PDC 2005-A Limited Partnership - FORM 10-Q - November 5, 2010

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
 
FORM 10-Q
 
x QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended September 30, 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
 
    
20-2088347
 
(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 (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 o No þ
 
As of September 30, 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)
 
       
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          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” or the “Registrant”) 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”) strategies, plans and objectives. However, these words are not the exclusive means of identifying forward-looking statements herein. PDC now conducts business under the name “PDC Energy.”
 
          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;
 
●
changes in estimates of proved reserves;
 
●
declines in the values of the Partnership’s natural gas and oil properties resulting from impairments;
 
●
the timing and extent of the Partnership’s success in further developing and producing the Partnership’s natural gas and oil reserves;
 
●
the Managing General Partner’s ability to acquire drilling rig services, supplies and services at reasonable prices;
 
●
risks incident to the refracturing and operation of natural gas and oil wells;
 
●
future production and refracturing costs;
 
●
the availability of Partnership future cash flows for investor distributions or funding of Well Refracturing Plan activities;
 
●
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, or U.S.;
 
●
changes in environmental laws and the regulations and enforcement related to those laws;
 
●
the identification of and severity of environmental events and governmental responses to the events;
 
●
the effect of natural gas and oil derivatives activities;
  ● the availability of funding for the consideration payable by PDC and its wholly-owned subsidiary to consummate the prospective mergers under the Acquisition Plan;
  ●
the timing and closing, if consummated, of the proposed merger of the 2004 partnerships with and into a wholly-owned subsidiary of PDC;
 
●
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 reports on Form 10-K and Form 10-K/A for the year ended December 31, 2009 filed with the Securities and Exchange Commission, or SEC, on March 31, 2010 and August 27, 2010 (“2009 Form 10-K” or “2009 Form 10-K/A”, respectively) 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 made. Other than as required under the securities laws, 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 -
 
 
 
PDC 2005-A Limited Partnership
(unaudited)
             
   
September 30,
 2010
    
December 31,
 2009*
  
Assets
            
             
Current assets:
            
Cash and cash equivalents
   $ 321,441     $ 224,751  
Accounts receivable
     242,270       408,544  
Oil inventory
     27,914       33,305  
Due from Managing General Partner-derivatives
     974,873       554,898  
Due from Managing General Partner-other, net
     15,191       355,801  
Total current assets
     1,581,689       1,577,299  
                 
Oil and gas properties, successful efforts method, at cost
     44,445,794       44,419,132  
Less: Accumulated depreciation, depletion and amortization
     (22,847,766 )     (20,809,309 )
Oil and gas properties, net
     21,598,028       23,609,823  
                 
Due from Managing General Partner-derivatives
     1,619,492       516,653  
Other assets
     44,384       24,607  
Total noncurrent assets
     23,261,904       24,151,083  
                 
Total Assets
   $ 24,843,593     $ 25,728,382  
                 
Liabilities and Partners’ Equity
                
                 
Current liabilities:
                
Accounts payable and accrued expenses
   $ 67,675     $ 41,448  
Due to Managing General Partner-derivatives
     557,082       529,551  
Total current liabilities
     624,757       570,999  
                 
Due to Managing General Partner-derivatives
     1,182,965       1,487,222  
Asset retirement obligations
     533,302       512,800  
Total liabilities
     2,341,024       2,571,021  
                 
Commitments and contingent liabilities
                
                 
Partners’ equity:
                
Managing General Partner
     4,515,498       4,646,456  
Limited Partners - 1,996.87 units issued and outstanding
     17,987,071       18,510,905  
Total Partners’ equity
     22,502,569       23,157,361  
                 
Total Liabilities and Partners’ Equity
   $ 24,843,593     $ 25,728,382  
 
*Derived from audited 2009 balance sheet
 
See accompanying notes to unaudited condensed financial statements.

 
- 2 -
 
PDC 2005-A Limited Partnership
                         
   
Three months ended September 30,
    
Nine months ended September 30,
  
   
2010
    
2009
    
2010
    
2009
  
Revenues:
                        
Natural gas and oil sales
   $ 835,268     $ 772,050     $ 3,048,792     $ 2,267,638  
Commodity price risk management gain (loss), net
     862,070       (593,108 )     2,415,131       (1,413,890 )
Total revenues
     1,697,338       178,942       5,463,923       853,748  
                                 
Operating costs and expenses:
                                
Natural gas and oil production costs
     424,650       459,163       1,026,163       1,186,398  
Direct costs - general and administrative
     35,197       79,882       114,008       348,751  
Depreciation, depletion and amortization
     607,225       916,146       2,038,457       2,857,006  
Accretion of asset retirement obligations
     6,936       4,624       20,502       13,872  
Total operating costs and expenses
     1,074,008       1,459,815       3,199,130       4,406,027  
                                 
Income (loss) from operations
     623,330       (1,280,873 )     2,264,793       (3,552,279 )
                                 
Interest expense
     —       (2,338 )     —       (2,338 )
Interest income
     —       11,848       —       33,815  
                                 
Net income (loss)
   $ 623,330     $ (1,271,363 )   $ 2,264,793     $ (3,520,802 )
                                 
Net income (loss) allocated to partners
   $ 623,330     $ (1,271,363 )   $ 2,264,793     $ (3,520,802 )
Less: Managing General Partner interest in net income (loss)
     124,666       (254,272 )     452,959       (704,160 )
Net income (loss) allocated to Investor Partners
   $ 498,664     $ (1,017,091 )   $ 1,811,834     $ (2,816,642 )
                                 
Net income (loss) per Investor Partner unit
   $ 250     $ (509 )   $ 907     $ (1,411 )
                                 
Investor Partner units outstanding
     1,996.87       1,996.87       1,996.87       1,996.87  
 
See accompanying notes to unaudited condensed financial statements.
 
