PDC 2003-C LP - FORM 10-Q - May 10, 2011

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EX-31.2 - EXHIBIT 31.2 - PDC 2003-C LPex31_2.htm
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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 March 31, 2011
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   000-50617

PDC 2003-C Limited Partnership
(Exact name of registrant as specified in its charter)
 
West Virginia
  
55-0825962
(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 reports) and (2) has been subject to such filing requirements for the past 90 days.
Yes þ  No  ¨

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

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

Large accelerated filer     ¨
Accelerated filer     ¨
   
Non-accelerated filer     ¨
Smaller reporting company     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, 2011 the Partnership had 874.81 units of limited partnership interest and no units of additional general partnership interest outstanding.
 
 
 
 
 
PDC 2003-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

INDEX TO REPORT ON FORM 10-Q
 
     
Page
  
 
PART I – FINANCIAL INFORMATION
      
         
    1  
Item 1.
Financial Statements (unaudited)
      
    3  
    4  
    5  
    6  
  11  
  21  
  21  
         
 
PART II – OTHER INFORMATION
      
         
  23  
  23  
  23  
  23  
  23  
  23  
  24  
         
    25  
 
 
 
 

This periodic report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”) regarding PDC 2003-A Limited Partnership’s (“Partnership” or the “Registrant”) business, financial condition and results of operations.  Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, is the Managing General Partner of the Partnership.  All statements other than statements of historical facts included in and incorporated by reference into this report are “forward-looking statements” within the meaning of the safe harbor provisions of the United States Private Securities Litigation Reform Act of 1995.  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, natural gas liquid(s) or “NGL(s)”, and crude oil production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and the Managing General Partner’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 known and unknown risks and uncertainties incidental to the development, production and marketing of natural gas, NGLs and crude 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 and worldwide demand;
 
·
volatility of commodity prices for natural gas and crude oil;
 
·
changes in estimates of proved reserves;
 
·
inaccuracy of reserve estimates and expected production rates;
 
·
declines in the value of the Partnership’s natural gas and crude oil properties resulting in impairments;
 
·
the availability of Partnership future cash flows for investor distributions or funding of additional Codell formation development activities;
 
·
the timing and extent of the Partnership’s success in further developing and producing the Partnership’s reserves;
 
·
the Managing General Partner’s ability to acquire drilling rig services, supplies and services at reasonable prices;
 
·
risks incidental to the additional Codell formation development and operation of natural gas and crude oil wells;
 
·
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 U.S. as well as other oil producing countries throughout the world;
 
·
changes in environmental laws, the regulation and enforcement of those laws and the costs to comply with those laws;
 
·
the impact of environmental events, governmental responses to the events and the Managing General Partner's ability to insure adequately against such events;
 
·
competition in the oil and gas industry;
 
·
the success of the Managing General Partner in marketing the Partnership’s oil and gas;
 
·
the effect of natural gas and crude oil derivative activities;
 
·
the availability of funding for the consideration payable by PDC and its wholly-owned subsidiary to consummate the prospective mergers of the 2005 partnerships and the timing of consummating these mergers, if at all;
 
·
losses possible from pending or future litigation; and
 
·
the success of strategic plans, expectations and objectives for future operations of the Managing General Partner.
 
 
- 1 -
 
PDC 2003-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
 
Further, the Partnership urges the reader to carefully review and consider the cautionary statements and disclosures made in this report, the Partnership’s annual report on Form 10-K for the year ended December 31, 2010 filed with the Securities and Exchange Commission (“SEC”) on March 30, 2011 (“2010 Form 10-K”) and the Partnership’s other filings with the SEC for further information on risks and uncertainties that could affect the Partnership’s business, financial condition and results of operations, which are incorporated by this reference as though fully set forth herein.  Readers are cautioned 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.  All forward looking statements are qualified in their entirety by this cautionary statement.

 
- 2 -

PART I – FINANCIAL INFORMATION

Item 1.             Financial Statements (unaudited)
 
PDC 2003-C Limited Partnership
 
   
March 31,
2011
    
December 31,
 2010*
  
Assets
            
             
Current assets:
            
Cash and cash equivalents
   $ 7,786     $ 7,830  
Accounts receivable
     106,356       75,487  
Crude oil inventory
     28,276       42,653  
Due from Managing General Partner-derivatives
     195,539       186,366  
Total current assets
     337,957       312,336  
                 
                 
Natural gas and crude oil properties, successful efforts method, at cost
     11,405,438       11,396,692  
Less:  Accumulated depreciation, depletion and amortization
     (7,366,470 )     (7,219,042 )
Natural gas and crude oil properties, net
     4,038,968       4,177,650  
                 
Due from Managing General Partner-derivatives
     258,201       301,042  
Other assets
     51,443       47,974  
Total noncurrent assets
     4,348,612       4,526,666  
                 
Total Assets
   $ 4,686,569     $ 4,839,002  
                 
Liabilities and Partners' Equity
                
                 
Current liabilities:
                
Accounts payable and accrued expenses
   $ 9,994     $ 14,438  
Due to Managing General Partner-derivatives
     218,229       181,324  
Due to Managing General Partner-other, net
     290,792       294,182  
Total current liabilities
     519,015       489,944  
                 
Due to Managing General Partner-derivatives
     202,769       227,588  
Asset retirement obligations
     268,773       264,835  
Total liabilities
     990,557       982,367  
                 
Commitments and contingent liabilities
                
                 
Partners' equity:
                
Managing General Partner
     742,179       773,624  
Limited Partners -  874.81 units issued and outstanding
     2,953,833       3,083,011  
Total Partners' equity
     3,696,012       3,856,635  
                 
Total Liabilities and Partners' Equity
   $ 4,686,569     $ 4,839,002  
 
*Derived from audited 2010 balance sheet
 
See accompanying notes to unaudited condensed financial statements.

