements have been prepared
without audit in accordance with accounting principles generally accepted in the
United States of America, or U.S., for interim financial information and with
the instructions to Form 10-Q and Article 8 of Regulation S-X of the Securities
and Exchange Commission, or SEC. Accordingly, pursuant to certain rules and
regulations, certain notes and other financial information included in audited
financial statements have been condensed or omitted.  In the
Partnership’s opinion, the accompanying interim unaudited condensed financial
statements contain all adjustments (consisting of only normal recurring
adjustments) necessary to present fairly the Partnership's financial position,
results of operations and cash flows for the periods presented.  The
interim results of operations and cash flows for the six months ended June 30,
2009 and 2008 are not necessarily indicative of the results to be expected for
the full year or any other future period.





The
accompanying interim unaudited condensed financial statements should be read in
conjunction with the audited financial statements and notes thereto included in
the Partnership's Form 10-K for the year ended December 31, 2008, as filed with
the SEC on October 26, 2009 (“the 2008 Form 10-K”).




- 4 -
 Index


PDC
2004-B LIMITED PARTNERSHIP
 NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
 June 30,
2009
 (unaudited)
  Note 2 −
Recent Accounting
Standards
 
 Recently Adopted Accounting
Standards
 
 In
December 2007, the Financial Accounting Standards Board, or FASB, issued
Statement of Financial Accounting Standards, or FAS, No. 141 (revised 2007),
Business Combinations,
or FAS No. 141(R).  FAS No. 141(R) requires an acquirer to recognize
the assets acquired, the liabilities assumed and any noncontrolling interest in
the acquiree at their acquisition-date fair values.  FAS No. 141(R)
also requires disclosure of the information necessary for investors and other
users to evaluate and understand the nature and financial effect of the business
combination.  Additionally, FAS No. 141(R) requires that
acquisition-related costs be expensed as incurred.  The provisions of
FAS No. 141(R) are effective for acquisitions completed on or after January 1,
2009; however, the income tax provisions of FAS No. 141(R) became effective as
of that date for all acquisitions, regardless of the acquisition
date.  FAS No. 141(R) amends FAS No. 109, Accounting for Income Taxes,
to require the acquirer to recognize changes in the amount of its deferred tax
benefits recognizable due to a business combination either in income from
continuing operations in the period of the combination or directly in
contributed capital, depending on the circumstances.  FAS No. 141(R)
further amends FAS No. 109 and FASB Interpretation No. (“FIN”) 48, Accounting for Uncertainty in Income
Taxes, to require, subsequent to a prescribed measurement period, changes
to acquisition-date income tax uncertainties to be reported in income from
continuing operations and changes to acquisition-date acquiree deferred tax
benefits to be reported in income from continuing operations or directly in
contributed capital, depending on the circumstances.  In April 2009,
the FASB issued FASB Staff Position, or FSP, No. FAS 141(R)-1, Accounting for Assets Acquired and
Liabilities Assumed in a Business Combination That Arise from Contingencies
(“FSP-141(R)-1”), amending the guidance of FAS No. 141(R) to require that
assets acquired and liabilities assumed in a business combination that arise
from contingencies be recognized at fair value if fair value can be reasonably
estimated and if not, the asset and liability would generally be recognized in
accordance with FAS No. 5, Accounting for Contingencies,
and FASB Interpretation No. 14, Reasonable Estimation of the Amount
of a Loss.  Further, FSP 141(R)-1 requires that certain
acquired contingencies be treated as contingent consideration and measured both
initially and subsequently at fair value.  The Partnership adopted the
provisions of FAS No. 141(R) and FSP 141(R)-1 effective January 1, 2009, for
which the provisions will be applied prospectively in the Partnership’s
accounting for future acquisitions, if any.  This adoption had no
impact on the Partnership’s financial statements.


In
December 2007, the FASB issued FAS No. 160, Non-controlling Interests in
Consolidated Financial Statements—An Amendment of ARB No. 51 (“FAS No.
160”).  FAS No. 160 requires the accounting and reporting for
minority interests to be recharacterized as non-controlling interests and
classified as a component of equity.  Additionally, FAS No. 160
establishes reporting requirements that provide sufficient disclosures which
clearly identify and distinguish between the interests of the parent and the
interests of the non-controlling owners.  The Partnership’s adoption
of the provisions of FAS No. 160 effective January 1, 2009 had no material
impact on the Partnership’s financial statements.





In
February 2008, the FASB issued FSP No. 157-2, Effective Date of FASB Statement No.
157, which delayed the effective date of FAS No. 157, Fair Value Measurements, by
one year (to January 1, 2009) for nonfinancial assets and liabilities, except
those that are recognized or disclosed at fair value in the financial statements
on a recurring basis (at least annually).  Effective January 1, 2009,
the Partnership adopted the provisions of FAS No. 157 with respect to
nonfinancial assets and liabilities as delayed by FSP 157-2.  The
adoption of FSP 157-2 did not have a material impact on the Partnership’s
financial statements.  See Note 4, Fair Value
Measurements.





In March
2008, the FASB issued FAS No. 161, Disclosures about Derivative
Instruments and Hedging Activities—An Amendment of FASB Statement No.
133, which changes the disclosure requirements for derivative instruments
and hedging activities.  Enhanced disclosures are required to provide
information about (a) how and why an entity uses derivative instruments, (b) how
derivative instruments and related hedged items are accounted for under
Statement 133 and its related interpretations and (c) how derivative instruments
and related hedged items affect an entity’s financial position, financial
performance and cash flows.  The Partnership adopted the provisions of
FAS No. 161 effective January 1, 2009.  The adoption of FAS No. 161
did not have a material impact on the Partnership’s financial
statements.  For more information on the Partnership’s derivative
accounting, see Note 5, Derivative Financial
Instruments.





In May
2009, the FASB issued FAS No. 165, Subsequent Events (“FAS No.
165”).  FAS No. 165 establishes general standards of accounting for
and disclosure of events that occur after the balance sheet date but before
financial statements are issued.  Specifically, FAS No. 165 sets forth
the period after the balance sheet date during which management of a reporting
entity should evaluate events or transactions that may occur for potential
recognition or disclosure in the financial statements, the circumstances under
which an entity should recognize events or transactions occurring after the
balance sheet date in its financial statements, and the disclosures that an
entity should make about events or transactions that occurred after the balance
sheet date.  FAS No. 165 is effective for interim or annual periods
ending after June 15, 2009, and is applied prospectively.  The
Partnership adopted FAS No. 165 as of June 30, 2009.




- 5 -
 Index


PDC
2004-B LIMITED PARTNERSHIP
 NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
 June 30,
2009
 (unaudited)


Recently Issued Accounting
Standards




In
January 2009, the SEC published its final rule regarding the modernization of
oil and gas reporting (the "final rule"), which modifies the SEC’s reporting and
disclosure rules for oil and natural gas reserves. The most notable changes of
the final rule include the replacement of the single day period-end pricing to
value oil and natural gas reserves to a 12-month average of the first day of the
month price for each month within the reporting period and also permits
voluntary disclosure of probable and possible reserves, a disclosure previously
prohibited by SEC rules. The final rule also reiterates that the definition of
proved undeveloped oil and gas reserves require that the Partnership adopt a
development plan with respect to these reserves. Additionally, the final rule
reiterates the documentation requirements which must be met to classify reserves
as proved undeveloped.  The development plan which has been adopted
should indicate that these reserves are scheduled to be developed within five
years, unless specific circumstances justify a longer time.


The
revised reporting and disclosure requirements are effective for the
Partnership’s Annual Report on Form 10-K for the year ending December 31,
2009.  Early adoption is not permitted.  We are evaluating
the impact that adoption of this final rule will have on the Partnership’s
financial statements, related disclosure and management’s discussion and
analysis.




In June
2009, the FASB issued FAS No. 167, Amendments to FASB Interpretation
No. 46(R), to improve financial reporting by enterprises involved with
variable interest entities by addressing (1) the effects on certain provisions
of FIN 46 (revised December 2003) (“FIN 46(R)”), Consolidation of Variable Interest
Entities, as a result of the elimination of the qualifying
special-purpose entity concept in FAS No. 166, Accounting for Transfers of
Financial Assets, and (2) constituent concerns about the application of
certain key provisions of FIN 46(R), including those in which the accounting and
disclosures under the Interpretation do not always provide timely and useful
information about an enterprise’s involvement in a variable interest
entity.  This statement is effective for financial statements issued
for fiscal years beginning after November 15, 2009, with earlier adoption
prohibited.  We are evaluating the impact that the adoption of FAS No.
167 will have on the Partnership’s financial statements, related disclosure and
management’s discussion and analysis.





In June
2009, the FASB issued FAS No. 168, The FASB Accounting Standards
Codification and the Hierarchy of Generally Accepted Accounting
Principles.  This standard replaces FAS No. 162, The Hierarchy of Generally Accepted
Accounting Principles, and establishes only two levels of U.S. GAAP,
authoritative and non-authoritative.  The FASB Accounting Standards
Codification (the “Codification”) will become the source of authoritative,
nongovernmental U.S. generally accepted accounting principles (“GAAP”), except
for rules and interpretive releases of the SEC, which are sources of
authoritative GAAP for SEC registrants.  All other non-grandfathered,
non-SEC accounting literature not included in the Codification will become
non-authoritative.  This standard is effective for financial
statements issued for fiscal years and interim periods ending after September
15, 2009.  As the Codification was not intended to change or alter
existing GAAP, we do not expect the adoption to have a material impact on the
Partnership’s financial statements.





In August
2009, the FASB issued Accounting Standards Update No. 2009-05, Measuring Liabilities at Fair Value(“ASU 2009-05”) which provides amendments to Accounting Standards
Codification, or ASC, Topic 820, Fair Value Measurements and
Disclosure, to reduce potential ambiguity in financial reporting when
measuring the fair value of liabilities.  These changes clarify
existing guidance that in circumstances in which a quoted price in an active
market for the identical liability is not available, an entity is required to
measure fair value using either a valuation technique that uses a quoted price
of either a similar liability or a quoted price of an identical or similar
liability when traded as an asset, or another valuation technique that is
consistent with the principles of fair value measurements, such as an income
approach (e.g., present value technique).  This guidance also states
that both a quoted price in an active market for the identical liability and a
quoted price for the identical liability when traded as an asset in an active
market when no adjustments to the quoted price of the asset are required are
Level 1 fair value measurements.  These changes become effective for
the Partnership on October 1, 2009.  The Partnership has not
determined the impact, if any, that these changes will have on the Partnership’s
financial statements.




