UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


WASHINGTON,
DC 20549





FORM
10-Q





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





For
the quarterly period ended March 31, 2009


or





£ TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD ____________ TO ____________





Commission
File Number   000-51218





PDC
2004-A Limited Partnership


(Exact
name of registrant as specified in its charter)





West Virginia
            20-0545296(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 £   No   T





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 £    No
£





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     £
            Accelerated
      filer     £Non-accelerated
      filer     £
            Smaller
      reporting company     T





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





As of
August 31, 2009 the Partnership had 1,451.54 units of limited partnership
interest and no units of additional general partnership interest
outstanding.










PDC
2004-A 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
            22Item
      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





Item1.
            Condensed
      Financial Statements (unaudited)





PDC 2004-A Limited Partnership


Condensed
Balance Sheets


(unaudited)





March 31,
            
            
            December 31,2009
            
            
            2008*AssetsCurrent
      assets:Cash
      and cash equivalents
            
            $
            157,918
            
            
            $
            156,423Accounts
      receivable
            
            
            133,427
            
            
            
            235,980Oil
      inventory
            
            
            36,827
            
            
            
            34,071Due
      from Managing General Partner-derivatives
            
            
            1,675,509
            
            
            
            1,425,088Due
      from Managing General Partner-other, net
            
            
            1,645,496
            
            
            
            1,547,149Total
      current assets
            
            
            3,649,177
            
            
            
            3,398,711Oil
      and gas properties, successful efforts method, at cost
            
            
            32,225,963
            
            
            
            32,224,807Less:  Accumulated
      depreciation, depletion and amortization
            
            
            (13,847,746
            )
            
            
            (13,383,328
            )Oil
      and gas properties, net
            
            
            18,378,217
            
            
            
            18,841,479Due
      from Managing General Partner-derivatives
            
            
            210,143
            
            
            
            490,059Other
      assets
            
            
            22,330
            
            
            
            17,186Total
      noncurrent assets
            
            
            18,610,690
            
            
            
            19,348,724Total
      Assets
            
            $
            22,259,867
            
            
            $
            22,747,435Liabilities and Partners'
      EquityCurrent
      liabilities:Accounts
      payable and accrued expenses
            
            $
            25,428
            
            
            $
            58,234Total
      current liabilities
            
            
            25,428
            
            
            
            58,234Due
      to Managing General Partner-derivatives
            
            
            766,973
            
            
            
            134,319Asset
      retirement obligations
            
            
            232,621
            
            
            
            229,324Total
      liabilities
            
            
            1,025,022
            
            
            
            421,877Commitments
      and contingenciesPartners'
      equity:Managing
      General Partner
            
            
            4,252,811
            
            
            
            4,470,953Limited
      Partners - 1,451.54 units issued and outstanding
            
            
            16,982,034
            
            
            
            17,854,605Total
      Partners' equity
            
            
            21,234,845
            
            
            
            22,325,558Total
      Liabilities and Partners' Equity
            
            $
            22,259,867
            
            
            $
            22,747,435





*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-A Limited Partnership


Condensed
Statements of Operations


(unaudited)





Three months ended
      March 31,2009
            
            
            2008Revenues:Oil
      and gas sales
            
            $
            452,659
            
            
            $
            1,142,259Oil
      and gas price risk management loss, net
            
            
            (62,035
            )
            
            
            (385,788
            )Total
      revenues
            
            
            390,624
            
            
            
            756,471Operating
      costs and expenses:Production
      and operating costs
            
            
            158,816
            
            
            
            266,382Direct
      costs - general and administrative
            
            
            67,870
            
            
            
            12,560Depreciation,
      depletion and amortization
            
            
            464,418
            
            
            
            390,227Accretion
      of asset retirement obligations
            
            
            3,297
            
            
            
            3,117Total
      operating costs and expenses
            
            
            694,401
            
            
            
            672,286(Loss)
      income from operations
            
            
            (303,777
            )
            
            
            84,185Interest
      income
            
            
            13,130
            
            
            
            18,217Net
      (loss) income
            
            $
            (290,647
            )
            
            $
            102,402Net
      (loss) income allocated to partners
            
            $
            (290,647
            )
            
            $
            102,402Less:  Managing
      General Partner interest in net (loss) income
            
            
            (58,129
            )
            
            
            20,480Net
      (loss) income allocated to Investor Partners
            
            $
            (232,518
            )
            
            $
            81,922Net
      (loss) income per Investor Partner unit
            
            $
            (160
            )
            
            $
            56Investor
      Partner units outstanding
            
            
            1,451.54
            
            
            
            1,451.54





See
accompanying notes to unaudited condensed financial statements.


