PDC 2005-A LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)
 
 UNITED STATES
 SECURITIES AND EXCHANGE COMMISSION
 WASHINGTON, DC 20549
 
 FORM 10-Q
 
 S  QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 For the quarterly period ended March 31, 2009
 or
 
 £TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD ____________ TO ____________
 
 Commission File Number   000-51309
 
 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  S  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     S
 
 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes £  No S
 
 As of April 30, 2009 the Partnership had 1,996.87 units of limited partnership interest and no units of general partnership interest outstanding.
  
 
 
  PDC2005-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
13Item 3.

Quantitative and Qualitative Disclosures About Market Risk
21Item 4T.

Controls and Procedures
21PART II – OTHER INFORMATIONItem 1.

Legal Proceedings
22Item 1A.

Risk Factors
22Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds
22Item 3.

Defaults Upon Senior Securities
22Item 4.

Submission of Matters to a Vote of Security Holders
22Item 5.

Other Information
22Item 6.

Exhibits
23SIGNATURES
24
 Index
  PART I – FINANCIAL INFORMATION
 
 Item1.
Condensed Financial Statements (unaudited)
 
 PDC2005-A Limited Partnership
 Condensed Balance Sheets
 (unaudited)
 
 March 31,


December 31,2009


2008*AssetsCurrent assets:Cash and cash equivalents

$
316,467


$
314,610Accounts receivable


248,335



318,421Oil inventory


29,456



30,950Due from Managing General Partner-derivatives


2,434,504



2,100,443Due from Managing General Partner-other, net


1,988,279



1,590,959Total current assets


5,017,041



4,355,383Oil and gas properties, successful efforts method


44,283,564



44,267,285Drilling advances to Managing General Partner


108,531



108,531Oil and gas properties, at cost


44,392,095



44,375,816Less:  Accumulated depreciation, depletion and amortization


(18,395,787
)


(17,313,642
)Oil and gas properties, net


25,996,308



27,062,174Due from Managing General Partner-derivatives


313,941



716,092Total noncurrent assets


26,310,249



27,778,266Total Assets

$
31,327,290


$
32,133,649Liabilities and Partners' EquityCurrent liabilities:Accounts payable and accrued expenses

$
58,395


$
66,607Total current liabilities


58,395



66,607Due to Managing General Partner-derivatives


1,032,708



165,957Asset retirement obligations


385,884



381,260Total liabilities


1,476,987



613,824Commitments and contingenciesPartners' equity:Managing General Partner


5,985,044



6,318,947Limited Partners - 1,996.87 units issued and outstanding


23,865,259



25,200,878Total Partners' equity


29,850,303



31,519,825Total Liabilities and Partners' Equity

$
31,327,290


$
32,133,649*Derived from audited 2008 balance sheet.
 
 
 See accompanying notes to unaudited condensed financial statements.
  - 1 -
 Index
  PDC2005-A Limited Partnership
 Condensed Statements of Operations
 (unaudited)
 
 Three months ended March 31,2009


2008Revenues:Oil and gas sales

$
863,692


$
1,786,187Oil and gas price risk management loss, net


(40,244
)


(605,227
)Total revenues


823,448



1,180,960Operating costs and expenses:Production and operating costs


318,164



406,728Direct costs - general and administrative


151,967



8,832Depreciation, depletion and amortization


1,082,145



646,183Accretion of asset retirement obligations


4,624



4,373Total operating costs and expenses


1,556,900



1,066,116(Loss) income from operations


(733,452
)


114,844Interest income


11,700



18,162Net (loss) income

$
(721,752
)

$
133,006Net (loss) income allocated to partners

$
(721,752
)

$
133,006Less: Managing General Partner interest in net (loss) income


(144,350
)


26,601Net (loss) income allocated to Investor Partners

$
(577,402
)

$
106,405Net (loss) income per Investor Partner unit

$
(289
)

$
53Investor Partner units outstanding


1,996.87



1,996.87
 
 
 See accompanying notes to unaudited condensed financial statements.
  - 2 -
 Index
  PDC2005-A Limited Partnership
 Condensed Statements of Cash Flows
 (unaudited)
 
 Three months ended March 31,2009


2008Cash flows from operating activities:Net (loss) income

$
(721,752
)

$
133,006Adjustments to reconcile net (loss) income to net cash provided by operating activities:Depreciation, depletion and amortization


1,082,145



646,183Accretion of asset retirement obligations


4,624



4,373Unrealized loss on derivative transactions


934,841



535,140Changes in operating assets and liabilities:Decrease in accounts receivable


70,086



89,534Decrease (increase) in oil inventory


1,494



(47,306
)(Decrease) increase in accounts payable and accrued expenses


(8,212
)


89,771Increase in due from Managing General Partner-other, net


(397,320
)


(243,607
)Net cash provided by operating activities


965,906



1,207,094Cash flows from investing activities:Capital expenditures for oil and gas properties


(16,279
)


(22,395
)Net cash used in investing activities


(16,279
)


(22,395
)Cash flows from financing activities:Distributions to Partners


(947,770
)


(1,178,066
)Net cash used in investing activities


(947,770
)


(1,178,066
)Net increase in cash and cash equivalents


1,857



6,633Cash and cash equivalents, beginning of period


314,610



164,781Cash and cash equivalents, end of period

$
316,467


$
171,414
 
 
 See accompanying notes to unaudited condensed financial statements.
  - 3 -
 Index
  PDC2005-A LIMITED PARTNERSHIP
 NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
 March 31, 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 its 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, it 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.  Petroleum Development Corporation, a Nevada Corporation, is the Managing General Partner of the Partnership (hereafter, the “Managing
General Partner,” “MGP” or “PDC”) and has a 20% ownership in the Partnership.  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.  Additionally, the Agreement provides for a preferred cash distribution
to Investor Partners during the first 10 years of the Partnership’s operations if the average annual return to Investor Partners falls below 12.5% of their subscriptions.  There have been no preferred cash distributions under this provision to date.
 
 As of April 30, 2009, there were 1,507 Investor Partners.  As of April 30, 2009, the Managing General Partner has repurchased 22.75 units of the total 1,996.87 outstanding units of Partnership interests from Investor Partners at an average price of $9,991 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.
 
 In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), the Managing General Partner manages all activities of the Partnership and acts as the intermediary for substantially all Partnership transactions.  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.
 
 The accompanying interim unaudited condensed financial statements have been prepared without audit in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Article 8 of Regulation S-X of the Securities and Exchange Commission,
or SEC. Accordingly, pursuant to certain rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted.  In the Partnership’s opinion, the accompanying interim unaudited condensed financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the Partnership's financial position, results of operations and cash flows for the periods presented.  The
interim results of operations and cash flows for the three months ended March 31, 2009 and 2008 are not necessarily indicative of the results to be expected for the full year or any other future period.
 
