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 ~~September~~March 3031, ~~2012~~2013

£ 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 ~~September~~March 3031, ~~2012~~2013 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)	23
	Condensed Statements of Operations (unaudited)	34
	Condensed Statements of Cash Flows (unaudited)	45
	Notes to Unaudited Condensed Financial Statements	56
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	1113
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	2221
Item 4.	Controls and Procedures	2221
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	2322
Item 1A.	Risk Factors	2322
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	2322
Item 3.	Defaults Upon Senior Securities	2322
Item 4.	Mine Safety Disclosures	2322
Item 5.	Other Information	2322
Item 6.	Exhibits	2423
	SIGNATURES	2524

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~~this ~~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 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 ("U.S.") 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~~future ~~PDC-Sponsored~~production, ~~Drilling Program Acquisition Plan discussed in Item 2~~expenses, ~~"Management's~~cash ~~Discussion~~flows and ~~Analysis~~liquidity; ofanticipated ~~Financial~~capital ~~Condition~~expenditures; ~~and~~availability ~~Results~~ of ~~Operations~~additional -midstream ~~Recent~~facilities ~~Developments";~~and ~~future~~services ~~cash~~in ~~flows~~the ~~and~~Wattenberg ~~anticipated~~Field ~~liquidity;~~and ~~anticipated~~timing ~~capital~~of ~~expenditures~~that availability; the adequacy of ~~the~~this ~~Managing General Partner~~Partnership's ~~casualty~~ insurance ~~coverage~~; the effectiveness of the Managing General Partner's derivative ~~policies~~program in ~~achieving~~providing ~~this~~a ~~Partnership's~~degree ~~risk~~of ~~management~~price ~~objectives~~stability; ~~the~~closing ~~timing~~ of ~~planned~~and ~~midstream~~expected ~~capacity~~proceeds ~~increases~~from inthis ~~the~~Partnership's ~~Wattenberg~~pending ~~Field~~asset disposition; 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 interpretation and enforcement related to those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations;

• potential declines in the ~~value~~values of 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;


•	potential for production decline rates from this Partnership's wells to be greater than expected;

• availability of ~~Partnership~~ future cash flows for investor distributions or funding of development activities;


•	timing and extent of this Partnership's success in further developing and producing this Partnership's reserves;


•	the Managing General Partner's ability to acquire supplies and services at reasonable prices;


•	timing and receipt of necessary regulatory permits;


•	risks incidental to the additional development and operation of natural gas and crude oil wells;

• this Partnership's future cash flows, liquidity and financial ~~position~~condition;

• competition ~~within~~in the oil and gas industry;


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


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

• effect of natural gas derivative activities;


•	impact of environmental events, governmental and other third-party responses to such events and the Managing General Partner's ability to insure adequately against such events;

• ~~the~~ cost of pending or future litigation;


•	potential obstacles to completing this Partnership's pending asset disposition or other transactions, in a timely manner or at all, and purchase price or other adjustments relating to those transactions that may be unfavorable to this Partnership;


•	the Managing General Partner's ability to retain or attract senior management and key technical employees; and


•	success of strategic plans, expectations and objectives for future operations of the Managing General Partner.

~~Further, this Partnership urges the reader to carefully review and consider the cautionary statements and disclosures made in this Quarterly Report on Form 10~~-Q, ~~this Partnership's Annual Report on Form 10~~1-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 and this Partnership's other filings with the SEC for further information on risks and uncertainties that could affect 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. 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.

Further, this Partnership urges the reader to carefully review and consider the cautionary statements and disclosures made in this Quarterly Report on Form 10-1Q, this Partnership's Annual Report on Form 10-K for the year ended December 31, 2012(“2012 Form 10-K”) filed with the U.S. Securities and Exchange Commission (“SEC”) on March 15, 2013 and this Partnership's other filings with the SEC for further information on risks and uncertainties that could affect this Partnership's business, financial condition, results of operations and cash flows. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report. 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.

- 2-

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

PDC 2002-B Limited Partnership

Condensed Balance Sheets

(unaudited)

	September 30, 2012			December 31, 2011*
	March 31, 2013			December 31, 2012*
Assets
Current assets:
Cash and cash equivalents	$	10,~~168~~106		$	10,~~261~~137
Accounts receivable	949,~~247~~477			3921,~~117~~527
Crude oil inventory	1017,~~060~~859			1124,~~174~~499
Due from Managing General Partner-derivatives	~~174~~112,~~870~~556			~~201~~180,~~175~~165
Total current assets	~~204~~189,~~345~~998			~~261~~236,~~727~~328
Natural gas and crude oil properties, successful efforts method, at cost	72,~~777~~196,~~402~~032			73,~~774~~167,~~445~~657
Less: Accumulated depreciation, depletion and amortization	(51,~~728~~595,~~222~~371		)	(52,~~592~~270,~~847~~162		)
Natural gas and crude oil properties, net	2600,~~049,180~~661			2897,~~181,598~~495
Due from Managing General Partner-derivatives	37,678			157,086
Assets held for sale	272,904			—
Other assets	4751,~~953~~010			4249,~~200~~653
Total Assets	$	21,~~339~~114,~~156~~573		$	21,~~642~~183,~~611~~476
Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	2,~~110~~930		$	42,~~951~~522
Due to Managing General Partner-derivatives	8360,~~173~~403			8781,~~900~~917
Due to Managing General Partner-other, net	4661,~~925~~704			9867,~~359~~520
Total current liabilities	~~132~~125,~~208~~037			~~191~~151,~~210~~959
Due to Managing General Partner-derivatives	19,597			77,860
Asset retirement obligations	160,955			223,265
Asset retirement obligations	219,559			208,823
Liabilities held for sale	66,082			—
Total liabilities	~~371~~352,~~364~~074			~~477~~375,~~893~~224
Commitments and contingent liabilities
Partners' equity:
Managing General Partner	~~463~~224,~~586~~231			~~500~~232,~~410~~462
Limited Partners - 559.02 units issued and outstanding	1538,~~504,206~~268			1575,~~664,308~~790
Total Partners' equity	1762,~~967,792~~499			2808,~~164,718~~252
Total Liabilities and Partners' Equity	$	21,~~339~~114,~~156~~573		$	21,~~642~~183,~~611~~476

*Derived from audited ~~2011~~2012 balance sheet

See accompanying notes to unaudited condensed financial statements.

-2 3-

PDC 2002-B Limited Partnership

Condensed Statements of Operations

(unaudited)

	Three months ended September 30,						Nine months ended September 30,
	Three months ended March 31,
	2012			2011			2012			2011
	2013			2012
Revenues:
Natural gas, NGLs and crude oil sales	$	4756,~~511~~243		$	~~161~~75,~~389~~644		$	~~251,367~~		$	~~490,925~~
Commodity price risk management gain (loss), net	(1419,~~379~~945		)	5761,~~010~~124			~~29,912~~			~~71,965~~
Total revenues	3336,~~132~~298			~~218~~136,~~399~~768			~~281,279~~			~~562,890~~
Operating costs and expenses:
Natural gas, NGLs and crude oil production costs	7430,~~281~~102			5722,~~046~~071			~~217,572~~			~~185,375~~
Direct costs - general and administrative	2930,~~086~~686			9728,~~302~~858			~~88,982~~			~~265,091~~
Depreciation, depletion and amortization	2617,~~663~~574			8948,~~710~~721			~~135,375~~			~~268,148~~
Accretion of asset retirement obligations	32,~~642~~775			2,~~385~~578			~~10,736~~			~~7,048~~
Total operating costs and expenses	~~133~~81,~~672~~137			~~246~~102,~~443~~228			~~452,665~~			~~725,662~~
Loss from operations	(100,540		)	(28,044		)	(171,386		)	(162,772		)
Income (loss) from continuing operations	(44,839		)	34,540
Interest income	5			735			15			81
Net loss	$	(100,535	)	$	(27,971	)	$	(171,371	)	$	(162,691	)
Income (loss) from discontinued operations	6,315			(76,507		)
Net loss allocated to partners	$	(100,535	)	$	(27,971	)	$	(171,371	)	$	(162,691	)
Net loss	$	(38,519	)	$	(41,962	)
Less: Managing General Partner interest in net loss	(11,715		)	(5,594		)	(34,274		)	(32,538		)
Net loss allocated to partners	$	(38,519	)	$	(41,962	)
Net loss allocated to Investor Partners	$	(88,820	)	$	(22,377	)	$	(137,097	)	$	(130,153	)
Less: Managing General Partner interest in net loss	(7,704		)	(8,392		)
Net loss per Investor Partner unit	$	(159	)	$	(40	)	$	(245	)	$	(233	)
Net loss allocated to Investor Partners	$	(30,815	)	$	(33,570	)
Investor Partner units outstanding	559.02			559.02			559.02			559.02
Net loss per Investor Partner unit	$	(55	)	$	(60	)
Investor Partner units outstanding	559.02			559.02

See accompanying notes to unaudited condensed financial statements.

