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 000-51452

PDC 2005-B Limited Partnership ~~(Exact name of registrant as specified in its charter)~~

(Exact name of registrant as specified in its charter)


West Virginia		20-2088726
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1775 Sherman Street, Suite 3000, Denver, Colorado 80203

(Address of principal executive offices) (Zip code)

(303) 860-5800

(Registrant’'s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such ~~files~~reports) and (2) has been subject to such filing requirements for the past 90 days.

Yes þ No o ¨

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

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

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

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

As of ~~September~~March 3031, ~~2010~~2011 the Partnership had 2,022.64 units of limited partnership interest and no units of additional general partnership interest outstanding.

INDEX

PDC 2005-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)	~~Financial Statements (unaudited)~~
	Condensed Balance Sheets (unaudited)	~~Condensed Balance Sheets (unaudited)~~3	2
	Condensed Statements of Operations (unaudited)	~~Condensed Statements of Operations (unaudited)~~4	3
	Condensed Statements of Cash Flows (unaudited)	~~Condensed Statements of Cash Flows (unaudited)~~5	4
	Notes to Unaudited Condensed Financial Statements	~~Notes to Unaudited Condensed Financial Statements~~6	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~13	11
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	~~Quantitative and Qualitative Disclosures About Market Risk~~25	21
Item 4.	Controls and Procedures	~~Controls and Procedures~~25	21
PART II – OTHER INFORMATION		~~PART II – OTHER INFORMATION~~
Item 1.	Legal Proceedings	~~Legal Proceedings~~26	22
Item 1A.	Risk Factors	~~Risk Factors~~26	22
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	~~Unregistered Sales of Equity Securities and Use of Proceeds~~26	22
Item 3.	Defaults Upon Senior Securities	~~Defaults Upon Senior Securities~~26	22
Item 4.	[Removed and Reserved]	~~[Removed and Reserved]~~26	22
Item 5.	Other Information	~~Other Information~~26	22
Item 6.	Exhibits Index	~~Exhibits~~27	23
	SIGNATURES	~~SIGNATURES~~28	26

~~INDEX~~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 2005-B 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 volumes, worldwide demand, and commodity prices for natural gas and oil;

changes in estimates of proved reserves;

· ~~declines~~inaccuracy ~~in the values~~ of ~~the~~reserve ~~Partnership’s~~estimates ~~natural gas~~ and ~~oil~~expected ~~properties~~production ~~resulting from impairments~~rates;

· ~~the~~declines ~~timing~~in ~~and~~the ~~extent~~value of the Partnership’s ~~success~~natural ingas ~~further developing~~ and ~~producing~~crude ~~the~~oil ~~Partnership’s~~properties ~~natural~~resulting ~~gas~~in ~~and oil reserves;~~impairments

the availability of Partnership future cash flows for investor distributions or funding of refracturing activities;

the timing and extent of the Partnership’s success in further developing and producing the Partnership’s reserves;

the Managing General Partner’s ability to acquire drilling rig services, supplies and services at reasonable prices;

· risks ~~incident~~incidental to the refracturing and operation of natural gas and crude oil wells;

· future production and refracturing costs;

· the availability of Partnership future cash flows for investor distributions or funding of Well Refracturing Plan activities;

the availability of sufficient pipeline and other transportation facilities to carry Partnership production and the impact of these facilities on price;

· the effect of existing and future laws, governmental regulations and the political and economic climate of the ~~United~~U.S. ~~States~~as ofwell ~~America,~~as orother ~~U.S.~~oil producing countries throughout the world;

· changes in environmental laws, ~~and~~ the ~~regulations~~regulation and enforcement ~~related~~of those laws and the costs to comply with those laws;

· the ~~identification~~impact of ~~and~~environmental ~~severity~~events, ofgovernmental ~~environmental~~responses to the events and ~~governmental~~the ~~responses~~Managing General Partner’s ability to ~~the~~insure adequately against such events;

· ~~the~~competition ~~effect~~in ofthe ~~natural~~oil ~~gas~~ and ~~oil~~gas ~~derivatives activities~~industry;

· the ~~availability~~success of ~~funding for~~ the ~~consideration~~Managing ~~payable~~General byPartner ~~PDC~~in ~~and~~marketing ~~its wholly-owned subsidiary to consummate~~ the ~~prospective~~Partnership’s ~~mergers~~oil ~~under~~and ~~the Acquisition Plan~~gas;

· the ~~timing~~effect ~~and closing, if consummated,~~ of ~~the~~natural ~~proposed~~gas ~~merger of the 2004 partnerships with~~ and ~~into~~crude aoil ~~wholly-owned~~derivative ~~subsidiary of PDC~~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 March 31, 2010 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.~~General Other 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.

- 1 -

~~INDEX~~Index

PDC 2005-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.

- 2 -

Index

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)

PDC 2005-B Limited Partnership

Condensed Balance Sheets

(unaudited)

	September 30,			December 31,
	March 31,			December 31,
	2010			2009*
	2011			2010*
Assets
Current assets:
Cash and cash equivalents	$	~~272~~442,~~724~~976		$	~~201~~332,~~006~~724
Accounts receivable		~~232~~288,~~901~~892			~~354~~263,~~817~~151
Oil inventory		38,880			29,980
Crude oil inventory		36,132			56,629
Due from Managing General Partner-derivatives		~~721~~656,~~323~~668			~~487~~627,~~802~~166
Due from Managing General Partner-other, net		~~158~~99,~~659~~381			~~578~~163,~~687~~036
Total current assets		1,~~424~~524,~~487~~049			1,~~652~~442,~~292~~706
Oil and gas properties, successful efforts method, at cost		45,036,137			45,007,332
Natural gas and crude oil properties, successful efforts method, at cost		45,061,383			45,057,210
Less: Accumulated depreciation, depletion and amortization		(2224,~~995~~210,~~074~~114	)		(2023,~~826~~606,~~745~~787	)
Oil and gas properties, net		22,041,063			24,180,587
Natural gas and crude oil properties, net		20,851,269			21,450,423
Due from Managing General Partner-derivatives		1841,~~150,226~~097			~~368~~982,~~502~~178
Other assets		3952,~~348~~445			1845,~~917~~853
Total noncurrent assets		2321,~~230~~744,~~637~~811			2422,~~568~~478,~~006~~454
Total Assets	$	2423,~~655~~268,~~124~~860		$	2623,~~220~~921,~~298~~160
Liabilities and Partners’ Equity
Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	7068,~~382~~356		$	3628,~~571~~315
Due to Managing General Partner-derivatives		~~434~~671,~~858~~264			~~377~~564,~~704~~535
Total current liabilities		~~505~~739,~~240~~620			~~414~~592,~~275~~850
Due to Managing General Partner-derivatives		~~853~~662,~~188~~199			1745,~~114,345~~409
Asset retirement obligations		~~543~~558,~~840~~395			~~522~~551,~~803~~063
Total liabilities		1,~~902~~960,~~268~~214			21,~~051~~889,~~423~~322
Commitments and contingent liabilities
Partners’ equity:
Partners' equity:
Managing General Partner		4,~~561~~272,~~640~~798			4,~~844~~417,~~843~~437
Limited Partners - 2,022.64 units issued and outstanding		1817,~~191~~035,~~216~~848			1917,~~324~~614,~~032~~401
Total Partners’ equity		22,752,856			24,168,875
Total Partners' equity		21,308,646			22,031,838
Total Liabilities and Partners’ Equity	$	24,655,124		$	26,220,298
Total Liabilities and Partners' Equity	$	23,268,860		$	23,921,160

*Derived from audited 2009 balance sheet________________________________

*Derived from audited 2010 balance sheet

See accompanying notes to unaudited condensed financial statements.

- 23 -

~~INDEX~~Index

PDC 2005-B Limited Partnership

Condensed Statements of Operations

(unaudited)

	Three months ended September 30,						Nine months ended September 30,
	Three months ended March 31,
	2010			2009			2010		2009
	2011			2010
Revenues:
Natural gas and oil sales	$	785,245		$	801,674		$	2,777,410	$	2,281,976
Natural gas, NGLs and crude oil sales	$	880,859		$	1,171,574
Commodity price risk management gain (loss), net		584,178			(427,874	)		1,726,392		(1,140,059	)
Commodity price risk management (loss) gain, net		(110,654	)		828,302
Total revenues		1770,~~369,423~~205			~~373~~1,~~800~~999,876			~~4,503,802~~		~~1,141,917~~
Operating costs and expenses:
Natural gas and oil production costs		509,094			318,823			1,201,525		875,830
Natural gas, NGLs and crude oil production costs		355,096			302,984
Direct costs - general and administrative		3547,~~213~~760			7935,~~809~~743			~~114,818~~		~~346,574~~
Depreciation, depletion and amortization		~~668~~603,~~850~~327			1782,~~235,465~~307			~~2,168,329~~		~~3,780,560~~
Accretion of asset retirement obligations		7,~~116~~332			46,~~891~~909			~~21,037~~		~~14,673~~
Total operating costs and expenses		1,~~220~~013,~~273~~515			1,~~638~~127,~~988~~943			~~3,505,709~~		~~5,017,637~~
Income (loss) from operations		149,150			(1,265,188	)		998,093		(3,875,720	)
Net (loss) income	$	(243,310	)	$	871,933
Interest expense		—			(1,322	)		—		(1,322	)
Net (loss) income allocated to partners	$	(243,310	)	$	871,933
Interest income		—			8,233			—		24,019
Less: Managing General Partner interest in net (loss) income		(48,662	)		174,387
Net income (loss)	$	149,150		$	(1,258,277	)	$	998,093	$	(3,853,023	)
Net (loss) income allocated to Investor Partners	$	(194,648	)	$	697,546
Net income (loss) allocated to partners	$	149,150		$	(1,258,277	)	$	998,093	$	(3,853,023	)
Net (loss) income per Investor Partner unit	$	(96	)	$	345
Less: Managing General Partner interest in net income (loss)		29,830			(251,656	)		199,619		(770,605	)
Investor Partner units outstanding		2,022.64			2,022.64
Net income (loss) allocated to Investor Partners	$	119,320		$	(1,006,621	)	$	798,474	$	(3,082,418	)
Net income (loss) per Investor Partner unit	$	59		$	(498	)	$	395	$	(1,524	)
Investor Partner units outstanding		2,022.64			2,022.64			2,022.64		2,022.64

See accompanying notes to unaudited condensed financial statements.