 
- 3 -
 
PDC 2003-C Limited Partnership
 
   
Three months ended March 31,
  
   
2011
    
2010
  
Revenues:
            
Natural gas, NGLs and crude oil sales
   $ 247,609     $ 267,571  
Commodity price risk management (loss) gain, net
     (40,517 )     238,761  
Total revenues
     207,092       506,332  
                 
Operating costs and expenses:
                
Natural gas, NGLs and crude oil production costs
     147,684       230,511  
Direct costs - general and administrative
     49,707       34,379  
Depreciation, depletion and amortization
     147,428       220,318  
Accretion of asset retirement obligations
     3,938       3,710  
Total operating costs and expenses
     348,757       488,918  
                 
(Loss) income from operations
     (141,665 )     17,414  
                 
Interest income
     1       39  
                 
Net (loss) income
   $ (141,664 )   $ 17,453  
                 
Net (loss) income allocated to partners
   $ (141,664 )   $ 17,453  
Less:  Managing General Partner interest in net (loss) income
     (28,333 )     3,491  
Net (loss) income allocated to Investor Partners
   $ (113,331 )   $ 13,962  
                 
Net (loss) income per Investor Partner unit
   $ (130 )   $ 16  
                 
Investor Partner units outstanding
     874.81       874.81  
 
See accompanying notes to unaudited condensed financial statements.

 
- 4 -
 
PDC 2003-C Limited Partnership
 
   
Three months ended March 31,
  
   
2011
    
2010
  
Cash flows from operating activities:
            
Net (loss) income
   $ (141,664 )   $ 17,453  
Adjustments to net (loss) income to reconcile to net cash provided by operating activities:
                
Depreciation, depletion and amortization
     147,428       220,318  
Accretion of asset retirement obligations
     3,938       3,710  
Unrealized loss (gain) on derivative transactions
     45,754       (132,381 )
Changes in operating assets and liabilities:
                
(Increase) decrease in accounts receivable
     (30,869 )     16,133  
Decrease in crude oil inventory
     14,377       2,299  
Increase in other assets
     (3,469 )     (2,869 )
Decrease in accounts payable and accrued expenses
     (4,444 )     (1,132 )
(Decrease) increase  in Due to Managing General Partner - other, net
     (3,390 )     849  
Net cash provided by operating activities
     27,661       124,380  
                 
Cash flows from investing activities:
                
Capital expenditures for natural gas and crude oil properties
     (8,746 )     (6,157 )
Net cash used in investing activities
     (8,746 )     (6,157 )
                 
Cash flows from financing activities:
                
Distributions to Partners
     (18,959 )     (118,184 )
Net cash used in financing activities
     (18,959 )     (118,184 )
                 
Net (decrease) increase in cash and cash equivalents
     (44 )     39  
Cash and cash equivalents, beginning of period
     7,830       105,479  
Cash and cash equivalents, end of period
   $ 7,786     $ 105,518  
 
See accompanying notes to unaudited condensed financial statements.
 
- 5 -
 
PDC 2003-C LIMITED PARTNERSHIP
March 31, 2011
(unaudited)

Note 1−General and Basis of Presentation

PDC 2003-C Limited Partnership (the “Partnership” or the “Registrant”) was organized as a limited partnership, in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of natural gas and crude oil properties.  Business operations of the Partnership commenced upon closing of an offering for the sale of Partnership units.  Upon funding, the Partnership entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner which authorizes Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, to conduct and manage the Partnership’s business.  In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), the Managing General Partner is authorized to manage all activities of the Partnership and initiates and completes substantially all Partnership transactions.

As of March 31, 2011, there were 741 Investor Partners.  PDC is the designated Managing General Partner of the Partnership and owns a 20% Managing General Partner ownership in the Partnership.  According to the terms of the Limited Partnership Agreement, revenues, costs and cash distributions of the Partnership are allocated 80% to the limited partners (“Investor Partners”), which are shared pro rata, based upon the number of units in the Partnership, and 20% to the Managing General Partner.  The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual Investor Partner.  Through March 31, 2011, the Managing General Partner has repurchased 35.3 units of Partnership interests from Investor Partners at an average price of $5,300 per unit.  As of March 31, 2011, the Managing General Partner owns 23.2% of the Partnership.

In March 2011, a condition of obligation arose subject to Section 4.02 Distributions, of the Partnership Agreement.  Pursuant to the Performance Standard Obligation provision, which expires in April 2014, the Partnership modified the distribution rate of cash distributions from that described in the previous paragraph, between the Managing General Partner and the Investor Partners.  During March 2011, distributions paid to the Managing General Partner were reduced and distributions to the Investor Partners were increased by $680 as a result of the Preferred Cash Distribution made under the terms in Section 4.02.  For more information concerning the Performance Standard Obligation, see Note 8, Partners’ Equity and Cash Distributions to the Partnership financial statements that accompany the 2010 Form 10-K.

The Partnership expects continuing operations of its natural gas and crude oil properties until such time the Partnership’s wells are depleted or become uneconomical to produce, at which time they may be sold or plugged, reclaimed and abandoned.  The Partnership’s maximum term of existence extends through December 31, 2050, 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 (“SEC”).  Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in the 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 2010 Form 10-K.  The Partnership’s accounting policies are described in the Notes to Financial Statements in the Partnership’s 2010 Form 10-K and updated, as necessary, in this Form 10-Q.  The results of operations for the three months ended March 31, 2011, 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.
 
 
- 6 -
 
PDC 2003-C LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 2011
(unaudited)
 
Note 2−Recent Accounting Standards

Recently Adopted 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.  These changes were effective for the Partnership’s financial statements issued for annual reporting periods, and for interim reporting periods within the year, beginning after December 15, 2010.  The adoption of this change did not have a material impact on the Partnership’s financial statements.

