10-Q 1 form10q.htm PDC 2005-A LIMITED PARTNERSHIP 10-Q 3-31-2010 form10q.htm
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 March 31, 2010
or

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

Commission File Number   000-51309

PDC 2005-A Limited Partnership
(Exact name of registrant as specified in its charter)
   
West Virginia
20-2088726
(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 (or for such shorter period that the registrant was required to file such files) and (2) has been subject to such filing requirements for the past 90 days.
Yes þ No o

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

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

Large accelerated filer     o
Accelerated filer     o
   
Non-accelerated filer     o
Smaller reporting company     þ

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

As of March 31, 2010 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

       
Page
   
PART I – FINANCIAL INFORMATION
    
         
Item 1.
  
Financial Statements (unaudited)
    
     
2
     
3
     
4
     
5
Item 2.
    
11
Item 3.
    
19
Item 4T.
    
19
         
   
PART II – OTHER INFORMATION
    
         
Item 1.
    
20
Item 1A.
    
20
Item 2.
    
20
Item 3.
    
20
Item 4.
    
20
Item 5.
    
20
Item 6.
    
21
         
     
22

 
 
 
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 natural gas and oil production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and the Managing General Partner Petroleum Development Corporation’s (“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 natural gas and oil;
 
·
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 the reader 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, 2009 filed with the Securities and Exchange Commission (“SEC”) on March 31, 2010, (“2009 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.

 
- 1 -

PART I – FINANCIAL INFORMATION

Item 1.             Financial Statements (unaudited)

PDC 2005-A Limited Partnership
  
Condensed Balance Sheets
  
(unaudited)
  
             
             
   
March 31, 2010
    
December 31, 2009*
  
Assets
            
             
Current assets:
            
Cash and cash equivalents
   $ 224,751     $ 224,751  
Accounts receivable
     449,001       408,544  
Oil inventory
     24,599       33,305  
Due from Managing General Partner-derivatives
     724,310       554,898  
Due from Managing General Partner-other, net
     489,922       355,801  
Total current assets
     1,912,583       1,577,299  
                 
                 
Oil and gas properties, successful efforts method, at cost
     44,424,848       44,419,132  
Less:  Accumulated depreciation, depletion and amortization
     (21,528,283 )     (20,809,309 )
Oil and gas properties, net
     22,896,565       23,609,823  
                 
Due from Managing General Partner-derivatives
     1,290,847       516,653  
Other assets
     31,131       24,607  
Total noncurrent assets
     24,218,543       24,151,083  
                 
Total Assets
   $ 26,131,126     $ 25,728,382  
                 
Liabilities and Partners' Equity
                
                 
Current liabilities:
                
Accounts payable and accrued expenses
   $ 46,400     $ 41,448  
Due to Managing General Partner-derivatives
     611,841       529,551  
Total current liabilities
     658,241       570,999  
                 
Due to Managing General Partner-derivatives
     1,593,141       1,487,222  
Asset retirement obligations
     519,533       512,800  
Total liabilities
     2,770,915       2,571,021  
                 
Commitments and contingent liabilities
                
                 
Partners' equity:
                
Managing General Partner
     4,687,026       4,646,456  
Limited Partners - 1,996.87 units issued and outstanding
     18,673,185       18,510,905  
Total Partners' equity
     23,360,211       23,157,361  
                 
Total Liabilities and Partners' Equity
   $ 26,131,126     $ 25,728,382  
 
*Derived from audited 2009 balance sheet


See accompanying notes to unaudited condensed financial statements.

 
- 2 -

PDC 2005-A Limited Partnership
  
Condensed Statements of Operations
  
(unaudited)
  
             
             
   
Three months ended March 31,
  
   
2010
    
2009
  
Revenues:
            
Natural gas and oil sales
   $ 1,286,676     $ 863,692  
Commodity price risk management gain (loss), net
     1,221,452       (40,244 )
Total revenues
     2,508,128       823,448  
                 
Operating costs and expenses:
                
Natural gas and oil production costs
     266,591       318,164  
Direct costs - general and administrative
     35,226       151,967  
Depreciation, depletion and amortization
     718,974       1,082,145  
Accretion of asset retirement obligations
     6,733       4,624  
Total operating costs and expenses
     1,027,524       1,556,900  
                 
Income (loss) from operations
     1,480,604       (733,452 )
                 
Interest income
     -       11,700  
                 
Net income (loss)
   $ 1,480,604     $ (721,752 )
                 
Net income (loss) allocated to partners
   $ 1,480,604     $ (721,752 )
Less:  Managing General Partner interest in net income (loss)
     296,121       (144,350 )
Net income (loss) allocated to Investor Partners
   $ 1,184,483     $ (577,402 )
                 
Net income (loss) per Investor Partner unit
   $ 593     $ (289 )
                 
Investor Partner units outstanding
     1,996.87       1,996.87  


See accompanying notes to unaudited condensed financial statements.

