UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

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

For the quarterly period ended ~~September~~March 3031, ~~2010~~2011

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

FOR THE TRANSITION PERIOD ____________ TO ____________

Commission File Number 000-50616

PDC 2003-B Limited Partnership ~~(Exact name of registrant as specified in its charter)~~

~~West Virginia~~ (~~State~~Exact orname ~~other jurisdiction~~ of ~~incorporation~~registrant oras ~~organization)~~specified ~~55-0825013~~in ~~(I.R.S.~~its ~~Employer Identification No.~~charter)

1775 Sherman Street, Suite 3000, Denver, Colorado 80203 (Address of principal executive offices) (Zip code)


West Virginia		55-0825013
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

~~(303)~~1775 ~~860-5800~~Sherman ~~(Registrant’s~~Street, ~~telephone~~Suite ~~number~~3000, ~~including~~Denver, ~~area code)~~Colorado 80203

~~Indicate by check mark whether the registrant~~ (1)Address ~~has filed all reports required to be filed by Section 13 or 15(d)~~ of ~~the~~principal ~~Securities~~executive ~~Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such files~~offices) ~~and~~ (2)Zip ~~has been subject to such filing requirements for the past 90 days. Yes o No x~~code)

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (~~§232.405 of this chapter~~303) ~~during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o~~860-5800

~~Indicate~~(Registrant's bytelephone ~~check mark whether the registrant is a large accelerated filer~~number, anincluding ~~accelerated~~area filer, a non-accelerated filer or a smaller reporting company. See the definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act:code)

~~Large~~Indicate ~~accelerated~~by ~~filer~~check omark ~~Accelerated~~whether ~~filer~~the oregistrant ~~Non-accelerated~~(1) ~~filer~~has ofiled ~~Smaller~~all ~~reporting~~reports ~~company~~required xto 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.

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

AsIndicate ofby ~~September~~check ~~30,~~mark ~~2010~~whether the ~~Partnership~~registrant ~~had~~has ~~867.33~~submitted ~~units~~electronically ofand ~~limited~~posted ~~partnership~~on ~~interest~~its corporate Web site, if any, every Interactive Data File required to be submitted and noposted ~~units~~pursuant to Rule 405 of ~~additional~~Regulation ~~general~~S-T ~~partnership~~(§232.405 ~~interest~~of ~~outstanding~~this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ 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 the 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 þ

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

As of March 31, 2011 the Partnership had 867.33 units of limited partnership interest and no units of additional general partnership interest outstanding.

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

INDEX TO REPORT ON FORM 10-Q

		Page	~~Page~~
PART I – FINANCIAL INFORMATION	~~PART I – FINANCIAL INFORMATION~~
	Note Regarding Forward-Looking Statements		1
	Special Note Regarding Forward-Looking Statements	1
Item 1.	Financial Statements (unaudited)
	Condensed Balance Sheets (unaudited)	3	2
	Condensed Statements of Operations (unaudited)	4	3
	Condensed Statements of Cash Flows (unaudited)	5	4
	Notes to Unaudited Condensed Financial Statements	6	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11	12
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	21	23
Item 4.	Controls and Procedures	21	24
PART II – OTHER INFORMATION	~~PART II – OTHER INFORMATION~~
Item 1.	Legal Proceedings	23	25
Item 1A.	Risk Factors	23	25
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	23	25
Item 3.	Defaults Upon Senior Securities	23	25
Item 4.	[Removed and Reserved]	23	25
Item 5.	Other Information	23	25
Item 6.	Exhibits Index	24	26
	SIGNATURES	25	29

Index

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This periodic report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (~~the~~ “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”) regarding PDC 2003-BA Limited Partnership’s (~~the~~ “Partnership” or the “Registrant”) business, financial condition, and results of operations. Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, is the Managing General Partner of the Partnership. All statements other than statements of historical facts included in and ~~prospects~~incorporated by reference into this report are “forward-looking statements” within the meaning of the safe harbor provisions of the United States Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein, which include statements of estimated natural gas, natural gas liquid(s) or “NGL(s)”, and crude oil production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and the Managing General Partner’s strategies, plans and objectives. However, these 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:

~~All~~· ~~statements~~changes ~~other than statements of historical facts included~~ in and incorporated by reference into this report are forward-looking statements. 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, which include statements of estimated natural gas and oil production ~~and~~volumes ~~reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures~~ and ~~the~~worldwide Managing General Partner Petroleum Development Corporation’s (“PDC”) strategies, plans and objectives. However, these words are not the exclusive means of identifying forward-looking statements herein. PDC now conducts business under the name “PDC Energy.”demand;

~~Although~~· ~~forward-looking~~volatility ~~statements~~of ~~contained~~commodity inprices ~~this~~for 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 risks and uncertainties incidental to the development, production and marketing of natural gas and ~~oil,~~crude 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:oil;

●· changes in ~~production~~estimates ~~volumes,~~of ~~worldwide~~proved ~~demand, and commodity prices for natural gas and oil~~reserves;

●· ~~changes~~inaccuracy inof reserve estimates ofand ~~proved~~expected ~~reserves~~production rates;

●· declines in the ~~values~~value of the Partnership’s natural gas and crude oil properties resulting ~~from~~in impairments;

●· the ~~timing~~availability ~~and extent~~ of ~~the~~ Partnership’s ~~success~~future incash ~~further~~flows ~~developing~~for ~~and~~investor ~~producing~~distributions ~~the~~or ~~Partnership’s~~funding ~~natural~~of ~~gas~~refracturing ~~and oil reserves~~activities;

●· the ~~Managing~~timing ~~General~~and ~~Partner’s~~extent ~~ability~~of tothe ~~acquire~~Partnership’s ~~drilling~~success ~~rig~~in ~~services,~~further ~~supplies~~developing and ~~services~~producing atthe ~~reasonable~~Partnership’s ~~prices~~reserves;

●· ~~risks~~the ~~incident~~Managing toGeneral ~~the~~Partner’s ~~refracturing~~ability ~~and~~to ~~operation~~acquire ofdrilling ~~natural~~rig ~~gas~~services, supplies and ~~oil~~services ~~wells~~at reasonable prices;

●· ~~future~~risks ~~production~~incidental ~~and~~to the refracturing ~~costs~~and operation of natural gas and crude oil wells;

●· the availability of ~~Partnership~~sufficient ~~future~~pipeline ~~cash~~and ~~flows~~other ~~for~~transportation ~~investor~~facilities ~~distributions~~to orcarry ~~funding~~Partnership production and the impact of ~~Well~~these ~~Refracturing~~facilities ~~Plan~~on ~~activities~~price;

●· the ~~availability~~effect of ~~sufficient~~existing ~~pipeline~~ and ~~other~~future ~~transportation~~laws, ~~facilities~~governmental toregulations ~~carry~~and ~~Partnership~~the ~~production~~political and ~~the~~economic ~~impact~~climate of ~~these~~the ~~facilities~~U.S. onas ~~price~~well as other oil producing countries throughout the world;

●· ~~the~~changes ~~effect~~in ofenvironmental ~~existing and future~~ laws, ~~governmental~~the ~~regulations~~regulation and ~~the~~enforcement ~~political~~of ~~and~~those ~~economic~~laws ~~climate~~and of the ~~United~~costs ~~States~~to ofcomply ~~America,~~with orthose ~~U.S.~~laws;

●· ~~changes~~the inimpact of environmental ~~laws~~events, ~~and~~governmental responses to the ~~regulations~~events and ~~enforcement~~the ~~related~~Managing toGeneral ~~those~~Partner’s ~~laws~~ability insure adequately against such events;

●· ~~the~~competition ~~identification~~in ofthe ~~and~~oil ~~severity of environmental events~~ and ~~governmental~~gas ~~responses to the events~~industry;

●· the ~~effect~~success of ~~natural~~the ~~gas~~Managing ~~and~~General Partner in marketing the Partnership’s oil ~~derivatives~~and ~~activities~~gas;

●· the ~~availability~~effect of ~~funding~~natural ~~for~~gas ~~the consideration payable by PDC~~ and ~~its~~crude ~~wholly-owned~~oil ~~subsidiary~~derivative ~~to consummate the prospective mergers under the Acquisition Plan, and the timing of consummating any such mergers if at all~~activities;

●· ~~conditions~~the inavailability of funding for the ~~capital~~consideration ~~markets;~~payable by PDC and its wholly-owned subsidiary to consummate the prospective mergers of the 2005 partnerships and the timing of consummating these mergers, if at all;

●· losses possible from pending or future litigation.; and

~~Further,~~· the ~~Partnership~~success ~~urges~~of ~~the~~strategic ~~reader to carefully review and consider the cautionary statements made in this report~~plans, ~~the~~expectations ~~Partnership’s annual reports on Form 10-K~~ and ~~Form~~objectives ~~10-K/A~~ for ~~the~~future ~~year~~operations ended December 31, 2009 filed with the Securities and Exchange Commission, or SEC, on August 3 and August 27, 2010 (“2009 Form 10-K”or “2009 Form 10-K/A,” respectively) and the Partnership’s other filings with the SEC and public disclosures. The Partnership cautions you not to place undue reliance on forward-looking statements, which speak only as of the ~~date~~Managing ~~made. Other~~General than as required under the securities laws, the Partnership undertakes no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated eventsPartner.

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Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Further, the Partnership urges the reader to carefully review and consider the cautionary statements and disclosures made in this report, the Partnership’s annual report on Form 10-K for the year ended December 31, 2010 filed with the Securities and Exchange Commission (“SEC”) on March 30, 2011 (“2010 Form 10-K”) and the Partnership’s other filings with the SEC for further information on risks and uncertainties that could affect the Partnership’s business, financial condition and results of operations, which are incorporated by this reference as though fully set forth herein. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report. The Partnership undertakes no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward looking statements are qualified in their entirety by this cautionary statement.

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Index

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)

PDC 2003-B Limited Partnership

PDC 2003-B Limited Partnership
Condensed Balance Sheets
(unaudited)


	March 31,			December 31,
	2011				2010*
Assets

Current assets:
Cash and cash equivalents	$	152,149		$	57,127
Accounts receivable		92,414			127,657
Crude oil inventory		27,752			21,075
Due from Managing General Partner-derivatives		287,048			274,292
Total current assets		559,363			480,151


Natural gas and crude oil properties, successful efforts method, at cost		14,135,344			14,134,724
Less: Accumulated depreciation, depletion and amortization		(8,631,872	)		(8,488,523	)
Natural gas and crude oil properties, net		5,503,472			5,646,201

Due from Managing General Partner-derivatives		368,267			430,200
Other assets		52,158			49,227
Total noncurrent assets		5,923,897			6,125,628

Total Assets	$	6,483,260		$	6,605,779

Liabilities and Partners' Equity

Current liabilities:
Accounts payable and accrued expenses	$	77,741		$	93,665
Due to Managing General Partner-derivatives		287,209			240,522
Due to Managing General Partner-other, net		192,601			157,809
Total current liabilities		557,551			491,996

Due to Managing General Partner-derivatives		289,326			325,668
Asset retirement obligations		233,263			229,847
Total liabilities		1,080,140			1,047,511

Commitments and contingent liabilities

Partners' equity:
Managing General Partner		1,083,321			1,114,350
Limited Partners - 867.33 units issued and outstanding		4,319,799			4,443,918
Total Partners' equity		5,403,120			5,558,268

Total Liabilities and Partners' Equity	$	6,483,260		$	6,605,779

~~Condensed Balance Sheets~~___________________________________________

~~(unaudited)~~*Derived from audited 2010 balance sheet

	September 30, 2010			December 31, 2009*
Assets
Current assets:
Cash and cash equivalents	$	37,121		$	57,505
Accounts receivable		74,533			158,083
Oil inventory		22,946			15,343
Due from Managing General Partner-derivatives		313,161			204,247
Total current assets		447,761			435,178
Natural gas and oil properties, successful efforts method, at cost		14,133,317			14,129,625
Less: Accumulated depreciation, depletion and amortization		(8,318,155	)		(7,852,403	)
Oil and gas properties, net		5,815,162			6,277,222
Due from Managing General Partner-derivatives		503,579			161,426
Other assets		45,979			36,152
Total noncurrent assets		6,364,720			6,474,800
Total Assets	$	6,812,481		$	6,909,978
Liabilities and Partners’ Equity
Current liabilities:
Accounts payable and accrued expenses	$	87,569		$	12,568
Due to Managing General Partner-derivatives		185,878			164,260
Due to Managing General Partner-other, net		94,639			98,610
Total current liabilities		368,086			275,438
Due to Managing General Partner-derivatives		372,225			482,463
Asset retirement obligations		226,481			216,681
Total liabilities		966,792			974,582
Commitments and contingent liabilities
Partners’ equity:
Managing General Partner		1,171,835			1,189,777
Limited Partners - 867.33 units issued and outstanding		4,673,854			4,745,619
Total Partners’ equity		5,845,689			5,935,396
Total Liabilities and Partners’ Equity	$	6,812,481		$	6,909,978

*Derived from audited 2009 balance sheet

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2003-B Limited Partnership

Condensed Statements of Operations

(unaudited)

	Three months ended September 30,					Nine months ended September 30,
	2010		2009			2010		2009
Revenues:
Natural gas and oil sales	$	252,506	$	291,303		$	858,986	$	790,081
Commodity price risk management gain (loss), net		257,429		(187,816	)		754,841		(480,698	)
Total revenues		509,935		103,487			1,613,827		309,383
Operating costs and expenses:
Natural gas and oil production costs		149,587		120,686			411,403		346,164
Direct costs - general and administrative		28,560		38,338			319,784		66,547
Depreciation, depletion and amortization		153,498		270,047			465,752		803,951
Accretion of asset retirement obligations		3,315		2,231			9,800		6,693
Total operating costs and expenses		334,960		431,302			1,206,739		1,223,355
Income (loss) from operations		174,975		(327,815	)		407,088		(913,972	)
Interest expense		—		(6,750	)		—		(6,750	)
Interest income		2		8,950			16		24,611
Net income (loss)	$	174,977	$	(325,615	)	$	407,104	$	(896,111	)
Net income (loss) allocated to partners	$	174,977	$	(325,615	)	$	407,104	$	(896,111	)
Less: Managing General Partner interest in net income (loss)		34,996		(65,123	)		81,421		(179,222	)
Net income (loss) allocated to Investor Partners	$	139,981	$	(260,492	)	$	325,683	$	(716,889	)
Net income (loss) per Investor Partner unit	$	161	$	(300	)	$	376	$	(827	)
Investor Partner units outstanding		867.33		867.33			867.33		867.33

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2003-B Limited Partnership

PDC 2003-B Limited Partnership
Condensed Statements of Operations
(unaudited)