-3 4-

PDC 2002-B Limited Partnership

Condensed Statements of Cash Flows

(unaudited)

	Nine months ended September 30,
	Three months ended March 31,
	2012			2011
	2013			2012
Cash flows from operating activities:
Net loss	$	(~~171~~38,~~371~~519	)	$	(~~162~~41,~~691~~962	)
Adjustments to net loss to reconcile to net cash from operating activities:
Depreciation, depletion and amortization	~~135~~23,~~375~~930			~~268~~59,~~148~~008
Accretion of asset retirement obligations	103,~~736~~772			73,~~048~~516
Unrealized (gain) loss on derivative transactions	8246,~~723~~095			(5226,~~129~~736		)
Changes in assets and liabilities:
Accounts receivable	29(27,~~870~~950		)	~~(19~~11,~~616~~668		)
Crude oil inventory	16,~~114~~640			(26,~~301~~800		)
Other assets	(51,~~753~~357		)	(51,~~754~~917		)
Accounts payable and accrued expenses	~~(2,841~~408		)	(115,~~426~~606		)
Due to Managing General Partner-other, net	(515,~~434~~816		)	24(2,~~785~~359		)
Net cash from operating activities	287,~~419~~203			5610,~~064~~024
Cash flows from investing activities:
Capital expenditures for natural gas and crude oil properties	~~(2,957~~—		)	(~~18,177~~656		)
Net cash from investing activities	~~(2,957~~—		)	(~~18,177~~656		)
Cash flows from financing activities:
Distributions to Partners	(257,~~555~~234		)	(379,~~876~~399		)
Net cash from financing activities	(257,~~555~~234		)	(379,~~876~~399		)
Net change in cash and cash equivalents	(9331		)	11(31		)
Cash and cash equivalents, beginning of period	10,~~261~~137			10,~~281~~261
Cash and cash equivalents, end of period	$	10,~~168~~106		$	10,~~292~~230

See accompanying notes to unaudited condensed financial statements.

-4 5-

PDC 2002-B ~~LIMITED~~Limited ~~PARTNERSHIP~~Partnership

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2012~~2013

(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, 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 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 this Partnership and initiates and completes substantially all Partnership transactions.

As of ~~September~~March 3031, ~~2012~~2013, there were ~~505~~498 limited partners in this Partnership (the “Investor Partners”). PDC is the designated Managing General Partner of this Partnership and owns a 20% Managing General Partner ownership in this Partnership. According to the terms of the Agreement, revenues, costs and cash distributions of this Partnership are allocated 80% to the Investor Partners, which are shared pro rata based upon the number of units in 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 ~~September~~March 3031, ~~2012~~2013, the Managing General Partner had repurchased 3741.21 units of Partnership interests from the Investor Partners at an average price of $3,~~952~~598 per unit. As of ~~September~~March 3031, ~~2012~~2013, the Managing General Partner owned 25.339% of this Partnership.

Beginning in November 2009, when the Investor Partners' 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~~668 and $~~3,979~~929 for the ~~nine~~three months ended ~~September~~March 3031, ~~2012~~2013 and ~~2011~~2012, 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~~expired in February 2013. For more information concerning the Performance Standard Obligation, see Note 8, Partners' Equity and Cash Distributions, to this Partnership's financial statements included in the ~~2011~~2012 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 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 this Partnership's audited financial statements and notes thereto included in this Partnership's ~~2011~~2012 Form 10-K. This Partnership's accounting policies are described in the Notes to Financial Statements in this Partnership's ~~2011~~2012 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 nine~~ months ended ~~September~~March 3031, ~~2012~~2013 are not necessarily indicative of the results to be expected for the full year or any other future period.

Certain reclassifications have been made to prior period financial statements to conform to the current year presentation. The reclassifications are mainly attributable to reporting as discontinued operations the results of operations related to the planned sale of this Partnership's Piceance Basin assets. The reclassifications had no impact on previously reported cash flows, net income or Partners’ equity. See Note ~~2−Recent~~8, ~~Accounting~~Assets ~~Standards~~Held for Sale, Divestitures and Discontinued Operations, for additional information regarding the planned divestiture.

~~Fair~~- ~~Value Measurement~~6-

OnPDC ~~May~~2002-B ~~12,~~Limited 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 this Partnership~~'s financial statements.~~

-5-

PDC 2002-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2012~~2013

(unaudited)

Note ~~3−Transactions~~2 ~~with~~- ~~Managing~~Summary ~~General~~of ~~Partner~~Significant Accounting Policies

Recently Adopted Accounting Standards

On January 1, 2013, this Partnership adopted changes issued by the Financial Accounting Standards Board regarding the disclosure of offsetting assets and liabilities. These changes require an entity to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an enforceable master netting arrangement or similar agreement. The enhanced disclosures enable users of an entity’s financial statements to understand and evaluate the effect or potential effect of master netting arrangements on an entity’s financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. This Partnership's adoption of these changes had no impact on the unaudited condensed financial statements.

Note 3 - Transactions with Managing General Partner

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

	September 30, 2012			December 31, 2011
	March 31, 2013			December 31, 2012
Natural gas, NGLs and crude oil sales revenues collected from this Partnership's third-party customers	$	2417,~~871~~019		$	5720,~~606~~841
Commodity price risk management, realized gain	2217,~~538~~239			914,~~620~~367
Other (1)	(9495,~~334~~962		)	(~~165~~102,~~585~~728		)
Total Due to Managing General Partner-other, net	$	(4661,~~925~~704	)	$	(9867,~~359~~520	)


(1)	All other unsettled transactions, excluding derivative instruments, between 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 nine months ended 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. 7-

	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Well operations and maintenance	$	70,130	$	45,460	$	200,518	$	148,171
Gathering, compression and processing fees	2,900		5,103		13,570		15,855
Direct costs - general and administrative	29,086		97,302		88,982		265,091
Cash distributions (1) (2)	1,210		1,570		3,976		5,564

PDC 2002-B Limited Partnership

(1) Cash distributions include $462 and $1,426 during the three and nine months ended September 30, 2012, respectively, and $549 and $1,968 during the three and nine months ended 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 $790 and $2,561 during the three and nine months ended September 30, 2012, respectively, and $1,064 and $3,979 for the three and nine months ended 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

~~September~~March 3031, ~~2012~~2013

(unaudited)

The following table presents Partnership transactions, excluding derivative transactions which are more fully detailed in Note ~~4−Fair~~5, ~~Value~~Derivative ~~Measurements~~Financial Instruments, with the Managing General Partner for the three months ended March 31, 2013 and ~~Disclosures~~2012. “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 for continuing operations and in Note 8, Assets Held for Sale, Divestitures and Discontinued Operations, for discontinued operations.

Determination of fair value. This Partnership's fair value measurements are estimated pursuant to a fair value hierarchy that requires 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:



	Three months ended March 31,
	2013		2012
Well operations and maintenance	$	47,522	$	103,679
Gathering, compression and processing fees	3,484		4,627
Direct costs - general and administrative	30,686		28,858
Cash distributions ^{(1) (2)}	1,017		1,451


(1)	Cash distributions include $490 and $501 during the three months ended March 31, 2013 and 2012, respectively, related to equity cash distributions for Investor Partner units repurchased by PDC.

(2)

Cash distributions to the Managing General Partner were reduced by $668 and $929 during the three months ended March 31, 2013 and 2012, 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.

Note 4 - Fair Value of Financial Instruments

Determination of fair value. This Partnership's fair value measurements are estimated pursuant to a fair value hierarchy that requires 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. In these cases, 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 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~~curve, 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.8-

~~The~~PDC ~~Managing~~2002-B ~~General~~Limited 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 this Partnership~~'s derivative instruments was not significant.~~

-7-

PDC 2002-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2012~~2013

(unaudited)

~~This~~The ~~Partnership's~~Managing ~~fixed-price~~General ~~swaps~~Partner ~~and~~validates ~~basis~~its ~~swaps~~fair ~~are~~value ~~included~~measurement inthrough ~~Level~~the 2review of counterparty statements and ~~its~~other ~~natural~~supporting ~~gas~~documentation, ~~collars~~the ~~are~~determination ~~included~~that inthe ~~Level~~source 3.of ~~The~~the ~~following~~inputs ~~table~~is ~~presents~~valid, ~~for~~the ~~each~~corroboration ~~applicable~~of ~~level~~the ~~within~~original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While the ~~fair~~Managing ~~value~~General ~~hierarchy~~Partner uses common industry practices to develop its valuation techniques, ~~this~~changes ~~Partnership~~in the Managing General Partner's ~~derivative~~pricing ~~assets~~methodologies ~~and~~or ~~liabilities,~~the ~~including~~underlying ~~both~~assumptions ~~current~~could result in significantly different fair values. While the Managing General Partner believes its valuation method is appropriate and ~~non-current~~consistent ~~portions~~with those used by other market participants, ~~measured~~the atuse of a different methodology or assumptions to determine the fair value onof certain financial instruments could result in a ~~recurring~~different ~~basis:~~estimate of fair value.