 
- 3 -

PDC 2005-A Limited Partnership
  
Condensed Statements of Cash Flows
  
(unaudited)
  
             
             
   
Three months ended March 31,
  
   
2010
    
2009
  
Cash flows from operating activities:
            
Net income (loss)
   $ 1,480,604     $ (721,752 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
                
Depreciation, depletion and amortization
     718,974       1,082,145  
Accretion of asset retirement obligations
     6,733       4,624  
Unrealized (gain) loss on derivative transactions
     (755,397 )     934,841  
Changes in operating assets and liabilities:
                
(Increase) decrease in accounts receivable
     (40,457 )     70,086  
Decrease in oil inventory
     8,706       1,494  
Increase in other assets
     (6,524 )     -  
Increase (decrease) in accounts payable and accrued expenses
     4,952       (8,212 )
Increase in due from Managing General Partner - other, net
     (134,121 )     (397,320 )
Net cash provided by operating activities
     1,283,470       965,906  
                 
Cash flows from investing activities:
                
Capital expenditures for oil and gas properties
     (5,716 )     (16,279 )
Net cash used in investing activities
     (5,716 )     (16,279 )
                 
Cash flows from financing activities:
                
Distributions to Partners
     (1,277,754 )     (947,770 )
Net cash used in financing activities
     (1,277,754 )     (947,770 )
                 
Net increase in cash and cash equivalents
     -       1,857  
Cash and cash equivalents, beginning of period
     224,751       314,610  
Cash and cash equivalents, end of period
   $ 224,751     $ 316,467  


See accompanying notes to unaudited condensed financial statements.

 
- 4 -
 
PDC 2005-A LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 2010
(unaudited)

Note 1−General and Basis of Presentation

The PDC 2005-A Limited Partnership 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, 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” 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 March 31, 2010, there were 1,501 Investor Partners.  As of March 31, 2010, 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 Partnership expects continuing operations of its oil and natural gas properties until such time that a well is depleted or becomes uneconomical to produce, at which time that well will be plugged and abandoned.  The Partnership’s maximum term of existence extends through December 31, 2055, unless dissolved by certain conditions stipulated within the Agreement which are unlikely to occur at this time, or by written consent of the Investor Partners owning a majority of outstanding units at that time.

In the Managing General Partner’s opinion, the accompanying interim unaudited condensed financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary for a fair presentation of the Partnership’s financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC.  Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted.  The information presented in this quarterly report on Form 10-Q should be read in conjunction with the Partnership’s audited financial statements and notes thereto included in the Partnership’s 2009 Form 10-K.  The Partnership’s accounting policies are described in the Notes to Financial Statements in the Partnership’s 2009 Form 10-K and updated, as necessary, in this Form 10-Q.  The results of operations for the three months ended March 31, 2010, and the cash flows for the same period, 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, 2009, as filed with the SEC on March 31, 2010 (“the 2009 Form 10-K”).

The Managing General Partner has evaluated the Partnership’s activities subsequent to March 31, 2010 and has concluded that no material subsequent events have occurred that would require recognition in the Partnership’s financial statements or disclosure in the notes to the Partnership’s financial statements.

 
- 5 -
 
PDC 2005-A LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 2010
(unaudited)

Note 2−Recent Accounting Standards

Recently Adopted Accounting Standards

Fair Value Measurements and Disclosures

In January 2010, the Financial Accounting Standards Board (“FASB”) issued changes clarifying existing disclosure requirements related to fair value measurements.  The update also added a new requirement to disclose fair value transfers in and out of Levels 1 and 2 and describe the reasons for the transfers.  The adoption of these changes as of January 1, 2010, did not have a material impact on the Partnership’s accompanying unaudited condensed financial statements.

Recently Issued Accounting Standards

Fair Value Measurements and Disclosures

In January 2010, the FASB issued changes related to fair value measurements requiring gross presentation of activities within the Level 3 roll forward, whereby entities must present separately information about purchases, sales, issuances and settlements.  This change will be effective for the Partnership’s financial statements issued for annual reporting periods beginning after December 15, 2010.  The Partnership does not expect adoption of these changes to have a material effect on the Partnership’s financial statements and related disclosures.
 
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.

The following table presents transactions with the Managing General Partner reflected in the balance sheet line item – Due from (to) Managing General Partner-other, net which remain undistributed or unsettled with the Partnership’s investors as of the dates indicated.

   
March 31, 2010
    
December 31, 2009
  
             
Natural gas and oil sales revenues collected from the Partnership's third-party customers
   $ 377,578     $ 392,255  
Commodity price risk management, realized gains
     328,340       396,498  
Other (1)
     (215,996 )     (432,952 )
Total Due from Managing General Partner-other, net
   $ 489,922     $ 355,801  

 
(1)
All other unsettled transactions, excluding derivative instruments, between the Partnership and the Managing General Partner.

 
- 6 -
 
PDC 2005-A LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 2010
(unaudited)

The following table presents Partnership transactions, excluding derivative transactions which are more fully detailed in Note 5, Derivative Financial Instruments, with the Managing General Partner and its affiliates for three months ended March 31, 2010 and 2009.  “Well operations and maintenance” and “Gathering, compression and processing fees” are included in “Natural gas and oil production costs” on the statements of operations.

