PDC 2002 B LTD PARTNERSHIP - FORM 10-Q - August 13, 2012

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EX-31.1 - CERTIFICATION BY CEO PURSUANT TO SECTION 302 OF SARAANES-OXLEY ACT OF 2002 - PDC 2002 B LTD PARTNERSHIPa2002b-ex311_20120630.htm
EX-32.1 - CERTIFICATIONS BY CEO AND CFO PURSUANT TO SECTION 906 OF SARBANES-OXLEY ACT OF 2002 - PDC 2002 B LTD PARTNERSHIPa2002b-ex321_20120630.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-Q

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

For the quarterly period ended June 30, 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  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)
 
Registrant's telephone number, including area code: (303) 860-5800

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
 
 
(Do not check if a smaller reporting company)
 
 

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

As of June 30, 2012 the Partnership had 559.02 units of limited partnership interest and no units of additional general partnership interest outstanding.


PDC 2002-B Limited Partnership


TABLE OF CONTENTS





SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly 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 (the "Partnership" or the "Registrant") business, financial condition and results of operations. PDC Energy, Inc. (“PDC”) 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 relate to, among other things: estimated natural gas, natural gas liquids (“NGLs”) and crude oil production and reserves; additional development plans; the PDC-Sponsored Drilling Program Acquisition Plan discussed in Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Recent Developments"; 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 future 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, including economic conditions that might impact demand;
•
volatility of commodity prices for natural gas, NGLs and crude oil;
•
the impact of governmental policies 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;
•
potential declines in the value of the Partnership's natural gas and crude oil properties resulting in impairments;
•
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;
•
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;
•
the timing and receipt of necessary regulatory permits;
•
risks incidental to the additional development and operation of natural gas and crude oil wells;
•
the Partnership's future cash flows, liquidity and financial position;
•
competition in the oil and gas industry;
•
the availability of sufficient pipeline and other transportation facilities to carry Partnership production and the impact of these facilities on the price the Partnership received for its production;
•
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 impact of environmental events, governmental responses to the events and the Managing General Partner's ability to insure adequately against such events;
•
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 Quarterly Report on Form 10-Q, 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 and prospects, 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

PDC 2002-B Limited Partnership
Condensed Balance Sheets
(unaudited)

 
June 30, 2012
 
December 31, 2011*
Assets
 
 
 

Current assets:
 
 
 

Cash and cash equivalents
$
10,199

 
$
10,261

Accounts receivable
44,785

 
39,117

Crude oil inventory
19,791

 
11,174

Due from Managing General Partner-derivatives
198,935

 
201,175

Total current assets
273,710

 
261,727

 
 
 
 
Natural gas and crude oil properties, successful efforts method, at cost
7,777,402

 
7,774,445

Less: Accumulated depreciation, depletion and amortization
(5,701,559
)
 
(5,592,847
)
Natural gas and crude oil properties, net
2,075,843

 
2,181,598

Due from Managing General Partner-derivatives
84,369

 
157,086

Other assets
46,035

 
42,200

 
 
 
 
Total Assets
$
2,479,957

 
$
2,642,611

 
 
 
 
Liabilities and Partners' Equity
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
4,773

 
$
4,951

Due to Managing General Partner-derivatives
85,387

 
87,900

Due to Managing General Partner-other, net
58,735

 
98,359

Total current liabilities
148,895

 
191,210

Due to Managing General Partner-derivatives
39,128

 
77,860

Asset retirement obligations
215,917

 
208,823

Total liabilities
403,940

 
477,893

 
 
 
 
Commitments and contingent liabilities


 


 
 
 
 
Partners' equity:
 
 
 
   Managing General Partner
484,441

 
500,410

   Limited Partners - 559.02 units issued and outstanding
1,591,576

 
1,664,308

Total Partners' equity
2,076,017

 
2,164,718

Total Liabilities and Partners' Equity
$
2,479,957

 
$
2,642,611

    *Derived from audited 2011 balance sheet

See accompanying notes to unaudited condensed financial statements.

-2-

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

 
Three months ended June 30,
 
Six months ended June 30,
 
2012
 
2011
 
2012
 
2011
Revenues:
 
 
 
 
 
 
 
Natural gas, NGLs and crude oil sales
$
102,688

 
$
175,345

 
$
203,856

 
$
329,536

Commodity price risk management gain (loss), net
(16,833
)
 
32,839

 
44,291

 
14,955

Total revenues
85,855

 
208,184

 
248,147

 
344,491

Operating costs and expenses:
 
 
 
 
 
 
 
Natural gas, NGLs and crude oil production costs
30,414

 
72,872

 
143,291

 
128,329

Direct costs - general and administrative
31,038

 
159,325

 
59,896

 
167,789

Depreciation, depletion and amortization
49,704

 
87,780

 
108,712

 
178,438

Accretion of asset retirement obligations
3,578

 
2,349

 
7,094

 
4,663

Total operating costs and expenses
114,734

 
322,326

 
318,993

 
479,219

Loss from operations
(28,879
)
 
(114,142
)
 
(70,846
)
 
(134,728
)
Interest income
5

 
4

 
10

 
8

Net loss
$
(28,874
)
 
