UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

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

OF 1934

For the quarterly period ended March 31, 2010

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)

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) and (2) has been subject to such filing requirements for the past 90 days.

Yes TNo ¨

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 ¨ No ¨

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

	Large accelerated filer ¨	Accelerated filer ¨

	Non-accelerated filer ¨	Smaller reporting company T

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

As of March 31, 2010 the Partnership had 2,022.64 units of limited partnership interest and no units of additional general partnership interest outstanding.

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

INDEX TO REPORT ON FORM 10-Q

		Page
PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements (unaudited)
	Condensed Balance Sheets(unaudited)	2
	Condensed Statements of Operations(unaudited)	3
	Condensed Statements of Cash Flows(unaudited)	4
	Notes to Unaudited Condensed Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	19
Item 4T.	Controls and Procedures	19

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	20
Item 1A.	Risk Factors	20
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	20
Item 3.	Defaults Upon Senior Securities	20
Item 4.	[Removed and Reserved]	20
Item 5.	Other Information	20
Item 6.	Exhibits	21

	SIGNATURES	22

Index

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’s” or the “Registrant’s”) business, financial condition, results of operations and prospects. All statements 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 reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and the Managing General Partner Petroleum Development Corporation’s (“PDC’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 risks and uncertainties incidental to the development, production and marketing of natural gas and oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

changes in production volumes, worldwide demand, and commodity prices for natural gas and oil;

risks incident to the operation of natural gas and oil wells;

future production and development costs;

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 States of America;

the effect of natural gas and oil derivatives activities;

conditions in the capital markets; and

losses possible from pending or future litigation.

Further, the Partnership urges the reader to carefully review and consider the cautionary statements made in this report, the Partnership’s annual report on Form 10-K for the year ended December 31, 2009 filed with the Securities and Exchange Commission (“SEC”) on March 31, 2010, (“2009 Form 10-K”), 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 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.

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Index

PART I – FINANCIAL INFORMATION

Item 1.

Financial Statements (unaudited)

PDC 2005-B Limited Partnership

Condensed Balance Sheets

(unaudited)

	March 31,			December 31,
	2010			2009*
Assets

Current assets:
Cash and cash equivalents	$	201,006		$	201,006
Accounts receivable		380,806			354,817
Oil inventory		22,482			29,980
Due from Managing General Partner-derivatives		535,172			487,802
Due from Managing General Partner-other, net		570,619			578,687
Total current assets		1,710,085			1,652,292


Oil and gas properties, successful efforts method, at cost		45,013,094			45,007,332
Less: Accumulated depreciation, depletion and amortization		(21,609,052	)		(20,826,745	)
Oil and gas properties, net		23,404,042			24,180,587

Due from Managing General Partner-derivatives		918,842			368,502
Other assets		25,703			18,917
Total noncurrent assets		24,348,587			24,568,006

Total Assets	$	26,058,672		$	26,220,298

Liabilities and Partners' Equity

Current liabilities:
Accounts payable and accrued expenses	$	41,215		$	36,571
Due to Managing General Partner-derivatives		453,362			377,704
Total current liabilities		494,577			414,275

Due to Managing General Partner-derivatives		1,174,513			1,114,345
Asset retirement obligations		529,712			522,803
Total liabilities		2,198,802			2,051,423

Commitments and contingent liabilities

Partners' equity:
Managing General Partner		4,783,043			4,844,843
Limited Partners - 2,022.64 units issued and outstanding		19,076,827			19,324,032
Total Partners' equity		23,859,870			24,168,875

Total Liabilities and Partners' Equity	$	26,058,672		$	26,220,298

_________________________________________

*Derived from audited 2009 balance sheet

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2005-B Limited Partnership

Condensed Statements of Operations

(unaudited)

	Three months ended March 31,
	2010		2009
Revenues:
Natural gas and oil sales	$	1,171,574	$	735,893
Commodity price risk management gain, net		828,302		31,158
Total revenues		1,999,876		767,051

