PDC 2002 C LTD PARTNERSHIP - FORM 10-Q - May 14, 2012

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EX-31.2 - CERTIFICATION OF CFO PURSUAND TO SECTION 302 OF SARBANES-OXLEY ACT OF 2002 - PDC 2002 C LTD PARTNERSHIPa2002c-ex312_20120331.htm
EX-31.1 - CERTIFICATION BY CEO PURSUANT TO SECTION 302 OF SARBANES-OXLEY ACT 0F OF 2002 - PDC 2002 C LTD PARTNERSHIPa2002c-ex311_20120331.htm
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EX-32.1 - CERTIFICATIONS BY CEO AND CFO PURSUANT TO SECTION 906 TO SARBANES-OXLEY ACT 2002 - PDC 2002 C LTD PARTNERSHIPa2002c-ex321_20120331.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 March 31, 2012
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  333-47622-03

PDC 2002-C Limited Partnership

(Exact name of registrant as specified in its charter)
 
West Virginia
 
35-2175775
 
 
(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 Website, 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 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 March 31, 2012 the Partnership had 471.91 units of limited partnership interest and no units of additional general partnership interest outstanding.


PDC 2002-C 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 2002-C Limited Partnership's 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 liquids (“NGLs”) and crude oil production and reserves; additional development 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;
•
the impact of governmental fiscal terms and/or regulations, including changes in environmental laws, the regulation and enforcement related to those laws and the costs to comply with those laws, as well as other regulations;
•
changes in estimates of proved reserves;
•
inaccuracy of reserve estimates and expected production rates;
•
the potential for production decline rates from the Partnership's wells to be greater than expected;
•
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 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 supplies and services at reasonable prices;
•
risks incidental to the additional development and operation of natural gas and crude oil wells;
•
the Partnership's future cash flow, liquidity and financial position;
•
the availability of sufficient pipeline and other transportation facilities to carry Partnership production and the impact of these facilities on price;
•
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 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, 2011 filed with the United States Securities and Exchange Commission (“SEC”) on March 20, 2012 (“2011 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 2002-C Limited Partnership
Condensed Balance Sheets
(unaudited)

 
March 31, 2012
 
December 31, 2011*
Assets
 
 
 

 
 
 
 
Current assets:
 
 
 

Cash and cash equivalents
$
7,331

 
$
7,363

Accounts receivable
23,735

 
57,318

Crude oil inventory
7,800

 
19,370

Due from Managing General Partner-derivatives
207,208

 
181,946

Total current assets
246,074

 
265,997

 
 
 
 
Natural gas and crude oil properties, successful efforts method, at cost
6,969,399

 
6,969,336

Less: Accumulated depreciation, depletion and amortization
(4,929,386
)
 
(4,882,949
)
Natural gas and crude oil properties, net
2,040,013

 
2,086,387

 
 
 
 
Due from Managing General Partner-derivatives
123,029

 
144,180

Other assets
43,771

 
42,160

Total non current assets
2,206,813

 
2,272,727

 
 
 
 
Total Assets
$
2,452,887

 
$
2,538,724

 
 
 
 
Liabilities and Partners' Equity
 
 
 
 
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
95,035

 
$
104,137

Due to Managing General Partner-derivatives
76,959

 
79,281

Due to Managing General Partner-other, net
35,753

 
90,506

Total current liabilities
207,747

 
273,924

 
 
 
 
Due to Managing General Partner-derivatives
53,383

 
71,474

Asset retirement obligations
224,952

 
221,153

Total liabilities
486,082

 
566,551

 
 
 
 
Commitments and contingent liabilities


 


 
 
 
 
Partners' equity:
 
 
 
   Managing General Partner
397,928

 
398,287

   Limited Partners - 471.91 units issued and outstanding
1,568,877

 
1,573,886

Total Partners' equity
1,966,805

 
1,972,173

 
 
 
 
Total Liabilities and Partners' Equity
$
2,452,887

 
$
2,538,724

*Derived from audited 2011 balance sheet

See accompanying notes to unaudited condensed financial statements.

-2-

PDC 2002-C Limited Partnership
Condensed Statements of Operations
(unaudited)

 
Three months ended March 31,
 
2012
 
2011
Revenues:
 
 
 
Natural gas, NGLs and crude oil sales
$
104,950

 
$
135,788

Commodity price risk management gain (loss), net
55,545

 
(21,856
)
Total revenues
160,495

 
113,932

 
 
 
 
Operating costs and expenses:
 
 
 
Natural gas, NGLs and crude oil production costs
79,432

 
37,913

Direct costs - general and administrative
29,060

 
4,530

Depreciation, depletion and amortization
46,437

 
60,545

Accretion of asset retirement obligations
3,799

 
2,296

Total operating costs and expenses
158,728

 
105,284

 
 
 
 
Income from operations
1,767

 
8,648

 
 
 
 
Interest income
4

 
43

 
 
 
 
Net income
$
1,771

 
$
8,691

 
 
 
 
Net income allocated to partners
$
1,771

 
$
8,691

Less: Managing General Partner interest in net income
354

 
1,738

Net income allocated to Investor Partners
$
1,417

 
$
6,953

 
 
 
 
Net income per Investor Partner unit
$
3

 
$
15

 
 
 
 
Investor Partner units outstanding
471.91

 
471.91
















See accompanying notes to unaudited condensed financial statements.