 
- 3 -
 
PDC 2005-A Limited Partnership
             
   
Nine months ended September 30,
  
   
2010
    
2009
  
Cash flows from operating activities:
            
Net income (loss)
   $ 2,264,793     $ (3,520,802 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
                
Depreciation, depletion and amortization
     2,038,457       2,857,006  
Accretion of asset retirement obligations
     20,502       13,872  
Unrealized (gain) loss on derivative transactions
     (1,799,540 )     3,400,498  
Changes in operating assets and liabilities:
                
Decrease in accounts receivable
     166,274       95,311  
Decrease (increase) in oil inventory
     5,391       (7,178 )
Increase in other assets
     (19,777 )     (18,133 )
Increase (decrease) in accounts payable and accrued expenses
     26,227       (36,522 )
Decrease in due from Managing General Partner - other, net
     340,610       1,447,392  
Net cash provided by operating activities
     3,042,937       4,231,444  
                 
Cash flows from investing activities:
                
Capital expenditures for oil and gas properties
     (26,662 )     (26,381 )
Proceeds from drilling advance refund from Managing General Partner
     —       108,531  
Net cash (used in) provided by investing activities
     (26,662 )     82,150  
                 
Cash flows from financing activities:
                
Distributions to Partners
     (2,919,585 )     (4,403,453 )
Net cash used in financing activities
     (2,919,585 )     (4,403,453 )
                 
Net increase in cash and cash equivalents
     96,690       (89,859 )
Cash and cash equivalents, beginning of period
     224,751       314,610  
Cash and cash equivalents, end of period
   $ 321,441     $ 224,751  
 
See accompanying notes to unaudited condensed financial statements.

 
 
- 4 -
 
PDC 2005-A LIMITED PARTNERSHIP
September 30, 2010
(unaudited)
Note 1−General and Basis of Presentation

The PDC 2005-A Limited Partnership (the "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 that now conducts business under the name “PDC Energy”, 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 September 30, 2010, there were 1,502 Investor Partners.  As of September 30, 2010, the Managing General Partner has repurchased 28.21 units of the total 1,996.87 outstanding units of Partnership interests from Investor Partners at an average price of $9,147 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 natural gas and oil properties until such time that the Partnership’s wells are depleted or become uneconomical to produce, at which time that well may be sold or plugged, reclaimed 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 statement 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 Securities and Exchange Commission, or 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 and nine months ended September 30, 2010, and the cash flows for the nine months ended September 30, 2010, are not necessarily indicative of the results to be expected for the full year or any other future period.

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.
 
 
- 5 -
 
PDC 2005-A LIMITED PARTNERSHIP
September 30, 2010
(unaudited)
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.

Internal Control over Financial Reporting in Exchange Act Periodic Reports

By Final Rule effective September 21, 2010, the SEC amended its rules and forms to conform them to Section 404(c) of the Sarbanes-Oxley Act of 2002, or SOX, as added by the Dodd-Frank Wall Street Reform and Consumer Protection Act.  The new SEC rules exempt the Partnership, as a smaller reporting company filer, from the SOX requirement that registrants which are accelerated or large accelerated filers, obtain and include in their annual report filed with the SEC, their independent registered public accounting firm’s attestation report on the effectiveness of the registrant’s internal controls over financial reporting.

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.

   
September 30,
    
December 31,
  
   
2010
    
2009
  
             
Natural gas and oil sales revenues collected from the Partnership's third-party customers
   $ 331,228     $ 392,255  
Commodity Price Risk Management, Realized Gains
     80,795       396,498  
Other (1)
     (396,832 )     (432,952 )
Total Due from Managing General Partner-other, net
   $ 15,191     $ 355,801  
 
 
(1)
All other unsettled transactions, excluding derivative instruments, between the Partnership and the Managing General Partner.  The majority of these are operating costs or general and administrative costs which have not been deducted from distributions.
 
 
- 6 -
 
PDC 2005-A LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
September 30, 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 the three and nine months ended September 30, 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 September 30,       Nine months ended September 30,  
   
2010
    
2009
    
2010
    
2009
  
                         
Well operations and maintenance
   $ 323,909     $ 363,182     $ 733,032     $ 910,103  
Gathering, compression and processing fees
     46,374       50,424       138,804       144,907  
Direct costs - general and administrative
     35,197       79,882       114,008       348,751  
Cash distributions*
     124,411       368,132       612,545       910,133  
 
*Cash distributions include $6,430 and $28,628 during the three and nine months ended September 30, 2010, respectively, and $8,742 and $29,444 during the three and nine months ended September 30, 2009, respectively, related to equity cash distributions on Investor Partner units repurchased by PDC.

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, which 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 September 30, 2010, the impact of non-performance risk on the fair value of the Partnership’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
September 30, 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 (Level 1)
    
Significant Unobservable Inputs (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 September 30, 2010
                        
Assets:
                        
Commodity based derivatives
   $ 2,374,031     $ 220,334     $ 2,594,365  
Total assets
     2,374,031       220,334       2,594,365  
                         
Liabilities:
                        
Commodity based derivatives
     —       (79,636 )     (79,636 )
Basis protection derivative contracts
     —       (1,660,411 )     (1,660,411 )
Total liabilities
     —       (1,740,047 )     (1,740,047 )
                         
Net asset (liability)
   $ 2,374,031     $ (1,519,713 )   $ 854,318  

The following table presents the changes of the Partnership’s Level 3 derivative financial instruments measured on a recurring basis:
       
   
Nine months ended September 30, 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
     173,036  
Settlements
     (268,267 )
Fair value, net liability, as of September 30, 2010
   $ (1,519,713 )
         
Change in unrealized gains (losses) relating to assets (liabilities) still held as of September 30, 2010 included in statement of operations line item:
        
Commodity price risk management, net   $  38,751  
 
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.
 
 
- 8 -
 
PDC 2005-A LIMITED PARTNERSHIP
September 30, 2010
(unaudited)
Note 5−Derivative Financial Instruments

As of September 30, 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 1,351,605 MMbtu of natural gas and 9,285 Bbls of oil.  Partnership policy prohibits the use of natural gas and oil derivative instruments for speculative purposes.