	Balance Sheet	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	$	172,789	$	2,081	$	174,870	$	192,906	$	8,269	$	201,175
Non-Current
Commodity-based derivatives	Due from Managing General Partner-derivatives	37,678		—		37,678		157,086		—		157,086
Total assets		210,467		2,081		212,548		349,992		8,269		358,261
Liabilities:
Current
Basis protection derivative contracts	Due to Managing General Partner-derivatives	83,173		—		83,173		87,900		—		87,900
Non-Current
Basis protection derivative contracts	Due to Managing General Partner-derivatives	19,597		—		19,597		77,860		—		77,860
Total liabilities		102,770		—		102,770		165,760		—		165,760
Net asset (1)		$	107,697	$	2,081	$	109,778	$	184,232	$	8,269	$	192,501

The Managing General Partner's derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. The Managing General Partner has elected not to offset the fair value positions recorded on the unaudited condensed balance sheets for this Partnership.

~~(1)As~~This ofPartnership's ~~September 30,~~fixed-price ~~2012~~swaps and ~~December 31,~~basis ~~2011,~~swaps ~~none~~are ofincluded in Level 2. The following table presents this Partnership's derivative ~~instruments~~assets ~~were~~and ~~designated~~liabilities asmeasured ~~hedges.~~ at fair value on a recurring basis:

	Nine months ended
	Balance Sheet		March 31, 2013				December 31, 2012
	September 30, 2012				September 30, 2011
	Line Item		Level 2				Level 2
Fair value, net asset, beginning of period	$	8,269			$	12,277
Assets:
Changes in fair value included in condensed statement of operations line item:
Current
Commodity price risk management gain (loss), net	1,241				3,316
Commodity-based derivatives	Due from Managing General Partner-derivatives		$	112,556			$	180,165
Settlements	(7,429		)		(10,264		)
Total assets			112,556				180,165
Fair value, net asset, end of period	$	2,081			$	5,329
Liabilities:
Change in unrealized gain (loss) relating to assets (liabilities) still held as of
Current
September 30, 2012 and 2011, respectively, included in condensed statement of operations line item:
Basis protection derivative contracts	Due to Managing General Partner-derivatives		60,403				81,917
Commodity price risk management gain (loss), net	$	166			$	1,829
Total liabilities			60,403				81,917
Net asset			$	52,153			$	98,248

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

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

-8-

PDC 2002-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

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~~9-

AsPDC of2002-B ~~September 30,~~Limited ~~2012, this~~ Partnership ~~had derivative instruments in place for a portion of its anticipated natural gas production through 2013 totaling 64,097 MMBtu.~~

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

	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	$	34,175		$	457		$	34,632		$	4,814		$	3,571	$	8,385
Unrealized gains (losses)	(34,175		)	(14,836		)	(49,011		)	(4,814		)	53,439		48,625
Total	$	—		$	(14,379	)	$	(14,379	)	$	—		$	57,010	$	57,010
	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 For the Current Period		Total
Commodity price risk management gain, net
Realized gains	$	89,607		$	23,028		$	112,635		$	18,433		$	1,403	$	19,836
Unrealized gains (losses)	(89,607		)	6,884			(82,723		)	(18,433		)	70,562		52,129
Total	$	—		$	29,912		$	29,912		$	—		$	71,965	$	71,965

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

-9-

PDC 2002-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2012~~2013

(unaudited)

Note ~~6−Commitments~~5 ~~and~~- ~~Contingencies~~Derivative Financial Instruments

As of March 31, 2013, this Partnership had derivative instruments in place for all of its anticipated 2013 natural gas production totaling 37,718 MMBtu. Partnership policy prohibits the use of natural gas and crude oil derivative instruments for speculative purposes.

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



	Three months ended March 31,
	2013									2012
Statement of operations line item:	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Losses For the Current Period			Total			Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total
Commodity price risk management gain (loss), net
Realized gains (losses)	$	26,669		$	(519	)	$	26,150		$	30,872		$	3,516	$	34,388
Unrealized gains (losses)	(26,669		)	(19,426		)	(46,095		)	(30,872		)	57,608		26,736
Total	$	—		$	(19,945	)	$	(19,945	)	$	—		$	61,124	$	61,124

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

Note 6 - Commitments and Contingencies

Legal Proceedings

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

Environmental

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

During the ~~nine~~three months ended ~~September 30~~March 31, ~~2012~~2013, as a result of the Managing General Partner's periodic review, ~~there were~~ no new environmental remediation ~~efforts~~liabilities were identified and this Partnership's expense for environmental remediation efforts was ~~insignificant~~not significant. AsThis ofPartnership ~~September 30,~~recorded ~~2012~~no ~~and~~environmental ~~December~~remediation liabilities as of March 31, ~~2011,~~2013. ~~accrued~~Environmental ~~environmental~~ remediation liabilities as of December 31, 2012 were ~~insignificant~~not significant.

The Managing General Partner is not currently aware of any environmental claims existing as of September 30, 2012 which have not been provided for or would otherwise have a material impact on 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 this Partnership's properties.~~ 10-

PDC 2002-~~10-~~B Limited Partnership

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2013

(unaudited)

The Managing General Partner is not currently aware of any environmental claims existing as of March 31, 2013 which have not been provided for or would otherwise have a material impact on 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 this Partnership's properties.

Note 7 - Asset Retirement Obligations

The following table presents the changes in carrying amounts of the asset retirement obligations associated with this Partnership's working interest in natural gas and crude oil properties:



	Three months ended
	March 31, 2013

Beginning balance	$	223,265
Accretion expense	3,772
Ending balance	227,037
Liabilities held for sale (1)	(66,082		)
Long-term portion	$	160,955


(1)	Represents asset retirement obligations related to this Partnership's assets held for sale. See Note 8, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding the planned sale of these properties.

Note 8 - Assets Held for Sale, Divestitures and Discontinued Operations

Piceance Basin. On February 4, 2013, this Partnership's Managing General Partner entered into a purchase and sale agreement ("PSA") with certain affiliates of Caerus Oil and Gas LLC (“Caerus”), pursuant to which this Partnership agreed to sell to Caerus all of its Piceance Basin assets for cash consideration of approximately $431,000, subject to post-closing adjustments. Under the same PSA, PDC has agreed to sell to Caerus PDC's and PDC sponsored partnerships' Piceance Basin assets and certain non-core Colorado oil and gas properties, leasehold mineral interests and related assets. Based on the amounts allocated to this Partnership in the PSA, PDC determined that it was in the best interest of this Partnership to sell its Piceance Basis assets under the PSA. The PSA does not include any of this Partnership's Wattenberg Field assets. These assets have been classified as held for sale in the unaudited condensed balance sheet as of March 31, 2013. The cash consideration is subject to customary adjustments, including adjustments based upon title and environmental due diligence and with respect to natural gas derivative position settlements that will be assumed by Caerus. The Managing General Partner intends to use the proceeds from the asset disposal for operational needs, for additional reserve development of natural gas, NGLs and crude oil production in the Wattenberg Field (the "Additional Development Plan") or distributions to Partners. There can be no assurance this Partnership will be successful in closing such divestiture. Following the planned sale, this Partnership will not have significant continuing involvement in the operations of, or cash flows from, the Piceance Basin oil and gas properties. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the unaudited condensed statement of operations for all periods presented.

Selected financial information related to divested and discontinued operations. The tables below set forth selected financial information related to this Partnership's Piceance Basin net assets held for sale and operating results related to discontinued operations. Net assets held for sale represents this Partnership's Piceance Basin assets that are expected to be sold, net of liabilities that are expected to be assumed by Caerus. While the reclassification of revenues and expenses related to discontinued operations for the 2012 period had no impact upon previously reported net earnings, the statement of operations table presents the revenues and expenses that were reclassified from the specified statement of operations line items to discontinued operations.

- 11-

PDC 2002-B Limited Partnership

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2013

(unaudited)

The following table presents balance sheet data related to assets held for sale:



	As of
	March 31, 2013

	Net Assets
Balance Sheet	Held for Sale

Assets
Properties, successful efforts method, at cost	$	971,625
Accumulated depreciation, depletion and amortization	(698,721		)
Total assets	272,904

Liabilities
Asset retirement obligations	66,082

Net Assets	$	206,822

The following table presents statements of operations data related to this Partnership's discontinued operations:



	Three Months Ended March 31,
Statement of Operations - Discontinued Operations	2013		2012

Revenues:
Natural gas, NGLs and crude oil sales	$	38,800	$	25,524
Total revenues	38,800		25,524

Operating costs and expenses:
Natural gas, NGLs and crude oil production costs	25,132		90,806
Depreciation, depletion and amortization	6,356		10,287
Accretion of asset retirement obligations	997		938
Total operating costs and expenses	32,485		102,031

Income (loss) from discontinued operations	$	6,315	$	(76,507	)

- 12-

Index

PDC 2002-B ~~LIMITED~~Limited ~~PARTNERSHIP~~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. 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 this Partnership~~ markets this Partnership's natural gas and crude oil production to ~~commercial~~midstream ~~end~~marketers. ~~users,~~Natural ~~interstate or intrastate pipelines~~gas, ~~local~~NGLs ~~utilities~~ and ~~petroleum~~crude ~~refiners~~oil oris ~~marketers,~~sold 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 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~~and toother factors such as high pressures in the gathering system whether caused by heat or third-party facilities issues, may impact 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, this Partnership modified the standard ownership-based pro-rata allocation of Partnership cash available for distribution. This modified distribution ended in 2013. 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~~Planned ~~Drilling~~Natural ~~Program~~Gas ~~Acquisition~~and ~~Plan~~Crude Oil Properties Divestitures