Operating costs and expenses:
Natural gas and oil production costs		302,984		301,411
Direct costs - general and administrative		35,743		150,998
Depreciation, depletion and amortization		782,307		1,308,914
Accretion of asset retirement obligations		6,909		4,891
Total operating costs and expenses		1,127,943		1,766,214

Income (loss) from operations		871,933		(999,163	)

Interest income		-		8,603

Net income (loss)	$	871,933	$	(990,560	)

Net income (loss) allocated to partners	$	871,933	$	(990,560	)
Less: Managing General Partner interest in net income (loss)		174,387		(198,112	)
Net income (loss) allocated to Investor Partners	$	697,546	$	(792,448	)

Net income (loss) per Investor Partner unit	$	345	$	(392	)

Investor Partner units outstanding		2,022.64		2,022.64

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2005-B Limited Partnership

Condensed Statements of Cash Flows

(unaudited)

	Three months ended March 31,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	871,933		$	(990,560	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		782,307			1,308,914
Accretion of asset retirement obligations		6,909			4,891
Unrealized (gain) loss on derivative transactions		(461,884	)		741,620
Changes in operating assets and liabilities:
Increase in accounts receivable		(25,989	)		(2,259	)
Decrease (increase) in oil inventory		7,498			(8,944	)
Increase in other assets		(6,786	)		-
Increase (decrease) in accounts payable and accrued expenses		4,644			(4,138	)
Decrease (increase) in due from Managing General Partner - other, net		8,068			(61,828	)
Net cash provided by operating activities		1,186,700			987,696

Cash flows from investing activities:
Capital expenditures for oil and gas properties		(5,762	)		-
Proceeds from Colorado sales tax refund related to capital purchases		-			2,894
Net cash (used in) provided by investing activities		(5,762	)		2,894

Cash flows from financing activities:
Distributions to Partners		(1,180,938	)		(988,844	)
Net cash used in financing activities		(1,180,938	)		(988,844	)

Net increase in cash and cash equivalents		-			1,746
Cash and cash equivalents, beginning of period		201,006			444,727
Cash and cash equivalents, end of period	$	201,006		$	446,473

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2005-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2010

(unaudited)

Note 1−General and Basis of Presentation

The PDC 2005-B Limited Partnership 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 and natural gas properties. Upon completion of the sale of Partnership units on May 18, 2005 the Partnership was funded and commenced its business operations. The Partnership owns natural gas and oil wells located in Colorado, and from the wells, the Partnership produces and sells natural gas and oil.

Purchasers of partnership units subscribed to and fully paid for 37.77 units of limited partner interests and 1,984.87 units of additional general partner interests at $20,000 per unit. In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), Petroleum Development Corporation, a Nevada Corporation, is the Managing General Partner of the Partnership (hereafter, the “Managing General Partner” or “PDC”) and has a 20% Managing General Partner ownership in the Partnership. Upon completion of the drilling phase of the Partnership's wells, all additional general partners units were converted into units of limited partner interests and thereafter became limited partners of the Partnership. Throughout the term of the Partnership, revenues, costs, and cash distributions are allocated 80% to the limited and additional general partners (collectively, the “Investor Partners”), which are shared pro rata based upon the portion of units owned in the Partnership, and 20% to the Managing General Partner.

As of March 31, 2010, there were 1,625 Investor Partners. As of March 31, 2010 the Managing General Partner has repurchased 42.41 units of the total 2,022.64 outstanding units of Partnership interests from Investor Partners at an average price of $11,077 per unit and, as a result, participates in the sharing of revenues, costs and cash distributions as both an investor partner and as the Managing General Partner.

The Managing General Partner, under the terms of the Drilling and Operating Agreement (the “D&O Agreement”), has full authority to conduct the Partnership’s business and actively manage the Partnership. The Partnership expects continuing operations of its oil and natural gas properties until such time that a well is depleted or becomes uneconomical to produce, at which time that well will be plugged and abandoned. The Partnership’s maximum term of existence extends through December 31, 2055, unless dissolved by certain conditions stipulated within the Agreement which are unlikely to occur at this time, or by written consent of the Investor Partners owning a majority of outstanding units at that time.

