PDC 2003-C LP - FORM 10-Q - August 12, 2011

Attached files

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EX-32.1 - CERTIFICATIONS BY CEO AND CFO PURSUANT TO SECTION 906 OF SARBANES-OXLEY ACT OF 2002 - PDC 2003-C LPa2003c-ex321_20110630.htm
EX-31.1 - CERTIFICATION BY CEO PURSUANT TO SECTION 302 OF SARBANES-OXLEY ACT OF 2002 - PDC 2003-C LPa2003c-ex311_20110630.htm
EXCEL - IDEA: XBRL DOCUMENT - PDC 2003-C LPFinancial_Report.xls
EX-31.2 - CERTIFICATION BY CFO PURSUANT TO SECTION 302 OF SARBANES-OXLEY ACT OF 2002 - PDC 2003-C LPa2003c-ex312_20110630.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-Q

S  QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934

For the quarterly period ended June 30, 2011
or

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

Commission File Number  000-50617

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 R 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 R 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 R
 

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

As of June 30, 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

PART I – FINANCIAL INFORMATION
 
 
Page
 
Item 1.
Financial Statements (unaudited)
 
 
 
 
 
Item 2.
Item 3.
Item 4.
 
 
 
PART II – OTHER INFORMATION
 
 
 
Item 1.
Item 1A.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
 
 
 
 


SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This periodic report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”) regarding PDC 2003-C 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. These statements include: estimated natural gas, natural gas liquid(s) or “NGL(s)”, and crude oil production and reserves; drilling plans; future cash flows and anticipated liquidity; anticipated capital expenditures; the adequacy of the Managing General Partner's casualty insurance coverage; the effectiveness of the Managing General Partner's derivative policies in achieving the Partnership's risk management objectives; and the Managing General Partner's strategies, plans and objectives.
The above statements 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, NGLs 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;
•
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;
•
the timing and receipt of necessary regulatory permits;
•
competition in the oil and gas industry;
•
the success of the Managing General Partner in marketing the Partnership's natural gas, NGLs and crude oil;
•
the effect of natural gas and crude oil derivative activities;
•
the cost of pending or future litigation;
•
the Managing General Partner's ability to retain or attract senior management and key technical employees; and
•
the success of strategic plans, expectations and objectives for future operations of the Managing General Partner.

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 United States 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.

-1-
PART I – FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)

PDC 2003-C Limited Partnership
Condensed Balance Sheets
(unaudited)

 
June 30, 2011
 
December 31, 2010*
Assets
 
 
 

 
 
 
 
Current assets:
 
 
 

Cash and cash equivalents
$
7,741

 
$
7,830

Accounts receivable
49,565

 
75,487

Crude oil inventory
39,178

 
42,653

Due from Managing General Partner-derivatives
202,072

 
186,366

Total current assets
298,556

 
312,336

 
 
 
 
Natural gas and crude oil properties, successful efforts method, at cost
11,418,273

 
11,396,692

Less: Accumulated depreciation, depletion and amortization
(7,491,415
)
 
(7,219,042
)
Natural gas and crude oil properties, net
3,926,858

 
4,177,650

 
 
 
 
Due from Managing General Partner-derivatives
242,429

 
301,042

Other assets
55,031

 
47,974

Total noncurrent assets
4,224,318

 
4,526,666

 
 
 
 
Total Assets
$
4,522,874

 
$
4,839,002

 
 
 
 
Liabilities and Partners' Equity
 
 
 
 
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
56,687

 
$
14,438

Due to Managing General Partner-derivatives
176,089

 
181,324

Due to Managing General Partner-other, net
189,239

 
294,182

Total current liabilities
422,015

 
489,944

 
 
 
 
Due to Managing General Partner-derivatives
174,296

 
227,588

Asset retirement obligations
272,769

 
264,835

Total liabilities
869,080

 
982,367

 
 
 
 
Commitments and contingent liabilities


 


 
 
 
 
Partners' equity:
 
 
 
   Managing General Partner
735,118

 
773,624

   Limited Partners - 874.81 units issued and outstanding
2,918,676

 
3,083,011

Total Partners' equity
3,653,794

 
3,856,635

 
 
 
 
Total Liabilities and Partners' Equity
$
4,522,874

 
$
4,839,002

    *Derived from audited 2010 balance sheet

See accompanying notes to unaudited condensed financial statements.

-2-
PDC 2003-C Limited Partnership
Condensed Statements of Operations
(unaudited)

 
Three months ended June 30,
 
Six months ended June 30,
 
2011
 
2010
 
2011
 
2010
Revenues:
 
 
 
 
 
 
 
Natural gas, NGLs and crude oil sales
$
199,771

 
$
266,017

 
$
447,380

 
$
533,588

Commodity price risk management gain, net
59,503

 
104,954

 
18,986

 
343,715

Total revenues
259,274

 
370,971

 
466,366

 
877,303

 
 
 
 
 
 
 
 
Operating costs and expenses:
 
 
 
 
 
 
 
Natural gas, NGLs and crude oil production costs
120,604

 
254,520

 
268,288

 
485,031

Direct costs - general and administrative
39,771

 
257,502

 
89,478

 
291,881

Depreciation, depletion and amortization
124,945

 
241,370

 
272,373

 
461,688

Accretion of asset retirement obligations
3,996

 
3,766

 
7,934

 
7,476

Total operating costs and expenses
289,316

 
757,158

 
638,073

 
1,246,076

 
 
 
 
 
 
 
 
Loss from operations
(30,042
)
 
(386,187
)
 
(171,707
)
 
(368,773
)
 
 
 
 
 
 
 
 
Interest income
1

 
39

 
2

 
78

 
 
 
 
 
 
 
 
Net loss
$
(30,041
)
 
$
(386,148
)
 
$
(171,705
)
 
$
(368,695
)
 
 
 
 
 
 
 
 
Net loss allocated to partners
$
(30,041
)
 
$
(386,148
)
 
$
(171,705
)
 
$
(368,695
)
Less: Managing General Partner interest in net loss
(6,008
)
 
(77,230
)
 
(34,341
)
 
(73,739
)
Net loss allocated to Investor Partners
$
(24,033
)
 
$
(308,918
)
 
$
(137,364
)
 
$
(294,956
)
 
 
 
 
 
 
 
 
Net loss per Investor Partner unit
$
(27
)
 
$
(353
)
 
$
(157
)
 
$
(337
)
 
 
 
 
 
 
 
 
Investor Partner units outstanding
874.81

 
874.81

 
874.81

 
874.81

















See accompanying notes to unaudited condensed financial statements.