	Three months ended March 31,
	2011			2010
Revenues:
Natural gas, NGLs and crude oil sales	$	249,752		$	366,034
Commodity price risk management (loss) gain, net		(45,782	)		367,050
Total revenues		203,970			733,084

Operating costs and expenses:
Natural gas, NGLs and crude oil production costs		92,666			99,246
Direct costs - general and administrative		48,059			72,565
Depreciation, depletion and amortization		143,349			172,624
Accretion of asset retirement obligations		3,416			3,219
Total operating costs and expenses		287,490			347,654

(Loss) income from operations		(83,520	)		385,430

Interest income		21			7

Net (loss) income	$	(83,499	)	$	385,437

Net (loss) income allocated to partners	$	(83,499	)	$	385,437
Less: Managing General Partner interest in net (loss) income		(16,700	)		77,087
Net (loss) income allocated to Investor Partners	$	(66,799	)	$	308,350

Net (loss) income per Investor Partner unit	$	(77	)	$	356

Investor Partner units outstanding		867.33			867.33

Condensed Statements of Cash Flows

(unaudited)

	Nine months ended September 30,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	407,104		$	(896,111	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		465,752			803,951
Accretion of asset retirement obligations		9,800			6,693
Unrealized (gain) loss on derivative transactions		(539,687	)		1,189,642
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable		83,550			(4,757	)
(Increase) decrease in oil inventory		(7,603	)		15,189
Increase in other assets		(9,827	)		(9,324	)
Increase (decrease) in accounts payable and accrued expenses		75,001			(12,960	)
Decrease in Due from Managing General Partner - other, net		—			981,438
Decrease in Due to Managing General Partner - other, net		(3,971)			—
Net cash provided by operating activities		480,119			2,073,761
Cash flows from investing activities:
Capital expenditures for oil and gas properties		(3,692	)		(95,905	)
Net cash used in investing activities		(3,692	)		(95,905	)
Cash flows from financing activities:
Distributions to Partners		(496,811	)		(1,977,130	)
Net cash used in financing activities		(496,811	)		(1,977,130	)
Net (decrease) increase in cash and cash equivalents		(20,384	)		726
Cash and cash equivalents, beginning of period		57,505			56,772
Cash and cash equivalents, end of period	$	37,121		$	57,498
Cash payments for:
Interest	$	—		$	6,750

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2003-B Limited Partnership
Condensed Statements of Cash Flows
(unaudited)


	Three months ended March 31,
	2011			2010
Cash flows from operating activities:
Net (loss) income	$	(83,499	)	$	385,437
Adjustments to net (loss) income to reconcile to net cash provided by operating activities:
Depreciation, depletion and amortization		143,349			172,624
Accretion of asset retirement obligations		3,416			3,219
Unrealized loss (gain) on derivative transactions		59,522			(210,000	)
Changes in operating assets and liabilities:
Decrease in accounts receivable		35,243			29,096
(Increase) decrease in crude oil inventory		(6,677	)		2,014
Increase in other assets		(2,931	)		(3,342	)
(Decrease) increase in accounts payable and accrued expenses		(15,924	)		100
Increase (decrease) in Due to Managing General Partner - other, net		34,792			(97,720	)
Net cash provided by operating activities		167,291			281,428

Cash flows from investing activities:
Capital expenditures for natural gas and crude oil properties		(620	)		(740	)
Net cash used in investing activities		(620	)		(740	)

Cash flows from financing activities:
Distributions to Partners		(71,649	)		(280,681	)
Net cash used in financing activities		(71,649	)		(280,681	)

Net increase in cash and cash equivalents		95,022			7
Cash and cash equivalents, beginning of period		57,127			57,505
Cash and cash equivalents, end of period	$	152,149		$	57,512

See accompanying notes to unaudited condensed financial statements

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Index

PDC 2003-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2010~~2011

(unaudited)

Note 1−General and Basis of Presentation

~~The~~ PDC 2003-B Limited Partnership (the “Partnership” or the “Registrant”) was organized as a limited partnership ~~on June 13~~, ~~2003~~ in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of ~~oil~~natural gas and ~~natural~~crude ~~gas~~oil properties. ~~Upon~~Business ~~completion~~operations of the Partnership commenced upon closing of an offering for the sale of Partnership units. Upon onfunding, ~~September~~the 3,Partnership ~~2003~~entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner which authorizes Petroleum Development Corporation (“PDC”), which conducts business under the ~~Partnership~~name ~~was~~PDC ~~funded~~Energy, to conduct and ~~commenced~~manage ~~its~~the ~~business~~Partnership’s ~~operations~~business. ~~The~~In accordance with the terms of the Limited Partnership ~~owns~~Agreement ~~natural~~(the ~~gas~~“Agreement”), ~~and~~the ~~oil~~Managing ~~wells~~General ~~located~~Partner inis ~~Colorado~~authorized ~~and~~to ~~from~~manage ~~the~~all ~~wells,~~activities of the Partnership ~~produces~~and initiates and ~~sells~~completes ~~natural~~substantially ~~gas~~all ~~and~~Partnership ~~oil~~transactions.

~~Purchasers~~As of ~~partnership~~March ~~units~~31, ~~subscribed~~2011, tothere ~~and~~were ~~fully~~771 ~~paid~~Investor ~~for 19~~Partners.79 PDC ~~units~~is ofthe ~~limited~~designated ~~partner~~Managing ~~interests~~General ~~and~~Partner ~~847.54 units~~ of ~~additional~~the ~~general~~Partnership ~~partner~~and ~~interests~~owns ata $20~~,000~~% ~~per~~Managing ~~unit~~General Partner ownership in the Partnership. InAccording ~~accordance~~to ~~with~~ the terms of the Limited Partnership Agreement, ~~(the “Agreement”)~~revenues, ~~Petroleum~~costs ~~Development~~and ~~Corporation,~~cash adistributions ~~Nevada~~of ~~Corporation~~the ~~that~~Partnership ~~now~~are ~~conducts~~allocated ~~business~~80% ~~under~~to the ~~name~~limited partners (“~~PDC~~Investor ~~Energy~~Partners”), iswhich ~~the~~are ~~Managing~~shared ~~General~~pro ~~Partner~~rata, ofbased ~~the~~upon ~~Partnership (hereafter,~~ the ~~“Managing~~number ~~General~~of ~~Partner”~~units orin ~~“PDC”)~~the Partnership, and ~~has a~~ 20% to the Managing General Partner ~~ownership in the Partnership~~. ~~Upon~~The ~~completion~~Managing ofGeneral ~~the~~Partner ~~drilling~~may ~~phase~~repurchase ofInvestor ~~the~~Partner ~~Partnership’s~~units ~~wells,~~under ~~all~~certain ~~additional~~circumstances ~~general~~provided ~~partners~~by ~~units~~the ~~were~~Agreement, ~~converted~~upon ~~into~~request ~~units~~ of ~~limited~~an ~~partner~~individual ~~interests~~Investor ~~and thereafter became limited partners of the Partnership~~Partner. ~~Throughout~~Through ~~the~~March ~~term of the Partnership~~31, ~~revenues~~2011, ~~costs,~~the ~~and~~Managing ~~cash~~General ~~distributions~~Partner ~~are~~has ~~allocated~~repurchased ~~80%~~51.4 tounits ~~the~~of ~~limited~~Partnership ~~and~~interests ~~additional~~from ~~general partners (collectively, the “~~Investor Partners~~”),~~ ~~which~~at ~~are~~an ~~shared~~average ~~pro~~price ~~rata~~of ~~based~~$5,692 ~~upon~~per ~~the~~unit. As ~~portion~~ of ~~units~~March ~~owned~~31, in2011, the ~~Partnership,~~Managing ~~and~~General 20Partner owns 24.7% toof the ~~Managing General Partner~~Partnership.

AsThe ofPartnership ~~September~~expects ~~30,~~continuing ~~2010,~~operations ~~there~~of ~~were~~its ~~779~~natural ~~Investor~~gas ~~Partners. As~~and ofcrude ~~September~~oil ~~30,~~properties ~~2010,~~until such time the ~~Managing~~Partnership’s ~~General~~wells ~~Partner~~are ~~has~~depleted ~~repurchased~~or ~~34.13~~become ~~units~~uneconomical ofto ~~the~~produce, ~~total~~at ~~867.33~~which ~~outstanding~~time ~~units~~they ofmay ~~Partnership~~be ~~interests~~sold ~~from~~or ~~Investor~~plugged, ~~Partners~~reclaimed atand anabandoned. The ~~average~~Partnership’s ~~price~~maximum term of ~~$7,200~~existence ~~per~~extends ~~unit~~through ~~and~~December 31, as2050, aunless ~~result,~~dissolved ~~participates~~by incertain conditions stipulated within the ~~sharing~~Agreement ofwhich ~~revenues,~~are ~~costs~~unlikely ~~and~~to ~~cash~~occur ~~distributions~~at asthis ~~both~~time, anor ~~investor~~by ~~partner~~written ~~and~~consent asof the ~~Managing~~Investor ~~General~~Partners ~~Partner~~owning a majority of outstanding units at that time.

~~The~~In the Managing General Partner’s opinion, ~~under~~ the ~~terms~~accompanying ofinterim ~~the~~unaudited ~~Drilling~~condensed ~~and~~financial ~~Operating~~statements ~~Agreement~~contain all adjustments (~~the~~consisting ~~“D&O~~of ~~Agreement”~~only normal recurring adjustments), ~~has~~necessary ~~full~~for ~~authority~~a tofair statement ~~conduct~~of the Partnership’s ~~business~~financial ~~and~~statements ~~actively~~for ~~manage~~interim periods in accordance with accounting principles generally accepted in the ~~Partnership~~United States of America ("U. ~~The~~S. ~~Partnership~~GAAP") ~~expects~~and ~~continuing~~with ~~operations~~the instructions to Form 10-Q and Article 10 of ~~its~~Regulation ~~natural~~S-X ~~gas~~of the Securities and ~~oil~~Exchange ~~properties~~Commission ~~until~~(“SEC”). Accordingly, pursuant to such ~~time~~rules ~~that~~and regulations, certain notes and other financial information included in the audited ~~Partnership’s~~financial ~~wells~~statements ~~are~~have ~~depleted~~been condensed or ~~become~~omitted. The ~~uneconomical~~information topresented ~~produce,~~in atthis ~~which~~quarterly ~~time~~report ~~that~~on ~~well~~Form ~~may~~10-Q should be ~~sold~~read orin ~~plugged,~~conjunction ~~reclaimed~~with the Partnership’s audited financial statements and ~~abandoned~~notes thereto included in the Partnership’s 2010 Form 10-K. The Partnership’s ~~maximum~~accounting ~~term~~policies ofare ~~existence~~described ~~extends~~in ~~through~~the ~~December~~Notes 31to Financial Statements in the Partnership’s 2010 Form 10-K and updated, ~~2050~~as necessary, ~~unless~~in ~~dissolved~~this byForm ~~certain~~10-Q. The ~~conditions~~results ~~stipulated~~of ~~within~~operations for the ~~Agreement~~three ~~(which~~months ~~are~~ended ~~unlikely~~March to31, ~~occur~~2011, atand ~~this~~the ~~time)~~cash orflows byfor ~~written~~the ~~consent~~same period, are not necessarily indicative of the ~~Investor~~results ~~Partners~~to ~~owning~~be aexpected ~~majority~~for ofthe ~~outstanding~~full ~~units~~year ator ~~that~~any ~~time~~other future period.

In the Managing General Partner’s opinion, the accompanying interim unaudited condensed financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary for a fair statement of the Partnership’s financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities and Exchange Commission, or SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. The information presented in this quarterly report on Form 10-Q should be read in conjunction with the Partnership’s audited financial statements and notes thereto included in the Partnership’s 2009 Form 10-K. The Partnership’s accounting policies are described in the Notes to Financial Statements in the Partnership’s 2009 Form 10-K and updated, as necessary, in this Form 10-Q. The results of operations for the three and nine months ended September 30, 2010, and the cash flows for the nine months ended September 30, 2010, are not necessarily indicative of the results to be expected for the full year or any other future period.

Note 2−Recent Accounting Standards

Recently Adopted Accounting Standards

Fair Value Measurements and Disclosures

In January 2010, the ~~Financial Accounting Standards Board (“~~FASB”) issued changes ~~clarifying existing disclosure requirements~~ related to fair value measurements~~. The~~ ~~update~~requiring ~~also~~gross ~~added~~presentation aof ~~new~~activities ~~requirement~~within tothe ~~disclose~~Level ~~fair~~3 ~~value~~roll ~~transfers~~forward, inwhereby ~~and~~entities ~~out~~must ofpresent ~~Levels~~separately 1information ~~and~~about 2purchases, sales, issuances and ~~describe~~settlements. These ~~the~~changes ~~reasons~~were effective for the ~~transfers. The~~Partnership’s ~~adoption~~financial ofstatements ~~these~~issued ~~changes~~for asannual ofreporting ~~January~~periods, 1and for interim reporting periods within the year, ~~2010~~beginning after December 15, 2010. The adoption of this change did not have a material impact on the Partnership’s ~~accompanying unaudited condensed~~ financial statements.

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Index

PDC 2003-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2010

(unaudited)

Recently Issued Accounting Standards

Fair Value Measurements and Disclosures

In January 2010, the FASB issued changes related to fair value measurements requiring gross presentation of activities within the Level 3 roll forward, whereby entities must present separately information about purchases, sales, issuances and settlements. This change will be effective for the Partnership’s financial statements issued for annual reporting periods beginning after December 15, 2010. The Partnership does not expect adoption of these changes to have a material effect on the Partnership’s financial statements and related disclosures.

Internal Control over Financial Reporting in Exchange Act Periodic Reports

By Final Rule effective September 21, 2010, the SEC amended its rules and forms to conform them to Section 404(c) of the Sarbanes-Oxley Act of 2002, or SOX, as added by the Dodd-Frank Wall Street Reform and Consumer Protection Act. The new SEC rules exempt the Partnership, as a smaller reporting company filer, from the SOX requirement that registrants which are accelerated or large accelerated filers, obtain and include in their annual report filed with the SEC, their independent registered public accounting firm’s attestation report on the effectiveness of the registrant’s internal controls over financial reporting.

Note 3−Transactions with Managing General Partner and Affiliates

The Managing General Partner transacts business on behalf of the Partnership under the authority of the D&O Agreement. Revenues and other cash inflows received on behalf of the Partnership are distributed to the Partners net of (after deducting) corresponding operating costs and other cash outflows incurred on behalf of the Partnership. The fair value of the Partnership’s portion of unexpired derivative instruments is recorded on the balance sheet under the captions “Due from Managing General Partner–derivatives,” in the case of net unrealized gains or “Due to Managing General Partner–derivatives,” in the case of net unrealized losses.

