UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION
 WASHINGTON,
DC 20549
 
 FORM
10-Q
 
 x  QUARTERLY
REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
 
 For
the quarterly period ended September 30, 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   000-51309
 
 PDC
2005-A Limited Partnership
 (Exact
name of registrant as specified in its charter)
 
 West Virginia
              
              20-2088347(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  x  No   ̈
 
 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     x
 
 Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).  Yes  ̈  No x
 
 As of
October 31, 2009, the Partnership had 1,996.87 units of limited partnership
interest and no units of additional general partnership interest
outstanding.
  
 
 PDC
2005-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
              15Item
      3.
              
              Quantitative and Qualitative Disclosures About Market
      Risk
              25Item
      4T.
              
              Controls and Procedures
              25PART
      II – OTHER INFORMATIONItem
      1.
              
              Legal Proceedings
              27Item
      1A.
              
              Risk Factors
              27Item
      2.
              
              Unregistered Sales of Equity Securities and Use of
      Proceeds
              27Item
      3.
              
              Defaults Upon Senior Securities
              27Item
      4.
              
              Submission of Matters to a Vote of Security
      Holders
              27Item
      5.
              
              Other Information
              27Item
      6.
              
              Exhibits
              28SIGNATURES
              29
  Index
  PART
I – FINANCIAL INFORMATION
 
 Item
1.             Condensed
Financial Statements (unaudited)
 
 PDC
      2005-A Limited PartnershipCondensed
      Balance Sheets(unaudited)September
      30,
              
              
              December
      31,2009
              
              
              
              2008*AssetsCurrent
      assets:Cash
      and cash equivalents
              
              $
              224,751
              
              
              $
              314,610Accounts
      receivable
              
              
              223,110
              
              
              
              318,421Oil
      inventory
              
              
              38,128
              
              
              
              30,950Due
      from Managing General Partner-derivatives
              
              
              1,048,130
              
              
              
              2,100,443Due
      from Managing General Partner-other, net
              
              
              143,567
              
              
              
              1,590,959Total
      current assets
              
              
              1,677,686
              
              
              
              4,355,383Oil
      and gas properties, successful efforts method
              
              
              44,293,666
              
              
              
              44,267,285Drilling
      advances to Managing General Partner
              
              
              -
              
              
              
              108,531Oil
      and gas properties, at cost
              
              
              44,293,666
              
              
              
              44,375,816Less:  Accumulated
      depreciation, depletion and amortization
              
              
              (20,170,648
              )
              
              
              (17,313,642
              )Oil
      and gas properties, net
              
              
              24,123,018
              
              
              
              27,062,174Due
      from Managing General Partner-derivatives
              
              
              61,713
              
              
              
              716,092Other
      assets
              
              
              18,133
              
              
              
              -Total
      noncurrent assets
              
              
              24,202,864
              
              
              
              27,778,266Total
      Assets
              
              $
              25,880,550
              
              
              $
              32,133,649Liabilities and Partners'
      EquityCurrent
      liabilities:Accounts
      payable and accrued expenses
              
              $
              30,085
              
              
              $
              66,607Due
      to Managing General Partner-derivatives
              
              
              462,450
              
              
              
              -Total
      current liabilities
              
              
              492,535
              
              
              
              66,607Due
      to Managing General Partner-derivatives
              
              
              1,397,313
              
              
              
              165,957Asset
      retirement obligations
              
              
              395,132
              
              
              
              381,260Total
      liabilities
              
              
              2,284,980
              
              
              
              613,824Commitments
      and contingent liabilitiesPartners'
      equity:Managing
      General Partner
              
              
              4,734,098
              
              
              
              6,318,947Limited
      Partners - 1,996.87 units issued and outstanding
              
              
              18,861,472
              
              
              
              25,200,878Total
      Partners' equity
              
              
              23,595,570
              
              
              
              31,519,825Total
      Liabilities and Partners' Equity
              
              $
              25,880,550
              
              
              $
              32,133,649
  *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 financial statements.
  -1-
 Index
  PDC
      2005-A Limited PartnershipCondensed
      Statements of Operations(unaudited)Three
      months ended September 30,
              
              
              Nine
      months ended September 30,2009
              
              
              2008
              
              
              2009
              
              
              2008Revenues:Oil
      and gas sales
              
              $
              772,050
              
              
              $
              2,162,064
              
              
              $
              2,267,638
              
              
              $
              6,526,487Oil
      and gas price risk management (loss) gain, net
              
              
              (593,108
              )
              
              
              3,887,434
              
              
              
              (1,413,890
              )
              
              
              846,222Total
      revenues
              
              
              178,942
              
              
              
              6,049,498
              
              
              
              853,748
              
              
              
              7,372,709Operating
      costs and expenses:Production
      and operating costs
              
              
              459,163
              
              
              
              615,428
              
              
              
              1,186,398
              
              
              
              1,562,466Direct
      costs - general and administrative
              
              
              79,882
              
              
              
              91,967
              
              
              
              348,751
              
              
              
              270,051Depreciation,
      depletion and amortization
              
              
              916,146
              
              
              
              649,914
              
              
              
              2,857,006
              
              
              
              1,970,078Accretion
      of asset retirement obligations
              
              
              4,624
              
              
              
              4,373
              
              
              
              13,872
              
              
              
              13,119Total
      operating costs and expenses
              
              
              1,459,815
              
              
              
              1,361,682
              
              
              
              4,406,027
              
              
              
              3,815,714(Loss)
      income from operations
              
              
              (1,280,873
              )
              
              
              4,687,816
              
              
              
              (3,552,279
              )
              
              
              3,556,995Interest
      expense
              
              
              (2,338
              )
              
              
              -
              
              
              
              (2,338
              )
              
              
              -Interest
      income
              
              
              11,848
              
              
              
              14,768
              
              
              
              33,815
              
              
              
              49,063Net
      (loss) income
              
              $
              (1,271,363
              )
              
              $
              4,702,584
              
              
              $
              (3,520,802
              )
              
              $
              3,606,058Net
      (loss) income allocated to partners
              
              $
              (1,271,363
              )
              
              $
              4,702,584
              
              
              $
              (3,520,802
              )
              
              $
              3,606,058Less:  Managing
      General Partner interest in net (loss) income
              
              
              (254,272
              )
              
              
              940,517
              
              
              
              (704,160
              )
              
              
              721,212Net
      (loss) income allocated to Investor Partners
              
              $
              (1,017,091
              )
              
              $
              3,762,067
              
              
              $
              (2,816,642
              )
              
              $
              2,884,846Net
      (loss) income per Investor Partner unit
              
              $
              (509
              )
              
              $
              1,884
              
              
              $
              (1,411
              )
              
              $
              1,445Investor
      Partner units outstanding
              
              
              1,996.87
              
              
              
              1,996.87
              
              
              
              1,996.87
              
              
              
              1,996.87
 
 See
accompanying notes to unaudited condensed financial statements.
  -2-
 Index
  PDC
      2005-A Limited PartnershipCondensed
      Statements of Cash Flows(unaudited)Nine
      months ended September 30,2009
              
              
              2008Cash
      flows from operating activities:Net
      (loss) income
              
              $
              (3,520,802
              )
              
              $
              3,606,058Adjustments
      to reconcile net (loss) income to net cash provided by operating
      activities:Depreciation,
      depletion and amortization
              
              
              2,857,006
              
              
              
              1,970,078Accretion
      of asset retirement obligations
              
              
              13,872
              
              
              
              13,119Unrealized
      loss (gain) on derivative transactions
              
              
              3,400,498
              
              
              
              (1,352,206
              )Changes
      in operating assets and liabilities:Decrease
      in accounts receivable
              
              
              95,311
              
              
              
              292,277Increase
      in accounts receivable - other
              
              
              -
              
              
              
              (128,874
              )Increase
      in oil inventory
              
              
              (7,178
              )
              
              
              (48,561
              )Increase
      in other assets
              
              
              (18,133
              )
              
              
              -(Decrease)
      increase in accounts payable and accrued expenses
              
              
              (36,522
              )
              
              
              128,168Decrease
      (increase) in due from Managing General Partner - other,
    net
              
              
              1,447,392
              
              
              
              (253,628
              )Net
      cash provided by operating activities
              
              
              4,231,444
              
              
              
              4,226,431Cash
      flows from investing activities:Capital
      expenditures for oil and gas properties
              
              
              (26,381
              )
              
              
              (27,855
              )Proceeds
      from drilling advance refund from Managing General Partner
              
              
              108,531Proceeds
      from Colorado sales tax refund related to capital
purchases
              
              
              -
              
              
              
              128,874Net
      cash provided by investing activities
              
              
              82,150
              
              
              
              101,019Cash
      flows from financing activities:Distributions
      to Partners
              
              
              (4,403,453
              )
              
              
              (4,306,497
              )Net
      cash used in financing activities
              
              
              (4,403,453
              )
              
              
              (4,306,497
              )Net
      (decrease) increase in cash and cash equivalents
              
              
              (89,859
              )
              
              
              20,953Cash
      and cash equivalents, beginning of period
              
              
              314,610
              
              
              
              164,781Cash
      and cash equivalents, end of period
              
              $
              224,751
              
              
              $
              185,734
  See
accompanying notes to unaudited condensed financial statements.
  -3-
 Index
 
 PDC
2005-A LIMITED PARTNERSHIP
 NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
 September
30, 2009
 (unaudited)
 
 Note
1−General and Basis of
Presentation
 
 The PDC
2005-A Limited Partnership (the “Partnership” or the “Registrant”) was organized
as a limited partnership on November 30, 2004, in accordance with the laws of
the State of West Virginia for the purpose of engaging in the exploration and
development of oil and natural gas properties.  Upon completion of the
sale of Partnership units on February 9, 2005 (date of inception), the
Partnership was funded and commenced its business operations.  The
Partnership owns natural gas and oil wells located in Colorado, and from the
wells, the Partnership produces and sells natural gas and oil.
 
 Purchasers
of partnership units subscribed to and fully paid for 124.79 units of limited
partner interests and 1,872.08 units of additional general partner interests at
$20,000 per unit.  In accordance with the terms of the Limited
Partnership Agreement (the “Agreement”), Petroleum Development Corporation, a
Nevada Corporation, is the Managing General Partner of the Partnership
(hereafter, the “Managing General Partner,” “MGP” or “PDC”) and has a 20%
Managing General Partner ownership in the Partnership.  Upon
completion of the drilling phase of the Partnership's wells, all additional
general partners units were converted into units of limited partner interests
and thereafter became limited partners of the Partnership.  Throughout
the term of the Partnership, revenues, costs, and cash distributions are
allocated 80% to the limited and additional general partners (collectively, the
“Investor Partners”), which are shared pro rata based upon the portion of units
owned in the Partnership, and 20% to the Managing General Partner.
 