 The accompanying condensed balance sheet as of December 31, 2008, was derived from audited financial statements, but as indicated above, may not include all disclosures required by accounting principles generally accepted in the United States of America  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 April 28, 2009.
 
 Note 2−Recent Accounting Standards
 
 Recently Adopted Accounting Standards
 
 In December 2007, the Financial Accounting Standards Board, or FASB, issued Statement of Financial Accounting Standards, or FAS, No. 141 (revised 2007), Business Combinations, or FAS No. 141(R).  FAS No. 141(R) requires an acquirer to recognize the assets acquired, the
liabilities assumed and any noncontrolling interest in the acquiree at their acquisition-date fair values.  FAS No. 141(R) also requires disclosure of the information necessary for investors and other users to evaluate and understand the nature and financial effect of the business combination.  Additionally, FAS No. 141(R) requires that acquisition-related costs be expensed as incurred.  The provisions of FAS No. 141(R) are effective for acquisitions completed on or after January
1, 2009; however, the income tax provisions of FAS No. 141(R) became effective as of that date for all acquisitions, regardless of the acquisition date.  FAS No. 141(R) amends FAS No. 109, Accounting for Income Taxes, to require the acquirer to recognize changes in the amount of its deferred tax benefits recognizable due to a business combination either in income from continuing operations in the period of the combination or directly in contributed capital, depending on the circumstances.  FAS
No. 141(R) further amends FAS No. 109 and FIN 48, Accounting for Uncertainty in Income Taxes, to require, subsequent to a prescribed measurement period, changes to acquisition-date income tax uncertainties to be reported in income from continuing operations and changes to acquisition-date acquiree deferred tax benefits to be reported in income from continuing operations or directly in contributed capital, depending on the circumstances.  In April 2009, the FASB issued FASB Staff Position, or FSP, No.
FAS 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies, amending the guidance of FAS No. 141(R) to required that assets acquired and liabilities assumed in a business combination that arise from contingencies be recognized at fair value if fair value can be reasonably estimated and if not, the asset and liability would generally be recognized in accordance with FAS No. 5, Accounting
for Contingencies, and FASB Interpretation No. 14, Reasonable Estimation of the Amount of a Loss.  Further, FSP 141(R)-1 requires that certain acquired contingencies be treated as contingent consideration and measured both initially and subsequently at fair value.  The Partnership’s adoption of the provisions of FAS No. 141(R) and FSP 141(R)-1 effective January 1, 2009 had no impact on the Partnership’s financial statements.
  - 4 -
 Index
  PDC 2005-A LIMITED PARTNERSHIP
 NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
 March 31, 2009
 (unaudited)
 
 In December 2007, the FASB issued FAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—An Amendment of ARB No. 51.  FAS No. 160 states that accounting and reporting for minority interests will be recharacterized as non-controlling interests and
classified as a component of equity.  Additionally, SFAS No. 160 establishes reporting requirements that provide sufficient disclosures which clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners.  The Partnership’s adoption of the provisions of FAS No. 160 effective January 1, 2009 did not have a material impact on the Partnership’s financial statements.
 
 In February 2008, the FASB issued FSP No. 157-2, Effective Date of FASB Statement No. 157, which delayed the effective date of FAS No. 157, Fair Value Measurements, by one year (to January 1, 2009) for nonfinancial assets and
liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).  Effective January 1, 2009, the Partnership adopted the provisions of FAS No. 157 delayed by FSP 157-2.  The adoption of FSP 157-2 did not have a material impact on the Partnership’s financial statements.  See Note 5, Fair Value Measurements.
 
 In March 2008, the FASB issued FAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—An Amendment of FASB Statement No. 133, which changes the disclosure requirements for derivative instruments and hedging activities.  Enhanced disclosures are
required to provide information about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows.  The Partnership’s adoption of FAS No. 161 effective January 1, 2009, did not have a material impact on the Partnership’s financial
statements.  For more information on the Partnership’s derivative accounting, see Note 4, Derivative Financial Instruments.
 
 Recently Issued Accounting Standards
 
 On April 9, 2009, the FASB issued two amendments to the fair value measurement and disclosure standards:
 
 ·
FSP No. FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly and
 ·
FSP No. FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments.
  - 5 -
 Index
  PDC 2005-A LIMITED PARTNERSHIP
 NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
 March 31, 2009
 (unaudited)
 
 FSP 157-4 affirms that the objective of fair value when the market for an asset is not active is the price that would be received to sell the asset in an orderly transaction; clarifies and includes additional factors for determining whether there has been a significant decrease in market activity for an asset when the market for that asset
is not active; eliminates the proposed presumption that all transactions are distressed (not orderly) unless proven otherwise and instead requires an entity to base its conclusion about whether a transaction was not orderly on the weight of the evidence; requires an entity to disclose a change in valuation technique (and the related inputs) resulting from the application of the FSP and to quantify its effects, if practicable; and applies to all fair value measurements when appropriate.
 
 FSP 107-1/APB 28-1 amends FAS No. 107, Disclosures about Fair Value of Financial Instruments, to require an entity to provide disclosures about fair value of financial instruments in interim financial information.  This FSP also amends Accounting Principles Board, or APB,
Opinion No. 28, Interim Financial Reporting, to require those disclosures in summarized financial information at interim reporting periods.  Pursuant to this FSP, a reporting entity shall include disclosures about the fair value of its financial instruments whenever it issues summarized financial information for interim reporting periods.  In addition, an entity shall disclose in the body or in the accompanying notes of its summarized
financial information for interim reporting periods and in its financial statements for annual reporting periods, the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position, as required by SFAS No. 107.
 
 These two amendments to fair value measurements and disclosure standards, FSP 157-4 and FSP 107-1/APB 28-1, are effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009.  However, early adoption is allowed only if certain FSPs are early-adopted
together: an entity early-adopting FSP 157-4 must also early-adopt FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments (and an entity early adopting FSP 107-1/APB 28-1 must also elect to early-adopt FSP 157-4 and FSP 115-2/124-4).  The Partnership does not expect these FSPs to have a significant impact on the Partnership’s financial statements when adopted on April 1, 2009.
 