AsOn ~~managing~~February ~~general~~4, ~~partner~~2013, ofthis ~~various~~Partnership's ~~public~~Managing ~~limited~~General ~~partnerships,~~Partner ~~PDC~~entered ~~has~~into ~~disclosed~~a ~~its~~PSA ~~intention~~with tocertain ~~pursue~~affiliates of Caerus, ~~beginning~~pursuant into ~~the~~which ~~fall~~this ofPartnership ~~2010,~~agreed ~~the~~to ~~acquisition~~sell to Caerus all of ~~the~~its ~~limited~~Piceance ~~partnership~~Basin ~~units~~oil ~~other~~and ~~than~~gas ~~those~~properties ~~held~~for bycash ~~PDC~~consideration orof ~~its~~approximately ~~affiliates~~$431,000. ~~held~~The bycash ~~limited~~consideration ~~partners~~is ~~(“non-affiliated~~subject ~~investor~~to ~~partners”)~~customary adjustments, inincluding ~~certain~~adjustments ~~limited~~based ~~partnerships~~upon ~~that~~title ~~PDC~~and ~~had~~environmental ~~previously~~due ~~sponsored,~~diligence ~~including~~and ~~this~~with ~~Partnership~~respect ~~(the~~to ~~“Acquisition~~natural ~~Plan”).~~gas ~~For~~derivative ~~additional~~positions ~~information~~that ~~regarding~~will be assumed by Caerus. Under the ~~Acquisition~~same ~~Plan~~PSA, ~~refer~~PDC has agreed to ~~disclosure~~sell ~~included~~to inCaerus PDC's ~~prior~~and ~~filings~~PDC ~~made~~sponsored ~~with~~partnerships' ~~the~~Piceance ~~SEC~~Basin assets and ~~presentations~~certain onnon-core ~~PDC's~~Colorado ~~website.~~oil ~~However~~and gas properties, ~~such~~leasehold ~~information~~mineral ~~shall~~interests ~~not,~~and byrelated ~~reason~~assets. ofBased ~~this~~on ~~reference,~~the beamounts ~~deemed~~allocated to bethis ~~incorporated~~Partnership byin ~~reference~~the inPSA, orPDC ~~otherwise~~determined bethat ~~deemed~~it towas bein ~~part~~the best interest of, this ~~report.~~Partnership ~~Under~~to sell its Piceance Basis assets under the ~~Acquisition~~PSA. ~~Plan,~~The ~~any~~PSA ~~existing~~does ornot ~~future~~include ~~merger~~any ~~offer~~of ~~will~~this bePartnership's ~~subject~~Wattenberg toField ~~the~~assets. ~~terms~~The ~~and~~effective ~~conditions~~date of the ~~related~~transaction ~~merger~~is ~~agreement~~January ~~and~~1, ~~such~~2013. ~~agreement~~The ~~will~~Managing ~~likely~~General ~~contemplate~~Partner ~~the~~intends ~~partnership~~to ~~being~~use ~~merged~~the ~~with~~proceeds ~~and~~from ~~into~~the asale ~~wholly-owned~~for ~~subsidiary~~this ofPartnership's ~~PDC.~~operational ~~Each~~needs, ~~such~~for ~~merger~~the ~~will~~Additional ~~also~~Development bePlan ~~subject~~or distributions to, ~~among~~Partners. ~~other~~As ~~things,~~of ~~PDC~~December ~~having~~31, ~~sufficient available capital~~2012, ~~the~~total ~~economics~~estimated ofproved ~~the~~reserves ~~merger~~related ~~and~~to ~~the~~these ~~approval~~assets bywere a144 ~~majority~~MMcf of ~~the~~natural ~~limited~~gas ~~partnership~~and ~~units~~1 ~~held~~MBbl byof ~~the~~crude ~~non-affiliated~~oil, ~~investor~~for ~~partners~~an aggregate of ~~such~~25 ~~limited~~MBbl ~~partnership.~~of ~~Consummation~~crude ofoil ~~any~~equivalent. ~~proposed~~See ~~merger~~Note of8, aAssets ~~limited~~Held ~~partnership~~for ~~under~~Sale, ~~the~~Divestitures ~~Acquisition~~and ~~Plan~~Discontinued ~~will~~Operations, ~~result~~to inthis ~~the~~Partnership's ~~termination~~unaudited ofcondensed ~~the~~financial ~~existence~~statements ofincluded ~~that~~elsewhere ~~partnership~~in ~~and~~this ~~each~~report ~~non-affiliated~~for ~~investor~~additional ~~partner~~details ~~will~~related ~~receive~~to the ~~right~~planned todivestiture ~~receive~~of athis ~~cash~~Partnership's ~~payment~~Piceance ~~for~~assets. ~~their~~There ~~limited~~can ~~partnership~~be ~~units~~no inassurance that ~~partnership~~this ~~and~~transaction will noclose ~~longer~~as ~~participate~~planned. inIn ~~that~~addition, ~~partnership's~~purchase ~~future~~price ~~earnings~~adjustments ormay reduce this Partnership's ~~economic~~proceeds ~~benefit~~from the transaction.

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 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 the 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 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 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, 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 an attractive rate of return to 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, 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 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 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.

Current estimated costs for these well refracturings or recompletions are between $180,000 and $260,000 per activity. As of September 30, 2012, this Partnership has approximately 18 additional development opportunities remaining. Total withholding for these activities from 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 the 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 September 30, 2012, no funds have been withheld from this Partnership's cash distributions pursuant to the Additional Development Plan.

This Partnership, along with other operators in the Wattenberg Field, is currently experiencing extremely high line pressures due to an oversupply of natural gas and natural gas liquids (NGLs) in the field based upon the main pipeline/processing provider's current take away capacity. The result of the high line pressure is that many of the wells in this field, including this Partnership's wells, have had their production curtailed and the curtailments have reduced the amount of natural gas, crude oil and NGLs produced and sold over the last several months. When natural gas production is curtailed, the curtailment affects the well's ability to lift the liquids out of the well bore.

DCP, an independent midstream company, is the main purchaser of natural gas and NGLs in this field. The Managing General Partner is working closely with DCP, who is implementing a multi-year facility expansion capable of significantly increasing long-term gathering and processing capacity in the Wattenberg Field. However, the Managing General Partner does not expect the impact of this increased capacity to substantially benefit this Partnership until late 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

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 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 this Partnership as a result of lower natural gas sales, a reduction in the estimated quantity of 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 from continuing operations decreased 4926%, or approximately $~~240~~19,000, for the first ~~nine~~three months of ~~2012~~2013 compared to the first ~~nine~~three months of ~~2011~~2012, while sales volumes ~~declined~~from 24continuing operations decreased 32% period-to-period. ~~The~~Partially offsetting this decrease, the average sales price per ~~Mcfe~~barrel of crude oil equivalent ("Boe"), excluding the impact of realized derivative gains, was $352.7822 for the current ~~year~~ period compared to $547.6491 for the same period a year ago. Realized ~~derivative~~ gains from all natural gas ~~sales~~derivatives contributed ~~an additional $1.69 per Mcfe, or~~ approximately $~~113~~26,000, to ~~the~~ total revenues for the first ~~nine~~three months of ~~2012~~2013 compared to ~~an additional $0.23, or~~ approximately $2034,000, from natural gas ~~and~~derivatives ~~crude oil sales~~ for the first ~~nine~~three months of ~~2011. Comparatively, the total per Mcfe price realized, consisting of the average sales price and realized derivative gains, decreased to $5.47 for the first nine months of~~ 2012 ~~from $5~~.87 ~~for the same period of 2011.~~

~~Direct costs~~ - ~~general and administrative decreased by approximately $176,000 during the 2012 nine month period due to the timing of fees for professional services.~~ 13-

-13-

Index

PDC 2002-B ~~LIMITED~~Limited ~~PARTNERSHIP~~Partnership

(A West Virginia Limited Partnership)

Results of Operations

Summary Operating Results

The following table presents selected information regarding this Partnership’s results offrom continuing operations:

