PDC 2002 B LTD PARTNERSHIP - FORM 10-Q - September 21, 2011

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2011
or

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

Commission File Number 000-50227

PDC 2002-B Limited Partnership
(Exact name of registrant as specified in its charter)

West Virginia
38-3648762
(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 o No þ

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

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

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

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

As of August 31, 2011 the Partnership had 559.02 units of limited partnership interest and no units of additional general partnership interest outstanding.
 
 
 
 

PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

INDEX TO REPORT ON FORM 10-Q

   
Page
PART I – FINANCIAL INFORMATION
     
 
1
Item 1.
  
 
2
 
3
 
4
 
5
Item 2.
12
Item 3.
22
Item 4.
22
     
PART II – OTHER INFORMATION
     
Item 1.
23
Item 1A.
23
Item 2.
23
Item 3.
23
Item 4.
23
Item 5.
23
Item 6.
24
     
 
25

 
 

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-B 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 refracturing 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 refracturing 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 June 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 2002-B Limited Partnership
Condensed Balance Sheets
(unaudited)

   
March 31,
    
December 31,
  
   
2011
    
2010*
  
Assets
            
             
Current assets:
            
Cash and cash equivalents
   $ 10,284     $ 10,281  
Accounts receivable
     54,307       33,072  
Crude oil inventory
     18,912       16,072  
Due from Managing General Partner-derivatives
     125,373       119,434  
Total current assets
     208,876       178,859  
                 
                 
Natural gas and crude oil properties, successful efforts method, at cost
     8,744,472       8,744,472  
Less: Accumulated depreciation, depletion and amortization
     (6,064,320 )     (5,973,662 )
Natural gas and crude oil properties, net
     2,680,152       2,770,810  
                 
Due from Managing General Partner-derivatives
     161,646       188,773  
Other assets
     36,446       34,528  
Total noncurrent assets
     2,878,244       2,994,111  
                 
Total Assets
   $ 3,087,120     $ 3,172,970  
                 
Liabilities and Partners' Equity
                
                 
Current liabilities:
                
Accounts payable and accrued expenses
   $ 4,336     $ 5,854  
Due to Managing General Partner-derivatives
     120,013       100,569  
Due to Managing General Partner-other, net
     32,735       94,642  
Total current liabilities
     157,084       201,065  
                 
Due to Managing General Partner-derivatives
     127,038       142,961  
Asset retirement obligations
     156,964       154,650  
Total liabilities
     441,086       498,676  
                 
Commitments and contingent liabilities
                
                 
Partners' equity:
                
Managing General Partner
     592,895       597,648  
Limited Partners - 559.02 units issued and outstanding
     2,053,139       2,076,646  
Total Partners' equity
     2,646,034       2,674,294  
                 
Total Liabilities and Partners' Equity
   $ 3,087,120     $ 3,172,970  
 
__________________________________
*Derived from audited 2010 balance sheet

See accompanying notes to unaudited condensed financial statements.

 
- 2 -

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

   
Three months ended March 31,
  
   
2011
    
2010
  
Revenues:
            
Natural gas, NGLs and crude oil sales
   $ 154,191     $ 215,077  
Commodity price risk management gain (loss), net
     (17,884 )     161,482  
Total revenues
     136,307       376,559  
                 
Operating costs and expenses:
                
Natural gas, NGLs and crude oil production costs
     55,457       83,384  
Direct costs - general and administrative
     8,464       1,822  
Depreciation, depletion and amortization
     90,658       139,951  
Accretion of asset retirement obligations
     2,314       2,180  
Total operating costs and expenses
     156,893       227,337  
                 
Income (loss) from operations
     (20,586 )     149,222  
                 
Interest income
     4       -  
                 
Net income (loss)
   $ (20,582 )   $ 149,222  
                 
Net income (loss) allocated to partners
   $ (20,582 )   $ 149,222  
Less: Managing General Partner interest in net income (loss)
     (4,116 )     29,844  
Net income (loss) allocated to Investor Partners
   $ (16,466 )   $ 119,378  
                 
Net income (loss) per Investor Partner unit
   $ (29 )   $ 214  
                 
Investor Partner units outstanding
     559.02       559.02  

See accompanying notes to unaudited condensed financial statements.