-3-
PDC 2003-C Limited Partnership
Condensed Statements of Cash Flows
(unaudited)

 
Six months ended June 30,
 
2011
 
2010
Cash flows from operating activities:
 
 
 
Net loss
$
(171,705
)
 
$
(368,695
)
Adjustments to net loss to reconcile to net cash
   provided by operating activities:
 
 
 
Depreciation, depletion and amortization
272,373

 
461,688

Accretion of asset retirement obligations
7,934

 
7,476

Unrealized gain on derivative transactions
(15,620
)
 
(218,122
)
Changes in operating assets and liabilities:
 
 
 
Decrease in accounts receivable
25,922

 
9,311

Decrease (increase) in crude oil inventory
3,475

 
(1,242
)
Increase in other assets
(7,057
)
 
(6,187
)
Increase in accounts payable and accrued expenses
42,249

 
37,008

Increase (decrease) in Due to Managing General Partner - other, net
(104,943
)
 
244,188

Net cash provided by operating activities
52,628

 
165,425

 
 
 
 
Cash flows from investing activities:
 
 
 
Capital expenditures for natural gas and crude oil properties
(21,581
)
 
(26,489
)
Net cash used in investing activities
(21,581
)
 
(26,489
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Distributions to Partners
(31,136
)
 
(138,858
)
Net cash used in financing activities
(31,136
)
 
(138,858
)
 
 
 
 
Net increase (decrease) in cash and cash equivalents
(89
)
 
78

Cash and cash equivalents, beginning of period
7,830

 
105,479

Cash and cash equivalents, end of period
7,741

 
105,557















See accompanying notes to unaudited condensed financial statements.

-4-
PDC 2003-C LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 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 June 30, 2011, there were 742 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 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 June 30, 2011, the Managing General Partner has repurchased 35.3 units of Partnership interests from the Investor Partners at an average price of $5,300 per unit. As of June 30, 2011, the Managing General Partner owns 23.2% of the Partnership.

Beginning in March 2011, when the average Investor Partner's annual rate of return fell below 12.8%, a condition of obligation arose subject to Section 4.02 Distributions, of the 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 the six months ended June 30, 2011, distributions paid to the Managing General Partner were reduced and distributions to the Investor Partners were increased by $2,063 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 and six months ended June 30, 2011, and the cash flows for the same periods, are not necessarily indicative of the results to be expected for the full year or any other future period.

Certain reclassifications have been made to correct the prior period disclosures to conform to the current year presentation, specifically related to the fair value level classification of certain derivative instruments. The reclassification had no impact on the Partnership's previously reported financial position, cash flows, net income or partners' equity. See Note 4, Fair Value Measurements and Disclosures, for additional information regarding the fair value classification of the Partnership's natural gas and crude oil derivative instruments.


-5-
PDC 2003-C LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2011
(unaudited)

On June 20, 2011, the Partnership, PDC and its wholly-owned subsidiary, DP 2004 Merger Sub, LLC (“DP Merger Sub”), a Delaware limited liability company, entered into an agreement and plan of merger (the “Merger Agreement”), in which PDC seeks to acquire the Partnership, subject to the vote and approval of a majority of the limited partnership units held, by Investor Partners of the Partnership, other than PDC and its affiliates (“non-affiliated investor partners”). Pending the outcome of the proposed Merger Agreement, the Managing General Partner suspended, as of April 7, 2011, the opportunity for an individual non-affiliated investor partner to request that PDC repurchase their respective limited partnership units. For more information on the proposed Merger Agreement, see Note 3, Transactions with Managing General Partner and Affiliates−Proposed Merger with PDC and DP 2004 Merger Sub, LLC, which follows.


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 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.

Recently Issued Accounting Standards

Fair Value Measurement

On May 12, 2011, the FASB issued changes related to fair value measurement. The changes represent the converged guidance of the FASB and the International Accounting Standards Board ("IASB") (collectively the "Boards") on fair value measurement. Many of the changes eliminate unnecessary wording differences between International Financial Reporting Standards ("IFRS") and U.S. GAAP. The changes expand existing disclosure requirements for fair value measurements categorized in Level 3 by requiring (1) a quantitative disclosure of the unobservable inputs and assumptions used in the measurement, (2) a description of the valuation processes in place and (3) a narrative description of the sensitivity of the fair value to changes in unobservable inputs and the interrelationships between those inputs. In addition, the changes also require the categorization by level in the fair value hierarchy of items that are not measured at fair value in the statement of financial position whose fair value must be disclosed. These changes are to be applied prospectively and are effective for public entities during interim and annual periods beginning after December 15, 2011. Early application is not permitted. With the exception of the disclosure requirements, the adoption of these changes is not expected to have a significant 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.

-6-
PDC 2003-C LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2011
(unaudited)

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.
    
 
June 30, 2011
 
December 31, 2010
Natural gas, NGLs and crude oil sales revenues
collected from the Partnership's third-party customers
$
62,573

 
$
100,499

Commodity price risk management, realized gain
617

 
28,705

Other (1)
(252,429
)
 
(423,386
)
Total Due to Managing General Partner-other, net
$
(189,239
)
 
$
(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.
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 six months ended June 30, 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 June 30,
 
Six months ended June 30,
 
2011
 
2010
 
2011
 
2010
 Well operations and maintenance
$
104,993

 
$
234,500

 
$
233,139

 
$
442,591

 Gathering, compression and processing fees
5,737

 
6,364

 
12,897

 
13,372

 Direct costs - general and administrative
39,771

 
257,502

 
89,478

 
291,881

 Cash distributions (1) (2)
1,501

 
4,693

 
5,250

 
31,516


(1)
Cash distributions include $448 and $1,085 during the three and six months ended June 30, 2011, respectively, and $558 and $3,745 during the three and six months ended June 30, 2010, respectively, related to equity cash distributions on Investor Partner units repurchased by PDC.
(2)
Cash distributions to the Managing General Partner were reduced by $1,383 and $2,063 during the three and six months ended June 30, 2011, respectively, due to Preferred Cash Distributions made by the Managing General Partner to Investor Partners under the Performance Standard Obligation provision of the Agreement. There was no reduction in either period in 2010. For more information concerning this obligation, see Note 1, General and Basis of Presentation.
Proposed Merger with PDC and DP 2004 Merger Sub, LLC