$
(114,138
)
 
$
(70,836
)
 
$
(134,720
)
 
 
 
 
 
 
 
 
Net loss allocated to partners
$
(28,874
)
 
$
(114,138
)
 
$
(70,836
)
 
$
(134,720
)
Less: Managing General Partner interest in net loss
(5,775
)
 
(22,828
)
 
(14,167
)
 
(26,944
)
Net loss allocated to Investor Partners
$
(23,099
)
 
$
(91,310
)
 
$
(56,669
)
 
$
(107,776
)
 
 
 
 
 
 
 
 
Net loss per Investor Partner unit
$
(41
)
 
$
(163
)
 
$
(101
)
 
$
(193
)
 
 
 
 
 
 
 
 
Investor Partner units outstanding
559.02

 
559.02

 
559.02

 
559.02

















See accompanying notes to unaudited condensed financial statements.

-3-

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

 
Six months ended June 30,
 
2012
 
2011
Cash flows from operating activities:
 
 
 
Net loss
$
(70,836
)
 
$
(134,720
)
Adjustments to net loss to reconcile to net cash
   from operating activities:
 
 
 
Depreciation, depletion and amortization
108,712

 
178,438

Accretion of asset retirement obligations
7,094

 
4,663

Unrealized (gain) loss on derivative transactions
33,712

 
(3,504
)
Changes in assets and liabilities:
 
 
 
Accounts receivable
(5,668
)
 
(15,728
)
Crude oil inventory
(8,617
)
 
1,774

Other assets
(3,835
)
 
(3,836
)
Accounts payable and accrued expenses
(178
)
 
(542
)
Due to Managing General Partner-other, net
(39,624
)
 
16,406

Net cash from operating activities
20,760

 
42,951

Cash flows from investing activities:
 
 
 
Capital expenditures for natural gas and crude oil properties
(2,957
)
 
(15,495
)
Net cash from investing activities
(2,957
)
 
(15,495
)
Cash flows from financing activities:
 
 
 
Distributions to Partners
(17,865
)
 
(27,449
)
Net cash from financing activities
(17,865
)
 
(27,449
)
 
 
 
 
Net change in cash and cash equivalents
(62
)
 
7

Cash and cash equivalents, beginning of period
10,261

 
10,281

Cash and cash equivalents, end of period
$
10,199

 
$
10,288

 
 
 
 





See accompanying notes to unaudited condensed financial statements.

-4-
PDC 2002-B LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2012
(unaudited)


Note 1−General and Basis of Presentation

PDC 2002-B 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 PDC Energy, Inc. (“PDC”) 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, 2012, there were 508 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 June 30, 2012, the Managing General Partner had repurchased 34.1 units of Partnership interests from the Investor Partners at an average price of $4,296 per unit. As of June 30, 2012, the Managing General Partner owned 24.88% of the Partnership.

Beginning in November 2009, when the Investor Partners' 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 $1,771 and $2,915 for the six months ended June 30, 2012 and 2011, respectively, as a result of the Preferred Cash Distribution made under the terms in Section 4.02. The Managing General Partner's obligation under Section 4.02 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 included in the 2011 Form 10-K.

In the Managing General Partner's opinion, the accompanying unaudited condensed financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary for a fair presentation of the Partnership's results 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 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 Quarterly Report on Form 10-Q. The results of operations and cash flows for the three and six months ended June 30, 2012 are not necessarily indicative of the results to be expected for the full year or any other future period.
 
Note 2−Recent Accounting Standards

Recently Adopted Accounting Standards

Fair Value Measurement

On May 12, 2011, the Financial Accounting Standards Board ("FASB") issued changes related to fair value measurement. The changes represent the converged guidance of the FASB and the International Accounting Standards Board on fair value measurement. Many of the changes eliminate unnecessary wording differences between International Financial Reporting Standards and U.S. GAAP. The changes expand existing disclosure requirements for fair value measurements categorized in Level 3 by requiring a quantitative disclosure of the unobservable inputs and assumptions used in the measurement, a description of the valuation processes in place and 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 were effective for public entities during interim and annual periods beginning after December 15, 2011. Adoption of these changes did not have a significant impact on the Partnership's financial statements.

-5-
PDC 2002-B LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2012
(unaudited)


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 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:

    
 
June 30, 2012
 
December 31, 2011
Natural gas, NGLs and crude oil sales revenues
collected from the Partnership's third-party customers
$
25,769

 
$
57,606

Commodity price risk management, realized gain
28,709

 
9,620

Other (1)
(113,213
)
 
(165,585
)
Total Due to Managing General Partner-other, net
$
(58,735
)
 
$
(98,359
)

(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.

