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~~September 30, 2012

£ 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~~September 30, 2012 ~~the~~this 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



PART I – FINANCIAL INFORMATION
		Page
Item 1.	Financial Statements
	Condensed Balance Sheets (unaudited)	2
	Condensed Statements of Operations (unaudited)	3
	Condensed Statements of Cash Flows (unaudited)	4
	Notes to Unaudited Condensed Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	22
Item 4.	Controls and Procedures	22

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	23
Item 1A.	Risk Factors	23
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	23
Item 3.	Defaults Upon Senior Securities	23
Item 4.	Mine Safety Disclosures	23
Item 5.	Other Information	23
Item 6.	Exhibits	24

	SIGNATURES	25

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~~this 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~~this Partnership's risk management objectives; the timing of planned midstream capacity increases in the Wattenberg Field; 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 and other laws, the ~~regulation~~interpretation and enforcement related to those laws and regulations, liabilities arising thereunder and the costs to comply with those laws, asand ~~well as other~~ regulations;

• potential declines in the value of ~~the~~this 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~~this 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~~this Partnership's success in further developing and producing ~~the~~this 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~~this Partnership's future cash flows, liquidity and financial position;

• competition inwithin the oil and gas industry;

• ~~the~~ availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to ~~carry~~process and transport this Partnership's production, particularly in the Wattenberg Field, and the impact of these facilities on the price ~~the~~this Partnership ~~received~~receives for its production;

• ~~the~~ success of the Managing General Partner in marketing ~~the~~this Partnership's natural gas, NGLs and crude oil;

• ~~the~~ effect of ~~natural gas~~ derivative activities;

• ~~the~~ impact of environmental events, governmental and other third-party responses to ~~the~~such 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~~this Partnership urges the reader to carefully review and consider the cautionary statements and disclosures made in this Quarterly Report on Form 10-Q, ~~the~~this Partnership's Annual Report on Form 10-K for the year ended December 31, 2011 (“2011 Form 10-K”) filed with the United States Securities and Exchange Commission (“SEC”) on March 20, 2012 ~~(“2011 Form 10-K”)~~ and ~~the~~this Partnership's other filings with the SEC for further information on risks and uncertainties that could affect ~~the~~this 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~~This 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*
	September 30, 2012			December 31, 2011*
Assets
Current assets:
Cash and cash equivalents	$	10,~~199~~168		$	10,261
Accounts receivable	449,~~785~~247			39,117
Crude oil inventory	1910,~~791~~060			11,174
Due from Managing General Partner-derivatives	~~198~~174,~~935~~870			201,175
Total current assets	~~273~~204,~~710~~345			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~~728,~~559~~222		)	(5,592,847		)
Natural gas and crude oil properties, net	2,~~075~~049,~~843~~180			2,181,598
Due from Managing General Partner-derivatives	8437,~~369~~678			157,086
Other assets	4647,~~035~~953			42,200
Total Assets	$	2,~~479~~339,~~957~~156		$	2,642,611
Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	42,~~773~~110		$	4,951
Due to Managing General Partner-derivatives	8583,~~387~~173			87,900
Due to Managing General Partner-other, net	5846,~~735~~925			98,359
Total current liabilities	~~148~~132,~~895~~208			191,210
Due to Managing General Partner-derivatives	3919,~~128~~597			77,860
Asset retirement obligations	~~215~~219,~~917~~559			208,823
Total liabilities	~~403~~371,~~940~~364			477,893
Commitments and contingent liabilities
Partners' equity:
Managing General Partner	~~484~~463,~~441~~586			500,410
Limited Partners - 559.02 units issued and outstanding	1,~~591~~504,~~576~~206			1,664,308
Total Partners' equity	21,~~076~~967,~~017~~792			2,164,718
Total Liabilities and Partners' Equity	$	2,~~479~~339,~~957~~156		$	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,
	Three months ended September 30,						Nine months ended September 30,
	2012			2011			2012			2011
Revenues:
Natural gas, NGLs and crude oil sales	$	~~102~~47,~~688~~511		$	~~175~~161,~~345~~389		$	~~203~~251,~~856~~367		$	~~329~~490,~~536~~925
Commodity price risk management gain (loss), net	(1614,~~833~~379		)	3257,~~839~~010			4429,~~291~~912			1471,~~955~~965
Total revenues	8533,~~855~~132			~~208~~218,~~184~~399			~~248~~281,~~147~~279			~~344~~562,~~491~~890
Operating costs and expenses:
Natural gas, NGLs and crude oil production costs	3074,~~414~~281			7257,~~872~~046			~~143~~217,~~291~~572			~~128~~185,~~329~~375
Direct costs - general and administrative	3129,~~038~~086			~~159~~97,~~325~~302			5988,~~896~~982			~~167~~265,~~789~~091
Depreciation, depletion and amortization	4926,~~704~~663			8789,~~780~~710			~~108~~135,~~712~~375			~~178~~268,~~438~~148
Accretion of asset retirement obligations	3,~~578~~642			2,~~349~~385			710,~~094~~736			47,~~663~~048
Total operating costs and expenses	~~114~~133,~~734~~672			~~322~~246,~~326~~443			~~318~~452,~~993~~665			~~479~~725,~~219~~662
Loss from operations	(28100,~~879~~540		)	(~~114~~28,~~142~~044		)	(70171,~~846~~386		)	(~~134~~162,~~728~~772		)
Interest income	5			473			1015			881
Net loss	$	(28100,~~874~~535	)	$	(~~114~~27,~~138~~971	)	$	(70171,~~836~~371	)	$	(~~134~~162,~~720~~691	)
Net loss allocated to partners	$	(28100,~~874~~535	)	$	(~~114~~27,~~138~~971	)	$	(70171,~~836~~371	)	$	(~~134~~162,~~720~~691	)
Less: Managing General Partner interest in net loss	(511,~~775~~715		)	(225,~~828~~594		)	(1434,~~167~~274		)	(2632,~~944~~538		)
Net loss allocated to Investor Partners	$	(2388,~~099~~820	)	$	(9122,~~310~~377	)	$	(56137,~~669~~097	)	$	(~~107~~130,~~776~~153	)
Net loss per Investor Partner unit	$	(41159	)	$	(~~163~~40	)	$	(~~101~~245	)	$	(~~193~~233	)
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,
	Nine months ended September 30,
	2012			2011
Cash flows from operating activities:
Net loss	$	(70171,~~836~~371	)	$	(~~134~~162,~~720~~691	)
Adjustments to net loss to reconcile to net cash from operating activities:
Depreciation, depletion and amortization	~~108~~135,~~712~~375			~~178~~268,~~438~~148
Accretion of asset retirement obligations	710,~~094~~736			47,~~663~~048
Unrealized (gain) loss on derivative transactions	3382,~~712~~723			(352,~~504~~129		)
Changes in assets and liabilities:
Accounts receivable	(529,~~668~~870		)	(1519,~~728~~616		)
Crude oil inventory	(81,~~617~~114		)	1(2,~~774~~301		)
Other assets	(35,~~835~~753		)	(35,~~836~~754		)
Accounts payable and accrued expenses	(~~178~~2,841		)	(~~542~~1,426		)
Due to Managing General Partner-other, net	(3951,~~624~~434		)	1624,~~406~~785
Net cash from operating activities	2028,~~760~~419			4256,~~951~~064
Cash flows from investing activities:
Capital expenditures for natural gas and crude oil properties	(2,957		)	(1518,~~495~~177		)
Net cash from investing activities	(2,957		)	(1518,~~495~~177		)
Cash flows from financing activities:
Distributions to Partners	(1725,~~865~~555		)	(2737,~~449~~876		)
Net cash from financing activities	(1725,~~865~~555		)	(2737,~~449~~876		)
Net change in cash and cash equivalents	(6293		)	711
Cash and cash equivalents, beginning of period	10,261			10,281
Cash and cash equivalents, end of period	$	10,~~199~~168		$	10,~~288~~292

See accompanying notes to unaudited condensed financial statements.