On June 20, 2011, the Partnership, PDC and DP Merger Sub entered into the Merger Agreement, in which PDC seeks to acquire the Partnership, subject to the vote and approval of a majority of the limited partnership units held by non-affiliated investor partners. Pursuant to the Merger Agreement, if the merger is approved by the holders of a majority of the limited partnership units held by the non-affiliated investor partners of the Partnership, as well as, the satisfaction of other customary closing conditions, then the Partnership will merge with and into DP Merger Sub, the separate existence of the Partnership will terminate and the non-affiliated investor partners will have the right to receive cash payments in the aggregate amount of $4,703,775 or $5,603 per limited partnership unit, subject to any adjustments made to the merger consideration for certain increases in commodity prices between the date of signing the merger agreement and the filing of the definitive proxy statement, plus the sum of the amounts withheld, if any, from per unit cash distributions by the Partnership from October 1, 2010 through August 31, 2011 for the Partnership's Additional Codell Formation Development Plan, less the sum of the per unit cash distributions made after August 31, 2011 and before the transaction closes. DP Merger Sub shall be the surviving entity of the merger and shall be wholly-owned by PDC, and the limited partners will have no continuing interest in the Partnership, since the Partnership will cease as a separate business entity. The merger will become effective following the filing of a certificate of merger with the Secretaries of State of West Virginia and Delaware as soon as practicable after the last condition precedent to the merger has been satisfied, or waived. Following consummation of the merger, the non-affiliated investor partners will no longer participate in the Partnership's future earnings or

-7-
PDC 2003-C LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2011
(unaudited)

any further economic benefit.
The Merger Agreement has been approved by PDC's Board of Directors (the “Board”); PDC, as sole member of the DP Merger Sub; and by the Special Committee formed by the Board, comprised of four directors of PDC who are not officers or employees of the Partnership or PDC and have no economic interest in the Partnership, to represent the interests of the non-affiliated investor partners holding limited partnership units.
The Merger Agreement among the Partnership, PDC and its subsidiary DP Merger Sub, may be terminated, and the merger abandoned:
•
should all parties agree by mutual consent to terminate the Merger Agreement;

•
by any party thereto, should the proposed merger not occur by December 15, 2011;

•
by any party thereto, should consummation of the merger become illegal or be otherwise prohibited by law or regulation;

•
by any party thereto, should any suit or action be pending against parties to the Merger Agreement challenging the legality or any aspect of the merger transaction;

•
by the Special Committee, on behalf of the Partnership and prior to approval by non-affiliated investor partners, should the Special Committee believe it has received a superior offer that is more favorable to the non-affiliated investor partners; or

•
by PDC or the Partnership, should either PDC or the Partnership fail to perform its obligations under the Merger Agreement and such failure has a non-curable material adverse effect on PDC or the Partnership, respectively, or materially and adversely affects the transactions contemplated by the Merger Agreement.

On June 23, 2011, the Partnership filed a preliminary proxy statement on Schedule 14A relating to the merger with the SEC. Although there is no assurance of the likelihood or timing of the merger transaction, upon clearance by the SEC, a definitive proxy statement will be mailed to the Partnership’s limited partners. Closing of the merger is conditioned on approval by a majority vote of non-affiliated investor partners on both proposals to (1) amend the limited partnership agreement to expressly provide non-affiliated investor partners the right to approve merger transactions and (2) approve the Merger Agreement, as described above. If approved by a majority vote of non-affiliated investor partners and after the filing of a certificate of merger with the Secretaries of State of West Virginia and Delaware, no additional filing or registration with, notification to, or authorization, consent or approval of, any governmental entity will be required in connection with the execution and delivery of the Merger Agreement by the Partnership, PDC or DP Merger Sub or the consummation by the Partnership, PDC or DP Merger Sub of the transactions contemplated thereby. Following consummation of the merger, the non-affiliated investor partners will no longer participate in the Partnership’s future earnings or any further economic benefit.
Regardless of whether the merger is consummated, all costs and expenses incurred by PDC, the Partnership and DP Merger Sub in connection with the Merger Agreement shall be paid by PDC.

-8-
PDC 2003-C LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2011
(unaudited)


Note 4−Fair Value Measurements and Disclosures

Derivative Financial Instruments

Determination of fair value. Fair value accounting standards have established a fair value hierarchy that prioritizes the inputs used in applying a valuation methodology. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:

Level 1 - Quoted prices (unadjusted) in active markets for identical assets or liabilities.

Level 2 - Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability and (iv) inputs that are derived from observable market data by correlation or other means.

Level 3 - Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.

Derivative Financial Instruments. The Partnership measures the fair value of its derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of the Managing General Partner's credit standing on the fair value of derivative liabilities and the effect of the Managing General Partner's counterparties' credit standings on the fair value of derivative assets, both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. The counterparties to the Partnership's derivative instruments are primarily financial institutions. The Managing General Partner validates the fair value measurement through (1) the review of counterparty statements and other supporting documentation, (2) the determination that the source of the inputs are valid, (3) the 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. While the Managing General Partner uses common industry practices to develop its valuation techniques, changes in the pricing methodologies or the underlying assumptions could result in significantly different fair values. While the Managing General Partner believes its valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.




-9-
PDC 2003-C LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2011
(unaudited)

The following table presents, for each hierarchy level, the Partnership's derivative assets and liabilities, both current and non-current portions, measured at fair value on a recurring basis.
 
June 30, 2011
 
December 31, 2010 (a)
 
 Level 2 (b)
 
 Level 3 (c)
 
 Total
 
 Level 2 (b)
 
 Level 3 (c)
 
 Total
 
 
 
 
 
 
 
 
 
 
 
 
 Assets:
 
 
 
 
 
 
 
 
 
 
 
 Commodity based derivatives
$
439,304

 
$
5,197

 
$
444,501

 
$
470,319

 
$
17,089

 
$
487,408

 Total assets
439,304

 
5,197

 
444,501

 
470,319

 
17,089

 
487,408

 
 
 
 
 
 
 
 
 
 
 
 
 Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 Commodity based derivatives
(39,340
)
 
—

 
(39,340
)
 
(67,297
)
 
—

 
(67,297
)
 Basis protection derivative contracts
(311,045
)
 
—

 
(311,045
)
 
(341,615
)
 
—

 
(341,615
)
 Total liabilities
(350,385
)
 
—

 
(350,385
)
 
(408,912
)
 
—

 
(408,912
)
 Net asset
$
88,919

 
$
5,197

 
$
94,116

 
$
61,407

 
$
17,089

 
$
78,496


(a) The Partnership reclassified its NYMEX-based natural gas fixed-price swaps from Level 1 to Level 2 (decreasing the previously reported net asset in Level 1 by approximately $470,000) and CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 (decreasing the previously reported net liability in Level 3 by approximately $409,000). The amounts presented reflect these reclassifications and conform to current period presentation.
(b) Includes the Partnership's fixed-price swaps and basis swaps.
(c) Includes the Partnership's natural gas collars.


The following table presents a reconciliation of the Partnership's Level 3 fair value measurements.
    