- 34 -

~~INDEX~~Index

PDC 2005-B Limited Partnership

Condensed Statements of Cash Flows

(unaudited)

	Nine months ended September 30,
	Three months ended March 31,
	2010			2009
	2011			2010
Cash flows from operating activities:
Net income (loss)	$	998,093		$	(3,853,023	)
Net (loss) income	$	(243,310	)	$	871,933
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Adjustments to net (loss) income to reconcile to net cash provided by operating activities:
Depreciation, depletion and amortization		2603,~~168,329~~327			3782,~~780,560~~307
Accretion of asset retirement obligations		217,~~037~~332			146,~~673~~909
Unrealized (gain) loss on derivative transactions		(1,219,248	)		2,837,250
Unrealized loss (gain) on derivative transactions		135,098			(461,884	)
Changes in operating assets and liabilities:
Decrease in accounts receivable		121,916			15,930
Increase in accounts receivable		(25,741	)		(25,989	)
(Increase) decrease in oil inventory		(8,900	)		12,289
Decrease in crude oil inventory		20,497			7,498
Increase in other assets		(206,~~431~~592	)		(126,~~132~~786	)
Increase (decrease) in accounts payable and accrued expenses		33,811			(23,702	)
Increase in accounts payable and accrued expenses		40,041			4,644
Decrease in due from Managing General Partner - other, net		420,028			936,329
Decrease in Due from Managing General Partner - other, net		63,655			8,068
Net cash provided by operating activities		2594,~~514,635~~307			31,~~708~~186,~~174~~700
Cash flows from investing activities:
Capital expenditures for oil and gas properties		(28,805	)		(29,321	)
Capital expenditures for natural gas and crude oil properties		(4,173	)		(5,762	)
Proceeds from drilling advance refund from Managing General Partner		—			54,741
Net cash used in investing activities		(4,173	)		(5,762	)
Net cash (used in) provided by investing activities		(28,805	)		25,420
Cash flows from financing activities:
Distributions to Partners		(2479,~~414,112~~882	)		(31,~~977~~180,~~315~~938	)
Net cash used in financing activities		(2479,~~414,112~~882	)		(31,~~977~~180,~~315~~938	)
Net increase in cash and cash equivalents		71110,~~718~~252			~~(243,721~~-	)
Cash and cash equivalents, beginning of period		~~201~~332,~~006~~724			~~444~~201,~~727~~006
Cash and cash equivalents, end of period	$	~~272~~442,~~724~~976		$	201,006

See accompanying notes to unaudited condensed financial statements.

- 45 -

~~INDEX~~Index

PDC 2005-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

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

(unaudited)

Note 1−General and Basis of Presentation

~~The~~ PDC 2005-B Limited Partnership (the "“Partnership"” or the “Registrant”) was organized as a limited partnership ~~on February 8~~, ~~2005~~ 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, ~~May~~the ~~18,~~Partnership ~~2005~~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~~1,619 ~~paid~~Investor ~~for 37~~Partners.77 PDC ~~units~~is ofthe ~~limited~~designated ~~partner~~Managing ~~interests~~General ~~and~~Partner ~~1,984.87 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%~~51.7 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~~$9,979 ~~upon~~per ~~the~~unit. As ~~portion~~ of ~~units~~March ~~owned~~31, in2011, the ~~Partnership,~~Managing ~~and~~General 20Partner owns 22.0% toof the ~~Managing General Partner~~Partnership.

AsThe ofPartnership ~~September~~expects ~~30,~~continuing ~~2010,~~operations ~~there~~of ~~were~~its ~~1,625~~natural ~~Investor~~gas ~~Partners. As~~and ofcrude ~~September~~oil ~~30,~~properties ~~2010,~~until ~~the~~such ~~Managing~~time ~~General~~the ~~Partner~~Partnership’s ~~has~~wells ~~repurchased~~are ~~42.91~~depleted ~~units~~or ofbecome ~~the~~uneconomical ~~total~~to 2produce,~~022.64~~ ~~outstanding~~at ~~units~~which oftime ~~Partnership~~they ~~interests~~may ~~from~~be ~~Investor~~sold ~~Partners~~or atplugged, anreclaimed ~~average~~and ~~price~~abandoned. The Partnership’s maximum term of ~~$11,004~~existence ~~per~~extends ~~unit~~through ~~and~~December 31, as2055, 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 ~~conduct~~statement 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 ~~Partnership’s~~audited ~~wells~~financial ~~are~~statements ~~depleted~~have 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, ~~2055~~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.

InOn ~~the~~November ~~Managing~~16, ~~General~~2010, ~~Partner’s~~the ~~opinion~~Partnership, ~~the~~PDC ~~accompanying~~and ~~interim~~its ~~unaudited~~wholly-owned ~~condensed~~subsidiary, ~~financial~~DP ~~statements~~2004 ~~contain~~Merger ~~all~~Sub, ~~adjustments~~LLC (~~consisting~~“DP ofMerger ~~only normal recurring adjustments~~Sub”), ~~necessary for~~ a ~~fair~~Delaware ~~statement~~limited ofliability ~~the~~company, ~~Partnership’s~~entered ~~financial~~into ~~statements~~an ~~for~~agreement ~~interim~~and ~~periods~~plan ~~in accordance with accounting principles generally accepted in the United States~~ of ~~America~~merger (the “~~U.S.~~Merger ~~GAAP~~Agreement”), ~~and~~in ~~with~~which ~~the~~PDC ~~instructions~~seeks to ~~Form~~acquire ~~10-Q and Article 10 of Regulation S-X of~~ the ~~Securities and Exchange Commission~~Partnership, orsubject ~~SEC. Accordingly, pursuant~~ to ~~such~~the ~~rules~~vote and ~~regulations,~~approval ~~certain~~of ~~notes~~a ~~and~~majority ~~other~~of ~~financial~~the ~~information~~limited ~~included~~partnership inunits ~~audited~~held, ~~financial~~as ~~statements~~of ~~have~~the ~~been~~close ~~condensed~~of orbusiness ~~omitted. The information presented in this quarterly report~~ on ~~Form~~January ~~10-Q~~31, ~~should~~2011, beby ~~read~~Investor inPartners ~~conjunction~~of ~~with~~ the Partnership’s, ~~audited~~other ~~financial~~than ~~statements~~PDC and ~~notes~~its ~~thereto~~affiliates ~~included~~(“non-affiliated ininvestor ~~the Partnership’s 2009 Form 10-K~~partners”). ~~The~~Pending ~~Partnership’s~~the ~~accounting~~outcome ~~policies~~of ~~are described in~~ the ~~Notes~~proposed toMerger ~~Financial~~Agreement, ~~Statements~~the inManaging ~~the~~General ~~Partnership’s~~Partner ~~2009~~suspended, ~~Form~~as ~~10-K~~of ~~and~~December ~~updated~~1, ~~as necessary~~2010, inthe ~~this~~opportunity ~~Form~~for ~~10-Q. The~~an ~~results~~individual ofnon-affiliated ~~operations~~investor ~~for~~partner ~~the~~to ~~three~~request ~~and~~that ~~nine~~PDC ~~months~~repurchase ~~ended~~their ~~September~~respective ~~30,~~limited ~~2010,~~partnership ~~and~~units. For ~~the~~more ~~cash~~information ~~flows~~on ~~for~~ the ~~nine~~proposed ~~months~~Merger ~~ended~~Agreement, ~~September~~see ~~30,~~Note ~~2010~~3, ~~are~~Transactions ~~not~~with ~~necessarily~~Managing ~~indicative~~General ofPartner ~~the~~and ~~results~~Affiliates−Proposed toMerger bewith ~~expected~~PDC ~~for~~and ~~the~~DP ~~full~~2004 ~~year~~Merger orSub, ~~any~~LLC, ~~other~~which ~~future period~~follows.

~~Note~~- ~~2−Recent~~6 ~~Accounting Standards~~-

~~Recently Adopted Accounting Standards~~Index

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 also added a new requirement to disclose fair value transfers in and out of Levels 1 and 2 and describe the reasons for the transfers. The adoption of these changes as of January 1, 2010, did not have a material impact on the Partnership’s accompanying unaudited condensed financial statements.

- 5 -

INDEX

PDC 2005-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

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

(unaudited)

~~Recently~~Note ~~Issued~~2−Recent Accounting Standards

Recently Adopted 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~~These ~~change~~changes ~~will~~were be effective for the Partnership’s financial statements issued for annual reporting periods, and for interim reporting periods within the year, beginning after December 15, 2010. The ~~Partnership does not expect~~ adoption of ~~these~~this ~~changes~~change todid not have a material ~~effect~~impact 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~~Ongoing ~~Managing General Partner transacts business on behalf of the~~ Partnership ~~under~~Business ~~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.Operations

The ~~following~~Managing ~~table~~General ~~presents~~Partner ~~transactions~~transacts ~~with~~business on behalf of the ~~Managing~~Partnership ~~General~~under ~~Partner~~the ~~reflected~~authority inof the ~~balance~~D&O ~~sheet~~Agreement. Revenues ~~line~~and ~~item~~other –cash ~~Due~~inflows ~~from~~received (on behalf of the Partnership are distributed to the Partners net of (after deducting) ~~Managing~~corresponding ~~General~~operating ~~Partner-~~costs and other, ~~net~~cash ~~which~~outflows ~~remain~~incurred ~~undistributed~~on orbehalf ~~unsettled~~of ~~with~~the Partnership. The fair value of the Partnership’s ~~investors~~portion asof 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 ~~dates~~case ~~indicated~~of net unrealized losses.

	September 30,			December 31,
	2010			2009
Natural gas and oil sales revenues collected from the Partnership’s third-party customers	$	315,288		$	394,751
Commodity Price Risk Management, Realized Gains		70,393			310,897
Other (1)		(227,022	)		(126,961	)
Total Due from Managing General Partner-other, net	$	158,659		$	578,687

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

	March 31,			December 31,
	2011			2010

Natural gas, NGLs and crude oil sales revenues collected from the Partnership's third-party customers	$	264,323		$	286,822
Commodity price risk management, realized gain		12,053			91,058
Other (1)		(176,995	)		(214,844	)
Total Due from Managing General Partner-other, net	$	99,381		$	163,036

(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.

- 67 -

~~INDEX~~Index

PDC 2005-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, Derivative Financial Instruments, with the Managing General Partner and its affiliates for the three ~~and nine~~ months ended ~~September~~March 3031, ~~2010~~2011 and ~~2009~~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 September 30,				Nine months ended September 30,
	Three months ended March 31,
	2010		2009		2010		2009
	2011		2010
Well operations and maintenance	$	~~431~~287,~~174~~277	$	~~242~~232,~~233~~388	$	~~979,066~~	$	~~672,859~~
Gathering, compression and processing fees		3028,~~069~~700		3127,~~253~~525		~~85,283~~		~~83,391~~
Direct costs - general and administrative		3547,~~213~~760		7935,~~809~~743		~~114,818~~		~~346,574~~
Cash distributions*		92,739		335,048		523,303		844,973
Cash distributions (1)		105,783		255,925

*(1) Cash distributions include $79,~~229~~806 and $4019,~~481~~738 during the three ~~and nine~~ months ended ~~September~~March 3031, ~~2010,~~2011 ~~respectively,~~ and ~~$16~~2010,~~157~~ ~~and $49,511 during the three and nine months ended September 30, 2009,~~ respectively, related to equity cash distributions on Investor Partner units repurchased by PDC.