- 6 -
 Index


PDC
2004-B LIMITED PARTNERSHIP
 NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
 June 30,
2009
 (unaudited)





Note 3 −
Transactions with
Managing General Partner and Affiliates





The
Managing General Partner transacts business on behalf of the Partnership under
the authority of the D&O Agreement.  Revenues and other cash
inflows received on behalf of the Partnership are distributed to the Partners
net of (after deducting) corresponding operating costs and other cash outflows
incurred on behalf of the Partnership.





The fair
value of the Partnership’s portion of unexpired derivative instruments is
recorded on the balance sheet under the captions “Due from Managing General
Partner–derivatives,” in the case of net unrealized gains or “Due to Managing
General Partner–derivatives,” in the case of net unrealized losses.





Undistributed
oil and natural gas revenues collected by the Managing General Partner from the
Partnership’s customers in the amount of $196,473 and $258,733 as of June 30,
2009 and December 31, 2008, respectively, are included in the balance sheet
caption “Due from Managing General Partner - other, net.”  Realized
gains or losses from derivative transactions that have not yet been distributed
to the Partnership are included in the balance sheet captions “Due from Managing
General Partner-other, net” or “Due to Managing General Partner-other, net,”
respectively.  Undistributed realized gains amounted to $283,438 and
$350,255 as of June 30, 2009 and December 31, 2008, respectively.  All
other unsettled transactions between the Partnership and the Managing General
Partner are recorded net on the balance sheet under the caption “Due from (to)
Managing General Partner – other, net.”





The
following table presents transactions with the Managing General Partner and its
affiliates for the periods described below.  “Well operations and
maintenance” and “Gathering, compression and processing fees” are included in
“Production and operating costs” on the Statements of
Operations.  Additionally, refer to Note 5, Derivative Financial
Instruments for derivative transactions between the Partnership and the
Managing General Partner.





Three
      months ended June 30,
            
            
            Six
      months ended June 30,2009
            
            
            2008
            
            
            2009
            
            
            2008Well
      operations and maintenance
            
            $
            98,852
            
            
            $
            118,076
            
            
            $
            181,681
            
            
            $
            190,886Gathering,
      compression and processing fees
            
            
            23,441
            
            
            
            39,157
            
            
            
            45,926
            
            
            
            70,092Direct
      costs - general and administrative
            
            
            116,295
            
            
            
            12,556
            
            
            
            258,321
            
            
            
            19,360Cash
      distributions*
            
            
            170,742
            
            
            
            153,456
            
            
            
            276,524
            
            
            
            255,041





*Cash
distributions include $12,008 and $17,359 during the three and six months ended
June 30, 2009, respectively, and $5,076 and $8,087 during the three and six
months ended June 30, 2008, respectively, related to equity cash distributions
on Investor Partner units repurchased by PDC.  For additional
disclosure regarding the Unit Repurchase Program, refer to Note 1, General and Basis of
Presentation.








Note 4 −
Fair Value
Measurements





Determination of Fair Value.
The Partnership determines the fair value of its assets and liabilities, unless
specifically excluded, pursuant to FAS No. 157.  FAS No. 157 defines
fair value as the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at
the measurement date.


- 7 -
 Index
 
 PDC
2004-B LIMITED PARTNERSHIP
 NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
 June 30,
2009
 (unaudited)


FAS No.
157 establishes a fair value hierarchy that requires an entity to maximize the
use of observable inputs and minimize the use of unobservable inputs when
measuring fair value.  The valuation hierarchy is based upon the
transparency of inputs to the valuation of an asset or liability as of the
measurement date, giving the highest priority to quoted prices in active markets
(Level 1) and the lowest priority to unobservable data (Level 3).  In
some cases, the inputs used to measure fair value might fall in different levels
of the fair value hierarchy.  The lowest level input that is
significant to a fair value measurement in its entirety determines the
applicable level in the fair value hierarchy.  Assessing the
significance of a particular input to the fair value measurement in its entirety
requires judgment, considering factors specific to the asset or liability, and
may affect the valuation of the assets and liabilities and their placement
within the fair value hierarchy levels.  The three levels of inputs
that may be used to measure fair value are defined as:





·
            Level 1 –
      Quoted prices (unadjusted) in active markets for identical assets or
      liabilities.  Included in Level 1 are commodity derivative
      instruments for New York Mercantile Exchange, or NYMEX, natural gas
      swaps.





·
            Level 2 –
      Inputs other than quoted prices included within Level 1 that are either
      directly or indirectly observable for the asset or liability, including
      (i) quoted prices for similar assets or liabilities in active markets,
      (ii) quoted prices for identical or similar assets or liabilities in
      inactive markets, (iii) inputs other than quoted prices that are
      observable for the asset or liability and (iv) inputs that are derived
      from observable market data by correlation or other
  means.





·
            Level 3 –
      Unobservable inputs for the asset or liability, including situations where
      there is little, if any, market activity for the asset or
      liability.  Included in Level 3 are the Partnership’s commodity
      derivative instruments for Colorado Interstate Gas, or CIG, based
      fixed-price natural gas swaps, collars and floors, oil swaps, and natural
      gas basis protection swaps.





Derivative Financial
Instruments.  The Partnership measures fair value based upon
quoted market prices, where available.  The valuation determination
includes: (1) identification of the inputs to the fair value methodology through
the review of counterparty statements and other supporting documentation, (2)
determination of the validity of the source of the inputs, (3) corroboration of
the original source of inputs through access to multiple quotes, if available,
or other information and (4) monitoring changes in valuation methods and
assumptions.  The methods described above may produce a fair value
calculation that may not be indicative of future fair values.  The
valuation determination also gives consideration to nonperformance risk on
Partnership liabilities in addition to nonperformance risk on PDC’s own business
interests and liabilities, as well as the credit standing of derivative
instrument counterparties.  The Managing General Partner primarily
uses two investment grade financial institutions as counterparties to its
derivative contracts, who hold the majority of the Managing General Partner’s
derivative assets.  The Managing General Partner has evaluated the
credit risk of the Partnership’s derivative assets from counterparties holding
its derivative assets using relevant credit market default rates, giving
consideration to amounts outstanding for each counterparty and the duration of
each outstanding derivative position.  Based on the Managing General
Partner’s evaluation, the Partnership has determined that the impact of
counterparty non-performance on the fair value of the Partnership’s derivative
instruments is insignificant.  As of June 30, 2009, no adjustment for
credit risk was recorded by the Partnership.  Furthermore, while the
Managing General Partner believes these valuation methods are appropriate and
consistent with that used by other market participants, the use of different
methodologies, or assumptions, to determine the fair value of certain financial
instruments could result in a different estimate of fair value.


- 8 -
 Index





PDC
2004-B LIMITED PARTNERSHIP


NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS


June 30,
2009


(unaudited)




The
following table presents, by hierarchy level, the Partnership’s derivative
financial instruments, including both current and non-current portions measured
at fair value for the periods described.





Level
      1
            
            
            Level
      3
            
            
            TotalAs
      of December 31, 2008Assets:Commodity
      based derivatives
            
            $
            -
            
            
            $
            1,315,396
            
            
            $
            1,315,396Total
      assets
            
            
            -
            
            
            
            1,315,396
            
            
            
            1,315,396Liabilities:
            
            
            -
            
            
            
            -Basis
      protection derivative contracts
            
            
            -
            
            
            
            (100,327
            )
            
            
            (100,327
            )Total
      liabilities
            
            
            -
            
            
            
            (100,327
            )
            
            
            (100,327
            )Net
      asset
            
            $
            -
            
            
            $
            1,215,069
            
            
            $
            1,215,069As
      of June 30, 2009Assets:Commodity
      based derivatives
            
            $
            45
            
            
            $
            855,119
            
            
            $
            855,164Total
      assets
            
            
            45
            
            
            
            855,119
            
            
            
            855,164Liabilities:Commodity
      based derivatives
            
            
            (65,940
            )
            
            $
            (2,798
            )
            
            
            (68,738
            )Basis
      protection derivative contracts
            
            
            -
            
            
            
            (698,472
            )
            
            
            (698,472
            )Total
      liabilities
            
            
            (65,940
            )
            
            
            (701,270
            )
            
            
            (767,210
            )Net
      (liability) asset
            
            $
            (65,895
            )
            
            $
            153,849
            
            
            $
            87,954





The
following table sets forth the changes of the Partnership’s Level 3 derivative
financial instruments measured on a recurring basis:





Six
      months endedJune
      30, 2009Fair
      value, net asset, as of December 31, 2008
            
            $
            1,215,069Changes
      in fair value included in statement of operations line
    item:Oil
      and gas price risk management loss, net
            
            
            (353,049
            )Settlements
            
            
            (708,171
            )Fair
      value, net asset, as of June 30, 2009
            
            $
            153,849Change
      in unrealized gains (losses) relating to assets
      (liabilities)  still held as of June 30, 2009, included in
      statement of   operations line item:Oil
      and gas price risk management, net
            
            $
            (501,651
            )





See Note
5, Derivative Financial
Instruments, for additional disclosure related to the Partnership’s
derivative financial instruments.





Non-Derivative Assets and
Liabilities.  The carrying values of the financial instruments
comprising “Cash and cash equivalents,” “Accounts receivable,” “Accounts payable
and accrued expenses” and “Due to (from) Managing General Partner-other, net”
approximate fair value due to the short-term maturities of these
instruments.