-4-

PDC 2002-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~June~~September 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~~this 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~~this 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~~this Partnership and initiates and completes substantially all Partnership transactions.

As of ~~June~~September 30, 2012, there were ~~508~~505 limited partners in ~~the~~this Partnership (“Investor Partners”). PDC is the designated Managing General Partner of ~~the~~this Partnership and owns a 20% Managing General Partner ownership in ~~the~~this Partnership. According to the terms of the Agreement, revenues, costs and cash distributions of ~~the~~this Partnership are allocated 80% to the Investor Partners, which are shared pro rata based upon the number of units in ~~the~~this 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~~September 30, 2012, the Managing General Partner had repurchased 3437.12 units of Partnership interests from the Investor Partners at an average price of $43,~~296~~952 per unit. As of ~~June~~September 30, 2012, the Managing General Partner owned 2425.8833% of ~~the~~this Partnership.

Beginning in November 2009, when the Investor Partners' average annual rate of return fell below 12.8%, ~~the~~this 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 $12,~~771~~561 and $23,~~915~~979 for the ~~six~~nine months ended ~~June~~September 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~~this 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~~this 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~~this Partnership's audited financial statements and notes thereto included in ~~the~~this Partnership's 2011 Form 10-K. ~~The~~This Partnership's accounting policies are described in the Notes to Financial Statements in ~~the~~this 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~~nine months ended ~~June~~September 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~~this Partnership's financial statements.

-5-

PDC 2002-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~June~~September 30, 2012

(unaudited)

Note 3−Transactions with Managing General Partner

The Managing General Partner transacts business on behalf of ~~the~~this Partnership under the authority of the D&O Agreement. Revenues and other cash inflows received by the Managing General Partner on behalf of ~~the~~this Partnership are distributed to the Partners net of corresponding operating costs and other cash outflows incurred on behalf of ~~the~~this Partnership. The fair value of ~~the~~this 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~~this Partnership's investors as of the dates indicated:

	June 30, 2012			December 31, 2011
	September 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
Natural gas, NGLs and crude oil sales revenues collected from this Partnership's third-party customers	$	24,871		$	57,606
Commodity price risk management, realized gain	2822,~~709~~538			9,620
Other (1)	(~~113~~94,~~213~~334		)	(165,585		)
Total Due to Managing General Partner-other, net	$	(5846,~~735~~925	)	$	(98,359	)

(1) All other unsettled transactions, excluding derivative instruments, between ~~the~~this 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~~nine months ended ~~June~~September 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,

Three months ended September 30,

Nine months ended September 30,

2012

2011

2012

2011

Well operations and maintenance

2670,~~709~~130

6045,~~006~~460

~~130~~200,~~388~~518

~~102~~148,~~711~~171

Gathering, compression and processing fees

62,~~099~~900

5,~~088~~103

1013,~~670~~570

1015,~~752~~855

Direct costs - general and administrative

3129,~~038~~086

~~159~~97,~~325~~302

5988,~~896~~982

~~167~~265,~~789~~091

Cash distributions (1) (2)

1,~~315~~210

21,~~963~~570

23,~~766~~976

35,~~994~~564

(1) Cash distributions include $~~463~~462 and $~~964~~1,426 during the three and ~~six~~nine months ended ~~June~~September 30, 2012, respectively, and $~~1,025~~549 and $1,~~419~~968 during the three and ~~six~~nine months ended ~~June~~September 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~~790 and $12,~~771~~561 during the three and ~~six~~nine months ended ~~June~~September 30, 2012, respectively, and $21,~~016~~064 and $23,~~915~~979 for the three and ~~six~~nine months ended ~~June~~September 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~~September 30, 2012

(unaudited)

Note 4−Fair Value Measurements and Disclosures

Determination of fair value. ~~The~~This Partnership's fair value measurements are estimated pursuant to a fair value hierarchy that requires ~~the~~this 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~~this 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~~this Partnership's derivative instruments was not significant.

-7-

PDC 2002-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~June~~September 30, 2012

(unaudited)

~~The~~This 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~~this Partnership's derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis:

	Balance Sheet	~~June~~September 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
Commodity-based derivatives	Due from Managing General Partner-derivatives	$	172,789	$	2,081	$	174,870	$	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
Commodity-based derivatives	Due from Managing General Partner-derivatives	37,678		—		37,678		157,086		—		157,086
Total assets		~~278~~210,~~787~~467		42,~~517~~081		~~283~~212,~~304~~548		349,992		8,269		358,261
Liabilities:
Current
Basis protection derivative contracts	Due to Managing General Partner-derivatives	8583,~~387~~173		—		8583,~~387~~173		87,900		—		87,900
Non-Current
Basis protection derivative contracts	Due to Managing General Partner-derivatives	3919,~~128~~597		—		3919,~~128~~597		77,860		—		77,860
Total liabilities		~~124~~102,~~515~~770		—		~~124~~102,~~515~~770		165,760		—		165,760
Net asset (1)		$	~~154~~107,~~272~~697	$	42,~~517~~081	$	~~158~~109,~~789~~778	$	184,232	$	8,269	$	192,501

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

The following table presents a reconciliation of this Partnership's Level 3 fair value measurements:

	Six months ended
	Nine months ended
	June 30, 2012			June 30, 2011
	September 30, 2012			September 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~~241			13,~~883~~316
Settlements	(57,~~179~~429		)	(10,264		)
Fair value, net asset, end of period	$	42,~~517~~081		$	35,~~896~~329
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:
September 30, 2012 and 2011, respectively, included in condensed statement of operations line item:
Commodity price risk management gain (loss), net	$	~~667~~166		$	~~396~~1,829

The significant unobservable input used in the fair value measurement of ~~the~~this 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~~this Partnership's Level 3 derivative contracts.

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

-8-

PDC 2002-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~June~~September 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~~September 30, 2012, ~~the~~this Partnership had derivative instruments in place for a portion of its anticipated natural gas production through 2013 totaling 7764,~~928~~097 MMBtu.