 
- 3 -

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

   
Three months ended March 31,
  
   
2011
    
2010
  
Cash flows from operating activities:
            
Net income (loss)
   $ (20,582 )   $ 149,222  
Adjustments to net income (loss) to reconcile to net cash provided by operating activities:
                
Depreciation, depletion and amortization
     90,658       139,951  
Accretion of asset retirement obligations
     2,314       2,180  
Unrealized loss (gain) on derivative transactions
     24,709       (96,431 )
Changes in operating assets and liabilities:
                
Decrease (increase) in accounts receivable
     (21,235 )     9,496  
Decrease (increase) in crude oil inventory
     (2,840 )     9,412  
Increase in other assets
     (1,918 )     (1,917 )
Increase (decrease) in accounts payable and accrued expenses
     (1,518 )     1,561  
Increase in Due from Managing General Partner - other, net
     -       (33,690 )
Decrease in Due to Managing General Partner - other, net
     (61,907 )     -  
Net cash provided by operating activities
     7,681       179,784  
                 
Cash flows from investing activities:
                
Capital expenditures for natural gas and crude oil properties
     -       (44 )
Net cash used in investing activities
     -       (44 )
                 
Cash flows from financing activities:
                
Distributions to Partners
     (7,678 )     (179,764 )
Net cash used in financing activities
     (7,678 )     (179,764 )
                 
Net increase (decrease) in cash and cash equivalents
     3       (24 )
Cash and cash equivalents, beginning of period
     10,281       935  
Cash and cash equivalents, end of period
   $ 10,284     $ 911  

See accompanying notes to unaudited condensed financial statements.

 
- 4 -

PDC 2002-B LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 2011
(unaudited)

Note 1−General and Basis of Presentation

PDC 2002-B 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 510 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 32.4 units of Partnership interests from the Investor Partners at an average price of $4,510 per unit. As of June 30, 2011, the Managing General Partner owns 24.6% of the Partnership.

Beginning in November 2009, 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 $899 and $16,812 for the three month periods ended March 31, 2011 and 2010, respectively, as a result of the Preferred Cash Distribution made under the terms in Section 4.02, which expires in February 2013. 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 2010 Form 10-K.

The Partnership expects continuing operations of its natural gas and crude oil properties until such time the Partnership’s wells are depleted or become uneconomical to produce, at which time they may be sold or plugged, reclaimed and abandoned. The Partnership’s maximum term of existence extends through December 31, 2050, unless dissolved by certain conditions stipulated within the Agreement, which are unlikely to occur at this time, or by written consent of the Investor Partners owning a majority of outstanding units at that time.

In the Managing General Partner’s opinion, the accompanying interim unaudited condensed financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary for a fair statement of the Partnership’s financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities and Exchange Commission (“SEC”). Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in the audited financial statements have been condensed or omitted. The information presented in this quarterly report on Form 10-Q should be read in conjunction with the Partnership’s audited financial statements and notes thereto included in the Partnership’s 2010 Form 10-K. The Partnership’s accounting policies are described in the Notes to Financial Statements in the Partnership’s 2010 Form 10-K and updated, as necessary, in this Form 10-Q. The results of operations for the three months ended March 31, 2011, and the cash flows for the same period, are not necessarily indicative of the results to be expected for the full year or any other future period.

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 2002-B LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 2011
(unaudited)

Note 2−Recent Accounting Standards

Recently Adopted Accounting Standards

Fair Value Measurements and Disclosures

In January 2010, the 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 2002-B LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 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.

   
March 31,
    
December 31,
  
   
2011
    
2010
  
             
Natural gas, NGLs and crude oil sales revenues collected from the Partnership's third-party customers
   $ 41,043     $ 65,527  
Commodity price risk management, realized gain
     3,833       16,576  
Other (1)
     (77,611 )     (176,745 )
Total Due to Managing General Partner-other, net
   $ (32,735 )   $ (94,642 )

 
(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 months ended March 31, 2011 and 2010. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Natural gas, NGLs and crude oil production costs” line item on the condensed statements of operations.