~~Note~~Proposed ~~4−Fair~~Merger ~~Value~~with ~~Measurements~~PDC and DP 2004 Merger Sub, LLC

~~Derivative~~On ~~Financial~~November ~~Instruments. The~~16, ~~Partnership~~2010, ~~measures~~the ~~fair~~Partnership, ~~value~~PDC ~~based~~and ~~upon~~DP ~~quoted~~Merger ~~market~~Sub ~~prices,~~entered ~~where~~into ~~available. The~~the ~~valuation~~Merger ~~determination~~Agreement, ~~includes:~~in ~~(1)~~which ~~identification~~PDC ofseeks ~~the inputs~~ to acquire the ~~fair~~Partnership, ~~value~~subject ~~methodology~~to ~~through~~ the ~~review~~vote ~~of counterparty statements~~ and ~~other~~approval ~~supporting documentation, (2) determination~~ of ~~the~~a ~~validity~~majority of the ~~source~~limited ofpartnership ~~the~~units ~~inputs~~held, ~~(3)~~as ~~corroboration~~ of the ~~original~~close ~~source~~ of ~~inputs~~business ~~through~~on ~~access~~January ~~to multiple quotes~~31, ~~if available~~2011, orby ~~other~~non-affiliated ~~information~~investor ~~and (4) monitoring changes in valuation methods and assumptions~~partners. ~~The~~ ~~methods~~Pursuant ~~described~~to ~~above~~the ~~may~~Merger ~~produce~~Agreement, aif ~~fair~~the ~~value~~merger ~~calculation~~is ~~that~~approved ~~may~~by ~~not~~the beholders ~~indicative~~ of ~~future~~a ~~fair~~majority ~~values. The~~of ~~valuation~~the ~~determination~~limited ~~also~~partnership ~~gives~~units ~~consideration~~held toby ~~nonperformance~~the ~~risk~~non-affiliated oninvestor ~~Partnership~~partners ~~liabilities~~of inthe ~~addition to nonperformance risk on PDC’s own business interests and liabilities~~Partnership, as well as, the ~~credit~~satisfaction ~~standing~~ of ~~derivative~~other ~~instrument~~customary ~~counterparties. The~~closing ~~Managing General Partner primarily uses financial institutions~~conditions, ~~which~~then ~~are also major lenders in PDC’s credit facility agreement, as counterparties to~~ the Partnership’s ~~derivative~~will ~~contracts. The~~merge ~~Managing~~with ~~General~~and ~~Partner~~into ~~has~~DP ~~evaluated~~Merger ~~the~~Sub ~~credit~~and ~~risk~~non-affiliated ofinvestor ~~the~~partners ~~counterparties~~will ~~holding~~have the ~~Partnership’s~~right ~~derivative~~to ~~assets~~receive ~~using~~a ~~relevant~~cash ~~credit~~payment ~~market default rates, giving consideration to amounts outstanding~~ for ~~each~~their ~~counterparty~~limited ~~and~~partnership ~~the duration of each outstanding derivative position~~units. ~~Based~~DP onMerger ~~the~~Sub ~~Managing~~shall ~~General~~be ~~Partner’s~~the ~~evaluation,~~surviving asentity of ~~September~~the ~~30,~~merger ~~2010,~~and ~~the~~shall ~~impact~~be ~~of non~~wholly-~~performance~~owned ~~risk~~by onPDC, ~~the~~and ~~fair value of~~ the ~~Partnership’s~~limited ~~derivative~~partners ~~assets~~will ~~and~~have ~~liabilities~~no ~~was~~continuing ~~not~~interest ~~significant. Validation~~in of the Partnership’s, ~~contracts’~~since ~~fair values are performed internally and while~~ the ~~Managing~~Partnership ~~General~~will ~~Partner~~cease ~~uses~~as ~~common~~a ~~industry~~separate ~~practices~~business toentity. The ~~develop~~merger ~~valuation~~will ~~techniques,~~become ~~changes~~effective infollowing the ~~Managing~~filing ~~General~~of ~~Partner’s~~a ~~pricing~~certificate ~~methodologies~~of ormerger ~~the~~with ~~underlying assumptions could result in significantly different fair values. While~~ the ~~Managing~~Secretaries ~~General~~of ~~Partner~~State ~~believes~~of ~~these~~West ~~valuation~~Virginia ~~methods~~and ~~are~~Delaware ~~appropriate~~as ~~and~~soon ~~consistent~~as ~~with~~practicable ~~those~~after ~~used~~the bylast ~~other~~condition ~~market~~precedent ~~participants,~~to the ~~use~~merger ofhas ~~different~~been ~~methodologies~~satisfied, or ~~assumptions,~~waived. Following toconsummation ~~determine~~of the ~~fair~~merger, ~~value~~the ofnon-affiliated ~~certain~~investor ~~financial~~partners ~~instruments~~will ~~could~~no ~~result~~longer participate in athe ~~different~~Partnership’s ~~estimate~~future ofearnings ~~fair~~or ~~value~~growth.

-The 7Merger Agreement has been approved by PDC’s Board of Directors (the “Board”); PDC, as sole member of the DP Merger Sub; and by the Special Committee formed by the Board, comprised of four directors of PDC who are not officers or employees of the Partnership or PDC and have no economic interest in the Partnership, to represent the interests of the non-affiliated investor partners holding limited partnership units.

~~INDEX~~The Merger Agreement among the Partnership, PDC and its subsidiary DP Merger Sub, may be terminated, and the merger abandoned:

should all parties agree by mutual consent to terminate the Merger Agreement;

by any party thereto, should the proposed merger not occur by April 30, 2011; provided that if the SEC’s proxy disclosure review process has not yet been completed after good faith effort by PDC, such date will be extended until August 31, 2011 - neither PDC nor the Special Committee has exercised any such rights as of the date of this filing;

by any party thereto, should consummation of the merger become illegal or be otherwise prohibited by law or regulation;

- 8 -

Index

PDC 2005-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

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

(unaudited)

~~The~~· ~~following~~by ~~table~~PDC ~~presents~~or the Partnership, byshould ~~hierarchy~~either ~~level,~~PDC or the Partnership’s ~~derivative~~fail ~~financial~~to ~~instruments,~~perform ~~including~~its ~~both~~obligations ~~current~~under the Merger Agreement and such failure has a non-~~current~~curable ~~portions~~material ~~measured~~adverse ateffect ~~fair~~on ~~value~~the PDC or the Partnership, respectively, or materially and adversely affects the transactions contemplated by the Merger Agreement.

	Quoted Prices in Active Markets (Level 1)			Significant Unobservable Inputs (Level 3)			Total
As of December 31, 2009
Assets:
Commodity based derivatives	$	373,862		$	482,442		$	856,304
Total assets		373,862			482,442			856,304
Liabilities:
Commodity based derivatives		(25,602	)		(121,477	)		(147,079	)
Basis protection derivative contracts		—			(1,344,970	)		(1,344,970	)
Total liabilities		(25,602	)		(1,466,447	)		(1,492,049	)
Net asset (liability)	$	348,260		$	(984,005	)	$	(635,745	)
As of September 30, 2010
Assets:
Commodity based derivatives	$	1,699,482		$	172,067		$	1,871,549
Total assets		1,699,482			172,067			1,871,549
Liabilities:
Commodity based derivatives		—			(107,349	)		(107,349	)
Basis protection derivative contracts		—			(1,180,697	)		(1,180,697	)
Total liabilities		—			(1,288,046	)		(1,288,046	)
Net asset (liability)	$	1,699,482		$	(1,115,979	)	$	583,503

by any party thereto, should any suit or action be pending against parties to the Merger Agreement challenging the legality or any aspect of the merger transaction;

~~The~~· ~~following~~by ~~table~~the ~~presents~~Special ~~the~~Committee, ~~changes~~on behalf of the Partnership’s ~~Level~~and 3prior ~~derivative~~to ~~financial~~approval ~~instruments~~by ~~measured~~non-affiliated oninvestor partners, should the Special Committee believe it has received a ~~recurring~~superior ~~basis:~~offer that is more favorable to the non-affiliated investor partners; or

	Nine months ended September 30, 2010
Fair value, net liability, as of December 31, 2009	$	(984,005	)
Changes in fair value included in statement of operations line item:
Commodity price risk management, net		153,495
Settlements		(285,469	)
Fair value, net liability, as of September 30, 2010	$	(1,115,979	)
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	$	32,741

Regardless of whether the merger is consummated, all costs and expenses incurred by PDC, the Partnership and DP Merger Sub in connection with the Merger Agreement shall be paid by PDC.

On February 7, 2011, definitive proxy statements were mailed to non-affiliated investor partners of the Partnership. Closing of the merger is conditioned on approval by a majority vote of non-affiliated investor partners of the Partnership on both proposals to (1) amend the limited partnership agreement to expressly provide non-affiliated investor partners the right to approve merger transactions and (2) approve the Merger Agreement.

The per unit merger value offered to non-affiliated investor partners of the Partnership under the Merger Agreement in exchange for their limited partnership units in the Partnership was based on an effective transaction date of January 1, 2011.

In late February 2011, PDC re-evaluated the merger consideration agreed to in the Merger Agreement and has offered supplemental merger consideration to the non-affiliated investor partners of this Partnership in addition to the merger consideration offered under the Merger Agreement. The supplemental merger consideration offered for this Partnership increased the per unit offer from $5,506 to $6,544, resulting in the aggregate offering price increasing from $10.9 million to $12.9 million. On May 6, 2011, PDC mailed definitive proxy supplements to the non-affiliated investor partners of this Partnership. The special meeting whereby non-affiliated investor partners of this Partnership will have an opportunity to vote and approve the Merger Agreement is currently scheduled for June 15, 2011. If the required approvals are received from the non-affiliated investor partners of the Partnership at the special meeting and various other closing conditions are satisfied, non-affiliated investor partners owning the Partnership’s outstanding limited partnership units (other than limited partnership units owned by non-affiliated investor partners who properly exercise appraisal rights) will have the right to receive cash in an amount equal to $6,544 per limited partnership unit, plus the sum of the amounts withheld from per unit cash distributions by the Partnership from October 1, 2010 through February 28, 2011 for the Partnership’s well refracturing plan (approximately $49.44 per limited partnership unit), less the sum of the per unit cash distributions made after February 28, 2011 and before the transaction closes.

- 9 -

Index

PDC 2005-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2011

(unaudited)

Note 4−Fair Value of Financial Instruments

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.