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

	September 30, 2010			December 31, 2009
Natural gas and oil sales revenues collected from the Partnership’s third-party customers	$	87,431		$	106,460
Commodity Price Risk Management, Realized Gains		28,797			132,191
Other (1)		(210,867	)		(337,261	)
Total Due to Managing General Partner-other, net	$	(94,639	)	$	(98,610	)

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

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Index

PDC 2003-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2010~~2011

(unaudited)

~~The following table presents Partnership transactions, excluding derivative transactions which are more fully detailed in~~ Note 5,3−Transactions ~~Derivative Financial Instruments,~~ with ~~the~~ Managing General Partner and its affiliates for the three and nine months ended September 30, 2010 and 2009. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Natural gas and oil production costs” line item on the statements of operations.Affiliates

	Three months ended September 30,				Nine months ended September 30,
	2010		2009		2010		2009
Well operations and maintenance	$	130,268	$	96,690	$	358,675	$	278,150
Gathering, compression and processing fees		8,696		9,428		25,972		25,894
Direct costs - general and administrative		28,560		38,338		319,784		66,547
Cash distributions*		3,152		205,222		113,817		435,285

The Managing General Partner transacts business on behalf of the Partnership under the authority of the D&O Agreement. Revenues and other cash inflows received on behalf of the Partnership are distributed to the Partners net of (after deducting) corresponding operating costs and other cash outflows incurred on behalf of the Partnership. The fair value of the Partnership’s portion of unexpired derivative instruments is recorded on the condensed balance sheets under the captions “Due from Managing General Partner–derivatives,” in the case of net unrealized gains or “Due to Managing General Partner–derivatives,” in the case of net unrealized losses.

*CashThe ~~distributions~~following ~~include~~table ~~$427~~presents ~~and~~transactions ~~$14,454~~with ~~during~~ the ~~three~~Managing ~~and~~General ~~nine~~Partner ~~months~~reflected ~~ended~~in ~~September~~the ~~30,~~condensed ~~2010,~~balance ~~respectively,~~sheet ~~and~~line ~~$21,313~~item ~~and~~– ~~$39,860~~“Due ~~during~~from ~~the~~(to) ~~three~~Managing ~~and~~General ~~nine months ended September 30~~Partner-other, ~~2009~~net,” ~~respectively,~~which ~~related~~remain toundistributed ~~equity~~or ~~cash~~unsettled ~~distributions~~with onthe ~~Investor~~Partnership’s ~~Partner~~investors ~~units~~as ~~repurchased~~of bythe ~~PDC~~dates indicated.

Note 4−Fair Value Measurements

	March 31,			December 31,
	2011			2010

Natural gas, NGLs and crude oil sales revenues collected from the Partnership's third-party customers	$	80,629		$	83,273
Commodity price risk management, realized gain		7,374			39,716
Other (1)		(280,604	)		(280,798	)
Total Due to Managing General Partner-other, net	$	(192,601	)	$	(157,809	)

~~Derivative Financial Instruments. The Partnership measures fair value based upon quoted market prices, where available. The valuation determination includes:~~ (1) ~~identification~~All ~~of the inputs to the fair value methodology through the review of counterparty statements and~~ other ~~supporting~~unsettled ~~documentation~~transactions, ~~(2)~~excluding ~~determination~~derivative ~~of the validity of the source of the inputs~~instruments, ~~(3)~~between ~~corroboration of~~ the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. The methods described above may produce a fair value calculation that may not be indicative of future fair values. The valuation determination also gives consideration to nonperformance risk on Partnership ~~liabilities in addition to nonperformance risk on PDC’s own business interests~~ and ~~liabilities, as well as~~ the ~~credit standing of derivative instrument counterparties. The~~ Managing General Partner ~~primarily uses financial institutions, which are also major lenders in PDC’s credit facility agreement, as counterparties to the Partnership’s derivative contracts~~. The ~~Managing~~majority ~~General Partner has evaluated the credit risk~~ of ~~the~~these ~~counterparties~~are ~~holding~~operating ~~the~~costsor ~~Partnership’s~~general ~~derivative assets using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty~~ and ~~the~~administrative ~~duration~~costs ofwhich ~~each~~have outstanding derivative position. Based on the Managing General Partner’s evaluation, as of September 30, 2010, the impact of non-performance risk on the fair value of the Partnership’s derivative assets and liabilities was not ~~significant. Validation~~been ofdeducted ~~the~~from Partnership’s contracts’ fair values are performed internally and while the Managing General Partner uses common industry practices to develop valuation techniques, changes in the Managing General Partner’s pricing methodologies or the underlying assumptions could result in significantly different fair valuesdistributions. While the Managing General Partner believes these valuation methods are appropriate and consistent with those used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

The following table presents Partnership transactions, excluding derivative transactions which are more fully detailed in Note 5, Derivative Financial Instruments, with the Managing General Partner and its affiliates for the three months ended March 31, 2011 and 2010. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Natural gas, NGLs and crude oil production costs” line item on the condensed statements of operations.

	Three months ended March 31,
	2011		2010

Well operations and maintenance	$	73,011	$	86,024
Gathering, compression and processing fees		7,492		9,313
Direct costs - general and administrative		48,059		72,565
Cash distributions (1)		17,711		64,260

(1)

Cash distributions include $3,382 and $8,123 during the three months ended March 31, 2011 and 2010, respectively, related to equity cash distributions on Investor Partner units repurchased by PDC.

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Index

PDC 2003-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2010~~2011

(unaudited)

~~The~~Note ~~following~~4−Fair ~~table~~Value ~~presents,~~of byFinancial ~~hierarchy level, the Partnership’s derivative financial instruments, including both current and non-current portions measured at fair value.~~Instruments

	Quoted Prices in Active Markets (Level 1)			Significant Unobservable Inputs (Level 3)			Total
As of December 31, 2009
Assets:
Commodity based derivatives	$	163,840		$	201,833		$	365,673
Total assets		163,840			201,833			365,673
Liabilities:
Commodity based derivatives		(11,426	)		(49,433	)		(60,859	)
Basis protection derivative contracts		—			(585,864	)		(585,864	)
Total liabilities		(11,426	)		(635,297	)		(646,723	)
Net asset (liability)	$	152,414		$	(433,464	)	$	(281,050	)
As of September 30, 2010
Assets:
Commodity based derivatives	$	747,260		$	69,480		$	816,740
Total assets		747,260			69,480			816,740
Liabilities:
Commodity based derivatives		—			(43,689	)		(43,689	)
Basis protection derivative contracts		—			(514,414	)		(514,414	)
Total liabilities		—			(558,103	)		(558,103	)
Net asset (liability)	$	747,260		$	(488,623	)	$	258,637

The following table presents, for each hierarchy level, the Partnership’s derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis as of March 31, 2011 and December 31, 2010.

The following table presents the changes of the Partnership’s Level 3 derivative financial instruments measured on a recurring basis:

	March 31, 2011								December 31, 2010
	Quoted Prices in Active Markets		Significant Unobservable Inputs						Quoted Prices in Active Markets		Significant Unobservable Inputs
	Level 1		Level 3			Total			Level 1		Level 3			Total

Assets:
Commodity based derivatives	$	647,641	$	7,674		$	655,315		$	676,975	$	27,517		$	704,492
Total assets		647,641		7,674			655,315			676,975		27,517			704,492

Liabilities:
Commodity based derivatives		-		(88,917	)		(88,917	)		-		(71,891	)		(71,891	)
Basis protection derivative contracts		-		(487,618	)		(487,618	)		-		(494,299	)		(494,299	)
Total liabilities		-		(576,535	)		(576,535	)		-		(566,190	)		(566,190	)

Net asset (liability)	$	647,641	$	(568,861	)	$	78,780		$	676,975	$	(538,673	)	$	138,302

	Nine months ended September 30, 2010
Fair value, net liability, as of December 31, 2009	$	(433,464	)
Changes in fair value included in statement of operations line item:
Commodity price risk management, net		60,627
Settlements		(115,786	)
Fair value, net liability, as of September 30, 2010	$	(488,623	)
Change in unrealized gains (losses) relating to assets (liabilities) still held as of September 30, 2010 included in statement of operations line item:
Commodity price risk management, net	$	10,269

The following table presents a reconciliation of the Partnership’s Level 3 fair value measurements.

	Three months ended
	March 31, 2011			March 31, 2010
Fair value, net liability, beginning of year	$	(538,673	)	$	(433,464	)
Changes in fair value included in statement of operations line item - Commodity price risk management, net		(54,234	)		(46,775	)
Settlements		24,046			(157,050	)
Fair value, net liability, end of period	$	(568,861	)	$	(637,289	)
Change in unrealized loss relating to assets (liabilities) still held as of March 31, 2011 and 2010, respectively, included in statement of operations line item:
Commodity price risk management, net	$	(53,473	)	$	(62,204	)

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

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

- 8 -

Index

PDC 2003-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2010~~2011

(unaudited)

Note 5−Derivative Financial Instruments

As of ~~September~~March 3031, ~~2010~~2011, the Partnership had derivative instruments, ~~comprised of commodity collars, commodity fixed-price swaps and a basis swap,~~ in place for a portion of its anticipated production through 2013 for a total of ~~419~~345,~~046~~925 MMbtu of natural gas and 42,~~978~~476 Bbls of ~~oil. Partnership~~crude ~~policy prohibits the use of natural gas and~~ oil ~~derivative instruments for speculative purposes~~.

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

			Fair Value
Derivative instruments not designated as hedge (1):		Balance Sheet Line Item	September 30, 2010		December 31, 2009
		Balance Sheet	March 31,		December 31,
Derivative instruments not designated as hedge (1):		Line Item	2011		2010
Derivative Assets:	Current
	Commodity contracts	Due from Managing General Partner-derivatives	$	~~313~~287,~~161~~048	$	~~204~~274,~~247~~292
	Non Current
	Commodity contracts	Due from Managing General Partner-derivatives		~~503~~368,~~579~~267		~~161~~430,~~426~~200
Total Derivative Assets			$	~~816~~655,~~740~~315	$	~~365~~704,~~673~~492
Derivative Liabilities:	Current
	Commodity contracts	Due to Managing General Partner-derivatives	$	3188,~~374~~917	$	1171,~~745~~891
	Basis protection contracts	Due to Managing General Partner-derivatives		~~154~~198,~~504~~292		~~152~~168,~~515~~631
	Non Current
	Commodity contracts	Due to Managing General Partner-derivatives		~~12,316~~-		~~49,114~~-
	Basis protection contracts	Due to Managing General Partner-derivatives		~~359~~289,~~909~~326		~~433~~325,~~349~~668
Total Derivative Liabilities			$	~~558~~576,~~103~~535	$	~~646~~566,~~723~~190

(1) As of ~~September~~March 3031, ~~2010~~2011 and December 31, ~~2009~~2010, none of the Partnership’s derivative instruments were designated as hedges.

The following table ~~summarizes~~presents the impact of the Partnership’s derivative instruments on the Partnership’s accompanying condensed statements of operations ~~for the three and nine months ended September 30, 2010 and 2009~~.

	Three months ended September 30,
	Three months ended March 31,
	2010									2009
	2011									2010
Statement of operations line item	Reclassification of Realized ~~Gains~~Loss (~~Losses~~Gain) Included in Prior Periods Unrealized			Realized and Unrealized ~~Gains~~Gain (Loss) For the Current Period			Total			Reclassification of Realized ~~Gains~~Loss (~~Losses~~Gain) Included in Prior Periods Unrealized			Realized and Unrealized ~~Losses~~Gain For the Current Period			Total
Commodity price risk management, net
Realized gains (losses)	$	16,128		$	16,455		$	32,583		$	177,593		$	(242	)	$	177,351
Realized gain	$	10,762		$	2,978		$	13,740		$	145,222		$	11,828		$	157,050
Unrealized (losses) gains		(16,128	)		240,974			224,846			(177,593	)		(187,574	)		(365,167	)
Unrealized (loss) gain		(10,762	)		(48,760	)		(59,522	)		(145,222	)		355,222			210,000
Total commodity price risk management gain (loss), net	$	—		$	257,429		$	257,429		$	—		$	(187,816	)	$	(187,816	)
Total commodity price risk management (loss) gain, net	$	-		$	(45,782	)	$	(45,782	)	$	-		$	367,050		$	367,050

	Nine months ended September 30,
	2010							2009
Statement of operations line item	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total		Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains (Losses) For the Current Period			Total
Commodity price risk management, net
Realized gains	$	58,313		$	156,841	$	215,154	$	577,691		$	131,253		$	708,944
Unrealized (losses) gains		(58,313	)		598,000		539,687		(577,691	)		(611,951	)		(1,189,642	)
Total commodity price risk management gain (loss), net	$	—		$	754,841	$	754,841	$	—		$	(480,698	)	$	(480,698	)

Derivative Counterparties. The Managing General Partner makes extensive use of over-the-counter derivative instruments that enable the Partnership to manage a portion of its exposure to price volatility from producing natural gas and crude oil. These arrangements expose the Partnership to the credit risk of nonperformance by the counterparties. The Managing General Partner primarily uses financial institutions, who are also major lenders in the Managing General Partner’s credit facility agreement, as counterparties to its derivative contracts. To date, the Managing General Partner has had no counterparty default losses. The Managing General Partner has evaluated the credit risk of the Partnership’s derivative assets from counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on this evaluation, the Managing General Partner has determined that the impact of the nonperformance of the counterparties on the fair value of the Partnership’s derivative instruments was not significant.

- 9 -

Index

PDC 2003-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2010~~2011

(unaudited)

Concentration of Credit Risk. A significant component of the Partnership’s future liquidity is concentrated in derivative instruments that enables the Partnership to manage a portion of its exposure to price volatility from producing natural gas and oil. These arrangements expose the Partnership to the risk of nonperformance by the counterparties. The Managing General Partner primarily uses financial institutions, who are also major lenders in the Managing General Partner’s credit facility agreement, as counterparties to the derivative contracts. To date, the Partnership has experienced no counterparty defaults.