   
Three months ended March 31,
  
   
2011
    
2010
  
             
Well operations and maintenance
   $ 42,705     $ 63,329  
Gathering, compression and processing fees
     5,664       7,252  
Direct costs - general and administrative
     8,464       1,822  
Cash distributions (1) (2)
     1,031       26,288  

 
(1)
Cash distributions include $394 and $7,148 during the three months ended March 31, 2011 and 2010, respectively, related to equity cash distributions on Investor Partner units repurchased by PDC.
 
(2)
Cash distributions to the Managing General Partner for the three months ended March 31, 2011 and 2010, were reduced by $899 and $16,812, respectively, due to Preferred Cash Distributions made by the Managing General Partner to Investor Partners under the Performance Standard Obligation provision of the Agreement. For more information concerning this obligation, see Note 1, General and Basis of Presentation.

 
- 7 -

PDC 2002-B LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 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.

 
- 8 -

PDC 2002-B LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 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.

   
March 31, 2011
    
December 31, 2010 (a)
  
   
Level 2 (b)
    
Level 3 (c)
    
Total
    
Level 2 (b)
    
Level 3 (c)
    
Total
  
                                     
Assets:
                                    
Commodity based derivatives
   $ 283,518     $ 3,501     $ 287,019     $ 295,930     $ 12,277     $ 308,207  
Total assets
     283,518       3,501       287,019       295,930       12,277       308,207  
                                                 
Liabilities:
                                                
Commodity based derivatives
     (33,362 )     -       (33,362 )     (26,987 )     -       (26,987 )
Basis protection derivative contracts
     (213,689 )     -       (213,689 )     (216,543 )     -       (216,543 )
Total liabilities
     (247,051 )     -       (247,051 )     (243,530 )     -       (243,530 )
                                                 
Net asset
   $ 36,467     $ 3,501     $ 39,968     $ 52,400     $ 12,277     $ 64,677  

 
(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 $296,000) 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 $244,000). 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.

   
Three months ended
  
   
March 31, 2011
    
March 31, 2010 (1)
  
             
Fair value, net asset, beginning of period
   $ 12,277     $ 25,590  
Changes in fair value included in statement of operations line item -
                
Commodity price risk management, net
     1,488       12,464  
Settlements
     (10,264 )     (25,734 )
Fair value, net asset, end of period
   $ 3,501     $ 12,320  
                 
Change in unrealized gain (loss) relating to assets (liabilities) still held as of March 31, 2011 and 2010, respectively, included in statement of operations line item:
                
Commodity price risk management, net
   $ (1 )   $ 9,941  

 
(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 $218,000). 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.

 
- 9 -

PDC 2002-B LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 2011
(unaudited)

Note 5−Derivative Financial Instruments

As of March 31, 2011, the Partnership had derivative instruments in place for a portion of its anticipated production through 2013 for a total of 151,599 MMbtu of natural gas and 929 Bbls of crude oil.

The following table presents the location and fair value amounts of the Partnership’s derivative instruments on the accompanying condensed balance sheets. These derivative instruments were comprised of commodity collars, commodity fixed-price swaps and basis swaps.

           
Fair Value
  
       
Balance Sheet
  
March 31,
    
December 31,
  
Derivative instruments not designated as hedge (1):
  
Line Item
  
2011
    
2010
  
                     
Derivative Assets:
  
Current
                
   
Commodity contracts
  
Due from Managing General Partner-derivatives
   $ 125,373     $ 119,434  
                         
   
Non Current
                    
   
Commodity contracts
  
Due from Managing General Partner-derivatives
     161,646       188,773  
                         
Total Derivative Assets
           $ 287,019     $ 308,207  
                         
Derivative Liabilities:
  
Current
                    
   
Commodity contracts
  
Due to Managing General Partner-derivatives
   $ 33,362     $ 26,987  
                         
   
Basis protection contracts
  
Due to Managing General Partner-derivatives
     86,651       73,582  
                         
   
Non Current
                    
   
Basis protection contracts
  
Due to Managing General Partner-derivatives
     127,038       142,961  
                         
Total Derivative Liabilities
       $ 247,051     $ 243,530  

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

The following table presents the impact of the Partnership’s derivative instruments on the Partnership’s accompanying condensed statements of operations.