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

Assets:
Commodity based derivatives	$	1,475,995	$	21,770		$	1,497,765		$	1,540,345	$	68,999		$	1,609,344
Total assets		1,475,995		21,770			1,497,765			1,540,345		68,999			1,609,344

Liabilities:
Commodity based derivatives		-		(217,024	)		(217,024	)		-		(176,801	)		(176,801	)
Basis protection derivative contracts		-		(1,116,439	)		(1,116,439	)		-		(1,133,143	)		(1,133,143	)
Total liabilities		-		(1,333,463	)		(1,333,463	)		-		(1,309,944	)		(1,309,944	)

Net asset (liability)	$	1,475,995	$	(1,311,693	)	$	164,302		$	1,540,345	$	(1,240,945	)	$	299,400

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	$	(1,240,945	)	$	(984,005	)
Changes in fair value included in statement of operations line item -
Commodity price risk management, net		(129,622	)		(105,143	)
Settlements		58,874			(366,418	)
Fair value, net liability, end of period	$	(1,311,693	)	$	(1,455,566	)

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	$	(127,468	)	$	(132,866	)

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.

- 810 -

~~INDEX~~Index

PDC 2005-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 basis protection swaps,~~ in place for a portion of its anticipated production through 2013 for a total of ~~959~~792,~~049~~019 MMbtu of natural gas and 126,~~399~~044 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	$	656,668	$	627,166
		Partner-derivatives	$	~~721,323~~	$	~~487,802~~
	Non Current
	Commodity contracts	Due from Managing General		841,097		982,178
		Partner-derivatives		~~1,150,226~~		~~368,502~~
Total Derivative Assets			$	1,~~871~~497,~~549~~765	$	~~856~~1,~~304~~609,344
Derivative Liabilities:	Current
	Commodity contracts	Due to Managing General	$	217,024	$	176,801
		Partner-derivatives	$	~~78,004~~	$	~~26,334~~
	Basis protection contracts	Due to Managing General		454,240		387,734
		Partner-derivatives		~~356,854~~		~~351,370~~
	Non Current
	Commodity contracts	Due to Managing General
	Basis protection contracts	Due to Managing General		662,199		745,409
		Partner-derivatives		~~29,344~~		~~120,745~~
	Basis protection contracts	Due to Managing General
Total Derivative Liabilities			$	1,333,463	$	1,309,944
		Partner-derivatives		823,844		993,600
Total Derivative Liabilities			$	1,288,046	$	1,492,049

(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 ~~Gains~~Gain ~~(Losses)~~ For the Current Period			Total
Commodity price risk management, net
Realized gains	$	43,141		$	38,143		$	81,284		$	422,547		$	1,578		$	424,125
Realized gain	$	18,239		$	6,205		$	24,444		$	338,695		$	27,723		$	366,418
Unrealized (losses) gains		(43,141	)		546,035			502,894			(422,547	)		(429,452	)		(851,999	)
Unrealized (loss) gain		(18,239	)		(116,859	)		(135,098	)		(338,695	)		800,579			461,884
Total commodity price risk management gain (loss), net	$	—		$	584,178		$	584,178		$	—		$	(427,874	)	$	(427,874	)
Total commodity price risk management (loss) gain, net	$	-		$	(110,654	)	$	(110,654	)	$	-		$	828,302		$	828,302

	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	$	149,765		$	357,379	$	507,144	$	1,407,138		$	290,053		$	1,697,191
Unrealized (losses) gains		(149,765	)		1,369,013		1,219,248		(1,407,138	)		(1,430,112	)		(2,837,250	)
Total commodity price risk management gain (loss), net	$	—		$	1,726,392	$	1,726,392	$	—		$	(1,140,059	)	$	(1,140,059	)

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.

- 911 -

~~INDEX~~Index

PDC 2005-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. AsDuring ofthe ~~September~~three 30months ended March 31, ~~2010~~2011, ~~the~~there ~~Partnership~~was ~~had~~one ~~accrued~~new an environmental remediation ~~liability~~project ~~included~~identified inby the ~~Balance~~ ~~Sheet~~Managing ~~line~~General ~~item~~Partner ~~captioned~~in ~~“Accounts~~which ~~payable~~$55,000 ~~and~~in ~~accrued~~ expenses.” ~~This~~were ~~accrual~~recorded ~~represents~~and ~~costs~~are ~~estimated~~included ~~to be incurred~~ in ~~addition~~the toline ~~normal~~item ~~recurring~~captioned ~~environmental-related~~“Natural ~~expenditures~~gas, ~~which~~NGLs ~~have been incurred~~ and ~~recorded~~crude atoil ~~September~~production ~~30, 2010~~costs.” ~~During~~As ~~the third~~of ~~quarter~~March of31, ~~2010~~2011, the ~~Managing~~Partnership ~~General~~has ~~Partner~~accrued ~~identified~~environmental ~~existing~~remediation ~~ground~~liabilities ~~contamination~~for atone ~~three~~of the Partnership’s well ~~sites. The~~pads ~~Partnership~~involving ~~recorded~~two anwells ~~accrual~~in ofthe ~~approximately~~amount of $4437,000, which is included in line item captioned “Accounts payable and accrued expenses” on the ~~estimated~~condensed ~~cost~~Balance ~~attributable~~Sheets. As toof December 31, 2010, the Partnership, ~~based~~had ~~principally~~immaterial onaccrued ~~estimated~~environmental ~~third~~remediation ~~party~~liabilities ~~costs,~~which toare ~~remediate~~included ~~the~~in ~~ground~~line ~~contamination~~item ~~less~~captioned ~~actual costs~~“Accounts ~~incurred~~payable ~~through~~and ~~September~~accrued ~~30,~~expenses” ~~2010,~~on ifthe ~~any~~condensed Balance 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.

InNote ~~December~~7−Third-party ~~2008,~~Volume ~~the~~Imbalance 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 nine 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 continues to work to bring this matter to closure. Given the inherent uncertainty in administrative actions of this nature, the Managing General Partner is unable to predict with certainty the ultimate outcome of this administrative action; however, the Managing General Partner does not believe that the ultimate outcome will have a material adverse effect on the Partnership’s financial position or results of operations.Settlement

~~Note~~Under ~~7−Subsequent~~the ~~Events~~Partnership’s revenue recognition policy, natural gas, NGLs and crude oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. In accordance with this policy, in the quarter ended March 31, 2011, the Partnership recorded approximately $59,000 in natural gas revenues which was the result of the receipts from a settlement from a third-party gas purchaser relating to prior years’ volume imbalances. The settlement was recorded in the current period as this was the period that the revenues were determinable and collection was reasonably assured.

~~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~~12 ~~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.

~~- 10 -~~Index

INDEX

PDC 2005-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 2005-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 May 2005 and operates 5149 gross (4745.34 net) productive wells located in the Rocky Mountain Region in the state of Colorado. In addition, two gross (1.9 net) Wattenberg Field Partnership wells are temporarily not in production at March 31, 2011 due to equipment problems or operational issues. One additional well drilled was evaluated as commercially unproductive and was therefore declared to be a developmental dry hole. 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,~~In ~~the~~November ~~managing general partner of various public limited partnerships~~2010, ~~has~~PDC ~~disclosed~~and ~~its~~DP ~~intention~~2004 toMerger ~~pursue the acquisitions~~Sub, ~~within the next three years beginning in the fall of 2010~~LLC, ofa ~~the remaining third~~wholly-~~party~~owned ~~Investor~~subsidiary ~~Partner~~of ~~interests in the limited partnerships which~~ PDC ~~has sponsored~~ (~~the~~ “~~Acquisition~~DP ~~Plan~~Merger Sub”), ~~including~~entered ~~this~~into ~~Partnership. (For~~separate ~~additional~~merger ~~information~~agreements ~~regarding~~with ~~PDC’s~~this ~~intention to pursue acquisitions of PDC sponsored partnerships~~Partnership, ~~refer to the disclosure included in Items 2.02 and/or 7.01 of~~ PDC’s ~~Forms 8~~2005-KA ~~dated~~Limited ~~March~~Partnership ~~4, 2010, June 9, 2010~~ and ~~July~~Rockies ~~15,~~Region ~~2010,~~Private ~~which~~Limited ~~information~~Partnership ~~shall not~~(collectively, bythe ~~reason~~“2005 ~~of this reference, be deemed to be incorporated by reference in, or otherwise be deemed to be part of, this report~~Partnerships”). 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~~. The~~ ~~transaction~~serves ~~will~~as ~~also be subject to, among other things, PDC having sufficient available capital and~~ the ~~approval~~Managing byGeneral aPartner ~~majority~~ of ~~the limited partnerships units held by the Investor Partners, excluding limited partnership units owned by PDC or its affiliates, of~~ each ~~respective limited partnership. Consummation~~ of ~~any proposed merger under~~ the ~~Acquisition~~2005 Plan will likely result in the termination of the existence of that partnership and the right for third-party Investor Partners to receive a cash payment for their limited partnership units in that partnershipPartnerships.

InPursuant ~~June~~to ~~2010,~~the ~~PDC~~Partnership’s ~~and a wholly owned subsidiary of PDC entered into a~~ merger agreement with PDC ~~2004-A Limited Partnership, PDC 2004-B Limited Partnership, PDC 2004-C Limited Partnership and PDC 2004-D Limited Partnership~~ (~~collectively,~~ the “~~2004~~Merger ~~partnerships~~Agreement”)~~. PDC serves as the managing general partner of each of the 2004 partnerships. Pursuant to each merger agreement~~, if the merger is approved by the holders of a majority of the limited partnership units held by ~~Investor~~the ~~Partners~~non-affiliated ofinvestor ~~that~~partners ~~partnership~~of ~~not~~the ~~owned by PDC or its affiliates~~Partnership, as well as, the satisfaction of other customary closing conditions, then the ~~partnership~~Partnership will merge with and into aDP ~~wholly~~Merger ~~owned~~Sub ~~subsidiary~~and ofnon-affiliated ~~PDC. If~~investor ~~all~~partners ~~four 2004 partnerships are acquired, PDC~~ will ~~pay~~have upthe right to anreceive ~~aggregate~~a ofcash ~~approximately~~payment ~~$36.4 million~~ for ~~the~~their limited partnership units ~~of these partnerships~~. DP ~~Definitive~~Merger ~~proxy~~Sub ~~statements~~shall ~~for~~be ~~each of~~ the ~~2004~~surviving ~~partnerships~~entity ~~requesting~~of ~~approval from~~ the ~~applicable third-party Investor Partners for, among other things, the~~ merger ~~agreements~~and ~~were~~shall ~~mailed~~be ~~to the third~~wholly-~~party~~owned ~~Investor~~by ~~Partners~~PDC, ofand the ~~2004~~limited ~~partnerships~~partners ~~in early October 2010. The special meetings whereby third-party Investor Partners of the 2004 partnerships~~ will have anno ~~opportunity~~continuing tointerest ~~vote~~in ~~and approve~~ the ~~applicable merger agreement are currently scheduled for December 8~~Partnership, ~~2010~~since ~~for each of~~ the ~~2004~~Partnership ~~partnerships.~~will Ifcease ~~the~~as ~~required~~a ~~approvals~~separate ~~are~~business ~~received~~entity. The ~~from~~merger ~~the~~will ~~third-party~~become ~~Investor~~effective ~~Partners~~following at the ~~special~~filing ~~meetings, each~~ of the mergers for the 2004 partnerships is expected to close shortly thereafter and no later than December 31, 2010. 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~~certificate of ~~criteria~~merger ~~that~~with ~~includes, but is not limited to,~~ the ~~following: age~~Secretaries ~~and productive-life stage characteristics~~ of ~~the~~State ~~partnership’s well inventory; favorability~~ of ~~economics~~West ~~for~~Virginia ~~Wattenberg~~and ~~Field~~Delaware ~~well~~as ~~refracturing;~~soon ~~and~~as ~~SEC~~practicable ~~reporting~~after ~~compliance~~the ~~status~~last ~~and~~condition ~~timing~~precedent ~~associated~~ to ~~gaining~~the ~~all~~merger ~~necessary~~has ~~regulatory~~been ~~approvals~~satisfied, ~~required~~or ~~for a merger and repurchase offer~~waived. ~~There~~Following isconsummation noof ~~assurance~~the ~~that~~merger, ~~any~~the ~~merger~~non-affiliated ~~and~~investor ~~acquisition~~partners will ~~occur~~no aslonger aparticipate ~~result~~in of the ~~proposed repurchase offers to PDC~~Partnership’s ~~2004~~future ~~partnerships,~~earnings or ~~any potential proposed repurchase offer to any other of PDC’s various public limited partnerships, including this Partnership, should they occur~~growth.