 In January 2009, the SEC published its final rule, Modernization of Oil and Gas Reporting, which modifies the SEC’s reporting and disclosure rules for oil and natural gas reserves.  The most notable changes of the final rule include the replacement of the single day
period-end pricing to value oil and natural gas reserves to a 12-month average of the first day of the month price for each month within the reporting period.  The final rule also permits voluntary disclosure of probable and possible reserves, a disclosure previously prohibited by SEC rules.  The revised reporting and disclosure requirements are effective for the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009.  Early adoption is not permitted.  The
Managing General Partner 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.  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 caption “Due from Managing General Partner–derivatives,” in the case of net unrealized gains or the “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 $615,360 and $565,638 as of March 31, 2009 and December 31, 2008, respectively, are included in the balance sheet caption “Due from Managing General Partner - other, net.”  Realized
gains or losses 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 $894,597 and $738,074 as of March 31, 2009 and December 31, 2008, respectively.  At May 14, 2009, unsettled amounts due from derivative counterparties related to undistributed realized gains at March
31, 2009 were approximately $40,000.  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.”
  - 6 -
 Index
  PDC 2005-A LIMITED PARTNERSHIP
 NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
 March 31, 2009
 (unaudited)
 
 The following table presents transactions with the Managing General Partner and its affiliates for the periods described below.  Additionally, refer to Note 4, Derivative Financial Instruments for derivative transactions between the Partnership and the Managing General
Partner.
 
 Three months ended March 31,2009


2008Well charges

$
54,183


$
64,587Supplies and equipment


158,852



135,545Gathering, compression and processing fees


46,734



45,517Direct costs - general and administrative


151,967



8,832Cash distributions*


195,042



237,894
  *Cash distributions include $5,488 and $2,282 during the three months ended March 31, 2009 and 2008, respectively, related to equity cash distributions on Investor Partner units repurchased by PDC.  For additional disclosure regarding the Unit Repurchase Program, refer to Note 1, Generaland
Part II Item 2, Unregistered Sales of Equity Securities and Use of Proceeds.
 
 Note 4−Derivative Financial Instruments
 
 The Partnership is exposed to the effect of market fluctuations in the prices of oil and natural gas as they relate to oil and natural gas sales.  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 accounts for derivative financial instruments in accordance with FAS No. 133, Accounting for Derivative Instruments and Certain Hedging Activities, as amended.  As of March 31, 2009, and December 31, 2008, none of the Partnership’s derivative instruments
qualified for use of hedge accounting under the terms of FAS No. 133.  The Partnership recognizes all derivative instruments as either assets or liabilities on its balance sheets at fair value, and changes in the fair value of those derivative instruments allocated to the Partnership are recorded on a net basis 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 loss, 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 5, Fair
Value Measurements, for a discussion of how the Managing General Partner determines the fair value the Partnership’s derivative instruments.
 
 As of March 31, 2009, the Managing General Partner had derivative contracts in place for a portion of the Partnership’s anticipated production through 2011 for a total of 1,005 MMbtu of natural gas and 25 MBbls of crude oil.
 
 Risk Management 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 instruments. As of March 31, 2009, the Partnership’s oil and natural gas derivative instruments were comprised of natural gas collars and swaps, oil swaps and basis protection swaps.
  - 7 -
 Index
  PDC 2005-A LIMITED PARTNERSHIP
 NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
 March 31, 2009
 (unaudited)
 
 ·
For swap instruments, if the market price is below the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the market price and the fixed contract price from the counterparty.  If the market price is above the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference
between the market price and the fixed contract price to the counterparty.
 
 ·
Basis protection swaps are arrangements that guarantee a price differential for natural gas valued at a specified pricing point, or hub.  For CIG basis protection swaps that have a negative pricing differential 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.
 
 ·
Collars contain a fixed floor price (put) and ceiling price (call).  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 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 is between the call and put strike price, no payments are due from either party.
 
 For Partnership oil and gas sales activities, the Managing General Partner purchases collars and swaps on the Partnership’s production 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 changes 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.
 
 The Partnership’s derivative instruments are recorded at fair value in accordance with FAS No. 157.  The following table summarizes the location and fair value amounts of the Partnership’s derivative instruments in the accompanying balance sheets as of March 31, 2009, and December 31, 2008.
 
 Fair ValueAs ofDerivatives not qualifying for hedge accounting under FAS No. 133 (1):


Balance Sheet Location


March 31,
2009


December 31,
2008Derivative Assets:
CurrentCommodity based derivative contracts


Due from Managing General Partner-derivatives


$
2,434,504


$
2,100,443Long TermCommodity based derivative contracts


Due from Managing General Partner-derivatives



313,941



716,092Total Derivative Assets





$
2,748,445


$
2,816,535Derivative Liabilities:
Long TermCommodity based derivative contracts


Due to Managing General Partner-derivatives



(74,019
)


-Basis protection derivative contracts


Due to Managing General Partner-derivatives



(958,689
)


(165,957
)Total Derivative Liabilities





$
(1,032,708
)

$
(165,957
)
 - 8 -
 Index
  PDC 2005-A LIMITED PARTNERSHIP
 NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
 March 31, 2009
 (unaudited)
 
 (1) As of March 31, 2009 and December 31, 2008, none of the Partnership’s derivative contracts qualified for hedge accounting under FAS No. 133.
 
 The following table summarizes the location and amounts of gains and losses on derivative instruments included in the Partnership’s accompanying statements of operations for the three months ended March 31, 2009 and 2008.
 
 Three months ended March 31,2009


2008Statement of operations line item

Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized


Realized and Unrealized Gains (Losses) For the Current Period


Total


Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized


Realized and Unrealized Gains (Losses) For the Current Period


TotalOil and gas price risk management, gain (loss), netRealized gains (losses)

$
739,077


$
155,520


$
894,597


$
104,540


$
(174,627
)

$
(70,087
)Unrealized losses


(739,077
)


(195,764
)


(934,841
)


(104,540
)


(430,600
)


(535,140
)Total oil and gas price risk management loss, net

$
-


$
(40,244
)

$
(40,244
)

$
-


$
(605,227
)

$
(605,227
)
 
 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.  These contracts consist of fixed-price swaps, basis protection swaps and collars.  Credit risk is the failure of the counterparty to perform under the terms of the derivative contract.  When the fair value of a derivative contract is positive, the counterparty owes the Managing General Partner, which in turn owes the Partnership, thus creating repayment risk from counterparties.  The Managing General Partner seeks to diversify counterparty
exposure by entering into transactions with high-quality counterparties including three investment grade financial institutions.  The Managing General Partner has evaluated the credit risk of the Partnership’s assets from counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position.  Based on this evaluation, the Managing General Partner has determined that the impact
of the nonperformance of counterparties on the fair value of the Partnership’s derivative instruments is insignificant.  The Managing General Partner has not experienced any counterparty defaults during the three months ended March 31, 2009, nor in any previous reporting period and no valuation allowance has been recorded by the Partnership.
 