 
Six months ended
 
June 30, 2011
 
June 30, 2010 (1)
 Fair value, net asset, beginning of period
$
17,089

 
$
38,562

 Changes in fair value included in statement of operations line item:
 
 
 
 Commodity price risk management, net
(26,479
)
 
(60,283
)
 Settlements
14,587

 
38,983

 Fair value, net asset, end of period
$
5,197

 
$
17,262

 
 
 
 
Change in unrealized gain (loss) relating to assets (liabilities) still held as of
 

 
 
June 30, 2011 and 2010, respectively, included in statement of operations line item:
 
 
 
 Commodity price risk management, net
$
527

 
$
13,859


(1) The Partnership reclassified its CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 (decreasing the previously reported net liability at the beginning of the period by approximately $337,000). The amounts presented reflect these reclassifications and conform to current period presentation.


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.

-10-
PDC 2003-C LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2011
(unaudited)

Note 5−Derivative Financial Instruments
As of June 30, 2011, the Partnership had derivative instruments in place for a portion of its anticipated production through 2013 for a total of 215,883 MMbtu of natural gas and 1,561 Bbl 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
 
 
 
 
 
June 30,
 
December 31,
Derivative instruments not designated as hedge(1):
 
Balance Sheet Line Item
 
2011
 
2010
Derivative Assets:
Current
 
 
 
 
 
 
 
Commodity contracts
 
Due from Managing General Partner-derivatives
 
$
202,072

 
$
186,366

 
Non Current
 
 
 
 
 
 
 
Commodity contracts
 
Due from Managing General Partner-derivatives
 
242,429

 
301,042

Total Derivative Assets
 
 
 
 
$
444,501

 
$
487,408

 
 
 
 
 
 
 
 
Derivative Liabilities:
Current
 
 
 
 

 
 

 
Commodity contracts
 
Due to Managing General Partner-derivatives
 
$
39,340

 
$
67,297

 
Basis protection contracts
 
Due to Managing General Partner-derivatives
 
136,749

 
114,027

 
Non Current
 
 
 
 
 
 
 
Basis protection contracts
 
Due to Managing General Partner-derivatives
 
174,296

 
227,588

Total Derivative Liabilities
 
 
 
$
350,385

 
$
408,912


(1)As of June 30, 2011 and December 31, 2010, none of the Partnership's derivative instruments were designated as hedges.


-11-
PDC 2003-C LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2011
(unaudited)

The following tables presents the impact of the Partnership's derivative instruments on the Partnership's accompanying condensed statements of operations.
 
 
 Three months ended June 30,
 
 
2011
 
2010
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 For the Current Period
 
Total
Commodity price risk management gain, net
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains (losses)
 
$
(3,539
)
 
$
1,668

 
$
(1,871
)
 
$
11,409

 
$
7,804

 
$
19,213

Unrealized gains (losses)
 
3,539

 
57,835

 
61,374

 
(11,409
)
 
97,150

 
85,741

Total commodity price risk management gain, net
$
—

 
$
59,503

 
$
59,503

 
$
—

 
$
104,954

 
$
104,954

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Six months ended June 30,
 
 
2011
 
2010
Statement of operations line item:
 
Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized
 
Realized and Unrealized Gains (Losses) For the Current Period
 
Total
 
Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized
 
Realized and Unrealized Gains For the Current Period
 
Total
Commodity price risk management gain, net
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains (losses)
 
$
9,994

 
$
(6,628
)
 
$
3,366

 
$
77,775

 
$
47,818

 
$
125,593

Unrealized gains (losses)
 
(9,994
)
 
25,614

 
15,620

 
(77,775
)
 
295,897

 
218,122

Total commodity price risk management gain, net
$
—

 
$
18,986

 
$
18,986

 
$
—

 
$
343,715

 
$
343,715


Concentration of Credit Risk. 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.


-12-
PDC 2003-C LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2011
(unaudited)

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 in place 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 six months ended June 30, 2011, two new environmental remediation projects were identified by the Managing General Partner for the Partnership in which approximately $70,000 of expense was recognized in the line item captioned "Natural gas, NGLs and crude oil production costs" in the condensed Statements of Operations. As of June 30, 2011 the Partnership had accrued environmental liabilities involving one well in the amount of approximately $50,000, which is included in the line item captioned "Accounts payable and accrued expenses" on the condensed Balance Sheets. At December 31, 2010, the Partnership has accrued environmental remediation liabilities involving two Partnership wells in the amount of approximately $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 currently aware of any environmental claims existing as of June 30, 2011, which have not been provided for or would otherwise have a material impact on the Partnership's condensed 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.



-13-
PDC 2003-C Limited Partnership
(A West Virginia Limited Partnership)



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

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 June 30, 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
In June 2011, PDC acquired three affiliated partnerships: PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership and Rockies Region Private Limited Partnership. PDC purchased these partnerships for the aggregate amount of $43.0 million.

On June 20, 2011, PDC and DP 2004 Merger Sub, LLC, a wholly-owned subsidiary of PDC (“DP Merger Sub”), entered into separate merger agreements with this Partnership, PDC 2003-A Limited Partnership, PDC 2003-B Limited Partnership, PDC 2003-D Limited Partnership and PDC 2002-D Limited Partnership (collectively, the "2003 and 2002-D Partnerships"). PDC serves as the Managing General Partner of each of the 2003 and 2002-D Partnerships.

Pursuant to the Merger Agreement, if the merger is approved by the holders of a majority of the limited partnership units held by the non-affiliated investor partners of the Partnership, as well as, the satisfaction of other customary closing conditions, then the Partnership will merge with and into DP Merger Sub, the separate existence of the Partnership will terminate and the non-affiliated investor partners will have the right to receive cash payments in the aggregate amount of $4,703,775 or $5,603 per limited partnership unit, subject to any adjustments made to the merger consideration for certain increases in commodity prices between the date of signing the merger agreement and the filing of the definitive proxy statement, plus the sum of the amounts withheld, if any, from per unit cash distributions by the Partnership from October 1, 2010 through August 31, 2011 for the Partnership's Additional Codell Formation Development Plan, less the sum of the per unit cash distributions made after August 31, 2011 and before the transaction closes. DP Merger Sub shall be the surviving entity of the merger and shall be wholly-owned by PDC, and the limited partners will have no continuing interest in the Partnership, since the Partnership will cease as a separate business entity. The merger will become effective following the filing of a certificate of merger with the Secretaries of State of West Virginia and Delaware as soon as practicable after the last condition precedent to the merger has been satisfied, or waived. Following consummation of the merger, the non-affiliated investor partners will no longer participate in the Partnership's future earnings or any further economic benefit.
The Merger Agreement has been approved by PDC's Board of Directors (the “Board”); PDC, as sole member of the DP Merger Sub; and by the Special Committee formed by the Board, comprised of four directors of PDC who are not officers or employees of the Partnership or PDC and have no economic interest in the Partnership, to represent the interests of the non-affiliated investor partners holding limited partnership units.