   
Three months ended March 31,
  
   
2010
    
2009
  
             
Well operations and maintenance
   $ 175,462     $ 213,035  
Gathering, compression and processing fees
     45,244       46,734  
Direct costs - general and administrative
     35,226       151,967  
Cash distributions*
     267,709       195,042  

*Cash distributions include $12,158 during the three months ended March 31, 2010, and $5,489 during the three months ended March 31, 2009, related to equity cash distributions on Investor Partner units repurchased by PDC.  For additional disclosure regarding the Unit Repurchase Program, refer to Note 1, General and Basis of Presentation.

Note 4−Fair Value Measurements

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 financial institutions, who are also major lenders in PDC’s credit facility agreement, as counterparties to the Partnership’s derivative contracts.  The Managing General Partner has evaluated the credit risk of the counterparties holding the Partnership’s 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, as of March 31, 2010, the impact of non-performance risk on the fair value of the Managing General Partner’s derivative assets and liabilities was not significant.  Validation of the Partnership’s contracts’ fair values are performed internally and while the Managing General Partner uses common industry practices to develop valuation techniques, changes in the Managing General Partner’s pricing methodologies or the underlying assumptions could result in significantly different fair values.  While the Managing General Partner believes these valuation methods are appropriate and consistent with those 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.

 
- 7 -
 
PDC 2005-A LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 2010
(unaudited)

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

   
Quoted Prices in Active Markets
    
Significant Unobservable Inputs
        
   
(Level 1)
    
(Level 3)
    
Total
  
                   
As of December 31, 2009
                  
Assets:
                  
Commodity based derivatives
   $ 520,527     $ 551,024     $ 1,071,551  
Total assets
     520,527       551,024       1,071,551  
                         
Liabilities:
                        
Commodity based derivatives
     (41,267 )     (90,592 )     (131,859 )
Basis protection derivative contracts
     -       (1,884,914 )     (1,884,914 )
Total liabilities
     (41,267 )     (1,975,506 )     (2,016,773 )
                         
Net asset (liability)
   $ 479,260     $ (1,424,482 )   $ (945,222 )
                         
As of March 31, 2010
                        
Assets:
                        
Commodity based derivatives
   $ 1,833,261     $ 181,896     $ 2,015,157  
Total assets
     1,833,261       181,896       2,015,157  
                         
Liabilities:
                        
Commodity based derivatives
     -       (86,748 )     (86,748 )
Basis protection derivative contracts
     -       (2,118,234 )     (2,118,234 )
Total liabilities
     -       (2,204,982 )     (2,204,982 )
                         
Net asset (liability)
   $ 1,833,261     $ (2,023,086 )   $ (189,825 )

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

   
Three months ended
  
   
March 31, 2010
  
Fair value, net liability, as of December 31, 2009
   $ (1,424,482 )
Changes in fair value included in statement of operations line item:
        
Commodity price risk management, net
     (132,549 )
Settlements
     (466,055 )
Fair value, net liability, as of March 31, 2010
   $ (2,023,086 )
         
Change in unrealized gains (losses) relating to assets (liabilities) still held as of March 31, 2010 included in statement of operations line item:
        
Commodity price risk management, net
   $ (166,976 )

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 current assets and current liabilities approximate fair value due to the short-term maturities of these instruments.
 
Note 5−Derivative Financial Instruments

As of March 31, 2010, the Partnership had derivative instruments, comprised of commodity collars, commodity fixed-price swaps and basis protection swaps, in place for a portion of its anticipated production through 2013 for a total of 1,614,999 MMbtu of natural gas and 15,921 Bbls of oil.  Partnership policy prohibits the use of natural gas and oil derivative instruments for speculative purposes.

 
- 8 -
 
PDC 2005-A LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 2010
(unaudited)

The following table summarizes the location and fair value amounts of the Partnership’s derivative instruments in the accompanying balance sheets.

           
Fair Value
  
Derivative instruments not designated as hedge  (1):
  
Balance Sheet Line Item
  
March 31, 2010
    
December 31, 2009
  
                     
Derivative Assets:
  
Current
                
   
Commodity contracts
  
Due from Managing General Partner-derivatives
   $ 724,310     $ 554,898  
                         
   
Non Current
                    
   
Commodity contracts
  
Due from Managing General Partner-derivatives
     1,290,847       516,653  
                         
                         
Total Derivative Assets
           $ 2,015,157     $ 1,071,551  
                         
Derivative Liabilities:
  
Current
                    
   
Commodity contracts
  
Due to Managing General Partner-derivatives
   $ (21,146 )   $ (42,274 )
                         
   
Basis protection contracts
  
Due to Managing General Partner-derivatives
     (590,695 )     (487,277 )
   
Non Current
                    
   
Commodity contracts
  
Due to Managing General Partner-derivatives
     (65,602 )     (89,584 )
                         
   
Basis protection contracts
  
Due to Managing General Partner-derivatives
     (1,527,539 )     (1,397,638 )
                         
Total Derivative Liabilities
       $ (2,204,982 )   $ (2,016,773 )

 
(1)
As of March 31, 2010 and December 31, 2009, none of the Partnership’s derivative instruments were designated hedges.