- 2
-
 Index


PDC2004-A Limited Partnership


Condensed
Statements of Cash Flows


(unaudited)





Three months ended
      March 31,2009
            
            
            2008Cash
      flows from operating activities:Net
      (loss) income
            
            $
            (290,647
            )
            
            $
            102,402Adjustments
      to reconcile net (loss) income to net cash provided by operating
      activities:Depreciation,
      depletion and amortization
            
            
            464,418
            
            
            
            390,227Accretion
      of asset retirement obligations
            
            
            3,297
            
            
            
            3,117Unrealized
      loss on derivative transactions
            
            
            662,149
            
            
            
            342,899Changes
      in operating assets and liabilities:Decrease
      (increase) in accounts receivable
            
            
            102,553
            
            
            
            (71,789
            )Increase
      in oil inventory
            
            
            (2,756
            )
            
            
            (45,728
            )Increase
      in other assets
            
            
            (5,144
            )
            
            
            (1,755
            )(Decrease)
      increase in accounts payable and accrued expenses
            
            
            (32,806
            )
            
            
            60,050Increase
      in due from Managing General Partner - other, net
            
            
            (98,347
            )
            
            
            (210,879
            )Net
      cash provided by operating activities
            
            
            802,717
            
            
            
            568,544Cash
      flows from investing activities:Capital
      expenditures for oil and gas properties
            
            
            (1,156
            )
            
            
            8,229Net
      cash (used in) provided by investing activities
            
            
            (1,156
            )
            
            
            8,229Cash
      flows from financing activities:Distributions
      to Partners
            
            
            (800,066
            )
            
            
            (572,862
            )Net
      cash used in financing activities
            
            
            (800,066
            )
            
            
            (572,862
            )Net
      increase in cash and cash equivalents
            
            
            1,495
            
            
            
            3,911Cash
      and cash equivalents, beginning of period
            
            
            156,423
            
            
            
            70,053Cash
      and cash equivalents, end of period
            
            $
            157,918
            
            
            $
            73,964





See
accompanying notes to unaudited condensed financial statements.


- 3
-
 Index


PDC2004-A LIMITED PARTNERSHIP


NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS


March 31,
2009


(unaudited)





Note
1−General and Basis of
Presentation





The PDC
2004-A Limited Partnership (the “Partnership” or the “Registrant”) was organized
as a limited partnership on April 9, 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 its
sale of Partnership units on April 30, 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, it produces and sells
natural gas and oil.





Purchasers
of partnership units subscribed to and fully paid for 33.34 units of limited
partner interests and 1,418.20 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%
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 March 31, 2009, there were 1,163 Investor Partners.  As of March
31, 2009, the Managing General Partner has repurchased 45.31 units of the total
1,451.54 outstanding units of Partnership interests from Investor Partners at an
average price of $7,667 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, under the terms of the Drilling and Operating
Agreement (the “D&O Agreement”), actively manages and conducts the business
of the Partnership.  PDC has full authority under the D&O
Agreement to conduct 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 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 three months ended March
31, 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 August 7, 2009 (“the 2008 Form 10-K”).








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.


- 4
-
 Index


PDC
2004-A LIMITED PARTNERSHIP


NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS


March 31,
2009


(unaudited)





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.





Recently Issued Accounting
Standards





In
January 2009, the SEC published its final rule, Modernization of Oil and Gas
Reporting, 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.  The final rule also
permits voluntary disclosure of probable and possible reserves, a disclosure
previously prohibited by SEC rules.  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.


- 5
-
 Index


PDC
2004-A LIMITED PARTNERSHIP


NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS


March 31,
2009


(unaudited)





On April
9, 2009, the FASB issued the following amendments to the fair value measurement
and disclosure standards:





·
            FSP
      No. FAS 157-4, Determining Fair Value When
      the Volume and Level of Activity for the Asset or Liability Have
      Significantly Decreased and Identifying Transactions That Are Not
      Orderly (“FSP 157-4”)





·
            FSP
      No. FAS 107-1 and APB 28-1, Interim Disclosures about Fair
      Value of Financial Instruments (“FSP 107-1/APB
    28-1”)





FSP 157-4
affirms that the objective of fair value when the market for an asset is not
active is the price that would be received to sell the asset in an orderly
transaction; clarifies and includes additional factors for determining whether
there has been a significant decrease in market activity for an asset when the
market for that asset is not active; eliminates the proposed presumption that
all transactions are distressed (not orderly) unless proven otherwise and
instead requires an entity to base its conclusion about whether a transaction
was not orderly on the weight of the evidence; requires an entity to disclose a
change in valuation technique (and the related inputs) resulting from the
application of the FSP and to quantify its effects, if practicable; and applies
to all fair value measurements when appropriate.





FSP
107-1/APB 28-1 amends FAS No. 107, Disclosures about Fair Value of
Financial Instruments, to require an entity to provide disclosures about
fair value of financial instruments in interim financial
information.  This FSP also amends Accounting Principles Board (“APB”)
Opinion No. 28, Interim
Financial Reporting, to require those disclosures in summarized financial
information at interim reporting periods.  Pursuant to this FSP, a
reporting entity shall include disclosures about the fair value of our financial
instruments whenever it issues summarized financial information for interim
reporting periods.  In addition, an entity shall disclose in the body
or in the accompanying notes of its summarized financial information for interim
reporting periods and in its financial statements for annual reporting periods
the fair value of all financial instruments for which it is practicable to
estimate that value, whether recognized or not recognized in the statement of
financial position, as required by FAS No. 107.