-3-

PDC 2002-C Limited Partnership
Condensed Statements of Cash Flows
(unaudited)

 
Three months ended March 31,
 
2012
 
2011
Cash flows from operating activities:
 
 
 
Net income
$
1,771

 
$
8,691

Adjustments to net income to reconcile to net cash
   provided by operating activities:
 
 
 
Depreciation, depletion and amortization
46,437

 
60,545

Accretion of asset retirement obligations
3,799

 
2,296

Unrealized loss (gain) on derivative transactions
(24,524
)
 
25,083

Changes in assets and liabilities:
 
 
 
Decrease in accounts receivable
33,583

 
7,045

Decrease (increase) in crude oil inventory
11,570

 
(5,910
)
Increase in other assets
(1,611
)
 
(1,865
)
Decrease in accounts payable and accrued expenses
(9,102
)
 
(2,340
)
Decrease in Due to Managing General Partner - other, net
(54,816
)
 
(69,009
)
Net cash provided by operating activities
7,107

 
24,536

 
 
 
 
Cash flows from investing activities:
 
 
 
Capital expenditures for natural gas and crude oil properties
—

 
(11,816
)
Net cash used in investing activities
—

 
(11,816
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Distributions to Partners
(7,139
)
 
(12,677
)
Net cash used in financing activities
(7,139
)
 
(12,677
)
 
 
 
 
Net increase (decrease) in cash and cash equivalents
(32
)
 
43

Cash and cash equivalents, beginning of period
7,363

 
117,209

Cash and cash equivalents, end of period
7,331

 
117,252
















See accompanying notes to unaudited condensed financial statements.

-4-
PDC 2002-C LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 2012
(unaudited)


Note 1−General and Basis of Presentation

PDC 2002-C Limited Partnership (the “Partnership” or the “Registrant”) was organized in 2002 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 commenced upon closing of an offering for the sale of Partnership units. Upon funding, the Partnership entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner which authorizes Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, to conduct and manage the Partnership's business. In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), the Managing General Partner is authorized to manage all activities of the Partnership and initiates and completes substantially all Partnership transactions.

As of March 31, 2012, there were 471 limited partners in the Partnership (“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 Investor Partners, which are shared pro rata, based upon the number of units in the Partnership, and 20% to the Managing General Partner. The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual Investor Partner. Through March 31, 2012, the Managing General Partner has repurchased 29.5 units of Partnership interests from the Investor Partners at an average price of $3,818 per unit. As of March 31, 2012, the Managing General Partner owns 25% of the Partnership.

Beginning in June 2011, when the Investor Partner's average 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 $715 for the three months ended March 31, 2012 as a result of the Preferred Cash Distribution made under the terms in Section 4.02, which expires in April 2013. There were no Preferred Cash Distributions prior to June 2011. For more information concerning the Performance Standard Obligation, see Note 8, Partners' Equity and Cash Distributions to the Partnership's financial statements that accompany the 2011 Form 10-K.

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 8 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 2011 Form 10-K. The Partnership's accounting policies are described in the Notes to Financial Statements in the Partnership's 2011 Form 10-K and updated, as necessary, in this Form 10-Q. The results of operations for the three months ended March 31, 2012, and the cash flows for the same period, is not necessarily indicative of the results to be expected for the full year or any other future period.



-5-
PDC 2002-C LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 2012
(unaudited)

Note 2−Recent Accounting Standards

Recently Adopted 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. The adoption of these changes did not have a significant impact on the Partnership's financial statements.

Note 3−Transactions with Managing General Partner

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 by the Managing General Partner 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 open 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 and “Due to Managing General Partner-derivatives,” in the case of net unrealized losses.

The following table presents transactions with the Managing General Partner reflected in the condensed balance sheet line item - “Due to Managing General Partner-other, net,” which remain undistributed or unsettled with the Partnership's investors as of the dates indicated.

    
 
March 31, 2012
 
December 31, 2011
Natural gas, NGLs and crude oil sales revenues
collected from the Partnership's third-party customers
$
15,158

 
$
40,289

Commodity price risk management, realized gain
22,100

 
6,118

Other (1)
(73,011
)
 
(136,913
)
Total Due to Managing General Partner-other, net
$
(35,753
)
 
$
(90,506
)

(1)
All other unsettled transactions, excluding derivative instruments, between the Partnership and the Managing General Partner. The majority of these are operating costs and general and administrative costs which have not been deducted from distributions.


-6-
PDC 2002-C LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 2012
(unaudited)

The following table presents Partnership transactions, excluding derivative transactions which are more fully detailed in Note 5, Derivative Financial Instruments, with the Managing General Partner for the three months ended March 31, 2012 and 2011. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Natural gas, NGLs and crude oil production costs” line item on the condensed statements of operations.    
 
 Three months ended March 31,
 
2012
 
2011
 Well operations and maintenance
$
70,479

 
$
25,970

 Gathering, compression and processing fees
3,750

 
4,835

 Direct costs - general and administrative
29,060

 
4,530

 Cash distributions (1) (2)
1,102

 
2,941


(1)
Cash distributions include $389 and $406 during the three months ended March 31, 2012 and 2011, respectively, related to equity cash distributions on Investor Partner units repurchased by PDC.
(2)
Cash distributions to the Managing General Partner were reduced by $715 during the three months ended March 31, 2012, due to Preferred Cash Distributions made by the Managing General Partner to Investor Partners under the Performance Standard Obligation provision of the Agreement. There were no Preferred Cash Distributions prior to June 2011. For more information concerning this obligation, see Note 1, General and Basis of Presentation.