 Note 5−Fair Value Measurements
 
 Determination of Fair Value. The Partnership determines the fair value of its assets and liabilities, unless specifically excluded, pursuant to FAS No. 157.  FAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability
in an orderly transaction between market participants at the measurement date.
 
 FAS No. 157 establishes a fair value hierarchy that requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.  The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the
highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3).  In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy.  The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy.  Assessing the significance of a particular input to the fair value measurement in its entirety requires
judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels.  The three levels of inputs that may be used to measure fair value are defined as:
 
 ·
Level 1 – Quoted prices (unadjusted) in active markets for identical assets or liabilities.  Included in Level 1 are commodity derivative instruments for New York Mercantile Exchange (“NYMEX”) natural gas swaps.
  - 9 -
 Index
  PDC 2005-A LIMITED PARTNERSHIP
 NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
 March 31, 2009
 (unaudited)
 
 ·
Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices
that are observable for the asset or liability and (iv) inputs that are derived from observable market data by correlation or other means.
 
 ·
Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.  Included in Level 3 are the Partnership’s asset retirement obligations and the Partnership’s commodity derivative instruments for 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 Managing General Partner’s 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 Managing General Partner’s valuation determination
also gives consideration to the 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 three investment grade financial institutions as counterparties to its derivative contracts.  The Managing General Partner has evaluated the credit risk of the Partnership’s derivative assets from counterparties
using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position.  The Managing General Partner has determined based on this evaluation, that the impact of counterparty non-performance on the fair value of the Partnership’s derivative instruments is insignificant for the Partnership.  Thus, no valuation allowance has been recorded by the Partnership as of March 31, 2009.  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 3As of


As ofMarch 31, 2009


December 31, 2008


March 31, 2009


December 31, 2008Assets:Commodity based derivatives

$
-


$
-


$
2,748,445


$
2,816,535Total assets


-



-



2,748,445



2,816,535Liabilities:Commodity based derivatives


(70,899
)


-



(3,120
)


-Basis protection derivative contracts


-



-



(958,689
)


(165,957
)Total liabilities


(70,899
)


-



(961,809
)


(165,957
)Net (Liability) Asset

$
(70,899
)

$
-


$
1,786,636


$
2,650,578
 - 10 -
 Index
  PDC 2005-A LIMITED PARTNERSHIP
 NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
 March 31, 2009
 (unaudited)
 
 The following table sets forth the changes of the Partnership’s Level 3 derivative financial instruments measured on a recurring basis:
 
 Three months endedMarch 31, 2009Fair value, net asset, as of December 31, 2008

$
2,650,578Unrealized and realized gains (losses) included in Oil and gas price risk management loss, net


30,655Settlements, net


(894,597
)Fair value, net asset, as of March 31, 2009

$
1,786,636Change in unrealized gains (losses) relating to assets (liabilities) still held as of March 31, 2009, included in statement of operations line item:Oil and gas price risk management loss, net

$
(121,745
)
 
 See Note 4, Derivative Financial Instruments, for additional disclosure related to the Partnership’s derivative financial instruments.
 
 Non-Derivative Assets and Liabilities.  The carrying values of the financial instruments comprising “Cash and cash equivalents,” “Accounts receivable,” “Accounts payable and accrued expenses” and “Due to (from) Managing General
Partner-other, net” approximate fair value due to the short-term maturities of these instruments.
 
 In accordance with Statement of Financial Accounting Standards, SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Partnership reviews its proved oil and gas properties for possible impairment, upon a triggering event, by comparing net capitalized costs
to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which the Partnership reasonably estimates the commodity to be sold.  The estimates of future prices may differ from current market prices of oil and natural gas.  Downward revisions in estimates to the Partnership’s reserve quantities, expectations of falling commodity prices or rising operating costs could result in a triggering event and therefore a possible impairment
of the Partnership’s oil and natural gas properties.  If net capitalized costs exceed undiscounted future net cash flows, impairment is measured by the amount by which the net capitalized costs exceed their fair value utilizing a future discounted cash flow analysis.  There were no triggering events and no impairment of oil and gas properties has been recognized during the three months ended March 31, 2009 or 2008.
 
 The Partnership accounts for asset retirement obligations by recording the estimated fair value of the plugging and abandonment obligations when incurred, which is when the well is completely drilled.  The Partnership estimates the fair value of the plugging and abandonment obligations based on a discounted cash flows analysis.  Upon
initial recognition of an asset retirement obligation, the Partnership increases the carrying amount of the long-lived asset by the same amount as the liability.  Over time, the liabilities are accreted for the change in their present value, through charges to oil and gas production and well operations costs.  The initial capitalized costs are depleted over the useful lives of the related assets, through charges to depreciation, depletion and amortization.  If the fair value of the
estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost.  Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations.
  - 11 -
 Index
  PDC 2005-A LIMITED PARTNERSHIP
 NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
 March 31, 2009
 (unaudited)
 
 Note 6−Commitments and Contingencies
 
 Royalty Settlement.On May 29, 2007, Glen Droegemueller, individually and as representative plaintiff on behalf of all others similarly situated, filed a class action complaint against the Managing General Partner in the District Court, Weld County, Colorado alleging that
the Managing General Partner underpaid royalties on natural gas produced from wells operated by the Managing General Partner in parts of the State of Colorado (the “Droegemueller Action”).  The plaintiff sought declaratory relief and to recover an unspecified amount of compensation for underpayment of royalties paid by us pursuant to leases.  The Managing General Partner removed the case to Federal Court on June 28, 2007.  On October 10, 2008, the court preliminarily approved a settlement
agreement between the plaintiffs and the Managing General Partner, on behalf of itself and the Partnership.  Although the Partnership was not named as a party in the suit, the lawsuit states that it relates to all wells operated by the Managing General Partner, which includes a majority of the Partnership’s 36 wells in the Wattenberg field.  The portion of the settlement relating to the Partnership’s wells for all periods through March 31, 2009 that has been expensed by the Partnership
is approximately $74,000 including associated legal costs of approximately $5,000.  Such moneys, on behalf of the Partnerships, were deposited in an escrow account on November 3, 2008.  The Managing General Partner believes that the amount accrued is adequate to satisfy this obligation.  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.  Distributions from the
escrow to the royalty owners are expected on or before June 7, 2009, unless the court approval of the settlement is appealed.
 
 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 four equal owners of Garden Gulch LLC, all of which are oil and gas companies operating in the Piceance region of Colorado.  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.  Given the preliminary stage of this proceeding and the inherent uncertainty in administrative actions of this nature, the Managing General Partner is unable to predict the ultimate outcome of this administrative action
at this time.
 