The following table summarizes the line item 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
  
September 30, 2010
    
December 31, 2009
  
                   
Derivative Assets:
Current
                
 
Commodity contracts
  
Due from Managing General
Partner-derivatives
   $ 974,873     $ 554,898  
                       
 
Non Current
                    
 
Commodity contracts
  
Due from Managing General
Partner-derivatives
     1,619,492       516,653  
                       
Total Derivative Assets
         $ 2,594,365     $ 1,071,551  
                       
Derivative Liabilities:
Current
                    
 
Commodity contracts
  
Due to Managing General
Partner-derivatives
   $ 57,760     $ 42,274  
 
 
  
 
                
 
Basis protection contracts
  
Due to Managing General
Partner-derivatives
     499,322       487,277  
                       
 
Non Current
                    
 
Commodity contracts
  
Due to Managing General
Partner-derivatives
     21,877       89,584  
 
 
  
 
                
 
Basis protection contracts
  
Due to Managing General
Partner-derivatives
     1,161,088       1,397,638  
Total Derivative Liabilities
       $ 1,740,047     $ 2,016,773  
 
(1) As of September 30, 2010 and December 31, 2009, none of the Partnership’s derivative instruments were designated as hedges.

The following table summarizes the impact of the Partnership’s derivative instruments on the Partnership’s accompanying statements of operations for the three and nine months ended September 30, 2010 and 2009.

      Three months ended September 30,  
      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 Losses For the Current Period
    
Total
  
                                     
Commodity price risk management, net
                                    
Realized gains (losses)
   $ 27,270     $ 56,931     $ 84,201     $ 513,607     $ (6,329 )   $ 507,278  
Unrealized (losses) gains
     (27,270 )     805,139       777,869       (513,607 )     (586,779 )     (1,100,386 )
Total commodity price risk management gain (loss), net
   $ —     $ 862,070     $ 862,070     $ —     $ (593,108 )   $ (593,108 )
 
                                                 
      Nine months ended September 30,  
     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
   $ 108,282     $ 507,309     $ 615,591     $ 1,557,047     $ 429,561     $ 1,986,608  
Unrealized (losses) gains
     (108,282 )     1,907,822       1,799,540       (1,557,047 )     (1,843,451 )     (3,400,498 )
Total commodity price risk management gain (loss), net
   $ —     $ 2,415,131     $ 2,415,131     $ —     $ (1,413,890 )   $ (1,413,890 )
 
 
- 9 -
 
PDC 2005-A LIMITED PARTNERSHIP
September 30, 2010
(unaudited)
 
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 the 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 defaults.

Note 6−Commitments and Contingencies

Environmental

Due to the nature of the natural gas and oil business, the Partnership is exposed to environmental risks.  The Managing General Partner has various policies and procedures to avoid environmental contamination and mitigate the risks from environmental contamination.  The Managing General Partner conducts periodic reviews to identify changes in the Partnership’s environmental risk profile.  Liabilities are accrued when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated.  As of September 30, 2010, the Partnership had accrued an environmental remediation liability included in the Balance Sheet line item captioned “Accounts payable and accrued expenses.” This accrual represents costs estimated to be incurred in addition to normal recurring environmental-related expenditures which have been incurred and recorded at September 30, 2010.  During the third quarter of 2010, the Managing General Partner identified existing ground contamination at one Partnership well site.  The Partnership recorded an accrual of approximately $35,000, which is the estimated cost attributable to the Partnership, based principally on estimated third party costs, to remediate the ground contamination less actual costs incurred through September 30, 2010, if any.  The Managing General Partner is not aware of any environmental claims existing as of September 30, 2010 which have not been provided for or would otherwise have a material impact on the Partnership’s financial statements.  However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on the Partnership’s properties.

    In December 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 natural gas and oil companies operating in the Piceance region of Colorado.  Operating expenses, including this fine, 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 alleged 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 into 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 with certainty the ultimate outcome of this administrative action; however, the Managing General Partner does not believe that the ultimate outcome will have a material adverse effect on the Partnership’s financial position or results of operations.

Note 7– Subsequent Events
 
On October 20, 2010, the Managing General Partner notified Investor Partners by letter, that the Partnership commenced the withholding of funds, on a pro-rata basis allocated to the Managing General Partner and Investor Partners based on their proportional ownership interest, which will be utilized to further develop the Partnership’s Denver-Julesburg (“DJ”) Basin Wattenberg Field wells under the previously announced Well Refracturing Plan.  The plan provides for the refracturing of the Partnership’s Wattenberg Field wells in the currently producing Codell formation and these activities are expected to begin mid-to-late 2011.  Funds withheld from the Partnership’s investors, including the Managing General Partner, in the October 2010 distribution amounted to $20,000 and have been deposited in the Partnership’s bank account.
 
 
- 10 -

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

Partnership 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) productive wells located in the Rocky Mountain Region in the state of Colorado.  The Managing General Partner markets the Partnership’s natural gas production to commercial end users, interstate or intrastate pipelines or local utilities, primarily under market sensitive contracts in which the price of natural gas sold varies as a result of market forces.  PDC does not charge an additional fee for the marketing of the natural gas and oil because these services are covered by the monthly well operating charge.  PDC, on behalf of the Partnership in accordance with the D&O Agreement, is authorized to 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.

PDC Sponsored Drilling Program Acquisition Plan
 
PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue the acquisitions, within the next three years beginning in the fall of 2010, of the remaining third-party Investor Partner interests in the limited partnerships which PDC has sponsored (the “Acquisition Plan”), including this Partnership.  (For additional information regarding PDC’s intention to pursue acquisitions of PDC sponsored partnerships, refer to the disclosure included in Items 2.02 and/or 7.01 of PDC’s Forms 8-K dated March 4, 2010, June 9, 2010 and July 15, 2010, which information shall not, by reason of this reference, be deemed to be incorporated by reference in, or otherwise be deemed to be part of, this report).  Under the Acquisition Plan, any existing or future merger offer will be subject to the terms and conditions of the related merger agreement and such agreement does or will likely contemplate the partnership being merged with and into a wholly owned subsidiary of PDC.  The transaction will also be subject to, among other things, PDC having sufficient available capital and the approval by a majority of the limited partnerships units held by the Investor Partners, excluding limited partnership units owned by PDC or its affiliates, of each respective limited partnership. Consummation of any proposed merger under the Acquisition Plan will likely result in the termination of the existence of that partnership and the right for third-party Investor Partners to receive a cash payment for their limited partnership units in that partnership.
 