Note 4−Fair Value Measurements and Disclosures

Derivative Financial Instruments

Determination of fair value. The Partnership's fair value measurements are estimated pursuant to a fair value hierarchy that requires the Partnership to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:
Level 1 - Quoted prices (unadjusted) in active markets for identical assets or liabilities.

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. Includes the Partnership's fixed-price swaps and basis swaps.

Level 3 - Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Includes the Partnership's natural gas collars.

Derivative Financial Instruments. The Managing General Partner measures the fair value of the Partnership's 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.


-7-
PDC 2002-C LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 2012
(unaudited)

The Managing General Partner validates its 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 Managing General Partner's 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.

The Managing General Partner has evaluated the credit risk of the counterparties holding the derivative assets, which are primarily financial institutions who are also major lenders in the Managing General Partner's corporate credit facility agreement, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on the Managing General Partner's evaluation, the Managing General Partner has determined that the impact of the risk of nonperformance of the Managing General Partner's counterparties on the fair value of the Partnership's derivative instruments is insignificant.

The following table presents, for each hierarchy level, the Partnership's derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis. These derivative instruments were comprised of commodity collars, commodity fixed-price swaps and basis swaps.
 
March 31, 2012
 
December 31, 2011
 
 Level 2
 
 Level 3
 
 Total
 
 Level 2
 
 Level 3
 
 Total
 
 
 
 
 
 
 
 
 
 
 
 
 Assets:
 
 
 
 
 
 
 
 
 
 
 

 
 
 
 
 
 
 
 
 
 
 
Current
 
 
 
 
 
 
 
 
 
 
 
Commodity based derivatives
$
202,212

 
$
4,996

 
$
207,208

 
$
176,059

 
$
5,887

 
$
181,946

 
 
 
 
 
 
 
 
 
 
 
 
Non-Current
 
 
 
 
 
 
 
 
 
 
 
 Commodity based derivatives
123,029

 
—

 
123,029

 
144,180

 
—

 
144,180

 
 
 
 
 
 
 
 
 
 
 
 
 Total assets
325,241

 
4,996

 
330,237

 
320,239

 
5,887

 
326,126

 
 
 
 
 
 
 
 
 
 
 
 
 Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current
 
 
 
 
 
 
 
 
 
 
 
Basis protection derivative contracts
76,959

 
—

 
76,959

 
79,281

 
—

 
79,281

 
 
 
 
 
 
 
 
 
 
 
 
Non-Current
 
 
 
 
 
 
 
 
 
 
 
Basis protection derivative contracts
53,383

 
—

 
53,383

 
71,474

 
—

 
71,474

 
 
 
 
 
 
 
 
 
 
 
 
 Total liabilities
130,342

 
—

 
130,342

 
150,755

 
—

 
150,755

 
 
 
 
 
 
 
 
 
 
 
 
 Net asset (1)
$
194,899

 
$
4,996

 
$
199,895

 
$
169,484

 
$
5,887

 
$
175,371


(1)As of March 31, 2012 and December 31, 2011, none of the Partnership's derivative instruments were designated as hedges.

    

-8-
PDC 2002-C LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 2012
(unaudited)

The following table presents a reconciliation of the Partnership's Level 3 fair value measurements.     
 
Three months ended
 
March 31, 2012
 
March 31, 2011
 Fair value, net asset, beginning of period
$
5,887

 
$
10,169

 Changes in fair value included in statement of operations line item:
 
 
 
 Commodity price risk management gain (loss), net
1,359

 
1,316

 Settlements
(2,250
)
 
(8,992
)
 Fair value, net asset, end of period
$
4,996

 
$
2,493

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

 
 
March 31, 2012 and 2011, respectively, included in statement of operations line item:
 
 
 
 Commodity price risk management gain (loss), net
$
1,160

 
$
—


The significant unobservable input used in the fair value measurement of the Partnership's derivative contracts is the implied volatility curve, and is provided by a third party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of the Partnership's Level 3 derivative contracts.

See Note 5, Derivative Financial Instruments, for additional disclosure related to the Partnership's derivative financial instruments.

Non-Derivative Financial Assets and Liabilities

The carrying values of the financial instruments comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments.

Note 5−Derivative Financial Instruments

As of March 31, 2012, the Partnership had derivative instruments in place for a portion of its anticipated natural gas production through 2013 for a total of 83,809 MMbtu.

The following table presents the impact of the Partnership's derivative instruments on the Partnership's accompanying condensed statements of operations.
 
 
 Three months ended March 31,
 
 
2012
 
2011
Statement of operations line item:
 
Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized
 
Realized and Unrealized Gains For the Current Period
 
Total
 
Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized
 
Realized and Unrealized Gains (Losses) For the Current Period
 
Total
Commodity price risk management gain (loss), net
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains
 
$
27,858

 
$
3,163

 
$
31,021

 
$
2,316

 
$
911

 
$
3,227

Unrealized gains (losses)
 
(27,858
)
 
52,382

 
24,524

 
(2,316
)
 
(22,767
)
 
(25,083
)
Total commodity price risk management gain (loss), net
$
—

 
$
55,545

 
$
55,545

 
$
—

 
$
(21,856
)
 
$
(21,856
)
 
 
 
 
 
 
 
 
 
 
 
 
 

-9-
PDC 2002-C LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 2012
(unaudited)

Derivative Counterparties. The Managing General Partner makes 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 risk of nonperformance of the counterparties on the fair value of the Partnership's derivative instruments was not significant.