The following tables present the impact of ~~the~~this Partnership's derivative instruments on ~~the~~this Partnership's accompanying condensed statements of operations:

	Three months ended June 30,
	Three months ended September 30,
	2012									2011
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 (losses)	$	44,293		$	(678	)	$	43,615		$	4,221		$	405		$	4,626
Realized gains	$	34,175		$	457		$	34,632		$	4,814		$	3,571		$	8,385
Unrealized gains (losses)	(4434,~~293~~175		)	(1614,~~155~~836		)	(6049,~~448~~011		)	(4,~~221~~814		)	3253,~~434~~439			2848,~~213~~625
Total	$	—		$	(1614,~~833~~379	)	$	(1614,~~833~~379	)	$	—		$	3257,~~839~~010		$	3257,~~839~~010
	Six months ended June 30,
	Nine months ended September 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
Realized gains	$	89,607		$	23,028		$	112,635		$	18,433		$	1,403		$	19,836
Unrealized gains (losses)	(6189,~~477~~607		)	276,~~765~~884			(3382,~~712~~723		)	(1318,~~542~~433		)	1770,~~046~~562			352,~~504~~129
Total	$	—		$	4429,~~291~~912		$	4429,~~291~~912		$	—		$	1471,~~955~~965		$	1471,~~955~~965

Derivative Counterparties. The Managing General Partner's derivative arrangements expose ~~the~~this 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~~this 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~~this Partnership's derivative instruments was not significant.

-9-

PDC 2002-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~June~~September 30, 2012

(unaudited)

Note 6−Commitments and Contingencies

Legal Proceedings

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

Environmental

Due to the nature of the oil and gas industry, ~~the~~this 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~~this 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.

InDuring ~~June~~the nine months ended September 30, 2012, as a result of the Managing General Partner's periodic review, ~~the~~there ~~liability~~were ~~for~~no ~~environmental~~new ~~remediation efforts and~~ environmental remediation ~~expense was reduced by approximately $16,000 due to the determination that previously anticipated environmental remediation~~ efforts ~~are~~identified noand ~~longer~~this ~~required. During the six months ended June 30, 2012, the~~ Partnership's expense for environmental remediation efforts was insignificant. As of ~~June~~ September 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~~ September 30, 2012 which have not been provided for or would otherwise have a material impact on ~~the~~this 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~~this Partnership's properties.

-10-

Index

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~~This 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~~this Partnership markets ~~the~~this 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~~this Partnership in accordance with the D&O Agreement, is authorized to enter into multi-year fixed price contracts and/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~~this 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~~this 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~~this 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~~this 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~~this Partnership, depends on that partnership's suitability in meeting a set of criteria that includes, but is not limited to, the following: age and productive-life stage characteristics of the partnership's well inventory; favorability of economics for additional development in the Wattenberg Field, including commodity prices; and SEC reporting compliance status and timing and 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 11the 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-

Index

PDC 2002-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Additional Development Plan

The Managing General Partner has prepared a plan for ~~the~~this 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~~this 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~~this 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~~an ~~highest~~attractive rate of return to ~~the~~this Partnership. On average, the production resulting from past PDC's refracturings or recompletions have increased production; however, not all past 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~~this 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~~this 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~~this 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 expected 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~~September 30, 2012, this Partnership ~~had~~has ~~scheduled~~approximately ~~to complete~~ 18 additional development opportunities remaining. Total withholding for these activities from ~~the~~this 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~~the ~~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~~ September 30, 2012, no funds have been withheld from ~~the~~this Partnership's cash distributions pursuant to the Additional Development Plan.

~~Both~~This Partnership, along with other operators in the ~~number~~Wattenberg ~~and~~Field, ~~timing~~is currently experiencing extremely high line pressures due to an oversupply of ~~the~~natural ~~additional~~gas ~~development~~and ~~activities~~natural ~~will~~gas beliquids (NGLs) in the field based onupon the ~~availability~~main ofpipeline/processing ~~cash~~provider's ~~withheld~~current ~~from~~take ~~Partnership~~away ~~distributions~~capacity. The ~~Managing~~result ~~General~~of ~~Partner~~the ~~believes~~high ~~that,~~line ~~based~~pressure onis ~~currently~~that ~~projected~~many ~~refracturing~~of ~~and~~the ~~recompletion~~wells ~~costs~~in ~~and~~this ~~currently~~field, ~~projected~~including ~~cash~~this ~~withholding~~Partnership's wells, ~~all~~have ~~scheduled~~had ~~Partnership~~their ~~additional~~production ~~development~~curtailed ~~activity~~and ~~will~~the becurtailments ~~completed~~have ~~within~~reduced athe ~~five-year~~amount ~~period.~~of ~~Any~~natural ~~funds~~gas, ~~not~~crude ~~used~~oil ~~for~~and ~~refracturing,~~NGLs ~~recompletion~~produced orand ~~other~~sold ~~operational~~over ~~needs~~the ~~will~~last beseveral ~~distributed~~months. When tonatural gas production is curtailed, the ~~Managing~~curtailment ~~General~~affects ~~Partner~~the ~~and~~well's ~~Investor~~ability ~~Partners~~to ~~based~~lift ~~upon~~the ~~their~~liquids ~~proportional~~out ~~ownership~~of ~~interest~~the well bore.

~~Implementation~~DCP, ofan ~~the~~independent ~~Additional~~midstream ~~Development~~company, ~~Plan~~is ~~will reduce or eliminate Partnership distributions to~~ the ~~Managing~~main ~~General~~purchaser ~~Partner~~of ~~and~~natural ~~Investor~~gas ~~Partners while the work is being conducted~~ and ~~paid~~NGLs ~~for~~in ~~through~~this ~~the Partnership's funds~~field. ~~Depending~~The ~~upon the level of withholding and the results of operations, it is possible that the~~ Managing General Partner ~~and~~is ~~Investor~~working ~~Partners~~closely ~~could~~with ~~have~~DCP, ~~taxable~~who ~~income~~is ~~from~~implementing ~~the~~a ~~Partnership without any corresponding distributions in future years. Non~~multi-~~affiliated~~year ~~investor~~facility ~~partners~~expansion ~~are~~capable ~~urged to consult a tax advisor to determine all~~ of ~~the~~significantly ~~relevant~~increasing ~~federal,~~long-term ~~state~~gathering and ~~local~~processing ~~tax~~capacity ~~consequences~~in of the ~~Additional~~Wattenberg ~~Development Plan~~Field. ~~The above discussion is not intended as a substitute for careful tax planning~~ However, ~~and~~the ~~non-affiliated~~Managing ~~investor~~General ~~partners~~Partner ~~should~~does ~~depend~~not ~~upon~~expect the ~~advice~~impact of ~~their~~this ~~own~~increased ~~tax~~capacity ~~advisors~~to ~~concerning~~substantially ~~the~~benefit ~~effects~~this ofPartnership ~~the~~until ~~Additional~~late ~~Development Plan~~2013.

Due to the limitations in the take away capacity and the extended timeline anticipated for the curtailments, the projected rates of return for refracturing and recompletion activities have significantly deteriorated. Therefore, at this time, PDC has temporarily suspended the Additional Development Plan and the withholding of funds designated for this development until the high line pressure situation improves. However, no assurance can be given that the Additional Development Plan will recommence.