Both FSP
157-4 and FSP 107-1/APB 28-1 are effective for interim and annual reporting
periods ending after June 15, 2009, with early adoption permitted for periods
ending after March 15, 2009.  However, early adoption is allowed only
if certain FSPs are early adopted together: an entity early adopting FSP 157-4
must also early adopt FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of
Other-Than-Temporary Impairments (“FSP 115-2/124-2”) and an entity early
adopting FSP 107-1/APB 28-1 must also elect to early adopt FSP 157-4 and FSP
115-2/124-4.  We do not expect these FSPs to have a significant impact
on the Partnership’s financial statements when adopted on April 1,
2009.





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 will adopt FAS No. 165 effective June 30, 2009.  The
adoption of FAS No. 165 is not expected to have a material impact on the
Partnership’s financial statements.





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.


- 6
-
 Index


PDC
2004-A LIMITED PARTNERSHIP


NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS


March 31,
2009


(unaudited)








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.








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 caption “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 $319,233 and $405,644 as of March 31,
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 $600,114 and
$524,635 as of March 31, 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.”


- 7
-
 Index


PDC
2004-A LIMITED PARTNERSHIP


NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS


March 31,
2009


(unaudited)





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
      March 31,2009
            
            
            2008Well
      operations and maintenance
            
            $
            103,690
            
            
            $
            137,425Gathering,
      compression and processing fees
            
            
            29,698
            
            
            
            26,518Direct
      costs - general and administrative
            
            
            67,870
            
            
            
            12,560Cash
      distributions*
            
            
            178,127
            
            
            
            124,050





*Cash
distributions include $18,114 and $9,478 during the three months ended March 31,
2009 and 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.





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 (“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-based and basis protection 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 March 31, 2009, no valuation
allowance has been 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-A LIMITED PARTNERSHIP


NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS


March 31,
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
            
            $
            -
            
            
            $
            1,915,147
            
            
            $
            1,915,147Total
      assets
            
            
            -
            
            
            
            1,915,147
            
            
            
            1,915,147Liabilities:Commodity
      based derivatives
            
            
            -
            
            
            
            -
            
            
            
            -Basis
      protection derivative contracts
            
            
            -
            
            
            
            (134,319
            )
            
            
            (134,319
            )Total
      liabilities
            
            
            -
            
            
            
            (134,319
            )
            
            
            (134,319
            )Net
      asset
            
            $
            -
            
            
            $
            1,780,828
            
            
            $
            1,780,828As
      of March 31, 2009Assets:Commodity
      based derivatives
            
            $
            -
            
            
            $
            1,885,652
            
            
            $
            1,885,652Total
      assets
            
            
            -
            
            
            
            1,885,652
            
            
            
            1,885,652Liabilities:Commodity
      based derivatives
            
            
            (52,687
            )
            
            $
            (2,447
            )
            
            
            (55,134
            )Basis
      protection derivative contracts
            
            
            -
            
            
            
            (711,839
            )
            
            
            (711,839
            )Total
      liabilities
            
            
            (52,687
            )
            
            
            (714,286
            )
            
            
            (766,973
            )Net
      (liability) asset
            
            $
            (52,687
            )
            
            $
            1,171,366
            
            
            $
            1,118,679


- 9
-
 Index


PDC
2004-A LIMITED PARTNERSHIP


NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS


March 31,
2009


(unaudited)





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





Three months endedMarch 31, 2009Fair
      value, net asset, as of December 31, 2008
            
            $
            1,780,828Changes
      in fair value included in Oil and gas price risk management,
      net
            
            
            (9,348
            )Settlements
            
            
            (600,114
            )Fair
      value, net asset, as of March 31, 2009
            
            $
            1,171,366Change
      in unrealized gains (losses) relating to assets (liabilities) still held
      as of March 31, 2009, included in statement of operations line
      item:Oil
      and gas price risk management, net
            
            $
            (111,490
            )





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 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 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 could result in a triggering
event and, therefore, a possible impairment of the Partnership’s oil and natural
gas properties.  If 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 three months ended March 31, 2009 and 2008, there were no triggering events;
therefore, no impairment of oil and gas properties was recognized.





The
Partnership accounts for asset retirement obligations by recording the estimated
fair value of the plugging and abandonment obligations when incurred, which is
when 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.  Over time, the liabilities
are accreted for the change in their 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.  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.


- 10
-
 Index


PDC
2004-A LIMITED PARTNERSHIP


NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS


March 31,
2009


(unaudited)





The
Partnership has elected not to designate any of the Partnership’s derivative
instruments as hedges.  Accordingly, the Partnership recognizes all
derivative instruments as either assets or liabilities on its balance sheets at
fair value.  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
June 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 784 MMbtu of natural gas and 14 MBbls of crude oil.





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.