	Three months ended September 30,							Nine months ended September 30,
	Three months ended March 31,
	2012		2011			Change		2012		2011			Change
	2013		2012			Change
Number of gross producing wells (end of period)	1411		1411			—		14		14			—
Production(1)
Natural gas (Mcf)	152,~~786~~540		204,~~605~~480			(2343	)%	~~53,168~~		~~64,754~~			~~(18~~	)%
NGLs (Bbl)	~~131~~173		~~416~~265			(6935	)%	~~507~~		~~1,074~~			~~(53~~	)%
Crude oil (Bbl)	~~204~~481		~~911~~567			(7815	)%	~~1,715~~		~~2,630~~			~~(35~~	)%
Natural gas equivalents (Mcfe)(2)	17,796		28,567			(38	)%	66,500		86,978			(24	)%
Crude oil equivalent (Boe)(2)	1,077		1,579			(32	)%
Average Mcfe per day	193		311			(38	)%	243		319			(24	)%
Average Boe per day	12		17			(32	)%
Natural gas, NGLs and crude oil sales
Natural gas	$	267,~~627~~516	$	6711,~~941~~801		(6136	)%	$	~~84,864~~	$	~~206,673~~		~~(59~~	)%
NGLs	37,~~861~~279		1810,~~045~~119			(7928	)%	~~19,879~~		~~52,159~~			~~(62~~	)%
Crude oil	1741,~~023~~448		7553,~~403~~724			(7723	)%	~~146,624~~		~~232,093~~			~~(37~~	)%
Total natural gas, NGLs and crude oil sales	$	4756,~~511~~243	$	~~161~~75,~~389~~644		(7126	)%	$	~~251,367~~	$	~~490,925~~		~~(49~~	)%
Realized gain (loss) on derivatives, net
Realized gain on derivatives, net
Natural gas	$	3426,~~632~~150	$	1434,~~274~~388		~~143~~(24	)%	$	~~112,635~~	$	~~42,229~~		~~167~~	%
Crude oil	—		(5,889		)	(100	)%	—		(22,393		)	(100	)%
Total realized gain on derivatives, net	$	26,150	$	34,388		(24	)%
Total realized gain on derivatives, net	$	34,632	$	8,385		*		$	112,635	$	19,836		*
Average selling price (excluding realized gain on derivatives)
Average selling price (excluding realized gain (loss) on derivatives)
Natural gas (Mcf)	$	2.96	$	2.63		12	%
Natural gas (per Mcf)	$	1.69	$	3.30		(49	)%	$	1.60	$	3.19		(50	)%
NGLs (Bbl)	42.08		38.18			10	%
NGLs (per Bbl)	29.47		43.38			(32	)%	39.21		48.57			(19	)%
Crude oil (per Bbl)	86.17		94.75			(9	)%
Crude oil (per Bbl)	83.45		82.77			1	%	85.50		88.25			(3	)%
Crude oil equivalent (per Boe)	52.22		47.91			9	%
Natural gas equivalents (per Mcfe)	2.67		5.65			(53	)%	3.78		5.64			(33	)%
Average cost per Boe
Average selling price (including realized gain (loss) on derivatives)
Natural gas, NGLs and crude oil production cost(3)	$	27.95	$	13.98		100	%
Natural gas (per Mcf)	$	3.88	$	3.99		(3	)%	$	3.71	$	3.84		(3	)%
Depreciation, depletion and amortization	16.32		30.86			(47	)%
NGLs (per Bbl)	29.47		43.38			(32	)%	39.21		48.57			(19	)%
Operating costs and expenses
Crude oil (per Bbl)	83.45		76.31			9	%	85.50		79.73			7	%
Direct costs - general and administrative	$	30,686	$	28,858		6	%
Natural gas equivalents (per Mcfe)	4.62		5.94			(22	)%	5.47		5.87			(7	)%
Depreciation, depletion and amortization	17,574		48,721			(64	)%
Average cost per Mcfe
Cash distributions	$	7,234	$	9,399		(23	)%
Natural gas, NGLs and crude oil production cost(3)	$	4.17	$	2.00		109	%	$	3.27	$	2.13		54	%
Depreciation, depletion and amortization	1.50		3.14			(52	)%	2.04		3.08			(34	)%
Operating costs and expenses
Direct costs - general and administrative	$	29,086	$	97,302		(70	)%	$	88,982	$	265,091		(66	)%
Depreciation, depletion and amortization	26,663		89,710			(70	)%	135,375		268,148			(50	)%
Cash distributions	$	7,690	$	10,427		(26	)%	$	25,555	$	37,876		(33	)%

*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 this Partnership has an interest by the average percentage of the leasehold or other property interest this Partnership owns.

(2) ~~Six~~One ~~Mcf~~Bbl of ~~natural~~crude ~~gas~~oil or NGL equals ~~one~~six ~~Bbl~~Mcf of ~~crude~~natural ~~oil or NGL~~gas.

⁽³⁾ Represents natural gas, NGLs and crude oil operating expenses, including production taxes.

- 14-

Index

PDC 2002-B Limited Partnership

(A West Virginia Limited Partnership)

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

Bbl - One barrel of crude oil or natural gas liquids ("NGLs") or 42 gallons of liquid volume.

~~Btu~~Boe - ~~British~~Barrels ~~thermal~~of ~~unit~~crude oil equivalent.

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. This Partnership's results of operations depend upon many factors, particularly the price of natural gas, NGLs and crude oil and the Managing General Partner's ability to market this Partnership's production effectively. Natural gas, ~~NGL~~NGLs and crude oil prices are among the most volatile of all commodity prices. These price variations can have a material impact on this Partnership's financial results and capital expenditures.

Natural gas 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 curtailments due to limited capacity on local gathering and processing infrastructure has resulted in capacity constraints. Like most producers, this Partnership relies on major interstate pipeline companies to construct these pipelines to increase capacity, rendering the timing and availability of these facilities beyond this Partnership's control. The price this Partnership receives for its natural gas produced is ~~impacted~~based byon the ~~Managing~~Colorado ~~General~~Interstate ~~Partner's~~Gas ~~transportation,~~("CIG") ~~gathering and processing agreements~~price. This Partnership's ~~currently~~NGL ~~uses~~price ~~the~~is ~~"net-back"~~mainly ~~method~~based ofon ~~accounting~~prices ~~for~~from ~~these~~the ~~arrangements~~Conway ~~related~~hub toin ~~its~~Kansas ~~natural~~where ~~gas sales. This Partnership sells natural gas at~~ the ~~wellhead~~Wattenberg ~~and~~production ~~collects~~is amarketed. ~~price~~Crude ~~and~~oil ~~recognizes~~pricing ~~revenues~~is ~~based~~predominately ondriven by the ~~wellhead~~physical ~~sales~~market, ~~price~~supply ~~since~~and ~~transportation~~demand, ~~costs downstream of~~ the ~~wellhead~~financial ~~are~~markets ~~incurred~~and bynational ~~the purchaser~~ and ~~reflected~~international ~~in the wellhead price~~politics. The ~~net-back~~majority ~~method~~of ~~results~~this inPartnership's ~~the~~crude ~~recognition~~oil ofis asold ~~sales~~on ~~price~~a ~~that~~calendar-year isbasis ~~below~~at ~~the~~a ~~indices~~fixed ~~for~~differential ~~which~~to ~~the~~NYMEX ~~production is based~~pricing.

~~The~~This ~~price~~Partnership ~~this~~currently ~~Partnership~~uses ~~receives~~the ~~for~~"net-back" ~~its~~method ~~natural~~of ~~gas~~accounting ~~produced~~for isthese ~~based~~arrangements onrelated ato ~~market~~its ~~basket~~natural ofgas ~~prices,~~sales. ~~which~~This ~~generally~~Partnership ~~includes~~sells natural gas ~~sold~~ at, ~~near~~the orwellhead ~~below~~and ~~Colorado~~collects ~~Interstate~~a ~~Gas~~price ~~("CIG") prices, as well as other nearby regional prices. The CIG Index,~~ and ~~other~~recognizes ~~indices~~revenues ~~for~~based ~~production~~on ~~delivered~~the towellhead ~~other~~sales ~~Rocky Mountain pipelines, has historically been less than the~~ price ~~received~~as ~~for~~transportation ~~natural~~costs ~~gas~~downstream ~~produced in the eastern regions~~ of the ~~U.S.,~~wellhead ~~which~~are isincurred ~~based~~by ~~on New York Mercantile Exchange ("NYMEX") prices. This negative differential has narrowed over~~ the ~~last~~purchaser ~~few years~~ and isreflected ~~lower~~in ~~than~~the ~~historical~~wellhead ~~variances~~price. The ~~negative~~net-back ~~differential~~method ~~between~~results ~~NYMEX~~in ~~and CIG averaged $0.22 and $0.30 for~~ the ~~nine~~recognition ~~months~~of ~~ended~~a ~~September~~sales ~~30,~~price ~~2012~~that ~~and~~is ~~2011,~~below ~~respectively. In September 2012,~~ the ~~Managing~~indices ~~General Partner renegotiated its marketing agreement~~ for ~~this~~which ~~Partnership's natural gas in~~ the ~~Piceance~~production ~~Basin. This new marketing agreement~~ is ~~expected to add approximately $0~~based.~~40 per MMbtu to this Partnership's Piceance natural gas price realization effective November 1, 2012.~~

~~This~~Recently, ~~Partnership~~a ~~has~~combination ~~experienced~~of aincreased ~~decline~~drilling activity and curtailments due to limited capacity on local gathering and processing infrastructure and, in ~~the~~some ~~price~~periods, ofhigher ~~NGLs~~temperatures, ~~mainly~~has atresulted ~~Conway~~in ~~hub~~capacity constraints in ~~Kansas~~the ~~where~~Wattenberg Field. The Managing General Partner anticipates that this Partnership's ~~Wattenberg~~will again experience high line pressures in 2013, particularly in the summer months, as field-wide production isvolumes ~~marketed~~from the ongoing development of the successful horizontal Wattenberg play outpace current midstream capacity. ~~This~~The Managing General Partner is ~~primarily~~working ~~due~~closely towith the ~~increase~~primary midstream provider in ~~ethane~~the Wattenberg Field who is implementing a multi-year facility expansion capable of significantly increasing long-term gathering and ~~propane~~processing ~~volumes~~capacity. ~~flowing~~The Managing General Partner expects reduced line pressures to ~~Conway~~substantially benefit this Partnership in late 2013, concurrent with the startup of the LaSalle gas plant and associated field compressor stations. Like most producers, this Partnership relies on its third-party midstream service providers to construct compression, gathering and processing facilities to keep pace with production growth. As a ~~limited~~result, ~~market~~the ~~for~~timing and availability of these ~~products~~facilities ~~out~~is ofbeyond this Partnership's or the ~~area.~~Managing General Partner's control.