                In June 2010, PDC and a wholly owned subsidiary of PDC entered into a merger agreement with PDC 2004-A Limited Partnership, PDC 2004-B Limited Partnership, PDC 2004-C Limited Partnership and PDC 2004-D Limited Partnership (collectively, the “2004 partnerships”).  PDC serves as the managing general partner of each of the 2004 partnerships.  Pursuant to each merger agreement, if the merger is approved by the holders of a majority of the limited partnership units held by Investor Partners of that partnership not owned by PDC or its affiliates, as well as the satisfaction of other customary closing conditions, then the partnership will merge with and into a wholly owned subsidiary of PDC.  If all four 2004 partnerships are acquired, PDC will pay up to an aggregate of approximately $36.4 million for the limited partnership units of these partnerships. Definitive proxy statements for each of the 2004 partnerships requesting approval from the applicable third-party Investor Partners for, among other things, the merger agreements were mailed to the third-party Investor Partners of the 2004 partnerships in early October 2010. The special meetings whereby third-party Investor Partners of the 2004 partnerships will have an opportunity to vote and approve the applicable merger agreement are currently scheduled for December 8, 2010 for each of the 2004 partnerships. If the required approvals are received from the third-party Investor Partners at the special meetings, each of the mergers for the 2004 partnerships is expected to close shortly thereafter and no later than December 31, 2010. The feasibility and timing of any future purchase offer by PDC to any additional partnership, including this Partnership, depends on that partnership’s suitability in meeting a set of criteria that includes, but is not limited to, the following:  age and productive-life stage characteristics of the partnership’s well inventory; favorability of economics for Wattenberg Field well refracturing; and SEC reporting compliance status and timing associated to gaining all necessary regulatory approvals required for a merger and repurchase offer.  There is no assurance that any merger and acquisition will occur as a result of the proposed repurchase offers to PDC’s 2004 partnerships, or any potential proposed repurchase offer to any other of PDC’s various public limited partnerships, including this Partnership, should they occur.
 
 
- 11 -
 
PDC 2005-A LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
 
Well Refracturing Plan

The Managing General Partner has developed the Well Refracturing Plan for the Partnership’s Wattenberg Field wells that were initially completed in the Codell formation during the Partnership’s initial development. Under the plan, the Partnership will initiate Codell formation refracturing activities during 2011.  These refracturing, or “refracing”, activities will consist of a second hydraulic fracturing treatment to the currently producing Codell formation.

Funding of the initial well refracturing activity began with the withholding, on a pro-rata basis, of $20,000 from the Partnership’s October 2010 monthly distributable cash flows which was allocated to the Managing General Partner and Investor Partners based on their proportional ownership interest.  This withholding was deposited into the Partnership’s bank account.

After the initial refrac funding is completed in 2011, the Partnership will re-evaluate the Well Refracturing Plan funding requirements and will continue to withhold cash at varying levels on a pro-rata basis, from the Managing General Partner’s and Investor Partner’s distributable cash flows from current production operations.  The most recent cost projection for Codell formation well refracturing ranges between $150,000 and $200,000 per refrac.  Total withholding from the Partnership’s distributable cash flows for the Partnership’s 33 well refracturing opportunities is estimated to be between $5.0 million and $6.6 million.  The number of refracturings and the timing of refracturing will be based on the availability of cash withheld from Partnership distributions.  The necessary funds to be retained by the Partnership for the payment of Well Refracturing Plan activities may materially reduce, up to 100%, of the Managing General Partner’s and Investor Partners’ distributable cash flows for a period of time not to exceed five years.

Partnership Operating Results Overview

Natural gas and oil sales increased 34% or $0.8 million for the first nine months of 2010 compared to the first nine months of 2009, even though production volumes decreased 12% period-to-period.  This increase was driven primarily by the improved commodity price environment and the increase in the Partnership’s oil production as a percentage of total production.  The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.10 for the current year period compared to $3.32 for the same period a year ago.  Realized derivative gains from natural gas and oil sales contributed an additional $1.02 per Mcfe or $0.6 million to the first nine months of 2010 total revenues.  Comparatively, the total per Mcfe price realized, consisting of the average sales price and realized derivative gains, decreased slightly to $6.12 for the current year nine months from $6.23 for the same prior year period.

The increase in revenues did not have a corresponding impact on costs and expenses as natural gas and oil production costs and general and administrative expense combined decreased by $0.4 million for the current year nine months compared to the same prior year period.  The decrease is primarily due to a reduction in billed professional fees and lower lease operating expenses due to the Managing General Partner’s cost cutting initiatives in the 2010 period compared to the 2009 period.
 
 
- 12 -
 
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 September 30,
    
Nine months ended September 30,
  
   
2010
    
2009
    
Change
    
2010
    
2009
    
Change
  
Number of producing wells (end of period)
     49       48       1       49       48       1  
                                                 
Production (1)
                                                
Natural gas (Mcf)
     162,575       197,809       -18 %     493,988       569,805       -13 %
Oil (Bbl)
     4,688       5,756       -19 %     17,382       18,859       -8 %
Natural gas equivalents (Mcfe) (2)
     190,703       232,345       -18 %     598,280       682,959       -12 %
                                                 
Natural Gas and Oil Sales
                                                
Natural gas
   $ 511,811     $ 459,280       11 %   $ 1,807,333     $ 1,388,394       30 %
Oil
     323,457       312,770       3 %     1,241,459       879,244       41 %
Total natural gas and oil sales
   $ 835,268     $ 772,050       8 %   $ 3,048,792     $ 2,267,638       34 %
                                                 
Realized Gain on Derivatives, net
                                                
Natural gas
   $ 28,317     $ 421,446       -93 %   $ 464,099     $ 1,603,556       -71 %
Oil
     55,884       85,832       -35 %     151,492       383,052       -60 %
Total realized gain on derivatives, net
   $ 84,201     $ 507,278       -83 %   $ 615,591     $ 1,986,608       -69 %
                                                 
Average Selling Price (excluding realized gain on derivatives)
                                                
Natural gas (per Mcf)
   $ 3.15     $ 2.32       36 %   $ 3.66     $ 2.44       50 %
Oil (per Bbl)
     69.00       54.34       27 %     71.42       46.62       53 %
Natural gas equivalents (per Mcfe)
     4.38       3.32       32 %     5.10       3.32       53 %
                                                 
Average Selling Price (including realized gain on derivatives)
                                                
Natural gas (per Mcf)
   $ 3.32     $ 4.45       -25 %   $ 4.60     $ 5.25       -12 %
Oil (per Bbl)
     80.92       69.25       17 %     80.14       66.93       20 %
Natural gas equivalents (per Mcfe)
     4.82       5.51       -12 %     6.12       6.23       -2 %
                                                 
Average Lifting Cost (per Mcfe) (3)
   $ 2.23     $ 1.98       12 %   $ 1.72     $ 1.74       -1 %
                                                 
Operating costs and expenses
                                                
Direct costs - general and administrative
   $ 35,197     $ 79,882       -56 %   $ 114,008     $ 348,751       -67 %
Depreciation, depletion and amortization
   $ 607,225     $ 916,146       -34 %   $ 2,038,457     $ 2,857,006       -29 %
                                                 
Cash distributions
   $ 589,905     $ 1,796,951       -67 %   $ 2,919,585     $ 4,403,453       -34 %
 
 
(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)
Lifting costs represent natural gas and oil operating expenses which include production taxes.