The following table summarizes the impact of the Partnership’s derivative instruments on the Partnership’s accompanying statements of operations for the three months ended March 31, 2010 and 2009.

   
Three months ended March 31,
  
   
2010
    
2009
  
Statement of operations line item
  
Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized
    
Realized and Unrealized Gains For the Current Period
    
Total
    
Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized
    
Realized and Unrealized Gains (Losses) For the Current Period
    
Total
  
                                     
Commodity price risk management, net
                                    
Realized gains
   $ 431,627     $ 34,428     $ 466,055     $ 739,077     $ 155,520     $ 894,597  
Unrealized (losses) gains
     (431,627 )     1,187,024       755,397       (739,077 )     (195,764 )     (934,841 )
Total commodity price risk management gain (loss), net
   $ -     $ 1,221,452     $ 1,221,452     $ -     $ (40,244 )   $ (40,244 )

Concentration of Credit Risk. A significant component of the Partnership’s future liquidity is concentrated in derivative instruments that enables the Partnership to manage a portion of its exposure to price volatility from producing natural gas and oil.  These arrangements expose the Partnership to credit risk of nonperformance by the counterparties.  The Managing General Partner primarily uses financial institutions, who are also major lenders in the Managing General Partner’s credit facility agreement, as counterparties to the derivative contracts.  To date, the Partnership has experienced no counterparty default losses.

 
- 9 -
 
PDC 2005-A LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 2010
(unaudited)

Note 6−Commitments and Contingencies

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 (the “CDPHE”), 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 Basin of Colorado.  Operating expenses, including amounts arising from this notice, if any, are allocated among the 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.  Commencing in December 2009, the Managing General Partner entered negotiations with the CDPHE regarding this notice and continues to work to bring this matter to closure.  Given 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 natural gas and oil price fluctuations on underlying sales contracts should the counterparties to the Managing General Partner’s derivative instruments not perform.   Nonperformance is not anticipated.  Neither the Managing General Partner, nor the Partnership, have had any counterparty default losses.

 
- 10 -
 
PDC 2005-A LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

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

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 operates 49 gross (44.4 net) development wells, all of which are currently in production.  The Partnership’s wells are located in the Rocky Mountain Region in the state of Colorado.  The Managing General Partner markets the Partnership’s natural gas production to commercial end users, interstate or intrastate pipelines or local utilities, primarily under market sensitive contracts in which the price of natural gas sold varies as a result of market forces.  PDC, on behalf of the Partnership through the D&O Agreement, may enter into multi-year fixed price contracts or utilize derivatives, including collars, swaps or basis protection swaps, in order to offset some or all of the commodity price variability for particular periods of time.  Seasonal factors, such as effects of weather on prices received and costs incurred, and availability of pipeline capacity, owned by PDC or other third parties, may impact the Partnership's results.  In addition, both sales volumes and prices tend to be affected by demand factors with a seasonal component.

The Partnership’s wells will produce until they are depleted or until they are uneconomical to produce; however, Partnership well recompletions in the Codell formation of Wattenberg Field wells, may provide for additional reserve development and production.  The Managing General Partner has developed a plan to initiate recompletion activities during 2011. This plan includes notifying investor partners that in October 2010, funds to begin these recompletions will be withheld from future distributable cash flows of the Partnership resulting from both current production and any increased production due to recompletion activities.  The funds retained which are necessary for the Partnership to pay for recompletion costs will materially reduce, up to 100%, distributable cash flows for a period of time not to exceed five years.  If any or all of the Partnership’s Wattenberg wells are not recompleted due to an unfavorable general economic climate or unfavorable commodity price environment, the Partnership will experience a reduction in proved reserves currently assigned to these wells.  Both the number of recompletions and the timing of recompletions will be based on the availability of cash withheld from distributions and continued favorable geological information.  The Managing General Partner believes that, based on projected recompletion costs and projected cash withholding, all partnership recompletions can be completed.  Current estimated costs for these well recompletions are between $150,000 and $200,000 per recompletion.  The Managing General Partner will continue to 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.

    PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue the acquisition of the remaining third party investor interests in the limited partnerships which PDC has sponsored, including PDC 2005-A Limited Partnership.  These purchases, which PDC has stated it anticipates might occur over the next three years, will be subject to PDC’s having sufficient available capital and the approval by a majority of the investors’ partnership interests, excluding partnership interest owned by PDC, of each respective limited partnership.
 
If a purchase offer from PDC is proposed and approved by a majority of the Partnerships’ unaffiliated limited partners, it would result in a liquidating cash distribution to all partners and termination of the existence of the Partnership.
 
 
- 11 -
 
PDC 2005-A LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

Results of Operations

The following table presents selected information regarding the Partnership’s results of operations.