Crude oil pricing is predominately driven by the physical market, supply and demand, the financial markets and national and international politics. The majority of this Partnership's crude oil is sold on a calendar-~~year~~ ~~basis at a fixed differential to NYMEX pricing.~~ 15-

-15-

Index

PDC 2002-B ~~LIMITED~~Limited ~~PARTNERSHIP~~Partnership

(A West Virginia Limited Partnership)

~~Nine~~Three months ended ~~September 30~~March 31, ~~2012~~2013 as compared to ~~nine~~three months ended ~~September 30~~March 31, ~~2011~~2012

For the ~~nine~~three months ended ~~September 30~~March 31, ~~2012~~2013 compared to the same period ofin ~~2011~~2012, natural gas, NGLs and crude oil ~~sales~~production ~~volumes~~from continuing operations, on an energy equivalency-basis, decreased 2432% primarily 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 $~~240~~19,000, or 4926%, decrease in sales from continuing operations for the ~~2012~~2013 ~~nine~~three month period as compared to the prior year period was a reflection of sales volume decreases of 2432% ~~and~~partially aoffset ~~decline~~by an increase in the average sales ~~prices~~price of 339%. The average sales price per ~~Mcfe~~Boe, excluding the impact of realized derivative gains, was $352.7822 for the current year ~~nine~~three month period compared to $547.6491 for the same period a year ago.

Natural gas, NGLs and crude oil sales from continuing operations for the ~~nine~~three months ended ~~September 30~~March 31, ~~2012~~2013 decreased by 5936%, 62 28% and 3723%, respectively, as compared to the ~~nine~~three months ended ~~September 30~~March 31, ~~2011~~2012. The decrease in natural gas sales resulted from ~~decreased~~lower ~~prices~~natural ~~per~~gas ~~Mcf~~production volumes of 5043%, ~~and~~partially ~~lower~~offset ~~natural~~by ~~gas~~increased ~~production~~prices ~~volumes~~per Mcf of 1812%. The decrease in NGLs sales was due to a decrease of 5335% in ~~NGLs~~ production volumes, ~~and~~partially tooffset aby ~~decrease~~an increase in the average commodity price per Bbl of 1910%. The crude oil sales decrease was due ~~primarily~~ to a ~~sales~~production volume decrease of 3515% and a decrease in the average commodity price per Bbl of 39%.

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

This Partnership ~~used~~uses various derivative instruments to manage fluctuations in natural gas ~~and crude oil~~ prices. This Partnership ~~had~~has in place collars, fixed-price swaps and/or basis swaps on a portion of this Partnership's estimated natural gas ~~and crude oil~~ production. This Partnership ~~sold~~sells its natural gas ~~and crude oil~~ at similar prices to the indices inherent in this Partnership's derivative instruments. As a result, for the volumes underlying this Partnership's derivative positions, this Partnership ultimately ~~realized~~realizes a price related to its collars of no less than the floor and no more than the ceiling and, for this Partnership's commodity swaps, this Partnership ultimately ~~realized~~realizes 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 this Partnership's natural gas ~~and crude oil~~ production. See Note 4, Fair Value ~~Measurements~~of ~~and~~Financial ~~Disclosures~~Instruments, and Note 5, Derivative Financial Instruments, to ~~the~~this Partnership's unaudited condensed financial statements included elsewhere in this report for additional details of this Partnership's derivative financial instruments.

-16-

Index

PDC 2002-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

	Three months ended September 30,						Nine months ended September 30,
	Three months ended March 31,
	2012			2011			2012			2011
	2013			2012
Commodity price risk management gain (loss), net:
Realized gains (losses)
Realized gains
Natural gas	$	3426,~~632~~150		$	1434,~~274~~388		$	~~112,635~~		$	~~42,229~~
Crude oil	—			(5,889		)	—			(22,393		)
Total realized gains, net	26,150			34,388
Total realized gains, net	34,632			8,385			112,635			19,836
Unrealized gains (losses)
Unrealized gains (losses)
Reclassification of realized gains included in
Reclassification of realized gains included in
prior periods unrealized gains	(26,669		)	(30,872		)
prior periods unrealized gains	(34,175		)	(4,814		)	(89,607		)	(18,433		)
Unrealized gains (losses) for the period	(19,426		)	57,608
Unrealized gains (losses) for the period	(14,836		)	53,439			6,884			70,562
Total unrealized gains (losses), net	(46,095		)	26,736
Total unrealized gains (losses), net	(49,011		)	48,625			(82,723		)	52,129
Total commodity price risk management gain (loss), net	$	(19,945	)	$	61,124
Total commodity price risk management gain (loss), net	$	(14,379	)	$	57,010		$	29,912		$	71,965

~~Nine~~- ~~months ended September 30, 2012 as compared to nine months ended September 30, 2011~~ 16-

Realized gains of approximately $113,000 recognized in the nine months ended September 30, 2012 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. For the nine months ended September 30, 2012, realized gains on natural gas, exclusive of basis swaps, were approximately $183,000. These gains were offset in part by realized losses of approximately $70,000 on this Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted-average price was narrower than the strike price of this Partnership's basis swaps.

Unrealized gains of approximately $7,000 for the nine months ended September 30, 2012 were primarily related to the downward shift in the natural gas forward curve and its impact on the fair value of this Partnership's open positions, offset in part by the narrowing of the CIG basis forward curve. For the nine-month period ended September 30, 2012, unrealized gains on this Partnership's natural gas positions were approximately $11,000, offset by unrealized losses on this Partnership's CIG basis swaps of approximately $4,000.

Realized gains recognized in the nine 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 $103,000 for the nine months ended 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.

Unrealized gains during the nine 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 shifts downward in the natural gas curves resulted in an unrealized gain of approximately $87,000 and the shift downward in the crude oil curve resulted in an unrealized gain of approximately $5,000 during the nine months ended September 30, 2011. These unrealized gains were partially offset by unrealized losses of approximately $21,000 on this Partnership's CIG basis protection swaps as the forward basis differential between the NYMEX and CIG had continued to narrow.

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

Realized gains of approximately $35,000 recognized in the three months ended September 30, 2012 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. For the three months ended September 30, 2012, realized gains on natural gas, exclusive of basis swaps, were approximately $57,000. These gains were offset in part by realized losses of $22,000 on this Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted-average price was narrower than the strike price of this Partnership's basis swaps.

-17-

Index

PDC 2002-B ~~LIMITED~~Limited ~~PARTNERSHIP~~Partnership

(A West Virginia Limited Partnership)

~~Unrealized~~Three ~~losses~~months ofended ~~approximately $15~~March 31,~~000~~ ~~for~~2013 ~~the~~as compared to three months ended ~~September~~March 3031, 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 open positions and by unrealized losses on CIG basis protection swaps due to the narrowing of the CIG basis forward curve.

Realized gains of approximately $26,000 recognized in the three months ended ~~September 30~~March 31, ~~2011~~2013 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~~For onthe ~~natural~~three ~~gas~~months ~~settlements~~ended ~~were~~March ~~approximately~~31, ~~$38~~2013,~~000~~ ~~for~~realized ~~the~~gains ~~three~~on ~~months~~natural ~~ended~~gas, ~~September 30~~exclusive of basis swaps, ~~2011~~were approximately $49,000. These gains were offset in part by anrealized ~~approximate~~losses of approximately $2423,000 ~~loss~~ on 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. This~~ Partnership's ~~also~~basis ~~realized an approximate $6,000 loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price~~swaps.

Unrealized ~~gains~~losses ~~during~~of ~~the~~approximately ~~three~~$19,000 ~~months~~for the quarter ended ~~September 30~~March 31, ~~2011~~2013 were primarily related to the ~~shifts~~upward shift in the natural gas forward ~~curves~~curve and ~~their~~its 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~~Realized ~~following~~gains ~~table~~of ~~presents~~approximately $34,000 recognized in the three months ended March 31, 2012 were primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of this Partnership's natural gas derivative positions. For the three months ended March 31, 2012, realized gains on natural gas, exclusive of basis swaps, were approximately $59,000. These gains were offset in ~~effect~~part asby realized losses of ~~September 30~~approximately $25,000 ~~2012:~~on this Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted-average price was narrower than the strike price of this Partnership's basis swaps.

	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 atSeptember 30, 2012(2)
		Floors		Ceilings
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

Unrealized gains of approximately $58,000 for the three months ended March 31, 2012 were primarily related to the downward shift in the natural gas forward curve and its impact on the fair value of this Partnership's open positions.