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

 
●
Bbl – One barrel or 42 U.S. gallons liquid volume
 
●
MBbl – One thousand barrels
 
●
Mcf – One thousand cubic feet
 
●
MMcf – One million cubic feet
 
●
Mcfe – One thousand cubic feet of natural gas equivalents
 
●
MMcfe – One million cubic feet of natural gas equivalents
 
●
MMbtu – One million British Thermal Units
 
 
- 13 -
 
PDC 2005-A LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
 
Natural Gas and Oil Sales

Nine months ended September 30, 2010 as compared to nine months ended September 30, 2009

The $0.8 million, or 34% increase in sales for the 2010 nine month period as compared to the prior year period, was primarily a reflection of the significantly higher average sales price per Mcfe of 53%, which was partially offset by a production volume decrease of 12%.  The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.10 for the current year nine month period compared to $3.32 for the same period a year ago.

Natural gas and oil revenues increased by 30% and 41%, respectively. The Partnership’s natural gas revenue increase benefited from rising commodity prices per Mcf of 50%, which were partially offset by lower Partnership natural gas production volumes of 13%.  This compares to the more significant oil revenue increase in which the rise in commodity prices of 53% was partially offset by a more moderate decline in oil production volumes, per Bbl of 8% during the current nine month period.

Three months ended September 30, 2010 as compared to three months ended September 30, 2009

The 8% increase in sales for the 2010 third quarter as compared to the prior year third quarter was primarily a reflection of the higher average sales price per Mcfe of 32%, substantially offset by the production volume decrease of 18%.  Average sales prices per Mcfe, excluding the impact of realized derivative gains, were $4.38 for the current year quarter compared to $3.32 for the same quarter a year ago.

The Partnership expects to experience 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 refraced.  Subsequent to a successful refracturing, 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 on PDC’s ability to market the Partnership’s production effectively.  Natural gas and oil prices are among the most volatile of all commodity prices.  This price volatility has 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 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 local market oversupply situations 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.  Oil pricing, unlike natural gas pricing, is driven predominantly by global supply and demand relationships.

The price at which PDC markets the natural gas produced in the Rocky Mountain Region by the Partnership 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 regional 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 the last year and is lower than historical variances.  This negative differential between NYMEX and CIG averaged $0.72 and $1.16 for the three and nine months ended September 30, 2009, respectively, and narrowed to an average of $0.51 and $0.88 for the three and nine months ended September 30, 2010, respectively.
 
 
- 14 -
 
PDC 2005-A LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Commodity Price Risk Management, Net

The Managing General Partner, on behalf of the Partnership in accordance with the D&O Agreement, is authorized to utilize various derivative instruments to manage volatility in natural gas and oil prices.  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 September 30,
    
Nine months ended September 30,
  
 
  
2010
    
2009
    
2010
    
2009
  
Commodity price risk management gain (loss), net
                        
Realized gains
                        
Natural Gas
   $ 28,317     $ 421,446     $ 464,099     $ 1,603,556  
Oil
     55,884       85,832       151,492       383,052  
Total realized gain, net
     84,201       507,278       615,591       1,986,608  
                                 
Unrealized gains (losses)
                                
Reclassification of realized gains included in prior periods unrealized
     (27,270 )     (513,607 )     (108,282 )     (1,557,047 )
Unrealized gain (loss) for the period
     805,139       (586,779 )     1,907,822       (1,843,451 )
Total unrealized gain (loss), net
     777,869       (1,100,386 )     1,799,540       (3,400,498 )
Commodity price risk management gain (loss), net
   $ 862,070     $ (593,108 )   $ 2,415,131     $ (1,413,890 )

Nine months ended September 30, 2010 as compared to nine months ended September 30, 2009

The realized derivative gains for the 2010 nine month period were $0.6 million.  These realized gains were primarily a result of lower natural gas and oil spot prices at settlement compared to the respective strike price, offset in part by realized losses due to the basis differential between NYMEX and CIG being narrower than the strike price of the derivative position.  For the 2010 nine month period, realized gains related to the Partnership's commodity positions were $0.9 million and realized losses on the Partnership’s basis position were $0.3 million.  Unrealized gains for the 2010 nine month period were $1.9 million due primarily to a downward shift in the natural gas and oil forward curves, offset by unrealized losses due to the basis differential between NYMEX and CIG being narrower than the strike price of the derivative position.  Unrealized gains on the Partnership’s commodity positions for the 2010 nine month period were $2.0 million offset by unrealized losses on the Partnership's basis position of $0.1 million.

For the 2009 nine month period, the Partnership realized significant derivative gains as a result of lower natural gas and oil prices at settlement compared to the respective derivative strike prices.  Unrealized losses for the period were related to oil swaps, as the forward strip price of oil rebounded during the period, and the CIG basis swaps, as the forward basis differential during the period between NYMEX and CIG continued to narrow from the strike price of the derivative position.

Three months ended September 30, 2010 as compared to three months ended September 30, 2009

The realized derivative gains for the 2010 third quarter were approximately $0.1 million.  These realized gains are a result of lower natural gas and oil spot prices at settlement compared to the respective strike price, offset in part by realized losses due to the basis differential between NYMEX and CIG being narrower than the strike price of the derivative position.  For the quarter, realized gains related to the Partnership's commodity positions were $0.2 million and realized losses on the Partnership’s basis position were $0.1 million.  For the 2010 quarter, the unrealized gains of $0.8 million were primarily related to the oil positions, as the forward strip price shifted downward during the quarter, and the widening of the NYMEX-CIG basis differential.  Unrealized gains on the Partnership’s commodity positions for the 2010 third quarter were $0.9 million offset by unrealized losses on the Partnership's basis position of $0.1 million.
 