In the Managing General Partner’s opinion, the accompanying interim unaudited condensed financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary for a fair presentation of the Partnership’s financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. The information presented in this quarterly report on Form 10-Q should be read in conjunction with the Partnership’s audited financial statements and notes thereto included in the Partnership’s 2009 Form 10-K. The Partnership’s accounting policies are described in the Notes to Financial Statements in the Partnership’s 2009 Form 10-K and updated, as necessary, in this Form 10-Q. The results of operations for the three months ended March 31, 2010, and the cash flows for the same period, are not necessarily indicative of the results to be expected for the full year or any other future period.

The accompanying interim unaudited condensed financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Partnership's Form 10-K for the year ended December 31, 2009, as filed with the SEC on March 31, 2010 (“the 2009 Form 10-K”).

The Managing General Partner has evaluated the Partnership’s activities subsequent to March 31, 2010 and has concluded that no material subsequent events have occurred that would require recognition in the Partnership’s financial statements or disclosure in the notes to the Partnership’s financial statements.

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Index

PDC 2005-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2010

(unaudited)

Note 2−Recent Accounting Standards

Recently Adopted Accounting Standards

Fair Value Measurements and Disclosures

In January 2010, the Financial Accounting Standards Board (“FASB”) issued changes clarifying existing disclosure requirements related to fair value measurements. The update 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.

Recently Issued Accounting Standards

Fair Value Measurements and Disclosures

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

Note 3−Transactions with Managing General Partner and Affiliates

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

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

	March 31,			December 31,
	2010			2009

Natural gas and oil sales revenues collected from the Partnership's third-party customers	$	418,233		$	394,751
Commodity price risk management, realized gains		256,836			310,897
Other (1)		(104,450	)		(126,961	)
Total Due from Managing General Partner-other, net	$	570,619		$	578,687

(1)

All other unsettled transactions, excluding derivative instruments, between the Partnership and the Managing General Partner.

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Index

PDC 2005-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2010

(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 three months ended March 31, 2010 and 2009. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in “Natural gas and oil production costs” on the statements of operations.

	Three months ended March 31,
	2010		2009

Well operations and maintenance	$	232,388	$	224,912
Gathering, compression and processing fees		27,525		24,665
Direct costs - general and administrative		35,743		150,998
Cash distributions*		255,925		209,061

*Cash distributions include $19,738 during the three months ended March 31, 2010, and $11,293 during the three months ended March 31, 2009, related to equity cash distributions on Investor Partner units repurchased by PDC. For additional disclosure regarding the Unit Repurchase Program, refer to Note 1, General and Basis of Presentation.

Note 4−Fair Value Measurements

Derivative Financial Instruments. The Partnership measures fair value based upon quoted market prices, where available. The valuation determination includes: (1) identification of the inputs to the fair value methodology through the review of counterparty statements and other supporting documentation, (2) determination of the validity of the source of the inputs, (3) corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. The methods described above may produce a fair value calculation that may not be indicative of future fair values. The valuation determination also gives consideration to nonperformance risk on Partnership liabilities in addition to nonperformance risk on PDC’s own business interests and liabilities, as well as the credit standing of derivative instrument counterparties. The Managing General Partner primarily uses financial institutions, who are also major lenders in PDC’s credit facility agreement, as counterparties to the Partnership’s derivative contracts. The Managing General Partner has evaluated the credit risk of the counterparties holding the Partnership’s derivative assets using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on the Managing General Partner’s evaluation, as of March 31, 2010, the impact of non-performance risk on the fair value of the Managing General Partner’s derivative assets and liabilities was not significant Validation of the Partnership’s contracts’ fair values are performed internally and while the Managing General Partner uses common industry practices to develop valuation techniques, changes in the Managing General Partner’s pricing methodologies or the underlying assumptions could result in significantly different fair values. While the Managing General Partner believes these valuation methods are appropriate and consistent with those used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

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Index

PDC 2005-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2010

(unaudited)

The following table presents, by hierarchy level, the Partnership’s derivative financial instruments, including both current and non-current portions measured at fair value.