Note 3−Transactions with Managing General Partner and Affiliates

The Managing General Partner transacts business on behalf of the Partnership under the authority of the D&O Agreement.  Revenues and other cash inflows received on behalf of the Partnership are distributed to the Partners net of (after deducting) corresponding operating costs and other cash outflows incurred on behalf of the Partnership.  The fair value of the Partnership’s portion of unexpired derivative instruments is recorded on the condensed balance sheets 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 condensed 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,
2011
    
December 31,
2010
  
             
Natural gas, NGLs and crude oil sales revenues collected from the Partnership's third-party customers
   $ 71,633     $ 100,499  
Commodity price risk management, realized gain
     2,060       28,705  
Other (1)
     (364,485 )     (423,386 )
Total Due to Managing General Partner-other, net
   $ (290,792 )   $ (294,182 )

 
(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.
 
 
- 7 -
 
PDC 2003-C LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 2011
(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 months ended March 31, 2011 and 2010.  “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Natural gas, NGLs and crude oil production costs” line item on the condensed statements of operations.
 
   
Three months ended March 31,
  
   
2011
    
2010
  
             
 Well operations and maintenance
   $ 128,146     $ 208,091  
 Gathering, compression and processing fees
     7,160       7,008  
 Direct costs - general and administrative
     49,707       34,379  
 Cash distributions (1) (2)
     3,749       26,823  
 
 
(1)
Cash distributions include $637 and $3,187 during the three months ended March 31, 2011 and 2010, respectively, related to equity cash distributions on Investor Partner units repurchased by PDC.
 
(2)
Cash distributions to the Managing General Partner for the three months ended March 31, 2011, were reduced by $680 due to Preferred Cash Distributions made by the Managing General Partner to Investor Partners under the Performance Standard Obligation provision of the Agreement.  For more information concerning this obligation, see Note 1, General and Basis of Presentation.

Note 4−Fair Value of Financial Instruments

The following table presents, for each hierarchy level, the Partnership’s derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis as of March 31, 2011 and December 31, 2010.
 
   
March 31, 2011
    
December 31, 2010
  
   
Quoted Prices in
 Active Markets
 Level 1
    
Significant
 Unobservable Inputs
 Level 3
    
Total
    
Quoted Prices in
 Active Markets
 Level 1
    
Significant
 Unobservable Inputs
 Level 3
    
Total
  
                                     
Assets:
                                    
Commodity based derivatives
   $ 449,072     $ 4,668     $ 453,740     $ 470,319     $ 17,089     $ 487,408  
Total assets
     449,072       4,668       453,740       470,319       17,089       487,408  
                                                 
Liabilities:
                                                
Commodity based derivatives
     -       (83,136 )     (83,136 )     -       (67,297 )     (67,297 )
Basis protection derivative contracts
     -       (337,862 )     (337,862 )     -       (341,615 )     (341,615 )
Total liabilities
     -       (420,998 )     (420,998 )     -       (408,912 )     (408,912 )
                                                 
Net asset (liability)
   $ 449,072     $ (416,330 )   $ 32,742     $ 470,319     $ (391,823 )   $ 78,496  
 
- 8 -
 
PDC 2003-C LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 2011
(unaudited)
 
The following table presents a reconciliation of the Partnership’s Level 3 fair value measurements.
 
   
Three months ended
  
   
March 31, 2011
    
March 31, 2010
  
Fair value, net liability, beginning of year
   $ (391,823 )   $ (298,107 )
Changes in fair value included in statement of operations line item -Commodity price risk management, net
     (46,248 )     (35,496 )
Settlements
     21,741       (106,380 )
Fair value, net liability, end of period
   $ (416,330 )   $ (439,983 )
                 
Change in unrealized loss relating to assets (liabilities) still held as of March 31, 2011 and 2010, respectively,included in statement of operations line item:
                
Commodity price risk management, net
   $ (45,106 )   $ (43,643 )
 
See Note 5, Derivative Financial Instruments, for additional disclosure related to the Partnership’s derivative financial instruments.

Non-Derivative Financial 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, 2011, the Partnership had derivative instruments in place for a portion of its anticipated production through 2013 for a total of 239,759 MMbtu of natural gas and 2,315 Bbls of crude oil.

The following table presents the location and fair value amounts of the Partnership’s derivative instruments on the accompanying condensed balance sheets.  These derivative instruments were comprised of commodity collars, commodity fixed-price swaps and basis swaps.
 
         
Fair Value
  
Derivative instruments not designated as hedge  (1):
    
Balance Sheet 
Line Item
  
March 31,
 2011
    
December 31,
 2010
  
                   
Derivative Assets:
  
Current
              
   
Commodity contracts
Due from Managing General Partner-derivatives
   $ 195,539     $ 186,366  
                       
   
Non Current
                  
   
Commodity contracts
Due from Managing General Partner-derivatives
     258,201       301,042  
                       
                       
Total Derivative Assets
         $ 453,740     $ 487,408  
                       
Derivative Liabilities:
  
Current
                  
   
Commodity contracts
Due to Managing General Partner-derivatives
   $ 83,136     $ 67,297  
                       
   
Basis protection contracts
Due to Managing General Partner-derivatives
     135,093       114,027  
   
Non Current
                  
   
Basis protection contracts
Due to Managing General Partner-derivatives
     202,769       227,588  
                       
Total Derivative Liabilities
         $ 420,998     $ 408,912  
 
 
(1)
As of March 31, 2011 and December 31, 2010, none of the Partnership’s derivative instruments were designated as hedges.
 
 
- 9 -
 
PDC 2003-C LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 2011
(unaudited)

The following table presents the impact of the Partnership’s derivative instruments on the Partnership’s accompanying condensed statements of operations.
 