   
Three months ended March 31,
  
   
2011
    
2010
  
                                     
Statement of operations line item
  
Reclassification of Realized 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 (loss), net
                                    
Realized gains
   $ 5,426     $ 1,399     $ 6,825     $ 60,184     $ 4,867     $ 65,051  
Unrealized gains (losses)
     (5,426 )     (19,283 )     (24,709 )     (60,184 )     156,615       96,431  
Total commodity price risk management gain (loss), net
   $ -     $ (17,884 )   $ (17,884 )   $ -     $ 161,482     $ 161,482  

 
- 10 -

PDC 2002-B LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
March 31, 2011
(unaudited)

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.

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 remediation efforts are probable and the costs can be reasonably estimated. During the three months ended March 31, 2011, there were no new environmental remediation projects identified by the Managing General Partner for the Partnership. As of March 31, 2011, the Partnership has no accrued environmental liabilities. At December 31, 2010, the Partnership had accrued environmental remediation liabilities for one Partnership well in the amount of approximately $2,000 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 March 31, 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.

 
- 11 -

PDC 2002-B 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-B 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 September 2002 and operates 14 gross (12.8 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 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.
 
Due to the Investor Partner's average annual rate of return being less than 12.8% in 2009, 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 distribution.

Recent Developments

PDC Sponsored Drilling Program Acquisition Plan

PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue, which began in the fall of 2010 and extends through 2012, the acquisition of the limited partnership units (the “Acquisition Plan”) held by Investor Partners of the particular partnership other than those held by PDC or its affiliates (“non-affiliated investor partners”), in certain limited partnerships that PDC had previously sponsored, including this Partnership. For additional information regarding PDC’s intention to pursue acquisitions of PDC sponsored partnerships, refer to prior disclosure included in PDC’s filings made with the SEC. However, such information shall not, by reason of this reference, be deemed to be incorporated by reference in, or otherwise be deemed to be part of, this report. Under the Acquisition Plan, any existing or future merger offer will be subject to the terms and conditions of the related merger agreement, and such agreement does or will likely contemplate the partnership being merged with and into a wholly-owned subsidiary of PDC. Each such merger will also be subject to, among other things, PDC having sufficient available capital, the economics of the merger and the approval by a majority of the limited partnership units held by the non-affiliated investor partners of each respective limited partnership. Consummation of any proposed merger of a limited partnership under the Acquisition Plan will result in the termination of the existence of that partnership and 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 any further economic benefit.

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.

In June 2011, PDC and a wholly-owned subsidiary of PDC entered into separate merger agreements with each of PDC 2003-A Limited Partnership, PDC 2003-B Limited Partnership, PDC 2003-C Limited Partnership, PDC 2003-D Limited Partnership and the 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 each 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 each respective partnership, as well as the satisfaction of other customary closing conditions, then the partnership will merge with and into a wholly-owned subsidiary of PDC. On September 14, 2011, a definitive proxy statement was mailed to the non-affiliated investor partners of each of the 2003 and 2002-D Partnerships requesting their approval of the merger transactions. Although there is no assurance of the likelihood or timing of the completion of the SEC proxy disclosure review process, the special meetings whereby non-affiliated investor partners of the 2003 and 2002-D Partnerships will have an opportunity to vote and approve the respective merger agreements are currently expected to occur in the fourth quarter of 2011.

 
- 12 -

PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

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 Wattenberg Field well refracturing; and SEC reporting compliance status and timing associated with gaining all necessary regulatory approvals required for a merger and repurchase offer. There is no assurance that any merger and acquisition will occur, as a result of PDC’s proposed repurchase offers to the 2003 and 2002-D Partnerships, or any potential proposed repurchase offer to any other of PDC’s various public limited partnerships, including this Partnership, should they occur.

Well Refracturing 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 “Well Refracturing Plan”). The Well Refracturing Plan consists of the Partnership’s refracturing of wells currently producing in the Codell formation. Under the Well Refracturing Plan, the Partnership plans to initiate refracturing activities during 2013. Refracturing, or “refracking,” activities consist of a second hydraulic fracturing treatment in a current production zone, all within an existing well bore.