Note 6−Commitments and Contingencies
Legal Proceedings

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

Environmental

Due to the nature of the oil and gas industry, the Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures in place to prevent 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 remediation efforts are probable and the costs can be reasonably estimated. During the three months ended March 31, 2012, there were no new environmental remediation projects identified by the Managing General Partner for the Partnership. As of March 31, 2012, the Partnership has accrued environmental remediation liabilities for two of the Partnership's wells in the amount of approximately $93,000, which is included in line item captioned “Accounts payable and accrued expenses” on the condensed balance sheet. At December 31, 2011, the Partnership had accrued environmental remediation liabilities for the same projects for approximately $99,000. The Managing General Partner is not currently aware of any environmental claims existing as of March 31, 2012, 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.

-10-
PDC 2002-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 2002-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 2002 and operates 14 gross (12.7 net) productive wells located in the Rocky Mountain Region in the state of Colorado. The Managing General Partner markets the Partnership's natural gas and crude oil production to commercial end users, interstate or intrastate pipelines, local utilities and petroleum refiners or marketers, 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 a separate 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.
Due to the Investor Partner's average annual rate of return being less than 12.8% in June 2011, the Partnership modified the standard ownership-based pro-rata allocation of Partnership cash available for distribution. See Footnote 1 - General and Basis of Presentation and Item 2 - Financial Condition, Liquidity and Capital Resources - Cash Flows for additional information and the effect of this modification on distributions.
Recent Developments
PDC Sponsored Drilling Program Acquisition Plan
PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue, beginning in the fall of 2010 and extending through 2013, the acquisition of the limited partnership units, other than those held by PDC or its affiliates, held by limited partners (“non-affiliated investor partners”), in certain limited partnerships that PDC had previously sponsored, including this Partnership (the “Acquisition Plan”). For additional information regarding the Acquisition Plan, refer to prior disclosure included in PDC's filings made with the SEC and presentations on PDC's website. However, such information shall not, by reason of this reference, be deemed to be incorporated by reference in, or otherwise be deemed to be part of, this report. Under the Acquisition Plan, any existing or future merger offer will be subject to the terms and conditions of the related merger agreement, and such agreement will likely contemplate the partnership being merged with and into a wholly-owned subsidiary of PDC. Each such merger will also be subject to, among other things, PDC having sufficient available capital, the economics of the merger and the approval by a majority of the limited partnership units held by the non-affiliated investor partners of such limited partnership. Consummation of any proposed merger of a limited partnership under the Acquisition Plan will result in the termination of the existence of that partnership and each non-affiliated investor partner will receive the right to receive a cash payment for their limited partnership units in that partnership and will no longer participate in that partnership's future earnings or the Partnership's economic benefit.

During 2010 and 2011, PDC purchased twelve partnerships for an aggregate amount of $107.7 million. The feasibility and timing of any future cash purchase offer by PDC to any additional partnership, including this Partnership, depends on that partnership's suitability in meeting a set of criteria that includes, but is not limited to, the following: age and productive-life stage characteristics of the partnership's well inventory; favorability of economics for additional development in the Wattenberg Field, including commodity prices; and SEC reporting compliance status and timing and ability to achieve all necessary SEC approvals required to commence a merger and repurchase offer. On December 21, 2011, PDC and its wholly-owned merger subsidiary were served with an alleged class action on behalf of certain former partnership unit holders, related to eleven partnership repurchases completed by mergers in 2010 and 2011.  The action was filed in United States ("U.S.") District Court for the Central District of California, and is titled Schulein v. Petroleum Development Corp.  The complaint alleges a claim that the proxy statements issued in connection with the mergers were inadequate, and a state law breach of fiduciary duty claim.  On February 10, 2012, PDC filed a motion to dismiss or in the alternative to stay. The motion was argued on April 2, 2012. The Court has not filed a ruling at this time. The case is set for a scheduling conference on June 11, 2012.  The Managing General Partner believes the suit is without merit and intends to defend it vigorously. There is no assurance that any potential proposed repurchase offer to any other of PDC's various public limited partnerships, including this Partnership, will occur.

-11-
PDC 2002-C Limited Partnership
(A West Virginia Limited Partnership)


 
Additional 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 Development Plan”). The Additional Development Plan consists of the Partnership's refracturing of wells currently producing in the Codell formation and/or recompletion in the Niobrara or Codell formation which is currently not producing. Under the Additional Development Plan, the Partnership plans to initiate additional development activities during 2013. Refracturing 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. Historically, refracturing and recompletion activities have resulted in an increase in both liquids and natural gas production.

Additional 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 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 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 that are believed to provide the highest rate of return to the Partnership. On average, the production resulting from PDC's refracturings or recompletions have increased production; however, not all refracturings or recompletions have been economically successful and similar future refracturing or recompletion activities may not be economically successful. If the additional development work is performed, the Partnership will bear 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 of 2010, the Managing General Partner began a program for its affiliated partnerships to begin accumulating cash from cash flows from operating activities to pay for future refracturing or recompletion costs. This program will materially reduce, up to 100%, cash available for distributions of the partnerships for a period of time not to exceed five years. This Partnership has not begun to withhold funds for refracturing as this Partnership has outstanding payables to the Managing General Partner.