In
accordance with FAS 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, the Partnership periodically assesses its
proved oil and gas properties for possible impairment, upon a triggering event,
by comparing net capitalized costs to estimated undiscounted future net cash
flows on a field-by-field basis using estimated production based upon estimated
prices at which the Partnership reasonably estimates the commodity to be
sold.  The estimates of future prices may differ from current market
prices of oil and natural gas.  Certain events, including but not
limited to, downward revisions in estimates to the Partnership’s reserve
quantities, expectations of falling commodity prices or rising operating costs
may result in a triggering event and, therefore, a possible impairment of the
Partnership’s oil and natural gas properties.  If, when assessing
impairment, net capitalized costs exceed undiscounted future net cash flows, the
measurement of impairment is based on estimated fair value utilizing a future
discounted cash flow analysis and is measured by the amount by which the net
capitalized costs exceed their fair value.  During the six months
ended June 30, 2009 and 2008, there were no triggering events; therefore, no
impairment of oil and gas properties was recognized.





- 9 -
 Index


PDC
2004-B LIMITED PARTNERSHIP
 NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
 June 30,
2009
 (unaudited)




The
Partnership accounts for asset retirement obligations by recording the estimated
fair value of the plugging and abandonment obligations when incurred, at the
time the well is completely drilled.  The Partnership estimates the
fair value of the plugging and abandonment obligations based on a discounted
cash flows analysis.  Upon initial recognition of an asset retirement
obligation, the Partnership increases the carrying amount of the long-lived
asset by the same amount as the liability.  Periodically, the
liabilities are accreted for the change in present value, through charges to
“Accretion of asset retirement obligations” on the statement of
operations.  The initial capitalized costs are depleted based on the
useful lives of the related assets, through charges to depreciation, depletion
and amortization, or DD&A.  If the fair value of the estimated
asset retirement obligation changes, an adjustment is recorded to both the asset
retirement obligation and the asset retirement cost.  Revisions in
estimated liabilities can result from revisions of estimated inflation rates,
escalating retirement costs and changes in the estimated timing of settling
asset retirement obligations.








Note 5 −
Derivative Financial
Instruments





The
Partnership is exposed to the effect of market fluctuations in the prices of oil
and natural gas.  Price risk represents the potential risk of loss
from adverse changes in the market price of oil and natural gas
commodities.  The Managing General Partner employs established
policies and procedures to manage the risks associated with these market
fluctuations using derivative instruments.  Partnership policy
prohibits the use of oil and natural gas derivative instruments for speculative
purposes.





The
Partnership recognizes all derivative instruments as either assets or
liabilities on the accompanying interim unaudited condensed balance sheets at
fair value.  The Partnership has elected not to designate any of the
Partnership’s derivative instruments as hedges.  Accordingly, changes
in the fair value of those derivative instruments allocated to the Partnership
are recorded in the Partnership’s statements of operations.  Changes
in the fair value of derivative instruments related to the Partnership’s oil and
gas sales activities are recorded in “Oil and gas price risk management,
net.”





Valuation
of a contract’s fair value is performed internally.  While the
Managing General Partner uses common industry practices to develop the
Partnership’s valuation techniques, changes in pricing methodologies or the
underlying assumptions could result in different fair values.  See
Note 4, Fair Value
Measurements, for a discussion of how the Managing General Partner
determines the fair value of the Partnership’s derivative
instruments.





As of
September 30, 2009, the Managing General Partner had derivative contracts in
place for a portion of the Partnership’s anticipated production through 2012 for
a total of 491 MMbtu of natural gas and 9 MBbls of crude oil.  During
late October 2009, the Managing General Partner entered into additional NYMEX
fixed-price gas swaps (ranging from $6.67 to $7.11 per MMbtu) and NYMEX gas
collars (floors ranging from $6.00 to $6.10 and ceilings ranging from $8.27 to
$8.60 per MMbtu) covering all monthly periods from November 2010 to December
2013. The Partnership will be allocated positions by the Managing General
Partner for MMbtu’s equal to the number of remaining MMbtu’s of CIG basis
protection swaps at September 30, 2009 which were not previously covered by
NYMEX fixed-price gas swaps or gas collars.





Derivative
Strategies.  The Partnership’s results of operations and
operating cash flows are affected by changes in market prices for oil and
natural gas.  To mitigate a portion of the exposure to adverse market
changes, the Managing General Partner has entered into various derivative
contracts.




- 10 -
 Index


PDC
2004-B LIMITED PARTNERSHIP
 NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
 June 30,
2009
 (unaudited)


For
Partnership oil and gas sales, the Managing General Partner enters into, for a
portion of the Partnership’s production, derivative contracts to protect against
price declines in future periods.  While these derivatives are
structured to reduce exposure to changes in price associated with the derivative
commodity, they also limit the benefit the Partnership might otherwise have
received from price increases in the physical market.  The Partnership
believes the derivative instruments in place continue to be effective in
achieving the risk management objectives for which they were
intended.





As of
June 30, 2009, the Partnership’s oil and natural gas derivative instruments were
comprised of commodity collars, commodity swaps and basis protection
swaps.





·
            Collars
      contain a fixed floor price (put) and ceiling price (call).  If
      the market price falls below the fixed put strike price, PDC, as Managing
      General Partner, receives the market price from the purchaser and receives
      the difference between the put strike price and market price from the
      counterparty.  If the market price exceeds the fixed call strike
      price, PDC, as Managing General Partner, receives the market price from
      the purchaser and pays the difference between the call strike price and
      market price to the counterparty.  If the market price is
      between the call and put strike price, no payments are due to or from the
      counterparty.





·
            Swaps
      are arrangements that guarantee a fixed price.  If the market
      price is below the fixed contract price, PDC, as Managing General Partner,
      receives the market price from the purchaser and receives the difference
      between the market price and the fixed contract price from the
      counterparty.  If the market price is above the fixed contract price,
      PDC, as Managing General Partner, receives the market price from the
      purchaser and pays the difference between the market price and the fixed
      contract price to the counterparty.





·
            Basis
      protection swaps are arrangements that guarantee a price differential for
      natural gas from a specified delivery point.  For CIG basis
      protection swaps, which traditionally have negative differentials to
      NYMEX, PDC, as Managing General Partner, receives a payment from the
      counterparty if the price differential is greater than the stated terms of
      the contract and pays the counterparty if the price differential is less
      than the stated terms of the
contract.


- 11 -
 Index





PDC
2004-B LIMITED PARTNERSHIP


NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS


June 30,
2009


(unaudited)




The
following table summarizes the location and fair value amounts of the
Partnership’s derivative instruments in the accompanying balance sheets as of
June 30, 2009, and December 31, 2008.





Fair
      ValueBalance
      Sheet
            
            June
      30,
            
            
            December
      31,Derivative
      instruments not designated as hedge  (1):
            
            Line
      Item
            
            2009
            
            
            2008Derivative
      Assets:
            CurrentCommodity
      contracts
            
            Due
      from Managing General Partner-derivatives
            
            $
            809,502
            
            
            $
            995,593Non CurrentCommodity
      contracts
            
            Due
      from Managing General Partner-derivatives
            
            
            45,662
            
            
            
            319,803Total
      Derivative Assets
            
            
            
            
            $
            855,164
            
            
            $
            1,315,396Derivative
      Liabilities:
            CurrentCommodity
      contracts
            
            Due
      to Managing General Partner-derivatives
            
            $
            (13,783
            )
            
            $
            -Basis
      protection contracts
            
            Due
      to Managing General Partner-derivatives
            
            
            (57,547
            )
            
            
            -Non CurrentCommodity
      contracts
            
            Due
      to Managing General Partner-derivatives
            
            
            (54,955
            )
            
            
            -Basis
      protection contracts
            
            Due
      to Managing General Partner-derivatives
            
            
            (640,925
            )
            
            
            (100,327
            )Total
      Derivative Liabilities
            
            
            
            $
            (767,210
            )
            
            $
            (100,327
            )





(1) As of
June 30, 2009 and December 31, 2008, none of the Partnership’s derivative
instruments were designated hedges.





The
following table summarizes the impact of the Partnership’s derivative
instruments on the Partnership’s accompanying statements of operations for the
three months and six months ended June 30, 2009 and 2008.





Three
      months ended June 30,2009
            
            
            2008Statement
      of operations line item
            
            Reclassification
      of Realized Gains (Losses) Included in Prior Periods
      Unrealized
            
            
            Realized
      and Unrealized Gains (Losses) For the Current Period
            
            
            Total
            
            
            Reclassification
      of Realized Gains (Losses) Included in Prior Periods
      Unrealized
            
            
            Realized
      and Unrealized Gains (Losses) For the Current Period
            
            
            TotalOil
      and gas price risk management, netRealized
      gains (losses)
            
            $
            302,139
            
            
            $
            (18,698
            )
            
            $
            283,441
            
            
            $
            (113,977
            )
            
            $
            (168,883
            )
            
            $
            (282,860
            )Unrealized
      (losses) gains
            
            
            (302,139
            )
            
            
            (349,416
            )
            
            
            (651,555
            )
            
            
            113,977
            
            
            
            (680,670
            )
            
            
            (566,693
            )Total
      oil and gas price risk management, net
            
            $
            -
            
            
            $
            (368,114
            )
            
            $
            (368,114
            )
            
            $
            -
            
            
            $
            (849,553
            )
            
            $
            (849,553
            )








Six
      months ended June 30,2009
            
            
            2008Statement
      of operations line item
            
            Reclassification
      of Realized Gains (Losses) Included in Prior Periods
      Unrealized
            
            
            Realized
      and Unrealized Gains (Losses) For the Current Period
            
            
            Total
            
            
            Reclassification
      of Realized Gains (Losses) Included in Prior Periods
      Unrealized
            
            
            Realized
      and Unrealized Gains (Losses) For the Current Period
            
            
            TotalOil
      and gas price risk management,  netRealized
      gains (losses)
            
            $
            556,781
            
            
            $
            151,390
            
            
            $
            708,171
            
            
            $
            (28,199
            )
            
            $
            (289,556
            )
            
            $
            (317,755
            )Unrealized
      (losses) gains
            
            
            (556,781
            )
            
            
            (570,334
            )
            
            
            (1,127,115
            )
            
            
            28,199
            
            
            
            (958,823
            )
            
            
            (930,624
            )Total
      oil and gas price risk management, net
            
            $
            -
            
            
            $
            (418,944
            )
            
            $
            (418,944
            )
            
            $
            -
            
            
            $
            (1,248,379
            )
            
            $
            (1,248,379
            )





Concentration of Credit Risk.
A significant portion of the Partnership’s liquidity is concentrated in
derivative instruments that enables the Partnership to manage a portion of its
exposure to price volatility from producing oil and natural
gas.  These arrangements expose the Partnership to credit risk of
nonperformance by the counterparties.  The Managing General Partner
primarily uses two financial institutions, who are also major lenders in the
Managing General Partner’s credit facility agreement, as counterparties to the
derivative contracts.