   
Three months ended March 31,
  
   
2011
    
2010
  
Statement of operations line item
  
Reclassification of Realized Loss (Gain) Included in Prior Periods Unrealized
    
Realized and Unrealized Gain (Loss) For the Current Period
    
Total
    
Reclassification of Realized Loss (Gain) Included in Prior Periods Unrealized
    
Realized and Unrealized Gain For the Current Period
    
Total
  
                                     
Commodity price risk management, net Realized gain
   $ 3,729     $ 1,508     $ 5,237     $ 98,234     $ 8,146     $ 106,380  
Unrealized (loss) gain
     (3,729 )     (42,025 )     (45,754 )     (98,234 )     230,615       132,381  
Total commodity price risk management (loss) gain, net
   $ -     $ (40,517 )   $ (40,517 )   $ -     $ 238,761     $ 238,761  
  
Derivative Counterparties. The Managing General Partner makes extensive use of over-the-counter derivative instruments that enable the Partnership to manage a portion of its exposure to price volatility from producing natural gas and crude oil.  These arrangements expose the Partnership to the 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 its derivative contracts.  To date, the Managing General Partner has had no counterparty default losses.  The Managing General Partner has evaluated the credit risk of the Partnership’s derivative assets from counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position.  Based on this evaluation, the Managing General Partner has determined that the impact of the nonperformance of the counterparties on the fair value of the Partnership’s derivative instruments was not significant.

Note 6−Commitments and Contingencies

Legal Proceedings

Neither the Partnership nor PDC, in its capacity as the Managing General Partner of the Partnership, are party to any pending legal proceeding that PDC believes would have a materially adverse effect on the Partnership’s business, financial condition, results of operations or liquidity.

Environmental

Due to the nature of the natural gas and crude oil industry, 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.  During the three months ended March 31, 2011, there was one environmental remediation project identified by the Managing General Partner, related to the Partnership in which $19,000 in costs were incurred.  As of March 31, 2011, the Partnership had no accrued environmental remediation liabilities.  As of December 31, 2010, the Partnership accrued for one of the Partnership’s well pads involving two wells in the amount of $6,000 which is included in line item captioned “Accounts payable and accrued expenses” on the condensed Balance Sheets.  The Managing General Partner is not aware of any environmental claims existing as of March 31, 2011, 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.
 
 
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PDC 2003-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)


Partnership Overview

PDC 2003-C Limited Partnership engages in the development, production and sale of natural gas, NGLs and crude oil.  The Partnership began natural gas and crude oil operations in November 2003 and operates 26 gross (23.1 net) productive wells located in the Rocky Mountain Region in the state of Colorado.  In addition, one (0.8 net) well in the Wattenberg Field is temporarily not in production at March 31, 2011 due to equipment problems.  The Managing General Partner markets the Partnership’s natural gas and crude oil production to commercial end users, interstate or intrastate pipelines, local utilities or oil companies, primarily under market sensitive contracts in which the price of natural gas, NGLs and crude oil sold varies as a result of market forces.  PDC does not charge an additional fee for the marketing of the natural gas, NGLs and crude 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.

Recent Developments

PDC Sponsored Drilling Program Acquisition Plan

PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue, beginning in the fall of 2010 and extending through the next three years, the acquisition of the limited partnership units (the “Acquisition Plan”) held by Investor Partners of the particular partnership other than those held by PDC or its affiliates (“non-affiliated investor partners”), in certain limited partnerships that PDC had previously sponsored, 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, 7.01 and/or 8.01 of PDC’s Forms 8-K dated March 4, 2010, June 9, 2010, July 15, 2010 and November 17, 2010.  However, such 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.  Each such merger will also be subject to, among other things, PDC having sufficient available capital, the economics of the merger and the approval by a majority of the limited partnership units held by the non-affiliated investor partners of each respective limited partnership.  Consummation of any proposed merger of a limited partnership under the Acquisition Plan will result in the termination of the existence of that partnership and the right of non-affiliated investor partners to receive a cash payment for their limited partnership units in that partnership.

In November 2010, PDC and a wholly-owned subsidiary of PDC entered into separate merger agreements with each of PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership, and the 2005 Rockies Region Private Limited Partnership (collectively, the “2005 Partnerships”).  PDC serves as the Managing General Partner of each of the 2005 Partnerships.  The special meetings whereby non-affiliated investor partners of the 2005 Partnerships will have an opportunity to vote and approve the respective merger agreements are currently scheduled for June 15, 2011.

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 with 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 PDC’s proposed repurchase offers to the 2005 Partnerships, or any potential proposed repurchase offer to any other of PDC’s various public limited partnerships, including this Partnership, should they occur.
 
 
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PDC 2003-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
 
Additional Codell Formation Development Plan

The Managing General Partner has prepared a plan for the Partnership’s Wattenberg Field wells which may provide for additional reserve development of natural gas, NGLs and crude oil production (the “Additional Codell Formation Development Plan”).  The Additional Codell Formation Development Plan consists of the Partnership’s refracturing of wells currently producing in the Codell formation and the recompletion of wells, currently producing in the deeper J-Sand formation, in the shallower Codell formation production zone.  Under the Additional Codell Formation Development Plan, the Partnership plans to initiate additional development activities during 2012.  Refracturing, or “refracing,” activities consist of a second hydraulic fracturing treatment in a current production zone, while recompletion activities consist of an initial hydraulic fracturing treatment in a new production zone, all within an existing well bore.

Additional Codell formation development of Wattenberg Field wells, which may provide for additional reserve development and production, generally occurs five to ten years after initial well drilling so that well resources are optimally utilized.  This additional Codell formation development would be expected to occur based on a favorable general economic environment and commodity price structure.  The Managing General Partner has the authority to determine whether to refracture or recomplete the individual wells and to determine the timing of any additional Codell formation development activity.  The timing of the refracturing or recompletion can be affected by the desire to optimize the economic return by additional development of the wells when commodity prices are at levels to obtain the highest rate of return to the Partnership.  On average, the production resulting from PDC's Codell refracturings or recompletions have been at modeled economics; however, all refracturings or recompletions have not been economically successful and similar future refracturing or recompletion activities may not be economically successful.  If the additional Codell formation development work is performed, PDC will charge the Partnership for the direct costs of refracturing or recompletion, and the Investor Partners and the Managing General Partner will each pay their proportionate share of costs based on the ownership sharing ratios of the Partnership from funds retained by the Managing General Partner from cash available for distributions. The Managing General Partner considers the cash available for distributions to be the Partnership’s net cash flows provided by operating activities less any net cash used in capital activities.