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
March 31, 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 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 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-A LIMITED PARTNERSHIP


NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS


March 31,
2009


(unaudited)





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





Fair
      ValueAs ofBalance
      Sheet
            
            March 31,
            
            
            December 31,Derivative instruments not designted as
      hedge  (1):
            
            Line Item
            
            2009
            
            
            2008Derivative
      Assets:
            CurrentCommodity
      contracts
            
            Due
      from Managing General Partner-derivatives
            
            $
            1,675,509
            
            
            $
            1,425,088Non CurrentCommodity
      contracts
            
            Due
      from Managing General Partner-derivatives
            
            
            210,143
            
            
            
            490,059Total
      Derivative Assets
            
            
            
            $
            1,885,652
            
            
            $
            1,915,147Derivative
      Liabilities:
            Non CurrentCommodity
      contracts
            
            Due
      to Managing General Partner-derivatives
            
            
            (55,134
            )
            
            
            -Basis
      protection contracts
            
            Due
      to Managing General Partner-derivatives
            
            
            (711,839
            )
            
            
            (134,319
            )Total
      Derivative Liabilities
            
            
            
            $
            (766,973
            )
            
            $
            (134,319
            )





(1) As of
March 31, 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 ended March 31, 2009 and 2008.





Three months ended March
31,2009
            
            
            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)
            
            $
            495,526
            
            
            $
            104,588
            
            
            $
            600,114
            
            
            $
            56,868
            
            
            $
            (99,757
            )
            
            $
            (42,889
            )Unrealized
      losses
            
            
            (495,526
            )
            
            
            (166,623
            )
            
            
            (662,149
            )
            
            
            (56,868
            )
            
            
            (286,031
            )
            
            
            (342,899
            )Total
      oil and gas price risk management loss, net
            
            $
            -
            
            
            $
            (62,035
            )
            
            $
            (62,035
            )
            
            $
            -
            
            
            $
            (385,788
            )
            
            $
            (385,788
            )





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.








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 us
pursuant to leases.  The Managing General Partner removed 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 it relates to all wells operated by the Managing
General Partner, which includes a majority of the Partnership’s 26 wells in the
Wattenberg field.  The portion of the settlement relating to the
Partnership’s wells for all periods through March 31, 2009 that has been
expensed by the Partnership is approximately $177,000 including associated legal
costs of approximately $12,000.  This entire settlement of $168,637
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.


- 12
-
 Index


PDC
2004-A LIMITED PARTNERSHIP


NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS


March 31,
2009


(unaudited)





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 this fine, if any, are allocated among the eight users of
the road based upon their respective usage.  The Partnership has 11
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.  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.





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.  Nonperformance is not anticipated.  The Managing
General Partner has had no counterparty default losses.


- 13
-
 Index


PDC
2004-A 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-A
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 (“U.S.”)
      and the impact of the global
economy;


·
            the
      effect of natural gas and oil derivatives
  activities;


·
            availability
      and cost of capital and conditions in the capital markets;
    and


·
            losses
      possible from pending and/or future litigation and the costs incident
      thereto.





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 August 7, 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-A Limited Partnership engages in the development, production and sale of
oil and natural gas.  The Partnership began oil and gas operations in
April 2004 and currently operates 37 gross (32.5 net) wells located in the Rocky
Mountain Region in the state of Colorado.  Of the Partnership’s total
well count, 36 are producing and one well is shut-in, pending evaluation and
future recompletion planning.  The Partnership sells the produced
natural gas 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 fixed price
contracts or utilize derivatives, including collars, swaps or basis protection
swaps, in order to offset some or all of the 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 may
impact the Partnership's results.  In addition, both sales volumes and
prices tend to be affected by demand factors with a seasonal
component.


- 14
-
 Index


PDC
2004-A 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 months
ended March 31, 2009, or first quarter of 2009 and the three months ended March
31, 2008, or first quarter of 2008.





Summary
      of Operating ResultsThree months ended
      March 31,2009
            
            
            2008
            
            
            ChangeNumber
      of producing wells (end of period)
            
            
            36
            
            
            
            37
            
            
            
            -Production:  (1)Oil
      (Bbl)
            
            
            2,852
            
            
            
            4,095
            
            
            
            -30
            %Natural
      gas (Mcf)
            
            
            120,049
            
            
            
            116,715
            
            
            
            3
            %Natural
      gas equivalents (Mcfe)  (2)
            
            
            137,161
            
            
            
            141,285
            
            
            
            -3
            %Average
      Selling Price (excluding realized gain (loss) on
    derivatives)Oil
      (per Bbl)
            
            $
            35.93
            
            
            $
            82.66
            
            
            
            -57
            %Natural
      gas (per Mcf)
            
            
            2.92
            
            
            
            6.89
            
            
            
            -58
            %Natural
      gas equivalents (per Mcfe)
            
            
            3.30
            
            
            
            8.08
            
            
            
            -59
            %Realized
      Gain (Loss) on Derivatives, netOil
      derivatives - realized gain (loss)
            
            $
            116,448
            
            
            $
            (20,030
            )
            
            
            *Natural
      gas derivatives - realized gain (loss)
            
            
            483,666
            
            
            
            (22,859
            )
            
            
            *Total
      realized gain (loss) on derivatives, net
            
            $
            600,114
            
            
            $
            (42,889
            )
            
            
            *Average
      Selling Price (including realized gain (loss) on
    derivatives)Oil
      (per Bbl)
            
            $
            76.76
            
            
            $
            77.77
            
            
            
            -1
            %Natural
      gas (per Mcf)
            
            
            6.95
            
            
            
            6.69
            
            
            
            4
            %Natural
      gas equivalents (per Mcfe)
            