Refracturing 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 refracturing 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 the individual wells and to determine the timing of any refracturing activity. The timing of the refracturing can be affected by the desire to optimize the economic return by refracturing 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 have been at modeled economics; however, all refracturings have not been economically successful and similar future refracturing activities may not be economically successful. If the refracturing work is performed, PDC will charge the Partnership for the direct costs of refracturing, and the Investor Partners and the Managing General Partner will each pay their proportionate share of costs based on the ownership sharing ratios of the Partnership from funds retained by the Managing General Partner from cash available for distributions. The Managing General Partner considers the cash available for distributions to be the Partnership’s net cash flows provided by operating activities less any net cash used in capital activities.

During the fourth quarter 2010, the Managing General Partner began a program for its affiliated partnerships to begin accumulating cash from cash flows from operating activities to pay for future refracturing 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 are between $175,000 and $240,000 per activity. As of March 31, 2011, this Partnership had scheduled to complete seven refracturing opportunities. Total withholding for these activities from the Partnership’s cash available for distributions is estimated to be between $1.2 million and $1.7 million. The Managing General Partner will continually evaluate the timing of commencing these refracturing 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 August 31, 2011, no funds have been withheld from the Partnership distributions pursuant to the Well Refracturing Plan.

If any or all of the Partnership’s Wattenberg wells are not refractured, the Partnership will experience a reduction in proved reserves currently assigned to these wells. Both the number and timing of the refracturing activities will be based on the availability of cash withheld from Partnership distributions. The Managing General Partner believes that, based on projected refracturing costs and projected cash withholding, all scheduled Partnership refracturing activity will be completed within a five year period. Any funds not used for refracturing or other operational needs will be distributed to the Managing General Partner and Investor Partners based on their proportional ownership interest.

 
- 13 -

PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

Implementation of the Well Refracturing Plan will reduce or eliminate Partnership distributions to the Managing General Partner and Investor Partners while the work is being conducted and paid for through the Partnership funds. Depending upon the level of withholding and the results of operations, it is possible that the Managing General Partner and Investor Partners could have taxable income from the Partnership without any corresponding distributions in future years. Non-affiliated investor partners are urged to consult a tax advisor to determine all of the relevant federal, state and local tax consequences of the Well Refracturing 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 Well Refracturing Plan.

Partnership Operating Results Overview

Natural gas, NGLs and crude oil sales decreased 28% or approximately $61,000 for the first three months of 2011 compared to the first three months of 2010, while sales volumes declined 20% period-to-period. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.20 for the current year period compared to $5.82 for the same period a year ago. Realized derivative gains from natural gas and crude oil sales contributed an additional $0.23 per Mcfe or approximately $7,000 to the first three months of 2011 total revenues compared to an additional $1.76 or approximately $65,000 to the first three months of 2010. Comparatively, the total realized price per Mcfe, consisting of the average sales price and realized derivative gains, decreased to $5.43 for the current year three months from $7.58 for the same prior year period.

 
- 14 -

PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

Results of Operations

Summary Operating Results

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

   
Three months ended March 31,
  
   
2011
    
2010
    
Change
  
Number of producing wells (end of period)
     14       14       -  
                         
Production(1)
                        
Natural gas (Mcf)
     23,473       29,296       -20 %
NGLs (Bbl)
     364       414       -12 %
Crude oil (Bbl)
     665       865       -23 %
Natural gas equivalents (Mcfe)(2)
     29,647       36,970       -20 %
Average Mcfe per day
     329       411       -20 %
                         
Natural Gas, NGLs and Crude Oil Sales
                        
Natural gas
   $ 77,886     $ 134,928       -42 %
NGLs
     18,956       18,886       *  
Crude oil
     57,349       61,263       -6 %
Total natural gas, NGLs and crude oil sales
   $ 154,191     $ 215,077       -28 %
                         
Realized Gain (Loss) on Derivatives, net
                        
Natural gas
   $ 13,704     $ 56,270       -76 %
Crude oil
     (6,879 )     8,781       -178 %
Total realized gain on derivatives, net
   $ 6,825     $ 65,051       -90 %
                         
Average Selling Price (excluding realized gain (loss) on derivatives)
                        
Natural gas (per Mcf)(3)
   $ 3.32     $ 4.61       -28 %
NGLs (per Bbl)
     52.08       45.62       14 %
Crude oil (per Bbl)
     86.24       70.82       22 %
Natural gas equivalents (per Mcfe)
     5.20       5.82       -11 %
                         