Note 6−Commitments and Contingencies

Legal Proceedings

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

Environmental

Due to the nature of the natural gas and crude oil ~~business~~industry, the Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures to avoid environmental contamination and mitigate the risks from environmental contamination. The Managing General Partner conducts periodic reviews to identify changes in the Partnership’s environmental risk profile. Liabilities are accrued when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. During the ~~second~~three ~~quarter~~months ofended ~~2010~~March 31, ~~the~~2011, ~~Managing~~there ~~General~~were ~~Partner~~no ~~identified~~new ~~existing~~environmental ~~ground~~remediation ~~contamination~~projects atidentified ~~one~~by ~~Partnership well. The accrual of approximately $50,000 was~~ the ~~estimated~~Managing ~~cost~~General ~~attributable~~Partner related to the Partnership,. As ~~based~~of ~~principally~~March on31, ~~estimated~~2011, ~~third~~and ~~party~~December ~~costs~~31, to2010, ~~remediate~~ the ~~ground contamination. The~~ Partnership ~~recorded~~has ~~the~~ accrued environmental remediation ~~liability~~liabilities infor ~~the~~three Balance Sheet line item captioned “Accounts payable and accrued expenses.” This accrual represented costs estimated to be incurred in addition to normal recurring environmental-related expenditures which have been incurred and recorded at June 30, 2010. During the third quarter of ~~2010,~~ the ~~Managing~~Partnership’s ~~General~~well ~~Partner~~pads ~~identified~~involving ~~existing~~five ~~ground contamination at four additional Partnership~~ wells~~. The~~ ~~Partnership~~in ~~recorded~~the anamount ~~additional environmental remediation accrual~~ of ~~approximately~~ $3670,000 ~~for~~and ~~these sites during the third quarter~~$89, ~~in a manner consistent with that which was applied during the second quarter~~000, ~~as previously described. At September 30~~respectively, ~~2010,~~which ~~the Partnership’s accrued environmental liability~~ is ~~approximately~~included ~~$80,000,~~in ~~which~~line ~~represents~~item ~~the~~captioned ~~remaining~~“Accounts ~~estimated~~payable ~~costs~~and toaccrued ~~complete~~expenses” ~~environmental~~on ~~remediation at~~ the ~~five~~condensed ~~Partnership~~Balance ~~well sites, less actual costs incurred through September 30, 2010, if any~~Sheets. The Managing General Partner is not aware of any environmental claims existing as of ~~September~~March 3031, ~~2010~~2011, which have not been provided for or would otherwise have a material impact on the Partnership’s financial statements. However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on the Partnership’s properties.

In December 2008, the Managing General Partner received a Notice of Violation/Cease and Desist Order (the “Notice”) from the Colorado Department of Public Health and Environment (the “CDPHE”), related to the stormwater permit for the Garden Gulch Road. The Managing General Partner manages this private road for Garden Gulch LLC. The Managing General Partner is one of eight users of this road, all of which are natural gas and oil companies operating in the Piceance region of Colorado. Operating expenses, including this fine, if any, are allocated among the users of the road based upon their respective usage. The Partnership has five wells in this region. The Notice alleged a deficient and/or incomplete stormwater management plan, failure to implement best management practices and failure to conduct required permit inspections. The Notice requires corrective action and states that the recipient shall cease and desist such alleged violations. The Notice states that a violation could result in civil penalties up to $10,000 per day. The Managing General Partner’s responses were submitted on February 6, 2009, and April 8, 2009. Commencing in December 2009, the Managing General Partner entered into negotiations with the CDPHE regarding this notice and a settlement was accepted by CDPHE in November 2010. This settlement did not have a material impact on the Partnership’s financial position or results of operations.

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PDC 2003-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2010

(unaudited)

Note 7−Subsequent Events

On October 20, 2010, the Managing General Partner notified Investor Partners by letter, that the Partnership commenced the withholding of funds, on a pro-rata basis allocated to the Managing General Partner and Investor Partners based on their proportional ownership interest, which will be utilized to further develop the Partnership’s Denver-Julesburg (“DJ”) Basin Wattenberg Field wells under the previously announced Well Refracturing Plan. The plan provides for the refracturing of the Partnership’s Wattenberg Field wells in the currently producing Codell formation and these activities are expected to begin mid-to-late 2011. Funds withheld from the Partnership’s investors, including the Managing General Partner, in the October 2010 distribution amounted to $20,000 and have been deposited in the Partnership’s bank account.

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Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Partnership Overview

PDC 2003-B Limited Partnership engages in the development, production and sale of ~~oil~~natural gas, NGLs and ~~natural~~crude ~~gas~~oil. The Partnership began ~~oil~~natural gas and ~~gas~~crude oil operations in ~~September~~ 2003 and operates 2523 gross (2220.34 net) productive wells located in the Rocky Mountain Region in the state of Colorado. ~~One~~In ~~additional~~addition, ~~Wattenberg~~three ~~Field~~gross ~~Partnership well~~ (02.97 net ~~well~~) isWattenberg Field Partnership wells are temporarily not in production at ~~September~~March 3031, ~~2010~~2011 due to equipment problems. The Managing General Partner markets the Partnership’s natural gas and crude oil production to commercial end users, interstate or intrastate pipelines, or local utilities or oil companies, primarily under market sensitive contracts in which the price of natural gas, NGLs and crude oil sold varies as a result of market forces. PDC does not charge an additional fee for the marketing of the natural gas, NGLs and crude oil because these services are covered by the monthly well operating charge. PDC, on behalf of the Partnership in accordance with the D&O Agreement, is authorized to enter into multi-year fixed price contracts or utilize derivatives, including collars, swaps or basis protection swaps, in order to offset some or all of the commodity price variability for particular periods of time. Seasonal factors, such as effects of weather on prices received and costs incurred, and availability of pipeline capacity, owned by PDC or other third parties, may impact the Partnership’'s results. In addition, both sales volumes and prices tend to be affected by demand factors with a seasonal component.

Recent Developments

PDC Sponsored Drilling Program Acquisition Plan

PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue, beginning in the fall of 2010 and extending through the next three years, the acquisition of the limited partnership units (the “Acquisition Plan”) held by Investor Partners of the ~~that~~ particular partnership other than those held by PDC or its affiliates (“non-affiliated ~~Investor~~investor ~~Partners~~partners”), in certain ~~the~~ limited partnerships that PDC ~~has~~had previously sponsored, including this Partnership. For additional information regarding PDC’s intention to pursue acquisitions of PDC sponsored partnerships, refer to the disclosure included in Items 2.02, 7.01 and/or 8.01 of PDC’s Forms 8-K dated March 4, 2010, June 9, 2010, July 15, 2010 and November 17, 2010. However, such information shall not, by reason of this reference, be deemed to be incorporated by reference in, or otherwise be deemed to be part of, this report. Under the Acquisition Plan, any existing or future merger offer will be subject to the terms and conditions of the related merger agreement, and such agreement does or will likely contemplate the partnership being merged with and into a wholly-owned subsidiary of PDC. Each such merger will also be subject to, among other things, PDC having sufficient available capital, the economics of the merger and the approval by a majority of the limited partnerships units held by the non-affiliated ~~Investor~~investor ~~Partners~~partners of each respective limited partnership. Consummation of any proposed merger of a ~~PDC sponsored~~ limited partnership under the Acquisition Plan will ~~likely~~ result in the termination of the existence of that partnership and the right of non-affiliated ~~Investor~~investor ~~Partners~~partners to receive a cash payment for their limited partnership units in that partnership.

In ~~June~~November 2010, PDC and a wholly-owned subsidiary of PDC entered into separate merger agreements with each of PDC ~~2004~~2005-A Limited Partnership, PDC ~~2004~~2005-B Limited Partnership, ~~PDC~~and ~~2004-C~~the ~~Limited~~2005 ~~Partnership~~Rockies ~~and~~Region ~~PDC~~Private ~~2004-D~~ Limited Partnership (collectively, the “~~2004~~2005 ~~partnerships~~Partnerships”). PDC serves as the ~~managing~~Managing ~~general~~General ~~partner~~Partner of each of the ~~2004~~2005 ~~partnerships~~Partnerships. ~~Definitive~~The ~~proxy~~special ~~statements~~meetings ~~for~~whereby ~~each of the 2004 partnerships requesting approval from the applicable~~ non-affiliated ~~Investor~~investor ~~Partners~~partners ~~for, among other things were mailed to the non-affiliated Investor Partners~~ of the ~~2004~~2005 partnerships inwill ~~early~~have ~~October~~an ~~2010. Special~~opportunity ~~meetings~~to ~~were~~vote ~~held~~and onapprove ~~December 8, 2010, at which~~ the ~~majority~~respective ofmerger ~~the~~agreements ~~non-affiliated~~are ~~Investor~~currently ~~Partners~~scheduled offor ~~each~~June of15, ~~the 2004 partnerships voted to approve the applicable merger agreement~~2011.

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Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

InThe ~~November~~feasibility ~~2010, PDC~~ and atiming ~~wholly-owned subsidiary~~ of ~~PDC~~any ~~entered~~future ~~into~~purchase ~~separate~~offer ~~merger~~by ~~agreements with each of~~ PDC ~~2005-A~~to ~~Limited~~any ~~Partnership,~~additional ~~PDC 2005-B Limited Partnership~~partnership, ~~and~~including ~~the~~this ~~2005 Rockies Region Private Limited~~ Partnership ~~(collectively~~, ~~the~~depends ~~“2005~~on ~~partnerships”). PDC~~that ~~serves as the managing general partner of each of the 2005 partnerships. On December 3, 2010, each of the 2005 partnerships filed with the SEC, a preliminary proxy statement relating to such~~ partnership’s ~~prospective~~suitability ~~merger. Upon~~in ~~completion~~meeting ~~of the SEC review process,~~ a ~~definitive~~set ~~proxy statement will be mailed to the 2005 partnerships’ non-affiliated Investor Partners requesting their approval~~ of ~~the~~criteria ~~merger~~that ~~transactions. Pursuant to each merger agreement~~includes, ifbut ~~the merger~~ is ~~approved~~not bylimited ~~the~~to, ~~holders of a majority of~~ the ~~limited~~following: ~~partnership~~age ~~units~~and ~~held by the non~~productive-~~affiliated~~life ~~Investor~~stage ~~Partners~~characteristics of ~~each~~the ~~respective~~ partnership,’s as well asinventory; ~~the~~favorability ~~satisfaction~~ of ~~other~~economics ~~customary~~for ~~closing~~Wattenberg ~~conditions,~~Field ~~then~~well ~~such~~refracturing; ~~partnership will merge with~~ and ~~into~~SEC areporting ~~wholly-owned~~compliance ~~subsidiary~~status ofand ~~PDC. PDC~~timing ~~has~~associated ~~offered~~with togaining ~~pay~~all ~~approximately~~necessary ~~$36.4~~regulatory ~~million~~approvals required for ~~the~~a ~~limited~~merger ~~partnership~~and ~~units~~repurchase ~~of the 2005 partnerships in connection with the mergers~~offer. ~~Although~~There ~~there~~ is no assurance ofthat ~~the~~any ~~likelihood~~merger orand ~~timing~~acquisition ofwill ~~the~~occur, ~~completion~~as ofa ~~the~~result ~~SEC~~of ~~proxy~~PDC’s ~~disclosure~~proposed ~~review~~repurchase ~~process~~offers orto ~~whether~~ the ~~Partnership~~2005 ~~will~~Partnerships, ~~obtain~~or ~~the~~any ~~necessary~~potential ~~approvals~~proposed ~~from~~repurchase ~~non-affiliated~~offer ~~investors,~~to ~~each~~any ~~merger~~other of ~~the~~PDC’s ~~2005~~various ~~partnerships~~public islimited ~~expected~~partnerships, toincluding ~~close~~this ~~during~~Partnership, ~~the~~should ~~first~~they ~~half of 2011~~occur.

The feasibility and timing of any future purchase offer by PDC to any additional partnership, including this Partnership, depends on that partnership’s suitability in meeting a set of criteria that includes, but is not limited to, the following: age and productive-life stage characteristics of the partnership’s well inventory; favorability of economics for Wattenberg Field well refracturing; and SEC reporting compliance status and timing associated to gaining all necessary regulatory approvals required for a merger and repurchase offer. There is no assurance that any merger and acquisition will occur as a result of PDC’s proposed repurchase offers to the 2005 partnerships, or any potential proposed repurchase offer to any other of PDC’s various public limited partnerships, including this Partnership, should they occur.

Well Refracturing Plan

The Managing General Partner has prepared a plan for the Partnership’s Wattenberg Field wells ~~that~~which ~~were~~may ~~initially~~provide ~~completed~~for inadditional ~~the~~reserve ~~Codell~~development ~~formation~~of ~~during~~natural ~~the~~gas, ~~Partnership’s~~NGLs ~~initial~~and ~~development~~crude oil production (the “Well Refracturing Plan”). The Well Refracturing Plan consists of the Partnership’s refracturing of wells currently producing in the Codell formation. Under the Well Refracturing Plan, the Partnership plans to initiate ~~Codell formation~~ refracturing activities during 2011. ~~These refracturing~~Refracturing, or “refracing,” activities ~~will~~ consist of a second hydraulic fracturing treatment toin ~~the~~a ~~currently~~current ~~producing~~production ~~Codell~~zone, ~~formation~~all within an existing well bore.

~~During~~Refracturing ~~the~~of ~~fourth~~Wattenberg ~~quarter~~Field ~~2010~~wells, ~~the~~which ~~Managing~~may ~~General~~provide ~~Partner~~for ~~began~~additional ~~withholding~~reserve ~~funds~~development ~~from~~and ~~several~~production, ofgenerally ~~the~~occurs ~~PDC~~five ~~sponsored~~to ~~partnerships,~~ten years after initial well drilling so that well resources are optimally utilized. This refracturing would be expected to occur based on a ~~pro-rata~~favorable ~~basis~~general ~~allocated~~economic toenvironment ~~the~~and commodity price structure. The Managing General Partner ~~and~~has ~~Investor~~the ~~Partners~~authority ~~based~~to ondetermine ~~their~~whether ~~proportional~~to ~~ownership~~refrac ~~interest,~~the ~~from~~individual ~~distributable~~wells ~~cash~~and ~~flows~~to ~~resulting~~determine ~~from~~the ~~current~~timing ~~production~~of any refracturing activity. The ~~funds~~timing ~~retained~~of ~~are~~the ~~necessary~~refracturing ~~for~~can be affected by the ~~Partnership~~desire to ~~pay~~optimize ~~for~~the economic return by refracturing ~~costs~~the ~~will~~wells ~~materially~~when ~~reduce,~~commodity upprices toare ~~100%,~~at ~~distributable~~levels ~~cash~~to ~~flows~~obtain ~~for~~the ahighest ~~period~~rate of ~~time~~return ~~not~~ to ~~exceed~~the ~~five years~~Partnership. IfOn ~~any~~average, orthe ~~all~~production ofresulting ~~the~~from ~~Partnership~~PDC’s ~~Wattenberg~~Codell ~~wells~~refracturings ~~are~~have ~~not~~been ~~refractured,~~at ~~the~~modeled ~~Partnership~~economics; ~~will~~however, ~~experience~~all arefracturings ~~reduction~~have innot ~~proved~~been ~~natural~~economically ~~gas~~successful and ~~oil reserves~~similar ~~currently~~future ~~assigned~~refracturing toactivities ~~these~~may ~~wells~~not be economically successful. ~~Both~~If the ~~number~~refracturing ~~and~~work ~~timing~~is ofperformed, ~~refracturings~~PDC will becharge ~~based~~the onPartnership for the ~~availability~~direct costs of ~~cash~~refracturing, ~~withheld~~and ~~from~~the ~~Partnership~~Investor ~~distributions. The~~Partners and the Managing General Partner ~~believes~~will ~~that,~~each ~~based~~pay ontheir ~~projected~~proportionate ~~refracturing~~share of costs ~~and~~based ~~projected~~on ~~cash~~the ~~withholding,~~ownership ~~all~~sharing ~~Partnership~~ratios ~~refracturings~~of ~~will~~the bePartnership ~~completed~~from ~~within~~funds aretained ~~five~~by ~~year~~the ~~period. This~~Managing ~~Partnership~~General ~~began~~Partner ~~withholding~~from cash ~~funds~~available for ~~this~~distributions. ~~additional~~The ~~Codell~~Managing ~~formation~~General ~~development~~Partner inconsiders ~~October~~the ~~2010~~cash byavailable ~~withholding~~for ~~$20,000~~distributions ~~and~~to ~~depositing~~be ~~into~~ the Partnership’s ~~bank~~net ~~account~~cash flows provided by operating activities less any net cash used in capital activities.