During the fourth quarter 2010, the Managing General Partner began a program for its affiliated partnerships to begin accumulating cash from cash flows from operating activities to pay for future refracturing and recompletion costs.  This program will materially reduce, up to 100%, cash available for distributions of the partnerships for a period of time not to exceed five years.  This Partnership has not begun to withhold funds for this additional Codell formation development as this Partnership has outstanding payables to the Managing General Partner.
 
 
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PDC 2003-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
 
 
Current estimated costs for these well refracturings or recompletions are between $175,000 and $240,000 per activity.  As of March 31, 2011, this Partnership had scheduled to complete 18 additional Codell formation development opportunities.  Total withholding for these activities from the Partnership’s cash available for distributions is estimated to be between $3.2 million and $4.3 million.  The Managing General Partner will continually evaluate the timing of commencing these additional Codell formation development activities based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the additional well development.  As of April 30, 2011, no funds have been withheld from the Partnership distributions for this recompletion and refracturing.
 
If any or all of the Partnership’s Wattenberg wells are not refractured or recompleted, the Partnership will experience a reduction in proved reserves currently assigned to these wells.  Both the number and timing of the additional Codell formation development activities will be based on the availability of cash withheld from Partnership distributions.  The Managing General Partner believes that, based on projected refracturing and recompletion costs and projected cash withholding, all scheduled Partnership additional Codell formation development activity will be completed within a five year period.  Any funds not used for refracturing, recompletion or other operational needs will be distributed to the Managing General Partner and Investor Partners based on their proportional ownership interest.
 
Implementation of the Additional Codell Formation Development Plan will reduce or eliminate Partnership distributions to the Managing General Partner and Investor Partners while the work is being conducted and paid for through the Partnership funds.  Depending upon the level of withholding and the results of operations, it is possible that the Managing General Partner and Investor Partners could have taxable income from the Partnership without any corresponding distributions in future years.  Non-affiliated Investor Partners are urged to consult a tax advisor to determine all of the relevant federal, state and local tax consequences of the Additional Codell Formation Development Plan.  The above discussion is not intended as a substitute for careful tax planning, and non-affiliated Investor Partners should depend upon the advice of their own tax advisors concerning the effects of the Additional Codell Formation Development Plan.

Partnership Operating Results Overview

Natural gas, NGLs and crude oil sales decreased 7% or $20,000 for the first three months of 2011 compared to the first three months of 2010, while sales volumes declined 9% period-to-period.  The average sales price per Mcfe, excluding the impact of realized derivative gains, was $7.35 for the current year period compared to $7.23 for the same period a year ago.  Realized derivative gains from natural gas and crude oil sales contributed an additional $0.16 per Mcfe or $5,000 to the first three months of 2011 total revenues compared to an additional $2.87 or $106,000 to the first three months of 2010.  Comparatively, the total realized price per Mcfe, consisting of the average sales price and realized derivative gains, decreased to $7.51 for the current year three months from $10.10 for the same prior year period.

Current period production and operating costs decreased by approximately $83,000, primarily due to first quarter 2010 charges for environmental remediation projects that did not re-occur in the first quarter of 2011.  Direct costs-general and administrative increased during the three months ended March 31, 2011, compared to the same period in 2010, by approximately $15,000 principally due to increased fees for professional services.
 
 
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PDC 2003-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

Results of Operations

Summary Operating Results

The following table presents selected information regarding the Partnership’s results of operations.
 
   
Three months ended March 31,
  
   
2011
    
2010
    
Change
  
Number of producing wells (end of period)
     26       25       1  
                         
Production(1)
                        
Natural gas (Mcf)
     19,826       21,678       -9 %
NGLs (Bbl)
     544       688       -21 %
Crude oil (Bbl)
     1,763       1,868       -6 %
Natural gas equivalents (Mcfe)(2)
     33,668       37,014       -9 %
Average Mcfe per day
     374       411       -9 %
                         
Natural Gas, NGLs and Crude Oil Sales
                        
Natural gas
   $ 65,789     $ 103,086       -36 %
NGLs
     27,374       28,929       -5 %
Crude oil
     154,446       135,556       14 %
Total natural gas, NGLs and crude oil sales
   $ 247,609     $ 267,571       -7 %
                         
Realized Gain (Loss) on Derivatives, net
                        
Natural gas
   $ 22,427     $ 85,157       -74 %
Crude oil
     (17,190 )     21,223       -181 %
Total realized gain on derivatives, net
   $ 5,237     $ 106,380       -95 %
                         
Average Selling Price (excluding realized gain (loss) on derivatives)
                       
Natural gas (per Mcf)
   $ 3.32     $ 4.76       -30 %
NGLs (per Bbl)
     50.32       42.05       20 %
Crude oil (per Bbl)
     87.60       72.57       21 %
Natural gas equivalents (per Mcfe)
     7.35       7.23       2 %
                         
Average Selling Price (including realized gain (loss) on derivatives)
                       
Natural gas (per Mcf)
   $ 4.45     $ 8.68       -49 %
NGLs (per Bbl)
     50.32       42.05       20 %
Crude oil (per Bbl)
     77.85       83.93       -7 %
Natural gas equivalents (per Mcfe)
     7.51       10.10       -26 %
                         
Average cost per Mcfe
                        
Natural gas, NGLs and crude oil production cost(3)
   $ 4.39     $ 6.23       -30 %
Depreciation, depletion and amortization
     4.38       5.95       -26 %
                         
Operating costs and expenses:
                        
Direct costs - general and administrative
   $ 49,707     $ 34,379       45 %
Depreciation, depletion and amortization
     147,428       220,318       -33 %
                         
Cash distributions
   $ 18,959     $ 118,184       -84 %
 
Amounts may not calculate due to rounding.
 