Average Selling Price (including realized gain (loss) on derivatives)
                        
Natural gas (per Mcf)
   $ 3.90     $ 6.53       -40 %
NGLs (per Bbl)
     52.08       45.62       14 %
Crude oil (per Bbl)
     75.89       80.98       -6 %
Natural gas equivalents (per Mcfe)
     5.43       7.58       -28 %
                         
Average cost per Mcfe
                        
Natural gas, NGLs and crude oil production cost(4)
   $ 1.87     $ 2.26       -17 %
Depreciation, depletion and amortization
     3.06       3.79       -19 %
                         
Operating costs and expenses:
                        
Direct costs - general and administrative
   $ 8,464     $ 1,822       *  
Depreciation, depletion and amortization
     90,658       139,951       -35 %
                         
Cash distributions
   $ 7,678     $ 179,764       -96 %

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

 
- 15 -

PDC 2002-B 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

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

For the three months ended March 31, 2011 compared to the same period in 2010, natural gas, NGLs and crude oil sales volume decreased 20% on an energy equivalency-basis due to normal production declines.

The approximately $61,000, or 28%, decrease in sales for the 2011 three month period as compared to the prior year period was primarily a reflection of a sales volume decrease of 20% and a decrease in sales prices of 11%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.20 for the current year three month period compared to $5.82 for the same period a year ago.

Natural gas and crude oil revenues decreased by 42% and 6%, respectively, and were partially offset by a slight increase in NGLs revenues. The Partnership’s natural gas revenue decrease resulted from decreased commodity prices per Mcf, of 28%, and decreases in natural gas production volumes of 20%. The increase in NGLs revenue was due to increased commodity prices per Bbl, of 14%, partially offset by a decrease of 12% in NGLs production volumes. The crude oil revenue decrease is due primarily to sales volume decreases of 23% partially offset by the rise in commodity prices per Bbl, of 22%, during the current three month period.

Commodity Price Risk Management, Net

The Partnership uses various derivative instruments to manage fluctuations in natural gas and crude oil prices. The Partnership has in place a variety of 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 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.

 
- 16 -

PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

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

   
Three months ended March 31,
  
Commodity price risk management gain (loss), net
  
2011
    
2010
  
Realized gains (losses)
            
Natural gas
   $ 13,704     $ 56,270  
Crude oil
     (6,879 )     8,781  
Total realized gains, net
     6,825       65,051  
                 
Unrealized gains (losses)
                
Reclassification of realized gains included in prior periods unrealized
     (5,426 )     (60,184 )
Unrealized gains (losses) for the period
     (19,283 )     156,615  
Total unrealized gains (losses), net
     (24,709 )     96,431  
Total commodity price risk management gain (loss), net
   $ (17,884 )   $ 161,482  

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

Realized gains recognized in the three months ended March 31, 2011 are primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of the Partnership’s natural gas derivative positions. Realized gains on natural gas settlements were approximately $26,000 for the three months ended March 31, 2011. These gains were offset in part by an approximate $12,000 loss on the Partnership’s Colorado Interstate Gas (“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 $7,000 loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price. Unrealized losses during the three months ended March 31, 2011 are primarily related to the shifts in the forward curves and their impact on the fair value of the Partnership’s open positions. The significant shift upward in the crude oil curve resulted in an unrealized loss of approximately $12,000 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 $7,000.

During the three months ended March 31, 2010, the Partnership recorded realized gains of approximately $65,000 as a result of natural gas and crude oil spot prices being lower at settlement compared to the respective strike price. During the three months ended March 31, 2010, the Partnership recorded unrealized gains of approximately $156,000, of which approximately $188,000 was related to the Partnership’s natural gas and crude oil positions, partially offset by unrealized losses on the Partnership’s CIG basis protection swaps of approximately $32,000 as the forward basis differential between NYMEX and CIG had continued to narrow.

 
- 17 -

PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

The following table presents the Partnership’s derivative positions in effect as of March 31, 2011.