 
- 15 -
 
PDC 2005-A LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
 
For the 2009 third quarter, the Partnership realized significant derivative gains as a result of lower natural gas and oil prices at settlement compared to the respective derivative strike prices.  Unrealized losses for the period were primarily related to oil swaps, as the forward strip price of oil rebounded during the period, and the CIG basis swaps, as the forward basis differential during the period between NYMEX and CIG continued to narrow from the strike price of the derivative position.

Natural Gas and Oil Sales Derivative Instruments.  The Managing General Partner, on behalf of the Partnership in accordance with the D&O Agreement, is authorized to utilize various derivative instruments to manage volatility in natural gas and oil prices.  The Partnership has in place a series of collars, fixed-price swaps and a basis swap on a portion of the Partnership’s natural gas and oil production.  See Note 5, Derivative Financial Instruments to the Partnership’s financial statements included in the 2009 Form 10-K for an additional discussion on how each derivative type impacts the Partnership’s cash flows.

The following table presents the Partnership’s derivative positions in effect as of September 30, 2010.

      Collars    
Fixed-Price Swaps
    
CIG Basis Protection Swaps
        
 
  
Quantity
(Gas-
    
Weighted Average
Contract Price
    
Quantity
(Gas-Mmbtu
    
Weighted
Average
Contract
    
Quantity
(Gas-
    
Weighted
Average
Contract
    
Fair Value at
September 30,
  
Commodity/ Index
  
Mmbtu)(1)
    
Floors
    
Ceilings
    
Oil-Bbls)(1)
    
Price
    
Mmbtu)(1)
    
Price
    
2010(2)
  
                                                 
Natural Gas
                                                
CIG
                                                
10/01 - 12/31/2010
     35,710     $ 4.75     $ 9.45       —     $ —       —     $ —     $ 39,774  
01/01 - 03/31/2011
     53,565       4.75       9.45       —       —       —       —       49,712  
                                                                 
NYMEX
                                                                
10/01 - 12/31/2010
     15,514       5.75       8.30       72,654       6.07       85,961       (1.88 )     60,826  
01/01 - 03/31/2011
     21,022       5.75       8.30       38,758       6.81       59,780       (1.88 )     42,065  
04/01 - 06/30/2011
     —       —       —       113,252       6.78       113,252       (1.88 )     134,793  
07/01 - 09/30/2011
     —       —       —       111,525       6.73       111,525       (1.88 )     109,396  
10/01 - 12/31/2011
     —       —       —       108,454       6.78       108,454       (1.88 )     68,147  
2012-2013
     28,595       6.00       8.27       752,556       7.05       781,150       (1.88 )     390,256  
Total Natural Gas
     154,406                       1,197,199               1,260,122               894,969  
                                                                 
Oil
                                                                
NYMEX
                                                                
10/01 - 12/31/2010
     —       —       —       3,336       92.96       —       —       38,984  
01/01 - 03/31/2011
     —       —       —       1,476       70.75       —       —       (17,709 )
04/01 - 06/30/2011
     —       —       —       1,487       70.75       —       —       (19,460 )
07/01 - 09/30/2011
     —       —       —       1,483       70.75       —       —       (20,589 )
10/01 - 12/31/2011
     —       —       —       1,503       70.75       —       —       (21,877 )
Total Oil
     —                       9,285               —               (40,651 )
                                                                 
Total Natural Gas and Oil
                                                           $ 854,318  
 
(1)  A standard unit of measure for natural gas (one MMBtu equals one Mcf).  
(2) 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.  Production taxes are estimates by the Managing General Partner based on tax rates determined using published information.  These estimates are subject to revision based on actual amounts determined during future filings by the Managing General Partner with the taxing authorities.  Production 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 but are expected to increase as wells age and require more extensive repair and maintenance.  These costs include water hauling and disposal, equipment repairs and maintenance, snow removal, environmental compliance and remediation, and service rig workovers.
 
 
- 16 -

PDC 2005-A LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
 
Nine months ended September 30, 2010 as compared to nine months ended September 30, 2009
 
For the nine months ended September 30, 2010 compared to the same period in 2009, natural gas and oil production, on an energy equivalency-basis, decreased 12%, due to normal production declines for this stage in the wells’ production life cycle.  Additionally, Grand Valley Field operational constraints on most wells in the first half of the year and three Grand Valley well workovers noted below, also contributed to the production decline during the current period.
 
Production and operating costs were lower by approximately $0.2 million or 14%, due in part, to lower lease operating expenses due to the Managing General Partner’s cost cutting initiatives partially offset by three well workovers and increased production taxes due to higher commodity valuations.  Additionally, 2010 well operations costs rose as a result of the increase in the per well operations fee charged by the Managing General Partner, consistent with the terms of the D&O Agreement.  Production and operating costs per Mcfe were $1.72 for the nine months ended September 30, of 2010 compared to $1.74 for the comparable period in 2009.
 
Three months ended September 30, 2010 as compared to three months ended September 30, 2009
 
For the quarter ended September 30, 2010 compared to the same period in 2009, natural gas and oil production, on an energy equivalency-basis, decreased 18%, primarily as a result of normal production decline as well as the Partnership wells’ reduced performance due the Grand Valley well workovers during the quarter.
 
Production and operating costs were lower by approximately $0.1 million, or 8% due to lower lease operating costs that were partially offset the three Grand Valley well workovers.  Production and operating costs per Mcfe were $2.23 and $1.98 for the quarter ended September 30, 2010 and 2009, respectively.
 
Direct Costs−General and Administrative
 
Nine months ended September 30, 2010 as compared to nine months ended September 30, 2009
 
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 nine months ended September 30, 2010, compared to the same period in 2009, by approximately $0.2 million principally due to reduced billings for professional services.
 
Three months ended September 30, 2010 as compared to three months ended September 30, 2009
 
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 September 30, 2010, compared to the same period in 2009, by approximately $45,000 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 September 30, 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, in the fourth quarter of 2009, of the SEC’s final rule regarding the modernization of oil and gas reporting, the Partnership changed to a valuation price determined by the 12-month average of the first-day-of-the-month price during each month of 2009.
 