 
- 14 -
 
PDC 2003-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
______________
 
(1)
Production is net and determined by multiplying the gross production volume of properties in which the Partnership has an interest by the average percentage of the leasehold or other property interest the Partnership owns.
 
(2)
Six Mcf of natural gas equals one Bbl of crude oil or NGL.
 
(3)
Production costs represent natural gas, NGLs and crude 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

Natural Gas, NGLs and Crude Oil Sales

For the three months ended March 31, 2011 compared to the same period in 2010, natural gas, NGLs and crude oil sales decreased 9% on an energy equivalency-basis.
 
Three months ended March 31, 2011 as compared to three months ended March 31, 2010

The $20,000, or 7%, decrease in sales for the 2011 three month period as compared to the prior year period was primarily a reflection of a sales volume decrease of 9% offset slightly by an increased sales prices of 2%.  The average sales price per Mcfe, excluding the impact of realized derivative gains, was $7.35 for the current year three month period compared to $7.23 for the same period a year ago.

Natural gas and NGLs revenues decreased by 36% and 5%, respectively, and were partially offset by an increase in crude oil revenues of 14%. The Partnership’s natural gas revenue decrease resulted from decreased commodity prices per Mcf, of 30%, and decreased Partnership natural gas production volumes of 9%.  The decrease in NGLs revenue was due to a decrease of 21% in NGLs production volumes partially offset by increased commodity prices per Bbl, of 20%.  The crude oil revenue increase is due primarily to the rise in commodity prices per Bbl, of 21% partially offset by sales volume decreases of 6% during the current three month period.

Commodity Price Risk Management, Net

The Partnership uses various derivative instruments to manage fluctuations in natural gas and crude oil prices.  The Partnership has in place a variety of floors, collars, fixed-price swaps and basis swaps on a portion of the Partnership’s estimated natural gas and crude oil production.  Because the Partnership sells its natural gas and crude oil at similar prices to the indices 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.

Commodity price risk management, net, includes realized gains and losses and unrealized mark-to-market changes in the fair value of the derivative instruments related to the Partnership’s natural gas and crude oil production.  See Note 4, Fair Value of Financial Instruments and Note 5, Derivative Financial Instruments, to the Partnership’s unaudited condensed financial statements included in this report for additional details of the Partnership’s derivative financial instruments.
 
- 15 -
 
PDC 2003-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

 
The following table presents the realized and unrealized derivative gains and losses included in commodity price risk management (loss) gain, net.
 
   
Three months ended March 31,
  
Commodity price risk management, net
  
2011
    
2010
  
Realized gain (loss)
            
Natural gas
   $ 22,427     $ 85,157  
Crude oil
     (17,190 )     21,223  
Total realized gain, net
     5,237       106,380  
                 
Unrealized gain (loss)
                
Reclassification of realized gain included in prior periods unrealized
     (3,729 )     (98,234 )
Unrealized (loss) gain for the period
     (42,025 )     230,615  
Total unrealized (loss) gain, net
     (45,754 )     132,381  
Commodity price risk management (loss) gain, net
   $ (40,517 )   $ 238,761  
 
Three months ended March 31, 2011 as compared to three months ended March 31, 2010

Realized gains recognized in the three months ended March 31, 2011 are primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of the Partnership’s natural gas derivative positions.  Realized gains on natural gas settlements were $41,000 for the three months ended March 31, 2011.  These gains were offset in part by a $19,000 loss on the Partnership’s CIG basis protection swaps as the negative basis differential between NYMEX and Colorado Interstate Gas (“CIG”) was narrower than the strike price of the basis positions.  The Partnership also realized a $17,000 loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price.  Unrealized losses during the three months ended March 31, 2011 are primarily related to the shifts in the forward curves and their impact on the fair value of the Partnership’s open positions.  The significant shift upward in the crude oil curve resulted in an unrealized loss of $31,000 during the three months ended March 31, 2011.  Likewise, the shifts upward in the natural gas and basis curves resulted in a total unrealized loss of $11,000.

During the three months ended March 31, 2010, the Partnership recorded realized gains of $106,000 as a result of natural gas and crude oil spot prices being lower at settlement compared to the respective strike price.  During the three months ended March 31, 2010, the Partnership recorded unrealized gains of $231,000, of which $281,000 was related to the Partnership’s natural gas and crude oil positions, partially offset by unrealized losses on the Partnership’s CIG basis protection swaps of $50,000 as the forward basis differential between NYMEX and CIG had continued to narrow.
 
 
- 16 -
 
PDC 2003-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
 
 
The following table presents the Partnership’s derivative positions in effect as of March 31, 2011.
 