~~Current~~During ~~estimated~~the ~~costs~~fourth ~~for~~quarter ~~these well refracturings are between $150~~2010,~~000~~ ~~and~~the ~~$200,000~~Managing ~~per~~General ~~refracturing. This~~Partner ~~Partnership~~began ~~potentially~~a ~~has~~program 21for ~~well~~its ~~refracturing~~affiliated ~~opportunities. Total~~partnerships ~~withholding~~to ~~for~~begin ~~these~~accumulating ~~activities~~cash from ~~the Partnership’s distributable~~ cash flows isfrom ~~estimated~~operating activities to bepay ~~between~~for ~~$3.2~~future ~~million~~refracturing ~~and $4~~costs.2 ~~million. The~~This ~~Managing~~program ~~General Partner~~ will ~~continually~~materially ~~evaluate~~reduce, ~~the~~up ~~timing~~to of100%, ~~commencing~~cash ~~these~~available ~~refracturings~~for ~~based~~distributions onof ~~engineering~~the ~~data~~partnerships ~~and~~for a ~~favorable~~period ~~commodity~~of ~~price~~time ~~environment~~not ~~in order~~ to ~~maximize~~exceed ~~the~~five ~~financial benefit of the refracturing~~years.

~~Implementation~~Current ofestimated ~~the~~costs ~~Well~~for ~~Refracturing~~these ~~Plan~~well ~~will~~refracturings ~~reduce~~are orbetween ~~eliminate~~$175,000 ~~Partnership~~and ~~distributions~~$240,000 toper ~~the~~activity. As ~~Managing~~of ~~General~~March ~~Partner~~31, ~~and~~2011, ~~Investor~~this ~~Partners~~Partnership ~~while~~had ~~the~~scheduled ~~work~~to iscomplete ~~being~~21 ~~conducted~~refracturing ~~and~~opportunities. Total ~~paid~~withholding for~~. Depending~~ ~~upon~~these activities from the ~~level~~Partnership’s cash ofavailable ~~withholding~~for ~~and~~distributions is ~~the~~estimated ~~results~~to ofbe ~~operations,~~between it$3.7 ismillion ~~possible~~and ~~that~~$5.0 ~~the~~million. The Managing General Partner ~~and~~will ~~Investor~~continually ~~Partners~~evaluate ~~could~~the ~~have~~timing ~~taxable~~of ~~income~~commencing ~~from~~these ~~the~~refracturing ~~Partnership~~activities ~~without~~based ~~any~~on ~~corresponding~~engineering ~~distributions~~data inand ~~the~~a ~~future. Investor~~favorable ~~Partners~~commodity ~~are~~price ~~urged~~environment toin ~~consult~~order ato ~~tax~~maximize ~~advisor~~the tofinancial ~~determine~~benefit ~~all~~ of the ~~relevant~~additional ~~federal,~~well ~~state~~development. During ~~and~~the ~~local~~three ~~tax~~months ~~consequences~~ended ofMarch ~~the~~31, ~~Well~~2011, ~~Refracturing~~$95,000 ~~Plan. The~~was ~~above~~withheld ~~discussion~~from isthe ~~not~~Partnership’s ~~intended~~cash asdistributions apursuant ~~substitute~~to ~~for~~the ~~careful~~Well ~~tax~~Refracturing ~~planning~~Plan. Cumulatively, ~~and~~$115,000 ~~third-party~~has ~~Investor~~been ~~Partners~~withheld ~~should~~from ~~depend~~Partnership ~~upon~~distributions ~~the~~through ~~advice~~April of30, ~~their~~2011 ~~own~~and ~~tax~~resides ~~advisors~~in ~~concerning~~ the ~~effects~~Partnership’s ofbank ~~the Well Refracturing Plan~~account.

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Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

Implementation of the Well Refracturing Plan has and will continue to reduce or eliminate Partnership distributions to the Managing General Partner and Investor Partners while the work is being conducted and paid for through the Partnership funds. Depending upon the level of withholding and the results of operations, it is possible that the Managing General Partner and Investor Partners could have taxable income from the Partnership without any corresponding distributions in future years. Non-affiliated Investor Partners are urged to consult a tax advisor to determine all of the relevant federal, state and local tax consequences of the Well Refracturing Plan. The above discussion is not intended as a substitute for careful tax planning, and non-affiliated Investor Partners should depend upon the advice of their own tax advisors concerning the effects of the Well Refracturing Plan.

Partnership Operating Results Overview

Natural gas, NGLs and crude oil sales ~~increased~~decreased 932% or $0.1 million for the first ~~nine~~three months of ~~2010~~2011 compared to the first ~~nine~~three months of ~~2009~~2010, ~~even~~while ~~though~~sales ~~production~~ volumes ~~decreased~~declined 2422% period-to-period. ~~This increase was driven primarily by the improved commodity price environment.~~ The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.8277 for the current year period compared to $46.0760 for the same period a year ago. Realized derivative gains from natural gas and crude oil sales contributed an additional $10.4631 per Mcfe or $~~0.2~~14,000 ~~million~~ to the first ~~nine~~three months of ~~2010~~2011 total revenues compared to an additional $2.83 or $157,000 to the first three months of 2010. Comparatively, the total ~~per~~realized ~~Mcfe~~ price ~~realized~~per Mcfe, consisting of the average sales price and realized derivative gains, decreased to $76.2808 for the current year ~~nine~~three months from $79.7343 for the same prior year period.

The Partnership’s combined natural gas, NGLs and crude oil production expenses and direct costs−~~administrative~~general and ~~general~~administrative, ~~increased~~decreased by $~~0.3~~31,000 ~~million~~ during ~~the 2010 nine month period~~2011. ~~Production~~This ~~costs~~decrease ~~were~~is ~~higher~~ primarily ~~due to~~ the ~~recognition of an environmental remediation liability while direct costs rose as a~~ result of ~~the~~lower ~~Partnership’s~~general ~~independent~~and ~~registered~~administrative ~~public~~expenses ~~accounting~~due ~~firm~~to lower fees ~~rendered~~ for ~~audit~~professional services. ~~These audit services were conducted under the 2010 Partnership SEC reporting compliance effort related to the filing of the Partnership’s financial statements for the years 2005 through 2009.~~

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Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Results of Operations

Summary Operating Results

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

	Three months ended September 30,								Nine months ended September 30,
	Three months ended March 31,
	2010			2009		Change			2010		2009		Change
	2011			2010		Change
Number of producing wells (end of period)		2523			2625		(12	)		25		26		(1	)
Production (1)
Production(1)
Natural gas (Mcf)		3932,~~673~~060			4938,~~480~~001		-2016	%		~~116,543~~		~~149,969~~		~~-22~~	%
Oil (Bbl)		1,574			2,514		-37	%		5,168		7,343		-30	%
NGLs (Bbl)		576			770		-25	%
Natural gas equivalents (Mcfe) (2)		49,117			64,564		-24	%		147,551		194,027		-24	%
Crude oil (Bbl)		1,301			2,138		-39	%
Natural Gas and Oil Sales
Natural gas equivalents (Mcfe)(2)		43,322			55,449		-22	%
Natural gas	$	142,305		$	137,167		4	%	$	487,143	$	418,250		16	%
Average Mcfe per day		481			616		-22	%
Oil		110,201			154,136		-29	%		371,843		371,831		0	%
Natural Gas, NGLs and Crude Oil Sales
Total natural gas and oil sales	$	252,506		$	291,303		-13	%	$	858,986	$	790,081		9	%
Natural gas	$	107,390		$	175,624		-39	%
Realized Gain on Derivatives, net
NGLs		30,279			35,004		-13	%
Natural gas	$	3,771		$	135,163		-97	%	$	137,031	$	520,737		-74	%
Crude oil		112,083			155,406		-28	%
Oil		28,812			42,188		-32	%		78,123		188,207		-58	%
Total natural gas, NGLs and crude oil sales	$	249,752		$	366,034		-32	%
Total realized gain on derivatives, net	$	32,583		$	177,351		-82	%	$	215,154	$	708,944		-70	%
Realized Gain (Loss) on Derivatives, net
Average Selling Price (excluding realized gain on derivatives)
Natural gas	$	32,033		$	133,191		-76	%
Natural gas (per Mcf)	$	3.59		$	2.77		29	%	$	4.18	$	2.79		50	%
Crude oil		(18,293	)		23,859		-177	%
Oil (per Bbl)		70.01			61.31		14	%		71.95		50.64		42	%
Total realized gain on derivatives, net	$	13,740		$	157,050		-91	%
Natural gas equivalents (per Mcfe)		5.14			4.51		14	%		5.82		4.07		43	%
Average Selling Price (excluding realized gain (loss) on derivatives)
Average Selling Price (including realized gain on derivatives)
Natural gas (per Mcf)	$	3.35		$	4.62		-28	%
Natural gas (per Mcf)	$	3.68		$	5.50		-33	%	$	5.36	$	6.26		-14	%
NGLs (per Bbl)		52.57			45.46		16	%
Oil (per Bbl)		88.32			78.09		13	%		87.07		76.27		14	%
Crude oil (per Bbl)		86.15			72.69		19	%
Natural gas equivalents (per Mcfe)		5.8077			76.2660		-2013	%		~~7.28~~		~~7.73~~		-6	%
Average Lifting Cost (per Mcfe) (3)	$	3.05		$	1.87		63	%	$	2.79	$	1.78		56	%
Average Selling Price (including realized gain (loss) on derivatives)
Operating costs and expenses
Natural gas (per Mcf)	$	4.35		$	8.13		-46	%
Direct costs - general and administrative	$	28,560		$	38,338		-26	%	$	319,784	$	66,547			*
NGLs (per Bbl)		52.57			45.46		16	%
Depreciation, depletion and amortization	$	153,498		$	270,047		-43	%	$	465,752	$	803,951		-42	%
Crude oil (per Bbl)		72.09			83.85		-14	%
Cash distributions	$	13,625		$	919,547		-99	%	$	496,811	$	1,977,130		-75	%
Natural gas equivalents (per Mcfe)		6.08			9.43		-36	%
Average cost per Mcfe
Natural gas, NGLs and crude oil production cost(3)	$	2.14		$	1.79		20	%
Depreciation, depletion and amortization		3.31			3.11		6	%
Operating costs and expenses:
Direct costs - general and administrative	$	48,059		$	72,565		-34	%
Depreciation, depletion and amortization		143,349			172,624		-17	%
Cash distributions	$	71,649		$	280,681		-74	%

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

~~(1)~~- ~~Production~~14 ~~is determined by multiplying the gross production volume of properties in which the Partnership has an interest by the percentage of the leasehold or other property interest the Partnership owns.~~-

(2) A ratio of energy content of natural gas and oil (six Mcf of natural gas equals one Bbl of oil) was used to obtain a conversion factor to convert oil production into equivalent Mcf of natural gas.

(3) Lifting costs represent natural gas and oil operating expenses which include production taxes.

- 15 -

Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

_______________

(1)

Production is net and determined by multiplying the gross production volume of properties in which the Partnership has an interest by the average percentage of the leasehold or other property interest the Partnership owns.

(2)

Six Mcf of natural gas equals one Bbl of crude oil or NGL.

(3)

Production costs represent natural gas, NGLs and crude oil operating expenses which include production taxes.

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

●· Bbl – One barrel or 42 U.S. gallons liquid volume

●· MBbl – One thousand barrels

●· Mcf – One thousand cubic feet

●· MMcf – One million cubic feet

●· Mcfe – One thousand cubic feet of natural gas equivalents

●· MMcfe – One million cubic feet of natural gas equivalents

●· MMbtu – One million British Thermal Units

Natural Gas, NGLs and Crude Oil Sales

~~Nine~~For the three months ended ~~September~~March 3031, ~~2010~~2011 as compared to ~~nine~~the ~~months~~same ~~ended~~period ~~September~~in 302010, ~~2009~~natural gas, NGLs and crude oil sales, on an energy equivalency-basis, decreased 22%, due to normal production declines for this stage in the wells’ production life cycle. Additional production declines were the result of four partnership wells which were temporarily shut-in during February for maintenance.

~~The~~Three ~~$0.1~~months ~~million,~~ended orMarch 9%31, ~~increase~~2011 ~~in sales for the 2010 nine month period~~ as compared to ~~the~~three ~~prior~~months ~~year~~ended ~~period,~~March ~~was primarily a reflection of the significantly higher average sales price per Mcfe~~31, of 43%, which was partially offset by a production volume decrease of 24%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.82 for the current year nine month period compared to $4.07 for the same period a year ago.2010

~~Natural~~The ~~gas~~$0.1 ~~revenues~~million, ~~increased~~or ~~by 16~~32%, ~~while~~decrease ~~oil~~in ~~revenues~~sales ~~were~~for ~~unchanged,~~the ~~period-to-period.~~2011 ~~The~~three ~~Partnership’s~~month ~~natural~~period ~~gas~~as ~~revenue~~compared ~~increase~~to ~~resulted~~the ~~from~~prior ~~rising~~year ~~commodity~~period ~~prices~~was ~~per~~primarily ~~Mcf,~~a reflection of ~~50%,~~a ~~which~~sales ~~was~~volume ~~partially~~decrease ~~offset~~of by22% ~~lower~~and ~~Partnership~~a ~~natural~~decline ~~gas~~in ~~production~~sales ~~volumes~~prices of 2213%. The ~~Partnership’s~~average ~~stable~~sales ~~oil~~price ~~revenues~~per ~~were~~Mcfe, excluding the ~~result~~impact of ~~the~~realized ~~rise~~derivative ~~in commodity prices per Bbl~~gains, ofwas ~~42%~~$5.77 ~~which~~for ~~were offset by~~ the ~~decline~~current inyear ~~oil~~three ~~production~~month ~~volumes~~period ofcompared ~~30%~~to ~~during~~$6.60 for the ~~current~~same ~~nine~~period ~~month~~a ~~period~~year ago.