-14-
PDC 2003-C Limited Partnership
(A West Virginia Limited Partnership)


The Merger Agreement among the Partnership, PDC and its subsidiary DP Merger Sub, may be terminated, and the merger abandoned:
•
should all parties agree by mutual consent to terminate the Merger Agreement;

•
by any party thereto, should the proposed merger not occur by December 15, 2011;

•
by any party thereto, should consummation of the merger become illegal or be otherwise prohibited by law or regulation;

•
by any party thereto, should any suit or action be pending against parties to the Merger Agreement challenging the legality or any aspect of the merger transaction;

•
by the Special Committee, on behalf of the Partnership and prior to approval by non-affiliated investor partners, should the Special Committee believe it has received a superior offer that is more favorable to the non-affiliated investor partners; or

•
by PDC or the Partnership, should either PDC or the Partnership fail to perform its obligations under the Merger Agreement and such failure has a non-curable material adverse effect on PDC or the Partnership, respectively, or materially and adversely affects the transactions contemplated by the Merger Agreement.

On June 23, 2011, the Partnership filed a preliminary proxy statement on Schedule 14A relating to the merger with the SEC. Although there is no assurance of the likelihood or timing of the merger transaction, upon clearance by the SEC, a definitive proxy statement will be mailed to the Partnership’s limited partners. Closing of the merger is conditioned on approval by a majority vote of non-affiliated investor partners on both proposals to (1) amend the limited partnership agreement to expressly provide non-affiliated investor partners the right to approve merger transactions and (2) approve the Merger Agreement, as described above. If approved by a majority vote of non-affiliated investor partners and after the filing of a certificate of merger with the Secretaries of State of West Virginia and Delaware, no additional filing or registration with, notification to, or authorization, consent or approval of, any governmental entity will be required in connection with the execution and delivery of the Merger Agreement by the Partnership, PDC or DP Merger Sub or the consummation by the Partnership, PDC or DP Merger Sub of the transactions contemplated thereby. Following consummation of the merger, the non-affiliated investor partners will no longer participate in the Partnership’s future earnings or any further economic benefit. 
Regardless of whether the merger is consummated, all costs and expenses incurred by PDC, the Partnership and DP Merger Sub in connection with the Merger Agreement shall be paid by PDC.
If the merger is not completed, the Partnership will continue the existing business plan to optimally develop and cost-effectively operate the Partnership's natural gas and oil reserves.  This plan encompasses the implementation of the Additional Codell Formation Development Plan, more fully outlined below. The information presented in this Report on Form 10-Q for the six months ended June 30, 2011 and the year ended December 31, 2010 does not give effect to the proposed Merger Agreement.

-15-
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 additional Codell formation development 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.

Current estimated costs for these well refracturings or recompletions are between $175,000 and $240,000 per activity. As of June 30, 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 July 31, 2011, no funds have been withheld from the Partnership distributions for this refracturing or recompletion.

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's 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.
 


-16-
PDC 2003-C Limited Partnership
(A West Virginia Limited Partnership)




Partnership Operating Results Overview

Natural gas, NGLs and crude oil sales decreased 16% or approximately $86,000 for the first six months of 2011 compared to the first six months of 2010, while sales volumes declined 18% period-to-period. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $7.12 for the current year period compared to $6.96 for the same period a year ago. Realized derivative gains from natural gas and crude oil sales contributed an additional $0.05 per Mcfe or approximately $3,000 to the first six months of 2011 total revenues compared to an additional $1.63 or approximately $126,000 to the first six months of 2010. Comparatively, the total realized price per Mcfe, consisting of the average sales price and realized derivative gains, decreased to $7.17 for the current year six months from $8.59 for the same prior year period.

Natural gas, NGLs and crude oil production costs decreased by approximately $217,000 during the six months ended June 30, 2011 compared to the same period in the prior year due to the effect of decreased environmental remediation and workover expenses. Direct costs − general and administrative decreased by approximately $202,000 during the 2011 six month period due to decreased fees for professional services.

-17-
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 June 30,
 
Six months ended June 30,
 
2011
 
2010
 
 Change
 
2011
 
2010
 
Change
Number of producing wells (end of period)
26

 
26

 
—

 
26

 
26

 
—

 
 
 
 
 
 
 
 
 
 
 
 
Production(1)
 
 
 
 
 
 
 

 
 
 
 

Natural gas (Mcf)
18,988

 
21,240

 
(11
)%
 
38,814

 
42,918

 
(10
)%
NGLs (Bbl)
574

 
675

 
(15
)%
 
1,118

 
1,363

 
(18
)%
Crude oil (Bbl)
1,123

 
2,401

 
(53
)%
 
2,886

 
4,269

 
(32
)%
Natural gas equivalents (Mcfe)(2)
29,170

 
39,696

 
(27
)%
 
62,838

 
76,710

 
(18
)%
Average Mcfe per day
321

 
436

 
(27
)%
 
347

 
424

 
(18
)%
 
 
 
 
 
 
 
 
 
 
 
 
Natural Gas, NGLs and Crude Oil Sales
 
 
 
 
 
 
 

 
 

 
 

Natural gas
$
64,500

 
$
69,348

 
(7
)%
 
$
130,289

 
$
172,434

 
(24
)%
NGLs
27,229

 
25,783

 
6
 %
 
54,603

 
54,712

 
*

Crude oil
108,042

 
170,886

 
(37
)%
 
262,488

 
306,442

 
(14
)%
Total natural gas, NGLs and crude oil sales
$
199,771

 
$
266,017

 
(25
)%
 
$
447,380

 
$
533,588

 
(16
)%
 
 
 
 
 
 
 
 
 
 
 
 
Realized Gain (Loss) on Derivatives, net
 
 
 
 
 
 
 

 
 

 
 

Natural gas
$
22,082

 
$
(3,425
)
 
*

 
$
44,509

 
$
81,732

 
(46
)%
Crude oil
(23,953
)
 
22,638

 
(206
)%
 
(41,143
)
 
43,861

 
(194
)%
Total realized gain (loss) on derivatives, net
$
(1,871
)
 
$
19,213

 
(110
)%
 
$
3,366

 
$
125,593

 
(97
)%
 
 
 
 
 
 
 
 
 
 
 
 
Average Selling Price (excluding realized gain (loss) on derivatives)
 
 
 
 
 
 
 

 
 