Current estimated costs for these well refracturings or recompletions are between $180,000 and $260,000 per activity. As of March 31, 2012, this Partnership had scheduled to complete 17 additional development opportunities. Total withholding for these activities from the Partnership's cash available for distributions is estimated to be between $3.2 million and $3.6 million if all of the activities are performed. The Managing General Partner will continually evaluate the timing of commencing these additional development activities based on engineering data and a favorable commodity price environment in order to maximize the expected financial benefit of the additional well development. As of March 31, 2012, no funds have been withheld from the Partnership's cash distributions pursuant to the Additional Development Plan.

Both the number and timing of the additional 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 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 Development Plan has and will continue to 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 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 Development Plan.

    

-12-
PDC 2002-C Limited Partnership
(A West Virginia Limited Partnership)


Current Low Natural Gas Price Environment

The natural gas market continues to be characterized by depressed prices. While the Partnership has derivative instruments in place for a majority of its expected natural gas production, sustained low natural gas prices would result in higher realized derivative gains upon settlement but also could have a material adverse effect as a result of lower natural gas sales, a reduction in the estimated quantity of proved reserves and the estimated future net cash flows expected to be generated from these reserves.

Partnership Operating Results Overview

Natural gas, NGLs and crude oil sales decreased 23%, or approximately $31,000, for the first three months of 2012 compared to the first three months of 2011, while sales volumes declined 11% period-to-period. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.17 for the current year period compared to $5.98 for the same period a year ago. Realized derivative gains from natural gas sales contributed an additional $1.53 per Mcfe, or approximately $31,000, to the total revenues for the first three months of 2012 compared to an additional $0.14, or approximately $3,000, from natural gas and crude oil sales for the first three months of 2011. Comparatively, the total per Mcfe price realized, consisting of the average sales price and realized derivative gains, increased to $6.70 for the current year three months from $6.12 for the same prior year period.

Natural Gas, NGLs and Crude Oil Production Costs increased by approximately $42,000 during the 2012 three month period due primarily to increased workovers and tubing repair activities. Direct costs − general and administrative increased by approximately $24,000 during the 2012 three month period due to the timing of fees for professional services.


-13-
PDC 2002-C Limited Partnership
(A West Virginia Limited Partnership)



Results of Operations

Summary Operating Results

The following table presents selected information regarding the Partnership’s results of operations.
 
 Three months ended March 31,
 
2012
 
2011
 
 Change
Number of gross producing wells (end of period)
13

 
14

 
(1
)
 
 
 
 
 
 
Production(1)
 
 
 
 
 
Natural gas (Mcf)
14,072

 
16,075

 
(12
)%
NGLs (Bbl)
385

 
393

 
(2
)%
Crude oil (Bbl)
651

 
713

 
(9
)%
Natural gas equivalents (Mcfe)(2)
20,288

 
22,711

 
(11
)%
Average Mcfe per day
223

 
252

 
(12
)%
 
 
 
 
 
 
Natural Gas, NGLs and Crude Oil Sales
 
 
 
 
 
Natural gas
$
28,282

 
$
53,437

 
(47
)%
NGLs
15,525

 
20,370

 
(24
)%
Crude oil
61,143

 
61,981

 
(1
)%
Total natural gas, NGLs and crude oil sales
$
104,950

 
$
135,788

 
(23
)%
 
 
 
 
 
 
Realized Gain (Loss) on Derivatives, net
 
 
 
 
 
Natural gas
$
31,021

 
$
12,328

 
152
 %
Crude oil
—

 
(9,101
)
 
(100
)%
Total realized gain on derivatives, net
$
31,021

 
$
3,227

 
*
 
 
 
 
 
 
Average Selling Price (excluding realized gain (loss) on derivatives)
 
 
 
 
 
Natural gas (per Mcf)
$
2.01

 
$
3.32

 
(40
)%
NGLs (per Bbl)
40.32

 
51.83

 
(22
)%
Crude oil (per Bbl)
93.92

 
86.93

 
8
 %
Natural gas equivalents (per Mcfe)
5.17

 
5.98

 
(13
)%
 
 
 
 
 
 
Average Selling Price (including realized gain (loss) on derivatives)
 
 
 
 
 
Natural gas (per Mcf)
$
4.21

 
$
4.09

 
3
 %
NGLs (per Bbl)
40.32

 
51.83

 
(22
)%
Crude oil (per Bbl)
93.92

 
74.17

 
27
 %
Natural gas equivalents (per Mcfe)
6.70

 
6.12

 
9
 %
 
 
 
 
 
 
Average cost per Mcfe
 
 
 
 
 
Natural gas, NGLs and crude oil production cost(3)
$
3.92

 
$
1.67

 
135
 %
Depreciation, depletion and amortization
$
2.29

 
$
2.67

 
(14
)%
 
 
 
 
 
 
Operating costs and expenses:
 
 
 
 
 
Direct costs - general and administrative
$
29,060

 
$
4,530

 
*
Depreciation, depletion and amortization
$
46,437

 
$
60,545

 
(23
)%
 
 
 
 
 
 
Cash distributions
$
7,139

 
$
12,677

 
(44
)%
*Percentage change is not meaningful, equal to or greater than 250% or not calculable.
Amounts may not recalculate due to rounding.

-14-
PDC 2002-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) Represents 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 of crude oil or natural gas liquids ("NGLs") or 42 gallons of liquid volume.
Btu - British thermal unit.
MBbl - One thousand barrels of crude oil or NGLs.
Mcf - One thousand cubic feet of natural gas volume.
Mcfe - One thousand cubic feet of natural gas equivalent (six Mcf of natural gas equals one Bbl of crude oil or NGL).
MMBtu - One million British thermal units.
MMcf - One million cubic feet of natural gas volume.
MMcfe - One million cubic feet of natural gas equivalent.
 