- 12 -
 Index
 
 PDC
2004-B LIMITED PARTNERSHIP
 NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
 June 30,
2009
 (unaudited)




Note 6 −
Commitments and
Contingencies





Colorado Royalty
Settlement.On May 29, 2007, Glen Droegemueller, individually
and as representative plaintiff on behalf of all others similarly situated,
filed a class action complaint against the Managing General Partner in the
District Court, Weld County, Colorado alleging that the Managing General Partner
underpaid royalties on natural gas produced from wells operated by the Managing
General Partner in parts of the State of Colorado (the “Droegemueller
Action”).  The plaintiff sought declaratory relief and to recover an
unspecified amount of compensation for underpayment of royalties paid by the
Managing General Partner pursuant to leases.  The Managing General Partner
moved the case to Federal Court on June 28, 2007.  On October 10, 2008, the
court preliminarily approved a settlement agreement between the plaintiffs and
the Managing General Partner, on behalf of itself and the Partnership. 
Although the Partnership was not named as a party in the suit, the lawsuit
states that this action relates to all wells operated by the Managing General
Partner, which includes a majority of the Partnership’s 16 wells in the
Wattenberg field.  The portion of the settlement relating to the
Partnership’s wells for all periods through June 30, 2009 that has been expensed
by the Partnership is approximately $19,000 including associated legal costs of
approximately $1,000.  This entire settlement of $17,713 was deposited
by the Managing General Partner into an escrow account on November 3,
2008.  Notice of the settlement was mailed to members of the class
action suit in the fourth quarter of 2008.  The final settlement was
approved by the court on April 7, 2009.  Settlement distribution
checks were mailed in July 2009.  During September 2009, all
settlement costs were passed through to the Partners and related required
judicial action from the settlement of the suit was implemented in this
distribution.





Colorado Stormwater
Permit.   On December 8, 2008, the Managing General
Partner received a Notice of Violation /Cease and Desist Order (the “Notice”)
from the Colorado Department of Public Health and Environment, related to the
stormwater permit for the Garden Gulch Road.  The Managing General
Partner manages this private road for Garden Gulch LLC.  The Managing
General Partner is one of eight users of this road, all of which are oil and gas
companies operating in the Piceance region of Colorado.  Operating
expenses, including amounts arising from this notice, if any, are allocated
among the eight users of the road based upon their respective
usage.  The Partnership has seven wells in this region.  The
Notice alleges a deficient and/or incomplete stormwater management plan, failure
to implement best management practices and failure to conduct required permit
inspections.  The Notice requires corrective action and states that
the recipient shall cease and desist such alleged violations.  The
Notice states that a violation could result in civil penalties up to $10,000 per
day.  The Managing General Partner’s responses were submitted on
February 6, 2009, and April 8, 2009.  No civil penalties have been
imposed or requested at this time.  Given the preliminary stage of
this proceeding and the inherent uncertainty in administrative actions of this
nature, the Managing General Partner is unable to predict the ultimate outcome
of this administrative action at this time and therefore no amounts have been
recorded on the Partnership’s financial records.





Derivative
Contracts.  The Partnership is exposed to oil and natural gas
price fluctuations on underlying sales contracts should the counterparties to
the Managing General Partner’s derivative instruments not
perform.  The Managing General Partner has had no counterparty default
losses and expects full performance by the counterparties to these agreements in
the future.





Note
7−Subsequent
Events





We have
evaluated the Partnership’s activities subsequent to June 30, 2009, through
December 18, 2009 (the date the financial statements were issued), and have
concluded that no subsequent events have occurred that would require recognition
in the Partnership’s financial statements or disclosure in the notes to the
unaudited condensed financial statements.


- 13 -
 Index




PDC
2004-B LIMITED PARTNERSHIP
 (A
West Virginia Limited Partnership)


Item 2. Management’s
Discussion and Analysis of Financial Condition and Results of
Operations


Special
Note Regarding Forward Looking Statements





This
periodic report contains “forward-looking statements” within the meaning of
Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E
of the Securities Exchange Act of 1934 (“Exchange Act”) regarding PDC 2004-B
Limited Partnership’s (the “Partnership’s” or the “Registrant’s”) business,
financial condition, results of operations and prospects.  All
statements other than statements of historical facts included in and
incorporated by reference into this report are forward-looking
statements.  Words such as “expects,” “anticipates,” “intends,”
“plans,” “believes,” “seeks,” “estimates” and similar expressions or variations
of such words are intended to identify forward-looking statements herein, which
include statements of estimated oil and natural gas production and reserves,
drilling plans, future cash flows, anticipated liquidity, anticipated capital
expenditures and the Managing General Partner Petroleum Development
Corporation’s (“MGP’s” or “PDC’s”) strategies, plans and
objectives.  However, these are not the exclusive means of identifying
forward-looking statements herein.  Although forward-looking
statements contained in this report reflect the Managing General Partner's good
faith judgment, such statements can only be based on facts and factors currently
known to the Managing General Partner.  Consequently, forward-looking
statements are inherently subject to risks and uncertainties, including risks
and uncertainties incidental to the development, production and marketing of
natural gas and oil, and actual outcomes may differ materially from the results
and outcomes discussed in the forward-looking statements. Important factors that
could cause actual results to differ materially from the forward-looking
statements include, but are not limited to:





·
            changes
      in production volumes, worldwide demand, and commodity prices for oil and
      natural gas;


·
            risks
      incident to the operation of natural gas and oil
  wells;


·
            future
      production and development costs;


·
            the
      availability of sufficient pipeline and other transportation facilities to
      carry Partnership production and the impact of these facilities on
      price;


·
            the
      effect of existing and future laws, governmental regulations and the
      political and economic climate of the United States of
      America;


·
            the
      effect of natural gas and oil derivatives
  activities;


·
            conditions
      in the capital markets; and


·
            losses
      possible from pending or future
litigation.





Further,
the Partnership urges you to carefully review and consider the cautionary
statements made in this report, the Partnership’s annual report on Form 10-K for
the year ended December 31, 2008 filed with the Securities and Exchange
Commission (“SEC”) on October 26, 2009 (“2008 Form 10-K”), and the Partnership’s
other filings with the SEC and public disclosures.  The Partnership
cautions you not to place undue reliance on forward-looking statements, which
speak only as of the date of this report.  The Partnership undertakes
no obligation to update any forward-looking statements in order to reflect any
event or circumstance occurring after the date of this report or currently
unknown facts or conditions or the occurrence of unanticipated
events.





Overview





PDC
2004-B Limited Partnership engages in the development, production and sale of
oil and natural gas.  The Partnership began oil and gas operations in
July 2004 and currently operates 23 gross (20.9 net) wells located in the Rocky
Mountain Region in the state of Colorado.  The Managing General
Partner markets the Partnership’s natural gas production to commercial end
users, interstate or intrastate pipelines or local utilities, primarily under
market sensitive contracts in which the price of natural gas sold varies as a
result of market forces.  PDC, on behalf of the Partnership through
the D&O Agreement, may enter into multi-year fixed price contracts or
utilize derivatives, including collars, swaps or basis protection swaps, in
order to offset some or all of the commodity price variability for particular
periods of time.  Seasonal factors, such as effects of weather on
prices received and costs incurred, and availability of pipeline capacity, owned
by PDC or other third parties, may impact the Partnership's
results.  In addition, both sales volumes and prices could be affected
by demand factors with a seasonal component.


- 14 -
 Index


PDC
2004-B LIMITED PARTNERSHIP
 (A
West Virginia Limited Partnership)


Results of
Operations





The
following table sets forth selected information regarding the Partnership’s
results of operations, including production volumes, oil and natural gas sales,
average sales prices received, average sales price including realized derivative
gains and losses, production and operating costs, depreciation, depletion and
amortization costs,  other operating income and expenses for the three
and six months ended June 30, 2009, or the current three and six month periods
and the three and six months ended June 30, 2008,  or the prior three
and six month periods.





Summary
      of Operating ResultsThree
      months ended June 30,
            
            
            Six
      months ended June 30,2009
            
            
            2008
            
            
            Change
            
            
            2009
            
            
            2008
            
            
            ChangeNumber
      of producing wells (end of period)
            
            
            23
            
            
            
            23
            
            
            
            -
            
            
            
            23
            
            
            
            23
            
            
            
            -Production:  (1)Oil
      (Bbl)
            
            
            2,515
            
            
            
            2,557
            
            
            
            -2
            %
            
            
            5,217
            
            
            
            4,927
            
            
            
            6
            %Natural
      gas (Mcf)
            
            
            87,440
            
            
            
            143,040
            
            
            
            -39
            %
            
            
            171,444
            
            
            
            255,501
            
            
            
            -33
            %Natural
      gas equivalents (Mcfe)  (2)
            
            
            102,530
            
            
            
            158,382
            
            
            
            -35
            %
            
            
            202,746
            
            
            
            285,063
            
            
            
            -29
            %Average
      Selling Price (excluding realized gain (loss) on
    derivatives)Oil
      (per Bbl)
            
            $
            51.64
            
            
            $
            113.51
            
            
            
            -55
            %
            
            $
            43.85
            
            
            $
            98.31
            
            
            
            -55
            %Natural
      gas (per Mcf)
            
            
            2.02
            
            
            
            8.32
            
            
            
            -76
            %
            
            
            2.48
            
            
            
            7.63
            
            
            
            -68
            %Natural
      gas equivalents (per Mcfe)
            
            
            2.99
            
            
            
            9.35
            
            
            
            -68
            %
            
            
            3.22
            
            
            
            8.54
            
            
            
            -62
            %Realized
      Gain (Loss) on Derivatives, netOil
      derivatives - realized gain (loss)
            
            $
            43,108
            
            
            $
            (45,232
            )
            
            
            195
            %
            
            $
            108,535
            
            
            $
            (56,117
            )
            