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 and six months ended June 30, 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 June 30,
 
Six months ended June 30,
 
2012
 
2011
 
2012
 
2011
 Well operations and maintenance
$
26,709

 
$
60,006

 
$
130,388

 
$
102,711

 Gathering, compression and processing fees
6,099

 
5,088

 
10,670

 
10,752

 Direct costs - general and administrative
31,038

 
159,325

 
59,896

 
167,789

 Cash distributions (1) (2)
1,315

 
2,963

 
2,766

 
3,994


(1)
Cash distributions include $463 and $964 during the three and six months ended June 30, 2012, respectively, and $1,025 and $1,419 during the three and six months ended June 30, 2011, respectively, related to equity cash distributions for Investor Partner units repurchased by PDC.
(2)
Cash distributions to the Managing General Partner were reduced by $842 and $1,771 during the three and six months ended June 30, 2012, respectively, and $2,016 and $2,915 for the three and six months ended June 30, 2011, respectively, due to Preferred Cash Distributions made by the Managing General Partner to Investor Partners under the Performance Standard Obligation provision of the Agreement. For more information concerning this obligation, see Note 1, General and Basis of Presentation.

-6-
PDC 2002-B LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2012
(unaudited)



Note 4−Fair Value Measurements and Disclosures

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) for identical assets or liabilities in active markets.

Level 2 - Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and 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.

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.

The Managing General Partner validates its fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and 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 lenders in the Managing General Partner's corporate credit facility, 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 potential impact of nonperformance of its counterparties on the fair value of the Partnership's derivative instruments was not significant.
 

-7-
PDC 2002-B LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2012
(unaudited)


The Partnership's fixed-price swaps and basis swaps are included in Level 2 and its natural gas collars are included in Level 3. The following table presents, for each applicable level within the fair value hierarchy, the Partnership's derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis:
 
Balance Sheet
 
June 30, 2012
 
December 31, 2011
 
Line Item
 
 Level 2
 
 Level 3
 
 Total
 
 Level 2
 
 Level 3
 
 Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
Current
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity based derivatives
Due from Managing General Partner-derivatives
 
$
194,418

 
$
4,517

 
$
198,935

 
$
192,906

 
$
8,269

 
$
201,175

Non-Current
 
 
 
 
 
 
 
 
 
 
 
 
 
 Commodity based derivatives
Due from Managing General Partner-derivatives
 
84,369

 
—

 
84,369

 
157,086

 
—

 
157,086

 Total assets
 
 
278,787

 
4,517

 
283,304

 
349,992

 
8,269

 
358,261

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
Current
 
 
 
 
 
 
 
 
 
 
 
 
 
Basis protection derivative contracts
Due to Managing General Partner-derivatives
 
85,387

 
—

 
85,387

 
87,900

 
—

 
87,900

Non-Current
 
 
 
 
 
 
 
 
 
 
 
 
 
Basis protection derivative contracts
Due to Managing General Partner-derivatives
 
39,128

 
—

 
39,128

 
77,860

 
—

 
77,860

 Total liabilities
 
 
124,515

 
—

 
124,515

 
165,760

 
—

 
165,760

 Net asset (1)
 
 
$
154,272

 
$
4,517

 
$
158,789

 
$
184,232

 
$
8,269

 
$
192,501

(1)As of June 30, 2012 and December 31, 2011, none of the Partnership's derivative instruments were designated as hedges.

The following table presents a reconciliation of the Partnership's Level 3 fair value measurements:
 
Six months ended
 
June 30, 2012
 
June 30, 2011
 Fair value, net asset, beginning of period
$
8,269

 
$
12,277

 Changes in fair value included in condensed statement of operations line item:
 
 
 
 Commodity price risk management gain (loss), net
1,427

 
1,883

 Settlements
(5,179
)
 
(10,264
)
 Fair value, net asset, end of period
$
4,517

 
$
3,896

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

 
 
June 30, 2012 and 2011, respectively, included in condensed statement of operations line item:
 
 
 
 Commodity price risk management gain (loss), net
$
667

 
$
396

The significant unobservable input used in the fair value measurement of the Partnership's derivative contracts is the implied volatility curve, which 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.


-8-
PDC 2002-B LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2012
(unaudited)

Non-Derivative Financial Assets and Liabilities

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

Note 5−Derivative Financial Instruments

As of June 30, 2012, the Partnership had derivative instruments in place for a portion of its anticipated natural gas production through 2013 totaling 77,928 MMBtu.

The following tables present the impact of the Partnership's derivative instruments on the Partnership's accompanying condensed statements of operations:
 
 
 Three months ended June 30,
 
 
2012
 
2011
Statement of operations line item:
 
Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized
 
Realized and Unrealized 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 (losses)
 
$
44,293

 
$
(678
)
 
$
43,615

 
$
4,221

 
$
405

 
$
4,626

Unrealized gains (losses)
 
(44,293
)
 
(16,155
)
 
(60,448
)
 
(4,221
)
 
32,434

 
28,213

Total
$
—

 
$
(16,833
)
 
$
(16,833
)
 
$
—

 
$
32,839

 
$
32,839

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Six months ended June 30,
 
 
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, net
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains (losses)
 
$
61,477

 
$
16,526

 
$
78,003

 
$
13,542

 
$
(2,091
)
 
$
11,451

Unrealized gains (losses)
 
(61,477
)
 
27,765

 
(33,712
)
 
(13,542
)
 
17,046

 
3,504

Total
$
—

 
$
44,291

 
$
44,291

 
$
—

 
$
14,955

 
$
14,955


Derivative Counterparties. The Managing General Partner's derivative arrangements expose the Partnership to the credit risk of nonperformance by the counterparties. The Managing General Partner primarily uses financial institutions who are also lenders under the Managing General Partner's credit facility 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 potential impact of nonperformance of the Managing General Partner's counterparties on the fair value of the Partnership's derivative instruments was not significant.