Natural Gas, NGLs and Crude Oil Sales

Natural Gas, NGLs and Crude Oil Pricing. The Partnership's results of operations depend upon many factors, particularly the price of natural gas, NGLs and crude oil and the Managing General Partner's ability to market the Partnership's production effectively. Natural gas, NGLs and crude oil prices are among the most volatile of all commodity prices. These price variations have a material impact on the Partnership's financial results and capital expenditures. The Partnership has experienced a decline in the price of NGLs, mainly at Conway hub in Kansas where the Partnership's Wattenberg production is priced, primarily due to increased ethane volumes and the limited market for ethane. Natural gas and NGL 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. 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, 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 predominately driven by the physical market, supply and demand, the financial markets and national and international politics.

The price the Partnership receives for its natural gas produced in the Rocky Mountain Region is based on a market basket of prices, which generally includes natural gas sold at, near or below CIG prices as well as other nearby region prices. The CIG Index, and other indices for production delivered to other Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is primarily New York Mercantile Exchange, or NYMEX, based. This negative differential has narrowed over the last few years. The negative differential between NYMEX and CIG averaged $0.12 and $0.28 for the three months ended March 31, 2012 and 2011, respectively.

Three months ended March 31, 2012 as compared to three months ended March 31, 2011

For the three months ended March 31, 2012 compared to the same period in 2011, natural gas, NGLs and crude oil sales volumes, on an energy equivalency-basis, decreased 11% due to normal production declines for this stage in the wells' production life cycle.
The $31,000, or 23%, decrease in sales for the 2012 three month period as compared to the prior year period was a reflection of sales volume decreases of 11% and a decline in average sales prices of 13%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.17 for the current year three month period compared to $5.98 for the same period a year ago.
Natural gas, NGLs and crude oil sales decreased by 47%, 24% and 1%, respectively. The Partnership's natural gas sales decrease resulted from decreased commodity prices per Mcf of 40% and lower Partnership natural gas production volumes of 12%. The decrease in NGLs sales was due to a decrease of 2% in NGLs production volumes and a decrease in the average commodity price per Bbl of 22%. The crude oil sales decrease was due primarily to sales volume decreases of 9%, partially offset by an increase in the average commodity price per Bbl of 8% during the current three month period.
 


-15-
PDC 2002-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 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 production. The Partnership sells its natural gas 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 Measurements and Disclosures 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 gain, net.
 
Three months ended March 31,
 
2012
 
2011
Commodity price risk management gain (loss), net:
 
 
 
  Realized gains (losses)
 
 
 
  Natural gas
$
31,021

 
$
12,328

  Crude oil
—

 
(9,101
)
       Total realized gains, net
31,021

 
3,227

 
 
 
 
  Unrealized gains (losses)
 
 
 
Reclassification of realized gains included in
 
 
 
   prior periods unrealized gains
(27,858
)
 
(2,316
)
  Unrealized gains (losses) for the period
52,382

 
(22,767
)
       Total unrealized gains (losses), net
24,524

 
(25,083
)
Total commodity price risk management gain (loss), net
$
55,545

 
$
(21,856
)

Three months ended March 31, 2012 as compared to three months ended March 31, 2011
Realized gains of approximately $31,000 recognized in the three months ended March 31, 2012, were 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. For the three months ended March 31, 2012, realized gains on natural gas, exclusive of basis swaps, were approximately$54,000. These gains were offset in part by realized losses of approximately $23,000 on the Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted average price was narrower than the strike price of the Partnership's basis swaps.
Unrealized gains of approximately $52,000 for the three months ended March 31, 2012, were primarily related to the downward shift in the natural gas forward curve and its impact on the fair value of the Partnership's open positions, offset in part by the narrowing of the CIG basis forward curve. For the period ended March 31, 2012, unrealized gains on the Partnership's natural gas positions were approximately $52,000, offset slightly by unrealized losses on the Partnership's CIG basis swaps.

Realized gains recognized in the three months ended March 31, 2011 were 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 $23,000 for the three months ended March 31, 2011. These gains were offset in part by an approximate $11,000 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 $9,000 loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price.

Unrealized losses during the three months ended March 31, 2011 were primarily related to the shifts in the forward curves and their impact on the fair value of the Partnership's open positions. The significant shift upward in the crude oil curve resulted in an unrealized loss of approximately $17,000 during the three months ended March 31, 2011. Likewise, the shifts upward in the natural gas and basis curves resulted in a total unrealized loss of approximately $6,000.

-16-
PDC 2002-C Limited Partnership
(A West Virginia Limited Partnership)



The following table presents the Partnership's derivative positions in effect as of March 31, 2012.
 