 Derivative Contracts.  The Partnership is exposed to oil and natural gas price fluctuations on underlying sales contracts should the counterparties to the Managing General Partner’s derivative instruments not perform.  Nonperformance is not anticipated.  The
Managing General Partner has had no counterparty default losses to date.
  - 12 -
 Index
  PDC 2005-A LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)
 
 Item2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
 Special Note Regarding Forward Looking Statements
 
 This periodic report on Form 10-Q 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 that are subject to risks and uncertainties.  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 them.  Consequently, forward-looking statements are inherently subject to risks and uncertainties, including risks and uncertainties incidental to the development, production and marketing of natural gas and oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Important factors that could cause actual results to differ materially from the forward-looking statements include,
but are not limited to:
 
 ·
changes in production volumes, worldwide demand, and commodity prices for oil and natural gas;
 ·
risks incident to the operation of natural gas and oil wells;
 ·
future production and development costs;
 ·
the availability of sufficient pipeline and other transportation facilities to carry Partnership production and the impact of these facilities on price;
 ·
the effect of existing and future laws, governmental regulations and the political and economic climate of the United States of America (“U.S.”) and the impact of the global economy;
 ·
the effect of natural gas and oil derivatives activities;
 ·
availability and cost of capital and conditions in the capital markets; and
 ·
losses possible from pending and/or future litigation and the costs incident thereto.
 
 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.  The Partnership sells the produced natural
gas to commercial end users, interstate or intrastate pipelines or local utilities, primarily under market sensitive contracts in which the price of natural gas sold varies as a result of market forces.  PDC, on behalf of the Partnership, may enter into fixed price contracts, or utilize derivatives, including collars, swaps or basis protection swaps, in order to offset some or all of the price variability for particular periods of time, generally for two to three years, but in no cases longer than five
years.  Seasonal factors, such as effects of weather on prices received and costs incurred, and availability of pipelines may impact the Partnership's results.  In addition, both sales volumes and prices tend to be affected by demand factors with a significant seasonal component.
 
 PDC last sponsored a drilling partnership (Rockies Region 2007 Limited Partnership) in the fall of 2007, and substantially completed the last drilling services for that partnership in 2008.  PDC does not currently have any plans to sponsor additional drilling partnerships.
  - 13 -
 Index
  PDC 2005-A LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)
 
 Results of Operations
 
 The table below sets forth selected information regarding the Partnership’s results of operations, including production volumes, oil and gas sales, average sales prices received, average sales price including realized derivative gains and losses, production and operating costs, depreciation, depletion and amortization costs, other
operating income and expenses for the three months ended March 31, 2009, or first quarter of 2009 and the three months ended March 31, 2008, or first quarter of 2008.
 
 Summary Operating ResultsThree months ended March 31,2009


2008


ChangeNumber of producing wells (end of period)


49



49



*Production:  (1)Oil (Bbl)


7,855



7,469



5
%Natural gas (Mcf)


190,448



172,794



10
%Natural gas equivalents (Mcfe)  (2)


237,578



217,608



9
%Average Selling PriceOil (per Bbl)  (3)

$
35.79


$
82.24



-56
%Natural gas (per Mcf)  (3)


3.06



6.78



-55
%Natural gas equivalents (per Mcfe)  (3)


3.64



8.21



-56
%Average Selling Price (including realized gain (loss), net on derivatives)Oil (per Bbl)

$
58.59


$
77.61



-24
%Natural gas (per Mcf)


6.82



6.58



4
%Natural gas equivalents (per Mcfe)


7.40



7.89



-6
%Average cost per McfeProduction and operating costs  (4)

$
1.34


$
1.87



-28
%Depreciation, depletion and amortization


4.55



2.97



53
%Revenues:Oil and gas sales

$
863,692


$
1,786,187



-52
%Oil and gas price risk management, gain (loss), net


(40,244
)


(605,227
)


-93
%Total revenues

$
823,448


$
1,180,960



-30
%Realized Gain (Loss) on Derivatives, netOil derivatives - realized gain (loss)

$
179,170


$
(34,613
)


*Natural gas derivatives - realized gain (loss)


715,427



(35,474
)


*Total realized gain (loss) on derivatives, net

$
894,597


$
(70,087
)


*Operating costs and expenses:Production and operating costs

$
318,164


$
406,728



-22
%Direct costs - general and administrative


151,967



8,832



*Depreciation, depletion and amortization


1,082,145



646,183



67
%Accretion of asset retirement obligations


4,624



4,373



6
%Total operating costs and expenses

$
1,556,900


$
1,066,116



46
%Income (loss) from operations

$
(733,452
)

$
114,844



*Interest income


11,700



18,162



-36
%Net (loss) income

$
(721,752
)

$
133,006



*Cash distributions

$
947,770


$
1,178,066



-20
%
 
 *Percentage change not meaningful or equal to or greater than 250% or not calculable.  Amounts may not calculate due to rounding.
  - 14 -
 Index
  PDC 2005-A LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)
 _______________
 (1)
Production is net and determined by multiplying the gross production volume of properties in which we have an interest by the percentage of the leasehold or other property interest we own.
 (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)
The Partnership utilizes derivative instruments to manage a portion of our exposure to price volatility of our natural gas and oil sales.  This amount excludes realized and unrealized gains and losses on commodity based derivative instruments.
 (4)
Production costs represent oil and gas operating expenses which include production taxes.
 
 Definitions used throughout Management’s Discussion and Analysis of Financial Condition and Results of Operations:
 
 ·
Bbl – One barrel or 42 U.S. gallons liquid volume
 ·
MBbl – One thousand barrels
 ·
Mcf – One thousand cubic feet
 ·
MMcf – One million cubic feet
 ·
Mcfe – One thousand cubic feet of natural gas equivalents
 ·
MMcfe – One million cubic feet of natural gas equivalents
 
 First Quarter 2009 Overview
 
 During the first quarter of 2009, the Partnership experienced the continuation of the significant declines in oil and natural gas commodity prices from last year, which was a year of significant events: oil and natural gas prices reached record and near record highs, respectively, through July; then, in the midst of U.S. credit turmoil
and a worldwide economic slump, in December, oil prices fell to their lowest in four years and natural gas prices dropped almost by half.  The Partnership’s derivative position has eased the impact of the fall in oil and natural gas prices.  The Partnership realized $0.9 million in realized derivative gains in the first quarter of 2009, up from $0.7 million in the fourth quarter of 2008.  At March 31, 2009, the Partnership estimated the net fair value of its derivative positions
to be a $1.7 million asset.  See the Liquidity and Capital Resources discussion below for the steps the Partnership is taking in this uncertain economic environment.
 