-The 11Merger Agreement has been approved by PDC’s Board of Directors (the “Board”); PDC, as sole member of the DP Merger Sub; and by the Special Committee formed by the Board, comprised of four directors of PDC who are not officers or employees of the Partnership or PDC and have no economic interest in the Partnership, to represent the interests of the non-affiliated investor partners holding limited partnership units.

~~INDEX~~The Merger Agreement among the Partnership, PDC and its subsidiary DP Merger Sub, may be terminated, and the merger abandoned:

should all parties agree by mutual consent to terminate the Merger Agreement;

by any party thereto, should the proposed merger not occur by April 30, 2011; provided that if the SEC’s proxy disclosure review process has not yet been completed after good faith effort by PDC, such date will be extended until August 31, 2011 – neither PDC nor the Special Committee has exercised any such rights as of the date of this filing;

- 13 -

Index

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

by any party thereto, should consummation of the merger become illegal or be otherwise prohibited by law or regulation;

by any party thereto, should any suit or action be pending against parties to the Merger Agreement challenging the legality or any aspect of the merger transaction;

by the Special Committee, on behalf of the Partnership and prior to approval by non-affiliated investor partners, should the Special Committee believe it has received a superior offer that is more favorable to the non-affiliated investor partners; or

by PDC or the Partnership, should either PDC or the Partnership fail to perform its obligations under the Merger Agreement and such failure has a non-curable material adverse effect on the PDC or the Partnership, respectively, or materially and adversely affects the transactions contemplated by the Merger Agreement.

Regardless of whether the merger is consummated, all costs and expenses incurred by PDC, the Partnership and DP Merger Sub in connection with the Merger Agreement shall be paid by PDC.

If the merger is not completed, the anticipated non-affiliated investor partner merger benefits that include unit liquidity and elimination of Schedule K-1 tax reports in the Partnership will not be realized and the Partnership will continue the existing business plan to optimally develop and cost-effectively operate the Partnership’s natural gas and oil reserves. This plan encompasses the implementation of the Well Refracturing Plan, more fully outlined below. The information presented in this Report on Form 10-Q for the quarter ended March 31, 2011 and the year ended December 31, 2010 does not give effect to the proposed Merger Agreement.

Well Refracturing Plan

The Managing General Partner has ~~developed~~prepared ~~the~~a ~~Well~~plan ~~Refracturing Plan~~ for the Partnership’s Wattenberg Field wells ~~that~~which ~~were~~may ~~initially~~provide ~~completed~~for inadditional reserve development of natural gas, NGLs and crude oil production (the ~~Codell~~“Well ~~formation~~Refracturing ~~during~~Plan”). The Well Refracturing Plan consists of the Partnership’s ~~initial~~refracturing ~~development.~~of wells currently producing in the Codell formation. Under the ~~plan~~Well Refracturing Plan, the Partnership ~~will~~plans to initiate ~~Codell formation~~ refracturing activities during ~~2011~~2012. ~~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.

~~Funding of the initial well refracturing activity began with the withholding, on a pro~~-~~rata~~ ~~basis,~~14 of $20,000 from the Partnership’s October 2010 monthly distributable cash flows which was allocated to the Managing General Partner and Investor Partners based on their proportional ownership interest. This withholding was deposited into the Partnership’s bank account.-

After the initial refrac funding is completed in 2011, the Partnership will re-evaluate the Well Refracturing Plan funding requirements and will continue to withhold cash at varying levels on a pro-rata basis, from the Managing General Partner’s and Investor Partner’s distributable cash flows from current production operations. The most recent cost projection for Codell formation well refracturing ranges between $150,000 and $200,000 per refrac. Total withholding from the Partnership’s distributable cash flows for the Partnership’s 35 well refracturing opportunities is estimated to be between $5.3 million and $7.0 million. The number of refracturings and the timing of refracturings will be based on the availability of cash withheld from Partnership distributions. The necessary funds to be retained by the Partnership for the payment of Well Refracturing Plan activities may materially reduce, up to 100%, of the Managing General Partner’s and Investor Partners’ distributable cash flows for a period of time not to exceed five years.Index

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Refracturing of Wattenberg Field wells, which may provide for additional reserve development and production, generally occurs five to ten years after initial well drilling so that well resources are optimally utilized. This refracturing would be expected to occur based on a favorable general economic environment and commodity price structure. The Managing General Partner has the authority to determine whether to refrac the individual wells and to determine the timing of any refracturing activity. The timing of the refracturing can be affected by the desire to optimize the economic return by refracturing the wells when commodity prices are at levels to obtain the highest rate of return to the Partnership. On average, the production resulting from PDC’s Codell refracturings have been at modeled economics; however, all refracturings have not been economically successful and similar future refracturing activities may not be economically successful. If the refracturing work is performed, PDC will charge the Partnership for the direct costs of refracturing, and the Investor Partners and the Managing General Partner will each pay their proportionate share of costs based on the ownership sharing ratios of the Partnership from funds retained by the Managing General Partner from cash available for distributions. The Managing General Partner considers the cash available for distributions to be the Partnership’s net cash flows provided by operating activities less any net cash used in capital activities.

During the fourth quarter 2010, the Managing General Partner began a program for its affiliated partnerships to begin accumulating cash from cash flows from operating activities to pay for future refracturing costs. This program will materially reduce, up to 100%, cash available for distributions of the partnerships for a period of time not to exceed five years.

Current estimated costs for these well refracturings are between $175,000 and $240,000 per activity. As of March 31, 2011, this Partnership had scheduled to complete 37 refracturing opportunities. Total withholding for these activities from the Partnership’s cash available for distributions is estimated to be between $6.5 million and $8.9 million. The Managing General Partner will continually evaluate the timing of commencing these refracturing activities based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the additional well development. During the three months ended March 31, 2011, $60,000 was withheld from the Partnership’s cash distributions pursuant to the Well Refracturing Plan. Cumulatively, $130,000 has been withheld from Partnership distributions through April 30, 2011 and resides in the Partnership’s bank account.

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.

- 15 -

Index

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Partnership Operating Results Overview

Natural gas, NGLs and crude oil sales ~~increased~~decreased 2225% or $0.53 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 1611% period-to-period. ~~This increase was driven primarily by the improved commodity price environment.~~ The average sales price per Mcfe, excluding the impact of net realized derivative gains, was $5.7468 for the current year period compared to $36.9470 for the same period a year ago. ~~Realized~~Net realized derivative gains from natural gas and crude oil sales contributed an additional $10.0516 per Mcfe or $~~0.5~~24,000 ~~million~~ to the first ~~nine~~three months of ~~2010~~2011 total revenues compared to an additional $2.10 or $366,000 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 ~~slightly~~ to $65.7984 for the current year ~~nine~~three months from $68.8880 for the same prior year period. During the three months ended March 31, 2011, natural gas revenue included $59,000 from a settlement more fully discussed in the notes to the Summary Operating Results table.

~~Natural~~- ~~gas~~16 and oil production and direct costs−administrative and general costs combined increased by $0.1 million during the 2010 nine month period. Higher production expenditures were primarily due to well workovers conducted in both of the Partnership’s Grand Valley and Wattenberg operating fields in addition to environmental remediation activities in the Wattenberg Field. The higher natural gas and oil production costs were partially offset by the reduction in direct costs−general and administrative expense due to the reduction in billed professional fees in the 2010 period compared to the 2009 period.-