 As of
September 30, 2009, there were 1,548 Investor Partners.  As of
September 30, 2009, the Managing General Partner has repurchased 23.75 units of
the total 1,996.87 outstanding units of Partnership interests from Investor
Partners at an average price of $9,944 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”), has full authority to conduct the
Partnership’s business and actively manage the Partnership.
 
 The
accompanying interim unaudited condensed financial statements have been prepared
without audit in accordance with accounting principles generally accepted in the
United States of America, or U.S., for interim financial information and with
the instructions to Form 10-Q and Article 8 of Regulation S-X of the Securities
and Exchange Commission, or SEC. Accordingly, pursuant to certain rules and
regulations, certain notes and other financial information included in audited
financial statements have been condensed or omitted.  In the
Partnership’s opinion, the accompanying interim unaudited condensed financial
statements contain all adjustments (consisting of only normal recurring
adjustments) necessary to present fairly the Partnership's financial position,
results of operations and cash flows for the periods presented.  The
interim results of operations and cash flows for the nine months ended September
30, 2009 and 2008 are not necessarily indicative of the results to be expected
for the full year or any other future period.
 
 The
accompanying interim unaudited condensed financial statements should be read in
conjunction with the audited financial statements and notes thereto included in
the Partnership's Form 10-K for the year ended December 31, 2008, as filed with
the SEC on March 31, 2009 (“the 2008 Form 10-K”).
 
 
 Note
2−Recent Accounting
Standards
 
 Recently Adopted Accounting
Standards
 
 Accounting
Standards Codification
 
 In June
2009, the Financial Accounting Standards Board, or FASB, issued the FASB
Accounting Standards CodificationTM (the “Codification”), thereby establishing
the Codification as the source of authoritative accounting principles recognized
by the FASB to be applied by nongovernmental entities in the preparation of
financial statements in conformity with U.S. Generally Accepted Accounting
Principles, or GAAP.  Rules and interpretive releases of the SEC under
authority of federal securities laws are also sources of authoritative GAAP for
SEC registrants.  The FASB will no longer issue new standards in the
form of Statements, FASB Staff Positions, or Emerging Issues Task Force
Abstracts; instead, the FASB will issue Accounting Standards
Updates.  Accounting Standards Updates will not be authoritative in
their own right as they will only serve to update the
Codification.  These changes and the Codification itself do not change
GAAP.  Effective July 1, 2009, the Partnership adopted the
Codification.  Other than the manner in which new accounting guidance
is referenced, the adoption of the Codification did not have any impact on the
Partnership’s accompanying interim unaudited condensed financial
statements.
  -4-
 Index
 
 PDC
2005-A LIMITED PARTNERSHIP
 NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
 September
30, 2009
 (unaudited)
 
 Subsequent
Events
 
 In May
2009, the FASB issued changes regarding subsequent events, which establishes
general standards of accounting for and disclosure of events that occur after
the balance sheet date but before financial statements are issued. Specifically,
the guidance sets forth the period after the balance sheet date during which the
Managing General Partner should evaluate events or transactions that may occur
for potential recognition or disclosure in the Partnership’s financial
statements, the circumstances under which the Partnership should recognize
events or transactions occurring after the balance sheet date in the
Partnership’s financial statements, and the disclosures that the Partnership
should make about events or transactions that occurred after the balance sheet
date. The Partnership adopted the guidance as of June 30, 2009. See Note 7,
Subsequent
Events.
 
 Business
Combinations
 
 In
December 2007, the FASB issued changes regarding the accounting for business
combinations. The new changes require:
 
 ·
              an
      acquirer to recognize the assets acquired, the liabilities assumed and any
      noncontrolling interest in the acquiree at their acquisition-date fair
      values;
 ·
              disclosure
      of the information necessary for investors and other users to evaluate and
      understand the nature and financial effect of the business
      combination;
 ·
              acquisition-related
      costs be expensed as incurred.
 
 The
changes also amend the 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. Further, the changes amend the accounting for 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 again issued changes to the accounting for business
combinations.  These changes apply to all assets acquired and
liabilities assumed in a business combination that arise from contingencies and
require:
 
 ·
              an
      acquirer to recognize at fair value, at the acquisition date, an asset
      acquired or liability assumed in a business combination that arises from a
      contingency if the acquisition-date fair value of that asset or liability
      can be determined during the measurement period otherwise the asset or
      liability should be recognized at the acquisition date if certain defined
      criteria are met;
 ·
              contingent
      consideration arrangements of an acquiree assumed by the acquirer in a
      business combination be recognized initially at fair
  value;
 ·
              subsequent
      measurements of assets and liabilities arising from contingencies be based
      on a systematic and rational method depending on their nature and
      contingent consideration arrangements be measured subsequently;
      and
 ·
              disclosures
      of the amounts and measurements basis of such assets and liabilities and
      the nature of the
contingencies.
  -5-
 Index
 
 PDC
2005-A LIMITED PARTNERSHIP
 NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
 September
30, 2009
 (unaudited)
 
 The
changes above became effective for acquisitions completed on or after January 1,
2009; however, the income tax changes became effective as of that date for all
acquisitions, regardless of the acquisition date. The Partnership adopted these
changes effective January 1, 2009, for which they will be applied prospectively
in the Partnership’s accounting for future acquisitions, if any.  This
adoption had no impact on the Partnership’s accompanying interim unaudited
condensed financial statements.
 
 Consolidation
– Noncontrolling Interest in a Subsidiary
 
 In
December 2007, the FASB issued changes regarding the nature and classification
of the noncontrolling interest in a subsidiary in the consolidated financial
statements. The changes require the accounting and reporting for minority
interests be recharacterized as noncontrolling interests and classified as a
component of equity. Additionally, the changes establish reporting requirements
that provide sufficient disclosures which clearly identify and distinguish
between the interests of the parent and the interests of the noncontrolling
owners.  The Partnership adopted these changes effective January 1,
2009.  The Partnership’s adoption of this guidance had no material
impact on the Partnership’s accompanying interim unaudited condensed financial
statements.
 
 Fair
Value Measurements and Disclosures
 
 In
February 2008, the FASB delayed by one year (to January 1, 2009) the fair value
measurements and disclosure requirements 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). The January 1,
2009, adoption of the fair value measurements and disclosure requirements for
the Partnership’s nonfinancial assets and liabilities did not have a material
impact on the Partnership’s accompanying interim unaudited condensed financial
statements. See Note 4, Fair
Value Measurements.
 
 Derivatives
and Hedging Disclosures
 
 In March
2008, the FASB issued changes regarding the disclosure requirements for
derivative instruments and hedging activities.  Pursuant to the
changes, enhanced disclosures are required to provide information about (a) how
and why the Partnership uses derivative instruments, (b) how the Partnership
accounts for derivative instruments and related hedged items and (c) how
derivative instruments and related hedged items affect the Partnership’s
financial position, financial performance and cash flows.  The
Partnership adopted these changes effective January 1, 2009.  The
adoption did not have a material impact on the Partnership’s accompanying
interim unaudited condensed financial statements. See Note 5, Derivative Financial
Instruments.
 
 Recently Issued Accounting
Standards
 
 Fair
Value Measurements and Disclosures
 
 In August
2009, the FASB issued changes regarding fair value measurements and disclosures
to reduce potential ambiguity in financial reporting when measuring the fair
value of liabilities.  These changes clarify existing guidance that in
circumstances in which a quoted price in an active market for the identical
liability is not available, an entity is required to measure fair value using
either a valuation technique that uses a quoted price of either a similar
liability or a quoted price of an identical or similar liability when traded as
an asset, or another valuation technique that is consistent with the principles
of fair value measurements, such as an income approach (e.g., present value
technique).  This guidance also states that both a quoted price in an
active market for the identical liability and a quoted price for the identical
liability when traded as an asset in an active market when no adjustments to the
quoted price of the asset are required are Level 1 fair value
measurements.  These changes become effective for the Partnership on
October 1, 2009.  The Partnership has not determined the impact, if
any, that these changes will have on the Partnership’s financial
statements.
  -6-
 Index
 
 PDC
2005-A LIMITED PARTNERSHIP
 NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
 September
30, 2009
 (unaudited)
 
 Consolidation
– Variable Interest Entities
 
 In June
2009, the FASB issued changes surrounding an entity’s analysis to determine
whether any of its variable interests constitute controlling financial interests
in a variable interest entity.  This analysis identifies the primary
beneficiary of a variable interest entity as the enterprise that has both of the
following characteristics:
 
 ·
              the
      power to direct the activities of a variable interest entity that most
      significantly impact the entity’s economic performance
  and
 ·
              the
      obligation to absorb losses of the entity that could potentially be
      significant to the variable interest entity or the right to receive
      benefits from the entity that could potentially be significant to the
      variable interest entity.
 
 Additionally,
the entity is required to assess whether it has an implicit financial
responsibility to ensure that a variable interest entity operates as designed
when determining whether it has the power to direct the activities of the
variable interest entity that most significantly impact the entity’s economic
performance.  The guidance also requires ongoing reassessments of
whether an enterprise is the primary beneficiary of a variable interest
entity.  These changes are effective for the Partnership’s financial
statements issued for fiscal years beginning after November 15, 2009, with
earlier adoption prohibited.  The Partnership is evaluating the impact
that the adoption of these changes will have on the Partnership’s financial
statements, related disclosure and management’s discussion and
analysis.
 
 Modernization
of Oil and Gas Reporting
 
 In
January 2009, the SEC published its final rule regarding the 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.  The Partnership is 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.
   Note
3−Transactions with
Managing General Partner and Affiliates
 
 The
Managing General Partner transacts business on behalf of the Partnership under
the authority of the D&O Agreement.  Revenues and other cash
inflows received on behalf of the Partnership are distributed to the Partners
net of (after deducting) corresponding operating costs and other cash outflows
incurred on behalf of the Partnership.
 
 The fair
value of the Partnership’s portion of unexpired derivative instruments is
recorded on the balance sheet under the captions “Due from Managing General
Partner–derivatives,” in the case of net unrealized gains or “Due to Managing
General Partner–derivatives,” in the case of net unrealized losses.
 