 
 

Natural gas (per Mcf)(3)
$
3.40

 
$
3.26

 
4
 %
 
$
3.36

 
$
4.02

 
(16
)%
NGLs (per Bbl)
47.44

 
38.20

 
24
 %
 
48.84

 
40.14

 
22
 %
Crude oil (per Bbl)
96.21

 
71.17

 
35
 %
 
90.95

 
71.78

 
27
 %
Natural gas equivalents (per Mcfe)
6.85

 
6.70

 
2
 %
 
7.12

 
6.96

 
2
 %
 
 
 
 
 
 
 
 
 
 
 
 
Average Selling Price (including realized gain (loss) on derivatives)
 
 
 
 
 
 
 

 
 

 
 

Natural gas (per Mcf)
$
4.56

 
$
3.10

 
47
 %
 
$
4.50

 
$
5.92

 
(24
)%
NGLs (per Bbl)
47.44

 
38.20

 
24
 %
 
48.84

 
40.14

 
22
 %
Crude oil (per Bbl)
74.88

 
80.60

 
(7
)%
 
76.70

 
82.06

 
(7
)%
Natural gas equivalents (per Mcfe)
6.78

 
7.19

 
(6
)%
 
7.17

 
8.59

 
(17
)%
 
 
 
 
 
 
 
 
 
 
 
 
Average cost per Mcfe
 
 
 
 
 
 
 
 
 
 
 
Natural gas, NGLs and crude oil production cost(4)
$
4.13

 
$
6.41

 
(36
)%
 
$
4.27

 
$
6.32

 
(32
)%
Depreciation, depletion and amortization
$
4.28

 
$
6.08

 
(30
)%
 
$
4.33

 
$
6.02

 
(28
)%
 
 
 
 
 
 
 
 
 
 
 
 
Operating costs and expenses:
 
 
 
 
 
 
 

 
 

 
 

Direct costs - general and administrative
$
39,771

 
$
257,502

 
(85
)%
 
$
89,478

 
$
291,881

 
(69
)%
Depreciation, depletion and amortization
$
124,945

 
$
241,370

 
(48
)%
 
$
272,373

 
$
461,688

 
(41
)%
 
 
 
 
 
 
 
 
 
 
 
 
Cash distributions
$
12,177

 
$
20,674

 
(41
)%
 
$
31,136

 
$
138,858

 
(78
)%
*Percentage change not meaningful, equal to or greater than 250% or not calculable.
Amounts may not calculate due to rounding.

-18-
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) The Partnership's average sales price for natural gas is based on the "net-back" method of accounting for transportation, gathering and processing arrangements with natural gas purchasers. See the Partnership's revenue recognition policy described in Note 2, Summary of Significant Accounting Policies, to financial statements in the Partnership's 2010 Form 10-K and Part 1, Item 2, Financial Condition, Liquidity and Capital Resources - Cash Flows, included in this report.
(4) 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

Six months ended June 30, 2011 as compared to six months ended June 30, 2010

For the six months ended June 30, 2011 compared to the same period in 2010, natural gas, NGLs and crude oil sales, on an energy equivalency-basis, decreased 18% due to normal production declines for this stage in the wells' production life cycle.
The approximately $86,000, or 16% decrease in sales for the 2011 six month period as compared to the prior year period, was primarily a reflection of sales volume decreases of 18% partially offset by an increase in sales prices of 2%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $7.12 for the current year six month period compared to $6.96 for the same period a year ago.
Natural gas and crude oil revenues decreased by 24% and 14%, respectively, while NGLs revenue remained relatively flat. The Partnership's natural gas revenue decrease resulted from lower Partnership natural gas production volumes of 10% and from decreased commodity prices per Mcf of 16%. The NGLs revenue remained relatively flat due to increased commodity prices per Bbl of 22%, offset by a decrease of 18% in NGLs production volumes. The crude oil revenue decrease is due primarily to sales volume decreases of 32%, partially offset by the rise in commodity prices per Bbl of 27%, during the current six month period.
Three months ended June 30, 2011 as compared to three months ended June 30, 2010

For the three months ended June 30, 2011 compared to the same period in 2010, natural gas, NGLs and crude oil sales, on an energy equivalency-basis, decreased 27% due to decreases in natural gas sales volumes due to normal production declines for this stage in the wells' production life cycle in addition to a significant decrease in crude oil sales volumes due to timing of oil tank pick-ups by the refinery.
The approximately $66,000, or 25%, decrease in sales for the 2011 three month period as compared to the prior year period was primarily a reflection of lower sales volumes of 27%, partially offset by an increase in sales prices of 2%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $6.85 for the current year three month period compared to $6.70 for the same period a year ago.

Natural gas and crude oil revenues decreased by 7% and 37%, respectively, and were partially offset by increases in NGLs revenue of 6%. The Partnership's natural gas revenue decrease resulted from lower Partnership natural gas production volumes of 11%, partially offset by increased commodity prices per Mcf, of 4%. The increase in NGLs revenue was due to increased commodity prices per Bbl of 24%, partially offset by a decrease of 15% in NGLs production volumes. The crude oil revenue decrease is due primarily to sales volume decreases of 53%, partially offset by the rise in commodity prices per Bbl of 35% during the current three month period.

-19-
PDC 2003-C Limited Partnership
(A West Virginia Limited Partnership)



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 collars, fixed-price swaps and basis swaps on a portion of the Partnership's estimated natural gas and crude oil production. The Partnership sells its natural gas and crude oil at similar prices to the indices inherent in the Partnership's derivative instruments. As a result, for the volumes underlying the Partnership's derivative positions, 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.

The following table presents the realized and unrealized derivative gains and losses included in commodity price risk management, net.
 