-9-
PDC 2002-B LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2012
(unaudited)


Note 6−Commitments and Contingencies

Legal Proceedings

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

Environmental

Due to the nature of the 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. These liabilities are reduced as remediation efforts are completed or are adjusted as a consequence of subsequent periodic reviews. Liabilities for environmental remediation efforts are included in line item captioned “Accounts payable and accrued expenses” on the condensed balance sheet.

In June 2012, as a result of the Managing General Partner's periodic review, the liability for environmental remediation efforts and environmental remediation expense was reduced by approximately $16,000 due to the determination that previously anticipated environmental remediation efforts are no longer required. During the six months ended June 30, 2012, the Partnership's expense for environmental remediation efforts was insignificant. As of June 30, 2012 and December 31, 2011, accrued environmental remediation liabilities were insignificant.

The Managing General Partner is not currently aware of any environmental claims existing as of June 30, 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-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 of Colorado. The Managing General Partner of the Partnership 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 to 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, costs incurred, and availability of PDC or third-party owned pipeline capacity, due to high pressures in the gathering system whether caused by heat or third-party facilities issues, 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 Partners' average annual rate of return being less than 12.8% in November 2009, the Partnership modified the standard ownership-based pro-rata allocation of Partnership cash available for distribution. See Note 1, General and Basis of Presentation, to the unaudited condensed financial statements included in this report and "Financial Condition, Liquidity and Capital Resources - Cash Flows" below for additional information and the effect of this modification on distributions.

Recent Developments

PDC-Sponsored Drilling Program Acquisition Plan

As managing general partner of various public limited partnerships, PDC 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 the Partnership (the “Acquisition Plan”). For additional information regarding the Acquisition Plan, refer to disclosure included in PDC's prior 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 12 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 the 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 the ability to achieve all necessary SEC approvals required to commence a merger and repurchase offer. 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.
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 11 partnership repurchases completed by mergers in 2010 and 2011. The action was filed in United States District Court for the Central District of California, and is titled Schulein v. Petroleum Development Corp. The complaint primarily alleges a claim that the proxy statements issued in connection with the mergers were inadequate, and a state law breach of fiduciary duty. On February 10, 2012, PDC filed a motion to dismiss, or in the alternative, to stay. On June 15, 2012, the Court denied the motion. The Court has approved a litigation schedule including a jury trial in May 2014.  

-11-
PDC 2002-B 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 formations which are 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 10 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 from 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 June 30, 2012, this Partnership had scheduled to complete 18 additional development opportunities. Total withholding for these activities from the Partnership's cash available for distributions is estimated to be between $3.4 million and $3.8 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 June 30, 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 currently projected refracturing and recompletion costs and currently 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 upon their proportional ownership interest.
 
Implementation of the Additional Development Plan will reduce or eliminate Partnership distributions to the Managing General Partner and Investor Partners while the work is being conducted and paid for through the Partnership's funds. Depending upon the level of withholding and the results of operations, it is possible that the Managing General Partner and Investor Partners could have taxable income from the Partnership without any corresponding distributions in future years. Non-affiliated investor partners are urged to consult a tax advisor to determine all of the relevant federal, state and local tax consequences of the Additional 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-B 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 in 2012, sustained low natural gas prices could have a material adverse effect on the Partnership as a result of lower natural gas sales, a reduction in the estimated quantity of the Partnership's proved reserves and a corresponding reduction in 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 38%, or approximately $126,000, for the first six months of 2012 compared to the first six months of 2011, while sales volumes declined 17% period-to-period. The average sales price per Mcfe, excluding the impact of realized derivative gains, was approximately $4.19 for the current year period compared to approximately $5.64 for the same period a year ago. Realized derivative gains from natural gas sales contributed an additional $1.60 per Mcfe, or approximately $78,000, to the total revenues for the first six months of 2012 compared to an additional $0.20, or approximately $11,000, from natural gas and crude oil sales for the first six months of 2011. Comparatively, the total per Mcfe price realized, consisting of the average sales price and realized derivative gains, decreased to $5.79 for the first six months of 2012 from $5.84 for the same period of 2011.

Direct costs - general and administrative decreased by approximately $108,000 during the 2012 six month period due to the timing of fees for professional services.