	Quoted Prices in			Significant
	Active Markets			Unobservable Inputs
	(Level 1)			(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 March 31, 2010
Assets:
Commodity based derivatives	$	1,281,705		$	172,309		$	1,454,014
Total assets		1,281,705			172,309			1,454,014

Liabilities:
Commodity based derivatives		-			(116,909	)		(116,909	)
Basis protection derivative contracts		-			(1,510,966	)		(1,510,966	)
Total liabilities		-			(1,627,875	)		(1,627,875	)

Net asset (liability)	$	1,281,705		$	(1,455,566	)	$	(173,861	)

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

	Three months ended
	March 31, 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		(105,143	)
Settlements		(366,418	)
Fair value, net liability, as of March 31, 2010	$	(1,455,566	)

Change in unrealized gains (losses) relating to assets (liabilities) still held as of March 31, 2010 included in statement of operations line item:
Commodity price risk management, net	$	(132,866	)

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

Non-Derivative 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.

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Index

PDC 2005-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2010

(unaudited)

Note 5−Derivative Financial Instruments

As of March 31, 2010, 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 1,126,304 MMbtu of natural gas and 21,117 Bbls of oil. Partnership policy prohibits the use of natural gas and oil derivative instruments for speculative purposes.

The following table summarizes the location and fair value amounts of the Partnership’s derivative instruments in the accompanying balance sheets.

			Fair Value
		Balance Sheet	March 31,			December 31,
Derivative instruments not designated as hedge (1):		Line Item	2010			2009

Derivative Assets:	Current
	Commodity contracts	Due from Managing General Partner-derivatives	$	535,172		$	487,802

	Non Current
	Commodity contracts	Due from Managing General Partner-derivatives		918,842			368,502


Total Derivative Assets			$	1,454,014		$	856,304

Derivative Liabilities:	Current
	Commodity contracts	Due to Managing General Partner-derivatives	$	(28,266	)	$	(26,334	)

	Basis protection contracts	Due to Managing General Partner-derivatives		(425,096	)		(351,370	)
	Non Current
	Commodity contracts	Due to Managing General Partner-derivatives		(88,643	)		(120,745	)

	Basis protection contracts	Due to Managing General Partner-derivatives		(1,085,870	)		(993,600	)

Total Derivative Liabilities			$	(1,627,875	)	$	(1,492,049	)

As of March 31, 2010 and December 31, 2009, none of the Partnership’s derivative instruments were designated hedges.

The following table summarizes the impact of the Partnership’s derivative instruments on the Partnership’s accompanying statements of operations for the three months ended March 31, 2010 and 2009.

	Three months ended March 31,
	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	$	338,695		$	27,723	$	366,418	$	644,216		$	128,562		$	772,778
Unrealized (losses) gains		(338,695	)		800,579		461,884		(644,216	)		(97,404	)		(741,620	)
Total commodity price risk management gain, net	$	-		$	828,302	$	828,302	$	-		$	31,158		$	31,158

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 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 the derivative contracts. To date, the Partnership has experienced no counterparty default losses.

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Index

PDC 2005-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2010

(unaudited)

Note 6−Commitments and Contingencies

Stormwater Permit. On December 8, 2008, the Managing General Partner received a Notice of Violation /Cease and Desist Order (the “Notice”) from the Colorado Department of Public Health and Environment (the “CDPHE”), related to the stormwater permit for the Garden Gulch Road. The Managing General Partner manages this private road for Garden Gulch LLC. The Managing General Partner is one of eight users of this road, all of which are oil and gas companies operating in the Piceance Basin of Colorado. Operating expenses, including amounts arising from this notice, 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 alleges 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 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 the ultimate outcome of this administrative action at this time and therefore no amounts have been recorded on the Partnership’s financial records.