 
- 17 -
 
PDC 2005-A LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
 
Nine months ended September 30, 2010 as compared to nine months ended September 30, 2009
 
The DD&A expense rate per Mcfe decreased to $3.41 for the 2010 nine month period, compared to $4.18 during the same period in 2009, as calculated by the respective methodologies described above.  The decrease in the per Mcfe rates for the 2010 period compared to the 2009 period is primarily the result of the changing production mix between the Partnership’s Wattenberg and Grand Valley Fields, which have significantly different DD&A rates. This was affected by field-level depletion rate changes due to 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.  The decreased DD&A expense rate, combined with the production declines noted in previous sections, resulted in a decreased DD&A expense of approximately $0.8 million for the 2010 nine month period compared to the same 2009 period.  During the 2009 nine month period, an out of period expense recorded in the first quarter of 2009 increased DD&A expense by approximately $106,000.
 
Three months ended September 30, 2010 as compared to three months ended September 30, 2009
 
The DD&A expense rate per Mcfe decreased to $3.18 for the 2010 third quarter, compared to $3.94 during the same quarter in 2009 as calculated by the respective methodologies described above.  The decrease in the per Mcfe rates for the 2010 third quarter compared to the 2009 third quarter is a result of the combined effects of the changing production mix between fields and changes in field-level depletion rates, noted above.  The lower DD&A expense rate, combined with the effect of the production declines noted in previous sections, resulted in the DD&A expense reduction of $0.3 million for the 2010 third quarter compared to the same 2009 quarter.
 
Capital Resources and Liquidity
 
The Partnership’s primary sources of cash for both the three and the nine months ended September 30, 2010 were from funds provided by operating activities which include 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 costs, 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 attempts to manage 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 September 30, 2010, the Partnership had natural gas and oil derivative positions in place covering 72% of the expected natural gas production and 71% of expected oil production for the remainder of 2010, at an average price of $4.34 per Mcf and $92.96 per Bbl, respectively.  The Partnership’s current derivative position average prices have declined from the significantly higher average commodity contract strike price levels in effect during the 2009 comparative period which were the result of contracts entered into during the high 2008 commodity price market; accordingly, the Partnership anticipates realized gains for the next 12 months to remain substantially below gains realized in 2009 and the first quarter of 2010.  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.
 
 
- 18 -
 
PDC 2005-A LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
 
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, if any.  Natural gas and oil production from the Partnership’s existing properties are generally expected to continue a gradual decline in the rate of production over the remaining lives of the wells.  Therefore, the Partnership anticipates a lower annual level of natural gas and oil production and, in the absence of significant price increases or successful refracturings, 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, and may substantially reduce or restrict the Partnership’s ability to participate in the Well Refracturing Plan activities which are more fully described in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Well Refracturing Plan.
 
Working Capital
 
Working capital at September 30, 2010 was unchanged at $1.0 million compared to the Partnership’s working capital at December 31, 2009.  Changes during the nine month comparison period in accounts receivable or payable balances that comprise working capital are as follows:
 
 
●
Cash and cash equivalents increased by $0.1 million as of September 30, 2010 compared to December 31, 2009.
 
●
Natural gas and oil receivables decreased by $0.2 million as of September 30, 2010 compared to December 31, 2009.
 
●
Realized derivative gains receivables decreased by $0.3 million as of September 30, 2010 compared to December 31, 2009.
 
●
Net short-term unrealized derivative gains receivable increased by approximately $0.4 million as of September 30, 2010 compared to December 31, 2009.
 
Working capital, primarily cash and cash equivalents, is expected to increase during early 2011 due to the Partnership’s withholding cash from the investors for the initial Wattenberg Field well refracturing activities.  Cash will begin to decrease as the funds are utilized in payment of the completed refracturing activities, currently planned to occur during mid-to-late 2011. Funding for the Well Refracturing Plan will be provided by the withholding of distributable cash flows from the Managing General Partner and Investor Partners on a pro-rata basis. Working capital is expected to similarly fluctuate by increasing during periods of Well Refracturing Plan funding and by decreasing during periods when payments are made for completed well refracturing.
 
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 $27,000 and $26,000 for the nine months ended September 30, 2010 and 2009, respectively.  The Partnership received an approximately $109,000 drilling advance refund from the Managing General Partner during the nine month period ended September 30, 2009.
   
 
- 19 -
 
PDC 2005-A LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
 
Cash Flows From Financing Activities
 
The Partnership initiated monthly cash distributions to investors in September 2005 and has distributed $43.0 million through September 30, 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.
 
Three months ended September 30,
     Managing General Partner Distributions      
Investor Partners
Distributions
      
Total Distributions
  
2010     $ 117,981     $ 471,924     $ 589,905  
                           
2009     $ 359,390     $ 1,437,561     $ 1,796,951  
 
Nine months ended September 30,
    
Managing General Partner Distributions
    
Investor Partners
Distributions
    
Total Distributions
  
                           
2010     $ 583,917     $ 2,335,668     $ 2,919,585  
                           
2009     $ 880,689     $ 3,522,764     $ 4,403,453  
 
The Partnership began funding for the Well Refracturing Plan during October 2010.  On a pro-rata basis based on percentage of ownership in the Partnership, the Partnership withheld $4,000 and $16,000 from the Managing General Partner and Investor Partners’ share, respectively, of distributable cash flows from the Partnership’s August 2010 natural gas and oil revenues distributed in October 2010.  The October 2010 and subsequent withholdings will provide the funding for planned Wattenberg Field well refracturing costs to be incurred during 2011, and thereafter.
 
Cash Flows From Operating Activities
 
Net cash provided by operating activities was $3.0 million for the nine months ended September 30, 2010, compared to approximately $4.2 million for the comparable period in 2009.  The approximately $1.2 million decrease in cash provided by operating activities was due primarily to the following:
 
 
●
An increase in natural gas and oil sales receipts of $0.6 million, or 23%, accompanied by decreases in natural gas and oil production costs of approximately $0.2 million or 14% and direct costs – general and administrative of $0.2 million, or 67%;
 
 
●
A decrease in commodity price risk management realized gains receipts of $1.5 million, or 61%;
 
 
●
A decrease in Due to Managing General Partner-other, net, receipts of approximately $0.7 million, excluding natural gas and oil sales received from third parties and realized derivative gains.
 