Three months ended June 30,
 
Six months ended June 30,
 
2011
 
2010
 
2011
 
2010
Commodity price risk management gain, net:
 
 
 
 
 
 
 
  Realized gains (losses)
 
 
 
 
 
 
 
  Natural gas
$
22,082

 
$
(3,425
)
 
$
44,509

 
$
81,732

  Crude oil
(23,953
)
 
22,638

 
(41,143
)
 
43,861

       Total realized gains (losses), net
(1,871
)
 
19,213

 
3,366

 
125,593

 
 
 
 
 
 
 
 
  Unrealized gains (losses)
 
 
 
 
 
 
 
Reclassification of realized gains (losses) included in
 
 
 
 
 
 
 
   prior periods unrealized
3,539

 
(11,409
)
 
(9,994
)
 
(77,775
)
  Unrealized gains for the period
57,835

 
97,150

 
25,614

 
295,897

       Total unrealized gains, net
61,374

 
85,741

 
15,620

 
218,122

Total commodity price risk management gain, net
$
59,503

 
$
104,954

 
$
18,986

 
$
343,715


Six months ended June 30, 2011 as compared to six months ended June 30, 2010

Realized gains recognized in the six months ended June 30, 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 approximately $100,000 for the six months ended June 30, 2011. These gains were offset in part by an approximate $56,000 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 an approximate $41,000 loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price. Unrealized gains during the six months ended June 30, 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 shifts downward in the natural gas curves resulted in an unrealized gain of approximately $50,000 which was partially offset by unrealized losses of approximately $20,000 on the Partnership's CIG basis protection swaps as the forward basis differential between the NYMEX and CIG had continued to narrow. Additionally, the shifts upward in the crude oil curves resulted in an unrealized loss of approximately $4,000.
The realized derivative gains for the 2010 six month period were approximately $126,000. 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 six month period, realized gains related to natural gas and oil derivatives were approximately $118,000 and $44,000, respectively, and realized losses on the Partnership's CIG basis protection swaps were approximately $36,000. Unrealized gains for the six month period were approximately $296,000 due primarily to a downward shift in the natural gas and oil forward curves. Unrealized gains on the Partnership's natural gas and oil positions for the period were approximately $255,000 and $41,000, respectively.

-20-
PDC 2003-C Limited Partnership
(A West Virginia Limited Partnership)



Three months ended June 30, 2011 as compared to three months ended June 30, 2010

Realized gains recognized in the three months ended June 30, 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 approximately $59,000 for the three months ended June 30, 2011. These gains were offset in part by an approximate $37,000 loss on the Partnership's CIG basis protection swaps as the negative basis differential between NYMEX and CIG was narrower than the strike price of the basis positions. The Partnership also realized an approximate $24,000 loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price. Unrealized gains during the three months ended June 30, 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 shift downward in the crude oil curve resulted in an unrealized gain of approximately $17,000 during the three months ended June 30, 2011. Likewise, the shifts downward in the natural gas and basis curves resulted in a total unrealized gain of approximately $41,000.
The realized derivative gains for the 2010 second quarter were approximately $19,000. 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 natural gas and oil derivatives were approximately $56,000 and realized losses on the Partnership's CIG basis swaps were approximately $37,000. For the 2010 second quarter, the unrealized gains 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 oil positions and CIG basis protection swaps for the 2010 second quarter were approximately $45,000 and $44,000, respectively. Additionally, the shifts downward in the natural gas curves resulted in an unrealized gain of approximately $8,000.
The following table presents the Partnership's derivative positions in effect as of June 30, 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
June 30, 2011(2)
Floors
 
Ceilings
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural Gas
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NYMEX
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
07/01 - 09/30/2011
—

 
$
—

 
$
—

 
23,639

 
$
6.73

 
23,639

 
$
(1.88
)
 
$
19,299

10/01 - 12/31/2011
—

 
—

 
—

 
23,103

 
6.78

 
23,103

 
(1.88
)
 
15,032

01/01 - 03/31/2012
1,305

 
6.00

 
8.27

 
21,101

 
6.98

 
22,406

 
(1.88
)
 
12,856

04/01 - 06/30/2012
709

 
6.00

 
8.27

 
21,353

 
6.98

 
22,062

 
(1.88
)
 
18,135

07/01 - 12/31/2012
2,011

 
6.00

 
8.27

 
41,288

 
6.98

 
43,299

 
(1.88
)
 
25,423

2013
—

 
—

 
—

 
81,374

 
7.12

 
81,374

 
(1.88
)
 
42,711

Total Natural Gas
4,025

 
 
 
 
 
211,858

 
 
 
215,883

 
 
 
133,456

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude Oil
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NYMEX
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
07/01 - 09/30/2011
—

 
—

 
—

 
773

 
70.75

 
—

 
—

 
(18,926
)
10/01 - 12/31/2011
—

 
—

 
—

 
788

 
70.75

 
—

 
—

 
(20,414
)
Total Crude Oil
—

 
 
 
 
 
1,561

 
 
 
—

 
 
 
(39,340
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Natural Gas and Crude Oil
 
 
 
 
 
 
 
 
 
 
 
 
$
94,116


(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 none 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.

-21-
PDC 2003-C Limited Partnership
(A West Virginia Limited Partnership)




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.

Six months ended June 30, 2011 as compared to six months ended June 30, 2010

Production and operating costs per Mcfe decreased to $4.27 during the current period compared to $6.32 for the prior year period due to the effect of decreased environmental remediation costs and tubing repairs. Current period production and operating costs include environmental remediation expenses of approximately $70,000 compared to environmental remediation expenses of approximately $140,000 for the same six month period in the prior year. Additionally, in the prior year period there were tubing repairs performed at three of the Partnership's Grand Valley field wells for approximately $130,000.

Three months ended June 30, 2011 as compared to three months ended June 30, 2010

Production and operating costs per Mcfe decreased to $4.13 during the current period compared to $6.41 for the prior year period due to the effect of decreased workover costs partially offset by an increase in environmental remediation charges. Current period production and operating costs include an environmental remediation charge of approximately $50,000 compared to environmental remediation charges of approximately $37,000 for the same three month period in the prior year. In the prior year period there were tubing repairs performed at two of the Partnership's Grand Valley field wells for approximately $100,000.

Direct Costs−General and Administrative

Six months ended June 30, 2011 as compared to six months ended June 30, 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 decreased during the six months ended June 30, 2011 compared to the same period in 2010, by approximately $202,000 principally due to decreased fees for professional services.

Three months ended June 30, 2011 as compared to three months ended June 30, 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 decreased during the three months ended June 30, 2011 compared to the same period in 2010, by approximately $218,000 principally due to decreased fees for professional services.

Depreciation, Depletion and Amortization

Six months ended June 30, 2011 as compared to six months ended June 30, 2010

The DD&A expense rate per Mcfe decreased to $4.33 for the 2011 six month period, compared to $6.02 during the same period in 2010. The decrease of $1.69 in the per Mcfe rates for the 2011 period compared to the 2010 period is due to a decrease of $0.76 as a result of the 2010 impairment of the Partnership's Grand Valley Field. There was an additional decrease of $0.93 resulting from 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. The decrease in production and the decreased DD&A expense rate resulted in an overall decreased DD&A expense of approximately $189,000 for the six months ended June 30, 2011 compared to the same period in 2010.
 