-13-
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 June 30,
 
Six months ended June 30,
 
2012
 
2011
 
 Change
 
2012
 
2011
 
 Change
Number of gross producing wells (end of period)
14

 
14

 
—

 
14

 
14

 
—

 
 
 
 
 
 
 
 
 
 
 
 
Production(1)
 
 
 
 
 
 
 

 
 
 
 

Natural gas (Mcf)
17,814

 
20,676

 
(14
)%
 
37,382

 
44,149

 
(15
)%
NGLs (Bbl)
111

 
294

 
(62
)%
 
376

 
658

 
(43
)%
Crude oil (Bbl)
934

 
1,054

 
(11
)%
 
1,511

 
1,719

 
(12
)%
Natural gas equivalents (Mcfe)(2)
24,084

 
28,764

 
(16
)%
 
48,704

 
58,411

 
(17
)%
Average Mcfe per day
265

 
316

 
(16
)%
 
268

 
323

 
(17
)%
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas, NGLs and crude oil sales
 
 
 
 
 
 
 

 
 

 
 

Natural gas
$
21,800

 
$
60,846

 
(64
)%
 
$
58,237

 
$
138,732

 
(58
)%
NGLs
5,899

 
15,158

 
(61
)%
 
16,018

 
34,114

 
(53
)%
Crude oil
74,989

 
99,341

 
(25
)%
 
129,601

 
156,690

 
(17
)%
Total natural gas, NGLs and crude oil sales
$
102,688

 
$
175,345

 
(41
)%
 
$
203,856

 
$
329,536

 
(38
)%
 
 
 
 
 
 
 
 
 
 
 
 
Realized gain (loss) on derivatives, net
 
 
 
 
 
 
 

 
 

 
 

Natural gas
$
43,615

 
$
14,252

 
206
 %
 
$
78,003

 
$
27,955

 
179
 %
Crude oil
—

 
(9,626
)
 
(100
)%
 
—

 
(16,504
)
 
(100
)%
Total realized gain on derivatives, net
$
43,615

 
$
4,626

 
*
 
$
78,003

 
$
11,451

 
*

 
 
 
 
 
 
 
 
 
 
 
 
Average selling price (excluding realized gain (loss) on derivatives)
 
 
 
 
 
 
 

 
 

 
 

Natural gas (per Mcf)
$
1.22

 
$
2.94

 
(58
)%
 
$
1.56

 
$
3.14

 
(50
)%
NGLs (per Bbl)
53.14

 
51.56

 
3
 %
 
42.60

 
51.84

 
(18
)%
Crude oil (per Bbl)
80.29

 
94.25

 
(15
)%
 
85.77

 
91.15

 
(6
)%
Natural gas equivalents (per Mcfe)
4.26

 
6.10

 
(30
)%
 
4.19

 
5.64

 
(26
)%
 
 
 
 
 
 
 
 
 
 
 
 
Average selling price (including realized gain (loss) on derivatives)
 
 
 
 
 
 
 

 
 

 
 

Natural gas (per Mcf)
$
3.67

 
$
3.63

 
1
 %
 
$
3.64

 
$
3.78

 
(3
)%
NGLs (per Bbl)
53.14

 
51.56

 
3
 %
 
42.60

 
51.84

 
(18
)%
Crude oil (per Bbl)
80.29

 
85.12

 
(6
)%
 
85.77

 
81.55

 
5
 %
Natural gas equivalents (per Mcfe)
6.07

 
6.26

 
(3
)%
 
5.79

 
5.84

 
(1
)%
 
 
 
 
 
 
 
 
 
 
 
 
Average cost per Mcfe
 
 
 
 
 
 
 
 
 
 
 
Natural gas, NGLs and crude oil production cost(3)(4)
$
1.26

 
$
2.53

 
(50
)%
 
$
2.94

 
$
2.20

 
34
 %
Depreciation, depletion and amortization
2.06

 
3.05

 
(32
)%
 
2.23

 
3.05

 
(27
)%
 
 
 
 
 
 
 
 
 
 
 
 
Operating costs and expenses
 
 
 
 
 
 
 

 
 

 
 

Direct costs - general and administrative
$
31,038

 
$
159,325

 
(81
)%
 
$
59,896

 
$
167,789

 
(64
)%
Depreciation, depletion and amortization
49,704

 
87,780

 
(43
)%
 
108,712

 
178,438

 
(39
)%
 
 
 
 
 
 
 
 
 
 
 
 
Cash distributions
$
8,466

 
$
19,771

 
(57
)%
 
$
17,865

 
$
27,449

 
(35
)%
*Percentage change is not meaningful, equal to or greater than 250% or not calculable.
Amounts may not recalculate due to rounding.

-14-
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) Represents natural gas, NGLs and crude oil operating expenses, including production taxes.
(4) Rate is lower by $0.65 per Mcf for the three months ended June 30, 2012, due to the reversal of previously recorded environmental remediation liabilities of approximately $16,000 in June 2012.

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

Bbl - One barrel of crude oil or 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 prices 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 Colorado Interstate Gas (“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 based on New York Mercantile Exchange ("NYMEX") prices. This negative differential has narrowed over the last few years and is lower than historical variances. The negative differential between NYMEX and CIG averaged $0.19 and $0.31 for the six months ended June 30, 2012 and 2011, respectively.