Derivative Contracts. The Partnership is exposed to natural gas and oil price fluctuations on underlying sales contracts should the counterparties to the Managing General Partner’s derivative instruments not perform. Nonperformance is not anticipated. Neither the Managing General Partner, nor the Partnership, have had any counterparty default losses.

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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

Overview

PDC 2005-B Limited Partnership engages in the development, production and sale of oil and natural gas. The Partnership began oil and gas operations in May 2005 and operates 51 gross (47.3 net) producing wells located in the Rocky Mountain Region in the state of Colorado. One additional Colorado developmental well was determined to be a dry hole. The Managing General Partner markets the Partnership’s natural gas production to commercial end users, interstate or intrastate pipelines or local utilities, primarily under market sensitive contracts in which the price of natural gas sold varies as a result of market forces. PDC, on behalf of the Partnership through the D&O Agreement, may 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.

The Partnership’s wells will produce until they are depleted or until they are uneconomical to produce; however, Partnership well recompletions in the Codell formation of Wattenberg Field wells, may provide for additional reserve development and production. The Managing General Partner has developed a plan to initiate recompletion activities during 2011. This plan includes notifying investor partners that in October 2010, funding for these recompletions will be procured through withholding of future distributable cash flows of the Partnership resulting from both current production and any increased production due to recompletion activities. The funds retained which are necessary for the Partnership to pay for recompletion costs will materially reduce, up to 100%, distributable cash flows for a period of time not to exceed five years. If any or all of the Partnership’s Wattenberg wells are not recompleted due to an unfavorable general economic climate or unfavorable commodity price environment, the Partnership will experience a reduction in proved reserves currently assigned to these wells. Both the number of recompletions and the timing of recompletions will be based on the availability of cash withheld from distributions and continued favorable geological information. The Managing General Partner believes that, based on projected recompletion costs and projected cash withholding, all partnership recompletions can be completed. Current estimated costs for these well recompletions are between $150,000 and $200,000 per recompletion. The Managing General Partner will continue to evaluate the feasibility of commencing those recompletions based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the recompletion.

PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue the acquisition of the remaining third party investor interests in the limited partnerships which PDC has sponsored, including PDC 2005-B Limited Partnership. These purchases, which PDC has stated it anticipates might occur over the next three years, will be subject to PDC’s having sufficient available capital and the approval by a majority of the investors’ partnership interests, excluding partnership interest owned by PDC, of each respective limited partnership.

If a purchase offer from PDC is proposed and approved by a majority of the Partnerships’ unaffiliated limited partners, it would result in a liquidating cash distribution to all partners and termination of the existence of the Partnership.

- 11 -

Index

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Results of Operations

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

	Three months ended March 31,
	2010		2009		Change
Number of producing wells (end of period)		51		51		-

Production: (1)
Natural gas (Mcf)		125,077		134,046		-7	%
Oil (Bbl)		7,471		8,952		-17	%
Natural gas equivalents (Mcfe) (2)		169,903		187,758		-10	%
Mcfe per day		1,888		2,086

Natural Gas and Oil Sales
Natural gas	$	626,976	$	407,685		54	%
Oil		544,598		328,208		66	%
Total natural gas and oil sales	$	1,171,574	$	735,893		59	%

Realized Gain on Derivatives, net (3)
Natural gas	$	305,693	$	534,010		-43	%
Oil		60,725		238,768		-75	%
Total realized gain on derivatives, net	$	366,418	$	772,778		-53	%

Average Selling Price (excluding realized gain on derivatives)
Natural gas (per Mcf)	$	5.01	$	3.04		65	%
Oil (per Bbl)		72.89		36.66		99	%
Natural gas equivalents (per Mcfe)		6.90		3.92		76	%

Average Selling Price (including realized gain on derivatives)
Natural gas (per Mcf)	$	7.46	$	7.03		6	%
Oil (per Bbl)		81.02		63.34		28	%
Natural gas equivalents (per Mcfe)		9.05		8.04		13	%

Average Lifting Cost (per Mcfe) (4)	$	1.78	$	1.61		11	%

Operating costs and expenses:
Direct costs - general and administrative	$	35,743	$	150,998		-76	%
Depreciation, depletion and amortization	$	782,307	$	1,308,914		-40	%

Cash distributions	$	1,180,938	$	988,844		19	%

_______________

(1)

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

(2)

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

(3)

Amounts represent realized derivative gains related to natural gas and oil sales.