            
            *Natural
      gas derivatives - realized gain (loss)
            
            
            240,333
            
            
            
            (237,628
            )
            
            
            201
            %
            
            
            599,636
            
            
            
            (261,638
            )
            
            
            *Total
      realized gain (loss) on derivatives, net
            
            $
            283,441
            
            
            $
            (282,860
            )
            
            
            200
            %
            
            $
            708,171
            
            
            $
            (317,755
            )
            
            
            *Average
      Selling Price (including realized gain (loss) on
    derivatives)Oil
      (per Bbl)
            
            $
            68.78
            
            
            $
            95.82
            
            
            
            -28
            %
            
            $
            64.65
            
            
            $
            86.92
            
            
            
            -26
            %Natural
      gas (per Mcf)
            
            
            4.77
            
            
            
            6.66
            
            
            
            -28
            %
            
            
            5.97
            
            
            
            6.61
            
            
            
            -10
            %Natural
      gas equivalents (per Mcfe)
            
            
            5.76
            
            
            
            7.56
            
            
            
            -24
            %
            
            
            6.72
            
            
            
            7.42
            
            
            
            -10
            %Average
      cost per McfeProduction
      and operating costs  (3)
            
            $
            1.37
            
            
            $
            1.87
            
            
            
            -27
            %
            
            $
            1.31
            
            
            $
            1.71
            
            
            
            -24
            %Depreciation,
      depletion and amortization
            
            
            3.39
            
            
            
            2.49
            
            
            
            36
            %
            
            
            3.47
            
            
            
            2.57
            
            
            
            35
            %Revenues:Oil
      and natural gas sales
            
            $
            306,926
            
            
            $
            1,480,313
            
            
            
            -79
            %
            
            $
            653,360
            
            
            $
            2,433,949
            
            
            
            -73
            %Realized
      gain (loss) on derivatives, net
            
            
            283,441
            
            
            
            (282,860
            )
            
            
            -200
            %
            
            
            708,171
            
            
            
            (317,755
            )
            
            
            *Unrealized
      loss on derivatives, net
            
            
            (651,555
            )
            
            
            (566,693
            )
            
            
            15
            %
            
            
            (1,127,115
            )
            
            
            (930,624
            )
            
            
            21
            %Total
      revenues
            
            $
            (61,188
            )
            
            $
            630,760
            
            
            
            -110
            %
            
            $
            234,416
            
            
            $
            1,185,570
            
            
            
            -80
            %Operating
      costs and expenses:Production
      and operating costs
            
            $
            139,995
            
            
            $
            295,585
            
            
            
            -53
            %
            
            $
            265,025
            
            
            $
            487,272
            
            
            
            -46
            %Direct
      costs - general and administrative
            
            
            116,295
            
            
            
            12,556
            
            
            
            *
            
            
            
            258,321
            
            
            
            19,360
            
            
            
            *Depreciation,
      depletion and amortization
            
            
            347,088
            
            
            
            394,122
            
            
            
            -12
            %
            
            
            704,443
            
            
            
            732,811
            
            
            
            -4
            %Accretion
      of asset retirement obligations
            
            
            2,321
            
            
            
            2,195
            
            
            
            6
            %
            
            
            4,642
            
            
            
            4,390
            
            
            
            6
            %Total
      operating costs and expenses
            
            $
            605,699
            
            
            $
            704,458
            
            
            
            -14
            %
            
            $
            1,232,431
            
            
            $
            1,243,833
            
            
            
            -1
            %Loss
      from operations
            
            $
            (666,887
            )
            
            $
            (73,698
            )
            
            
            -805
            %
            
            $
            (998,015
            )
            
            $
            (58,263
            )
            
            
            -1613
            %Interest
      income
            
            
            6,663
            
            
            
            9,516
            
            
            
            -30
            %
            
            
            13,772
            
            
            
            19,739
            
            
            
            -30
            %Net
      loss
            
            $
            (660,224
            )
            
            $
            (64,182
            )
            
            
            -929
            %
            
            $
            (984,243
            )
            
            $
            (38,524
            )
            
            
            -2455
            %Cash
      distributions
            
            $
            793,670
            
            
            $
            741,902
            
            
            
            7
            %
            
            $
            1,295,828
            
            
            $
            1,234,775
            
            
            
            5
            %





*Percentage
change not meaningful, equal to or greater than 250% or not
calculable.  Amounts may not calculate due to rounding.


_______________


(1)
            Production
      is determined by multiplying the gross production volume of properties in
      which the Partnership has an interest by the percentage of the leasehold
      or other property interest the Partnership
owns.


(2)
            A
      ratio of energy content of natural gas and oil (six Mcf of natural gas
      equals one Bbl of oil) was used to obtain a conversion factor to convert
      oil production into equivalent Mcf of natural
  gas.


(3)
            Production
      costs represent oil and gas operating expenses which include production
      taxes.


- 15 -
 Index





PDC
2004-B LIMITED PARTNERSHIP


(A
West Virginia Limited Partnership)


Definitions
used throughout Management’s Discussion and Analysis of Financial Condition and
Results of Operations:





·
            Bbl
      – One barrel or 42 U.S. gallons liquid
volume


·
            MBbl
      – One thousand barrels


·
            Mcf
      – One thousand cubic feet


·
            MMcf
      – One million cubic feet


·
            Mcfe
      – One thousand cubic feet of natural gas
  equivalents


·
            MMcfe
      – One million cubic feet of natural gas
  equivalents


·
            MMbtu
      – One million British Thermal Units





The
Partnership continued to experience the depressed natural gas prices from the
significant declines in late July 2008 through the second quarter of
2009.  The Partnership’s production decreased to 203 MMcfe for the
first six months of 2009 compared to 285 MMcfe for prior year six month period,
a decrease of 29%, while the Partnership’s average sales price declined $5.32
per Mcfe, a decrease of 62%.  While the Partnership certainly has felt
the impact of the significant changes in commodity prices, the Managing General
Partner believes that it was successful in managing the Partnership’s operations
in such a manner that the Managing General Partner was able to minimize the
negative impacts as the Partnership’s derivative position eased the
impact.  The Partnership’s realized derivative gains for the current
six month period of $0.7 million added an average of $3.50 per Mcfe produced
during the first six months of 2009.  From May through August 2009,
natural gas prices rebounded slightly while crude oil prices increased
substantially to price levels that remained, however, significantly lower than
those of the comparable period in 2008.  At June 30, 2009, the
estimated net fair value of the Partnership’s open derivative positions is a net
asset of $0.1 million.





Depressed
commodity prices for the six months of 2009 as compared to the higher prices in
prior year’s six month period were the primary contributors to the $0.8 million
change in oil and gas price risk management, net.  Of the $0.8 million
change, $1.0 million was related to an increase in realized derivative gains and
the remaining $0.2 million was related to an increase in unrealized derivative
losses.  Unrealized gains and losses are non-cash
items.  These non-cash charges to the Partnership’s statement of
operations will continue to fluctuate with the fluctuation in commodity prices
until the existing positions mature or are closed, at which time they will
become realized or cash items.  The Partnership has elected not to
designate any of the Partnership’s derivative instruments as
hedges.  While the required accounting treatment under Statement of
Financial Accounting Standards, or FAS, No. 133, Accounting for Derivative
Instruments and Certain Hedging Activities for derivatives that are not
designated as hedges, may result in significant swings in operating results over
the life of the derivatives, the combination of the settled derivative contracts
and the revenue received from the oil and gas sales at delivery are expected to
result in a more predictable cash flow stream than would the sales contracts
without the associated derivatives.





The table
below, which demonstrates the markets’ expected volatility in commodity pricing,
sets forth the average NYMEX and CIG prices for the next 24 months (forward
curve) from the selected dates:




June
      30,
              
              
              September
      30,
              
              
              March
      31,
              
              
              September
      30,
              
              
              October
      31,Commodity
              
              Index
              
              2008
              
              
              2008
              
              
              2009
              
              
              2009
              
              
              2009Natural
      gas: (per
      MMbtu)NYMEX
              
              $
              12.52
              
              
              $
              8.21
              
              
              $
              5.44
              
              
              $
              6.25
              
              
              $
              6.00CIG
              
              
              8.86
              
              
              
              5.46
              
              
              
              4.15
              
              
              
              5.64
              
              
              
              5.49Oil:
      (per
      Bbl)
              
              NYMEX
              
              
              140.15
              
              
              
              103.63
              
              
              
              59.35
              
              
              
              74.64
              
              
              
              81.26




Oil and Natural Gas
Sales





Partnership
production decreased to 103 MMcfe and 203 MMcfe for the current year three and
six month periods, respectively, from 158 MMcfe and 285 MMcfe for the prior year
three and six month periods, respectively.  The Partnership’s oil and
gas sales revenue for the current three and six month periods, excluding price
risk management impacts, decreased from the comparable periods in 2008, by $1.2
million and $1.8 million, respectively, due to the significant decline in
commodity prices and by decreased volumes.  Approximately $0.7 million
and $1.1 million of the decrease in oil and natural gas sales revenue for the
current three month and six month periods, respectively, was due to pricing and
$0.5 million and $0.7 million was due to decreased production,
respectively.




- 16 -
 Index
  PDC
2004-B LIMITED PARTNERSHIP
 (A
West Virginia Limited Partnership)


The
Partnership expects to experience continued declines in both oil and natural gas
production volumes over the wells’ life cycles until such time that the
Partnership’s Wattenberg wells may be successfully
recompleted.  Subsequent to a successful recompletion, production will
once again begin to decline.





Oil and Natural Gas
Pricing





Financial
results depend upon many factors, particularly the price of oil and natural gas
and the Partnership’s ability to market its production
effectively.  Oil and natural gas prices are among the most volatile
of all commodity prices.  These price variations have a material
impact on the Partnership’s financial results.  Oil and natural gas
prices also vary by region and locality, depending upon the distance to markets,
and the supply and demand relationships in that region or
locality.  This can be especially true in the Rocky Mountain
Region.  The combination of increased drilling activity and the lack
of local markets have resulted in a local market oversupply situation from time
to time.  Like most producers in the region, the Partnership relies on
major interstate pipeline companies to construct these pipelines to increase
capacity, rendering the timing and availability of these facilities and
transportation capacity beyond the Partnership’s control.