   
Three months ended March 31,
  
   
2010
    
2009
    
Change
  
Number of producing wells (end of period)
     49       49       -  
                         
Production:  (1)
                        
Natural gas (Mcf)
     164,223       190,448       -14 %
Oil (Bbl)
     6,565       7,855       -16 %
Natural gas equivalents (Mcfe)  (2)
     203,613       237,578       -14 %
Mcfe per day
     2,262       2,640          
                         
Natural Gas and Oil Sales
                        
Natural gas
   $ 808,795     $ 582,599       39 %
Oil
     477,881       281,093       70 %
Total natural gas and oil sales
   $ 1,286,676     $ 863,692       49 %
                         
Realized Gain on Derivatives, net  (3)
                        
Natural gas
   $ 419,843     $ 715,427       -41 %
Oil
     46,212       179,170       -74 %
Total realized gain on derivatives, net
   $ 466,055     $ 894,597       -48 %
                         
Average Selling Price (excluding realized gain on derivatives)
                        
Natural gas (per Mcf)
   $ 4.92     $ 3.06       61 %
Oil (per Bbl)
     72.79       35.79       103 %
Natural gas equivalents (per Mcfe)
     6.32       3.64       74 %
                         
Average Selling Price (including realized gain on derivatives)
                        
Natural gas (per Mcf)
   $ 7.48     $ 6.82       10 %
Oil (per Bbl)
     79.83       58.59       36 %
Natural gas equivalents (per Mcfe)
     8.61       7.40       16 %
                         
Average Lifting Cost (per Mcfe)  (4)
   $ 1.31     $ 1.34       -2 %
                         
Operating costs and expenses:
                        
Direct costs - general and administrative
   $ 35,226     $ 151,967       -77 %
Depreciation, depletion and amortization
   $ 718,974     $ 1,082,145       -34 %
                         
Cash distributions
   $ 1,277,754     $ 947,770       35 %
                         

 
(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)
Amounts represent realized derivative gains related to natural gas and oil sales.
 
(4)
Production costs represent natural gas and oil operating expenses, which include production taxes.

 
- 12 -
 
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 and Oil Sales

The $0.4 million, or 49% increase in total sales for the 2010 three month period as compared to the same period in 2009 was primarily a reflection of the significantly higher average sales price per Mcfe of 74%, which was partially offset by production volume decreases of 14% on an Mcfe, or energy equivalency basis, during the 2010 three month period compared to the prior year period.  Average sales price per Mcfe, excluding the impact of realized derivative gains, was $6.32 for the current year quarter compared to $3.64 for the same quarter a year ago.

The increase in natural gas revenues of 39% contrasts to the more significant increase in oil revenues of 70%. The Partnership’s oil revenue increase was bolstered by improved average oil sales prices (103%) as compared to the more moderate, yet significant, increase in natural gas sales prices (61%) during the period.

The Partnership expects to experience continued declines in both natural gas and oil 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 be expected to decline.

Natural Gas and Oil Pricing

Financial results depend upon many factors, particularly the price of natural gas and oil and the Partnership’s ability to market its production effectively.  Natural gas and oil prices are among the most volatile of all commodity prices.  These price variations have a material impact on the Partnership’s financial results.  Natural gas and oil prices also vary by region and locality, depending upon the distance to markets, and the supply and demand relationships in that region or locality and the availability of sufficient pipeline capacity.  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 Colorado Interstate Gas, or 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 Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is primarily New York Mercantile Exchange, or NYMEX, based, because of the lack of interstate transmission capacity which moved Rocky Mountain natural gas production to Northeastern U.S. industrial and heating markets.  This negative differential has narrowed in recent months and for two out of the last six months became a slight positive differential, which is inconsistent with historical variances.  This negative differential between NYMEX and CIG averaged $1.62 for the three months ended March 31, 2009, and narrowed to an average of $0.16 for the three months ended March 31, 2010.

 
- 13 -
 
PDC 2005-A LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

Commodity Price Risk Management, Net

The Managing General Partner uses natural gas and oil derivative instruments to manage price risk for PDC as well as sponsored drilling partnerships.  Commodity price risk management, net includes realized gains and losses and unrealized changes in the fair value of derivative instruments related to the Partnership’s natural gas and oil production.  The Managing General Partner sets these instruments for PDC, and the various partnerships managed by PDC.  Derivative financial instrument positions taken by the Managing General Partner on the Partnership’s behalf are specifically designated to the Partnership’s production volumes. See Note 4, Fair Value Measurements and Note 5, Derivative Financial Instruments, to the Partnership’s unaudited condensed financial statements included in this report, for additional details on the Partnership’s derivative financial instruments.

The following table presents the realized and unrealized derivative gains and losses included in commodity price risk management gain (loss), net.

   
Three months ended March 31,
  
Commodity price risk management, net
  
2010
    
2009
  
Realized gains
            
Oil
   $ 46,212     $ 179,170  
Natural Gas
     419,843       715,427  
Total realized gain, net
     466,055       894,597  
                 
Unrealized gains (losses)
                
Reclassification of realized (gains) losses included in prior periods unrealized
    (431,627 )     (739,077 )
Unrealized gain (loss) for the period
     1,187,024       (195,764 )
Total unrealized gain (loss), net
     755,397       (934,841 )
Commodity price risk management gain (loss), net
   $ 1,221,452     $ (40,244 )

Realized gains recognized in the first quarter of 2010 which total $0.5 million, are a result of lower natural gas and oil spot prices at the settlement date compared to the respective strike price.  During the first quarter of 2010, the Partnership recorded unrealized derivative gains of $1.2 million, $1.4 million of which was related to the Partnership’s natural gas positions, offset in part by unrealized losses on the Partnership’s CIG basis swaps of $0.2 million, as the forward basis differential between NYMEX and CIG has continued to narrow.