            
            7.68
            
            
            
            7.78
            
            
            
            -1
            %Average
      cost per McfeProduction
      and operating costs  (3)
            
            $
            1.16
            
            
            $
            1.89
            
            
            
            -39
            %Depreciation,
      depletion and amortization
            
            
            3.39
            
            
            
            2.76
            
            
            
            23
            %Revenues:Oil
      and gas sales
            
            $
            452,659
            
            
            $
            1,142,259
            
            
            
            -60
            %Oil
      and gas price risk management, net
            
            
            (62,035
            )
            
            
            (385,788
            )
            
            
            -84
            %Total
      revenues
            
            $
            390,624
            
            
            $
            756,471
            
            
            
            -48
            %Operating
      costs and expenses:Production
      and operating costs
            
            $
            158,816
            
            
            $
            266,382
            
            
            
            -40
            %Direct
      costs - general and administrative
            
            
            67,870
            
            
            
            12,560
            
            
            
            *Depreciation,
      depletion and amortization
            
            
            464,418
            
            
            
            390,227
            
            
            
            19
            %Accretion
      of asset retirement obligations
            
            
            3,297
            
            
            
            3,117
            
            
            
            6
            %Total
      operating costs and expenses
            
            $
            694,401
            
            
            $
            672,286
            
            
            
            3
            %(Loss)
      income from operations
            
            
            (303,777
            )
            
            
            84,185
            
            
            
            -461
            %Interest
      income
            
            
            13,130
            
            
            
            18,217
            
            
            
            -28
            %Net
      (loss) income
            
            $
            (290,647
            )
            
            $
            102,402
            
            
            
            -384
            %Cash
      distributions
            
            $
            800,066
            
            
            $
            572,862
            
            
            
            40
            %





*Percentage
change not meaningful or 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 we have an interest by the percentage of the leasehold or other
      property interest we own.


- 15
-
 Index


PDC
2004-A LIMITED PARTNERSHIP


(A
West Virginia Limited Partnership)





(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.





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





First Quarter 2009
Overview





During
the first quarter of 2009, the Partnership experienced the continuation of the
significant declines in oil and natural gas commodity prices from last year,
which was a year of significant events: oil and natural gas prices reached
record and near record highs, respectively, through July; then, in the midst of
U.S. credit turmoil and a worldwide economic slump, in December, oil prices fell
to their lowest level in four years and natural gas prices dropped almost by
half.  The Partnership’s derivative position has eased the impact of
the fall in oil and natural gas prices.  The Partnership realized $0.6
million in realized derivative gains in the first quarter of 2009, up from
realized derivative losses of $0.04 million in the first quarter of
2008.  At March 31, 2009, the Partnership estimated the net fair value
of its derivative positions to be a $1.1 million asset.  See the Liquidity and Capital
Resources discussion below for the steps the Partnership is taking in
this uncertain economic environment.





Production
decreased to 137,161 Mcfe for the first three months of 2009 compared to 141,285
Mcfe for the same prior year period, a decrease of 3%, while the average sales
price declined $4.78 per Mcfe a decrease of 59%.  The Partnership’s
realized derivative gains for the first quarter of 2009 of $0.6 million added an
average of $4.38 per Mcfe produced during the current three month period,
somewhat easing the significant drop in prices.





A
decrease in the spread between the NYMEX and CIG prices for natural gas,
slightly offset by lower CIG natural gas prices, resulted in unrealized losses
on oil and natural gas derivatives of $0.2 million during the
quarter.  An unrealized loss is a non-cash item and further gains or
losses will be recognized as prices decrease or increase until the positions
mature or are closed.  The Partnership has elected not to designate
any of the Partnership’s derivative instruments as hedges.  While the
required accounting treatment for derivatives that do not qualify for hedge
accounting treatment under SFAS No. 133 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.





During
the three month period ended March 31, 2009, daily crude oil prices fluctuated
in a range of $33.98 to $54.34 per barrel, with the overall trend of the monthly
average of daily NYMEX-index oil prices rising, from $41.99 per barrel in
January to $48.12 per barrel in March. Rocky Mountain regional natural gas daily
prices tracked downward through March 2009 however, the monthly average of daily
CIG-index prices of $3.67 in January, declined to $2.50 by March.  See
Oil and Gas Price Risk
Management, Netdiscussion below.


- 16
-
 Index


PDC
2004-A LIMITED PARTNERSHIP


(A
West Virginia Limited Partnership)





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:





December 31,
            
            
            June 30,
            
            
            December 31,
            
            
            March 31,Commodity
            
            Index
            
            2007
            
            
            2008
            
            
            2008
            
            
            2009Natural
      gas: (per
      MMbtu)NYMEX
            
            $
            8.12
            
            
            $
            12.52
            
            
            $
            6.62
            
            
            $
            5.44CIG
            
            
            6.78
            
            
            
            8.86
            
            
            
            4.49
            
            
            
            4.15Oil:
      (per
      Bbl)
            
            
            NYMEX
            
            
            90.79
            
            
            
            140.15
            
            
            
            57.49
            
            
            
            59.35





Oil and Natural Gas
Sales





Partnership
production decreased to 137 MMcfe for the current year three month period from
141 MMcfe the prior year three month period.  The Partnership’s oil
and gas sales revenue for the current three month period, excluding price risk
management impacts, decreased $0.7 million, substantially due to the dramatic
decline in commodity prices.