~~- 12 -~~Index

INDEX

PDC 2005-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)		5149			5148		—1			51		51		—
Production (1)
Production(1)
Natural gas (Mcf)		118,449			159,208		-26	%		365,196		430,455		-15	%
Natural gas (Mcf)(2)		119,608			121,980		-2	%
Oil (Bbl)		5,880			6,796		-13	%		19,725		24,707		-20	%
NGLs (Bbl)		747			1,343		-44	%
Natural gas equivalents (Mcfe) (2)		153,729			199,984		-23	%		483,546		578,697		-16	%
Crude oil (Bbl)		5,145			7,471		-31	%
Natural Gas and Oil Sales
Natural gas equivalents (Mcfe)(3)		154,960			174,864		-11	%
Natural gas	$	380,648		$	384,398		-1	%	$	1,379,892	$	1,066,001		29	%
Average Mcfe per day		1,722			1,943		-11	%
Oil		404,597			417,276		-3	%		1,397,518		1,215,975		15	%
Natural Gas, NGLs and Crude Oil Sales
Total natural gas and oil sales	$	785,245		$	801,674		-2	%	$	2,777,410	$	2,281,976		22	%
Natural gas (4)	$	408,735		$	577,821		-29	%
Realized Gain on Derivatives, net
NGLs		33,113			49,155		-33	%
Natural gas	$	7,877		$	309,729		-97	%	$	308,113	$	1,186,709		-74	%
Crude oil		439,011			544,598		-19	%
Oil		73,407			114,396		-36	%		199,031		510,482		-61	%
Total natural gas, NGLs and crude oil sales	$	880,859		$	1,171,574		-25	%
Total realized gain on derivatives, net	$	81,284		$	424,125		-81	%	$	507,144	$	1,697,191		-70	%
Realized Gain (Loss) on Derivatives, net
Average Selling Price (excluding realized gain on derivatives)
Natural gas	$	70,560		$	305,693		-77	%
Natural gas (per Mcf)	$	3.21		$	2.41		33	%	$	3.78	$	2.48		52	%
Crude oil		(46,116	)		60,725		-176	%
Oil (per Bbl)		68.81			61.40		12	%		70.85		49.22		44	%
Total realized gain on derivatives, net	$	24,444		$	366,418		-93	%
Natural gas equivalents (per Mcfe)		5.11			4.01		27	%		5.74		3.94		46	%
Average Selling Price (excluding realized gain (loss) on derivatives)
Average Selling Price (including realized gain on derivatives)
Natural gas (per Mcf) (4)	$	3.42		$	4.74		-28	%
Natural gas (per Mcf)	$	3.28		$	4.36		-25	%	$	4.62	$	5.23		-12	%
NGLs (per Bbl)		44.33			36.60		21	%
Oil (per Bbl)		81.29			78.23		4	%		80.94		69.88		16	%
Crude oil (per Bbl)		85.33			72.89		17	%
Natural gas equivalents (per Mcfe)		5.6468			6.1370		-815	%		~~6.79~~		~~6.88~~		-1	%
Average Lifting Cost (per Mcfe) (3)	$	3.31		$	1.59		108	%	$	2.48	$	1.51		65	%
Average Selling Price (including realized gain (loss) on derivatives)
Operating costs and expenses
Natural gas (per Mcf)	$	4.01		$	7.24		-45	%
Direct costs - general and administrative	$	35,213		$	79,809		-56	%	$	114,818	$	346,574		-67	%
NGLs (per Bbl)		44.33			36.60		21	%
Depreciation, depletion and amortization	$	668,850		$	1,235,465		-46	%	$	2,168,329	$	3,780,560		-43	%
Crude oil (per Bbl)		76.36			81.02		-6	%
Cash distributions	$	427,547		$	1,594,454		-73	%	$	2,414,112	$	3,977,315		-39	%
Natural gas equivalents (per Mcfe)		5.84			8.80		-34	%
Average cost per Mcfe
Natural gas, NGLs and crude oil production cost(5)	$	2.29		$	1.73		32	%
Depreciation, depletion and amortization		3.89			4.47		-13	%
Operating costs and expenses:
Direct costs - general and administrative	$	47,760		$	35,743		34	%
Depreciation, depletion and amortization		603,327			782,307		-23	%
Cash distributions	$	479,882		$	1,180,938		-59	%

~~(1)~~Amounts ~~Production~~may isnot ~~determined~~calculate bydue ~~multiplying~~to ~~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~~rounding.

~~(2)~~- A17 ~~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.~~Index

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

- 13 -

INDEX

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Natural~~(1) ~~Gas~~Production is net and ~~Oil~~determined ~~Sales~~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.

~~Nine~~(2) ~~months~~Approximately ~~ended~~9,926 ~~September~~Mcf, 30or 8%, ~~2010~~of asthe ~~compared~~Partnership’s tonatural ~~nine~~gas production was the result of a settlement with a third-party gas purchaser recorded during the three months ended ~~September~~March 3031, ~~2009~~2011, related to prior years’ volume imbalances.

~~The~~(3) ~~$0.5~~Six ~~million,~~Mcf ~~or 22% increase in sales for the 2010 nine month period as compared to the prior year period, was primarily a reflection~~ of ~~the~~natural ~~significantly~~gas ~~higher~~equals ~~average~~one ~~sales~~Bbl ~~price per Mcfe~~ of ~~46%,~~crude ~~which~~oil ~~was~~or ~~partially offset by a production volume decrease of 16%~~NGL. ~~The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.74 for the current year nine month period compared to $3.94 for the same period a year ago.~~

~~Natural~~(4) ~~gas~~Approximately ~~and~~$59,000, ~~oil~~or ~~revenues increased by 29% and~~ 15%, ~~respectively. The~~of the Partnership’s natural gas ~~revenue~~sales ~~increase~~and ~~benefited~~with ~~from~~an ~~rising~~effect ~~commodity~~of ~~prices~~$0.23 per Mcf ofto ~~52%,~~the ~~which~~Partnership’s ~~were~~average ~~partially~~overall ~~offset~~Mcf byprice ~~lower~~for ~~Partnership~~ natural gas ~~production~~sales ~~volumes of 15%. This compares to the more moderate oil~~ revenue ~~increase~~was ~~in which~~ the ~~rise~~result ~~in commodity prices~~ of ~~44%~~the ~~was~~settlement ~~partially~~with ~~offset~~a bythird-party agas ~~steeper~~purchaser ~~decline~~noted in ~~oil~~footnote ~~production~~2 ~~volumes, per Bbl of 20% during the current nine month period~~above.

~~Three~~(5) ~~months~~Production ~~ended~~costs ~~September~~represent 30natural gas, ~~2010~~NGLs asand ~~compared~~crude tooil ~~three~~operating ~~months~~expenses ~~ended~~which ~~September~~include ~~30,~~production ~~2009~~taxes.

~~Sales~~Definitions ~~for~~used ~~the~~throughout ~~2010~~Management’s ~~third~~Discussion ~~quarter remained substantially unchanged at $0.8 million compared to the prior year third quarter. This stability in quarter-to-quarter Partnership natural gas~~ and ~~oil~~Analysis ~~revenues is primarily a reflection~~ of ~~the~~Financial ~~higher~~Condition ~~average~~and ~~sales~~Results ~~price per Mcfe~~ of 27%, substantially offset by the production volume decrease of 23%. Average sales prices per Mcfe, excluding the impact of realized derivative gains, were $5.11 for the current year quarter compared to $4.01 for the same quarter a year ago. Operations:

~~The~~· ~~Partnership~~Bbl ~~expects~~– toOne ~~experience~~barrel ~~declines~~or in42 ~~both natural gas and oil production volumes over the wells’ life cycles until such time that the Partnership’s Wattenberg wells may be successfully refraced~~U. ~~Subsequent~~S. togallons aliquid ~~successful refracturing, production will once again be expected to decline.~~volume

~~Natural~~· ~~Gas~~MBbl ~~and~~– ~~Oil~~One ~~Pricing~~thousand barrels

~~Financial~~· ~~results~~Mcf ~~depend~~– ~~upon~~One ~~many~~thousand ~~factors,~~cubic 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.feet

~~The~~· ~~price~~MMcf at– ~~which~~One ~~PDC~~million ~~markets~~cubic the natural 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 indices for 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 markets. This negative differential has narrowed in the last year and is 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, 2009, respectively, and narrowed to an average of $0.51 and $0.88 for the three and nine months ended September 30, 2010, respectively.feet

-· 14Mcfe -– One thousand cubic feet of natural gas equivalents

~~INDEX~~· MMcfe – One million cubic feet of natural gas equivalents

MMbtu – One million British Thermal Units

Natural Gas, NGLs and Crude Oil Sales

For the three months ended March 31, 2011 compared to the same period in 2010, natural gas, NGLs and crude oil sales, on an energy equivalency-basis, decreased 11%. Excluding the natural gas sales settlement identified in footnotes 2 and 4 of the Summary Operating Results table, natural gas, NGLs and crude oil production, on an energy equivalency-basis, decreased 17% due to normal production declines for this stage in the wells’ production life cycle.

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

The $0.3 million, or 25%, decrease in sales for the 2011 three month period as compared to the prior year period was primarily a reflection of a decline in sales prices of 15% and sales volume decreases of 11%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.68 for the current year three month period compared to $6.70 for the same period a year ago.

Natural gas, NGLs and crude oil revenues decreased by 29%, 33% and 19%, respectively. The Partnership’s natural gas revenue decrease resulted from decreased commodity prices per Mcf of 28% and sales volume decreases of 2%, including the settlement identified above in the Summary Operating Results table. The decrease in NGLs revenue was due to a decrease of 44% in NGLs production volumes partially offset by increased commodity prices per Bbl of 21%. The crude oil revenue decrease is due primarily to a sales volume decrease of 31% partially offset by the rise in commodity prices per Bbl of 17% during the current three month period.

- 18 -

Index

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Commodity Price Risk Management, Net

The ~~Managing General Partner, on behalf of the~~ Partnership inuses ~~accordance with the D&O Agreement, is authorized to utilize~~ various derivative instruments to manage ~~volatility~~fluctuations in natural gas and crude oil prices. ~~Commodity~~The ~~price~~Partnership ~~risk~~has ~~management,~~in ~~net,~~place ~~includes~~a ~~realized~~variety ~~gains~~of ~~and~~floors, ~~losses~~collars, ~~and~~fixed-price ~~unrealized~~swaps ~~changes~~and inbasis ~~the~~swaps ~~fair~~on ~~value~~a portion of ~~derivative instruments related to~~ the Partnership’s estimated natural gas and crude oil production. ~~The~~Because ~~Managing~~the ~~General~~Partnership ~~Partner~~sells ~~sets~~its ~~these~~natural ~~instruments~~gas ~~for PDC,~~ and ~~the~~crude ~~various~~oil ~~partnerships~~at ~~managed~~similar byprices ~~PDC. Derivative~~to ~~financial~~the ~~instrument~~indices ~~positions~~inherent ~~taken~~in by the ~~Managing~~Partnership’s ~~General~~derivative ~~Partner~~instruments, on the Partnership’s ~~behalf~~ultimately ~~are~~realizes ~~specifically~~a ~~designated~~price related to ~~the~~its ~~Partnership’s~~collars ~~production~~of ~~volumes.~~no ~~See~~less ~~Note~~than 4,the ~~Fair~~floor ~~Value Measurements~~ and ~~Note~~no 5,more ~~Derivative~~than ~~Financial~~the ~~Instruments~~ceiling and, tofor the Partnership’s ~~unaudited~~commodity ~~condensed financial statements included in this report~~swaps, ~~for~~the ~~additional~~Partnership ~~details~~ultimately onrealizes the ~~Partnership’s~~fixed ~~derivative~~price ~~financial~~related ~~instruments~~to its swaps.

~~The~~Commodity ~~following~~price ~~table~~risk ~~presents~~management, ~~the~~net, includes realized gains and losses and unrealized mark-to-market changes in the fair value of the derivative ~~gains~~instruments related to the Partnership’s natural gas and ~~losses~~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 ~~commodity~~this ~~price~~report ~~risk~~for ~~management~~additional ~~gain~~details ~~(loss),~~of ~~net~~the Partnership’s derivative financial instruments.