The price
the Partnership receives for the natural gas produced in the Rocky Mountain
Region is based on a variety of prices, which primarily includes natural gas
sold at CIG prices with a portion sold at Mid-Continent, San Juan Basin,
Southern California or other nearby region prices.  The CIG Index, and
other indices for production delivered to other Rocky Mountain pipelines, has
historically been less than the price received for natural gas produced in the
eastern regions, which is NYMEX based.  Since March 31, 2009, this
negative differential has narrowed in recent months and has even more recently
become a positive differential.  CIG was $1.79 lower than NYMEX in
January 2009, narrowed to close at $0.37 lower in October 2009 and has more
recently closed at $0.02 higher than NYMEX for November 2009.





Oil and Gas Price Risk
Management, Net





The
Managing General Partner uses oil and natural gas derivative instruments to
manage price risk for PDC as well as its sponsored drilling
partnerships.  The Managing General Partner sets these instruments for
PDC, and the various partnerships managed by PDC.  Prior to September
30, 2008, as volumes produced changed, the mix between PDC and the partnerships
changed on a pro-rata basis.  Effective September 30, 2008, PDC
changed the allocation procedure whereby the allocation of the derivative
positions between PDC and each partnership was set at a fixed
quantity.  Existing positions are allocated based on fixed quantities
for each position and new positions will have specific designations relative to
the applicable partnership.


- 17 -
 Index





PDC
2004-B LIMITED PARTNERSHIP


(A
West Virginia Limited Partnership)




The
following table presents the primary composition of “Oil and gas price risk
management loss, net” for the periods described:





Three
      months ended June 30,
            
            
            Six
      months ended June 30,Oil
      and gas price risk management, net
            
            2009
            
            
            2008
            
            
            2009
            
            
            2008Realized
      gains (losses)Oil
            
            $
            43,108
            
            
            $
            (45,232
            )
            
            $
            108,535
            
            
            $
            (56,117
            )Natural
      Gas
            
            
            240,333
            
            
            
            (237,628
            )
            
            
            599,636
            
            
            
            (261,638
            )Total
      realized gain (loss), net
            
            
            283,441
            
            
            
            (282,860
            )
            
            
            708,171
            
            
            
            (317,755
            )Unrealized
      gains (losses)Reclassification
      of realized (gains) losses included in prior periods
      unrealized
            
            (302,139
            )
            
            
            113,977
            
            
            
            (556,781
            )
            
            
            28,199Unrealized
      loss for the period
            
            
            (349,416
            )
            
            
            (680,670
            )
            
            
            (570,334
            )
            
            
            (958,823
            )Total
      unrealized loss, net
            
            
            (651,555
            )
            
            
            (566,693
            )
            
            
            (1,127,115
            )
            
            
            (930,624
            )Oil
      and gas price risk management loss, net
            
            $
            (368,114
            )
            
            $
            (849,553
            )
            
            $
            (418,944
            )
            
            $
            (1,248,379
            )





Realized
gains recognized in the current year three and six month periods, are a result
of lower oil and gas commodity prices at settlement date compared to the
respective contract price.  During the current year three month period, the
Partnership recorded unrealized derivative losses of $0.1 million on the
Partnership’s oil swaps as the forward strip price of oil increased during the
quarter, along with unrealized losses on the Partnership’s CIG basis swaps of
$0.2 million, as the forward basis differential between NYMEX and CIG has
continued to narrow.   During the current year six month period,
the Partnership recorded unrealized derivative losses of $0.1 million on its oil
swaps and $0.6 million on its CIG basis swaps due to the narrowing of the
negative differential between NYMEX and CIG basis, as previously
discussed.  These decreases were offset in part by unrealized gains on
the Partnership’s natural gas collars of $0.2 million.





Oil and
gas price risk management, net includes realized gains and losses and unrealized
changes in the fair value of derivative instruments related to the Partnership’s
oil and natural gas production.  See Note 4, Fair Value Measurements and
Note 5, Derivative Financial
Instruments, to the accompanying unaudited condensed financial statements
for additional details of the Partnership’s derivative financial
instruments.





Oil and Natural Gas Sales Derivative
Instruments.  The Managing General Partner uses various
derivative instruments to manage fluctuations in oil and natural gas
prices.  The Partnership has in place a series of collars, fixed price
swaps and basis protection swaps on a portion of the Partnership’s oil and
natural gas production as set forth in the following table.


- 18 -
 Index


PDC
2004-B LIMITED PARTNERSHIP
 (A
West Virginia Limited Partnership)


This
table identifies the Partnership’s derivative positions related to oil and gas
sales activities in effect as of September 30, 2009, on the Partnership’s
production.  The Partnership’s production volumes for the three months
ended June 30, 2009, were 2,515 Bbls of oil and 87,440 Mcf of natural
gas.





Collars
            
            
            Fixed-Price
      Swaps
            
            
            Basis
      Protection SwapsFloors
            
            
            CeilingsWeighted
            
            
            
            
            
            Weighted
            
            
            
            
            
            Weighted
            
            
            
            
            
            Weighted
            
            
            Fair
      ValueCommodity/
            
            
            Quantity
            
            
            Average
            
            
            Quantity
            
            
            Average
            
            
            Quantity
            
            
            Average
            
            
            Quantity
            
            
            Average
            
            
            AtOperating
      Area/
            
            
            (Gas-MMbtu
            
            
            Contract
            
            
            (Gas-MMbtu
            
            
            Contract
            
            
            (Gas-MMbtu
            
            
            Contract
            
            
            (Gas-MMbtu
            
            
            Contract
            
            
            September
      30,Index
            
            
            Oil-Bbls)
            
            
            Price
            
            
            Oil-Bbls)
            
            
            Price
            
            
            Oil-Bbls)
            
            
            Price
            
            
            Oil-Bbls)
            
            
            Price
            
            
            2009(1)Natural
      GasRocky
      Mountain RegionCIG4Q
      2009
            
            
            
            53,257
            
            
            $
            6.67
            
            
            
            53,257
            
            
            $
            8.16
            
            
            
            19,688
            
            
            $
            9.20
            
            
            
            -
            
            
            $
            -
            
            
            $
            216,4042010
            
            
            
            61,365
            
            
            
            6.63
            
            
            
            61,365
            
            
            
            8.11
            
            
            
            29,532
            
            
            
            9.20
            
            
            
            181,047
            
            
            
            1.88
            
            
            
            (35,508
            )2011
            
            
            
            28,989
            
            
            
            4.75
            
            
            
            28,989
            
            
            
            9.45
            
            
            
            -
            
            
            
            -
            
            
            
            215,685
            
            
            
            1.88
            
            
            
            (237,892
            )2012
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            227,947
            
            
            
            1.88
            
            
            
            (235,262
            )2013
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            211,753
            
            
            
            1.88
            
            
            
            (202,882
            )NYMEX2010
            
            
            
            7,747
            
            
            
            5.75
            
            
            
            7,747
            
            
            
            8.30
            
            
            
            160,968
            
            
            
            5.62
            
            
            
            -
            
            
            
            -
            
            
            
            (85,279
            )2011
            
            
            
            10,536
            
            
            
            5.75
            
            
            
            10,536
            
            
            
            8.30
            
            
            
            58,166
            
            
            
            6.96
            
            
            
            -
            
            
            
            -
            
            
            
            1,4342012
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            61,041
            
            
            
            6.96
            
            
            
            -
            
            
            
            -
            
            
            
            (2,708
            )Total
      Natural Gas
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            (581,693
            )OilRocky
      Mountain RegionNYMEX4Q
      2009
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            1,411
            
            
            
            90.51
            
            
            
            -
            
            
            
            -
            
            
            
            27,4122010
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            4,904
            
            
            
            92.96
            
            
            
            -
            
            
            
            -
            
            
            
            90,3522011
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            2,822
            
            
            
            70.75
            
            
            
            -
            
            
            
            -
            
            
            
            (18,294
            )Total
      Oil
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            99,470Total
      Natural Gas and Oil
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            $
            (482,223
            )





(1)
Approximately 83% of the total fair value of the derivative instruments was
measured using significant unobserved inputs (Level 3 assets and liabilities).
See Note 4, Fair Value
Measurements, to the accompanying interim unaudited condensed financial
statements.





During
late October 2009, the Managing General Partner entered into additional NYMEX
fixed-price gas swaps (ranging from $6.67 to $7.11 per MMbtu) and NYMEX gas
collars (floors ranging from $6.00 to $6.10 and ceilings ranging from $8.27 to
$8.60 per MMbtu) covering all monthly periods from November 2010 to December
2013. The Partnership will be allocated positions by the Managing General
Partner for MMbtu’s equal to the number of remaining MMbtu’s of CIG basis
protection swaps at September 30, 2009 which were not previously covered by
NYMEX fixed-price gas swaps or gas collars.





Production and Operating
Costs





Generally,
production and operating costs vary either with total oil and natural gas sales
or production volumes.  Property and severance taxes are estimated by
the Managing General Partner based on rates determined using historical
information.  These amounts are subject to revision based on actual
amounts determined during future filings by the Managing General Partner with
the taxing authorities.  Property and severance taxes vary directly
with total oil and natural gas sales.  Transportation costs vary
directly with production volumes.  Fixed monthly well operating costs
increase on a per unit basis as production decreases per the historical decline
curve.  General oil field services and all other costs vary and can
fluctuate based on services required.  These costs include water
hauling and disposal, equipment repairs and maintenance, snow removal and
service rig workovers.





For the
six months ended June 30, 2009 compared to the same period in 2008, oil and
natural gas production, on an energy equivalency-basis, decreased 29%, due to
reduced production resulting from the Wattenberg Field’s high pipeline pressure
in addition to normally-occurring production declines throughout an oil and
natural gas well’s production life cycle.  Production and operating
costs were lower by $0.2 million, or 46%, due to volume-associated reductions of
$0.1 million in production taxes, natural gas transport and lease operating
expenses.  In addition to volume-associated production tax decreases,
lower commodity valuations further reduced production taxes by approximately
$0.1 million.  Production and operating costs per Mcfe were $1.31 for
the six months ended June 30 of 2009 compared to $1.71 for the comparable period
in 2008.