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 have been 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 facilities to increase
pipeline capacity, rendering the timing and availability of these facilities
beyond the Partnership’s control.  Oil pricing is also driven strongly
by supply and demand relationships.  Beginning January 1, 2009, Suncor
Energy Marketing, Inc. (“Suncor”) became the primary purchaser of the
Partnership’s crude oil production.





The price
the Partnership receives for the natural gas produced in the Rocky Mountain
Region is based on a market basket 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.


- 17
-
 Index


PDC
2004-A LIMITED PARTNERSHIP


(A
West Virginia Limited Partnership)





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, jointly by area of
operation.  Prior to September 30, 2008, as volumes produced changed,
the mix between PDC and the partnerships changed on a prorata
basis.  As of September 30, 2008, PDC has fixed the allocation of the
derivative positions between PDC and each partnership.  Existing
positions are allocated based on fixed quantities for each position and new
positions will have specific designations relative to the applicable
partnership.





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





Three months ended
      March 31,Oil
      and gas price risk management, net
            
            2009
            
            
            2008Realized
      gains (losses)Oil
            
            $
            116,448
            
            
            $
            (20,030
            )Natural
      Gas
            
            
            483,666
            
            
            
            (22,859
            )Total
      realized gain (loss), net
            
            
            600,114
            
            
            
            (42,889
            )Unrealized
      gains (losses)Reclassification
      of realized gains included in prior periods unrealized
            
            
            (495,526
            )
            
            
            (56,868
            )Unrealized
      loss for the period
            
            
            (166,623
            )
            
            
            (286,031
            )Total
      unrealized loss, net
            
            
            (662,149
            )
            
            
            (342,899
            )Oil
      and gas price risk management loss, net
            
            $
            (62,035
            )
            
            $
            (385,788
            )





The
unrealized loss for first quarter 2009 of $0.2 million was primarily due to a
decrease in fair value from our CIG basis protection swaps of $0.6 million
offset in part by a $0.4 million unrealized gain from our commodity
derivatives.  The net unrealized gain from commodity derivatives
resulted from the continued decline in commodity prices during the first
quarter.  The unrealized loss from the Partnership’s CIG basis
protection swaps resulted from a more significant decline in NYMEX pricing
compared to CIG pricing.  The realized gains from commodity
derivatives resulted from the current realized prices being below the
Partnership’s swaps and floor contract prices.





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-A 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 June 30, 2009, on the Partnership’s
production.  The Partnership’s production volumes for the three months
ended March 31, 2009, were 2,852 Bbls of oil and 120,049 Mcf of natural
gas.





Floors
            
            
            Ceilings
            
            
            Swaps (Fixed Prices)
            
            
            Basis Protection ContractsWeighted
            
            
            
            
            
            Weighted
            
            
            
            
            
            Weighted
            
            
            
            
            
            Weighted
            
            
            Fair
      ValueCommodity/
            
            Quantity
            
            
            Average
            
            
            Quantity
            
            
            Average
            
            
            Quantity
            
            
            Average
            
            
            Quantity
            
            
            Average
            
            
            AtIndex/
            
            (Gas-MMbtu
            
            
            Contract
            
            
            (Gas-MMbtu
            
            
            Contract
            
            
            (Gas-MMbtu
            
            
            Contract
            
            
            (Gas-MMbtu
            
            
            Contract
            
            
            June 30,Operating Area
            
            Oil-Bbls)
            
            
            Price
            
            
            Oil-Bbls)
            
            
            Price
            
            
            Oil-Bbls)
            
            
            Price
            
            
            Oil-Bbls)
            
            
            Price
            
            
            2009Natural
      GasRocky
      Mountain RegionCIG3Q
      2009
            
            
            101,618
            
            
            $
            5.75
            
            
            
            101,618
            
            
            $
            8.90
            
            
            
            -
            
            
            $
            -
            
            
            
            -
            
            
            $
            -
            
            
            $
            302,9484Q
      2009
            
            
            71,496
            
            
            
            6.67
            
            
            
            71,496
            
            
            
            10.21
            
            
            
            26,415
            
            
            
            9.20
            
            
            
            -
            
            
            
            -
            
            
            
            352,1602010
            
            
            82,634
            
            
            
            6.63
            
            
            
            82,634
            
            
            
            10.78
            
            
            
            39,623
            
            
            
            9.20
            
            
            
            242,594
            
            
            
            1.88
            
            
            
            95,0142011
            
            
            39,298
            
            
            
            4.75
            
            
            
            39,298
            
            
            
            9.45
            
            
            
            -
            
            
            
            -
            
            
            
            288,860
            
            
            
            1.88
            
            
            
            (254,234
            )2012
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            305,366
            
            
            
            1.88
            
            
            
            (254,510
            )2013
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            284,002
            
            
            
            1.88
            
            
            
            (213,801
            )NYMEX2010
            
            
            11,261
            
            
            
            5.75
            
            
            