	Three months ended September 30,						Nine months ended September 30,
	2010			2009			2010			2009
Commodity price risk management gain (loss), net
Realized gains
Natural Gas	$	7,877		$	309,729		$	308,113		$	1,186,709
Oil		73,407			114,396			199,031			510,482
Total realized gain, net		81,284			424,125			507,144			1,697,191
Unrealized gains (losses)
Reclassification of realized gains included in prior periods unrealized		(43,141	)		(422,547	)		(149,765	)		(1,407,138	)
Unrealized gain (loss) for the period		546,035			(429,452	)		1,369,013			(1,430,112	)
Total unrealized gain (loss), net		502,894			(851,999	)		1,219,248			(2,837,250	)
Commodity price risk management gain (loss), net	$	584,178		$	(427,874	)	$	1,726,392		$	(1,140,059	)

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

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

	Three months ended March 31,
Commodity price risk management, net	2011			2010
Realized gain (loss)
Natural gas	$	70,560		$	305,693
Crude oil		(46,116	)		60,725
Total realized gain, net		24,444			366,418

Unrealized (loss) gain
Reclassification of realized gain included in prior periods unrealized prior periods unrealized		(18,239	)		(338,695	)
Unrealized (loss) gain for the period		(116,859	)		800,579
Total unrealized (loss) gain, net		(135,098	)		461,884
Commodity price risk management (loss) gain, net	$	(110,654	)	$	828,302

~~The~~Three ~~realized~~months ~~derivative~~ended ~~gains~~March ~~for~~31, ~~the~~2011 ~~2010~~as ~~nine month period were $0.5 million. These realized gains were primarily a result of lower natural gas and oil spot prices at settlement~~ compared to ~~the~~three ~~respective~~months ~~strike~~ended ~~price,~~March ~~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~~31, ~~realized gains related to the Partnership's commodity positions were $0.7 million and realized losses on the Partnership’s basis position were $0.2 million. Unrealized gains for the~~ 2010 nine month period were $1.4 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 $1.5 million offset by unrealized losses on the Partnership's basis position of $0.1 million.

~~For~~Realized ~~the~~gains ~~2009~~recognized ~~nine~~in ~~month~~the ~~period,~~three ~~the~~months ~~Partnership~~ended ~~realized~~March ~~significant~~31, ~~derivative~~2011 ~~gains~~are asprimarily athe result of lower natural gas ~~and~~spot ~~oil~~ prices at settlement compared to the respective ~~derivative~~ strike ~~prices~~price of the Partnership’s natural gas derivative positions. ~~Unrealized~~Realized ~~losses~~gains on natural gas settlements were $139,000 for the ~~period~~three months ended March 31, 2011. These gains were ~~related~~offset toin ~~oil~~part ~~swaps~~by a $68,000 loss on the Partnership’s CIG basis protection swaps as the ~~forward~~negative ~~strip~~basis differential between NYMEX and Colorado Interstate Gas (“CIG”) was narrower than the strike price of the basis positions. The Partnership also realized a $46,000 loss on its crude oil ~~rebounded~~positions ~~during~~due to higher spot prices at settlement compared to the ~~period,~~respective ~~and~~strike price. Unrealized losses during the ~~CIG~~three ~~basis~~months ~~swaps~~ended March 31, as2011 are primarily related to the shifts in the forward ~~basis~~curves ~~differential~~and ~~during~~their impact on the ~~period~~fair ~~between~~value ~~NYMEX~~of ~~and~~the ~~CIG~~Partnership’s ~~continued~~open topositions. The ~~narrow~~significant ~~from~~shift upward in the ~~strike~~crude ~~price~~oil curve resulted in an unrealized loss of $81,000 during the ~~derivative~~three ~~position~~months ended March 31, 2011. Likewise, the shifts upward in the natural gas and basis curves resulted in a total unrealized loss of $36,000.

~~Three~~During the three months ended ~~September~~March 3031, 2010, the Partnership recorded realized gains of $366,000 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 ~~September~~March 3031, ~~2009~~2010, the Partnership recorded unrealized gains of $801,000, of which $967,000 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 $166,000 as the forward basis differential between NYMEX and CIG had continued to narrow.

The realized derivative gains for the 2010 third quarter were approximately $0.1 million. These 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 $0.2 million and realized losses on the Partnership’s basis position were $0.1 million. For the 2010 quarter, the unrealized gains $0.5 million were primarily related to the oil positions, as the forward strip price shifted downward during the quarter, and the widening of the NYMEX-~~CIG~~ ~~basis~~19 differential. Unrealized gains on the Partnership’s commodity positions for the 2010 third quarter were $0.6 million offset by unrealized losses on the Partnership's basis position of $0.1 million.-

~~- 15 -~~Index

INDEX

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~For~~The ~~the~~following ~~2009~~table ~~third~~presents ~~quarter,~~ the Partnership’s ~~realized significant~~ derivative ~~gains~~positions asin aeffect ~~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~~March ~~rebounded during the period~~31, ~~and the CIG basis swaps, as the forward basis differential during the period between NYMEX and CIG continued to narrow from the strike price of the derivative position~~2011.

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.

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

Natural Gas

NYMEX
04/01 - 06/30/2011		-	$	-	$	-		81,122	$	6.78		81,122	$	(1.88	)	$	78,708
07/01 - 09/30/2011		-		-		-		79,721		6.73		79,721		(1.88	)		58,457
10/01 - 12/31/2011		-		-		-		77,385		6.78		77,385		(1.88	)		41,991
01/01 - 03/31/2012		6,161		6.00		8.27		68,423		6.98		74,583		(1.88	)		23,275
04/01 - 12/31/2012		12,609		6.00		8.27		202,561		6.98		215,169		(1.88	)		103,838
2013		-		-		-		264,037		7.12		264,037		(1.88	)		75,058
Total Natural Gas		18,770						773,249				792,017					381,327

Crude Oil
NYMEX
04/01 - 06/30/2011		-		-		-		2,001		70.75		-		-			(70,875	)
07/01 - 09/30/2011		-		-		-		2,027		70.75		-		-			(73,308	)
10/01 - 12/31/2011		-		-		-		2,016		70.75		-		-			(72,842	)
Total Crude Oil		-						6,044				-					(217,025	)

Total Natural Gas and Crude Oil																$	164,302

~~The~~(1) ~~following~~A ~~table~~standard ~~presents~~unit ~~the~~of ~~Partnership’s~~measure ~~derivative~~for ~~positions~~natural ingas ~~effect~~(one asMMbtu ofequals ~~September~~one ~~30, 2010~~Mcf).

	Collars						Fixed-Price Swaps				CIG Basis Protection Swaps
Commodity/	Quantity (Gas-		Weighted Average Contract Price				Quantity (Gas-Mmbtu		Weighted Average Contract		Quantity (Gas-		Weighted Average Contract			Fair Value at September 30,
Index	Mmbtu)(1)		Floors		Ceilings		Oil-Bbls)(1)		Price		Mmbtu)(1)		Price			2010(2)
Natural Gas
CIG
10/01 - 12/31/2010		26,098	$	4.75	$	9.45		—	$	—		—	$	—		$	29,068
01/01 - 03/31/2011		39,147		4.75		9.45		—		—		—		—			36,332
NYMEX
10/01 - 12/31/2010		8,929		5.75		8.30		50,333		6.14		61,468		(1.88	)		39,795
01/01 - 03/31/2011		12,015		5.75		8.30		30,508		6.83		42,523		(1.88	)		33,307
04/01 - 06/30/2011		—		—		—		81,122		6.78		81,122		(1.88	)		96,558
07/01 - 09/30/2011		—		—		—		79,721		6.73		79,721		(1.88	)		78,203
10/01 - 12/31/2011		—		—		—		77,385		6.78		77,385		(1.88	)		48,638
2012-2013		18,770		6.00		8.27		535,021		7.05		553,789		(1.88	)		277,742
Total Natural Gas		104,959						854,090				896,008					639,643
Oil
NYMEX
10/01 - 12/31/2010		—		—		—		4,382		92.96		—		—			51,208
01/01 - 03/31/2011		—		—		—		1,973		70.75		—		—			(23,672	)
04/01 - 06/30/2011		—		—		—		2,001		70.75		—		—			(26,191	)
07/01 - 09/30/2011		—		—		—		2,027		70.75		—		—			(28,141	)
10/01 - 12/31/2011		—		—		—		2,016		70.75		—		—			(29,344	)
Total Oil		—						12,399				—					(56,140	)
Total Natural Gas and Oil																$	583,503

(2)

Approximately 2% 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 of Financial Instruments, to the accompanying unaudited condensed financial statements included in this report.

~~(1)~~Natural AGas, ~~standard~~NGLs ~~unit of measure for natural gas (one MMBtu equals one Mcf). (2) Approximately 9% of the fair value of the Partnership’s derivative assets~~ and ~~all~~Crude ofOil ~~the~~Production Partnership’s derivative liabilities were measured using significant unobservable inputs (Level 3), see Note 4, Fair Value Measurements, to the accompanying unaudited condensed financial statements included in this report.Costs

-Generally, 16natural -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.

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

Production and operating costs per Mcfe increased to $2.29 during the current period compared to $1.73 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 increased by approximately $52,000, primarily due to increases in environmental costs of approximately $55,000 at two of the Partnership’s wells partially offset by decreases in natural gas transportation and lease operating expenses resulting from decreased production volumes as compared to the same period in 2010.

- 20 -

Index

PDC 2005-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 16%, which reflects in part, the normally-occurring production declines throughout a natural gas and oil well’s production life cycle. Additionally, Grand Valley Field well equipment constraints, requiring well workovers of four wells, as well as Wattenberg Field operational constraints on most wells during the first half of 2010, also contributed to the production decline during the current period.

Production and operating costs were higher by approximately $0.3 million or 37%, primarily as a result of higher lease operating expenses related to eight Partnership well workovers as well as increased production taxes due to higher commodity valuations. Additionally, 2010 well operations costs rose as a 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 and operating costs per Mcfe were $2.48 for the nine months ended September 30 of 2010 compared to $1.51 for the comparable period in 2009.

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 23%, primarily as a result of the Partnership wells’ reduced performance in the Grand Valley Field due to the well equipment constraints noted above and expected normally-occurring production life-cycle decline in both operating fields.

Production and operating costs were higher by approximately $0.2 million, or 60% primarily due to higher lease operating expenses as a result of six workovers conducted during the quarter. Environmental remediation costs recorded during the quarter ended September 30, 2010 include an accrual of approximately $44,000 for estimated costs to complete remediation at three well sites. Production and operating costs per Mcfe were $3.31 and $1.59 for the quarter ended September 30, 2010 and 2009, respectively.

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 ~~decreased~~increased during the ~~nine~~three months ended ~~September~~March 3031, ~~2010~~2011, compared to the same period in ~~2009~~2010, by approximately $~~0.2~~12,000 ~~million~~ principally due to ~~reduced~~increased ~~billings~~fees for the above referenced professional services.