- 19 -
 Index


PDC
2004-B LIMITED PARTNERSHIP
 (A
West Virginia Limited Partnership)


For the
three months ended June 30, 2009, compared to the same period in 2008, oil and
natural gas production declined 35% which reduced volume-associated expenditures
by $0.1 million.  Along with reduced volume-associated expenditures, a
decrease of approximately $0.1 million in production-related taxes due to lower
commodity valuations, decreased overall production and operating costs by $0.2
million.  Production and operating costs per Mcfe were $1.37 and $1.87
for the three month period ended June 30, 2009 and 2008,
respectively.





Direct Costs−General and
Administrative





Direct
costs – general and administrative consist primarily of professional fees for
financial statement audits, income tax return preparation and legal
matters.  Direct costs increased during the three and six months ended
June 30, 2009, compared to the same period in 2008, by approximately $0.1
million and $0.2 million, respectively, primarily due to an increase in
professional fees for audit services principally to complete prior years’
audits.





Depreciation, Depletion and
Amortization





Depreciation,
depletion and amortization (DD&A) expense results solely from the
depreciation, depletion and amortization of well equipment and lease costs. The
calculation of DD&A expense is directly related to reserves and production
volumes.  DD&A expense is primarily based upon year-end proved
developed producing oil and gas reserves.  These reserves are valued
at the price of oil and natural gas as of December 31 each year.  If
prices increase, the estimated volume of oil and gas reserves may increase,
resulting in a decrease in the rate of DD&A expense per unit of
production.  If prices decrease, as prices did from December 31, 2007
to December 31, 2008, the estimated volumes of oil and gas reserves may decrease
resulting in an increase in the rate of DD&A expense per unit of
production.





The
DD&A rate per Mcfe increased to $3.39 and $3.47 for the three and six month
periods ended June 30, 2009, respectively, compared to the DD&A per Mcfe
rate of $2.49 and $2.57 during the same periods ended June 30,
2008.  The variances in the per Mcfe rates for the three month
periods in each year compared to the corresponding six month periods in each
year are primarily the result of the changing production mix between the
Partnership’s Wattenberg and Grand Valley fields which have significantly
different DD&A rates.  These increased rates, offset by lower
production volumes, resulted in decreases of approximately $47,000 and $28,000,
respectively, in DD&A expense for the three and six months ended June 30,
2009 compared to same periods in 2008.  This is primarily the result
of production level decreases of 35% and 29%, respectively, for the three and
six month periods ended June 30, 2009, which were offset by increases in per
Mcfe expense due to lower proved developed reserves at December 31, 2008
compared to December 31, 2007.  While production and overall year-end
reserves are expected to decline gradually year-to-year over the wells’
remaining life cycles, downward revisions to oil and natural gas proved
developed reserves in the annual 2008 reserve report, resulted in the increased
DD&A unit cost increases during the three and six month periods ended June
30, 2009 as compared to the same periods in 2008.





Interest
Income





Significantly
lower interest rates applied to undistributed revenues held by the Managing
General Partner, resulted in lower interest income during the six months ended
June 30, 2009, compared to the same periods in 2008.  For the three
months ended June 30, 2009 and 2008, respectively, interest income declined due
to both lower undistributed revenues held by the Managing General Partner and
significantly lower interest rates applied to those amounts, during the
comparable periods.





Liquidity and Capital
Resources





Oil and
natural gas production from the Partnership’s existing properties, which
commenced in fourth quarter 2004 and peaked during the second quarter 2005,
declined rapidly through 2006.  During 2007, 2008 and through
September of 2009 oil and natural gas production declined
gradually.  Production is expected to continue to decline gradually
over the remaining lives of the wells.  Therefore, the Partnership may
be unable to maintain its current level of oil and gas production and cash flows
from operations if commodity prices remain in their current depressed state for
a prolonged period beyond 2009.  This decreased production would have
a material negative impact on the Partnership’s operations and may result in
reduced cash distributions to the Investor Partners in 2010 and
beyond.




- 20 -
 Index


PDC
2004-B LIMITED PARTNERSHIP
 (A
West Virginia Limited Partnership)




Working
Capital





Working
capital at June 30, 2009 was $1.5 million compared to working capital of $2.2
million at December 31, 2008.  This decrease of $0.7 million was
primarily due to a decrease in receivables from oil and gas sales at June 30,
2009 to $0.3 million as compared to $0.4 million at December 31,
2008.  In addition, the receivables at June 30, 2009 for realized and
short-term net unrealized derivative gains decreased to $0.3 million and $0.7
million, respectively, from the amounts at December 31, 2008 of $0.4 million and
$1.0 million, respectively.





Cash
Flows From Investing Activities





The
Partnership received an approximately $9,000 refund from the Managing General
Partner during the six month period ended June 30, 2009, for estimated capital
expenditures previously charged for oil and gas properties which the Managing
General Partner subsequently determined were not applicable to the
Partnership.





Cash
Flows From Financing Activities





The
Partnership initiated monthly cash distributions to investors in February 2005
and has distributed $18.4 million through June 30, 2009.  The table
below sets forth the cash distributions to the Managing General Partner and
Investor Partners including Managing General Partner distribution relating to
limited partnership units repurchased for the periods described as
follows:





Three
      months ended June 30,2009
                
                
                2008Managing
                  General
      Partner
                  Distributions
                
                
                Investor
                  Partners
                  Distributions
                
                
                Total
                  Distributions
                
                
                Managing
                  General
      Partner
                  Distributions
                
                
                Investor
                  Partners
                  Distributions
                
                
                Total
                  Distributions$
                158,734
                
                
                $
                634,936
                
                
                $
                793,670
                
                
                $
                148,380
                
                
                $
                593,522
                
                
                $
                741,902
 
 
 Six
      months ended June 30,2009
                
                
                2008Managing
                  General
      Partner
                  Distributions
                
                
                Investor
                  Partners
                  Distributions
                
                
                Total
                  Distributions
                
                
                Managing
                  General
      Partner
                  Distributions
                
                
                Investor
                  Partners
                  Distributions
                
                
                Total
                  Distributions$
                259,165
                
                
                $
                1,036,663
                
                
                $
                1,295,828
                
                
                $
                246,954
                
                
                $
                987,821
                
                
                $
                1,234,775


Investor
Partner cash distributions include $12,008 and $17,359 during the three and six
months ended June 30, 2009, respectively, and $5,076 and $8,087 during the three
and six months ended June 30, 2008, respectively, related to equity cash
distributions on Investor Partner units repurchased by the Managing General
Partner.





Cash
Flows From Operating Activities





The
Partnership’s operations are expected to be conducted with available funds and
revenues generated from its oil and natural gas production
activities.  Changes in cash flow from operations are largely due to
the same factors that affect the Partnership’s net income that are more fully
discussed under Results of
Operations, excluding the non-cash items depreciation, depletion and
amortization and unrealized gains and losses on derivative
transactions.  Based on current oil and natural gas prices and prices
set by derivatives, and the Partnership’s anticipated production, the
Partnership expects positive cash flows from operations for the remainder of
2009.





- 21 -
 Index


PDC
2004-B LIMITED PARTNERSHIP
 (A
West Virginia Limited Partnership)


Changes
in market prices for oil and natural gas, the Partnership’s production levels,
impact of realized gains and losses on the Partnership’s oil and natural gas
derivative instruments and changes in costs are the principal determinants of
the level of the Partnership cash flow from operations.  Oil and
natural gas sales for the six months ended June 30, 2009 were approximately 73%
lower than the same period in the prior year, resulting from a 62% decrease in
average oil and natural gas prices and a 29% decrease in oil and natural gas
production.  While a decline in oil and natural gas prices would
affect the amount of cash from operations that could be generated, the
Partnership has oil and natural gas derivative positions in place, as of the
date of this filing covering 71% of the Partnership’s expected oil production
and 78% of its expected natural gas production for the remainder of 2009, at
average prices of $90.51 per Bbl and $7.35 per Mcf,
respectively.  These contracts reduce the impact of price changes on
cash provided by operations for a substantial portion of the `expected
production for the remainder of 2009.  However, the remaining 29% and
22% of estimated remaining 2009 oil and natural gas production, respectively, is
not subject to the Partnership’s derivative instrument risk management;
consequently, associated revenues will be directly impacted by changing
commodity market prices.





The value
of the Partnership’s current derivatives positions could change based on changes
in oil and natural gas futures markets, the investors’ view of underlying oil
and natural gas supply and demand trends and changes in volumes
produced.  Partnership oil and natural gas derivatives as of June 30,
2009 are detailed in Note 5, Derivative Financial
Instruments to the accompanying interim unaudited condensed financial
statements.





Net cash
provided by operating activities was $1.3 million for the six months ended June
30, 2009 compared to $1.2 million during the same period in 2008, an increase of
$0.1 million.  Variances between the two periods in cash provided by
operating activities were due primarily to the following:




·
            An
      increase in realized oil and gas price risk management, net of $1.0
      million; a decrease in production and operating cost of $0.2 million; and
      a decrease in accounts receivable collections of $0.9;
  and





·
            A
      decrease in oil and gas sale revenues of $1.8 million, accompanied by an
      increase in direct costs – general and administrative of $0.2
      million.





Information
related to the oil and gas reserves of the Partnership’s wells is discussed in
detail in the Partnership’s Annual Report on Form 10-K Supplemental Oil and Gas
Information−Unaudited, Net
Proved Oil and Gas ReservesandInformation and Standardized Measure of Discounted
Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas
Reserves.





Partnership
well recompletions in the Codell formation of Wattenberg Field wells, which may
provide for additional reserve development and production, generally occur five
to seven years after initial well drilling so that well resources are optimally
utilized.  These well recompletions would be expected to occur based
on a favorable general economic environment and commodity price
structure.  Since borrowing is not permitted by the Limited
Partnership Agreement, well recompletion activities will be funded through the
retention of revenues and reduction of Partner cash
distributions.  There are no immediate plans to initiate recompletion
activities in the Wattenberg Field wells owned by the Partnership.  As
the optimal period approaches, the Managing General Partner will re-evaluate the
feasibility of commencing those recompletions based on engineering data and a
favorable commodity price environment in order to maximize the financial benefit
of the recompletion.  However, no assurances can be given that
recompletion activities will be feasible or economic.