   
Collars
    
Fixed-Price Swaps
    
CIG Basis Protection Swaps
        
         
Weighted Average
    
Quantity
    
Weighted Average
          
Weighted Average
    
Fair Value at
  
Commodity/
  
Quantity
    
Contract Price
    
(Gas-MMbtu(1)
    
Contract
    
Quantity
    
Contract
    
March 31,
  
Index
  
(Gas-MMbtu(1))
    
Floors
    
Ceilings
    
Oil-Bbls)
    
Price
    
(Gas-MMbtu(1))
    
Price
    
2011(2)
  
                                                 
Natural Gas
                                                
NYMEX
                                                
04/01 - 06/30/2011
     -     $ -     $ -       15,411     $ 6.78       15,411     $ (1.88 )   $ 14,954  
07/01 - 09/30/2011
     -       -       -       15,193       6.73       15,193       (1.88 )     11,142  
10/01 - 12/31/2011
     -       -       -       14,786       6.78       14,786       (1.88 )     8,025  
01/01 - 03/31/2012
     989       6.00       8.27       13,291       6.98       14,280       (1.88 )     4,600  
04/01 - 12/31/2012
     2,026       6.00       8.27       39,286       6.98       41,312       (1.88 )     20,217  
2013
     -       -       -       50,617       7.12       50,617       (1.88 )     14,392  
Total Natural Gas
     3,015                       148,584               151,599               73,330  
                                                                 
Crude Oil
                                                                
NYMEX
                                                                
04/01 - 06/30/2011
     -       -       -       303       70.75       -       -       (10,733 )
07/01 - 09/30/2011
     -       -       -       310       70.75       -       -       (11,211 )
10/01 - 12/31/2011
     -       -       -       316       70.75       -       -       (11,418 )
Total Crude Oil
     -                       929               -               (33,362 )
                                                                 
Total Natural Gas and Crude Oil
                                             $ 39,968  

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

Production and operating costs per Mcfe declined to $1.87 during the current period compared to $2.26 for the prior year period due to a decrease in water hauling charges in 2011 compared to 2010.

Direct Costs−General and Administrative

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

Direct costs – general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer’s reserve reports and legal matters. Direct costs increased during the three months ended March 31, 2011, compared to the same period in 2010, by approximately $7,000 principally due to increased fees for professional services.

 
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PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

Depreciation, Depletion and Amortization

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

The DD&A expense rate per Mcfe decreased to $3.06 for the 2011 three month period, compared to $3.79 during the same period in 2010. The decrease in the per Mcfe rates for the 2011 period compared to the 2010 period is due to the effect of the upward revision in the Partnership’s proved developed producing natural gas, NGLs and crude oil reserves particularly in the Wattenberg Field as of December 31, 2010. The production declines, noted in previous sections, also contributed to the decreased DD&A expense of approximately $49,000 for the 2011 three month period compared to the same period in 2010.

Financial Condition, Liquidity and Capital Resources

The Partnership’s primary sources of cash for the three months ended March 31, 2011 were from funds provided by operating activities which include the sale of natural gas, NGLs and crude oil production and the realized gains from the Partnership’s derivative positions. These sources of cash were primarily used to fund the Partnership’s operating costs, general and administrative activities and provided monthly distributions to the Investor Partners and PDC, the Managing General Partner. Additionally, the Partnership’s operating cash flows were reduced by approximately $99,000 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 Well Refracturing Plan, was taken into consideration when assessing the Partnership’s ability to complete this plan. When this balance is repaid, any future withholdings would provide the funding for planned Wattenberg Field well refracturing costs to be incurred beginning in 2013. For additional information, see Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments- Well Refracturing 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 March 31, 2011, the Partnership had natural gas and crude oil derivative positions in place covering 62% of the expected natural gas production and 44% of expected crude oil production for the remainder of 2011, at an average price of $4.88 per Mcf and $70.75 per Bbl, respectively. The Partnership’s current derivative position average prices have declined from the significantly higher average commodity contract strike price levels in effect during the 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 refracturing activities which are more fully described in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments−Well Refracturing Plan.

 
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PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

Working Capital

The Partnership had working capital of approximately $52,000 at March 31, 2011 compared to a working capital deficit of approximately $22,000 at December 31, 2010. The following offsetting changes resulted in an increase of approximately $74,000 to the working capital:

 
·
Realized and unrealized derivative gains receivable decreased by approximately $25,000 between March 31, 2011 and December 31, 2010.
 