-12-

Index

PDC 2002-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Implementation of the Additional Development Plan will in the future reduce or eliminate Partnership distributions to the Managing General Partner and Investor Partners while the work is being conducted and paid for through this 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 this 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 obtain the advice of their own tax advisors concerning the effects of the Additional Development Plan.

Current Low Natural Gas Price Environment

~~The~~While there was a 39% improvement in prices in the current quarter for this Partnership, the natural gas market still continues to be characterized by depressed prices relative to prior years. While ~~the~~this Partnership has derivative instruments in place for a majority of its expected natural gas production in 2012 and 2013, sustained low natural gas prices could have a material adverse effect on ~~the~~this Partnership as a result of lower natural gas sales, a reduction in the estimated quantity of ~~the~~this 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 3849%, or approximately $~~126~~240,000, for the first ~~six~~nine months of 2012 compared to the first ~~six~~nine months of 2011, while sales volumes declined 1724% period-to-period. The average sales price per Mcfe, excluding the impact of realized derivative gains, was ~~approximately~~ $43.1978 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 $1.6069 per Mcfe, or approximately $78113,000, to the total revenues for the first ~~six~~nine months of 2012 compared to an additional $0.2023, or approximately $1120,000, from natural gas and crude oil sales for the first ~~six~~nine months of 2011. Comparatively, the total per Mcfe price realized, consisting of the average sales price and realized derivative gains, decreased to $5.7947 for the first ~~six~~nine months of 2012 from $5.8487 for the same period of 2011.

Direct costs - general and administrative decreased by approximately $~~108~~176,000 during the 2012 ~~six~~nine month period due to the timing of fees for professional services.

-13-

Index

PDC 2002-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Results of Operations

Summary Operating Results

The following table presents selected information regarding ~~the~~this Partnership’s results of operations:

	Three months ended June 30,							Six months ended June 30,
	Three months ended September 30,							Nine months ended September 30,
	2012		2011			Change		2012		2011			Change
Number of gross producing wells (end of period)	14		14			—		14		14			—
Production(1)
Natural gas (Mcf)	1715,~~814~~786		20,~~676~~605			(1423	)%	3753,~~382~~168		4464,~~149~~754			(1518	)%
NGLs (Bbl)	~~111~~131		~~294~~416			(6269	)%	~~376~~507		~~658~~1,074			(4353	)%
Crude oil (Bbl)	~~934~~204		~~1,054~~911			(1178	)%	1,~~511~~715		12,~~719~~630			(1235	)%
Natural gas equivalents (Mcfe)(2)	2417,~~084~~796		28,~~764~~567			(1638	)%	4866,~~704~~500		5886,~~411~~978			(1724	)%
Average Mcfe per day	~~265~~193		~~316~~311			(1638	)%	~~268~~243		~~323~~319			(1724	)%
Natural gas, NGLs and crude oil sales
Natural gas	$	2126,~~800~~627	$	6067,~~846~~941		(6461	)%	$	5884,~~237~~864	$	~~138~~206,~~732~~673		(5859	)%
NGLs	53,~~899~~861		1518,~~158~~045			(6179	)%	1619,~~018~~879		3452,~~114~~159			(5362	)%
Crude oil	7417,~~989~~023		9975,~~341~~403			(2577	)%	~~129~~146,~~601~~624		~~156~~232,~~690~~093			(1737	)%
Total natural gas, NGLs and crude oil sales	$	~~102~~47,~~688~~511	$	~~175~~161,~~345~~389		(4171	)%	$	~~203~~251,~~856~~367	$	~~329~~490,~~536~~925		(3849	)%
Realized gain (loss) on derivatives, net
Natural gas	$	4334,~~615~~632	$	14,~~252~~274		~~206~~143	%	$	78112,~~003~~635	$	2742,~~955~~229		~~179~~167	%
Crude oil	—		(95,~~626~~889		)	(100	)%	—		(1622,~~504~~393		)	(100	)%
Total realized gain on derivatives, net	$	4334,~~615~~632	$	48,~~626~~385		*		$	78112,~~003~~635	$	1119,~~451~~836		*
Average selling price (excluding realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	1.2269	$	23.9430		(5849	)%	$	1.5660	$	3.1419		(50	)%
NGLs (per Bbl)	5329.1447		5143.5638			3(32	)%	4239.6021		5148.8457			(1819	)%
Crude oil (per Bbl)	8083.2945		9482.2577			~~(15~~1	)%	85.7750		9188.1525			(63	)%
Natural gas equivalents (per Mcfe)	42.2667		65.1065			(3053	)%	43.1978		5.64			(2633	)%
Average selling price (including realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	3.6788	$	3.6399		1(3	)%	$	3.6471	$	3.7884		(3	)%
NGLs (per Bbl)	5329.1447		5143.5638			3(32	)%	4239.6021		5148.8457			(1819	)%
Crude oil (per Bbl)	8083.2945		8576.1231			(69	)%	85.7750		8179.5573			57	%
Natural gas equivalents (per Mcfe)	64.0762		65.2694			(322	)%	5.7947		5.8487			(17	)%
Average cost per Mcfe
Natural gas, NGLs and crude oil production cost(3)(4)	$	1.26	$	2.53		(50	)%	$	2.94	$	2.20		34	%
Natural gas, NGLs and crude oil production cost(3)	$	4.17	$	2.00		109	%	$	3.27	$	2.13		54	%
Depreciation, depletion and amortization	21.0650		3.0514			(3252	)%	2.2304		3.0508			(2734	)%
Operating costs and expenses
Direct costs - general and administrative	$	3129,~~038~~086	$	~~159~~97,~~325~~302		(8170	)%	$	5988,~~896~~982	$	~~167~~265,~~789~~091		(6466	)%
Depreciation, depletion and amortization	4926,~~704~~663		8789,~~780~~710			(4370	)%	~~108~~135,~~712~~375		~~178~~268,~~438~~148			(3950	)%
Cash distributions	$	87,~~466~~690	$	1910,~~771~~427		(5726	)%	$	1725,~~865~~555	$	2737,~~449~~876		(3533	)%

*Percentage change is not meaningful, equal to or greater than 250% or not calculable.

Amounts may not recalculate due to rounding.