-22-
PDC 2003-C Limited Partnership
(A West Virginia Limited Partnership)



Three months ended June 30, 2011 as compared to three months ended June 30, 2010

The DD&A expense rate per Mcfe decreased to $4.28 for the 2011 three month period, compared to $6.08 during the same period in 2010. The decrease of $1.80 in the per Mcfe rates for the 2011 period compared to the 2010 period is due to a decrease of $0.78 as a result of the 2010 impairment of the Partnership's Grand Valley Field. There was an additional decrease of $1.02 resulting from 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. The decrease in production and the decreased DD&A expense rate resulted in an overall decreased DD&A expense of approximately $116,000 for the three months ended June 30, 2011 compared to the same period in 2010.

Financial Condition, Liquidity and Capital Resources

The Partnership's primary sources of cash for the six months ended June 30, 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. Additionally, the Partnership's operating cash flows were reduced by approximately $171,000 due to payments by the Partnership to reduce the balance of Due to the Managing General Partner-other, net (See Working Capital below). The future repayment of the entire balance of Due to the Managing General Partner-other, net prior to withholding any distributions to fund the Additional Codell Formation Development Plan was taken into consideration when assessing the Partnership's ability to complete this plan. When this balance is repaid, any future withholdings will provide the funding for planned Wattenberg Field well refracturing or recompletion costs to be incurred beginning in 2012. For additional information, see Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments-Additional Codell Formation Development Plan.

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 June 30, 2011, the Partnership had natural gas and crude oil derivative positions in place covering all of the expected natural gas production and 48% of expected crude oil production for the remainder of 2011, at an average price of $4.87 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 first quarter of 2010 comparative period which were the result of contracts entered into during the high 2008 commodity price market. 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.


-23-
PDC 2003-C Limited Partnership
(A West Virginia Limited Partnership)



Working Capital

The Partnership had a working capital deficit at June 30, 2011 of approximately $123,000 compared to a working capital deficit of approximately $178,000 at December 31, 2010. The Partnership's working capital deficit decreased by approximately $55,000 during the six months ended June 30, 2011. This deficit arose in the second half of 2010 due primarily to the increase in 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 are being repaid by the Partnership. The decrease in the working capital deficit was primarily due to the following changes:

•
Due to the Managing General Partner decreased by approximately $171,000 between June 30, 2011 and December 31, 2010,
•
Accounts receivable decreased by $64,000 between June 30, 2011 and December 31, 2010.
•
Realized and unrealized derivative gains receivable decreased by $7,000 between June, 2011 and December 31, 2010.
•
Crude oil inventory decreased by approximately $3,000 between June 30, 2011 and December 31, 2010, and
•
Accounts payable and accrued expenses increased by $42,000 between June 30, 2011 and December 31, 2010.

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 are 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 has 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 $0.31 and $0.32 for the six months ended June 30, 2011 and 2010, respectively.

The price the Partnership receives on its natural gas sales is impacted by the Managing General Partner's transportation, gathering and processing agreements. The Partnership currently uses the "net-back" method of accounting for these arrangements related to the Partnership's natural gas sales. The Partnership sells natural gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based.

-24-
PDC 2003-C Limited Partnership
(A West Virginia Limited Partnership)



Net cash provided by operating activities was approximately $53,000 for the six months ended June 30, 2011, compared to approximately $165,000 for the comparable period in 2010. The decrease of approximately $112,000 in cash provided by operating activities was due primarily to the following:
•
A decrease in natural gas, NGLs and crude oil sales receipts of approximately $27,000, or 5%,

•
A decrease in commodity price risk management realized gains receipts of approximately $167,000, or 84%, and

•
An offsetting decrease in production costs and direct costs - general and administrative payments of approximately $82,000.

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 $22,000 and $26,000 for the six months ended June 30, 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 June 30, 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.
Distributions
 
 
 
 
 
 
 
Three months ended June 30,
 
Managing General Partner
 
Investor Partners
 
Total
2011
 
$
1,053

 
$
11,124

 
$
12,177

2010
 
$
4,135

 
$
16,539

 
$
20,674

 
 
 
 
 
 
 
Six months ended June 30,
 
Managing General Partner
 
Investor Partners
 
Total
2011
 
$
4,165

 
$
26,971

 
$
31,136

2010
 
$
27,771

 
$
111,087

 
$
138,858


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 $2,063 for the six months ended June 30, 2011 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 June 30, 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.

Commitments and Contingencies

See Note 6, Commitments and Contingencies, to the accompanying unaudited condensed financial statements, included in this report.


-25-
PDC 2003-C Limited Partnership
(A West Virginia Limited Partnership)


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.


Item 3. Quantitative and Qualitative Disclosures About Market Risk

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 June 30, 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.

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 June 30, 2011.

(b)    Changes in Internal Control over Financial Reporting
 
During the three months ended June 30, 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.
 

-26-
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.


Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds

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 that the Managing General Partner repurchase their respective individual Investor Partner units, up to an aggregate total limit during any calendar year for all requesting Investor Partner unit repurchases of 10% of the initial subscription units.

There were no limited partnership units repurchased by PDC during the three months ended June 30, 2011.


Item 3. Defaults Upon Senior Securities

Not applicable.


Item 4. [Removed and Reserved]


Item 5. Other Information

Not applicable.

-27-
PDC 2003-C Limited Partnership
(A West Virginia Limited Partnership)




Item 6. Exhibits

The exhibits presented below are in addition to those presented in the Partnership's Form 10-K and subsequent quarterly filings on Form 10-Q.


 
 
 
 
Incorporated by Reference

Exhibit
Number
 
Exhibit Description
 
Form
 

SEC File
Number
 
Exhibit
 
Filing Date
 

Filed
Herewith
 
 
 
 
 
 
 
 
 
 
 
 
 
31.1
 
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
 
 
 
 
 
 
 
 
 
 
 
 
 
31.2
 
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
 
 
 
 
 
 
 
 
 
 
 
 
 
32.1
 
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

-28-
PDC 2003-C Limited Partnership
(A West Virginia Limited Partnership)


SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

PDC 2003-C Limited Partnership
By its Managing General Partner
Petroleum Development Corporation (dba PDC Energy)

 
By: /s/ James M. Trimble
 
 
James M. Trimble
Chief Executive Officer
of Petroleum Development Corporation (dba PDC Energy)
 
 
August 12, 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/ James M. Trimble
 
Chief Executive Officer
August 12, 2011
James M. Trimble
 
Petroleum Development Corporation (dba PDC Energy)
Managing General Partner of the Registrant
 
 
 
(Principal executive officer)
 
 
 
 
 
/s/ Gysle R. Shellum
 
Chief Financial Officer
August 12, 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
August 12, 2011
R. Scott Meyers
 
Petroleum Development Corporation (dba PDC Energy)
Managing General Partner of the Registrant
 
 
 
(Principal accounting officer)
 
 

-29-

PDC 2003-C LP Reports