 Although production has increased to 237,578 Mcfe for the first three months of 2009 compared to 217,608 Mcfe for the same prior year period, an increase of 9%, the average sales price declined $4.57 per Mcfe.  This increase was due to larger than expected natural gas production from several of the Partnership’s larger
producing wells.  The Partnership’s realized derivative gains for the first quarter of 2009 of $0.9 million added an average of $3.76 per Mcfe produced during the current three month period, somewhat easing the significant drop in prices.
 
 A decrease in the spread between the NYMEX and CIG prices for natural gas, slightly offset by lower CIG natural gas prices, resulted in unrealized losses on oil and natural gas derivatives of $0.2 million during the quarter.  An unrealized loss is a non-cash item and further gains or losses will be recognized as prices decrease
or increase until the positions mature or are closed.  None of the Partnership’s derivative instruments qualified for use of hedge accounting under the terms of FAS No. 133 during the current reporting period.  While the required accounting treatment for derivatives that do not qualify for hedge accounting treatment under SFAS No. 133 may result in significant swings in operating results over the life of the derivatives, the combination of the settled derivative contracts and the revenue
received from the oil and gas sales at delivery are expected to result in a more predictable cash flow stream than would the sales contracts without the associated derivatives.
 
 During the three month period ended March 31, 2009, daily crude oil prices fluctuated in a range of $33.98 to $54.34 per barrel, with the overall trend of the monthly average of daily NYMEX-index oil prices rising, from $41.99 per barrel in January to $48.12 per barrel in March. Rocky Mountain regional natural gas daily prices tracked
downward through March 2009 however, the monthly average of daily CIG-index prices of $3.67 in January, declined to $2.50 by March.  See Oil and Gas Price Risk Management Loss, Netdiscussion below.
  - 15 -
 Index
  PDC 2005-A LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)
 
 The table below, which demonstrates the markets’ expected volatility in commodity pricing, sets forth the average NYMEX and CIG prices for the next 24 months (forward curve) from the selected dates:
 
 
 December 31,


June 30,


December 31,


March 31,Commodity


Index

2007


2008


2008


2009Natural gas: (per MMbtu)NYMEX

$
8.12


$
12.52


$
6.62


$
5.44CIG


6.78



8.86



4.49



4.15Oil: (per Bbl)


NYMEX


90.79



140.15



57.49



59.35
 
 Oil and Natural Gas Sales Activity
 
 Partnership production for the current three month period was 237,578 Mcfe, averaging 2,640 MMcfe per day, a 9% increase from the 2,391 Mcfe per day produced during the same three month period in 2008.  This increase was due to larger than expected natural gas production from several of the Partnership’s larger producing
wells.  Weighted average prices (excluding realized gains or losses on derivatives) were $3.64 per Mcfe for the current three month period compared to $8.21 for the prior year’s same three-month period.  Decreased commodity prices resulted in a decrease in sales of $1.1 million which was partially offset by increased production of $0.2 million, resulting in a total net decrease of $0.9 million in oil and gas sales for the current three month period as compared to the prior three month
period.  The year-to-year decrease in both oil and natural gas revenues of 54% and 50%, respectively, reflects significant decreases in oil prices (56%) and natural gas prices (55%) during the period.
 
 The Partnership expects to experience continued declines in both oil and natural gas production volumes over the wells’ life cycles until the Wattenberg wells are recompleted.
 
 Oil and Natural Gas Pricing:
 
 Financial results depend upon many factors, particularly the price of oil and natural gas and the Partnership’s ability to market its production effectively.  Oil and natural gas prices have been among the most volatile of all commodity prices.  These price variations have a material impact on the Partnership’s
financial results.  Oil and natural gas prices also vary by region and locality, depending upon the distance to markets, and the supply and demand relationships in that region or locality.  This can be especially true in the Rocky Mountain Region.  The combination of increased drilling activity and the lack of local markets have resulted in a local market oversupply situation from time to time.  Like most producers in the region, the Partnership relies on major interstate
pipeline companies to construct these facilities to increase pipeline capacity, rendering the timing and availability of these facilities beyond the Partnership’s control.  Oil pricing is also driven strongly by supply and demand relationships.  Beginning January 1, 2009, Suncor Energy Marketing, Inc. (“Suncor”) became the primary purchaser of the Partnership’s crude oil production.
 
 The price the Partnership receives for the natural gas produced in the Rocky Mountain Region is based on a market basket of prices, which primarily includes natural gas sold at CIG prices with a portion sold at Mid-Continent 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.
  - 16 -
 Index
  PDC 2005-A LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)
 
 Oil and Gas Price Risk Management Loss, Net
 
 The Managing General Partner uses oil and natural gas derivative instruments to manage price risk for PDC as well as its sponsored drilling partnerships.  The Managing General Partner sets these instruments for PDC, and the various partnerships managed by PDC, jointly by area of operation.  Prior to September 30, 2008,
as volumes produced changed, the mix between PDC and the partnerships would change.  As of September 30, 2008, PDC has fixed the allocation of the derivative positions between PDC and each partnership.  Existing positions are allocated based on fixed quantities for each position and new positions will have specific designations relative to the applicable partnership.
 
 The following table presents the primary composition of “Oil and gas price risk management loss, net” for the periods described:
 
 Three months ended March 31,2009


2008Realized gain (loss)Oil

$
179,170


$
(34,613
)Natural Gas


715,427



(35,474
)Total realized gain (loss)


894,597



(70,087
)Reclassification of realized gain included in prior periods unrealized gain


(739,077
)


(104,540
)Unrealized loss for the period


(195,764
)


(430,600
)Oil and gas price risk management loss, net

$
(40,244
)

$
(605,227
)
 
 The unrealized loss for first quarter 2009 of $0.2 million was primarily due to a decrease in fair value from our CIG basis protection swaps of $0.8 million offset in part by a $0.6 million unrealized gain from our commodity derivatives.  The net unrealized gain from commodity derivatives resulted from the continued decline in
commodity prices during the first quarter.  The unrealized loss from the Partnership’s CIG basis protection swaps resulted from a more significant decline in NYMEX pricing compared to CIG pricing.  The realized gains from commodity derivatives resulted from the current realized prices being below our swaps and floor contract prices.  Oil and gas price risk management loss, net includes realized gains and losses and unrealized gains and losses resulting from changes in the fair
value of derivative instruments related to our oil and natural gas production.
 
 Oil and Gas Derivative Activities.  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.
  - 17 -
 Index
  PDC 2005-A LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)
 
 The following table identifies the Partnership’s derivative positions related to oil and gas sales activities in effect as of March 31, 2009, on the Partnership’s production by area of operation.  The Partnership’s production volumes for the three months ended March 31, 2009, were 7,855 Bbls of oil and 190,448
Mcf of natural gas.  No new positions have been entered into subsequent to March 31, 2009, through May 12, 2009.
 