-14-

Index

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~~this Partnership has an interest by the average percentage of the leasehold or other property interest ~~the~~this 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~~This Partnership's results of operations depend upon many factors, particularly the ~~prices~~price of natural gas, NGLs and crude oil and the Managing General Partner's ability to market ~~the~~this Partnership's production effectively. Natural gas, ~~NGLs~~NGL and crude oil prices are among the most volatile of all commodity prices. These price variations have a material impact on ~~the~~this 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~~Natural ~~price~~gas ~~the~~prices ~~Partnership~~vary ~~receives~~by ~~for~~region ~~its~~and ~~natural~~locality, ~~gas~~depending ~~produced~~upon inthe distance to markets, the ~~Rocky~~availability ~~Mountain~~of ~~Region~~pipeline iscapacity ~~based~~and onthe asupply ~~market~~and ~~basket~~demand ofrelationships ~~prices,~~in ~~which~~that ~~generally~~region ~~includes~~or ~~natural~~locality. ~~gas~~The ~~sold~~combination ~~at,~~of ~~near~~increased ordrilling ~~below~~activity ~~Colorado~~and ~~Interstate~~curtailments ~~Gas~~due ~~(“CIG”)~~to ~~prices,~~limited ascapacity ~~well~~on aslocal ~~other~~gathering ~~nearby~~and ~~region~~processing ~~prices~~infrastructure has resulted in capacity constraints. ~~The~~Like ~~CIG~~most ~~Index~~producers, ~~and~~this ~~other~~Partnership ~~indices~~relies ~~for~~on ~~production~~major ~~delivered~~interstate topipeline ~~other~~companies ~~Rocky~~to ~~Mountain~~construct these pipelines to increase capacity, ~~has~~rendering ~~historically~~the ~~been~~timing ~~less~~and ~~than~~availability ~~the~~of these facilities beyond this Partnership's control. The price ~~received~~this Partnership receives for its natural gas ~~produced~~is inimpacted by the ~~eastern~~Managing ~~regions~~General Partner's transportation, ~~which~~gathering isand ~~based~~processing onagreements. ~~New~~This ~~York~~Partnership ~~Mercantile~~currently ~~Exchange~~uses (the "~~NYMEX~~net-back") ~~prices~~method of accounting for these arrangements related to its natural gas sales. This ~~negative~~Partnership ~~differential~~sells ~~has~~natural ~~narrowed~~gas ~~over~~at the ~~last~~wellhead ~~few~~and ~~years~~collects a price and isrecognizes ~~lower~~revenues ~~than~~based ~~historical~~on ~~variances.~~the ~~The~~wellhead ~~negative~~sales ~~differential~~price ~~between~~since ~~NYMEX~~transportation ~~and~~costs ~~CIG~~downstream ~~averaged~~of ~~$0.19~~the wellhead are incurred by the purchaser and $0reflected in the wellhead price.31 ~~for~~The net-back method results in the ~~six~~recognition ~~months~~of ~~ended~~a ~~June~~sales ~~30,~~price ~~2012~~that ~~and~~is ~~2011,~~below ~~respectively.~~the indices for which the production is based.

~~Six~~The ~~months~~price ~~ended~~this ~~June~~Partnership 30receives for its natural gas produced is based on a market basket of prices, ~~2012~~which generally includes natural gas sold at, near or below Colorado Interstate Gas ("CIG") prices, as ~~compared~~well as other nearby regional prices. The CIG Index, and other indices for production delivered to ~~six~~other Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions of the U.S., 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 $0.22 and $0.30 for the nine months ended ~~June~~September 30, 2012 and 2011, respectively. In September 2012, the Managing General Partner renegotiated its marketing agreement for this Partnership's natural gas in the Piceance Basin. This new marketing agreement is expected to add approximately $0.40 per MMbtu to this Partnership's Piceance natural gas price realization effective November 1, 2012.

~~For~~This ~~the~~Partnership ~~six~~has ~~months~~experienced ~~ended~~a ~~June~~decline 30in the price of NGLs, ~~2012~~mainly ~~compared~~at toConway ~~the~~hub ~~same~~in ~~period~~Kansas ofwhere ~~2011,~~this ~~natural~~Partnership's ~~gas,~~Wattenberg ~~NGLs~~production ~~and~~is ~~crude~~marketed. ~~oil~~This ~~sales~~is ~~volumes,~~primarily ondue anto ~~energy~~the ~~equivalency-basis,~~increase ~~decreased~~in ~~17%~~ethane ~~due~~and propane volumes flowing to ~~normal~~Conway, ~~production~~with ~~declines~~a ~~for~~limited ~~this~~market ~~stage~~for inthese ~~the~~products ~~wells’~~out ~~production~~of ~~life~~the ~~cycle~~area.

~~The~~Crude ~~approximately~~oil ~~$126,000,~~pricing oris ~~38%,~~predominately ~~decrease~~driven inby ~~sales for~~ the ~~2012~~physical ~~six~~market, ~~month~~supply ~~period~~and asdemand, ~~compared to~~ the ~~prior~~financial ~~year~~markets ~~period~~and ~~was~~national ~~a reflection of sales volume decreases of 17%~~ and ainternational ~~decline in average sales prices of 26%~~politics. The ~~average~~majority ~~sales price per Mcfe, excluding the impact~~ of ~~realized~~this ~~derivative~~Partnership's ~~gains,~~crude ~~was~~oil ~~$4.19~~is ~~for~~sold ~~the~~on ~~current~~a calendar-year ~~six~~basis ~~month~~at ~~period~~a ~~compared~~fixed differential to ~~$5.64~~NYMEX ~~for the same period a year ago~~pricing.

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-

Index

PDC 2002-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Three~~Nine months ended ~~June~~September 30, 2012 as compared to ~~three~~nine months ended ~~June~~September 30, 2011

For the ~~three~~nine months ended ~~June~~September 30, 2012 compared to the same period inof 2011, natural gas, NGLs and crude oil sales volumes, on an energy equivalency-basis, decreased 1624% due to normal production declines for this stage in the wells’ production life cycle and a decrease in production precipitated by curtailments due to high line pressure in the Wattenberg Field.

The approximately $73240,000, or 4149%, decrease in sales for the 2012 ~~three~~nine month period as compared to the prior year period was a reflection of sales volume decreases of 1624% and a decline in average sales ~~price~~prices of 3033%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $43.2678 for the current year ~~three~~nine month period compared to $65.1064 for the same period a year ago.

Natural gas, NGLs and crude oil sales for the ~~three~~nine months ended ~~June~~September 30, 2012 decreased by 6459%, 6162% and 2537%, respectively, as compared to the ~~three~~nine months ended ~~June~~September 30, 2011. The decrease in natural gas sales resulted from decreased prices per Mcf of 5850% and lower natural gas production volumes of 1418%. The decrease in NGLs sales was due to a decrease of 6253% in NGLs production volumes, ~~partially~~and ~~offset~~to bya andecrease ~~increase~~ in the average commodity price per Bbl of 319%. The crude oil sales decrease was due primarily to a sales volume decrease of 1135% and a decrease in the average commodity price per Bbl of 153%.

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

For the three months ended September 30, 2012 compared to the same period in 2011, natural gas, NGLs and crude oil sales volumes, on an energy equivalency-basis, decreased 38% precipitated primarily by production curtailments due to high line pressure in the Wattenberg Field and due to normal production declines for this stage in the wells’ production life cycle.

The approximately $114,000, or 71%, decrease in sales for the 2012 three month period as compared to the prior year period was a reflection of sales volume decreases of 38% and a decline in average sales price of 53%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $2.67 for the current year three month period compared to $5.65 for the same period a year ago.