(4)

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

- 12 -

Index

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

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

MBbl – One thousand barrels

Mcf – One thousand cubic feet

MMcf – One million cubic feet

Mcfe – One thousand cubic feet of natural gas equivalents

MMcfe – One million cubic feet of natural gas equivalents

MMbtu – One million British Thermal Units

Natural Gas and Oil Sales

The $0.4 million, or 59% increase in total sales in for the 2010 three month period as compared to the same period in 2009, was primarily a reflection of the significantly higher average sales price per Mcfe, of 76% that was partially offset by the reduction of Partnership production volumes of 10% during the two comparable periods. Average sales price per Mcfe, excluding the impact of realized derivative gains, was $6.90 for the current year quarter compared to $3.92 for the same quarter a year ago.

Oil revenue increases of 66% were slightly above natural gas revenue increases of 54% for the 2010 three month period compared to the same period last year. The Partnership’s oil revenue increase was bolstered by improved average oil sales prices (99%) as compared to the more moderate, yet significant, increase in natural gas sales prices (65%) during the period.

The Partnership expects to experience continued declines in both natural gas and oil production volumes over the wells’ life cycles until such time that the Partnership’s Wattenberg wells may be successfully recompleted. Subsequent to a successful recompletion, production will once again be expected to decline.

Natural Gas and Oil Pricing

Financial results depend upon many factors, particularly the price of natural gas and oil and the Partnership’s ability to market its production effectively. Natural gas and oil prices are among the most volatile of all commodity prices. These price variations have 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 the 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 a local market oversupply situation 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.

The price the Partnership receives for the natural gas produced in the Rocky Mountain Region 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 region 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 recent months and for two out of the last six months became a slight positive differential, which is inconsistent with historical variances. This negative differential between NYMEX and CIG averaged $1.62 for the three months ended March 31, 2009, and narrowed to an average of $0.16 for the three months ended March 31, 2010.

- 13 -

Index

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Commodity Price Risk Management, Net

The Managing General Partner uses natural gas and oil derivative instruments to manage price risk for PDC as well as sponsored drilling partnerships. Commodity price risk management, net includes realized gains and losses and unrealized changes in the fair value of derivative instruments related to the Partnership’s natural gas and oil production. The Managing General Partner sets these instruments for PDC, and the various partnerships managed by PDC. Derivative financial instrument positions taken by the Managing General Partner on the Partnership’s behalf, are specifically designated to the Partnership’s production volumes. See Note 4, Fair Value Measurements and Note 5, Derivative Financial Instruments, to the Partnership’s unaudited condensed financial statements included in this report, for additional details on the Partnership’s derivative financial instruments.

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

	Three months ended March 31,
Commodity price risk management, net	2010			2009
Realized gains
Oil	$	60,725		$	238,768
Natural Gas		305,693			534,010
Total realized gain, net		366,418			772,778

Unrealized gains (losses)
Reclassification of realized (gains) losses included in prior periods unrealized		(338,695	)		(644,216	)
Unrealized gain (loss) for the period		800,579			(97,404	)
Total unrealized gain (loss), net		461,884			(741,620	)
Commodity price risk management gain, net	$	828,302		$	31,158

Realized gains recognized in the first quarter of 2010 which total $0.4 million, are a result of lower natural gas and oil spot prices at the settlement date compared to the respective strike price. During the first quarter of 2010, the Partnership recorded unrealized derivative gains of $0.8 million, $1.0 million of which was related to the Partnership’s natural gas positions, offset in part by unrealized losses on the Partnership’s CIG basis swaps of $0.2 million, as the forward basis differential between NYMEX and CIG has continued to narrow.