~~Three~~Natural ~~months~~gas, ~~ended~~NGLs ~~September~~and 30crude oil revenues decreased by 39%, ~~2010~~13% asand ~~compared~~28%, respectively. The Partnership’s natural gas revenue decrease resulted from decreased commodity prices per Mcf, of 28%, and lower Partnership natural gas production volumes of 16%. The decrease in NGLs revenue was due to ~~three~~a ~~months~~decrease ~~ended~~of ~~September~~25% 30in NGLs production volumes partially offset by increased commodity prices per Bbl, ~~2009~~of 16%. The crude oil revenue decrease is due primarily to a sales volume decrease of 39% partially offset by the rise in commodity prices per Bbl, of 19% during the current three month period.

~~The~~Commodity ~~13%~~Price ~~decline~~Risk ~~in sales for the 2010 third quarter as compared to the prior year third quarter was primarily a reflection of the decline in production volumes of 24%~~Management, partially offset by a higher average sales price per Mcfe of 14%. Average sales prices per Mcfe, excluding the impact of realized derivative gains, were $5.14 for the current year quarter compared to $4.51 for the same quarter a year ago.Net

The Partnership ~~expects~~uses various derivative instruments to ~~experience~~manage ~~declines~~fluctuations in ~~both~~ natural gas and crude oil ~~production~~prices. The ~~volumes~~Partnership ~~over~~has ~~the~~in ~~wells’~~place ~~life~~a ~~cycles~~variety ~~until~~of ~~such~~floors, ~~time~~collars, ~~that~~fixed-price swaps and basis swaps on a portion of the Partnership’s ~~Wattenberg~~estimated ~~wells~~natural ~~may~~gas beand ~~successfully~~crude ~~refraced~~oil production. ~~Subsequent~~Because the Partnership sells its natural gas and crude oil at similar prices to the indices inherent in the Partnership’s derivative instruments, the Partnership ultimately realizes a ~~successful~~price ~~refracturing~~related to its collars of no less than the floor and no more than the ceiling and, ~~production~~for ~~will~~the ~~once~~Partnership’s ~~again~~commodity beswaps, ~~expected~~the Partnership ultimately realizes the fixed price related to ~~decline~~its swaps.

~~Natural~~Commodity ~~Gas~~price risk management, net, includes realized gains and ~~Oil~~losses ~~Pricing~~and unrealized mark-to-market changes in the fair value of the derivative instruments related to the Partnership’s natural gas and crude oil production. See Note 4, Fair Value of Financial Instruments and Note 5, Derivative Financial Instruments, to the Partnership’s unaudited condensed financial statements included in this report for additional details of the Partnership’s derivative financial instruments.

~~Financial~~- ~~results~~15 depend upon many factors, particularly the price of natural gas and oil and on PDC’s ability to market the Partnership’s production effectively. Natural gas and oil prices are among the most volatile of all commodity prices. This price volatility has a material impact on the Partnership’s financial results. Natural gas and oil prices also vary by region and locality, depending upon the distance to markets, and the supply and demand relationships in that region or locality and availability of sufficient pipeline capacity. This can be especially true in the Rocky Mountain Region. The combination of increased drilling activity and the lack of local markets have resulted in local market oversupply situations from time to time. Like most producers in the region, the Partnership relies on major interstate pipeline companies to construct these pipelines to increase capacity, rendering the timing and availability of these facilities and transportation capacity beyond the Partnership’s control. Oil pricing, unlike natural gas pricing, is driven predominantly by global supply and demand relationships.-

- 16 -

Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

The ~~price~~following attable ~~which~~presents ~~PDC markets~~ the ~~natural~~realized gas produced in the Rocky Mountain Region by the Partnership is based on a variety of prices, which primarily includes natural gas sold at Colorado Interstate Gas, or CIG, prices with a portion sold at Mid-Continent, San Juan Basin, Southern California or other nearby regional prices. The CIG Index, and ~~other~~unrealized ~~indices~~derivative ~~for~~gains production delivered to Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is primarily New York Mercantile Exchange, or NYMEX, based, because of the lack of interstate transmission capacity which moved Rocky Mountain natural gas production to Northeastern U.S. industrial and ~~heating~~losses ~~markets. This~~included ~~negative differential has narrowed~~ in ~~the~~commodity ~~last~~price ~~year~~risk ~~and~~management is(loss) ~~lower than historical variances. This negative differential between NYMEX and CIG averaged $0.72 and $1.16 for the three and nine months ended September 30~~gain, ~~2009, respectively, and narrowed to an average of $0~~net.~~51 and $0.88 for the three and nine months ended September 30, 2010, respectively.~~

Commodity Price Risk Management, Net

	Three months ended March 31,
Commodity price risk management, net	2011			2010
Realized gain (loss)
Natural gas	$	32,033		$	133,191
Crude oil		(18,293	)		23,859
Total realized gain, net		13,740			157,050

Unrealized gain (loss)
Reclassification of realized gain included in prior periods unrealized		(10,762	)		(145,222	)
Unrealized (loss) gain for the period		(48,760	)		355,222
Total unrealized (loss) gain, net		(59,522	)		210,000
Commodity price risk management (loss) gain, net	$	(45,782	)	$	367,050

~~The~~Three ~~Managing~~months ~~General~~ended ~~Partner,~~March ~~on behalf of the Partnership in accordance with the D&O Agreement~~31, is2011 ~~authorized~~as tocompared ~~utilize various derivative instruments~~ to ~~manage~~three ~~volatility~~months inended ~~natural~~March ~~gas and oil prices. Commodity price risk management~~31, net, includes realized gains and losses and unrealized changes in the fair value of derivative instruments related to the Partnership’s natural gas and oil production. The Managing General Partner sets these instruments for PDC, and the various partnerships managed by PDC. Derivative financial instrument positions taken by the Managing General Partner on the Partnership’s behalf are specifically designated to the Partnership’s production volumes. See Note 4, Fair Value Measurements and Note 5, Derivative Financial Instruments, to the Partnership’s unaudited condensed financial statements included in this report, for additional details on the Partnership’s derivative financial instruments.2010

~~The~~Realized ~~following~~gains ~~table~~recognized ~~presents~~in the ~~realized~~three ~~and~~months ~~unrealized~~ended March 31, 2011 are primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of the Partnership’s natural gas derivative positions. Realized gains on natural gas settlements were $61,000 for the three months ended March 31, 2011. These gains were offset in part by a $29,000 loss on the Partnership’s CIG basis protection swaps as the negative basis differential between NYMEX and Colorado Interstate Gas (“CIG”) was narrower than the strike price of the basis positions. The Partnership also realized a $18,000 loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price. Unrealized losses ~~included~~during the three months ended March 31, 2011 are primarily related to the shifts in ~~commodity~~the ~~price~~forward ~~risk~~curves ~~management~~and ~~gain~~their (impact on the fair value of the Partnership’s open positions. The significant shift upward in the crude oil curve resulted in an unrealized loss) of $33,000 ~~net~~during the three months ended March 31, 2011. Likewise, the shifts upward in the natural gas and basis curves resulted in a total unrealized loss of $16,000.

	Three months ended September 30,						Nine months ended September 30,
	2010			2009			2010			2009
Commodity price risk management gain (loss), net
Realized gain
Natural Gas	$	3,771		$	135,163		$	137,031		$	520,737
Oil		28,812			42,188			78,123			188,207
Total realized gain, net		32,583			177,351			215,154			708,944
Unrealized gain (loss)
Reclassification of realized gain included in prior periods unrealized		(16,128	)		(177,593	)		(58,313	)		(577,691	)
Unrealized gain (loss) for the period		240,974			(187,574	)		598,000			(611,951	)
Total unrealized gain (loss), net		224,846			(365,167	)		539,687			(1,189,642	)
Commodity price risk management gain (loss), net	$	257,429		$	(187,816	)	$	754,841		$	(480,698	)

During the three months ended March 31, 2010, the Partnership recorded realized gains of $157,000 as a result of natural gas and crude oil spot prices being lower at settlement compared to the respective strike price. During the three months ended March 31, 2010, the Partnership recorded unrealized gains of $355,000, of which $427,000 was related to the Partnership’s natural gas and crude oil positions, partially offset by unrealized losses on the Partnership’s CIG basis protection swaps of $72,000 as the forward basis differential between NYMEX and CIG had continued to narrow.

~~Nine~~- ~~months~~16 ~~ended September 30, 2010 as compared to nine months ended September 30, 2009~~-

The realized derivative gains for the 2010 nine month period were $0.2 million. These realized gains were primarily a result of lower natural gas and oil spot prices at settlement compared to the respective strike price, offset in part by realized losses due to the basis differential between NYMEX and CIG being narrower than the strike price of the derivative position. For the 2010 nine month period, realized gains related to the Partnership’s commodity positions were $0.2 million which were partially offset by realized losses on the Partnership’s basis position. Unrealized gains for the 2010 nine month period were $0.6 million due primarily to a downward shift in the natural gas and oil forward curves, offset by unrealized losses due to the basis differential between NYMEX and CIG being narrower than the strike price of the derivative position. Unrealized gains on the Partnership’s commodity positions for the 2010 nine month period were $0.6 million, which were partially offset by unrealized losses on the Partnership’s basis position.

For the 2009 nine month period, the Partnership realized significant derivative gains as a result of lower natural gas and oil prices at settlement compared to the respective derivative strike prices. Unrealized losses for the period were related to oil swaps, as the forward strip price of oil rebounded during the period, and the basis position, as the forward basis differential during the period between NYMEX and CIG continued to narrow from the strike price of the derivative position.

- 17 -

Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Three~~The ~~months~~following ~~ended~~table ~~September~~presents ~~30,~~the ~~2010~~Partnership’s asderivative ~~compared~~positions toin ~~three~~effect ~~months~~as ~~ended~~of ~~September~~March 3031, ~~2009~~2011.

The Partnership’s realized gains are a result of lower natural gas and oil spot prices at settlement compared to the respective strike price, offset in part by realized losses due to the basis differential between NYMEX and CIG being narrower than the strike price of the derivative position. For the quarter, realized gains related to the Partnership’s commodity positions were partially offset by realized losses on the Partnership’s basis position. For the 2010 quarter, the unrealized gains of $0.2 million were primarily related to the natural gas positions, as the forward strip price shifted downward during the quarter, and the widening of the NYMEX-CIG basis differential. Unrealized gains on the Partnership’s commodity positions for the 2010 third quarter were approximately $0.2 million, which were partially offset by unrealized losses on the Partnership’s basis position.

	Collars						Fixed-Price Swaps				CIG Basis Protection Swaps
Commodity/ Index	Quantity (Gas-		Weighted Average Contract Price				Quantity (Gas-Mmbtu(1)		Weighted Average Contract		Quantity (Gas-		Weighted Average Contract			Fair Value at March 31,
	Mmbtu(1))		Floors		Ceilings		Oil-Bbls)		Price		Mmbtu(1))		Price			2011(2)

Natural Gas

NYMEX
04/01 - 06/30/2011		-	$	-	$	-		35,391	$	6.78		35,391	$	(1.88	)	$	34,342
07/01 - 09/30/2011		-		-		-		34,795		6.73		34,795		(1.88	)		25,520
10/01 - 12/31/2011		-		-		-		33,790		6.78		33,790		(1.88	)		18,343
01/01 - 03/31/2012		2,176		6.00		8.27		30,401		6.98		32,577		(1.88	)		10,552
04/01 - 12/31/2012		4,441		6.00		8.27		89,594		6.98		94,034		(1.88	)		46,151
2013		-		-		-		115,337		7.12		115,337		(1.88	)		32,790
Total Natural Gas		6,617						339,308				345,924					167,698

Crude Oil
NYMEX
04/01 - 06/30/2011		-		-		-		805		70.75		-		-			(28,514	)
07/01 - 09/30/2011		-		-		-		825		70.75		-		-			(29,837	)
10/01 - 12/31/2011		-		-		-		846		70.75		-		-			(30,567	)
Total Crude Oil		-						2,476				-					(88,918	)

Total Natural Gas and Crude Oil																$	78,780

For the 2009 third quarter, the Partnership realized significant derivative gains as a result of lower natural gas and oil prices at settlement compared to the respective derivative strike prices. Unrealized losses for the period were primarily related to oil swaps, as the forward strip price of oil rebounded during the period, and the basis position, as the forward basis differential during the period between NYMEX and CIG continued to narrow from the strike price of the derivative position.

Natural Gas and Oil Sales Derivative Instruments. The Managing General Partner, on behalf of the Partnership in accordance with the D&O Agreement, is authorized to utilize various derivative instruments to manage volatility in natural gas and oil prices. The Partnership has in place a series of collars, fixed-price swaps and a basis swap on a portion of the Partnership’s natural gas and oil production. See Note 5, Derivative Financial Instruments to the Partnership’s financial statements included in the 2009 Form 10-K for an additional discussion on how each derivative type impacts the Partnership’s cash flows.

The following table presents the Partnership’s derivative positions in effect as of September 30, 2010.

	Collars						Fixed-Price Swaps				CIG Basis Protection Swaps
			Weighted Average				Quantity		Weighted Average				Weighted Average			Fair Value at
Commodity/	Quantity		Contract Price				(Gas-Mmbtu(1)		Contract		Quantity		Contract			September 30,
Index	(Gas-Mmbtu(1))		Floors		Ceilings		Oil-Bbls)		Price		(Gas-Mmbtu(1))		Price			2010(2)
Natural Gas
CIG
10/01 - 12/31/2010		11,818	$	4.75	$	9.45		—	$	—		—	$	—		$	13,163
01/01 - 03/31/2011		17,727		4.75		9.45		—		—		—		—			16,453
NYMEX
10/01 - 12/31/2010		3,181		5.75		8.30		22,242		6.14		26,387		(1.88	)		17,549
01/01 - 03/31/2011		4,340		5.75		8.30		13,813		6.83		18,153		(1.88	)		15,127
04/01 - 06/30/2011		—		—		—		35,391		6.78		35,391		(1.88	)		42,128
07/01 - 09/30/2011		—		—		—		34,795		6.73		34,795		(1.88	)		34,137
10/01 - 12/31/2011		—		—		—		33,790		6.78		33,790		(1.88	)		21,244
2012-2013		6,617		6.00		8.27		235,332		7.05		241,948		(1.88	)		122,424
Total Natural Gas		43,683						375,363				390,464					282,225
Oil
NYMEX
10/01 - 12/31/2010		—		—		—		1,720		92.96		—		—			20,100
01/01 - 03/31/2011		—		—		—		782		70.75		—		—			(9,383	)
04/01 - 06/30/2011		—		—		—		805		70.75		—		—			(10,537	)
07/01 - 09/30/2011		—		—		—		825		70.75		—		—			(11,454	)
10/01 - 12/31/2011		—		—		—		846		70.75		—		—			(12,314	)
Total Oil		—						4,978				—					(23,588	)
Total Natural Gas and Oil																$	258,637

(1)

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

(2) Approximately 91% of the fair value of the Partnership’s derivative assets and all of the Partnership’s derivative liabilities were measured using significant unobservable inputs (Level 3),; see Note 4, Fair Value ~~Measurements~~of Financial Instruments, to the accompanying unaudited condensed financial statements included in this report.