Natural gas, NGLs and crude oil sales for the three months ended September 30, 2012 decreased by 61%, 79% and 77%, respectively, as compared to the three months ended September 30, 2011. The decrease in natural gas sales resulted from decreased prices per Mcf of 49% and lower natural gas production volumes of 23%. The decrease in NGLs sales was due to a decrease of 69% in NGLs production volumes and a decrease in the average commodity price per Bbl of 32%. The crude oil sales decrease was due primarily to a sales volume decrease of 78%, partially offset by an increase in the average commodity price per Bbl of 1%.

Commodity Price Risk Management

~~The~~This Partnership used various derivative instruments to manage fluctuations in natural gas and crude oil prices. ~~The~~This Partnership had in place collars, fixed-price swaps and basis swaps on a portion of ~~the~~this Partnership's estimated natural gas and crude oil production. ~~The~~This Partnership sold its natural gas and crude oil at similar prices to the indices inherent in ~~the~~this Partnership's derivative instruments. As a result, for the volumes underlying ~~the~~this Partnership's derivative positions, ~~the~~this Partnership ultimately realized a price related to its collars of no less than the floor and no more than the ceiling and, for ~~the~~this Partnership's commodity swaps, ~~the~~this 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~~this 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~~this 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-

Index

PDC 2002-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Six~~The ~~months~~following ~~ended~~table ~~June~~presents ~~30,~~the ~~2012~~realized asand ~~compared~~unrealized toderivative ~~six~~gains ~~months~~and ~~ended~~losses ~~June~~included ~~30,~~in ~~2011~~commodity price risk management gain (loss), net:

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.



	Three months ended September 30,						Nine months ended September 30,
	2012			2011			2012			2011
Commodity price risk management gain (loss), net:
Realized gains (losses)
Natural gas	$	34,632		$	14,274		$	112,635		$	42,229
Crude oil	—			(5,889		)	—			(22,393		)
Total realized gains, net	34,632			8,385			112,635			19,836
Unrealized gains (losses)
Reclassification of realized gains included in
prior periods unrealized gains	(34,175		)	(4,814		)	(89,607		)	(18,433		)
Unrealized gains (losses) for the period	(14,836		)	53,439			6,884			70,562
Total unrealized gains (losses), net	(49,011		)	48,625			(82,723		)	52,129
Total commodity price risk management gain (loss), net	$	(14,379	)	$	57,010		$	29,912		$	71,965

~~Unrealized~~Nine ~~gains of approximately $28,000 for the six~~ months ended ~~June~~September 30, 2012 ~~were~~as ~~primarily~~compared ~~related~~ to ~~the~~nine ~~downward~~months ~~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~~September 30, ~~2012,~~2011 ~~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 of approximately $113,000 recognized in the ~~six~~nine months ended ~~June~~September 30, ~~2011~~2012 were primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of ~~the~~this Partnership's natural gas derivative positions. ~~Realized~~For ~~gains~~the onnine ~~natural~~months ~~gas~~ended ~~settlements~~September ~~were~~30, ~~approximately $64~~2012,~~000~~ ~~for~~realized ~~the~~gains ~~six~~on ~~months~~natural ~~ended~~gas, ~~June~~exclusive 30of basis swaps, ~~2011~~were approximately $183,000. These gains were offset in part by anrealized ~~approximate~~losses of approximately $3670,000 ~~loss~~ on ~~the~~this Partnership's ~~CIG~~ basis ~~protection~~swap ~~swaps~~positions as the negative basis differential between NYMEX and CIG weighted-average price was narrower than the strike price of ~~the~~this ~~basis positions. The~~ Partnership's ~~also~~basis ~~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~~swaps.

Unrealized gains ~~during~~of approximately $7,000 for the ~~six~~nine months ended ~~June~~September 30, ~~2011~~2012 were primarily related to the ~~shifts~~downward shift in the natural gas forward ~~curves~~curve and ~~their~~its impact on the fair value of ~~the~~this Partnership's open positions., ~~The~~offset ~~shifts~~in ~~downward~~part inby the ~~natural~~narrowing ~~gas~~of ~~curves~~the ~~resulted~~CIG inbasis anforward ~~unrealized~~curve. ~~gain~~For ofthe ~~approximately~~nine-month ~~$31,000~~period ~~which~~ended ~~was~~September 30, ~~partially~~2012, ~~offset by~~ unrealized ~~losses~~gains ~~of approximately $12,000~~ on ~~the~~this Partnership's ~~CIG~~natural ~~basis~~gas ~~protection~~positions ~~swaps~~were asapproximately ~~the~~$11,000, ~~forward~~offset ~~basis~~by ~~differential~~unrealized ~~between~~losses ~~the~~on ~~NYMEX~~this ~~and~~Partnership's CIG ~~had~~basis ~~continued~~swaps ~~to narrow. Additionally, the shifts upward in the crude oil curves resulted in an unrealized loss~~ of approximately $24,000.

~~Three~~Realized gains recognized in the nine months ended ~~June~~September 30, ~~2012~~2011 aswere primarily the result of lower natural gas spot prices at settlement compared to ~~three~~the respective strike price of this Partnership's natural gas derivative positions. Realized gains on natural gas settlements were approximately $103,000 for the nine months ended ~~June~~September 30, 2011. These gains were offset in part by an approximate $61,000 loss on this 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. This Partnership also realized an approximate $22,000 loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price.

~~Realized~~Unrealized gains ofduring ~~approximately $44,000 recognized in~~ the ~~three~~nine months ended ~~June~~September 30, ~~2012~~2011 were primarily ~~the~~related ~~result~~to ofthe ~~lower~~shifts ~~natural~~in ~~gas~~the ~~spot~~forward ~~prices~~curves atand ~~settlement~~their ~~compared~~impact toon the ~~respective~~fair ~~strike~~value ~~price~~ of ~~the~~this Partnership's open positions. The shifts downward in the natural gas ~~derivative~~curves ~~positions.~~resulted ~~For~~in ~~the~~an ~~three~~unrealized ~~months~~gain ~~ended~~of ~~June~~approximately 30$87,000 ~~2012,~~and ~~realized~~the ~~gains~~shift ondownward ~~natural~~in ~~gas,~~the ~~exclusive~~crude ofoil ~~basis~~curve ~~swaps,~~resulted ~~were~~in an unrealized gain of approximately $665,000. during the nine months ended September 30, 2011. These unrealized gains were partially offset ~~in part~~ by ~~realized~~unrealized losses of approximately $2221,000 on ~~the~~this Partnership's CIG basis ~~swap~~protection ~~positions~~swaps as the ~~negative~~forward basis differential between the NYMEX and CIG ~~weighted-average~~had ~~price~~continued ~~was~~to ~~narrower than the strike price of the Partnership's basis swaps~~narrow.