During the first quarter of 2009, the Partnership experienced realized gains and unrealized derivative losses as natural gas and oil prices declined. The net unrealized loss for the first quarter of 2009 of $0.1 million was comprised of a decrease in fair value of the Partnership’s CIG basis swaps of $0.6 million which resulted from a steeper decline in NYMEX pricing relative to CIG pricing that was partially offset by a $0.5 million net unrealized gain from the Partnership’s commodity derivatives.

Realized derivative gains, down 53% from the prior year first quarter, contributed an additional $2.15 per Mcfe to this year’s total revenues. Comparatively, the total per Mcfe price realized, consisting of the average sales price and realized derivative gains, increased 13% to $9.05 for the current year quarter from $8.04 for the prior year first quarter.

Natural Gas and Oil Sales Derivative Instruments. The Managing General Partner uses various derivative instruments to manage fluctuations in natural gas and oil prices. The Partnership has in place a series of collars, fixed price swaps and basis protection swaps on a portion of the Partnership’s natural gas and oil production as set forth in the following table. Under the Partnership’s collar arrangements, if the applicable index rises above the ceiling price, the Managing General Partner pays the counterparty; however, if the index drops below the floor price, the counterparty pays the Managing General Partner. Under the Partnership’s commodity swap arrangements, if the applicable index rises above the swap price, the Managing General Partner pays the counterparty; however, if the index drops below the swap price, the counterparty pays the Managing General Partner. Under the Partnership’s basis protection swaps, if the differential widens beyond the basis swap price, then the counterparty pays the Managing General Partner; however, if the differential narrows, then the Managing General Partner pays the counterparty. Because the Partnership sells all of its physical natural gas and oil at similar prices to the indexes inherent in the Partnership’s derivative instruments, the Partnership ultimately realizes a price related to its collars of no less than the floor and no more than the ceiling and, for the Partnership’s commodity swaps, the Partnership ultimately realizes the fixed price related to its swaps.

- 14 -

Index

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

The following table presents the Partnership’s derivative positions in effect as of March 31, 2010.

	Collars						Fixed-Price Swaps				CIG Basis Protection Swaps
Commodity/ Index	Quantity (Gas-Mmbtu)		Weighted Average Contract Price				Quantity (Gas-Mmbtu Oil-Bbls)		Weighted Average Contract Price		Quantity (Gas-Mmbtu)		Weighted Average Contract Price			Fair Value at March 31, 2010(1)
Commodity/ Index	Quantity (Gas-Mmbtu)		Floors		Ceilings		Quantity (Gas-Mmbtu Oil-Bbls)		Weighted Average Contract Price		Quantity (Gas-Mmbtu)		Weighted Average Contract Price			Fair Value at March 31, 2010(1)

Natural Gas
CIG
10/01 - 12/31/2010		26,098	$	4.75	$	9.45		-	$	-		-	$	-		$	16,945
01/01 - 03/31/2011		39,147		4.75		9.45		-		-		-		-			18,573

NYMEX
04/01 - 06/30/2010		-		-		-		84,338		5.56		92,277		(1.88	)		1,418
07/01 - 09/30/2010		-		-		-		82,917		5.57		90,127		(1.88	)		(18,801	)
10/01 - 12/31/2010		8,929		5.75		8.30		50,333		6.14		61,468		(1.88	)		(3,079	)
01/01 - 03/31/2011		12,015		5.75		8.30		30,508		6.83		42,523		(1.88	)		(9,193	)
04/01 - 12/31/2011		-		-		-		238,228		6.77		238,228		(1.88	)		(3,793	)
2012-2013		18,770		6.00		8.27		535,021		7.05		553,789		(1.88	)		(163,237	)
Total Natural Gas		104,959						1,021,345				1,078,412					(161,167	)