 Undistributed
oil and natural gas revenues collected by the Managing General Partner from the
Partnership’s customers in the amount of $263,490 and $565,638 as of September
30, 2009 and December 31, 2008, respectively, are included in the balance sheet
caption “Due from Managing General Partner - other, net.”  Realized
gains or losses from derivative transactions that have not yet been distributed
to the Partnership are included in the balance sheet captions “Due from Managing
General Partner-other, net” or “Due to Managing General Partner-other, net,”
respectively.  Undistributed realized gains amounted to $332,110 and
$738,074 as of September 30, 2009 and December 31, 2008,
respectively.  All other unsettled transactions between the
Partnership and the Managing General Partner are recorded net on the balance
sheet under the caption “Due from (to) Managing General Partner – other,
net.”
  -7-
 Index
 
 PDC
2005-A LIMITED PARTNERSHIP
 NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
 September
30, 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 September 30,
              
              
              Nine
      months ended September 30,2009
              
              
              2008
              
              
              2009
              
              
              2008Well
      operations and maintenance
              
              $
              363,182
              
              
              $
              354,082
              
              
              $
              910,103
              
              
              $
              793,611Gathering,
      compression and processing fees
              
              
              50,424
              
              
              
              61,870
              
              
              
              144,907
              
              
              
              169,881Direct
      costs - general and administrative
              
              
              79,882
              
              
              
              91,967
              
              
              
              348,751
              
              
              
              270,051Cash
      distributions*
              
              
              368,132
              
              
              
              345,118
              
              
              
              910,133
              
              
              
              873,015
 
 *Cash
distributions include $8,742 and $29,444 during the three and nine months ended
September 30, 2009, respectively, and $5,566 and $11,717 during the three and
nine months ended September 30, 2008, respectively, related to equity cash
distributions on Investor Partner units repurchased by PDC.  For
additional disclosure regarding the Unit Repurchase Program, refer to Note 1,
General and Basis of
Presentation.
 
 Distributions
to Partners in 2009 were impacted by several non-recurring
items.  Receivables collected from the Managing General Partner for
the over-withholding of production taxes related to Partnership production prior
to 2007 increased distributions by $1.2 million.  In addition, the
Partnership’s payment to the Managing General Partner for royalty settlement
costs of $0.1 million decreased distributions during the period.  Cash
distribution to the partners includes $0.4 million paid on the behalf of
Investor Partners, to the Internal Revenue Service and state taxing authorities
as a part of a comprehensive settlement agreement with taxing
agencies.  Both amounts had been previously accrued by the Partnership
in “Due from (to) Managing General Partner – other, net.”
 
 
 Note
4−Fair Value
Measurements
 
 Determination of Fair
Value.  The Partnership’s fair value measurements are estimated
pursuant to a fair value hierarchy that requires the Partnership to maximize the
use of observable inputs and minimize the use of unobservable inputs when
measuring fair value.  The valuation hierarchy is based upon the
transparency of inputs to the valuation of an asset or liability as of the
measurement date, giving the highest priority to quoted prices in active markets
(Level 1) and the lowest priority to unobservable data (Level 3).  In
some cases, the inputs used to measure fair value might fall in different levels
of the fair value hierarchy.  The lowest level input that is
significant to a fair value measurement in its entirety determines the
applicable level in the fair value hierarchy.  Assessing the
significance of a particular input to the fair value measurement in its entirety
requires judgment, considering factors specific to the asset or liability, and
may affect the valuation of the assets and liabilities and their placement
within the fair value hierarchy levels.  The three levels of inputs
that may be used to measure fair value are defined as:
 
 ·
              Level 1 –
      Quoted prices (unadjusted) in active markets for identical assets or
      liabilities.  Included in Level 1 are commodity derivative
      instruments for New York Mercantile Exchange, or NYMEX, based 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.
  -8-
 Index
 
 PDC
2005-A LIMITED PARTNERSHIP
 NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
 September
30, 2009
 (unaudited)
 
 ·
              Level 3 –
      Unobservable inputs for the asset or liability, including situations where
      there is little, if any, market activity for the asset or
      liability.  Included in Level 3 are the Partnership’s commodity
      derivative instruments for Colorado Interstate Gas, or CIG, based
      fixed-price natural gas swaps, collars and floors, oil swaps and natural
      gas basis protection swaps.
 
 Derivative Financial
Instruments.  The Partnership measures fair value based upon
quoted market prices, where available.  The valuation determination
includes: (1) identification of the inputs to the fair value methodology through
the review of counterparty statements and other supporting documentation, (2)
determination of the validity of the source of the inputs, (3) corroboration of
the original source of inputs through access to multiple quotes, if available,
or other information and (4) monitoring changes in valuation methods and
assumptions.  The methods described above may produce a fair value
calculation that may not be indicative of future fair values.  The
valuation determination also gives consideration to nonperformance risk on
Partnership liabilities in addition to nonperformance risk on PDC’s own business
interests and liabilities, as well as the credit standing of derivative
instrument counterparties.  The Managing General Partner primarily
uses two investment grade financial institutions as counterparties to its
derivative contracts, who hold the majority of the Managing General Partner’s
derivative assets.  The Managing General Partner has evaluated the
credit risk of the Partnership’s derivative assets from counterparties holding
its derivative assets using relevant credit market default rates, giving
consideration to amounts outstanding for each counterparty and the duration of
each outstanding derivative position.  Based on the Managing General
Partner’s evaluation, the Partnership has determined that the impact of
counterparty non-performance on the fair value of the Partnership’s derivative
instruments is insignificant.  As of September 30, 2009, no adjustment
for credit risk was recorded by the Partnership.  Furthermore, while
the Managing General Partner believes these valuation methods are appropriate
and consistent with that used by other market participants, the use of different
methodologies, or assumptions, to determine the fair value of certain financial
instruments could result in a different estimate of fair value.
 
 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
              
              $
              -
              
              
              $
              2,816,535
              
              
              $
              2,816,535Total
      assets
              
              
              -
              
              
              
              2,816,535
              
              
              
              2,816,535Liabilities:Basis
      protection derivative contracts
              
              
              -
              
              
              
              (165,957
              )
              
              
              (165,957
              )Total
      liabilities
              
              
              -
              
              
              
              (165,957
              )
              
              
              (165,957
              )Net
      asset
              
              $
              -
              
              
              $
              2,650,578
              
              
              $
              2,650,578As
      of September 30, 2009Assets:Commodity
      based derivatives
              
              $
              4,933
              
              
              $
              1,104,910
              
              
              $
              1,109,843Total
      assets
              
              
              4,933
              
              
              
              1,104,910
              
              
              
              1,109,843Liabilities:Commodity
      based derivatives
              
              
              (168,674
              )
              
              
              (63,174
              )
              
              
              (231,848
              )Basis
      protection derivative contracts
              
              
              -
              
              
              
              (1,627,915
              )
              
              
              (1,627,915
              )Total
      liabilities
              
              
              (168,674
              )
              
              
              (1,691,089
              )
              
              
              (1,859,763
              )Net
      (liability) asset
              
              $
              (163,741
              )
              
              $
              (586,179
              )
              
              $
              (749,920
              )
  -9-
 Index
 
 PDC
2005-A LIMITED PARTNERSHIP
 NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
 September
30, 2009
 (unaudited)
 
 The
following table sets forth the changes of the Partnership’s Level 3 derivative
financial instruments measured on a recurring basis:
 
 Nine
      months endedSeptember
      30, 2009Fair
      value, net asset, as of December 31, 2008
              
              $
              2,650,578Changes
      in fair value included in statement of operations line
    item:Oil
      and gas price risk management loss, net
              
              
              (1,250,149
              )Settlements
              
              
              (1,986,608
              )Fair
      value, net asset, as of September 30, 2009
              
              $
              (586,179
              )Change
      in unrealized gains (losses) relating to assets (liabilities) still held
      as of September 30, 2009, included in statement of operations line
      item:Oil
      and gas price risk management, net
              
              $
              (1,616,532
              )
 
 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.
 
 The
Partnership periodically assesses its proved oil and gas properties for possible
impairment, upon a triggering event, by comparing net capitalized costs to
estimated undiscounted future net cash flows on a field-by-field basis using
estimated production based upon estimated prices at which the Partnership
reasonably estimates the commodity to be sold.  The estimates of
future prices may differ from current market prices of oil and natural
gas.  Certain events, including but not limited to, downward revisions
in estimates to the Partnership’s reserve quantities, expectations of falling
commodity prices or rising operating costs may result in a triggering event and,
therefore, a possible impairment of the Partnership’s oil and natural gas
properties.  If, when assessing impairment, net capitalized costs
exceed undiscounted future net cash flows, the measurement of impairment is
based on estimated fair value utilizing a future discounted cash flow analysis
and is measured by the amount by which the net capitalized costs exceed their
fair value.  During the nine months ended September 30, 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, at the
time the well is completely drilled.  The Partnership estimates the
fair value of the plugging and abandonment obligations based on a discounted
cash flows analysis.  Upon initial recognition of an asset retirement
obligation, the Partnership increases the carrying amount of the long-lived
asset by the same amount as the liability.  Periodically, the
liabilities are accreted for the change in present value, through charges to
“Accretion of asset retirement obligations” on the statement of
operations.  The initial capitalized costs are depleted based on the
useful lives of the related assets, through charges to depreciation, depletion
and amortization or DD&A.  If the fair value of the estimated
asset retirement obligation changes, an adjustment is recorded to both the asset
retirement obligation and the asset retirement cost.  Revisions in
estimated liabilities can result from revisions of estimated inflation rates,
escalating retirement costs and changes in the estimated timing of settling
asset retirement obligations.
  -10-
 Index
 
 PDC
2005-A LIMITED PARTNERSHIP
 NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
 September
30, 2009
 (unaudited)
 
 Note
5−Derivative Financial
Instruments
 
 The
Partnership is exposed to the effect of market fluctuations in the prices of oil
and natural gas.  Price risk represents the potential risk of loss
from adverse changes in the market price of oil and natural gas
commodities.  The Managing General Partner employs established
policies and procedures to manage the risks associated with these market
fluctuations using derivative instruments.  Partnership policy
prohibits the use of oil and natural gas derivative instruments for speculative
purposes.
 
 The
Partnership recognizes all derivative instruments as either assets or
liabilities on the accompanying interim unaudited condensed balance sheets at
fair value. The Partnership has elected not to designate any of the
Partnership’s derivative instruments as hedges. Accordingly, changes in the fair
value of those derivative instruments allocated to the Partnership are recorded
in the Partnership’s statements of operations.  Changes in the fair
value of derivative instruments related to the Partnership’s oil and gas sales
activities are recorded in “Oil and gas price risk management,
net.”
 