Six months ended June 30, 2012 as compared to six months ended June 30, 2011

For the six months ended June 30, 2012 compared to the same period of 2011, natural gas, NGLs and crude oil sales volumes, on an energy equivalency-basis, decreased 17% due to normal production declines for this stage in the wells’ production life cycle.
The approximately $126,000, or 38%, decrease in sales for the 2012 six month period as compared to the prior year period was a reflection of sales volume decreases of 17% and a decline in average sales prices of 26%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $4.19 for the current year six month period compared to $5.64 for the same period a year ago.
Natural gas, NGLs and crude oil sales for the six months ended June 30, 2012 decreased by 58%, 53% and 17%, respectively, as compared to the six months ended June 30, 2011. The decrease in natural gas sales resulted from decreased prices per Mcf of 50% and lower natural gas production volumes of 15%. The decrease in NGLs sales was due to a decrease of 43% in NGLs production volumes and to a decrease in the average commodity price per Bbl of 18%. The crude oil sales decrease was due primarily to a sales volume decrease of 12% and a decrease in the average commodity price per Bbl of 6%.

-15-
PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)



Three months ended June 30, 2012 as compared to three months ended June 30, 2011

For the three months ended June 30, 2012 compared to the same period in 2011, natural gas, NGLs and crude oil sales volumes, on an energy equivalency-basis, decreased 16% due to normal production declines for this stage in the wells’ production life cycle.

The approximately $73,000, or 41%, decrease in sales for the 2012 three month period as compared to the prior year period was a reflection of sales volume decreases of 16% and a decline in average sales price of 30%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $4.26 for the current year three month period compared to $6.10 for the same period a year ago.
Natural gas, NGLs and crude oil sales for the three months ended June 30, 2012 decreased by 64%, 61% and 25%, respectively, as compared to the three months ended June 30, 2011. The decrease in natural gas sales resulted from decreased prices per Mcf of 58% and lower natural gas production volumes of 14%. The decrease in NGLs sales was due to a decrease of 62% in NGLs production volumes, partially offset by an increase in the average commodity price per Bbl of 3%. The crude oil sales decrease was due primarily to a sales volume decrease of 11% and a decrease in the average commodity price per Bbl of 15%.

Commodity Price Risk Management

The Partnership used various derivative instruments to manage fluctuations in natural gas and crude oil prices. The Partnership had in place collars, fixed-price swaps and basis swaps on a portion of the Partnership's estimated natural gas and crude oil production. The Partnership sold 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 realized 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 realized the fixed price related to its swaps.

Commodity price risk management 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 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 (loss), net:
 
Three months ended June 30,
 
Six months ended June 30,
 
2012
 
2011
 
2012
 
2011
Commodity price risk management gain (loss), net:
 
 
 
 
 
 
 
  Realized gains (losses)
 
 
 
 
 
 
 
  Natural gas
$
43,615

 
$
14,252

 
$
78,003

 
$
27,955

  Crude oil
—

 
(9,626
)
 
—

 
(16,504
)
       Total realized gains, net
43,615

 
4,626

 
78,003

 
11,451

  Unrealized gains (losses)
 
 
 
 
 
 
 
Reclassification of realized gains included in
 
 
 
 
 
 
 
   prior periods unrealized gains
(44,293
)
 
(4,221
)
 
(61,477
)
 
(13,542
)
Unrealized gains (losses) for the period
(16,155
)
 
32,434

 
27,765

 
17,046

Total unrealized gains (losses), net
(60,448
)
 
28,213

 
(33,712
)
 
3,504

Total commodity price risk management gain (loss), net
$
(16,833
)
 
$
32,839

 
$
44,291

 
$
14,955



-16-
PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)


Six months ended June 30, 2012 as compared to six months ended June 30, 2011

Realized gains of approximately $78,000 recognized in the six months ended June 30, 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 six months ended June 30, 2012, realized gains on natural gas, exclusive of basis swaps, were approximately $126,000. These gains were offset in part by realized losses of approximately $48,000 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 $28,000 for the six months ended June 30, 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 June 30, 2012, unrealized gains on the Partnership's natural gas positions were approximately $32,000, offset by unrealized losses on the Partnership's CIG basis swaps of approximately $4,000.

Realized gains recognized in the six months ended June 30, 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 $64,000 for the six months ended June 30, 2011. These gains were offset in part by an approximate $36,000 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 a loss of approximately $17,000 on its crude oil positions due to higher spot prices at settlement compared to the respective strike price.

Unrealized gains during the six months ended June 30, 2011 were primarily related to the shifts in the forward curves and their impact on the fair value of the Partnership's open positions. The shifts downward in the natural gas curves resulted in an unrealized gain of approximately $31,000 which was partially offset by unrealized losses of approximately $12,000 on the Partnership's CIG basis protection swaps as the forward basis differential between the NYMEX and CIG had continued to narrow. Additionally, the shifts upward in the crude oil curves resulted in an unrealized loss of approximately $2,000.

Three months ended June 30, 2012 as compared to three months ended June 30, 2011

Realized gains of approximately $44,000 recognized in the three months ended June 30, 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 June 30, 2012, realized gains on natural gas, exclusive of basis swaps, were approximately $66,000. These gains were offset in part by realized losses of $22,000 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 losses of approximately $16,000 for the three months ended June 30, 2012 were primarily related to the upward shift in the natural gas forward curve and its impact on the fair value of the Partnership's open positions and by the narrowing of the CIG basis forward curve. For the period ended June 30, 2012, unrealized losses on the Partnership's natural gas positions were approximately $13,000 in addition to unrealized losses on the Partnership's CIG basis swaps of approximately $3,000.