During the first quarter of 2009, the Partnership experienced realized gains and unrealized derivative losses as natural gas and oil prices declined.  The net unrealized loss for the first quarter of 2009 of $0.2 million was comprised of a decrease in fair value of the Partnership’s CIG basis swaps of $0.8 million which resulted from a steeper decline in NYMEX pricing relative to CIG pricing that was partially offset by a $0.6 million net unrealized gain from the Partnership’s commodity derivatives.

Realized derivative gains, down 48% from the prior year first quarter, contributed an additional $2.29 per Mcfe to this year’s total revenues.  Comparatively, the total per Mcfe price realized, consisting of the average sales price and realized derivative gains, increased 16% to $8.61 for the current year quarter from $7.40 for the prior year first quarter.

Natural Gas and Oil Sales Derivative Instruments.  The Managing General Partner uses various derivative instruments to manage fluctuations in natural gas and oil prices.  The Partnership has in place a series of collars, fixed price swaps and basis protection swaps on a portion of the Partnership’s natural gas and oil production as set forth in the following table.  Under the Partnership’s collar arrangements, if the applicable index rises above the ceiling price, the Managing General Partner pays the counterparty; however, if the index drops below the floor price, the counterparty pays the Managing General Partner.  Under the Partnership’s commodity swap arrangements, if the applicable index rises above the swap price, the Managing General Partner pays the counterparty; however, if the index drops below the swap price, the counterparty pays the Managing General Partner.  Under the Partnership’s basis protection swaps, if the differential widens beyond the basis swap price, then the counterparty pays the Managing General Partner; however, if the differential narrows, then the Managing General Partner pays the counterparty.  Because the Partnership sells all of its physical natural gas and oil at similar prices to the indexes inherent in the Partnership’s derivative instruments, the Partnership ultimately realizes a price related to its collars of no less than the floor and no more than the ceiling and, for the Partnership’s commodity swaps, the Partnership ultimately realizes the fixed price related to its swaps. 

 
- 14 -
 
PDC 2005-A LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

The following table presents the Partnership’s derivative positions in effect as of March 31, 2010.

   
Collars
    
Fixed-Price Swaps
    
CIG Basis Protection Swaps
        
Commodity/
  
Quantity
(Gas-
    
Weighted Average Contract Price
    
Quantity
(Gas-Mmbtu
    
Weighted Average Contract
    
Quantity
(Gas-
    
Weighted Average Contract
    
Fair Value at March 31,
  
Index
  
Mmbtu)
    
Floors
    
Ceilings
    
Oil-Bbls)
    
Price
    
Mmbtu)
    
Price
    
2010(1)
  
                                                 
Natural Gas
                                                
CIG
                                                
10/01 - 12/31/2010
     35,710     $ 4.75     $ 9.45       -     $ -       -     $ -     $ 23,186  
01/01 - 03/31/2011
     53,565       4.75       9.45       -       -       -       -       25,413  
                                                                 
NYMEX
                                                                
04/01 - 06/30/2010
     -       -       -       132,765       5.55       127,368       (1.88 )     28,152  
07/01 - 09/30/2010
     -       -       -       130,629       5.56       124,865       (1.88 )     (5,485 )
10/01 - 12/31/2010
     15,514       5.75       8.30       72,654       6.07       85,961       (1.88 )     (960 )
01/01 - 03/31/2011
     21,022       5.75       8.30       38,758       6.81       59,780       (1.88 )     (16,022 )
04/01 - 12/31/2011
     -       -       -       333,231       6.77       333,231       (1.88 )     (5,466 )
2012-2013
     28,595       6.00       8.27       752,556       7.05       781,150       (1.88 )     (231,224 )
Total Natural Gas
     154,406                       1,460,593               1,512,355               (182,406 )
                                                                 
Oil
                                                                
NYMEX
                                                                
04/01 - 06/30/2010
     -       -       -       3,300       92.96       -       -       28,524  
07/01 - 09/30/2010
     -       -       -       3,336       92.96       -       -       26,184  
10/01 - 12/31/2010
     -       -       -       3,336       92.96       -       -       24,621  
01/01 - 03/31/2011
     -       -       -       1,476       70.75       -       -       (21,146 )
04/01 - 12/31/2011
     -       -       -       4,473       70.75       -       -       (65,602 )
Total Oil
     -                       15,921               -               (7,419 )
                                                                 
Total Natural Gas and Oil
                                                           $ (189,825 )

(1) Approximately 9% of the fair value of the Partnership’s derivative assets and all of the Partnership’s derivative liabilities were measured using significant unobservable inputs (Level 3), see Note 4, Fair Value Measurements, to the accompanying unaudited condensed financial statements included in this report.