 Valuation
of a contract’s fair value is performed internally. While the Managing General
Partner uses common industry practices to develop the Partnership’s valuation
techniques, changes in pricing methodologies or the underlying assumptions could
result in different fair values.  See Note 4, Fair Value Measurements, for
a discussion of how the Managing General Partner determines the fair value of
the Partnership’s derivative instruments.
 
 As of
September 30, 2009, the Managing General Partner had derivative contracts in
place for a portion of the Partnership’s anticipated production through 2012 for
a total of 935 MMbtu of natural gas and 23 MBbls of crude oil.  During
late October 2009, the Managing General Partner entered into additional NYMEX
fixed-price gas swaps ($6.67 to $7.11) and NYMEX gas collars ($6.00-$6.10 floor:
$8.27-$8.60 ceiling) covering all monthly periods from November 2010 to December
2013. The Partnership will be allocated positions by the Managing General
Partner for MMbtu’s equal to the number of remaining MMbtu’s of basis protection
swaps at September 30, 2009 which were not previously covered by NYMEX
fixed-price gas swaps or gas collars.
 
 Derivative
Strategies.  The Partnership’s results of operations and
operating cash flows are affected by changes in market prices for oil and
natural gas.  To mitigate a portion of the exposure to adverse market
changes, the Managing General Partner has entered into various derivative
contracts.
 
 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
September 30, 2009, the Partnership’s oil and natural gas derivative instruments
were comprised of commodity collars, commodity swaps and basis protection
swaps.
 
 ·
              Collars
      contain a fixed floor price (put) and ceiling price (call).  If
      the market price falls below the fixed put strike price, PDC, as Managing
      General Partner, receives the market price from the purchaser and receives
      the difference between the put strike price and market price from the
      counterparty.  If the market price exceeds the fixed call strike
      price, PDC, as Managing General Partner, receives the market price from
      the purchaser and pays the difference between the call strike price and
      market price to the counterparty.  If the market price is
      between the call and put strike price, no payments are due to or from the
      counterparty.
 
 ·
              Swaps
      are arrangements that guarantee a fixed price.  If the market
      price is below the fixed contract price, PDC, as Managing General Partner,
      receives the market price from the purchaser and receives the difference
      between the market price and the fixed contract price from the
      counterparty.  If the market price is above the fixed contract price,
      PDC, as Managing General Partner, receives the market price from the
      purchaser and pays the difference between the market price and the fixed
      contract price to the
counterparty.
  -11-
 Index
 
 PDC
2005-A LIMITED PARTNERSHIP
 NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
 September
30, 2009
 (unaudited)
 
 ·
              Basis
      protection swaps are arrangements that guarantee a price differential for
      natural gas from a specified delivery point.  For CIG basis
      protection swaps, which traditionally have negative differentials to
      NYMEX, PDC, as Managing General Partner, receives a payment from the
      counterparty if the price differential is greater than the stated terms of
      the contract and pays the counterparty if the price differential is less
      than the stated terms of the
contract.
 
 The
following table summarizes the location and fair value amounts of the
Partnership’s derivative instruments in the accompanying balance sheets as of
September 30, 2009, and December 31, 2008.
 
 Fair
      ValueBalance
      Sheet
              
              September
      30,
              
              
              December
      31,Derivative
      instruments not designated as hedge  (1):
              
              Line
      Item
              
              2009
              
              
              2008Derivative
      Assets:
              
              CurrentCommodity
      contracts
              
              Due
      from Managing General Partner-derivatives
              
              $
              1,048,130
              
              
              $
              2,100,443Non CurrentCommodity
      contracts
              
              Due
      from Managing General Partner-derivatives
              
              
              61,713
              
              
              
              716,092Total
      Derivative Assets
              
              
              
              
              
              $
              1,109,843
              
              
              $
              2,816,535Derivative
      Liabilities:
              
              CurrentCommodity
      contracts
              
              Due
      to Managing General Partner-derivatives
              
              $
              (149,219
              )
              
              $
              -Basis
      protection contracts
              
              Due
      to Managing General Partner-derivatives
              
              
              (313,231
              )
              
              
              -Non CurrentCommodity
      contracts
              
              Due
      to Managing General Partner-derivatives
              
              
              (82,629
              )
              
              
              -Basis
      protection contracts
              
              Due
      to Managing General Partner-derivatives
              
              
              (1,314,684
              )
              
              
              (165,957
              )Total
      Derivative Liabilities
              
              
              
              $
              (1,859,763
              )
              
              $
              (165,957
              )
 
 (1) As of
September 30, 2009 and December 31, 2008, none of the Partnership’s derivative
instruments were designated hedges.
 
 The
following table summarizes the impact of the Partnership’s derivative
instruments on the Partnership’s accompanying statements of operations for the
three and nine months ended September 30, 2009 and 2008.
 
 Three
      months ended September 30,2009
              
              
              2008Statement
      of operations line item
              
              Reclassification
      of Realized Gains (Losses) Included in Prior Periods
      Unrealized
              
              
              Realized
      and Unrealized Gains (Losses) For the Current Period
              
              
              Total
              
              
              Reclassification
      of Realized Gains (Losses) Included in Prior Periods
      Unrealized
              
              
              Realized
      and Unrealized Gains (Losses) For the Current Period
              
              
              TotalOil
      and gas price risk management, netRealized
      gains (losses)
              
              $
              513,607
              
              
              $
              (6,329
              )
              
              $
              507,278
              
              
              $
              (559,832
              )
              
              $
              611,368
              
              
              $
              51,536Unrealized
      (losses) gains
              
              
              (513,607
              )
              
              
              (586,779
              )
              
              
              (1,100,386
              )
              
              
              559,832
              
              
              
              3,276,066
              
              
              
              3,835,898Total
      oil and gas price risk management loss (gain), net
              
              $
              -
              
              
              $
              (593,108
              )
              
              $
              (593,108
              )
              
              $
              -
              
              
              $
              3,887,434
              
              
              $
              3,887,434
 
 Nine
      months ended September 30,2009
              
              
              2008Statement
      of operations line item
              
              Reclassification
      of Realized Gains (Losses) Included in Prior Periods
      Unrealized
              
              
              Realized
      and Unrealized Gains (Losses) For the Current Period
              
              
              Total
              
              
              Reclassification
      of Realized Gains (Losses) Included in Prior Periods
      Unrealized
              
              
              Realized
      and Unrealized Gains (Losses) For the Current Period
              
              
              TotalOil
      and gas price risk management,  netRealized
      gains (losses)
              
              $
              1,557,047
              
              
              $
              429,561
              
              
              $
              1,986,608
              
              
              $
              (127,926
              )
              
              $
              (378,058
              )
              
              $
              (505,984
              )Unrealized
      (losses) gains
              
              
              (1,557,047
              )
              
              
              (1,843,451
              )
              
              
              (3,400,498
              )
              
              
              127,926
              
              
              
              1,224,280
              
              
              
              1,352,206Total
      oil and gas price risk management loss (gain), net
              
              $
              -
              
              
              $
              (1,413,890
              )
              
              $
              (1,413,890
              )
              
              $
              -
              
              
              $
              846,222
              
              
              $
              846,222
  -12-
 Index
 
 PDC
2005-A LIMITED PARTNERSHIP
 NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
 September
30, 2009
 (unaudited)
 
 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 the
Managing General Partner pursuant to leases.  The Managing General Partner
moved the case to Federal Court on June 28, 2007.  On October 10, 2008, the
court preliminarily approved a settlement agreement between the plaintiffs and
the Managing General Partner, on behalf of itself and the Partnership. 
Although the Partnership was not named as a party in the suit, the lawsuit
states that this action relates to all wells operated by the Managing General
Partner, which includes a majority of the Partnership’s 36 wells in the
Wattenberg field.  The portion of the settlement relating to the
Partnership’s wells for all periods through September 30, 2009 that has been
expensed by the Partnership is approximately $78,000 including associated legal
costs of approximately $7,000.  This entire settlement of $70,954 was
deposited by the Managing General Partner into an escrow account on November 3,
2008.  Notice of the settlement was mailed to members of the class
action suit in the fourth quarter of 2008.  The final settlement was
approved by the court on April 7, 2009.  Settlement distribution
checks were mailed in July 2009.During September 2009, all
settlement costs were passed through to the Partners and related required
judicial action from the settlement of the suit was implemented in this
distribution.
 
 Colorado Stormwater
Permit.  On December 8, 2008, the Managing General Partner
received a Notice of Violation /Cease and Desist Order (the “Notice”) from the
Colorado Department of Public Health and Environment, related to the stormwater
permit for the Garden Gulch Road.  The Managing General Partner
manages this private road for Garden Gulch LLC.  The Managing General
Partner is one of eight users of this road, all of which are oil and gas
companies operating in the Piceance region of Colorado.  Operating
expenses, including amounts arising from this notice, if any, are allocated
among the eight users of the road based upon their respective
usage.  The Partnership has 13 wells in this region.  The
Notice alleges a deficient and/or incomplete stormwater management plan, failure
to implement best management practices and failure to conduct required permit
inspections.  The Notice requires corrective action and states that
the recipient shall cease and desist such alleged violations.  The
Notice states that a violation could result in civil penalties up to $10,000 per
day.  The Managing General Partner’s responses were submitted on
February 6, 2009, and April 8, 2009.  No civil penalties have been
imposed or requested at this time.  Given the preliminary stage of
this proceeding and the inherent uncertainty in administrative actions of this
nature, the Managing General Partner is unable to predict the ultimate outcome
of this administrative action at this time and therefore no amounts have been
recorded on the Partnership’s financial records.
 
 Derivative
Contracts.  The Partnership is exposed to oil and natural gas
price fluctuations on underlying sales contracts should the counterparties to
the Managing General Partner’s derivative instruments not
perform.  The Managing General Partner has had no counterparty default
losses and expects full performance by the counterparties to these agreements in
the future.
  -13-
 Index
 
 PDC
2005-A LIMITED PARTNERSHIP
 NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
 September
30, 2009
 (unaudited)
 
 Note
7−Subsequent
Events
 
 The
Partnership evaluated the Partnership’s activities subsequent to September 30,
2009, through November 13, 2009 (the date the financial statements were issued),
and have concluded that no subsequent events have occurred that would require
recognition in the Partnership’s financial statements or disclosure in the notes
to the unaudited condensed financial statements.
  -14-
 Index
 
 PDC
2005-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 2005-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;
 ·
              the
      effect of natural gas and oil derivatives
  activities;
 ·
              conditions
      in the capital markets; and
 ·
              losses
      possible from pending or future
litigation.
 