The following table presents this Partnership's derivative positions in effect as of March 31, 2013:



	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			Fair Value at March 31, 2013
Commodity/ Index	Quantity (Gas-MMBtu⁽¹⁾)	Weighted- Average Contract Price		Quantity (Gas-MMBtu⁽¹⁾)	Weighted- Average Contract Price			Fair Value at March 31, 2013

Natural Gas
NYMEX
04/01 - 06/30/2013	12,786	$	7.12	12,786	$	(1.88	)	$	19,153
07/01 - 09/30/2013	12,614	7.12		12,614	(1.88		)	17,485
10/01 - 12/31/2013	12,318	7.12		12,318	(1.88		)	15,515
Total⁽²⁾	37,718			37,718				$	52,153

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

(2) AsPursuant ofto ~~September 30~~a purchase and sale agreement entered into on February 4, ~~2012~~2013, approximately 1%26,952 MMBtu of the ~~fair~~above ~~value~~Fixed-Price Swaps, and an equal amount of ~~this~~CIG ~~Partnership's~~Basis ~~derivative~~Protection ~~assets~~Swaps, ~~were~~is ~~measured~~expected ~~using~~to ~~significant~~be ~~unobservable~~assigned ~~inputs~~to ~~(Level~~certain 3)affiliates of Caerus upon the closing of the planned sale. There can be no assurance that this transaction will close as planned. See Note 48, ~~Fair~~Assets ~~Value~~held ~~Measurements~~for Sale, Divestiture and ~~Disclosures~~Discontinued Operations, to ~~the~~this ~~unaudited~~Partnership's ~~condensed~~ financial statements included elsewhere in this report for additional information regarding the planned divestiture of certain of this Partnership's natural gas properties.

~~Natural~~- ~~Gas, NGLs and Crude Oil Production Costs~~17-

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.

-18-

Index

PDC 2002-B ~~LIMITED~~Limited ~~PARTNERSHIP~~Partnership

(A West Virginia Limited Partnership)

~~Nine~~Natural ~~months ended September 30~~Gas, ~~2012~~NGLs asand ~~compared~~Crude toOil ~~nine~~Production ~~months ended September 30, 2011~~ Costs

~~Natural~~Generally, natural gas, NGLs and crude oil production costs ~~for~~vary ~~the~~with ~~nine~~changes ~~months~~in ~~ended~~total ~~September~~natural 30gas, ~~2012~~NGLs ~~increased~~and bycrude ~~approximately~~oil ~~$32,000~~sales ~~compared~~and toproduction volumes. Production taxes are estimates by the ~~same~~Managing ~~period~~General inPartner ~~2011~~based on tax rates determined using published information. ~~Lease~~These ~~operating~~estimates ~~costs~~are ~~were~~subject ~~higher~~to revision based on actual amounts determined during future filings by ~~approximately~~the ~~$54,000~~Managing inGeneral Partner with the ~~current~~taxing ~~period~~authorities. asProduction ~~workovers~~taxes ~~and~~vary ~~tubing~~directly ~~repair~~with ~~activities~~total ~~were~~natural ~~collectively~~gas, ~~lower~~NGLs inand ~~2011.~~crude ~~Higher~~oil ~~lease~~sales. ~~operating~~Transportation costs ~~were~~vary ~~partially~~directly ~~offset~~with byproduction ~~lower~~volumes. ~~revenue-~~Fixed ~~and~~monthly ~~volume-based~~well operating costs byincrease ~~approximately~~on ~~$20,000~~a inper ~~2012,~~unit ~~consistent~~basis ~~with~~as ~~sales~~production ~~and~~decreases ~~production~~per ~~declines~~the ~~from~~historical ~~2011~~decline curve. ~~Natural~~In ~~gas~~addition, ~~NGLs~~general ~~and~~oil ~~crude~~field ~~oil~~services ~~production~~and ~~costs~~all ~~per~~other ~~Mcfe~~costs ~~increased~~vary toand ~~$3.27~~can ~~during~~fluctuate ~~2012~~based ~~from~~on ~~$2.13~~services inrequired, ~~2011~~but ~~due~~are expected to ~~lower~~increase ~~volumes~~as wells age and ~~increased~~require ~~costs~~more extensive repair and maintenance.

~~Three~~These ~~months~~costs ~~ended~~include ~~September 30,~~water ~~2012~~hauling asand ~~compared~~disposal, toequipment ~~three~~repairs ~~months~~and ~~ended~~maintenance, ~~September 30~~snow removal, ~~2011~~environmental compliance and remediation and service rig workovers.

~~Natural~~Three ~~gas, NGLs and crude oil production costs for the three~~ months ended ~~September~~March 3031, ~~2012~~2013 ~~increased~~as ~~by approximately $17,000~~ compared to ~~the~~three ~~same~~months ~~period~~ended ~~in 2011. Lease operating costs were lower by approximately $26~~March 31,~~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~~Natural ~~Costs-General~~gas, NGLs and ~~Administrative~~crude oil production costs for the three months ended March 31, 2013 increased approximately $8,000 compared to the same period in 2012 due primarily to higher lease operating costs in 2013 as workover activities were collectively lower in 2012. Natural gas, NGLs and crude oil production costs per Boe increased to $27.95 during 2013 from $13.98 in 2012 due to lower volumes.

~~Nine months ended September 30~~Depreciation, ~~2012~~Depletion asand ~~compared to nine months ended September 30, 2011~~ Amortization

~~Direct~~Three ~~costs-general~~months ~~and~~ended ~~administrative consist primarily of professional fees for financial statement audits~~March 31, ~~income~~2013 ~~tax~~as ~~return~~compared ~~preparation,~~to ~~independent~~three ~~engineers' reserve reports and legal matters. Direct costs-general and administrative decreased during the nine~~ months ended ~~September 30~~March 31, 2012 ~~compared to the same period in 2011 by approximately $176,000, principally due to the timing of fees for professional services.~~

~~Three~~Depreciation, depletion and amortization ("DD&A") expense related to natural gas and crude oil properties is directly related to proved reserves and production volumes. DD&A expense for continuing operations decreased approximately $31,000 for the three months ended ~~September~~March 3031, ~~2012~~2013 as compared to the three months ended ~~September~~ March 31, 2012 due to lower production volumes and by a decreased DD&A expense rate in 2013. The DD&A expense rate per Boe decreased to $16.32 for the 2013 three months compared to $30.86 during the same period in 2012 due to the effect of an impairment recorded for the Wattenberg Field assets as of December 31, ~~2011~~2012.

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

~~Depreciation~~On February 4, ~~Depletion~~2013, the Managing General Partner entered into a purchase and ~~Amortization~~sale ~~("DD&A")~~agreement with Caerus, pursuant to which this Partnership agreed to sell to Caerus its Piceance Basin assets for cash consideration of approximately $431,000, subject to post-closing adjustments. Following the planned sale, this Partnership will not have significant continuing involvement in the operations of, or cash flows from, the Piceance Basin assets. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the unaudited condensed statement of operations for all periods presented.

~~Nine~~See ~~months~~Note ~~ended~~8, ~~September~~Assets 30Held for Sale, ~~2012~~Divestitures asand ~~compared~~Discontinued Operations, to ~~nine~~the ~~months~~accompanying ~~ended~~unaudited ~~September~~condensed ~~30,~~financial ~~2011~~statements included elsewhere in this report for additional information regarding the planned sale of this Partnership's Piceance Basin assets.

The ~~DD&A~~table ~~expense~~below ~~rate~~presents ~~per~~production ~~Mcfe~~data ~~decreased~~related to $2.04 for the nine months ended September 30, 2012, compared to $3.08 during the same period in 2011. The decrease in the per Mcfe rates for the 2012 period compared to the 2011 period was due to a combination of the effect of the 2011 impairment of this Partnership's Piceance Basin assets ~~and~~that ~~the~~are ~~change~~planned ~~in the production mix from the Piceance Basin relative~~ to ~~the~~be ~~Wattenberg~~divested ~~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~~that ~~expense~~are ~~rate~~classified ~~resulted~~as indiscontinued ~~an overall decreased DD&A expense of approximately $133,000 for the 2012 nine months compared to the same 2011 period.~~ operations:

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



	Three Months Ended March 31,
Discontinued Operations	2013	2012
Production
Natural gas (Mcf)	13,902	15,088
Crude oil (Bbl)	10	9
Crude oil equivalent (Boe)	2,327	2,524

~~The~~- DD&A expense rate per Mcfe decreased to $1.50 for the three months ended September 30, 2012, compared to $3.14 during the same period in 2011. The decrease in the per Mcfe rates for the 2012 period compared to the 2011 period was due to a combination of the effect of the 2011 impairment of 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 $63,000 for the 2012 three months compared to the same 2011 period. 18-

-19-

Index

PDC 2002-B ~~LIMITED~~Limited ~~PARTNERSHIP~~Partnership

(A West Virginia Limited Partnership)

Financial Condition, Liquidity and Capital Resources

This Partnership's primary ~~source~~sources of cash for the ~~nine~~three ~~months~~month periods ended ~~September~~March 3031, 2013 and 2012 ~~was~~were operating activities, which include the sale of natural gas, NGLs and crude oil production, and to 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~~March 3031, ~~2012~~2013, this Partnership had natural gas derivative positions in place covering ~~79%~~all of its expected natural gas production for the remainder of ~~2012~~2013 at an average price of $5.0524 per Mcf. This Partnership has no ~~NGL~~NGLs 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~~2013 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~~activities.