Realized gains recognized in the three months ended June 30, 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 $38,000 for the three months ended June 30, 2011. These gains were offset in part by an approximate $24,000 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 a loss of approximately $9,000 on its crude oil positions due to higher spot prices at settlement compared to the respective strike price.

Unrealized gains during the three months ended June 30, 2011 were primarily related to the shifts in the forward curves and their impact on the fair value of the Partnership's open positions. The shift downward in the crude oil curve resulted in an unrealized gain of approximately $7,000 during the three months ended June 30, 2011. Likewise, the shifts downward in the natural gas and basis curves resulted in a total unrealized gain of approximately $25,000.

-17-
PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)



The following table presents the Partnership's derivative positions in effect as of June 30, 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
June 30, 2012(2)
Floors
 
Ceilings
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural Gas
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NYMEX
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
07/01 - 09/30/2012
715

 
$
6.00

 
$
8.27

 
13,116

 
$
6.98

 
13,831

 
$
(1.88
)
 
$
34,175

10/01 - 12/31/2012
780

 
6.00

 
8.27

 
12,700

 
6.98

 
13,480

 
(1.88
)
 
28,443

01/01 - 03/31/2013
—

 
—

 
—

 
12,899

 
7.12

 
12,899

 
(1.88
)
 
24,906

04/01 - 06/30/2013
—

 
—

 
—

 
12,786

 
7.12

 
12,786

 
(1.88
)
 
26,024

07/01 - 09/30/2013
—

 
—

 
—

 
12,614

 
7.12

 
12,614

 
(1.88
)
 
24,435

10/01 - 12/31/2013
—

 
—

 
—

 
12,318

 
7.12

 
12,318

 
(1.88
)
 
20,806

Total
1,495

 
 
 
 
 
76,433

 
 
 
77,928

 
 
 
$
158,789


(1) A standard unit of measure for natural gas (one MMBtu equals one Mcf).
(2) As of June 30, 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 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.
Six months ended June 30, 2012 as compared to six months ended June 30, 2011
Natural gas, NGLs and crude oil production costs for the six months ended June 30, 2012 increased by approximately $15,000 compared to the same period in 2011. Lease operating costs were higher by approximately $28,000 in the current period as workovers and tubing repair activities were collectively lower in the prior period. Higher lease operating costs were partially offset by lower revenue and volume-based costs by approximately $13,000 in 2012, consistent with sales and production declines from 2011. Natural gas, NGLs and crude oil production costs per Mcfe increased to $2.94 during 2012 from $2.20 in 2011 due to lower volumes and increased costs.

Three months ended June 30, 2012 as compared to three months ended June 30, 2011

Natural gas, NGLs and crude oil production costs for the three months ended June 30, 2012 decreased by approximately $42,000 compared to the same period in 2011. Lease operating costs were lower by approximately $33,000 in the current period as workovers and tubing repair activities were collectively higher in the prior period and the reversal in June 2012 of previously recorded environmental remediation liabilities of approximately $16,000. Additionally, revenue and volume-based costs were lower by approximately $9,000 in 2012, consistent with sales and production declines from 2011. Natural gas, NGLs and crude oil production costs per Mcfe decreased to $1.26 during 2012 from $2.53 in 2011 due to lower volumes and increased costs.


-18-
PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)


Direct Costs-General and Administrative

Six months ended June 30, 2012 as compared to six months ended June 30, 2011
Direct costs-general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineers' reserve reports and legal matters. Direct costs-general and administrative decreased during the six months ended June 30, 2012 compared to the same period in 2011 by approximately $108,000, principally due to the timing of fees for professional services.

Three months ended June 30, 2012 as compared to three months ended June 30, 2011

Direct costs-general and administrative decreased during the three months ended June 30, 2012 compared to the same period in 2011 by approximately $128,000, principally due to the timing of fees for professional services.
 
Depreciation, Depletion and Amortization ("DD&A")

Six months ended June 30, 2012 as compared to six months ended June 30, 2011
The DD&A expense rate per Mcfe decreased to $2.23 for the six months ended June 30, 2012, compared to $3.05 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 decreases in production and DD&A expense rate resulted in an overall decreased DD&A expense of approximately $70,000 for the 2012 six months compared to the same 2011 period.

Three months ended June 30, 2012 as compared to three months ended June 30, 2011

The DD&A expense rate per Mcfe decreased to $2.06 for the three months ended June 30, 2012, compared to $3.05 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 decreases in production and DD&A expense rate resulted in an overall decreased DD&A expense of approximately $38,000 for the 2012 three months compared to the same 2011 period.


Financial Condition, Liquidity and Capital Resources

The Partnership's primary sources of cash for the six months ended June 30, 2012 were 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, direct costs-general and administrative and monthly distributions to the Investor Partners and 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, sales volumes and realized gains and losses from commodity contracts. Commodity prices have historically been volatile and the Managing General Partner attempts to manage this volatility through the use of derivatives. Therefore, the primary source of cash flows from operations becomes the net activity between natural gas, NGLs and crude oil sales and realized natural gas and crude oil derivative gains and losses. The Partnership does not engage in speculative positions, nor does the Partnership hold derivative instruments for 100% of the Partnership's expected future production from producing wells, and therefore may still experience significant fluctuations in cash flows from operations. As of June 30, 2012, the Partnership had natural gas derivative positions in place covering 80% of the expected natural gas production for the remainder of 2012 at an average price of $5.05 per Mcf. 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.