 Further,
the Partnership urges you to carefully review and consider the cautionary
statements made in this report, the Partnership’s annual report on Form 10-K for
the year ended December 31, 2008 filed with the Securities and Exchange
Commission (“SEC”) on March 31, 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
2005-A Limited Partnership engages in the development, production and sale of
oil and natural gas.  The Partnership began oil and gas operations in
February 2005 and currently operates 49 gross (43.4 net) wells located in the
Rocky Mountain Region in the state of Colorado.  Of the Partnership’s
total well count, 48 are producing and one well is not producing due to
mechanical problems.  The Managing General Partner markets the
Partnership’s natural gas production to commercial end users, interstate or
intrastate pipelines or local utilities, primarily under market sensitive
contracts in which the price of natural gas sold varies as a result of market
forces.  PDC, on behalf of the Partnership through the D&O
Agreement, may enter into multi-year fixed price contracts or utilize
derivatives, including collars, swaps or basis protection swaps, in order to
offset some or all of the commodity price variability for particular periods of
time.  Seasonal factors, such as effects of weather on prices received
and costs incurred, and availability of pipeline capacity, owned by PDC or other
third parties, may impact the Partnership's results.  In addition,
both sales volumes and prices tend to be affected by demand factors with a
seasonal component.
  -15-
 Index
 
 PDC
2005-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
and nine months ended September 30, 2009, or the current three and nine month
periods and the three and nine months ended September 30, 2008, or the prior
three and nine month periods.
 
 Summary
      of Operating ResultsThree
      months ended September 30,
              
              
              Nine
      months ended September 30,2009
              
              
              2008
              
              
              Change
              
              
              2009
              
              
              2008
              
              
              ChangeNumber
      of producing wells (end of period)
              
              
              48
              
              
              
              49
              
              
              
              *
              
              
              
              48
              
              
              
              49
              
              
              
              *Production:  (1)Oil
      (Bbl)
              
              
              5,756
              
              
              
              6,335
              
              
              
              -9
              %
              
              
              18,859
              
              
              
              19,908
              
              
              
              -5
              %Natural
      gas (Mcf)
              
              
              197,809
              
              
              
              217,695
              
              
              
              -9
              %
              
              
              569,805
              
              
              
              612,518
              
              
              
              -7
              %Natural
      gas equivalents (Mcfe)  (2)
              
              
              232,345
              
              
              
              255,705
              
              
              
              -9
              %
              
              
              682,959
              
              
              
              731,966
              
              
              
              -7
              %Average
      Selling Price (excluding realized gain (loss) on
    derivatives)Oil
      (per Bbl)
              
              $
              54.34
              
              
              $
              107.71
              
              
              
              -50
              %
              
              $
              46.62
              
              
              $
              100.37
              
              
              
              -54
              %Natural
      gas (per Mcf)
              
              
              2.32
              
              
              
              6.80
              
              
              
              -66
              %
              
              
              2.44
              
              
              
              7.39
              
              
              
              -67
              %Natural
      gas equivalents (per Mcfe)
              
              
              3.32
              
              
              
              8.46
              
              
              
              -61
              %
              
              
              3.32
              
              
              
              8.92
              
              
              
              -63
              %Realized
      Gain (Loss) on Derivatives, netOil
      derivatives - realized gain (loss)
              
              $
              85,832
              
              
              $
              (81,797
              )
              
              
              205
              %
              
              $
              383,052
              
              
              $
              (221,235
              )
              
              
              *Natural
      gas derivatives - realized gain (loss)
              
              
              421,446
              
              
              
              133,333
              
              
              
              -216
              %
              
              
              1,603,556
              
              
              
              (284,749
              )
              
              
              *Total
      realized gain (loss) on derivatives, net
              
              $
              507,278
              
              
              $
              51,536
              
              
              
              *
              
              
              $
              1,986,608
              
              
              $
              (505,984
              )
              
              
              *Average
      Selling Price (including realized gain (loss) on
    derivatives)Oil
      (per Bbl)
              
              $
              69.25
              
              
              $
              94.80
              
              
              
              -27
              %
              
              $
              66.93
              
              
              $
              89.25
              
              
              
              -25
              %Natural
      gas (per Mcf)
              
              
              4.45
              
              
              
              7.41
              
              
              
              -40
              %
              
              
              5.25
              
              
              
              6.93
              
              
              
              -24
              %Natural
      gas equivalents (per Mcfe)
              
              
              5.51
              
              
              
              8.66
              
              
              
              -36
              %
              
              
              6.23
              
              
              
              8.23
              
              
              
              -24
              %Average
      cost per McfeProduction
      and operating costs  (3)
              
              $
              1.98
              
              
              $
              2.41
              
              
              
              -18
              %
              
              $
              1.74
              
              
              $
              2.13
              
              
              
              -19
              %Depreciation,
      depletion and amortization
              
              
              3.94
              
              
              
              2.54
              
              
              
              55
              %
              
              
              4.18
              
              
              
              2.69
              
              
              
              55
              %Revenues:Oil
      and natural gas sales
              
              $
              772,050
              
              
              $
              2,162,064
              
              
              
              -64
              %
              
              $
              2,267,638
              
              
              $
              6,526,487
              
              
              
              -65
              %Realized
      gain (loss) on derivatives, net
              
              
              507,278
              
              
              
              51,536
              
              
              
              *
              
              
              
              1,986,608
              
              
              
              (505,984
              )
              
              
              *Unrealized
      loss (gain) on derivatives, net
              
              
              (1,100,386
              )
              
              
              3,835,898
              
              
              
              -129
              %
              
              
              (3,400,498
              )
              
              
              1,352,206
              
              
              
              *Total
      revenues
              
              $
              178,942
              
              
              $
              6,049,498
              
              
              
              -97
              %
              
              $
              853,748
              
              
              $
              7,372,709
              
              
              
              -88
              %Operating
      costs and expenses:Production
      and operating costs
              
              $
              459,163
              
              
              $
              615,428
              
              
              
              -25
              %
              
              $
              1,186,398
              
              
              $
              1,562,466
              
              
              
              -24
              %Direct
      costs - general and administrative
              
              
              79,882
              
              
              
              91,967
              
              
              
              -13
              %
              
              
              348,751
              
              
              
              270,051
              
              
              
              29
              %Depreciation,
      depletion and amortization
              
              
              916,146
              
              
              
              649,914
              
              
              
              41
              %
              
              
              2,857,006
              
              
              
              1,970,078
              
              
              
              45
              %Accretion
      of asset retirement obligations
              
              
              4,624
              
              
              
              4,373
              
              
              
              6
              %
              
              
              13,872
              
              
              
              13,119
              
              
              
              6
              %Total
      operating costs and expenses
              
              $
              1,459,815
              
              
              $
              1,361,682
              
              
              
              7
              %
              
              $
              4,406,027
              
              
              $
              3,815,714
              
              
              
              15
              %(Loss)
      income from operations
              
              $
              (1,280,873
              )
              
              $
              4,687,816
              
              
              
              -127
              %
              
              $
              (3,552,279
              )
              
              $
              3,556,995
              
              
              
              -200
              %Interest
      expense
              
              
              (2,338
              )
              
              
              -
              
              
              
              *
              
              
              
              (2,338
              )
              
              
              -
              
              
              
              *Interest
      income
              
              
              11,848
              
              
              
              14,768
              
              
              
              -20
              %
              
              
              33,815
              
              
              
              49,063
              
              
              
              -31
              %Net
      (loss) income
              
              $
              (1,271,363
              )
              
              $
              4,702,584
              
              
              
              -127
              %
              
              $
              (3,520,802
              )
              
              $
              3,606,058
              
              
              
              -198
              %Cash
      distributions
              
              $
              1,796,951
              
              
              $
              1,697,758
              
              
              
              6
              %
              
              $
              4,403,453
              
              
              $
              4,306,497
              
              
              
              2
              %
 
 *Percentage
change not meaningful, equal to or greater than 250% or not
calculable.  Amounts may not calculate due to rounding.
 _______________
 (1)
              Production
      is determined by multiplying the gross production volume of properties in
      which the Partnership has an interest by the percentage of the leasehold
      or other property interest the Partnership
owns.
 (2)
              A
      ratio of energy content of natural gas and oil (six Mcf of natural gas
      equals one Bbl of oil) was used to obtain a conversion factor to convert
      oil production into equivalent Mcf of natural
  gas.
 (3)
              Production
      costs represent oil and gas operating expenses which include production
      taxes.
  -16-
 Index
  PDC
2005-A LIMITED PARTNERSHIP
 (A
West Virginia Limited Partnership)
 
 Definitions
used throughout Management’s Discussion and Analysis of Financial Condition and
Results of Operations:
 
 ·
              Bbl
      – One barrel or 42 U.S. gallons liquid
volume
 ·
              MBbl
      – One thousand barrels
 ·
              Mcf
      – One thousand cubic feet
 ·
              MMcf
      – One million cubic feet
 ·
              Mcfe
      – One thousand cubic feet of natural gas
  equivalents
 ·
              MMcfe
      – One million cubic feet of natural gas
  equivalents
 ·
              MMbtu
      – One million British Thermal Units
 
 Natural
gas prices rebounded somewhat from earlier in 2009, through September
2009.  The Partnership continued to experience the depressed natural
gas prices from the significant declines in late July 2008 through the end of
2008.  While the Partnership’s production decreased to 683 MMcfe for
the 2009 nine month period compared to 732 MMcfe for the same 2008 period, a
decrease of 7%, the Partnership’s average sales price declined $5.60 per Mcfe, a
decrease of 63%.  While the significant changes in commodity prices
have impacted the Partnership’s results of operations, the Managing General
Partner believes that it was successful in managing the Partnership’s operations
to reduce the negative impacts of lower prices through the Partnership’s
derivative positions. The Partnership’s realized derivative gains for the 2009
nine month period of $2.0 million added an average of $2.91 per Mcfe produced
during the 2009 nine month period.  At September 30, 2009, the
Managing General Partner estimates the net fair value of the Partnership’s open
derivative positions to be a net liability of $0.7 million.
 