Collars
 
Fixed-Price Swaps
 
CIG Basis Protection Swaps
 
 
Commodity/
Index
Quantity
(Gas-MMBtu(1))
 
Weighted Average
Contract Price
 
Quantity
(Gas-MMBtu(1))
 
Weighted
Average
Contract
Price
 
Quantity
(Gas-MMBtu(1))
 
Weighted
Average
Contract
Price
 

Fair Value at
March 31, 2012(2)
Floors
 
Ceilings
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural Gas
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NYMEX
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
04/01 - 06/30/2012
378

 
$
6.00

 
$
8.27

 
12,229

 
$
6.98

 
12,607

 
$
(1.88
)
 
$
39,970

07/01 - 09/30/2012
512

 
6.00

 
8.27

 
11,990

 
6.98

 
12,502

 
(1.88
)
 
35,538

10/01 - 12/31/2012
562

 
6.00

 
8.27

 
11,672

 
6.98

 
12,234

 
(1.88
)
 
29,600

01/01 - 03/31/2013
—

 
—

 
—

 
11,752

 
7.12

 
11,752

 
(1.88
)
 
25,141

04/01 - 06/30/2013
—

 
—

 
—

 
11,706

 
7.12

 
11,706

 
(1.88
)
 
25,355

07/01 - 09/30/2013
—

 
—

 
—

 
11,620

 
7.12

 
11,620

 
(1.88
)
 
23,719

10/01 - 12/31/2013
—

 
—

 
—

 
11,388

 
7.12

 
11,388

 
(1.88
)
 
20,572

Total Natural Gas
1,452

 
 
 
 
 
82,357

 
 
 
83,809

 
 
 
199,895

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) A standard unit of measure for natural gas (one MMBtu equals one Mcf).
(2) As of March 31, 2012, approximately 2% of the fair value of the Partnership's derivative assets were measured using significant unobservable inputs (Level 3); see Note 4, Fair Value Measurements and Disclosures, to the accompanying unaudited condensed financial statements included in this report.

Natural Gas, NGLs and Crude Oil Production Costs

Generally, natural gas, NGLs and crude oil production costs vary with changes in total natural gas, NGLs and crude oil sales and production volumes. Production taxes are estimates by the Managing General Partner based on tax rates determined using published information. These estimates are subject to revision based on actual amounts determined during future filings by the Managing General Partner with the taxing authorities. Production taxes vary directly with total natural gas, NGLs and crude oil sales. Transportation costs vary directly with production volumes. Fixed monthly well operating costs increase on a per unit basis as production decreases per the historical decline curve. In addition, general oil field services and all other costs vary and can fluctuate based on services required but are expected to increase as wells age and require more extensive repair and maintenance. These costs include water hauling and disposal, equipment repairs and maintenance, snow removal, environmental compliance and remediation, and service rig workovers.

Three months ended March 31, 2012 as compared to three months ended March 31, 2011

Production and operating costs for the three month period ended March 31, 2012 increased by approximately $42,000 compared to the same period in 2011. Lease operating costs were higher by approximately $47,000 in the current period as workovers and tubing repair activities collectively were lower in the prior period. Higher lease operating costs were partially offset by lower revenue and volume-based costs by approximately $3,000 in 2012, consistent with sales and production declines from 2011. Production and operating costs per Mcfe increased to $3.92 during 2012 from $1.67 in 2011 due to lower volumes and increased costs.

Direct Costs−General and Administrative

Three months ended March 31, 2012 as compared to three months ended March 31, 2011

Direct costs - general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer's reserve reports and legal matters. Direct costs increased during the three months ended March 31, 2012, compared to the same period in 2011, by approximately $24,000, principally due to the timing of fees for professional services.

-17-
PDC 2002-C Limited Partnership
(A West Virginia Limited Partnership)



Depreciation, Depletion and Amortization (DD&A)

Three months ended March 31, 2012 as compared to three months ended March 31, 2011

The DD&A expense rate per Mcfe decreased to $2.29 for the 2012 three month period, compared to $2.67 during the same period in 2011. The decrease in the per Mcfe rates for the 2012 period compared to the 2011 period is due to the effect of the 2011 impairment of the Partnership’s Piceance Basin assets. The decrease in production and the decreased DD&A expense rate resulted in an overall decreased DD&A expense of approximately $14,000 for the 2012 three month period compared to the same 2011 period.


Financial Condition, Liquidity and Capital Resources

The Partnership's primary sources of cash for the three months ended March 31, 2012 were from funds provided by operating activities which include the sale of natural gas, NGLs and crude oil production and the net realized gains from the Partnership's derivative positions. These sources of cash were primarily used to fund the Partnership's operating costs, general and administrative activities and provided monthly distributions to the Investor Partners and PDC, the Managing General Partner. Any future withholdings would provide the funding for planned Wattenberg Field refracturing or recompletion costs to be incurred during 2013 and thereafter, and are expected to decrease distributions from historical levels.

Fluctuations in the Partnership's operating cash flows are substantially driven by changes in commodity prices, in production volumes and in realized gains and losses from commodity positions. Commodity prices have historically been volatile and the Managing General Partner attempts to manage this volatility through derivatives. Therefore, the primary source of the Partnership's cash flow from operations becomes the net activity between the Partnership's natural gas, NGLs and crude oil sales and realized natural gas and crude oil derivative gains and losses. However, the Partnership does not engage in speculative positions, nor does the Partnership hold derivative instruments for 100% of the Partnership's expected future production from producing wells and therefore may still experience significant fluctuations in cash flows from operations. As of March 31, 2012, the Partnership had natural gas derivative positions in place covering 85% of the expected natural gas production for the remainder of 2012, at an average price of $5.07 per Mcf. However, the Partnership has no NGL or crude oil derivatives. 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 derivatives. 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 2012 and beyond, and may substantially reduce or restrict the Partnership's ability to participate in the additional 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 Development Plan.
  

-18-
PDC 2002-C Limited Partnership
(A West Virginia Limited Partnership)



Working Capital

The Partnership had working capital of approximately $38,000 at March 31, 2012 compared to a working capital deficit of approximately $8,000 at December 31, 2011, an increase of approximately $46,000. The increase was primarily due to the following changes:

•
Accounts receivable decreased approximately $59,000 between March 31, 2012 and December 31, 2011.