Natural Gas and Oil Production Costs

Generally, natural gas and oil production costs vary with changes in total natural gas and oil sales and 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 natural gas and oil 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.  In addition, 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 2010 three month period compared to 2009 three month period, oil and natural production, on an energy equivalency-basis, decreased 33,965 Mcfe, or 14%, due to normally-occurring production declines throughout an oil and natural gas well’s production life cycle in addition to temporary operational constraints during the current quarter at most Grand Valley Field and some Wattenberg Field Partnership wells.  Production and operating costs were lower by approximately $0.1 million, or 16% due in part, to volume-associated reductions in production taxes and lease operating expenses.  Although higher commodity valuations increased production taxes during the three months ended March 31, 2010, this increase was partially offset by a downward adjustment to these accrued taxes due to revisions to tax rates by the Colorado tax agencies, of which the Partnership was notified during the first quarter 2010.  Production and operating costs per Mcfe were $1.31 for the 2010 three month period compared to $1.34 for the comparable 2009 three month period.

 
- 15 -
 
PDC 2005-A LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

Direct Costs−General and Administrative

Direct costs – general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer’s reserve reports and legal matters.  Direct costs decreased during the three months ended March 31, 2010, compared to the same period in 2009, by approximately $0.1 million principally due to reduced billings for professional services.

Depreciation, Depletion and Amortization

DD&A expense related to natural gas and oil properties is directly related to production volumes for the period.  For the quarter ended March 31, 2009, the Partnership’s natural gas and oil economically producible reserve quantities were determined by valuing in-ground natural gas and oil resources, at the price of natural gas and oil as of December 31, 2008.  Upon adoption of the SEC’s final rule regarding the modernization of oil and gas reporting in the fourth quarter of 2009, the Partnership changed to a price determined by the 12-month average of the first-day-of-the-month price during each month of 2009.

The DD&A expense rate per Mcfe decreased to $3.53 for the 2010 three month period, compared to $4.55 during the same period in 2009 as calculated by the respective methodologies described above.  In addition, an out of period expense recorded in the first quarter of 2009 increased DD&A expense by approximately $106,000.  The variance in the per Mcfe rates for the 2010 period compared to the 2009 period is partially the result of the changing production mix between the Partnership’s Wattenberg and Grand Valley fields, which have significantly different DD&A rates, in addition to the effects of reserve revisions at December 31, 2009 compared to December 31, 2008 in which proved developed producing downward revisions in the Partnership’s Grand Valley Field were offset by upward proved developed producing revisions in its Wattenberg Field.  These decreased rates, combined with lower production volumes, resulted in the in DD&A expense reduction of approximately $0.4 million for the 2010 three month period compared to the same 2009 period.

Capital Resources and Liquidity

The Partnership’s primary sources of cash are from funds generated from the sale of natural gas and oil production and the realized gains from the Partnership’s derivative positions.  These sources of cash were primarily used to fund the Partnership’s operating cost, general and administrative activities and provide monthly distributions to the Investor Partners and PDC, the Managing General Partner.  Fluctuations in the Partnership’s operating cash flow are substantially driven by changes in commodity prices, in production volumes and in realized gains and losses from commodity positions.  Commodity prices have historically been volatile and the Partnership manages this volatility through derivatives.  Therefore, the primary source of the Partnership’s cash flow from operations becomes the net activity between the Partnership’s natural gas and oil sales and realized derivative gains and losses.  However, the Partnership does not engage in speculative positions, nor does the Partnership hold economic hedges for 100% of the Partnership’s expected future production from producing wells and therefore may still experience significant fluctuations in cash flows from operations.  As of March 31, 2010, the Partnership had natural gas and oil derivative positions in place covering 77% of expected natural gas production and 70% of expected oil production for the remainder of 2010, at an average price of $3.84 per Mcf and $92.96 per Bbl, respectively. See Results of Operations for further discussion of the impact of prices and volumes on sales from operations and the impact of derivative activities on the Partnership’s revenues.

The Partnership’s future operations are expected to be conducted with available funds and revenues generated from natural gas and oil production activities and commodity gains (losses).  Natural gas and oil production from the Partnership’s existing properties are generally expected to continue a gradual decline over the remaining life of the wells.  Therefore, the Partnership expects a lower annual level of natural gas and oil production and, in the absence of significant price increases or recompletions, lower revenues.  The Partnership also expects cash flows from operations to decline if commodity prices remain at current levels or decrease in the future.  Under these circumstances decreased production would have a material negative impact on the Partnership’s operations and may result in reduced cash distributions to the Investor Partners through the remainder of 2010 and beyond.  Future cash distributions may also be reduced to fund well recompletions in the Codell formation of the Wattenberg field.

 
- 16 -
 
PDC 2005-A LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

Working Capital

Working capital at March 31, 2010 was $1.2 million compared to working capital of $1.0 million at December 31, 2009.  This increase of approximately $0.2 million was primarily due to the following changes in accounts receivable balances:

 
·
Natural gas and oil receivables remained unchanged at $0.8 million as of March 31, 2010 and as of December 31, 2009.
 
·
Realized derivative gains receivables decreased to $0.3 million as of March 31, 2010, from $0.4 million as of December 31, 2009.
 
·
Net short-term unrealized derivative gains receivables increased to $0.1 million as of March 31, 2010.
 