-Natural 18Gas, -NGLs and Crude Oil Production Costs

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

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

Production and operating costs per Mcfe increased to $2.14 during the current period compared to $1.79 for the prior year period due to the effect of higher per-well related expenditures partially offset by lower per-volume related natural gas, NGLs and crude oil production costs. Current period production and operating costs decreased by approximately $7,000, primarily due to reductions in natural gas transportation and lease operating expenses resulting from decreased production volumes as compared to the same period in 2010.

- 17 -

Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Natural Gas and Oil Production Costs

Generally, natural gas and oil production costs vary with changes in total natural gas and 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 and 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.

Nine months ended September 30, 2010 as compared to nine months ended September 30, 2009

For the nine months ended September 30, 2010 compared to the same period in 2009, natural gas and oil production, on an energy equivalency-basis, decreased 24%, due to normal production declines for this stage in the wells’ production life cycle in addition to production reductions that resulted from well equipment problems at two Partnership wells.

Current period production and operating costs were higher by approximately $0.1 million, primarily due to the nonrecurring recognition of an $80,000 environmental remediation liability. On-going production costs, for the 2010 period compared to the prior year period, rose as a result of production tax increases due to higher commodity valuations and higher well operations costs that were the result of the increase in the per well operations fee charged by the Managing General Partner, consistent with the terms of the D&O Agreement. Production volume-associated reductions in production taxes, natural gas transportation and lease operating expenses partially offset these expense increases. Production and operating costs per Mcfe rose to $2.79 during the current period compared to $1.78 for the prior year period due to the effect of higher per-well related expenditures offset by lower per-volume related natural gas and oil production costs.

Three months ended September 30, 2010 as compared to three months ended September 30, 2009

For the quarter ended September 30, 2010 compared to the same period in 2009, natural gas and oil production on an energy equivalency-basis, decreased 24%, primarily as a result of the Partnership wells’ reduced performance due to the same factors that are noted above.

Production and operating costs were higher by $29,000, primarily due to the $30,000 third quarter environmental remediation liability recognition related to four Partnership well locations in addition to higher well operations fees and production taxes, more fully described above. These cost increases were partially offset by lower volume-associated production costs, previously noted. Production and operating costs per Mcfe rose to $3.05 during the current period compared to $1.87 for the prior year period due to the effect of higher per-well related expenditures offset by lower per-volume related natural gas and oil production costs.

Direct Costs−General and Administrative

~~Nine~~Three months ended ~~September~~March 3031, ~~2010~~2011 as compared to ~~nine~~three months ended ~~September~~March 3031, ~~2009~~ 2010

Direct costs – general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer’s reserve reports and legal matters. Direct costs ~~increased~~decreased during the ~~nine~~three months ended ~~September~~March 3031, ~~2010~~2011, compared to the same period in ~~2009~~2010, by approximately $~~0.3~~25,000 ~~million~~ principally due to ~~increased~~decreased fees for ~~professional services related to~~ the ~~Partnership’s~~above ~~SEC~~referenced ~~reporting~~professional ~~compliance efforts previously described in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Partnership Operating Results Overview~~services.

- 19 -

Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Three months ended September 30, 2010 as compared to three months ended September 30, 2009

Depreciation, Depletion and Amortization

~~DD&A~~Three ~~expense~~months ~~related~~ended toMarch ~~natural~~31, ~~gas~~2011 ~~and~~as ~~oil~~compared ~~properties is directly related~~ to ~~production~~three ~~volumes~~months ~~for the period. For the quarter~~ ended ~~September~~March 30, 2009, the Partnership’s natural gas and oil economically producible reserve quantities were determined by valuing in-ground natural gas and oil resources, at the price of natural gas and oil as of December 31, 2008. Upon adoption, in the fourth quarter of 2009, of the SEC’s final rule regarding the modernization of oil and gas reporting, the Partnership changed to a valuation price determined by the 12-month average of the first-day-of-the-month price during each month of 2009.2010

~~Nine~~The ~~months~~DD&A ~~ended~~expense ~~September~~rate 30per Mcfe increased to $3.31 for the 2011 three month period, compared to $3.11 during the same period in 2010. The asincrease in the per Mcfe rates for the 2011 period compared to ~~nine~~the ~~months~~2010 ~~ended~~period ~~September~~is 30due to the changing production mix between the Partnership’s Wattenberg and Grand Valley Fields, ~~2009~~which have significantly different DD&A rates. The production declines, noted in previous sections, partially offset by the increased DD&A expense rate, resulted in a decreased DD&A expense of approximately $29,000 for the 2011 three month period compared to the same 2010 period.

~~The~~Financial ~~DD&A expense rate per Mcfe decreased to $3.16 for the 2010 nine month period~~Condition, ~~compared~~Liquidity to $4.14 during the same period in 2009, as calculated by the respective methodologies described above. The decrease in the per Mcfe rates for the 2010 period compared to the 2009 period is primarily the result of the reduction of the capitalized properties subject to DD&A as a consequence of the fourth quarter 2009 Grand Valley Field loss on natural gas and ~~oil~~Capital properties’ impairment. This reduction in the DD&A expense rate period-over-period due to impairment recognition was partially offset by the effect of the Partnership’s proved developed producing reserve revisions at December 31, 2009 compared to December 31, 2008, in which the downward estimate revision of the Partnership’s proved developed producing natural gas and oil reserves in the Partnership’s Grand Valley Field was partially offset by an upward estimate in Wattenberg Field reserves. The decreased DD&A expense rate, combined with the effect of the production declines noted in previous sections, resulted in a decreased DD&A expense of approximately $0.3 million for the 2010 nine month period compared to the same 2009 period.Resources

~~Three~~The Partnership’s primary sources of cash for the three months ended ~~September~~March 3031, ~~2010~~2011 aswere ~~compared~~from funds provided by operating activities which include the sale of natural gas, NGLs and crude oil production and the realized gains from the Partnership’s derivative positions. These sources of cash were primarily used to ~~three~~fund ~~months~~the Partnership’s operating costs, general and administrative activities and provided monthly distributions to the Investor Partners and PDC, the Managing General Partner. During the quarter ended ~~September~~March 31, 2011, the Managing General Partner withheld $95,000 from the Partnership’s cash distributions pursuant to the Well Refracturing Plan. Through April 30, 2011, $115,000 has been withheld from Partnership distributions to fund this plan. These and subsequent withholdings will provide the funding for planned Wattenberg Field well refracturing costs to be incurred during 2011, and thereafter and are expected to decrease distributions from the 2009 levels for the next several years. For additional information, see Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments—Well Refracturing Plan.

~~The~~Fluctuations ~~DD&A~~in ~~expense~~the ~~rate~~Partnership’s ~~per~~operating ~~Mcfe~~cash ~~decreased~~flows toare $3substantially driven by changes in commodity prices, in production volumes and in realized gains and losses from commodity positions.13 Commodity ~~for~~prices have historically been volatile and the ~~2010~~Managing ~~third~~General ~~quarter,~~Partner ~~compared~~attempts to $4manage this volatility through derivatives.18 Therefore, ~~during~~the primary source of the ~~same~~Partnership’s ~~quarter~~cash inflow ~~2009~~from asoperations ~~calculated~~becomes bythe net activity between the ~~respective~~Partnership’s ~~methodologies~~natural ~~described~~gas, ~~above~~NGLs and crude oil sales and realized natural gas and crude oil derivative gains and losses. ~~The~~However, ~~decrease~~the Partnership does not engage in speculative positions, nor does the ~~per~~Partnership ~~Mcfe~~hold ~~rates~~derivative instruments for 100% of the ~~2010~~Partnership’s ~~third~~expected ~~quarter~~future ~~compared~~production tofrom ~~the~~producing ~~2009~~wells ~~third~~and ~~quarter~~therefore ismay astill ~~result~~experience significant fluctuations in cash flows from operations. As of March 31, 2011, the ~~offsetting~~Partnership ~~effects~~had natural gas and crude oil derivative positions in place covering 88% of the ~~Grand~~expected ~~Valley~~natural ~~Field~~gas ~~impairment~~production ~~recognition~~ and ~~annual~~38% ~~reserve~~of ~~estimate~~expected ~~revisions~~crude oil production for the remainder of 2011, ~~noted~~at ~~above~~an average price of $4.88 per Mcf and $70.75 per Bbl, respectively. The ~~lower~~Partnership’s ~~DD&A~~current ~~expense~~derivative ~~rate,~~position ~~combined~~average ~~with~~prices have declined from the significantly higher average commodity contract strike price levels in effect during the 2010 comparative period which were the result of contracts entered into during the ~~production~~high ~~declines~~2008 ~~noted~~commodity inprice ~~previous~~market; ~~sections~~accordingly, ~~resulted~~the inPartnership anticipates realized gains for the ~~DD&A~~next ~~expense~~12 ~~reduction~~months to remain substantially below gains realized in 2009 and the first quarter of $02010.1 See ~~million~~Results of Operations for further discussion of the ~~2010~~impact ~~third~~of ~~quarter~~prices ~~compared~~and tovolumes on sales from operations and the ~~same~~impact ~~2009~~of ~~quarter~~derivative activities on the Partnership’s revenues.

~~Capital~~- ~~Resources~~18 ~~and Liquidity~~-

The Partnership’s primary sources of cash for both the three and the nine months ended September 30, 2010 were from funds provided by operating activities which include the sale of natural gas and oil production and the realized gains from the Partnership’s derivative positions. These sources of cash were primarily used to fund the Partnership’s operating costs, general and administrative activities and provide monthly distributions to the Investor Partners and PDC, the Managing General Partner. Fluctuations in the Partnership’s operating cash flow are substantially driven by changes in commodity prices, in production volumes and in realized gains and losses from commodity positions. Commodity prices have historically been volatile and the Partnership attempts to manage this volatility through derivatives. Therefore, the primary source of the Partnership’s cash flow from operations becomes the net activity between the Partnership’s natural gas and oil sales and realized derivative gains and losses. However, the Partnership does not engage in speculative positions, nor does the Partnership hold economic hedges for 100% of the Partnership’s expected future production from producing wells and therefore may still experience significant fluctuations in cash flows from operations. As of September 30, 2010, the Partnership had natural gas and oil derivative positions in place covering substantially all of the expected natural gas production and 78% of expected oil production for the remainder of 2010, at an average price of $4.33 per Mcf and $92.96 per Bbl, respectively. The Partnership’s current derivative position average prices have declined from the significantly higher average commodity contract strike price levels in effect during the 2009 comparative period which were the result of contracts entered into during the high 2008 commodity price market; accordingly, the Partnership anticipates realized gains for the next 12 months to remain substantially below gains realized in 2009 and the first quarter of 2010. See Results of Operations for further discussion of the impact of prices and volumes on sales from operations and the impact of derivative activities on the Partnership’s revenues.

- 20 -

Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

The Partnership’s future operations are expected to be conducted with available funds and revenues generated from natural gas, NGLs and crude oil production activities and commodity gains~~, if any~~. Natural gas, NGLs and crude oil production from the Partnership’s existing properties are generally expected to continue a gradual decline in the rate of production over the remaining ~~lives~~life of the wells. Therefore, the Partnership anticipates a lower annual level of natural gas, NGLs and crude oil production and, in the absence of significant price increases or ~~successful~~additional ~~refracturings~~reserve development, lower revenues. The Partnership also expects cash flows from operations to decline if commodity prices remain at current levels or decrease in the future. Under these circumstances decreased production would have a material negative impact on the Partnership’s operations and may result in reduced cash distributions to the Managing General Partner and Investor Partners through the remainder of ~~2010~~2011 and beyond, and may substantially reduce or restrict the Partnership’s ability to participate in the ~~Well~~refracturing ~~Refracturing Plan~~ activities which are more fully described in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments−Well Refracturing Plan.

Working Capital

The Partnership had working capital ofat ~~approximately~~March ~~$0.1~~31, ~~million~~2011 atof ~~September 30~~$2,000 ~~2010~~ compared to negative working capital of $~~0.2~~12,000 ~~million~~ at December 31, ~~2009. This~~2010, ~~decrease~~an increase of approximately $014,000.1 This ~~million~~increase was primarily due to the following changes ~~in balances~~:

●· ~~Natural~~Cash ~~gas~~ and ~~oil~~cash ~~receivables~~equivalents ~~decreased~~increased by $~~0.1~~95,000 ~~million~~between asMarch ~~of September 30~~31, ~~2010~~2011 ~~compared~~and to December 31, ~~2009~~2010.

●· ~~Realized~~Accounts ~~derivative~~receivable ~~gains receivables~~ decreased by $~~0.1~~38,000 ~~million~~between asMarch ~~of September 30~~31, ~~2010~~2011 ~~compared~~and to December 31, ~~2009~~2010.

●· ~~Net~~Realized ~~short-term unrealized~~ derivative gains ~~receivable~~receivables ~~increased~~decreased by ~~approximately~~ $~~0.1~~32,000 ~~million~~between asMarch ~~of September 30~~31, ~~2010~~2011 ~~compared~~and to December 31, ~~2009~~2010.

●· ~~Accounts~~Unrealized ~~payable~~derivative ~~and~~gains ~~accrued~~receivables ~~expenses~~decreased ~~increased~~ by $~~0.1~~34,000 ~~million~~between asMarch ~~of September 30~~31, ~~2010,~~2011 ~~compared~~and to December 31, ~~2009, primarily due to the environmental remediation accrual~~2010.

●· ~~Due~~Crude ~~to the Managing General Partner-other payable, excluding natural gas and~~ oil ~~sales~~inventory ~~received~~increased ~~from third parties and realized derivative gains, decreased~~ by approximately $~~0.1~~7,000 ~~million~~between asMarch ~~of September 30~~31, ~~2010~~2011 ~~compared~~and to December 31, ~~2009~~2010.