   
Collars
    
Fixed-Price Swaps
    
CIG Basis Protection Swaps
        
Commodity/
Index
  
Quantity
(Gas-
MMbtu (1))
    
Weighted Average
Contract Price
    
Quantity
(Gas-MMbtu (1)
Oil-Bbls)
    
Weighted Average Contract
Price
    
Quantity
(Gas-
MMbtu (1))
    
Weighted Average Contract
Price
    
Fair Value at March 31, 2011 (2)
  
 
Floors
    
Ceilings
  
                                                 
Natural Gas
                                                
NYMEX
                                                
04/01 - 06/30/2011
     -     $ -     $ -       23,875     $ 6.78       23,875     $ (1.88 )   $ 23,168  
07/01 - 09/30/2011
     -       -       -       23,639       6.73       23,639       (1.88 )     17,339  
10/01 - 12/31/2011
     -       -       -       23,103       6.78       23,103       (1.88 )     12,538  
01/01 - 03/31/2012
     1,305       6.00       8.27       21,100       6.98       22,406       (1.88 )     7,401  
04/01 - 12/31/2012
     2,720       6.00       8.27       62,643       6.98       65,361       (1.88 )     32,300  
2013
     -       -       -       81,374       7.12       81,374       (1.88 )     23,132  
Total Natural Gas
     4,025                       235,734               239,758               115,878  
                                                                 
Crude Oil
                                                                
NYMEX
                                                                
04/01 - 06/30/2011
     -       -       -       754       70.75       -       -       (26,708 )
07/01 - 09/30/2011
     -       -       -       773       70.75       -       -       (27,956 )
10/01 - 12/31/2011
     -       -       -       788       70.75       -       -       (28,472 )
Total Crude Oil
     -                       2,315               -               (83,136 )
                                                                 
Total Natural Gas and Crude Oil
                                                           $ 32,742  
 
 
(1)
A standard unit of measure for natural gas (one MMbtu equals one Mcf).
 
(2)
Approximately 1% 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 of Financial Instruments, to the accompanying unaudited condensed financial statements included in this report.

Natural Gas, NGLs and Crude Oil Production Costs

Generally, natural gas, NGLs and crude oil production costs vary with changes in total natural gas, NGLs and crude 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, NGLs and crude 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.

Three months ended March 31, 2011 as compared to three months ended March 31, 2010

Production and operating costs per Mcfe declined to $4.39 during the current period compared to $6.23 for the prior year period due to a decrease in environmental charges in 2011 compared to 2010.  Current period production and operating costs decreased by approximately $83,000, primarily due to first quarter 2010 charges for environmental remediation projects at four of the Partnership’s wells for approximately $120,000, which was not as significant in the first quarter of 2011.
 
 
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PDC 2003-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
 

Direct Costs−General and Administrative

Three months ended March 31, 2011 as compared to three months ended March 31, 2010

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 increased during the three months ended March 31, 2011, compared to the same period in 2010, by approximately $15,000 principally due to increased fees for the above referenced professional services.
 
Depreciation, Depletion and Amortization

Three months ended March 31, 2011 as compared to three months ended March 31, 2010

The DD&A expense rate per Mcfe decreased to $4.38 for the 2011 three month period, compared to $5.95 during the same period in 2010.  The decrease in the per Mcfe rates for the 2011 period compared to the 2010 period is partially due to the fourth quarter 2010 impairment of the Partnership’s Grand Valley Field.  Additionally the effect of the upward revision in the Partnership’s proved developed producing natural gas, NGLs and crude oil reserves particularly in the Wattenberg Field as of December 31, 2010, resulted in a decrease in the per Mcfe rates.  The production declines, noted in previous sections, contributed to the decreased DD&A expense of approximately $73,000 for the 2011 three month period compared to the same period in 2010.

Financial Condition, Liquidity and Capital Resources

The Partnership’s primary sources of cash for the three months ended March 31, 2011 were from funds provided by operating activities which include the sale of natural gas, NGLs and crude 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 provided monthly distributions to the Investor Partners and PDC, the Managing General Partner.  Any future withholdings would provide the funding for planned Wattenberg Field refracturing and recompletion costs to be incurred during 2012, and thereafter and are expected to decrease distributions from historical levels. 
 
Fluctuations in the Partnership’s operating cash flows 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 Managing General Partner 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, NGLs and crude oil sales and realized natural gas and crude oil derivative gains and losses.  However, the Partnership does not engage in speculative positions, nor does the Partnership hold derivative instruments 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, 2011, the Partnership had natural gas and crude oil derivative positions in place covering 100% of the expected natural gas production and 39% of expected crude oil production for the remainder of 2011, at an average price of $4.88 per Mcf and $70.75 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 2010 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.

The Partnership’s future operations are expected to be conducted with available funds and revenues generated from natural gas, NGLs and crude oil production activities and commodity gains.  Natural gas, NGLs and crude oil production from the Partnership’s existing properties are generally expected to continue a gradual decline in the rate of production over the remaining life of the wells.  Therefore, the Partnership anticipates a lower annual level of natural gas, NGLs and crude oil production and, in the absence of significant price increases or additional reserve development, 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 Managing General Partner and Investor Partners through the remainder of 2011 and beyond, and may substantially reduce or restrict the Partnership’s ability to participate in the additional Codell formation development activities which are more fully described in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments−Additional Codell Formation Development Plan.
 
 
- 18 -
 
PDC 2003-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

 
Working Capital

The Partnership had negative working capital of approximately $0.2 million at both March 31, 2011 and December 31, 2010.  The Partnership’s working capital deficit remained unchanged as net cash provided by operations was used to fund investing activities and for cash distributions to the Partners.  This deficit arose in the third and fourth quarters of 2010 due primarily to the increase to “Direct costs – general and administrative” resulting from the Partnership’s SEC compliance effort.  These costs were in excess of cash provided by operating activities during that period and were paid by the Managing General Partner and remain unpaid by the Partnership.

Working capital is expected to fluctuate by increasing during periods of Additional Codell Formation Development Plan funding and by decreasing during periods when payments are made for refracturing or recompletions.
 
Cash Flows

Cash Flows From Operating Activities

The Partnership’s cash flows provided by operating activities is primarily impacted by commodity prices, production volumes, realized gains and losses from its derivative positions, operating costs and general and administrative expenses.  See Results of Operations above for an additional discussion of the key drivers of cash flows provided by operating activities.