 Floors


Ceilings


Swaps (Fixed Prices)


Basis Protection ContractsCommodity/Index/ Operating Area

Quantity(Gas-MMbtuOil-Bbls)


WeightedAverageContractPrice


Quantity(Gas-MMbtuOil-Bbls)


WeightedAverageContractPrice


Quantity(Gas-MMbtuOil-Bbls)


WeightedAverageContractPrice


Quantity(Gas-MMbtuOil-Bbls)


WeightedAverageContractPrice


Fair ValueAtMarch 31,2009Natural GasRocky Mountain RegionCIG2Q 2009


146,974


$
5.75



146,974


$
8.90



-


$
-



-


$
-


$
481,6073Q 2009


146,974



5.75



146,974



8.90



-



-



-



-



422,2484Q 2009


102,312



6.66



102,312



10.20



37,454



9.20



-



-



541,5262010


115,690



6.65



115,690



10.80



56,181



9.20



338,193



1.88



322,7912011


53,563



4.75



53,563



9.45



-



-



393,012



1.88



(244,611
)2012


-



-



-



-



-



-



407,688



1.88



(297,971
)2013


-



-



-



-



-



-



373,458



1.88



(236,072
)NYMEX2010


17,824



5.75



17,824



8.30



304,190



5.55



-



-



(70,356
)2011


23,986



5.75



23,986



8.30



-



-



-



-



(3,663
)Total Natural Gas





























915,499OilRocky Mountain RegionNYMEX2Q 2009


-



-



-



-



3,829



90.52



-



-



148,2083Q 2009


-



-



-



-



3,871



90.52



-



-



135,9094Q 2009


-



-



-



-



3,871



90.52



-



-



124,5562010


-



-



-



-



13,228



92.96



-



-



391,565Total Oil


































800,238Total Natural Gas and Oil
























$
1,715,737
 
 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 estimates 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.  In addition, general oil field service costs have experienced significant inflationary increases.
 
 For the three months ended March 31, 2009 compared to 2008, oil and natural production, on an energy equivalency-basis, increased 19,970 Mcfe, or 9%, due to larger than expected natural gas production from several of the Partnership’s larger producing wells.  Production and operating costs were lower by approximately $89,000,
or 22%, due to a decrease in general oil field services costs.  Production and operating costs per Mcfe were $1.34 for the first quarter of 2009 compared to $1.87 for the first quarter of 2008.
 
 Direct Costs−General and Administrative
 
 Direct costs – general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation and legal matters.  Direct costs increased during the first three months of 2009 by $143,135 primarily due to an increase in professional fees for audit and tax services.
  - 18 -
 Index
  PDC 2005-A LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)
 
 Depreciation, Depletion and Amortization
 
 Depreciation, depletion and amortization (DD&A) results solely from the depreciation, depletion and amortization of well equipment and lease costs.  DD&A expense is directly related to reserves and production volumes.  DD&A expense is primarily based upon year-end proved developed producing oil and gas reserves.  These
reserves are priced at the price of oil and natural gas as of December 31 each year.  If prices increase, the corresponding volume of oil and gas reserves will increase, resulting in decreases in the rate of DD&A per unit of production.  If prices decrease, as they did from 2007 to 2008, volumes of oil and gas reserves will decrease resulting in increases in the rate of DD&A per unit of production.
 
 The increase in the per Mcfe rate to $4.55 for the quarter ended March 31, 2009 compared to the per Mcfe rate of $2.97 during the same quarter in 2008 resulted in a $435,962 increase in DD&A for the three months ended March 31, 2009 compared to same period in 2008.  This increase per Mcfe is primarily the result of significantly
lower reserves at December 31, 2008 compared to December 31, 2007.  While both production and overall year-end reserves are expected to decline gradually year-to-year over the wells’ remaining life cycles, downward revisions to oil and natural gas reserves in the annual 2008 reserve report, principally related to changes in pricing resulted in the larger DD&A unit cost increase during the first quarter of 2009 as compared to the first quarter 2008.
 
 Interest Income
 
 Interest income decreased in March 31, 2009 compared to the same period in the previous year, due to the lower level of undistributed revenues held by the Managing General Partner during the three months ended March 31, 2009, as well as a reduction in the interest rates applied to those undistributed revenue amounts.
 
 Liquidity and Capital Resources
 
 The Partnership could not maintain the Partnership’s 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, which would have a material negative impact on the Partnership’s operations in 2010 and beyond.
 
 Working Capital
 
 Working capital at March 31, 2009 was $4.9 million compared to working capital of $4.3 million at December 31, 2008.
 
 Investing Cash Flows
 
 The Partnership has from time-to-time, invested in additional equipment which supports treatment, delivery and measurement or environmental protection, such amounts totaled approximately $16,000 and $22,000 for the three months ended March 31, 2009 and 2008, respectively.
 
 Financing Cash Flows
 
 The Partnership initiated monthly cash distributions to investors in September 2005 and has distributed $35.9 million of operating cash flows through March 31, 2009.  The table below sets forth the cash distributions to the Managing General Partner and Investor Partners including Managing General distribution relating to limited
partnership units repurchased for the periods described as follows:
 
 Quarter Ended

Managing General Partner Distributions


Investor Partners Distributions


Total DistributionsMarch 31, 2009

$
189,554


$
758,216


$
947,770March 31, 2008

$
235,612


$
942,454


$
1,178,066
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 Index
  PDC 2005-A LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)
 
 Operating Cash Flows
 
 The Partnership’s operations are expected to be conducted with available funds and revenues generated from its oil and natural gas production activities.  Changes in cash flow from operations are largely due to the same factors that affect the Partnership’s net income that are more fully discussed under Results
of Operations, excluding the non-cash items depreciation, depletion and amortization and unrealized gains and losses on derivative transactions.  Based on current oil and natural gas prices and prices set by derivatives, and the Partnership’s anticipated production, the Partnership expects positive cash flows from operations for the remainder of 2009.
 
 Changes in market prices for oil and natural gas, the Partnership’s ability to increase production, the impact of realized gains and losses on the Partnership’s oil and natural gas derivative instruments and changes in costs are the principal determinants of the level of the Partnership cash flow from operations.  Oil
and natural gas sales for the three months ended March 31, 2009 were approximately 52% lower than the same period in the prior year, resulting from a 56% decrease in average oil and natural gas prices and a 9% increase 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 75% of its expected natural gas production in 2009, at average prices of $90.52 per Bbl and $6.26 per Mcf, respectively.  These contracts reduce the impact of price changes on cash provided by operations for a substantial portion of the Partnership’s 2009 cash from expected production.
 