            11,261
            
            
            
            8.30
            
            
            
            237,809
            
            
            
            5.61
            
            
            
            -
            
            
            
            -
            
            
            
            (85,574
            )2011
            
            
            15,308
            
            
            
            5.75
            
            
            
            15,308
            
            
            
            8.30
            
            
            
            76,628
            
            
            
            6.96
            
            
            
            -
            
            
            
            -
            
            
            
            6922012
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            81,771
            
            
            
            6.96
            
            
            
            -
            
            
            
            -
            
            
            
            (15,475
            )Total
      Natural Gas
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            (72,780
            )OilRocky
      Mountain RegionNYMEX3Q
      2009
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            2,516
            
            
            
            90.52
            
            
            
            -
            
            
            
            -
            
            
            
            49,0324Q
      2009
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            2,516
            
            
            
            90.52
            
            
            
            -
            
            
            
            -
            
            
            
            44,3412010
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            8,773
            
            
            
            92.96
            
            
            
            -
            
            
            
            -
            
            
            
            151,918Total
      Oil
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            245,291Total
      Natural Gas and Oil
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            $
            172,511





In July
2009, the Managing General Partner entered into a NYMEX-based oil swap covering
approximately 50% of the Partnership’s estimated production of oil for the
calendar year 2011 at $70.75 per barrel.





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
three months ended March 31, 2009 compared to 2008, oil and natural production,
on an energy equivalency-basis, decreased 4,124 Mcfe, or 3%, due to anticipated
production declines throughout an oil and natural gas well’s production life
cycle.  Production and operating costs were lower by $0.1 million, or
40%, due to a decrease in production taxes.  Production and operating
costs per Mcfe were $1.16 for the first quarter of 2009 compared to $1.89 for
the first quarter of 2008.





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 first three months of 2009
by $0.1 million primarily due to an increase in professional fees for audit and
tax services.


- 19
-
 Index


PDC
2004-A LIMITED PARTNERSHIP


(A
West Virginia Limited Partnership)





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.
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 priced
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 will increase,
resulting in decreases in the rate of DD&A expense per unit of
production.  If prices decrease, as they did from December 31, 2007 to
December 31, 2008, the estimated volumes of oil and gas reserves will decrease
resulting in increases in the rate of DD&A expense per unit of
production.





The
DD&A rate per Mcfe increased to $3.39 for the quarter ended March 31, 2009
compared to the DD&A rate per Mcfe of $2.76 during the same quarter in 2008
which resulted in a $0.1 million increase in DD&A for the three months ended
March 31, 2009 compared to same period in 2008.  This increase per
Mcfe is primarily the result of significantly lower reserves at December 31,
2008 compared to December 31, 2007.  While both 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 reserves in the
annual 2008 reserve report, principally related to changes in pricing resulted
in the increased DD&A unit cost increase during the first quarter of 2009 as
compared to the first quarter 2008.





Interest
Income





Although
undistributed revenues held by the Managing General Partner increased during the
three months ended March 31, 2009 compared to the same period in the previous
year, significantly lower interest rates in effect during the three months ended
March 31, 2009, applied to the undistributed amounts was the primary factor for
the interest income decline during the three months ended March 31, 2009,
compared to the comparable period in 2008.





Liquidity and Capital
Resources





Because
oil and gas production from the Partnership’s existing properties declines
rapidly in the first two years, 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.





Working
Capital





Working
capital at March 31, 2009 was $3.6 million compared to working capital of $3.3
million at December 31, 2008.  The increase of $0.3 million was
primarily due to a combined increase of receivables for realized and short-term
net unrealized derivative gains, which were $0.6 million and $1.7 million,
respectively, at March 31, 2009 and $0.5 million and $1.4 million, respectively,
at December 31, 2008.  This increase was partially offset by a
decrease in receivables from oil and gas sales at March 31, 2009 to $0.5 million
as compared to $0.6 million at December 31, 2008.





Investing
Cash Flows





The
Partnership has from time-to-time, invested in additional equipment which
supports treatment, delivery and measurement or environmental
protection.  These amounts totaled approximately $1,200 for the three
months ended March 31, 2009.


- 20
-
 Index


PDC
2004-A LIMITED PARTNERSHIP


(A
West Virginia Limited Partnership)





Cash
Flows From Financing Activities





The
Partnership initiated monthly cash distributions to investors in November 2004
and has distributed $29.7 million of operating cash flows through March 31,
2009.  The table below sets forth the cash distributions to the
Managing General Partner and Investor Partners including Managing General
distribution relating to limited partnership units repurchased for the periods
described as follows:





Managing
            
            
            InvestorQuarter
            
            General
      Partner
            
            
            Partners
            
            
            TotalEnded
            
            Distributions
            
            
            Distributions
            
            
            DistributionsMarch 31,
      2009
            
            $
            160,013
            
            
            $
            640,053
            
            
            $
            800,066March 31,
      2008
            
            $
            114,572
            
            
            $
            458,290
            
            
            $
            572,862





Investor
Partner cash distributions include $18,114 during the three months ended March
31, 2009, and $9,478 during the three months ended March 31, 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.