-19-
PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)


The Partnership's future operations are expected to be conducted with available funds and revenues generated from natural gas, NGLs and crude oil production activities and commodity derivatives. Natural gas, NGLs and crude oil production from 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 adverse 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 Recent Developments−Additional Development Plan above.

Working Capital

At June 30, 2012, the Partnership had a working capital surplus of approximately $125,000 compared to a working capital surplus of approximately $71,000 at December 31, 2011. The increase of approximately $54,000 was primarily due to the following changes:

•
accounts receivable decreased by approximately $26,000 between June 30, 2012 and December 31, 2011;
•
realized and unrealized derivative gains receivable increased by approximately $19,000 between June 30, 2012 and December 31, 2011;
•
oil inventory increased by approximately $9,000 between June 30, 2012 and December 31, 2011; and
•
amounts 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 $52,000 between June 30, 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

Operating Activities

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

The Partnership currently uses the "net-back" method of accounting for recording natural gas sales. Under this method, 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 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 sales prices that are below the related pricing indices.

Net cash flows from operating activities were approximately $21,000 for the six months ended June 30, 2012 compared to approximately $43,000 for the comparable period in 2011. The decrease of approximately $22,000 in cash provided by operating activities was due primarily to the following:

•
a decrease in natural gas, NGLs and crude oil sales receipts of approximately $101,000;
•
an increase in commodity price risk management realized gain receipts of approximately $35,000; and
•
a decrease in production costs and direct costs-general and administrative payments of approximately $44,000.

Investing Activities

From time to time, the Partnership 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 six months ended June 30, 2012 and 2011, respectively.


-20-
PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)


Financing Activities

The Partnership initiated monthly cash distributions to investors in March 2003 and has distributed $9.5 million through June 30, 2012. The table below presents cash distributions to the Partnership's investors. Distributions to the Managing General Partner represent amounts distributed to the Managing General Partner for its 20% general partner interest in the Partnership and Investor Partner distributions include amounts distributed to Investor Partners for their 80% ownership share in the Partnership, as well as amounts distributed to the Managing General Partner for limited partnership units repurchased.
Distributions
 
 
 
 
 
 
 
Three months ended June 30,
 
Managing General Partner
 
Investor Partners
 
Total
2012
 
$
852

 
$
7,614

 
$
8,466

2011
 
1,938

 
17,833

 
19,771

 
 
 
 
 
 
 
Six months ended June 30,
 
Managing General Partner
 
Investor Partners
 
Total
2012
 
$
1,802

 
$
16,063

 
$
17,865

2011
 
2,575

 
24,874

 
27,449


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, partially offset by a decrease in capital expenditures for natural gas and crude oil properties.

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 $1,771 and $2,915 for the six months ended June 30, 2012 and 2011, 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 crude 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 June 30, 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, 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.

-21-
PDC 2002-B 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 June 30, 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 June 30, 2012.

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

-22-
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 in 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 June 30, 2012:

Period
 
Total Number of
 Units Repurchased
 
Average Price Paid
 Per Unit
April 1 - 30, 2012
 
—

 
$
—

May 1 - 31, 2012
 
0.25

 
200

June 1 - 30, 2012
 
—

 
—

     Total
 
0.25

 
$
200



Item 3.    Defaults Upon Senior Securities

Not applicable.


Item 4.    Mine Safety Disclosures

Not applicable.


Item 5.    Other Information

None.

-23-
PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)



Item 6. Exhibits

 
 
 
 
Incorporated by Reference
 
 

Exhibit
Number
 
Exhibit Description
 
Form
 

SEC File
Number
 
Exhibit
 
Filing Date
 

Filed
Herewith
 
 
 
 
 
 
 
 
 
 
 
 
 
31.1
 
Certification by Chief Executive Officer of PDC Energy, Inc., 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 PDC Energy, Inc., 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 PDC Energy, Inc., 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.

-24-
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
PDC Energy, Inc.

 
By: /s/ James M. Trimble
 
 
James M. Trimble
President and Chief Executive Officer
of PDC Energy, Inc.
 
 
August 13, 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
August 13, 2012
James M. Trimble
 
PDC Energy, Inc.
Managing General Partner of the Registrant
 
 
 
(principal executive officer)
 
 
 
 
 
/s/ Gysle R. Shellum
 
Chief Financial Officer
August 13, 2012
Gysle R. Shellum
 
PDC Energy, Inc.
Managing General Partner of the Registrant
 
 
 
(principal financial officer)
 
 
 
 
 
/s/ R. Scott Meyers
 
Chief Accounting Officer
August 13, 2012
R. Scott Meyers
 
PDC Energy, Inc.
Managing General Partner of the Registrant
 
 
 
(principal accounting officer)
 
 

-25-

PDC 2002 B LTD PARTNERSHIP Reports