 The Partnership’s current derivatives positions could change based on changes in oil and natural gas futures markets, the view of underlying oil and natural gas supply and demand trends and changes in volumes produced.  Partnership oil and natural gas derivatives as of March 31, 2009 are detailed in Note 4, Derivative
Financial Instruments to the accompanying unaudited condensed financial statements.
 
 Net cash provided by operating activities was $1.0 million for the three months ended March 31, 2009 compared to $1.2 million during the same period in 2008, a decrease of $0.2 million.  The decrease in cash provided by operating activities was due primarily to the following:
 
 ·
A decrease in oil and gas sale revenues of $0.9 million, or 52%, accompanied by an increase in direct costs – general and administrative of $0.1 million
 
 ·
An increase in realized oil and gas price risk management loss, net of $1.0 million and a decrease in production and operating cost of 22%.
 
 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.
 
 No bank borrowings are anticipated until such time as recompletions of the Codell formation in the Wattenberg Field wells are undertaken by the Partnership, which is expected to occur in 2011 or later.
 
 PDC, as Managing General Partner, does not believe liquidity relative to its own business interests, nor that of the Partnership, has been materially affected by the recent events in the credit markets.  The Managing General Partner continues to monitor events and circumstances surrounding lenders in its credit facility and has
experienced no disruptions in its ability to access this facility.  However, the Managing General Partner cannot predict with any certainty the impact to the Partnership of any continued disruption in the credit environment.
 
 Commitments and Contingencies
 
 See Note 6, Commitments and Contingencies, to the accompanying unaudited condensed financial statements.
  - 20 -
 Index
  PDC 2005-A LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)
 
 Critical Accounting Policies and Estimates
 
 The preparation of the accompanying unaudited condensed financial statements, in conformity with accounting principles generally accepted in the United States of America, requires management to use judgment in making estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and
liabilities and the reported amounts of revenue and expenses.
 
 The Managing General Partner 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 our Annual Report on Form 10-K for the fiscal year ended December 31, 2008, filed with the SEC on April 28, 2009.
 
 Recent Accounting Standards
 
 See Note 2, Recent Accounting Standards to the accompanying unaudited condensed financial statements, included in this report for recent accounting standards.
 
 
 Item3.       Quantitative and Qualitative Disclosures About Market Risk
 
 Not Applicable
 
 
 Item4T.    Controls and Procedures
 
 The Partnership has no direct management or officers.  The management, officers and other employees that provide services on behalf of the Partnership are employed by the Managing General Partner.
 
 2008 Material Weakness
 
 As discussed in Management’s Report on Internal Control Over Financial Reporting included in the Partnership’s 2008 Annual Report on Form 10-K, the Partnership did not maintain effective internal controls over financial reporting as of December 31, 2008, over transactions
that are directly related to and processed by the Partnership, in that the Partnership failed to maintain sufficient documentation to adequately assess the operating effectiveness of internal control over financial reporting.  More specifically, the Partnership’s financial close and reporting narrative failed to adequately describe the process, identify key controls and assess segregation of duties.  This material weakness has not been remediated as of March 31, 2009.  The
2008 Annual Report on Form 10-K did not include an attestation report of the Partnership’s independent registered public accounting firm regarding internal control over financial reporting pursuant to Item 308T (a)(4) of Regulation S-K.  Such report is required in the Partnership’s 2009 Annual Report on Form 10-K
 
 (a)  Evaluation of Disclosure Controls and Procedures
 
 As of March 31, 2009, PDC, as Managing General Partner on behalf of the Partnership, carried out an evaluation, under the supervision and with the participation of the Managing General Partner's management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Partnership's
disclosure controls and procedures.  Pursuant to Securities Exchange Act Rules 13a-15(e) and 15d-15(e) these are the controls and procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports it 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 issuer’s management,
including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
  - 21 -
 Index
  PDC 2005-A LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)
 
 Based upon that evaluation, the Managing General Partner’s Chief Executive Officer and Chief Financial Officer concluded that the Partnership’s disclosure controls and procedures were not effective as of March 31, 2009 due to the existence of the material weakness described above in 2008
Material Weakness included in this Item 4 (T).
 
 (b)  Remediation of Material Weakness in Internal Control
 
 The Partnership has completed the planning phase for developing a revised financial close and reporting narrative which will adequately describe the process, identify key controls and assess segregation of duties.  This revised narrative is expected to be completed during the second quarter of 2009.  At present, the
Partnership has not quantified the total cost of this initiative, however the majority of this cost is expected to be paid by the Managing General Partner.
 
 
 PART II – OTHER INFORMATION
 
 
 Item1.
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.
 
 
 Item1A.
Risk Factors
 
 Not Applicable
 
 
 Item2.
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.  First quarter 2009 repurchases were made in February 2009 when the Managing General Partner repurchased 4 units at an average price of $9,285 per unit, and in March 2009, when 3.25 units were purchased at an average price of $9,368 per unit.  Second quarter 2009 repurchases were made in April 2009, when 4.75 units were repurchased at
an average price of $9,223 per unit.
 
 Other Repurchases:  Individual investor partners periodically offer and PDC repurchases, units on a negotiated basis before the third anniversary of the date of the first cash distribution.
 
 Items3, 4 and 5 have been omitted as there is nothing to report.
  - 22 -
 Index
  PDC 2005-A LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)
 
 Item6.
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

Domestic Crude Oil Purchase Agreement between Suncor Energy Marketing Inc. and Petroleum Development Corporation, dated April 22, 2008*









X31.1

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
 _________________
 *A confidential treatment request pursuant to Exchange Act rule 24b.2 was filed with the SEC with respect to portions of this agreement.
 - 23 -
 Index
 SIGNATURES
  Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 PDC 2005-A Limited Partnership
 By its Managing General Partner
 Petroleum Development Corporation
 
 By: /s/ Richard W. McCulloughRichard W. McCullough
Chairman and Chief Executive Officer
May 18, 2009
 
 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:
 
 
 Signature

Title

Date/s/ Richard W. McCullough

Chairman and Chief Executive Officer

May 18, 2009Richard W. McCullough

Petroleum Development CorporationManaging General Partner of the Registrant(Principal executive officer)/s/ Gysle R. Shellum

Chief Financial Officer

May 18, 2009Gysle R. Shellum

Petroleum Development CorporationManaging General Partner of the Registrant(Principal financial officer)/s/ R. Scott Meyers

Chief Accounting Officer

May 18, 2009R. Scott Meyers

Petroleum Development CorporationManaging General Partner of the Registrant(Principal accounting officer)
   - 24 -