~~Unrealized~~Three ~~losses of approximately $16,000 for the three~~ months ended ~~June~~ September 30, 2012 ~~were~~as ~~primarily~~compared ~~related~~ to ~~the~~three ~~upward~~months ~~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~~September 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.~~ 2011

Realized gains of approximately $35,000 recognized in the three months ended ~~June~~ September 30, ~~2011~~2012 were primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of ~~the~~this Partnership's natural gas derivative positions. ~~Realized~~For ~~gains~~the onthree ~~natural~~months ~~gas~~ended ~~settlements~~September 30, ~~were~~2012, ~~approximately~~realized ~~$38,000~~gains ~~for~~on ~~the~~natural ~~three~~gas, ~~months~~exclusive ~~ended~~of ~~June~~basis 30swaps, ~~2011~~were approximately $57,000. These gains were offset in part by anrealized ~~approximate~~losses of $2422,000 ~~loss~~ on ~~the~~this Partnership's ~~CIG~~ basis ~~protection~~swap ~~swaps~~positions as the negative basis differential between NYMEX and CIG weighted-average price was narrower than the strike price of ~~the~~this ~~basis positions. The~~ Partnership's ~~also~~basis ~~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~~swaps.

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-

Index

PDC 2002-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~The~~Unrealized ~~following~~losses ~~table~~of ~~presents~~approximately $15,000 for the three months ended September 30, 2012 were primarily related to the upward shift in the natural gas forward curve and its impact on the fair value of this Partnership's ~~derivative~~open positions inand ~~effect~~by asunrealized losses on CIG basis protection swaps due to the narrowing of ~~June 30,~~the ~~2012:~~CIG basis forward curve.

	Collars					Fixed-Price Swaps			CIG Basis Protection Swaps
Commodity/Index	Quantity(Gas-MMBtu(1))	Weighted-AverageContract Price				Quantity(Gas-MMBtu(1))	Weighted-AverageContractPrice		Quantity(Gas-MMBtu(1))	Weighted-AverageContractPrice			Fair Value atJune 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

Realized gains recognized in the three months ended September 30, 2011 were primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of this Partnership's natural gas derivative positions. Realized gains on natural gas settlements were approximately $38,000 for the three months ended September 30, 2011. These gains were offset in part by an approximate $24,000 loss on this 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. This Partnership also realized an approximate $6,000 loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price.

Unrealized gains during the three months ended September 30, 2011 were primarily related to the shifts in the forward curves and their impact on the fair value of this Partnership's open positions. The downward shifts in the natural gas curves resulted in an unrealized gain of approximately $58,000 and the downward shift in the crude oil curve resulted in an unrealized gain of approximately $6,000 during the three months ended September 30, 2011. These unrealized gains were partially offset by unrealized losses of approximately $11,000 on this Partnership's CIG basis protection swaps as the forward basis differential between the NYMEX and CIG had continued to narrow.

The following table presents this Partnership's derivative positions in effect as of September 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 September 30, 2012⁽²⁾
Commodity/ Index	Quantity (Gas-MMBtu⁽¹⁾)	Floors		Ceilings		Quantity (Gas-MMBtu⁽¹⁾)	Weighted- Average Contract Price		Quantity (Gas-MMBtu⁽¹⁾)	Weighted- Average Contract Price			Fair Value at September 30, 2012⁽²⁾

Natural Gas
NYMEX
10/01 - 12/31/2012	780,000,000	$	6.00	$	8.27	12,700,000,000	$	6.98	13,480,000,000	$	(1.88	)	$	26,493
01/01 - 03/31/2013	—	—		—		12,899,000,000	7.12		12,899,000,000	(1.88		)	21,478
04/01 - 06/30/2013	—	—		—		12,786,000,000	7.12		12,786,000,000	(1.88		)	22,557
07/01 - 09/30/2013	—	—		—		12,614,000,000	7.12		12,614,000,000	(1.88		)	21,169
10/01 - 12/31/2013	—	—		—		12,318,000,000	7.12		12,318,000,000	(1.88		)	18,081
Total	780,000,000					63,317,000,000			64,097,000,000				$	109,778

⁽¹⁾A standard unit of measure for natural gas (one MMBtu equals one Mcf).

(2) As of ~~June~~September 30, 2012, approximately 21% of the fair value of ~~the~~this 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-

Index

PDC 2002-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Nine months ended September 30, 2012 as compared to nine months ended September 30, 2011

Natural gas, NGLs and crude oil production costs for the nine months ended September 30, 2012 increased by approximately $32,000 compared to the same period in 2011. Lease operating costs were higher by approximately $54,000 in the current period as workovers and tubing repair activities were collectively lower in 2011. Higher lease operating costs were partially offset by lower revenue- and volume-based costs by approximately $20,000 in 2012, consistent with sales and production declines from 2011. Natural gas, NGLs and crude oil production costs per Mcfe increased to $3.27 during 2012 from $2.13 in 2011 due to lower volumes and increased costs.

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

Natural gas, NGLs and crude oil production costs for the three months ended September 30, 2012 increased by approximately $17,000 compared to the same period in 2011. Lease operating costs were lower by approximately $26,000 in the current period as workovers and tubing repair activities were collectively higher in 2011. Additionally, revenue- and volume-based costs were lower by approximately $7,000 in 2012, consistent with sales and production declines from 2011. Natural gas, NGLs and crude oil production costs per Mcfe increased to $4.17 during 2012 from $2.00 in 2011 due to lower volumes and increased costs.

Direct Costs-General and Administrative

~~Six~~Nine months ended ~~June~~September 30, 2012 as compared to ~~six~~nine months ended ~~June~~September 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~~nine months ended ~~June~~September 30, 2012 compared to the same period in 2011 by approximately $~~108~~176,000, principally due to the timing of fees for professional services.

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

Direct costs-general and administrative decreased during the three months ended ~~June~~ September 30, 2012 compared to the same period in 2011 by approximately $~~128~~68,000, principally due to the timing of fees for professional services.

Depreciation, Depletion and Amortization ("DD&A")

~~Six~~Nine months ended ~~June~~September 30, 2012 as compared to ~~six~~nine months ended ~~June~~September 30, 2011

The DD&A expense rate per Mcfe decreased to $2.2304 for the ~~six~~nine months ended ~~June~~September 30, 2012, compared to $3.0508 during the same period in 2011. The decrease in the per Mcfe rates for the 2012 period compared to the 2011 period iswas due to a combination of the effect of the 2011 impairment of ~~the~~this Partnership’'s Piceance Basin assets and the change in the production mix from the Piceance Basin relative to the Wattenberg Field. The percentage of production from the Wattenberg Field, which has the higher DD&A rate, was lower in 2012 due to the high line pressure curtailments. The decreases in production and DD&A expense rate resulted in an overall decreased DD&A expense of approximately $70133,000 for the 2012 ~~six~~nine months compared to the same 2011 period.

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

The DD&A expense rate per Mcfe decreased to $21.0650 for the three months ended ~~June~~ September 30, 2012, compared to $3.0514 during the same period in 2011. The decrease in the per Mcfe rates for the 2012 period compared to the 2011 period iswas due to a combination of the effect of the 2011 impairment of ~~the~~this Partnership’'s Piceance Basin assets and the change in the production mix from the Piceance Basin relative to the Wattenberg Field. The percentage of production from the Wattenberg Field, which has the higher DD&A rate, was lower in 2012 due to the high line pressure curtailments. The decreases in production and DD&A expense rate resulted in an overall decreased DD&A expense of approximately $3863,000 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-

Index

PDC 2002-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~The~~Financial ~~Partnership's future operations are expected to be conducted with available funds and revenues generated from natural gas~~Condition, ~~NGLs~~Liquidity and ~~crude~~Capital ~~oil~~Resources 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.