 There
were two primary contributors to the $2.3 million decrease in oil and gas price
risk management, net.  A decrease in future prices at September 30,
2009 compared to December 30, 2008 resulted in a $4.8 million increase in
unrealized derivative losses.  This was partially offset by a $2.5
million increase in realized derivative gains which resulted from depressed
commodity prices for the 2009 nine month period, as compared to the higher
prices in the same 2008 period.  Unrealized gains and losses are
non-cash items and these non-cash charges to the Partnership’s statement of
operations will continue to fluctuate with the fluctuation in commodity prices
until the positions mature or are closed, at which time they will become
realized or cash items.  The Partnership has elected not to designate
any of the Partnership’s derivative instruments as hedges.  Under
hedge accounting, changes in the fair value of derivatives less amounts
reclassified to realized gains/losses are shown as other comprehensive income in
the statement of equity and not in the statement of operations.  While
the required accounting treatment of recording all changes in the fair value of
derivatives in the statement of operations, for derivatives that are not
designated as hedges, may result in significant swings in operating results over
the life of the derivatives, the combination of the settled derivative contracts
and the revenue received from the oil and gas sales at delivery are expected to
result in a more predictable cash flow stream than would the sales contracts
without the associated derivatives.
 
 The table
below, which demonstrates the markets’ expected volatility in commodity pricing,
sets forth the average NYMEX and CIG prices for the next 24 months (forward
curve) from the selected dates
 
 September
      30,
              
              
              March
      31,
              
              
              September
      30,
              
              
              October
      31,Commodity
              
              Index
              
              2008
              
              
              2009
              
              
              2009
              
              
              2009Natural
      gas: (per
      MMbtu)NYMEX
              
              $
              8.21
              
              
              $
              5.44
              
              
              $
              6.25
              
              
              $
              6.00CIG
              
              
              5.46
              
              
              
              4.15
              
              
              
              5.64
              
              
              
              5.49Oil:
      (per
      Bbl)
              
              NYMEX
              
              
              103.63
              
              
              
              59.35
              
              
              
              74.64
              
              
              
              81.26
  -17-
 Index
  PDC
2005-A LIMITED PARTNERSHIP
 (A
West Virginia Limited Partnership)
 
 Oil and Natural Gas
Sales
 
 Partnership
production decreased to 232 MMcfe and 683 MMcfe for the current year three and
nine month periods, respectively, from 256 MMcfe and 732 MMcfe for the prior
year three and nine month periods, respectively.  The Partnership’s
oil and gas sales revenue, excluding price risk management impact, for the
current three and nine month periods decreased from comparable periods by $1.4
million and $4.2 million, respectively, due to a significant decline in
commodity prices and decreased volumes.  For the current three and
nine month periods, approximately $1.2 million and $3.8 million, respectively,
of the decrease in oil and natural gas sales revenue, was due to pricing, and
$0.2 million and $0.4 million, respectively, was due to decreased
production
 
 The
Partnership expects to experience continued declines in both oil and natural gas
production volumes over the wells’ life cycles until such time that the
Partnership’s Wattenberg wells may be successfully
recompleted.  Subsequent to a successful recompletion, production will
once again begin to decline.
 
 Oil and Natural Gas
Pricing
 
 Financial
results depend upon many factors, particularly the price of oil and natural gas
and the Partnership’s ability to market its production
effectively.  Oil and natural gas prices are among the most volatile
of all commodity prices.  These price variations have a material
impact on the Partnership’s financial results.  Oil and natural gas
prices also vary by region and locality, depending upon the distance to markets,
and the supply and demand relationships in that region or
locality.  This can be especially true in the Rocky Mountain
Region.  The combination of increased drilling activity and the lack
of local markets have resulted in a local market oversupply situation from time
to time.  Like most producers in the region, the Partnership relies on
major interstate pipeline companies to construct these pipelines to increase
capacity, rendering the timing and availability of these facilities and
transportation capacity beyond the Partnership’s control.
 
 The price
the Partnership receives for the natural gas produced in the Rocky Mountain
Region is based on a variety of prices, which primarily includes natural gas
sold at CIG prices with a portion sold at Mid-Continent, San Juan Basin,
Southern California or other nearby region prices.  The CIG Index, and
other indices for production delivered to other Rocky Mountain pipelines, has
historically been less than the price received for natural gas produced in the
eastern regions, which is NYMEX based.  This negative differential has
narrowed in recent months and has even more recently become a positive
differential.  CIG was $1.79 lower than NYMEX in January 2009,
narrowed to close at $0.37 lower in October 2009 and has more recently closed
at$0.02 higher than NYMEX for November 2009.
 
 Oil and Gas Price Risk
Management, Net
 
 The
Managing General Partner uses oil and natural gas derivative instruments to
manage price risk for PDC as well as sponsored drilling
partnerships.  The Managing General Partner sets these instruments for
PDC, and the various partnerships managed by PDC.  Prior to September
30, 2008, as volumes produced changed, the mix between PDC and the partnerships
changed on a pro-rata basis.  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.
  -18-
 Index
 
 PDC
2005-A LIMITED PARTNERSHIP
 (A
West Virginia Limited Partnership)
 
 The
following table presents the primary composition of “Oil and gas price risk
management, net” for the periods described:
 
 Three
      months ended September 30,
              
              
              Nine
      months ended September 30,Oil
      and gas price risk management, net
              
              2009
              
              
              2008
              
              
              2009
              
              
              2008Realized
      gains (losses)Oil
              
              $
              85,832
              
              
              $
              (81,797
              )
              
              $
              383,052
              
              
              $
              (221,235
              )Natural
      Gas
              
              
              421,446
              
              
              
              133,333
              
              
              
              1,603,556
              
              
              
              (284,749
              )Total
      realized gain (loss), net
              
              
              507,278
              
              
              
              51,536
              
              
              
              1,986,608
              
              
              
              (505,984
              )Unrealized
      gains (losses)Reclassification
      of realized (gains) losses included in prior periods
      unrealized
              
              
              (513,607
              )
              
              
              559,832
              
              
              
              (1,557,047
              )
              
              
              127,926Unrealized
      loss (gain)  for the period
              
              
              (586,779
              )
              
              
              3,276,066
              
              
              
              (1,843,451
              )
              
              
              1,224,280Total
      unrealized loss (gain), net
              
              
              (1,100,386
              )
              
              
              3,835,898
              
              
              
              (3,400,498
              )
              
              
              1,352,206Oil
      and gas price risk management (loss), net
              
              $
              (593,108
              )
              
              $
              3,887,434
              
              
              $
              (1,413,890
              )
              
              $
              846,222
 
 Realized
gains recognized in the current year three and nine month periods, are a result
of lower oil and gas commodity prices at settlement date compared to the
respective contract price.  During the current year three month period, the
Partnership recorded unrealized derivative losses on the Partnership’s CIG basis
swaps of $0.4 million, as the forward basis differential between NYMEX and CIG
has continued to narrow and unrealized losses on the Partnership’s collars of $
0.1 million and natural gas swaps of $0.1 million as pricing curves have
rebounded slightly from prior periods.  During the current year nine
month period, the Partnership recorded unrealized derivative losses on its oil
swaps of $0.2 million, as the forward strip price of oil rebounded during the
quarter and on the Partnership’s CIG basis swaps of $1.5 million.  The
Partnership also recorded unrealized losses on the Partnership’s natural gas
swaps of $0.1 million as natural gas prices, which had declined in previous
quarters, have risen slightly above those price levels reflected in previous
forward curves.
 
 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.
  -19-
 Index
  PDC
2005-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 September 30, 2009, on the Partnership’s
production.  The Partnership’s production volumes for the three months
ended September 30, 2009 were 5,756 Bbls of oil and 197,809 Mcf of natural
gas.
 
 Collars
              
              
              Fixed-Price
      Swaps
              
              
              Basis
      Protection SwapsFloors
              
              
              CeilingsCommodity/
      Operating Area/ Index
              
              Quantity(Gas-MMbtu
      Oil-Bbls)
              
              
              Weighted
      Average Contract Price
              
              
              Quantity(Gas-MMbtu
      Oil-Bbls)
              
              
              Weighted
      Average Contract Price
              
              
              Quantity(Gas-MMbtu
      Oil-Bbls)
              
              
              Weighted
      Average Contract Price
              
              
              Quantity(Gas-MMbtu
      Oil-Bbls)
              
              
              Weighted
      Average Contract Price
              
              
              Fair
      Value At September 30,2009(1)Natural
      GasRocky
      Mountain RegionCIG4Q
      2009
              
              
              102,314
              
              
              $
              6.66
              
              
              
              102,314
              
              
              $
              8.17
              
              
              
              37,452
              
              
              $
              9.20
              
              
              
              -
              
              
              $
              -
              
              
              $
              414,0462010
              
              
              115,693
              
              
              
              6.65
              
              
              
              115,693
              
              
              
              8.10
              
              
              
              56,178
              
              
              
              9.20
              
              
              
              338,194
              
              
              
              1.88
              
              
              
              (59,975
              )2011
              
              
              53,565
              
              
              
              4.75
              
              
              
              53,565
              
              
              
              9.45
              
              
              
              -
              
              
              
              -
              
              
              
              393,011
              
              
              
              1.88
              
              
              
              (433,532
              )2012
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              407,691
              
              
              
              1.88
              
              
              
              (420,832
              )2013
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              373,459
              
              
              
              1.88
              
              
              
              (357,912
              )NYMEX2010
              
              
              15,514
              
              
              
              5.75
              
              
              
              15,514
              
              
              
              8.30
              
              
              
              319,707
              
              
              
              5.61
              
              
              
              -
              
              
              
              -
              
              
              
              (169,711
              )2011
              
              
              21,022
              
              
              
              5.75
              
              
              
              21,022
              
              
              
              8.30
              
              
              
              104,370
              
              
              
              6.96
              
              
              
              -
              
              
              
              -
              
              
              
              2,5502012
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              109,177
              
              
              
              6.96
              
              
              
              -
              
              
              
              -
              
              
              
              (4,902
              )Total
      Natural Gas
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              (1,030,268
              )OilRocky
      Mountain RegionNYMEX4Q
      2009
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              3,860
              
              
              
              90.52
              
              
              
              -
              
              
              
              -
              
              
              
              75,0262010
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              13,234
              
              
              
              92.96
              
              
              
              -
              
              
              
              -
              
              
              
              243,8282011
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              5,949
              
              
              
              70.75
              
              
              
              -
              
              
              
              -
              
              
              
              (38,506
              )Total
      Oil
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              280,348Total
      Natural Gas and Oil
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              $
              (749,920
              )
 
 (1)
Approximately 78% of the total fair value of the derivative instruments was
measured using significant unobserved inputs (Level 3 assets and liabilities).
See Note 4, Fair Value
Measurements, to the accompanying interim unaudited condensed financial
statements.
 