Commitments and
Contingencies





See Note
6, Commitments and
Contingencies, to the accompanying unaudited condensed financial
statements.





Recent Accounting
Standards





See Note
2, Recent Accounting
Standards to the accompanying unaudited condensed financial statements,
included in this report for recent accounting standards.




- 22 -
 Index


PDC
2004-B LIMITED PARTNERSHIP
 (A
West Virginia Limited Partnership)
  Critical Accounting Policies
and Estimates





The
preparation of the accompanying unaudited condensed financial statements, in
conformity with accounting principles generally accepted in the United States of
America, requires management to use judgment in making estimates and assumptions
that affect the reported amounts of assets and liabilities, disclosure of
contingent assets and liabilities and the reported amounts of revenue and
expenses.





The
Partnership believes that the Partnership’s accounting policies for revenue
recognition, derivatives instruments, fair value measurements, oil and natural
gas properties, and asset retirement obligations are based on, among other
things, judgments and assumptions made by management that include inherent risks
and uncertainties.  There have been no significant changes to these
policies or in the underlying accounting assumptions and estimates used in these
critical accounting policies from those disclosed in the financial statements
and accompanying notes contained in the Partnership’s Form 10-K for the year
ended December 31, 2008.








Item 3. Quantitative
and Qualitative Disclosures About Market Risk





Not
Applicable








Item 4T. Controls
and Procedures





The
Partnership has no direct management or officers.  The management,
officers and other employees that provide services on behalf of the Partnership
are employed by the Managing General Partner.





2008 Material
Weakness





As
discussed in the Management’s
Report on Internal Control Over Financial Reporting included in the
Partnership’s 2008 Annual Report on Form 10-K, the Partnership did not maintain
effective internal controls over financial reporting as of December 31, 2008,
over transactions that are directly related to and processed by the Partnership,
in that the Partnership failed to maintain sufficient documentation to
adequately assess the operating effectiveness of internal control over financial
reporting.  More specifically, the Partnership’s financial close and
reporting narrative failed to adequately describe the process, identify key
controls and assess segregation of duties.  This material weakness has
not been remediated as of June 30, 2009.  The 2008 Annual Report on
Form 10-K did not include an attestation report of the Partnership’s independent
registered public accounting firm regarding internal control over financial
reporting pursuant to Item 308T (a)(4) of Regulation
S-K.      Pursuant to Final Order dated October
19, 2009, temporary Item 308T was extended through December 15,
2010.  Accordingly, the Partnership will file the attestation report
of the Partnership’s independent registered public accounting firm regarding
internal control with the Partnership’s Annual Report on Form 10-K as of
December 31, 2010.








(a)  Evaluation of Disclosure
Controls and Procedures





As of
June 30, 2009, PDC, as Managing General Partner on behalf of the Partnership,
carried out an evaluation, under the supervision and with the participation of
the Managing General Partner's management, including its Chief Executive Officer
and Chief Financial Officer, of the effectiveness of the design and operation of
the Partnership's disclosure controls and procedures pursuant to Exchange Act
Rules 13a-15(e) and 15d-15(e).  This evaluation considered the various
processes carried out under the direction of the Managing General Partner’s
Disclosure Committee in an effort to ensure that information required to be
disclosed in the SEC reports the Partnership files or submits under the Exchange
Act is recorded, processed, summarized and reported, within the time periods
specified in the SEC’s rules and forms, and that such information is accumulated
and communicated to the Partnership’s management, including its principal
executive and principal financial officers, as appropriate to allow timely
decisions regarding required disclosure.





- 23 -
 Index


PDC
2004-B LIMITED PARTNERSHIP
 (A
West Virginia Limited Partnership)





Based
upon that evaluation, the Managing General Partner’s Chief Executive Officer and
Chief Financial Officer concluded that the Partnership’s disclosure controls and
procedures were not effective as of June 30, 2009 due to the existence of the
material weakness described above in 2008 Material Weakness
included in this Item 4 (T).  Because of the nature of the material
weakness noted, the Partnership is not able to quantify the dollar amounts of
exposure or potential range of the dollar amount of potential revisions to the
financial statements, from this material weakness.





(b)  Remediation of Material
Weakness in Internal Control





PDC, the
Managing General Partner, with participation from the Audit Committee of its
Board of Directors, has been addressing the material weakness disclosed in the
Partnership’s 2008 Annual Report on Form 10-K.  The Managing General
Partner believes that with effective implementation of planned changes in
internal controls over financial reporting outlined below, that it will be able
to remediate this known material weakness as of December 31,
2009.  However, this control weakness will not be considered
remediated until the changes in internal controls over financial reporting are
operating effectively for a sufficient period of time and the Managing General
Partner has concluded, through testing, that these controls are operating
effectively.





The
Partnership made no changes in its internal control over financial reporting
(such as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act
of 1934) during the quarter ended June 30, 2009.





The
Partnership has developed a plan to improve controls over certain key financial
statement spreadsheets that support all significant balance sheet and income
statement accounts.  The Partnership also created and documented a
procedural framework to ensure the completeness and accuracy of the
Partnership’s derivative activities with implementation planned for the second
half of 2009.  Additionally, the Partnership has completed the
development of a revised financial close and reporting narrative that adequately
describes the process, identifies key controls and assesses segregation of
duties.  This narrative was implemented during July and August of 2009
and the controls and procedures are currently being tested.  Testing
is expected to be completed by December 31, 2009.  At present, the
Partnership has not quantified the total cost of this initiative; however the
majority of this cost is expected to be paid by the Managing General
Partner.





Until
PDC, the Managing General Partner, is able to conclude that the Partnership has
remediated this known material weakness in internal control over financial
reporting, the Managing General Partner will continue to perform additional
analysis and procedures in order to ensure that the Partnership’s financial
statements contained in its subsequent SEC filings are prepared in accordance
with generally accepted accounting principles in the United States.





The
Managing General Partner continues to evaluate the ongoing effectiveness and
sustainability of these planned changes in internal control over financial
reporting, and, as a result of the ongoing evaluation, may identify additional
changes to improve internal control over financial reporting.  Further
information regarding the material weakness of the Partnership referenced above
may be found in the Partnership’s Annual Report on 10-K for the year ended
December 31, 2008 under Item 9A (T), Controls and Procedures −
Management’s Report on
Internal Control Over Financial Reporting.


- 24 -
 Index




PDC
2004-B LIMITED PARTNERSHIP
 (A
West Virginia Limited Partnership)




PART
II – OTHER INFORMATION





Item 1. Legal
Proceedings





Information
regarding the Registrant’s legal proceedings can be found in Note 6, Commitments and
Contingencies, to the Partnership’s accompanying unaudited condensed
financial statements.








Item 1A. Risk
Factors





Not
Applicable








Item 2. Unregistered
Sales of Equity Securities and Use of Proceeds





Unit Repurchase
Program:  Beginning February 2008, the third anniversary of the
date of the first Partnership cash distributions, Investor Partners of the
Partnership may request that the Managing General Partner repurchase their
respective individual Investor Partner units, up to an aggregate total limit
during any calendar year for all requesting Investor Partner unit repurchases of
10% of the initial subscription units.





Second
quarter 2009 unit repurchases were 4.25 units repurchased at an average price of
$10,794 per unit during April. There were no unit repurchases during May or
June, 2009.





Other
Repurchases:  Individual investor partners periodically offered
and PDC repurchased, units on a negotiated basis before the third anniversary of
the date of the first cash distribution.








Items 3, 4 and 5 have been omitted as there is nothing to
report.


- 25 -
 Index




PDC
2004-B LIMITED PARTNERSHIP
 (A
West Virginia Limited Partnership)




Item 6. Exhibits





(a)       Exhibit
Index.


Incorporated
      by ReferenceExhibit
      Number
            
            Exhibit
      Description
            
            Form
            
            SEC File
              Number
            
            Exhibit
            
            Filing
      Date
            
            Filed
              Herewith3.1
            
            Limited
      Partnership Agreement
            
            10-K
            
            000-51219
            
            3.1
            
            08/05/20093.2
            
            Certificate
      of limited partnership which reflects the organization of the Partnership
      under West Virginia law
            
            10-K
            
            000-51219
            
            3.2
            
            08/05/200910.1
            
            Drilling
      and operating agreement between the Partnership and PDC, as Managing
      General Partner of the Partnership
            
            10-K
            
            000-51219
            
            10.1
            
            08/05/200931.1
            
            Rule
      13a-14(a)/15d-14(c) Certification of Chief Executive Officer of Petroleum
      Development Corporation, the Managing General Partner of the Partnership
      as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of
      2002.
            
            
            
            
            
            
            
            
            
            X31.2
            
            Rule
      13a-14(a)/15d-14(c) Certification of Chief Financial Officer of Petroleum
      Development Corporation, the Managing General Partner of the Partnership
      as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of
      2002.
            
            
            
            
            
            
            
            
            
            X32.1
            
            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
      Partnership.
            
            
            
            
            
            
            
            
            
            X


- 26 -
 Index





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
2004-B Limited Partnership


By its
Managing General Partner


Petroleum
Development Corporation





By:
      /s/ Richard W. McCulloughRichard
      W. McCullough
              Chairman
      and Chief Executive Officer
              December
      18, 2009





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/
      Richard W. McCullough
            
            Chairman
      and Chief Executive Officer
            
            December
      18, 2009Richard
      W. McCullough
            
            Petroleum
      Development CorporationManaging
      General Partner of the Registrant(Principal
      executive officer)/s/
      Gysle R. Shellum
            
            Chief
      Financial Officer
            
            December
      18, 2009Gysle
      R. Shellum
            
            Petroleum
      Development CorporationManaging
      General Partner of the Registrant(Principal
      financial officer)/s/
      R. Scott Meyers
            
            Chief
      Accounting Officer
            
            December
      18, 2009R.
      Scott Meyers
            
            Petroleum
      Development CorporationManaging
      General Partner of the Registrant(Principal
      accounting officer)





- 27 -