This Partnership's primary source of cash for the nine months ended September 30, 2012 was operating activities, which include the sale of natural gas, NGLs and crude oil production, and the net realized gains from this Partnership's derivative positions. These sources of cash were primarily used to fund this 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 this Partnership's operating cash flows are substantially driven by changes in commodity prices, sales volumes, which can be impacted by high line pressures, 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. This Partnership does not engage in speculative positions, nor does this Partnership hold derivative instruments for 100% of this Partnership's expected future production from producing wells, and therefore may still experience significant fluctuations in cash flows from operations. As of September 30, 2012, this Partnership had natural gas derivative positions in place covering 79% of its expected natural gas production for the remainder of 2012 at an average price of $5.05 per Mcf. This 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 this Partnership's revenues.

This 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, this 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. This 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 this 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 this 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~~September 30, 2012, ~~the~~this Partnership had a working capital surplus of approximately $~~125~~72,000 compared to a working capital surplus of approximately $71,000 at December 31, 2011. The increase of approximately $541,000 was primarily due to the following changes:

• accounts receivable decreased by approximately $2663,000 between ~~June~~September 30, 2012 and December 31, 2011;

• realized and unrealized derivative gains receivable ~~increased~~decreased by approximately $199,000 between ~~June~~September 30, 2012 and December 31, 2011; and

• amounts due to Managing General Partner-other, net, excluding natural gas, NGLs and crude oil ~~inventory~~sales ~~increased~~received from third parties and realized derivative gains, decreased by approximately $971,000 between ~~June~~September 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~~This 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.

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Index

PDC 2002-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Net cash flows from operating activities were approximately $28,000 for the nine months ended September 30, 2012 compared to approximately $56,000 for the comparable period in 2011. The decrease of approximately $28,000 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 $198,000;


•	an increase in commodity price risk management realized gain receipts of approximately $70,000; and


•	a decrease in production costs and direct costs-general and administrative payments of approximately $100,000.

Investing Activities

From time to time, this Partnership invests in equipment which supports treatment, delivery and measurement of natural gas, NGLs and crude oil or environmental protection. These amounts were approximately $3,000 and $18,000 for the nine months ended September 30, 2012 and 2011, respectively.

Financing Activities

~~The~~This Partnership initiated monthly cash distributions to investors in March 2003 and has distributed $9.5 million through ~~June~~September 30, 2012. The table below presents cash distributions to ~~the~~this 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~~this Partnership and Investor Partner distributions include amounts distributed to Investor Partners for their 80% ownership share in ~~the~~this 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

Three months ended September 30,

Managing General Partner

Investor Partners

Total

2012

~~852~~748

76,~~614~~942

87,~~466~~690

2011

1,~~938~~021

179,~~833~~406

1910,~~771~~427

Six months ended June 30,

Managing General Partner

Investor Partners

Total

Nine months ended September 30,

Managing General Partner

Investor Partners

Total

2012

12,~~802~~550

1623,~~063~~005

1725,~~865~~555

2011

23,~~575~~596

2434,~~874~~280

2737,~~449~~876

The decrease in total distributions for the three months ended September 30, 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~~The indecrease 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~~total ~~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~~nine months ended ~~June~~September 30, 2012 ~~and~~as compared to 2011, ~~respectively,~~is asprimarily adue ~~result~~to of the ~~Preferred~~decrease ~~Cash~~in ~~Distribution~~cash ~~made~~flows ~~under~~from ~~the~~operating ~~terms~~activities induring ~~Section~~2012, ~~4.02.~~partially ~~Because~~offset ofby the ~~expected~~decrease ~~production~~in ~~declines~~capital ~~related~~expenditures tofor ~~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 Agreementproperties.

Beginning in November 2009, when the Investor Partner's average annual rate of return fell below 12.8%, this Partnership modified the standard ownership-based pro-rata allocation of Partnership cash available for distribution, pursuant to the Performance Standard Obligation outlined in Section 4.02 of the Agreement. Distributions paid to the Managing General Partner were reduced and distributions to the Investor Partners were increased by $2,561 and $3,979 for the nine months ended September 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 this 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~~September 30, 2012, ~~the~~this 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~~this Partnership's financial condition, results of operations, liquidity, capital expenditures or capital resources.

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Index

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~~this 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~~this Partnership's 2011 Form 10-K.

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Index

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~~This Partnership has no direct management or officers. The management, officers and other employees that provide services on behalf of ~~the~~this Partnership are employed by the Managing General Partner.

(a) Evaluation of Disclosure Controls and Procedures

As of ~~June~~September 30, 2012, PDC, as Managing General Partner on behalf of ~~the~~this 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~~this 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~~this 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~~this 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~~this Partnership's disclosure controls and procedures were effective as of ~~June~~September 30, 2012.

(b) Changes in Internal Control over Financial Reporting

During the three months ended ~~June~~September 30, 2012, PDC, the Managing General Partner, made no changes in ~~the~~this 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~~this Partnership's internal control over financial reporting.

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Index

PDC 2002-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

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~~this 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~~September 30, 2012:

Period	Total Number of Units Repurchased	Average Price Paid Per Unit
April 1 - 30, 2012	—	$	—
July 1 - 31, 2012	3.13	$	202
May 1 - 31, 2012	0.25	200
August 1 - 31, 2012	—	—
June 1 - 30, 2012	—	—
September 1 - 30, 2012	—	—
Total	03.2513	$	~~200~~202

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

-23-

Index

PDC 2002-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 6. Exhibits

Incorporated by Reference

ExhibitNumber

Exhibit Description

Form

SEC FileNumber

Exhibit

Filing Date

FiledHerewith

31.1

Certification by Chief Executive Officer of PDC Energy, Inc., the Managing General Partner of ~~the~~this 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.

31.2

Certification by Chief Financial Officer of PDC Energy, Inc., the Managing General Partner of ~~the~~this 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.

32.1*

Certifications by Chief Executive Officer and Chief Financial Officer of PDC Energy, Inc., the Managing General Partner of ~~the~~this 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-

Index

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. TrimblePresident and Chief Executive Officerof PDC Energy, Inc. ~~August~~November 138, 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~~November 138, 2012
James M. Trimble	PDC Energy, Inc. Managing General Partner of the Registrant
	(principal executive officer)
/s/ Gysle R. Shellum	Chief Financial Officer	~~August~~November 138, 2012
Gysle R. Shellum	PDC Energy, Inc. Managing General Partner of the Registrant
	(principal financial officer)
/s/ R. Scott Meyers	Chief Accounting Officer	~~August~~November 138, 2012
R. Scott Meyers	PDC Energy, Inc. Managing General Partner of the Registrant
	(principal accounting officer)

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Filing Compare · PDC 2002 B LTD PARTNERSHIP