 During
late October 2009, the Managing General Partner entered into additional NYMEX
fixed-price gas swaps ($6.67 to $7.11) and NYMEX gas collars ($6.00-$6.10 floor:
$8.27-$8.60 ceiling) covering all monthly periods from November 2010 to December
2013. The Partnership will be allocated positions by the Managing General
Partner for MMbtu’s equal to the number of remaining MMbtu’s of basis protection
swaps at September 30, 2009 which were not previously covered by NYMEX
fixed-price gas swaps or gas collars.
 
 Production and Operating
Costs
 
 Generally,
production and operating costs vary either with total oil and natural gas sales
or production volumes.  Property and severance taxes are estimated by
the Managing General Partner based on rates determined using historical
information.  These amounts are subject to revision based on actual
amounts determined during future filings by the Managing General Partner with
the taxing authorities.  Property and severance taxes vary directly
with total oil and natural gas sales.  Transportation costs vary
directly with production volumes.  Fixed monthly well operating costs
increase on a per unit basis as production decreases per the historical decline
curve.  General oil field services and all other costs vary and can
fluctuate based on services required.  These costs include water
hauling and disposal, equipment repairs and maintenance, snow removal and
service rig workovers.
 
 For the
nine months ended September 30, 2009 compared to the same period in 2008, oil
and natural gas production, on an energy equivalency-basis, decreased 7%, due to
reduced production resulting from the Wattenberg Field’s second quarter 2009
high pipeline pressure in addition to normally-occurring production declines
throughout an oil and natural gas well’s production life
cycle.  Production and operating costs were lower by $0.4 million, or
24%, due to volume-associated reductions of $0.1 million in production taxes,
natural gas transport and lease operating expenses.  In addition to volume
associated production tax decreases, lower commodity valuations further reduced
production taxes by approximately $0.4 million. However, lease operating costs
increased by $0.1 million due to a well site remediation required by the state
of Colorado which offset lower third-party costs of well service providers and
Managing General Partner’s cost reduction initiatives.  Production and
operating costs per Mcfe were $1.74 for the nine months ended September 30, 2009
compared to $2.13 for the comparable period in 2008.
  -20-
 Index
 
 PDC
2005-A LIMITED PARTNERSHIP
 (A
West Virginia Limited Partnership)
 
 For the
three months ended September 30, 2009, compared to the same period in 2008, oil
and natural gas production declined 9% which reduced volume-associated
expenditures by $0.1 million.  Along with reduced volume-associated
expenditures, a decrease of approximately $0.1 million in production-related
taxes due to lower commodity valuations, decreased overall production and
operating costs by $0.2 million.  Production and operating costs per
Mcfe were $1.98 and $2.41 for the three month period ended September 30, 2009
and 2008, respectively.
 
 Direct Costs−General and
Administrative
 
 Direct
costs – general and administrative consist primarily of professional fees for
financial statement audits, income tax return preparation and legal
matters.  Direct costs remained substantially unchanged during the
three months ended September 30, 2009, compared to the same period in 2008, but
increased by $0.1 million during the nine months ended September 30, 2009,
compared to the same period in 2008, primarily due to an increase in
professional fees for audit and legal services.
 
 Depreciation, Depletion and
Amortization
 
 Depreciation,
depletion and amortization (DD&A) expense results solely from the
depreciation, depletion and amortization of well equipment and lease
costs.  The calculation of DD&A expense is directly related to
reserves and production volumes.  DD&A expense is primarily based
upon year-end proved developed producing oil and gas reserves.  These
reserves are 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 may 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 may
decrease resulting in increases in the rate of DD&A expense per unit of
production.
 
 The
DD&A rate per Mcfe increased to $3.94 and $4.18 for the three and nine month
periods ended September 30, 2009, respectively, compared to $2.54 and $2.69
during the same periods ended September 30, 2008.  These increased
rates, offset by lower production volumes, resulted in increases of $0.2 million
and $0.9 million in DD&A for the three and nine months ended September 30,
2009 compared to same periods in 2008, respectively.  This is
primarily the result of production level decreases of 9% and 7% for each of the
three and nine month periods ended September 30, 2009, offset by an increase in
per Mcfe expense due to lower proved developed reserves at December 31, 2008
compared to December 31, 2007.  While production and overall year-end
reserves are expected to decline gradually year-to-year over the wells’
remaining life cycles, downward revisions to proved developed oil and natural
gas reserves in the annual 2008 reserve report, resulted in the increased
DD&A unit cost increases during the three and nine month periods ended
September 30, 2009 as compared to the same periods in 2008.
 
 Interest
Expense
 
 The
Partnership incurred interest expense of approximately $2,300 for the three and
nine months ended September 30, 2009, related to amounts funded by the Managing
General Partner in November 2008, into escrow on behalf of the Partnership,
which were subsequently paid to Colorado Royalty Settlement litigants in July
2009.  Interest rates paid by the Partnership were determined in
accordance with the Applicable Federal Interest Rate applicable to Qualified
Legal Settlements under Internal Revenue Code §468B.  For more
information on the Colorado Royalty Settlement, see Note 6, Commitments and
Contingencies, to the accompanying unaudited condensed financial
statements and Note 2, Summary
of Significant Accounting Policies, Due from (to) Managing General Partner –
other, net, to the 2008 Form 10-K.
  -21-
 Index
  PDC
2005-A LIMITED PARTNERSHIP
 (A
West Virginia Limited Partnership)
 
 Interest
Income
 
 Significantly
lower undistributed revenues held by the Managing General Partner, and
significantly lower interest rates applied to those undistributed amounts,
resulted in lower interest income during the three and nine months ended
September 30, 2009, compared to the same periods in 2008.
 
 Liquidity and Capital
Resources
 
 Oil and
gas production from the Partnership’s existing properties declined rapidly in
the first two years (2006 through 2007) and is expected to continue to
decline gradually over the remaining lives of the wells.  Therefore
the Partnership may be unable to maintain its current level of oil and gas
production and cash flows from operations if commodity prices remain in their
current depressed state for a prolonged period beyond 2009.  This
decreased production would have a material negative impact on the Partnership’s
operations and may result in reduced cash distributions to the Investor Partners
in 2010 and beyond.
 
 Working
Capital
 
 Working
capital at September 30, 2009 was $1.2 million compared to working capital of
$4.3 million at December 31, 2008.  This decrease of $3.1 million was
primarily due to the reduction of receivables at September 30, 2009 for realized
and short-term net unrealized derivative gains which decreased $0.3 million and
$0.6 million, respectively, from the amounts at December 31, 2008 of $0.7
million and $2.1 million, respectively. In addition, receivables from oil and
gas sales at September 30, 2009 of $0.5 million decreased compared to
receivables of $0.9 million at December 31, 2008.  In September 2009,
there was a net reduction of $1.1 million in amounts due from the Managing
General Partner as a $1.2 million receivable for over-withheld production taxes
related to Partnership production prior to 2007 was collected.  In
addition, the Partnership settled the obligation for the Colorado Royalty
Settlement of $0.1 million with the Managing General Partner.  For
more information on the Colorado Royalty Settlement see Note 6, Commitments and Contingencies
to the accompanying interim unaudited condensed financial
statements.  The net cash impact of these transactions increased
distributions by $1.2 million during the quarter.
 
 Cash
Flows From Investing Activities
 
 The
Partnership, from time-to-time, invests in additional equipment which supports
treatment, delivery and measurement of oil and gas or environmental
protection.  These amounts totaled approximately $26,000 for the nine
months ended September 30, 2009.  The Partnership received an
approximately $109,000 drilling advance refund from the Managing General Partner
during the nine month period ended September 30, 2009.
  -22-
 Index
 
 PDC
2005-A LIMITED PARTNERSHIP
 (A
West Virginia Limited Partnership)
 
 Cash
Flows From Financing Activities
 
 The
Partnership initiated monthly cash distributions to investors in September 2005
and has distributed $39.3 million through September 30, 2009.  The
table below sets forth the cash distributions to the Managing General Partner
and Investor Partners including Managing General Partner distribution relating
to limited partnership units repurchased for the periods described as
follows:
 
 Three
      months ended September 30,2009
              
              
              2008Managing
      General Partner Distributions
              
              
              Investor Partners
      Distributions
              
              
              Total
      Distributions
              
              
              Managing
      General Partner Distributions
              
              
              Investor
      Partners Distributions
              
              
              Total
      Distributions$
              359,390
              
              
              $
              1,437,561
              
              
              $
              1,796,951
              
              
              $
              339,552
              
              
              $
              1,358,206
              
              
              $
              1,697,758
 
 Nine
      months ended September 30,2009
              
              
              2008Managing
      General Partner Distributions
              
              
              Investor Partners
      Distributions
              
              
              Total
      Distributions
              
              
              Managing
      General Partner Distributions
              
              
              Investor Partners
      Distributions
              
              
              Total
      Distributions$
              880,689
              
              
              $
              3,522,764
              
              
              $
              4,403,453
              
              
              $
              861,298
              
              
              $
              3,445,199
              
              
              $
              4,306,497
 
 Investor
Partner cash distributions include $8,742 and $29,444 during the three and nine
months ended September 30, 2009, respectively, and $5,566 and $11,717 during the
three and nine months ended September 30, 2008, respectively, related to equity
cash distributions on Investor Partner units repurchased by the Managing General
Partner.
 
 Cash
Flows From Operating Activities
 
 The
Partnership’s operations are expected to be conducted with available funds and
revenues generated from its oil and natural gas production
activities.  Changes in cash flow from operations are largely due to
the same factors that affect the Partnership’s net income that are more fully
discussed under Results of
Operations, excluding the non-cash items depreciation, depletion and
amortization and unrealized gains and losses on derivative
transactions.  Based on current oil and natural gas prices and prices
set by derivatives, and the Partnership’s anticipated production, the
Partnership expects positive cash flows from operations for the remainder of
2009.
 