~~Working~~· ~~capital,~~Accounts ~~primarily~~payable ~~cash~~ and ~~cash~~accrued ~~equivalents,~~expenses isdecreased ~~expected~~by to$16,000 ~~increase~~between ~~during~~March early 2011 due to the Partnership’s withholding cash from the investors for the initial Wattenberg Field well refracturing activities. Cash will begin to decrease as the funds are utilized in payment of the completed refracturing activities31, ~~currently planned to occur during mid-to-late~~ 2011. ~~Funding for the Well Refracturing Plan will be provided by the withholding of distributable cash flows from the Managing General Partner~~ and ~~Investor~~December ~~Partners~~31, ~~on a pro-rata basis~~2010. Working capital is expected to similarly fluctuate by increasing during periods of Well Refracturing Plan funding and by decreasing during periods when payments are made for completed well refracturing.

-Working 21capital -is expected to fluctuate by increasing during periods of Well Refracturing Plan funding and by decreasing during periods when payments are made for refracturing.

Cash Flows

Cash Flows From Operating Activities

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

- 19 -

Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Cash~~Natural ~~Flows~~gas, NGLs and crude oil prices exhibit a high degree of volatility. These price variations have a material impact on the Partnership’s financial results. Natural gas and NGLs prices vary by region and locality, depending upon the distance to markets, the availability of pipeline capacity and the supply and demand relationships in that region or locality. This can be especially true in the Rocky Mountain Region. The combination of increased drilling activity and the lack of local markets have resulted in local market oversupply situations from time to time. Like most producers in the region, the Partnership relies on major interstate pipeline companies to construct these pipelines to increase capacity, rendering the timing and availability of these facilities beyond the Partnership’s control. Crude oil pricing is predominantly driven by the physical market, supply and demand, the financial markets and global unrest.

The price at which PDC markets the natural gas produced in the Rocky Mountain Region by the Partnership is based on a market basket of prices, which primarily includes natural gas sold at CIG prices with a portion sold at Mid-Continent, San Juan Basin, Southern California or other nearby region prices. The CIG Index and other indices for production delivered to other Rocky Mountain pipelines have historically been less than the price received for natural gas produced in the eastern regions, which is primarily New York Mercantile Exchange, or NYMEX, based. This negative differential has narrowed over the last few years and is lower than historical variances. The negative differential of CIG relative to NYMEX averaged $0.28 and $0.16 for the three months ended March 31, 2011 and 2010, respectively.

Net cash provided by operating activities was approximately $0.2 million for the three months ended March 31, 2011, compared to approximately $0.3 million for the comparable period in 2010. The approximately $0.1 million decrease in cash provided by operating activities was due primarily to the following:

A decrease in natural gas, NGLs and crude oil sales receipts of $0.1 million, or 24%,

A decrease in commodity price risk management realized gains receipts of $0.1 million,

A decrease in production costs and direct costs – general and administrative payments of $0.1 million.

Cash Flows From Investing Activities

The Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of natural gas, NGLs and crude oil or environmental protection. These amounts totaled approximately $41,000 ~~and~~each ~~$96,000~~ for the ~~nine~~three months ended ~~September~~March 3031, ~~2010~~2011 and ~~2009, respectively~~2010.

Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in March 2004 and has distributed $18.56 million through ~~September~~March 3031, ~~2010~~2011. The table below presents ~~the~~ cash distributions to the Partnership’s investors. Managing General Partner ~~and~~distributions ~~Investor~~include ~~Partners,~~amounts ~~including~~distributed to PDC for its Managing General Partner’s 20% ownership share in the Partnership. Investor Partner distributions ~~relating~~include toamounts ~~limited~~distributed ~~partnership~~to ~~units~~Investor ~~repurchased,~~Partners for their 80% ownership share in the ~~periods~~Partnership ~~described~~and include amounts distributed to PDC for limited partnership units repurchased.

Three months ended September 30,	Managing General Partner Distributions		Investor Partners Distributions		Total Distributions
Quarter	Managing		Investor
2010	$	2,725	$	10,900	$	13,625
ended	General Partner		Partners		Total
2009	$	183,909	$	735,638	$	919,547
March 31,	Distributions		Distributions		Distributions
2011	$	14,329	$	57,320	$	71,649
2010	$	56,137	$	224,544	$	280,681

Nine months ended September 30,	Managin General Partner Distributions		Investor Partners Distributions		Total Distributions
2010	$	99,363	$	397,448	$	496,811
2009	$	395,425	$	1,581,705	$	1,977,130

The decrease in total distributions for 2011 as compared to 2010 is primarily due to the significant decrease in cash flows from operating activities during 2011 and from funds held by the Managing General Partner for the Well Refracturing Plan.

The Partnership began funding for the Well Refracturing Plan during October 2010. OnDuring the quarter ended March 31, 2011, on a pro-rata basis based on percentage of ownership in the Partnership, the Partnership withheld $419,000 and $1676,000 from the Managing General Partner and Investor Partners’ share, ~~respectively,~~ of ~~distributable~~ cash ~~flows~~available ~~from the Partnership’s August 2010 natural gas and oil revenues distributed in October 2010. The October 2010 and subsequent withholdings will provide the funding~~ for ~~planned Wattenberg Field well refracturing costs to be incurred during 2011~~distributions, ~~and thereafter~~respectively.

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Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Cash~~Off-Balance ~~Flows~~Sheet ~~From Operating Activities~~Arrangements

~~Net~~As ~~cash~~of ~~provided~~March by31, ~~operating~~2011, ~~activities~~the ~~was~~Partnership ~~$0.5~~had ~~million~~no ~~for~~existing ~~the~~off-balance ~~nine~~sheet ~~months~~arrangements, ~~ended~~as ~~September~~defined ~~30,~~under ~~2010~~SEC rules, ~~compared~~which tohave ~~approximately~~or ~~$2.1~~are ~~million~~reasonably ~~for~~likely ~~the~~to ~~comparable~~have ~~period~~a inmaterial ~~2009. The~~current ~~approximately~~or ~~$1.6~~future ~~million~~effect ~~decrease~~on inthe ~~cash~~Partnership’s ~~provided~~financial bycondition, ~~operating~~revenues ~~activities~~or ~~was~~expenses, ~~due~~results ~~primarily~~of tooperations, ~~the~~liquidity, ~~following:~~capital expenditures or capital resources.

● A decrease in commodity price risk management realized gains receipts of $0.5 million, or 63%, accompanied by increases in natural gas and oil production costs of approximately $0.1 million, or 18%, and in direct costs – general and administrative of $0.3 million;

● A decrease in accounts payable−accrued expenses payments of $0.1 million and

● An increase in Due to Managing General Partner-other, net, payments of approximately $0.8 million, excluding natural gas and oil sales received from third parties and realized derivative gains.

Commitments and Contingencies

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

Recent Accounting Standards

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

Critical Accounting Policies and Estimates

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

There have been no ~~other~~ significant changes to the Partnership’s critical accounting policies and estimates or in the underlying accounting assumptions and estimates used in these critical accounting policies from those disclosed in the financial statements and accompanying notes contained in the Partnership’s ~~2009~~2010 Form 10-K, such policies include revenue recognition, derivatives instruments, fair value measurements, natural gas and oil properties, and asset retirement obligations are based on, among other things, judgments and assumptions made by management that include inherent risks and uncertainties.

Off-Balance Sheet Arrangements

Currently, the Partnership does not have any off-balance sheet arrangements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

- 23 -

Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 4. Controls and Procedures

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

(a) Evaluation of Disclosure Controls and Procedures

As of ~~September~~March 3031, ~~2010~~2011, PDC, as Managing General Partner on behalf of the Partnership, carried out an evaluation, under the supervision and with the participation of the Managing General Partner’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Partnership’s disclosure controls and procedures pursuant to ~~Securities~~ Exchange Act ~~Rule~~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~~disclosure ~~Committee~~committee in an effort to ensure that information required to be disclosed in the SEC reports that wethe ~~file~~Partnership files or ~~submit~~submits under the Exchange Act ~~are~~is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that such information is accumulated and communicated to the Partnership’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely discussion regarding required ~~financial~~ disclosure.

~~Based~~- on21 the results of this evaluation, the Managing General Partner’s Chief Executive Officer and the Chief Financial Officer concluded that the Partnership’s disclosure controls and procedures were effective as of September 30, 2010.-

Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Based on the results of this evaluation, the Managing General Partner’s Chief Executive Officer and the Chief Financial Officer concluded that the Partnership’s disclosure controls and procedures were effective as of March 31, 2011.

(b) Changes in Internal Control over Financial Reporting

During the three months ended March 31, 2011, PDC, the Managing General Partner, made no changes in the Partnership’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the ~~Securities~~ Exchange Act ~~of 1934~~) ~~during the quarter ended September 30, 2010,~~ that have materially affected or are reasonably likely to materially affect the Partnership’s internal control over financial reporting.

- 2422 -

Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

~~Information~~Neither ~~regarding~~ the ~~Registrant’s~~Partnership ~~legal~~nor ~~proceedings~~PDC, ~~can~~in beits ~~found~~capacity inas ~~Note~~the 6,Managing ~~Commitments~~General ~~and~~Partner ~~Contingencies~~of the Partnership, are party to any pending legal proceeding that PDC believes would have a materially adverse effect on the Partnership’s ~~accompanying~~business, ~~unaudited~~financial ~~condensed~~condition, ~~financial~~results ~~statements~~of operations or liquidity.

Item 1A. Risk Factors

Not applicable.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Unit Repurchase Program: Beginning March 2007, the third anniversary of the date of the first Partnership cash distributions, Investor Partners of the Partnership may request ~~that~~ the Managing General Partner repurchase their respective individual Investor Partner units, up to an aggregate total limit during any calendar year for all requesting Investor Partner unit repurchases of 10% of the initial subscription units.

The following table presents information about the Managing General Partner’s limited partner unit repurchases during the three months ended ~~September~~March 3031, ~~2010~~2011.

Period	Total Number of Units Repurchased		Average Price Paid per Unit
	Total Number of Units Repurchased		Average Price Paid per Unit
July 1−31, 2010		0.25	$	3,660
Period
August 1−31, 2010		0.50		3,460
January 1−31, 2011		0.75	$	2,900
September 1−30, 2010		—		—
February 1−28, 2011		1.25		2,548
Total third quarter Unit Repurchase Program repurchases		0.75
March 1−31, 2011		-		-
Total first quarter Unit Repurchase Program repurchases		2.00

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. [Removed and Reserved]

Item 5. Other Information

Not applicable.

- 2523 -

Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 6. Exhibits Index

~~(a) Exhibit~~The ~~Index~~exhibits presented below are in addition to those presented in the Partnership’s Form 10-K.

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed Herewith
3.1	Limited Partnership Agreement	10-K	000-50616	3.1	02/12/2010
31.1	Certification by Chief Executive Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership, pursuant to Rule 13a-14(a)/15d-14(c) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					X
3.2	Certificate of limited partnership which reflects the organization of the Partnership under West Virginia law	10-K	000-50616	3.2	02/12/2010
31.2	Certification by Chief Financial Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership, pursuant to Rule 13a-14(a)/15d-14(c) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					X
10.1	Drilling and operating agreement between the Partnership and Petroleum Development Corporation, as Managing General Partner.	10-K	000-50616	10.1	02/12/2010
32.1	Certifications by Chief Executive Officer and Chief Financial Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership, pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.					X
10.2	Form of assignment of leases to the Partnership	10-K	000-50616	10.2	02/12/2010
10.4	Gas Purchase and Processing Agreement between Duke Energy Field Services, Inc.; United States Exploration, Inc.; and Petroleum Development Corporation, dated October 28, 1999 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)	10-12G/A Amend 3	000-53201	10.3	03/31/2009
10.5	Gas Purchase and Processing Agreement between Natural Gas Associates, a Colorado partnership, and Aceite Energy Corporation, Walker Exploratory Program 1982-A Limited and Cattle Creek Company, dated October 14, 1983 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)	10-12G/A Amend 3	000-53201	10.4	03/31/2009
10.6	Gas Purchase and Processing Agreement between Natural Gas Associates, a Colorado partnership, and SHF Partnership, a Colorado general partnership, Trailblazer Oil and Gas, Inc., Alfa Resources, Inc., Pulsar Oil and Gas, Inc., Overthrust Oil Royalty Corporation, Corvette Petroleum Ltd., Robert Lanari, an individual, and Toby A Martinez, an individual, dated September 21, 1983 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)	10-12G/A Amend 3	000-53201	10.5	03/31/2009

- 2624 -

Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

10.7

Domestic Crude Oil Purchase Agreement with ConocoPhillips Company, dated January 1, 1993, as amended by agreements with Teppco Crude Oil, LLC dated August 2, 2007; September 24, 2007; October 17, 2007; January 7, 2008; January 15, 2008; and April 17, 2008 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)

10-12G/A Amend 3

000-53201

10.6

03/31/2009

10.8

Gas Purchase Agreement between Williams Production RMT Company, Riley Natural Gas Company and Petroleum Development Corporation, dated as of June 1, 2006 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)

10-12G/A Amend 3

000-53201

10.7

03/31/2009

10.9

Domestic Crude Oil Purchase Agreement between Suncor Energy Marketing Inc. and Petroleum Development Corporation, dated April 22, 2008 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership]

10-Q

000-53201

10.1

05/18/2009

31.1

Certification by Chief Executive Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership, pursuant to Rule 13a-14(a)/15d-14(c) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certification by Chief Financial Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership, pursuant to Rule 13a-14(a)/15d-14(c) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

- 27 -

Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

32.1

Certifications by Chief Executive Officer and Chief Financial Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership, pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002.

- 28 -

Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

PDC 2003-B Limited Partnership

By its Managing General Partner

Petroleum Development Corporation (dba PDC Energy)

By /s/ Richard W. McCullough

Richard W. McCullough

Chairman and Chief Executive Officer

of Petroleum Development Corporation (dba PDC Energy)

~~December~~May 1510, ~~2010~~2011

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:

Signature	Title	Date
/s/ Richard W. McCullough	Chairman and Chief Executive Officer	~~December~~May 1510, ~~2010~~2011
Richard W. McCullough	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
	(Principal executive officer)
/s/ Gysle R. Shellum	Chief Financial Officer	~~December~~May 1510, ~~2010~~2011
Gysle R. Shellum	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
	(Principal financial officer)
/s/ R. Scott Meyers	Chief Accounting Officer	~~December~~May 1510, ~~2010~~2011
R. Scott Meyers	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
	(Principal accounting officer)

- 2925 -

Filing Compare · PDC 2003-B LP