Natural gas, NGLs and crude oil prices exhibit a high degree of volatility.  These price variations have a material impact on the Partnership’s financial results.  Natural gas and NGLs prices vary by region and locality, depending upon the distance to markets, the availability of pipeline capacity and the supply and demand relationships in that region or locality.  This can be especially true in the Rocky Mountain Region.  The combination of increased drilling activity and the lack of local markets have resulted in 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 beyond the Partnership’s control.  Crude oil pricing is predominantly driven by the physical market, supply and demand, the financial markets and global unrest.

The price at which PDC markets the natural gas produced in the Rocky Mountain Region by the Partnership is based on a market basket of prices, which primarily includes natural gas sold at CIG prices with a portion sold at Mid-Continent, San Juan Basin, Southern California or other nearby region prices.  The CIG Index, and other indices for production delivered to other Rocky Mountain pipelines, have 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.  This negative differential has narrowed over the last few years and is lower than historical variances.  The negative differential of CIG relative to NYMEX averaged $0.28 and $0.16 for the three months ended March 31, 2011 and 2010, respectively.
 
 
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PDC 2003-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

Net cash provided by operating activities was approximately $28,000 for the three months ended March 31, 2011, compared to approximately $124,000 for the comparable period in 2010.  The approximately $96,000 decrease in cash provided by operating activities was due primarily to the following:

 
·
A decrease in natural gas, NGLs and crude oil sales receipts of $45,000, or 16%,

 
·
A decrease in commodity price risk management realized gains receipts of $90,000, or 74%, and

 
·
A decrease in production costs and direct costs – general and administrative payments of approximately $27,000.

Cash Flows From Investing Activities

The Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of natural gas, NGLs and crude oil or environmental protection.  These amounts totaled approximately $9,000 and $6,000 for the three months ended March 31, 2011 and 2010, respectively.

Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in May 2004 and has distributed $14.2 million through March 31, 2011.  The table below presents cash distributions to the Partnership’s investors.  Managing General Partner distributions include amounts distributed to PDC for its Managing General Partner’s 20% ownership share in the Partnership.  Investor Partner distributions include amounts distributed to Investor Partners for their 80% ownership share in the Partnership and include amounts distributed to PDC for limited partnership units repurchased.
 
 
Quarter
ended March 31,
  
Managing
General Partner
Distributions
    
Investor
Partners
Distributions
    
Total
Distributions
  
                   
2011
   $ 3,112     $ 15,847     $ 18,959  
                         
2010
   $ 23,636     $ 94,548     $ 118,184  
 
The decrease in total distributions for 2011 as compared to 2010 is primarily due to the significant decrease in cash flows from operating activities during 2011.

Beginning in March 2011, when the average Investor Partner’s annual rate of return fell below 12.8%, the Partnership modified the standard ownership-based pro-rata allocation of Partnership cash available for distribution, pursuant to the Performance Standard Obligation outlined in Section 4.02 of the Agreement.  Distributions paid to the Managing General Partner were reduced and distributions to the Investor Partners were increased, by $680 as a result of the Preferred Cash Distribution made under the terms of Section 4.02.  Because of the expected production declines related to the Partnership’s mature natural gas and oil operations, the Managing General Partner believes performance obligation allocation rate modifications are likely to continue until April 2014, when the provision expires under the terms of the Agreement.
 
Off-Balance Sheet Arrangements

As of March 31, 2011, the Partnership had no existing off-balance sheet arrangements, as defined under SEC rules, which have or are reasonably likely to have a material current or future effect on the Partnership’s financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
 
 
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PDC 2003-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

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.

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 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 2010 Form 10-K.


Not applicable.

Item 4.             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, 2011, PDC, as Managing General Partner on behalf of the Partnership, carried out an evaluation, under the supervision and with the participation of the Managing General Partner’s management, including 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 Exchange Act Rules 13a-15(e) and 15d-15(e).  This evaluation considered the various processes carried out under the direction of the Managing General Partner’s disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports that the Partnership files or submits under the Exchange Act is 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 disclosure.
 
 
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PDC 2003-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

 
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, 2011.

(b) Changes in Internal Control over Financial Reporting
 
During the three months ended March 31, 2011, 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 Exchange Act) that have materially affected or are reasonably likely to materially affect the Partnership’s internal control over financial reporting.
 
 
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PDC 2003-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

PART II – OTHER INFORMATION

Item 1.             Legal Proceedings

Neither the Partnership nor PDC, in its capacity as the Managing General Partner of the Partnership, are party to any pending legal proceeding that PDC believes would have a materially adverse effect on the Partnership’s business, financial condition, results of operations or liquidity.
 
Item 1A.          Risk Factors

Not applicable.


Unit Repurchase Program:  Beginning May 2007, the third anniversary of the date of the first Partnership cash distributions, Investor Partners of the Partnership may request 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 March 31, 2011.
 
Period
  
Total Number of
Units Repurchased
    
Average Price
Paid per
Unit
  
             
January 1−31, 2011
     3.25     $ 1,011  
February 1−28, 2011
     0.25       760  
March 1−31, 2011
     -       -  
     Total first quarter Unit Repurchase Program repurchases
     3.50          
 
Item 3.             Defaults Upon Senior Securities

Not applicable.

Item 4.             [Removed and Reserved]

Item 5.             Other Information

Not applicable.
 
 
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PDC 2003-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

Item 6.             Exhibits Index

The exhibits presented below are in addition to those presented in the Partnership’s Form 10-K.
   
Incorporated by Reference
  
Exhibit Number
  
Exhibit Description
  
   Form
  
SEC File
Number
  
Exhibit
  
Filing Date
   Filed Herewith  
 
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
  
 
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 the Sarbanes-Oxley Act of 2002.
 
                          
X
  
 
 
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PDC 2003-C 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 2003-C 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)

May 10, 2011

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 10, 2011
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
May 10, 2011
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
May 10, 2011
R. Scott Meyers
  
Petroleum Development Corporation (dba PDC Energy)
  
   
Managing General Partner of the Registrant
  
   
(Principal accounting officer)
  
 
 
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