·
Due to Managing General Partner-other, net decreased by approximately $99,000 between March 31, 2011 and December 31, 2010.

Working capital is expected to fluctuate by increasing during periods of Well Refracturing Plan funding and by decreasing during periods when payments are made for refracturing.

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 $0.28 and $0.16 for the three months ended March 31, 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.

 
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PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

Net cash provided by operating activities was approximately $8,000 for the three months ended March 31, 2011, compared to approximately $180,000 for the comparable period in 2010. The approximate $172,000 decrease in cash provided by operating activities was due primarily to the following:

 
·
A decrease in natural gas, NGLs and crude oil sales receipts of approximately $37,000 or 19%,

 
·
A decrease in commodity price risk management realized gains receipts of approximately $54,000 or 74%, and

 
·
An increase in production costs and direct costs – general and administrative payments of approximately $81,000.

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 were not significant for the three months ended March 31, 2011 and 2010, respectively.

Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in March 2003 and has distributed $9.5 million through March 31, 2011. The table below presents cash distributions to the Partnership’s investors. Managing General Partner distributions include amounts distributed to PDC for its Managing General Partner’s 20% ownership share in the Partnership. Investor Partner distributions include amounts distributed to Investor Partners for their 80% ownership share in the Partnership and include amounts distributed to PDC for limited partnership units repurchased.

Quarter
ended
March 31,
  
Managing
General Partner
Distributions
    
Investor
Partners
Distributions
    
Total
Distributions
  
                   
2011
   $ 637     $ 7,041     $ 7,678  
                         
2010
   $ 19,140     $ 160,624     $ 179,764  

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 November 2009, 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 $899 and $16,812 for the three month periods ended March 31, 2011 and 2010, respectively, 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 oil operations, the Managing General Partner believes performance obligation allocation rate modifications are likely to continue until February 2013, when the provision expires under the terms of the Agreement.

Off-Balance Sheet Arrangements

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

 
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PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)

Commitments and Contingencies

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

Recent Accounting Standards

See Note 2, Recent Accounting Standards, to the accompanying unaudited condensed financial statements, included in this report.

Critical Accounting Policies and Estimates

The preparation of the accompanying unaudited condensed financial statements in conformity with U.S. GAAP requires management to use judgment in making estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities and the reported amounts of revenue and expenses.

There have been no significant changes to the Partnership’s critical accounting policies and estimates or in the underlying accounting assumptions and estimates used in these critical accounting policies from those disclosed in the financial statements and accompanying notes contained in the Partnership’s 2010 Form 10-K.

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, 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 March 31, 2011.

(b)
Changes in Internal Control over Financial Reporting

During the three months ended March 31, 2011, PDC, the Managing General Partner, made no changes in the Partnership’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect the Partnership’s internal control over financial reporting.

 
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PDC 2002-B 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, 2011.

Period
  
Total Number of
Units Repurchased
    
Average Price
Paid per
Unit
  
             
January 2011
     0.25     $ 3,400  
February 2011
     1.20       2,596  
March 2011
     -       -  
Total first quarter Unit Repurchase Program repurchases
     1.45          

Item 3.
Defaults Upon Senior Securities

Not applicable.

Item 4.
[Removed and Reserved]
 
 
Item 5.
Other Information

Not applicable.

 
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PDC 2002-B 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
                         
 
Certification by Chief Executive Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership, pursuant to Rule 13a-14(a)/15d-14(c) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
                  
X
                         
 
Certification by Chief Financial Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership, pursuant to Rule 13a-14(a)/15d-14(c) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
                  
X
                         
 
Certifications by Chief Executive Officer and Chief Financial Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership, pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
                  
X

 
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PDC 2002-B 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-B 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)

September 21, 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
  
September 21, 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
  
September 21, 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
  
September 21, 2011
R. Scott Meyers
  
Petroleum Development Corporation (dba PDC Energy)
    
   
Managing General Partner of the Registrant
    
   
(Principal accounting officer)
    
 
 
- 25 -

PDC 2002 B LTD PARTNERSHIP Reports