·
Due to Managing General Partner-other, net, excluding natural gas and oil sales received from third parties and realized derivative gains, decreased to a $0.2 million liability as of March 31, 2010, from a $0.4 million liability as of December 31, 2009.

Cash Flows

Cash Flows From Investing Activities

The Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of natural gas and oil or environmental protection.  These amounts totaled approximately $6,000 and $16,000 for the three months ended March 31, 2010 and 2009, respectively.

Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in September 2005 and has distributed $41.3 million through March 31, 2010.  The table below presents the cash distributions to the Managing General Partner and Investor Partners, including Managing General Partner distributions relating to limited partnership units repurchased, for the periods described.

Quarter ended March 31,
  
Managing General Partner Distributions
    
Investor Partners Distributions
    
Total Distributions
  
                   
2010
   $ 255,551     $ 1,022,203     $ 1,277,754  
                         
2009
   $ 189,553     $ 758,217     $ 947,770  

 
- 17 -
 
PDC 2005-A LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

Cash Flows From Operating Activities

Net cash provided by operating activities was $1.3 million for the three months ended March 31, 2010, compared to $1.0 million for the comparable period in 2009.  The $0.3 million increase in cash provided by operating activities was due primarily to the following:

 
·
Increases in natural gas and oil sales receipts of $0.4, accompanied by decreases in production and operating cost of $0.1 million and direct costs – general and administrative of $0.1 million, offset by

 
·
Decreases in commodity price risk management realized gains receipts of $0.2 million, and

 
·
A decrease in the liability Due to Managing General Partner-other, net, excluding natural gas and oil sales received from third parties and realized derivative gains, of $0.2 million.

Commitments and Contingencies

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

Recent Accounting Standards

See Note 2, Recent Accounting Standards to the accompanying unaudited condensed financial statements.

Critical Accounting Policies and Estimates

The preparation of the accompanying unaudited condensed financial statements in conformity with U.S. GAAP 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.

There have been no other significant changes to the Partnership’s critical accounting policies and estimates 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 2009 Form 10-K, such policies include revenue recognition, derivatives instruments, fair value measurements, natural gas and oil properties, and asset retirement obligations are based on, among other things, judgments and assumptions made by management that include inherent risks and uncertainties.

 
- 18 -
 
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.

(a) Evaluation of Disclosure Controls and Procedures

As of March 31, 2010, PDC, as Managing General Partner of the Partnership, carried out an evaluation under the supervision and with the participation of the Managing General Partner’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Partnership’s disclosure controls and procedures pursuant to Securities Exchange Act Rule 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 that we file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that such information is accumulated and communicated to the Partnership’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely discussion regarding required financial disclosure.

Based on the results of this evaluation, the Managing General Partner’s Chief Executive Officer and the Chief Financial Officer concluded that the Partnership’s disclosure controls and procedures were effective as of March 31, 2010.

(b) Changes in Internal Control over Financial Reporting
 
PDC, the Managing General Partner, made no changes in the Partnership’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during the quarter ended March 31, 2010, that have materially affected or are reasonably likely to materially affect the Partnership’s internal control over financial reporting.

 
- 19 -
 
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.  There were no limited partnership units repurchased by PDC for the three months ended March 31, 2010.
 
 
Item 3.     Defaults Upon Senior Securities

Not applicable.


Item 4.     [Removed and Reserved]


Item 5.     Other Information

Not applicable.

 
- 20 -
 
PDC 2005-A LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

Item 6.     Exhibits

(a)       Exhibit Index.
       
Incorporated by Reference
Exhibit Number
  
Exhibit Description
  
Form
  
SEC File Number
  
Exhibit
  
Filing Date
  
Filed Herewith
3.1
  
Limited Partnership Agreement
  
10-12G/A
Amend 1
  
000-53201
  
3
  
08/06/2008
    
                         
3.2
  
Certificate of limited partnership which reflects the organization of the Partnership under West Virginia law
  
10-12G/A
Amend 1
  
000-53201
  
3.1
  
08/06/2008
    
                         
10.2
  
Drilling and operating agreement between the Partnership and PDC, as Managing General Partner of the Partnership
  
10-12G/A
Amend 1
  
000-53201
  
10.2
  
08/06/2008
    
                         
 
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.
                  
X
                         
 
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.
                  
X
                         
 
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

 
- 21 -
 
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. McCullough
Richard W. McCullough
Chairman and Chief Executive Officer
May 14, 2010


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 14, 2010
Richard W. McCullough
  
Petroleum Development Corporation
    
   
Managing General Partner of the Registrant
    
   
(Principal executive officer)
    
         
/s/ Gysle R. Shellum
  
Chief Financial Officer
  
May 14, 2010
Gysle R. Shellum
  
Petroleum Development Corporation
    
   
Managing General Partner of the Registrant
    
   
(Principal financial officer)
    
         
/s/ R. Scott Meyers
  
Chief Accounting Officer
  
May 14, 2010
R. Scott Meyers
  
Petroleum Development Corporation
    
   
Managing General Partner of the Registrant
    
   
(Principal accounting officer)
    
 
 
- 22 -