Working Capital

At ~~September~~March 3031, ~~2012~~2013, this Partnership had a working capital surplus of approximately $7265,000, compared to a working capital surplus of approximately $7184,000 at December 31, ~~2011~~2012. The ~~increase~~decrease of approximately $119,000 was primarily due to the following changes:

• accounts receivable ~~decreased~~increased by approximately $6324,000 between ~~September~~March 3031, ~~2012~~2013 and December 31, ~~2011~~2012;

• ~~realized~~oil ~~and~~inventory ~~unrealized derivative gains receivable~~ decreased by approximately $97,000 between ~~September~~March 3031, ~~2012~~2013 and December 31, ~~2011~~2012; ~~and~~

• ~~amounts~~realized ~~due to Managing General Partner-other, net, excluding natural gas, NGLs~~ and ~~crude~~unrealized ~~oil sales received from third parties and realized~~ derivative gains, receivable decreased by approximately $7143,000 between ~~September~~March 3031, ~~2012~~2013 and December 31, ~~2011.~~2012; and

~~Working~~• ~~capital~~amounts isdue ~~expected~~ to ~~increase~~Managing ~~during~~General ~~periods~~Partner-other, ofnet, ~~Additional~~excluding ~~Development~~natural ~~Plan~~gas, ~~funding~~NGLs and ~~decrease~~crude ~~during~~oil ~~periods~~sales ~~when~~received ~~payments~~from ~~are~~third ~~made~~parties ~~for~~and ~~refracturing~~realized orderivative ~~recompletion~~gains, ~~activities.~~decreased by approximately $7,000 between March 31, 2013 and December 31, 2012.

~~Cash~~Additional ~~Flows~~Development Plan activities, which would include investments in equipment and services to complete refracturing and recompletion opportunities, are suspended until pipeline capacity improves. If the Additional Development Plan commences, funding will be provided by the withholding of distributable cash flows from the Managing General Partner and Investor Partners. Future working capital balances are expected to fluctuate by increasing during periods of Additional Development Plan funding and decreasing during periods when payments are made for refracturing or recompletion activities.

~~Operating~~- ~~Activities~~19-

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.

-20-

Index

PDC 2002-B ~~LIMITED~~Limited ~~PARTNERSHIP~~Partnership

(A West Virginia Limited Partnership)

~~Net~~Cash 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:Flows

•Operating ~~a decrease in natural gas, NGLs and crude oil sales receipts of approximately $198,000;~~Activities

•This anPartnership's ~~increase~~cash inflows from operating activities are primarily impacted by commodity ~~price~~prices, ~~risk~~production ~~management~~volumes, realized ~~gain~~gains ~~receipts~~and oflosses ~~approximately~~from ~~$70~~derivative positions,~~000;~~ operating costs and direct costs-general and administrative expenses. The key components for the changes in this Partnership's cash flows from operating activities are described in more detail in Results of Operations above.

•Net acash ~~decrease~~flows infrom ~~production~~operating ~~costs~~activities ~~and~~were ~~direct~~approximately ~~costs-general~~$7,000 ~~and~~for ~~administrative~~the ~~payments~~three ofmonths ended March 31, 2013 compared to approximately $~~100~~10,000 for the comparable period in 2012. The increase of approximately $3,000 in cash from operating activities was due primarily to the following:


•	a decrease in natural gas, NGLs and crude oil sales receipts of approximately $61,000;


•	an increase in commodity price risk management realized gain receipts of approximately $4,000; and


•	a decrease in production costs and direct costs-general and administrative payments of approximately $54,000.

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~~There ~~amounts~~ were ~~approximately~~no ~~$3,000~~investing ~~and~~activities ~~$18,000~~ for the ~~nine~~three months ended ~~September~~March 3031, ~~2012~~2013. ~~and~~These ~~2011~~amounts were not significant during the three months ended March 31, ~~respectively~~2012.

Financing Activities

This Partnership initiated monthly cash distributions to investors in March 2003 and has distributed $9.5 million through ~~September~~March 3031, ~~2012~~2013. The table below presents cash distributions to 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 this Partnership and Investor Partner distributions include amounts distributed to Investor Partners for their 80% ownership share in this Partnership, as well as amounts distributed to the Managing General Partner for limited partnership units repurchased.

Distributions
Three months ended September 30,	Managing General Partner		Investor Partners		Total
Three months ended March 31,	Managing General Partner		Investor Partners		Total
2012	$	748	$	6,942	$	7,690
2013	$	527	$	6,707	$	7,234
2011	1,021		9,406		10,427
2012	950		8,449		9,399
Nine months ended September 30,	Managing General Partner		Investor Partners		Total
2012	$	2,550	$	23,005	$	25,555
2011	3,596		34,280		37,876

~~The~~Three ~~decrease in total distributions for the three~~ months ended ~~September 30~~March 31, ~~2012~~2013 as compared to ~~2011~~three ismonths ~~primarily~~ended ~~due~~March 31, ~~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.~~

The decrease in total distributions for the ~~nine~~three months ended ~~September 30~~March 31, ~~2012~~2013 as compared to ~~2011,~~2012 is primarily due to ~~the~~a decrease in cash flows from operating activities during ~~2012, partially offset by the decrease in capital expenditures for natural gas and crude oil properties~~2013.

Beginning in November 2009, when the Investor ~~Partner~~Partners'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~~668 and $~~3,979~~929 for the ~~nine~~three months ended ~~September~~March 3031, ~~2012~~2013 and ~~2011~~2012, respectively, as a result of the Preferred Cash Distribution made under the terms in Section 4.02. ~~Because~~The ~~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~~continued ~~likely to continue~~ until February 2013, when the provision ~~expires~~expired under the terms of the Agreement.

Off-Balance Sheet Arrangements

As of ~~September~~March 3031, ~~2012~~2013, 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 this Partnership's financial condition, results of operations, liquidity, capital expenditures or capital resources.

-21 20-

Index

PDC 2002-B ~~LIMITED~~Limited ~~PARTNERSHIP~~Partnership

(A West Virginia Limited Partnership)

Commitments and Contingencies

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

Recent Accounting Standards

See Note 2, Recent Accounting Standards, to the accompanying unaudited condensed financial statements included elsewhere 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 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 this Partnership's ~~2011~~2012 Form 10-K.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

Item 4. Controls and Procedures

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

(a) Evaluation of Disclosure Controls and Procedures

As of ~~September~~March 3031, ~~2012~~2013, PDC, as Managing General Partner on behalf of 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 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 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 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 this Partnership's disclosure controls and procedures were effective as of ~~September~~March 3031, ~~2012~~2013.

(b) Changes in Internal Control over Financial Reporting

During the three months ended ~~September~~March 3031, ~~2012~~2013, PDC, the Managing General Partner, made no changes in 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, this Partnership's internal control over financial reporting.

-22 21-

Index

PDC 2002-B ~~LIMITED~~Limited ~~PARTNERSHIP~~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 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 ~~September~~March 3031, ~~2012~~2013:

Period	Total Number of Units Repurchased	Average Price Paid Per Unit
July 1 - 31, 2012	3.13	$	202
January 1 - 31, 2013	0.25	$	400
August 1 - 31, 2012	—	—
February 1 - 28, 2013	0.25	200
September 1 - 30, 2012	—	—
March 1 - 31, 2013	0.25	200
Total	30.1375	$	~~202~~267

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

-23 22-

Index

PDC 2002-B ~~LIMITED~~Limited ~~PARTNERSHIP~~Partnership

(A West Virginia Limited Partnership)

Item 6. Exhibits Index

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 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.

10.1

Purchase and Sale Agreement by and among PDC Energy, Inc., affiliated partnerships and certain affiliates of Caerus Oil and Gas LLC, dated February 4, 2013.

10-Q

000-07246

10.1

5/1/2013

31.2

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

31.1

Certification by Chief Executive Officer of PDC Energy, Inc., the Managing General Partner of this Partnership, pursuant to Rule 13a-14(a)/15d-14(a) 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 this Partnership, pursuant to Rule 13a-14(a)/15d-14(a) 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 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 23-

Index

PDC 2002-B ~~LIMITED~~Limited ~~PARTNERSHIP~~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~~TrimbleChief ~~and~~Executive ~~Chief~~Officer ~~Executive~~and ~~Officerof~~Presidentof PDC Energy, Inc. ~~November~~May 810, ~~2012~~2013

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 and President	~~November~~May 810, ~~2012~~2013
James M. Trimble	PDC Energy, Inc. Managing General Partner of the Registrant
	(principal executive officer)
/s/ Gysle R. Shellum	Chief Financial Officer	~~November~~May 810, ~~2012~~2013
Gysle R. Shellum	PDC Energy, Inc. Managing General Partner of the Registrant
	(principal financial officer)
/s/ R. Scott Meyers	Chief Accounting Officer	~~November~~May 810, ~~2012~~2013
R. Scott Meyers	PDC Energy, Inc. Managing General Partner of the Registrant
	(principal accounting officer)

-25 24-

Filing Compare · PDC 2002 B LTD PARTNERSHIP