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

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 decreased during the three months ended September 30, 2010, compared to the same period in 2009, by approximately $45,000 principally due to reduced billings for professional services.

- 17 -

INDEX

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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 decreased to $3.89 for the 2011 three month period, compared to $4.47 during the same period in 2010. The decrease in the per Mcfe rates for the 2011 period compared to the 2010 period is due to the changing production mix between the Partnership’s Wattenberg and Grand Valley Fields, which have significantly different DD&A rates. Additionally the effect of the upward revision in the Partnership’s proved developed producing natural gas, NGLs and crude oil reserves as of December 31, 2010, resulted in a decrease in the per Mcfe rates. The decreased DD&A expense rate, and production decreases, noted in previous sections, resulted in an overall decreased DD&A expense of approximately $0.2 million for the 2011 three month period compared to ~~nine~~the same 2010 period. The settlement identified above in the Summary Operating Results table increased DD&A expense by $27,000 in the three months ended ~~September~~March 3031, ~~2009~~2011.

~~The~~Financial ~~DD&A expense rate per Mcfe decreased to $4.48 for the 2010 nine month period~~Condition, ~~compared~~Liquidity to $6.53 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 changing production mix between the Partnership’s Wattenberg and ~~Grand~~Capital Valley Fields, which have significantly different DD&A rates. This was partially offset by lower field-level depletion rates due to the effects of reserve revisions at December 31, 2009 compared to December 31, 2008 in which proved developed producing upward revisions occurred in both the Partnership’s Grand Valley and Wattenberg fields. 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 $1.6 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 $60,000 from the Partnership’s cash distributions pursuant to the Well Refracturing Plan. Through April 30, 2011, $130,000 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 2012, 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 $4substantially driven by changes in commodity prices, in production volumes and in realized gains and losses from commodity positions.35 Commodity ~~for~~prices have historically been volatile and the ~~2010~~Managing ~~third~~General ~~quarter,~~Partner ~~compared~~attempts to $6manage 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 ~~combined~~Partnership ~~effects~~had natural gas and crude oil derivative positions in place covering 73% of the ~~changing~~expected natural gas production ~~mix~~and ~~between~~41% ~~fields~~of ~~and~~expected ~~lower~~crude ~~field-level~~oil ~~depletion~~production ~~rates~~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 $02010.6 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~~The ~~Resources~~Partnership’s future operations are expected to be conducted with available funds and ~~Liquidity~~revenues generated from natural gas, NGLs and crude oil production activities and commodity gains. Natural gas, NGLs and crude oil production from the Partnership’s existing properties are generally expected to continue a gradual decline in the rate of production over the remaining life of the wells. Therefore, the Partnership anticipates a lower annual level of natural gas, NGLs and crude oil production and, in the absence of significant price increases or additional reserve development, lower revenues. The Partnership also expects cash flows from operations to decline if commodity prices remain at current levels or decrease in the future. Under these circumstances decreased production would have a material negative impact on the Partnership’s operations and may result in reduced cash distributions to the Managing General Partner and Investor Partners through the remainder of 2011 and beyond, and may substantially reduce or restrict the Partnership’s ability to participate in the refracturing activities which are more fully described in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments−Well Refracturing Plan.

~~The~~- ~~Partnership’s~~21 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 73% of the expected natural gas production and 73% of expected oil production for the remainder of 2010, at an average price of $4.32 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.-

~~- 18 -~~Index

INDEX

PDC 2005-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 and oil production activities and commodity gains, if any. Natural gas and 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 of the wells. Therefore, the Partnership anticipates a lower annual level of natural gas and oil production and, in the absence of significant price increases or successful refracturings, 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 Investor Partners through the remainder of 2010 and beyond, and may substantially reduce or restrict the Partnership’s ability to participate in the Well Refracturing Plan activities which are more fully described in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Well Refracturing Plan.

Working Capital

The Partnership had working capital of approximately $0.98 million at ~~September~~both 30March 31, ~~2010~~2011 ~~compared~~and ~~to working capital of $1.2 million at~~ December 31, ~~2009~~2010. ~~This~~The ~~decrease~~following ofoffsetting ~~approximately~~changes ~~$0.3~~resulted ~~million~~in ~~was~~substantially ~~primarily~~no ~~due~~change to the ~~following~~working ~~changes in accounts receivable and payable balances~~capital:

●· ~~Natural~~Cash ~~gas~~ and ~~oil~~cash ~~receivables~~equivalents ~~decreased~~increased by $0.21 million asbetween ofMarch ~~September 30~~31, ~~2010~~2011 ~~compared~~and to December 31, ~~2009~~2010.

●· Realized and Unrealized derivative gains receivables decreased by $0.21 million asbetween ofMarch ~~September 30~~31, ~~2010~~2011 ~~compared~~and to December 31, ~~2009~~2010.

●Working ~~Net~~capital ~~short-term~~is ~~unrealized~~expected ~~derivative~~to ~~gains~~fluctuate ~~receivable~~by ~~increased~~increasing byduring ~~approximately~~periods ~~$0.2~~of ~~million~~Well asRefracturing ofPlan ~~September~~funding ~~30,~~and ~~2010~~by ~~compared~~decreasing toduring ~~December~~periods ~~31,~~when ~~2009~~payments are made for refracturing.

● Due to the Managing General Partner-other payable, excluding natural gas and oil sales received from third parties and realized derivative gains, increased by approximately $0.1 million as of September 30, 2010 compared to December 31, 2009.

Working capital, primarily cash and cash equivalents, is expected to increase during 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 activities, 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 Partners on a pro-rata basis. 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.

Cash Flows

Cash Flows From ~~Investing~~Operating Activities

The Partnership,’s ~~from~~cash ~~time-to-time,~~flows ~~invests~~provided inby ~~additional~~operating ~~equipment~~activities ~~which~~is ~~supports~~primarily ~~treatment~~impacted by commodity prices, ~~delivery~~production volumes, realized gains and ~~measurement~~losses offrom ~~natural~~its ~~gas~~derivative positions, operating costs and ~~oil~~general orand ~~environmental~~administrative ~~protection~~expenses. ~~These~~See ~~amounts~~Results ~~totaled~~of ~~approximately~~Operations ~~$29,000~~above for an additional discussion of the ~~nine~~key ~~months~~drivers ~~ended~~of ~~September~~cash ~~30,~~flows ~~2010~~provided ~~and~~by ~~2009,~~operating ~~respectively~~activities.

-Natural 19gas, -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.

~~INDEX~~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.

- 22 -

Index

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Net cash provided by operating activities was approximately $0.6 million for the three months ended March 31, 2011, compared to approximately $1.2 million for the comparable period in 2010. The approximately $0.6 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 $0.2 million, or 22%,

A decrease in commodity price risk management realized gains receipts of $0.3 million, or 75% and

An increase 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 $4,000 and $6,000 for the three months ended March 31, 2011 and 2010, respectively.

Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in December 2005 and has distributed $3233.42 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		$	85,510		$	342,037		$	427,547
ended	General Partner			Partners			Total
2009		$	318,891		$	1,275,563		$	1,594,454
March 31,	Distributions			Distributions			Distributions
2011	$	95,977		$	383,905		$	479,882
2010	$	236,187		$	944,751		$	1,180,938

Nine months ended September 30,	Managing General Partner Distributions		Investor Partners Distributions		Total Distributions
2010	$	482,822	$	1,931,290	$	2,414,112
2009	$	795,462	$	3,181,853	$	3,977,315

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 $412,000 and $1648,000 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.

~~Cash~~- ~~Flows~~23 ~~From Operating Activities~~-

Net cash provided by operating activities was $2.5 million for the nine months ended September 30, 2010, compared to approximately $3.7 million for the comparable period in 2009. The approximately $1.2 million decrease in cash provided by operating activities was due primarily to the following:Index

●PDC An2005-B ~~increase~~LIMITED ~~in natural gas and oil sales receipts of $0.4 million, or 17%, accompanied by a decrease in direct costs – general and administrative of $0.2 million, or 67%;~~PARTNERSHIP

● (A ~~decrease~~West inVirginia ~~commodity~~Limited ~~price risk management realized gains receipts of $1.3 million, or 64% accompanied by an increase in natural gas and oil production costs of approximately $0.3 million or 37%;~~Partnership)

~~● A decrease in Due to Managing General Partner~~Off-~~other,~~Balance ~~net,~~Sheet ~~receipts of approximately $0.2 million, excluding natural gas and oil sales received from third parties and realized derivative gains.~~Arrangements

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

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.

- 20 -

INDEX

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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~~24 ~~Arrangements~~-

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

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

Item 4. Controls and Procedures

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

(a) Evaluation of Disclosure Controls and Procedures

As of ~~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 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 ~~September~~March 3031, ~~2010~~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.

- 2125 -

~~INDEX~~Index

PDC 2005-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 December 2008, 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~~There ~~following~~were ~~table~~no ~~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
July 1–31, 2010		—	$	—
August 1–31, 2010		0.50		4,810
September 1–30, 2010		—		—
Total third quarter Unit Repurchase Program repurchases		0.50

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. [Removed and Reserved]

Item 5. Other Information

Not applicable.

- 2226 -

~~INDEX~~Index

PDC 2005-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 (filed by PDC as Managing General Partner for PDC 2004-2006 Drilling Program)

S-1 Post- Effective Amend 2

333-111260

Appendix A

06/29/2005

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.

3.2

Certificate of limited partnership which reflects the organization of the Partnership under West Virginia law

10-K

000-51452

3.2

02/26/2009

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.

10.1

Drilling and operating agreement between the Partnership and Petroleum Development Corporation (dba PDC Energy), as Managing General Partner.

10-K

000-51452

10.1

02/26/2009

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.

10.2

Form of assignment of leases to the Partnership

10-K

000-51452

10.2

02/26/2009

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~~27 ~~3 000~~-~~53201 10.5 03/31/2009~~

~~- 23 -~~Index

INDEX

PDC 2005-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

10-Q

000-51452

10.1

05/18/2009

31.1

- 24 -

INDEX

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

31.2

32.1

- 25 -

INDEX

PDC 2005-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 2005-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)
	November 5, 2010

By /s/ Richard W. McCullough

Richard W. McCullough

Chairman and Chief Executive Officer

of Petroleum Development Corporation (dba PDC Energy)

May 16, 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	~~Date~~
/s/ Richard W. McCullough	Chairman and Chief Executive Officer	May 16, 2011	~~November 5, 2010~~
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	May 16, 2011	~~November 5, 2010~~
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	May 16, 2011	~~November 5, 2010~~
R. Scott Meyers	Petroleum Development Corporation (dba PDC Energy) ~~Managing General Partner of the Registrant~~
	(Principal accounting officer)
	Managing General Partner of the Registrant
	(Principal accounting officer)

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