Commitments and Contingencies
 
See Note 6, Commitments and Contingencies, to the accompanying unaudited condensed financial statements, included in this report.
 
Recent Accounting Standards
 
See Note 2, Recent Accounting Standards to the accompanying unaudited condensed financial statements, included in this report.
 
 
- 20 -
 
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 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.
 
Off-Balance Sheet Arrangements
 
Currently, the Partnership does not have any off-balance sheet arrangements.
 
 
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
 
Not applicable.
 
 
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 September 30, 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 September 30, 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 September 30, 2010, that have materially affected or are reasonably likely to materially affect the Partnership’s internal control over financial reporting.
 
 
- 21 -
 
PDC 2005-A LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
 
 
 
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.
 
Not applicable.
 
 
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.
 
The following table presents information about the Managing General Partner’s limited partner unit repurchases during the three months ended September 30, 2010.
 
Period
  
Total Number of
Units Repurchased
    
Average Price Paid per
Unit
  
             
July 1—31, 2010
     1.25     $ 4,756  
August 1—31, 2010
     2.96       4,969  
September 1—30, 2010
     —       —  
Total third quarter Unit Repurchase Program repurchases
     4.21          
 
 
Not applicable.
 
 
 
Not applicable.
 
 
- 22 -
 
PDC 2005-A LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
 
Item 6.
 
(a)       Exhibit Index.
 
       
Incorporated by Reference
    
Exhibit Number
  
Exhibit Description
  
Form
  
SEC File Number
  
Exhibit
  
Filing Date
  
Filed Herewith
3.1
  
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
  
06/29/2005
    
                         
3.2
  
Certificate of limited partnership which reflects the organization of the Partnership under West Virginia law
  
10-K
  
000-51309
  
3.2
  
02/26/2009
    
                         
10.1
  
Drilling and operating agreement between the Partnership and Petroleum Development Corporation, as Managing General Partner.
  
10-K
  
000-51309
  
10.1
  
02/26/2009
    
                         
10.2
  
Form of assignment of leases to the Partnership
  
10-K
  
000-51309
  
10.2
  
02/26/2009
    
                         
10.4
  
Gas Purchase and Processing Agreement between Duke Energy Field Services, Inc.; United States Exploration, Inc.; and Petroleum Development Corporation, dated October 28, 1999 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)
  
10-12G/A Amend 3
  
000-53201
  
10.3
  
03/31/2009
    
                         
10.5
  
Gas Purchase and Processing Agreement between Natural Gas Associates, a Colorado partnership, and Aceite Energy Corporation, Walker Exploratory Program 1982- A Limited and Cattle Creek Company, dated October 14, 1983 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)
  
10-12G/A
Amend 3
  
000-53201
  
10.4
  
03/31/2009
    
       
 
                
10.6
  
Gas Purchase and Processing Agreement between Natural Gas Associates, a Colorado partnership, and SHF Partnership, a Colorado general partnership, Trailblazer Oil and Gas, Inc., Alfa Resources, Inc., Pulsar Oil and Gas, Inc., Overthrust Oil Royalty Corporation, Corvette Petroleum Ltd., Robert Lanari, an individual, and Toby A Martinez, an individual, dated September 21, 1983 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)
  
10-12G/A Amend 3
  
000-53201
  
10.5
  
03/31/2009
    
 
 
- 23 -
 
PDC 2005-A LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
 
       
Incorporated by Reference
    
Exhibit Number
  
Exhibit Description
  
Form
  
SEC File Number
  
Exhibit
  
Filing Date
  
Filed Herewith
10.7
  
Domestic Crude Oil Purchase Agreement with ConocoPhillips Company, dated January 1, 1993, as amended by agreements with Teppco Crude Oil, LLC dated August 2, 2007; September 24, 2007; October 17, 2007; January 7, 2008; January 15, 2008; and April 17, 2008 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)
  
10-12G/A
Amend 3
  
000-53201
  
10.6
  
03/31/2009
    
       
 
                
10.8
  
Gas Purchase Agreement between Williams Production RMT Company, Riley Natural Gas Company and Petroleum Development Corporation, dated as of June 1, 2006 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)
  
10-12G/A Amend 3
  
000-53201
  
10.7
  
03/31/2009
    
                         
10.9
  
Domestic Crude Oil Purchase Agreement between Suncor Energy Marketing Inc. and Petroleum Development Corporation, dated April 22, 2008
  
10-Q
  
000-51309
  
10.1
  
05/18/2009
    
                         
 
Certification by Chief Executive Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership, pursuant to Rule 13a- 14(a)/15d-14(c) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
                  
X
 
 
- 24 -
 
PDC 2005-A LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
 
        Incorporated by Reference    
Exhibit Number
  
Exhibit Description
  
Form
  
SEC File Number
  
Exhibit
  
Filing Date
  
Filed Herewith
 
Certification by Chief Financial Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership, pursuant to Rule 13a-14(a)/15d-14(c) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
                        X
                         
 
Certifications by Chief Executive Officer and Chief Financial Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership, pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002.
                  
X
 
 
- 25 -
 
PDC 2005-A LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
 
 
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 (dba PDC Energy)
 
  By /s/ Richard W. McCullough
 
  
 
Richard W. McCullough
Chairman and Chief Executive Officer
of Petroleum Development Corporation (dba PDC Energy)
  
     
 
November 5, 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
  
November 5, 2010
Richard W. McCullough
  
Petroleum Development Corporation (dba PDC Energy)
    
   
Managing General Partner of the Registrant
    
   
(Principal executive officer)
    
         
/s/ Gysle R. Shellum
  
Chief Financial Officer
  
November 5, 2010
Gysle R. Shellum
  
Petroleum Development Corporation (dba PDC Energy)
    
   
Managing General Partner of the Registrant
    
   
(Principal financial officer)
    
         
/s/ R. Scott Meyers
  
Chief Accounting Officer
  
November 5, 2010
R. Scott Meyers
  
Petroleum Development Corporation (dba PDC Energy)
    
   
Managing General Partner of the Registrant
    
   
(Principal accounting officer)
    
 
 
- 26 -

PDC 2005-A Limited Partnership Reports