Changes
in market prices for oil and natural gas, the Partnership’s ability to increase
production, the 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 three months ended
March 31, 2009 were approximately 60% lower than the same period in the prior
year, resulting from a 59% decrease in average oil and natural gas prices and a
3% 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
would be generated, the Partnership has oil and natural gas derivative positions
in place, as of the date of this filing, covering 82% of the Partnership’s
expected oil production and 71% of its expected natural gas production for the
remainder of 2009, at average prices of $90.52 per Bbl and $6.54 per Mcf,
respectively.  These contracts reduce the impact of price changes on
cash provided by operations for a substantial portion of the Partnership’s cash
from expected production for the remainder of 2009.  However, the
remaining 18% and 29% 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
Partnership’s current derivatives positions could change based on changes in oil
and natural gas futures markets, the view of underlying oil and natural gas
supply and demand trends and changes in volumes produced.  Partnership
oil and natural gas derivatives as of March 31, 2009 are detailed in Note 5,
Derivative Financial
Instruments to the accompanying unaudited condensed financial
statements.


- 21
-
 Index


PDC
2004-A LIMITED PARTNERSHIP


(A
West Virginia Limited Partnership)





Net cash
provided by operating activities was $0.8 million for the three months ended
March 31, 2009 compared to $0.6 million during the same period in 2008, an
increase of $0.2 million.  Variances between the two periods in cash
provided by operating activities was due primarily to the
following:








·
            A
      decrease in oil and gas sale revenues of $0.7 million, or 60%, accompanied
      by an increase in direct costs – general and administrative of $0.1
      million; and





·
            An
      increase in realized oil and gas price risk management, net of $0.6
      million and a decrease in production and operating cost of
      40%.





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 in 2011
or after, should a favorable general economic environment and commodity price
structure exist at that time.  Since borrowing is not permitted, well
recompletion activities will be funded through the retention of revenues and
reduction of Partner cash distributions.  Based on the current
economic environment however, the Partnership has no immediate plans to initiate
recompletion activities in the Wattenberg Field wells owned by the
Partnership.  The Partnership will re-evaluate the feasibility of
commencing those recompletion activities if economic conditions
improve.





Commitments and
Contingencies





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





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.





Recent Accounting
Standards





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








Item
      3.
            Quantitative
      and Qualitative Disclosures About Market
Risk





Not
Applicable


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 Index


PDC
2004-A LIMITED PARTNERSHIP


(A
West Virginia Limited Partnership)





Item4T.
            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 March 31, 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.  Such report
is required in the Partnership’s 2009 Annual Report on Form 10-K.





(a)  Evaluation of Disclosure
Controls and Procedures





As of
March 31, 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.





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 March 31, 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 oversight 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, through the third and fourth quarter 2009 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 March 31, 2009.





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 is
expected to be implemented using a phased-in approach, during the second half of
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.


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 Index


PDC
2004-A LIMITED PARTNERSHIP


(A
West Virginia Limited Partnership)





Until
PDC, the Managing General Partner, has concluded that the Partnership has
remediated this known material weakness in internal control over financial
reporting, the Managing General Partner will 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.


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 Index


PDC
2004-A 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 November 2007, 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.





In the
first quarter of 2009, January repurchases totaled 1.25 units at an average
price of $6,776 per unit, February repurchases totaled 4.25 units at an average
price of $7,356 per unit, and March repurchases totaled 5.00 units at an average
price of $7,457 per unit.





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.


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 Index


PDC
2004-A 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
            
            000-51218
            
            3.1
            
            08/04/20093.2
            
            Certificate
      of limited partnership which reflects the organization of the Partnership
      under West Virginia law.
            
            10-K
            
            000-51218
            
            3.2
            
            08/04/200910.1
            
            Domestic
      Crude Oil Purchase Agreement between Suncor Energy Marketing Inc. and
      Petroleum Development Corporation, dated April 22, 2008 (filed by PDC as
      Managing General Partner for Rockies Region 2007 Limited
      Partnership).
            
            10-Q
            
            000-53201
            
            10.1
            
            05/18/200910.2
            
            Drilling
      and operating agreement between PDC as Managing General Partner of the
      Partnership.
            
            10-K
            
            000-51218
            
            10.1
            
            08/04/200931.1
            
            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
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 Index


PDC2004-A LIMITED PARTNERSHIP


(A
West Virginia Limited Partnership)





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-A Limited Partnership


By its
Managing General Partner


Petroleum
Development Corporation





By: /s/ Richard W.
McCullough


Richard
W. McCullough


Chairman
and Chief Executive Officer


September
23, 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
            September
      23, 2009Richard
      W. McCullough
            
            Petroleum
      Development CorporationManaging
      General Partner of the Registrant(Principal
      executive officer)/s/ Gysle R. Shellum
            
            Chief
      Financial Officer
            September
      23, 2009Gysle
      R. Shellum
            
            Petroleum
      Development CorporationManaging
      General Partner of the Registrant(Principal
      financial officer)/s/ R. Scott Meyers
            
            Chief
      Accounting Officer
            September
      23, 2009R.
      Scott Meyers
            
            Petroleum
      Development CorporationManaging
      General Partner of the Registrant(Principal
      accounting officer)






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