 Changes
in market prices for oil and natural gas, the Partnership’s production levels,
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 nine months ended September 30, 2009 were
approximately 65% lower than the same period in the prior year, resulting from a
63% decrease in average oil and natural gas prices and a 7% 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 90% of the Partnership’s expected oil production
and 73% of its expected natural gas production for the remainder of 2009, at
average prices of $90.52 per Bbl and $7.34 per Mcf,
respectively.  These contracts reduce the impact of price changes on
cash provided by operations for a substantial portion of the expected production
for the remainder of 2009.  However, the remaining 10% and 27% 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 investors’ view of underlying oil and
natural gas supply and demand trends and changes in volumes
produced.  Partnership oil and natural gas derivatives as of September
30, 2009 are detailed in Note 5, Derivative Financial
Instruments to the accompanying interim unaudited condensed financial
statements.
  -23-
 Index
 
 PDC
2005-A LIMITED PARTNERSHIP
 (A
West Virginia Limited Partnership)
 
 Net cash
provided by operating activities was $4.2 million for the nine months ended
September 30, 2009, unchanged from the comparable period in
2008.  Fluctuations between the two periods in component activity
determining cash provided by operating activities are as follows:
 
 ·
              A
      decrease in oil and gas sale revenues of $4.3 million, or 65%, accompanied
      by increases in direct costs – general and administrative of $0.1 million;
      and
 
 ·
              An
      increase in realized oil and gas price risk management, net of $2.5
      million and a decrease in production and operating cost of $0.4 million or
      24%.
 
 ·
              A
      reduction in Due from Managing General Partner – other, net, of $1.1
      million in September 2009, due to the Managing General Partner’s $1.2
      million collection of receivables for over-withheld production taxes
      related to Partnership production prior to 2007, which was offset by the
      Partnership’s $0.1 million payment to the Managing General Partner for
      royalty settlement costs.  For more information on the Colorado
      Royalty Settlement see Note 6, Commitments and
      Contingencies to the accompanying interim unaudited condensed
      financial statements.
 
 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
provide for additional reserve development and production, generally occur five
to seven years after initial well drilling so that well resources are optimally
utilized.  These well recompletions would be expected to
occur based on a favorable general economic environment and commodity
price structure. Since borrowing is not permitted by the Limited
Partnership Agreement, well recompletion activities will be funded through
the retention of revenues and reduction of Partner cash distributions. 
There are
no immediate plans to initiate recompletion activities in the Wattenberg Field
wells owned by the Partnership.  As the optimal period approaches, the
Managing General Partner will re-evaluate the feasibility of commencing those
recompletions based on engineering data and a favorable commodity price
environment in order to maximize the financial benefit of the
recompletion.  However, no assurances can be given that recompletion
activities will be feasible or economic.
 Commitments and
Contingencies
 
 See Note
6, Commitments and
Contingenciesto the accompanying unaudited condensed financial
statements.
 
 Recent Accounting
Standards
 
 See Note
2, Recent Accounting
Standards to the accompanying unaudited condensed financial statements,
included in this report for recent accounting standards.
 
 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.
  -24-
 Index
 
 PDC
2005-A LIMITED PARTNERSHIP
 (A
West Virginia Limited Partnership)
 
 Item
3.     Quantitative and Qualitative
Disclosures About Market Risk
 
 Not
Applicable
 
 
 Item
4T.   Controls and Procedures
 
 The
Partnership has no direct management or officers.  The management,
officers and other employees that provide services on behalf of the Partnership
are employed by the Managing General Partner.
 
 2008 Material
Weakness
 
 As
discussed in the Management’s
Report on Internal Control Over Financial Reporting included in the
Partnership’s 2008 Annual Report on Form 10-K, the Partnership did not maintain
effective internal controls over financial reporting as of December 31, 2008,
over transactions that are directly related to and processed by the Partnership,
in that the Partnership failed to maintain sufficient documentation to
adequately assess the operating effectiveness of internal control over financial
reporting.  More specifically, the Partnership’s financial close and
reporting narrative failed to adequately describe the process, identify key
controls and assess segregation of duties.  This material weakness has
not been remediated as of September 30, 2009.  The 2008 Annual Report
on Form 10-K did not include an attestation report of the Partnership’s
independent registered public accounting firm regarding internal control over
financial reporting pursuant to Item 308T (a)(4) of Regulation
S-K.   Pursuant to Final Order dated October 19, 2009, temporary
Item 308T was extended through December 15, 2010.  Accordingly, the
Partnership will file the attestation report of the Partnership’s independent
registered public accounting firm regarding internal control with the
Partnership’s Annual Report on Form 10-K as of December 31, 2010.
 
 (a)  Evaluation of Disclosure
Controls and Procedures
 
 As of
September 30, 2009, PDC, as Managing General Partner on behalf of the
Partnership, carried out an evaluation, under the supervision and with the
participation of the Managing General Partner's management, including its Chief
Executive Officer and Chief Financial Officer, of the effectiveness of the
design and operation of the Partnership's disclosure controls and procedures
pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e).  This
evaluation considered the various processes carried out under the direction of
the Managing General Partner’s Disclosure Committee in an effort to ensure that
information required to be disclosed in the SEC reports the Partnership files or
submits under the Exchange Act is recorded, processed, summarized and reported,
within the time periods specified in the SEC’s rules and forms, and that such
information is accumulated and communicated to the Partnership’s management,
including its principal executive and principal financial officers, as
appropriate to allow timely decisions regarding required
disclosure.
 
 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 September 30, 2009 due to the existence of
the material weakness described above in 2008 Material Weakness
included in this Item 4 (T).  Because of the nature of the material
weakness noted, the Partnership is not able to quantify the dollar amounts of
exposure or potential range of the dollar amount of potential revisions to the
financial statements, from this material weakness.
 
 (b)  Remediation of Material
Weakness in Internal Control
 
 PDC, the
Managing General Partner, with participation from the Audit Committee of its
Board of Directors, has been addressing the material weakness disclosed in the
Partnership’s 2008 Annual Report on Form 10-K.  The Managing General
Partner believes that with effective implementation of planned changes in
internal controls over financial reporting outlined below, that it will be able
to remediate this known material weakness as of December 31,
2009.  However, this control weakness will not be considered
remediated until the changes in internal controls over financial reporting are
operating effectively for a sufficient period of time and the Managing General
Partner has concluded, through testing, that these controls are operating
effectively.
  -25-
 Index
 
 PDC
2005-A LIMITED PARTNERSHIP
 (A
West Virginia Limited Partnership)
 
 The
Partnership made the following 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 September 30, 2009.
 
 The
Partnership developed documentation that materially describes the business
processes and identifies key controls for internal control over financial
reporting that will assist the Managing General Partner in adequately assessing
the control over financial reporting for the Partnership.  In
addition, the Partnership developed documentation to adequately assess
segregation of duties.  At present, the Partnership has not quantified
the total cost of this initiative; however the majority of this cost is expected
to be paid by the Managing General Partner.
 
 Until
PDC, the Managing General Partner, is able to conclude that the Partnership has
remediated this known material weakness in internal control over financial
reporting, the Managing General Partner will continue to perform additional
analysis and procedures in order to ensure that the Partnership’s financial
statements contained in its subsequent SEC filings are prepared in accordance
with generally accepted accounting principles in the United States.
 
 (c)  Other Changes in Internal
Control over Financial Reporting
 
 During
the 2009 third quarter, PDC made the following changes in PDC’s internal control
over financial reporting (as such defined in Rules 13a-15(f) and 15d-15(f) of
the Securities Exchange Act of 1934) that have materially affected or are
reasonably likely to materially affect the Partnership’s internal control over
financial reporting:
 
 ·
              Effective
      July 1, 2009, as part of PDC’s broader financial reporting system, PDC
      implemented a new partnership investor distribution accounting module to
      the existing accounting software.  PDC has taken the necessary
      steps to monitor and maintain appropriate internal controls during this
      period of change.  These steps included procedures to preserve
      the integrity of the data converted and a review by the business owners to
      validate data converted.  Additionally, PDC provided training
      related to the business process changes and the financial reporting system
      software to individuals using the financial reporting system to carry out
      their job responsibilities, as well as, those who rely on the financial
      information.  PDC anticipates that the implementation of this
      module will strengthen the overall systems of internal controls due to
      enhanced automation and integration of related processes.  PDC
      is modifying the design and documentation of internal control process and
      procedures relating to the new module to supplement and complement
      existing internal control over financial reporting.  The system
      changes were undertaken to integrate systems and consolidate information
      and were not undertaken in response to any actual or perceived
      deficiencies in PDC’s internal control over financial
      reporting.  Testing of the controls related to these new systems
      is ongoing and is included in the scope of PDC’s assessment of its
      internal control over financial reporting for
  2009.
 
 The
Managing General Partner continues to evaluate the ongoing effectiveness and
sustainability of the changes PDC made 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.
  -26-
 Index
 
 PDC
2005-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 September 2008, the third anniversary of
the date of the first Partnership cash distributions, Investor Partners of the
Partnership may request that the Managing General Partner repurchase their
respective individual Investor Partner units, up to an aggregate total limit
during any calendar year for all requesting Investor Partner unit repurchases of
10% of the initial subscription units.
 
 In the
third quarter of 2009, July repurchases by PDC totaled 0.5 units at an average
price of $8,890 per unit.  There were no repurchases in August or
September 2009.
 
 Other
Repurchases:  Individual investor partners periodically offered
and PDC repurchased, units on a negotiated basis before the third anniversary of
the date of the first cash distribution.
 
 
 Items
3, 4 and 5 have been omitted as there is nothing to
report.
  -27-
 Index
 
 PDC
2005-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 (filed by PDC as Managing General Partner for PDC
      2004-2006 Drilling Program)
              
              S-1
      Post-Effective Amend 2
              
              333-111260
              
              Appendix
      A
              
              06/29/20053.2
              
              Certificate
      of limited partnership which reflects the organization of the Partnership
      under West Virginia law
              
              10-K
              
              000-51309
              
              3.2
              
              02/26/200910.1
              
              Drilling
      and operating agreement between the Partnership and PDC,
      the Managing General Partner of the Partnership
              
              10-K
              
              000-51309
              
              10.1
              
              02/26/200931.1
              
              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
  -28-
 Index
 
 PDC
2005-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
2005-A Limited Partnership
 By its
Managing General Partner
 Petroleum
Development Corporation
 
 By:
      /s/ Richard W. McCulloughRichard
      W. McCullough
                Chairman
      and Chief Executive Officer
                November
      13, 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
              
              November
      13, 2009Richard
      W. McCullough
              
              Petroleum
      Development CorporationManaging
      General Partner of the Registrant(Principal
      executive officer)/s/
      Gysle R. Shellum
              
              Chief
      Financial Officer
              
              November
      13, 2009Gysle
      R. Shellum
              
              Petroleum
      Development CorporationManaging
      General Partner of the Registrant(Principal
      financial officer)/s/
      R. Scott Meyers
              
              Chief
      Accounting Officer
              
              November
      13, 2009R.
      Scott Meyers
              
              Petroleum
      Development CorporationManaging
      General Partner of the Registrant(Principal
      accounting officer)


-29-