•
Realized and unrealized derivative gains receivable increased by approximately $43,000 between March 31, 2012 and December 31, 2011.

•
Oil inventory decreased by approximately $11,000 between March 31, 2012 and December 31, 2011.

•
Due to Managing General Partner-other, net, excluding natural gas, NGLs and crude oil sales received from third parties and realized derivative gains, decreased by approximately $64,000 between March 31, 2012 and December 31, 2011.

•
Accounts payable decreased approximately $9,000 between March 31, 2012 and December 31, 2011.

Working capital is expected to increase during periods of Additional Development Plan funding and decrease during periods when payments are made for refracturing or recompletion activities.

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.

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.

Net cash provided by operating activities was approximately $7,000 for the three months ended March 31, 2012, compared to approximately $24,000 for the comparable period in 2011. The decrease of approximately $17,000 in net cash provided by operating activities was due primarily to the following:

•
An increase in natural gas, NGLs and crude oil sales receipts of approximately $19,000, or 13%,

•
A decrease in commodity price risk management realized gains receipts of approximately $2,000, or 14%, and

•
An increase in production costs and direct costs - general and administrative payments of approximately $34,000.

Cash Flows from Investing Activities

The Partnership, from time-to-time, invests in equipment which supports treatment, delivery and measurement of natural gas, NGLs and crude oil or environmental protection. These amounts were not significant for the three months ended March 31, 2012 and 2011, respectively.


-19-
PDC 2002-C Limited Partnership
(A West Virginia Limited Partnership)


Cash Flows from Financing Activities

The Partnership initiated monthly cash distributions to investors in May 2003 and has distributed $9.6 million through March 31, 2012. The table below presents cash distributions to the Partnership's investors. Distributions to the Managing General Partner represent amounts distributed to PDC for the Managing General Partner's 20% general partner interest 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 March 31,
 
Managing General Partner
 
Investor Partners
 
Total
2012
 
$
713

 
$
6,426

 
$
7,139

2011
 
2,535

 
10,142

 
12,677

 
 
 
 
 
 
 

The decrease in total distributions for 2012 as compared to 2011 is primarily due to the decrease in cash flows from operating activities during 2012.

Beginning in June 2011, when the Investor Partner's average 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 $715 for the three months ended March 31, 2012 as a result of the Preferred Cash Distribution made under the terms in Section 4.02. Because of the expected production declines related to the Partnership's mature natural gas and crude oil operations, the Managing General Partner believes performance obligation allocation rate modifications are likely to continue until April 2013, when the provision expires under the terms of the Agreement.

Off-Balance Sheet Arrangements

As of March 31, 2012, 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.

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 2011 Form 10-K.

-20-
PDC 2002-C Limited Partnership
(A West Virginia Limited Partnership)





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 March 31, 2012, 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 March 31, 2012.

(b)    Changes in Internal Control over Financial Reporting
 
During the three months ended March 31, 2012, 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.
 

-21-
PDC 2002-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 March 2006, the third anniversary of the date of the first Partnership cash distributions, Investor Partners of the Partnership may request that the Managing General Partner repurchase their respective individual Investor Partner units, up to an aggregate total limit during any calendar year for all requesting Investor Partner unit repurchases of 10% of the initial subscription units.

The following table presents information about the Managing General Partner's limited partner unit repurchases during the three months ended March 31, 2012.

Period
 
Total Number of
 Units Repurchased
 
Average Price Paid
 Per Unit
January 1 - 31
 


 
$
—

February 1 - 29
 
2.91

 
229

March 1 - 31
 
—

 
—

Total first quarter repurchases
 
2.91

 
 



Item 3. Defaults Upon Senior Securities

Not applicable.


Item 4. Mine Safety Disclosures

Not applicable.


Item 5. Other Information

Not applicable.

-22-
PDC 2002-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.

 
 
 
 
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.
 
 
 
 
 
 
 
 
 

 
 
 
 
 
 
 
 
 
 
 
 
 
101.INS*
 
XBRL Instance Document
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
101.SCH*
 
XBRL Taxonomy Extension Schema Document
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
101.CAL*
 
XBRL Taxonomy Extension Calculation Linkbase Document
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
101.DEF*
 
XBRL Taxonomy Extension Definition Linkbase Document
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
101.LAB*
 
XBRL Taxonomy Extension Label Linkbase Document
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
101.PRE*
 
XBRL Taxonomy Extension Presentation Linkbase Document
 
 
 
 
 
 
 
 
 
 
*Furnished herewith.

-23-
PDC 2002-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 2002-C Limited Partnership
By its Managing General Partner
Petroleum Development Corporation (dba PDC Energy)

 
By: /s/ James M. Trimble
 
 
James M. Trimble
President and Chief Executive Officer
of Petroleum Development Corporation (dba PDC Energy)
 
 
May 14, 2012
 
 
 
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
 
President and Chief Executive Officer
May 14, 2012
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
May 14, 2012
Gysle R. Shellum
 
Petroleum Development Corporation (dba PDC Energy)
Managing General Partner of the Registrant
 
 
 
(principal financial officer)
 
 
 
 
 
/s/ R. Scott Meyers
 
Chief Accounting Officer
May 14, 2012
R. Scott Meyers
 
Petroleum Development Corporation (dba PDC Energy)
Managing General Partner of the Registrant
 
 
 
(principal accounting officer)
 
 

-24-

PDC 2002 C LTD PARTNERSHIP Reports