Oil
NYMEX
04/01 - 06/30/2010		-		-		-		4,336		92.96		-		-			37,479
07/01 - 09/30/2010		-		-		-		4,382		92.96		-		-			34,394
10/01 - 12/31/2010		-		-		-		4,382		92.96		-		-			32,341
01/01 - 03/31/2011		-		-		-		1,973		70.75		-		-			(28,266	)
04/01 - 12/31/2011		-		-		-		6,044		70.75		-		-			(88,642	)
Total Oil		-						21,117				-					(12,694	)

Total Natural Gas and Oil																$	(173,861	)

(1) Approximately 12% of the fair value of the Partnership’s derivative assets and all of the Partnership’s derivative liabilities were measured using significant unobservable inputs (Level 3), see Note 4, Fair Value Measurements, to the accompanying unaudited condensed financial statements included in this report.

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. Property and severance taxes are estimates by the Managing General Partner based on rates determined using historical information. These amounts are subject to revision based on actual amounts determined during future filings by the Managing General Partner with the taxing authorities. Property and severance 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. These costs include water hauling and disposal, equipment repairs and maintenance, snow removal and service rig workovers.

For the 2010 three month period compared to 2009 three month period, oil and natural production, on an energy equivalency-basis, decreased 17,855 Mcfe, or 10% primarily due to normal production declines for this stage in the wells’ production life cycle in addition to temporary operational constraints during the current quarter at a majority of the Partnership’s Wattenberg Field wells. Production and operating costs remained substantially unchanged at approximately $0.3 million, quarter-to-quarter. Although higher commodity valuations increased production taxes during the three months ended March 31, 2010, this increase was partially offset by a downward adjustment to these accrued taxes due to revisions to tax rates by the Colorado tax agencies, of which the Partnership was notified during the first quarter 2010. Production and operating costs per Mcfe were $1.78 for the 2010 three month period compared to $1.61 for the comparable 2009 three month period.

- 15 -

Index

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Direct Costs−General and Administrative

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 March 31, 2010, compared to the same period in 2009, by approximately $0.1 million principally due to reduced billings for professional services.

Depreciation, Depletion and Amortization

DD&A expense related to natural gas and oil properties is directly related to production volumes for the period. For the quarter ended March 31, 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 of the SEC’s final rule regarding the modernization of oil and gas reporting in the fourth quarter of 2009, the Partnership changed to a price determined by the 12-month average of the first-day-of-the-month price during each month of 2009.

DD&A expense decreased by $0.5 million, or 40%, primarily as result of the significant reduction in the DD&A expense rate per Mcfe that was accompanied by the Partnership’s decrease in production volumes of 10%, quarter-over-quarter. The DD&A expense rate per Mcfe decreased to $4.60 for the 2010 three month period compared to $6.97 during the same period in 2009 partially, as a result of the changing production mix between the Partnership’s Wattenberg and Grand Valley fields that have significantly different DD&A rates, in addition to the effects of reserve revisions at December 31, 2009 compared to December 31, 2008 as calculated by the respective methodologies described above, in which proved developed producing upward revisions occurred in both the Partnership’s Grand Valley and Wattenberg fields.

Capital Resources and Liquidity

The Partnership’s primary sources of cash are from funds generated from 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 cost, 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 manages 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 March 31, 2010, the Partnership had natural gas and oil derivative positions in place covering 75% of expected natural gas production and 73% of expected oil production for the remainder of 2010, at an average price of $3.60 per Mcf and $92.96 per Bbl, respectively. 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.

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 (losses). Natural gas and oil production from the Partnership’s existing properties are generally expected to continue a gradual decline over the remaining life of the wells. Therefore, the Partnership expects a lower annual level of natural gas and oil production and, in the absence of significant price increases or recompletions, 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. Future cash distributions may also be reduced to fund well recompletions in the Codell formation of the Wattenberg field.

- 16 -

Index

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Working Capital

Working capital at March 31, 2010 of $1.2 million was substantially unchanged from working capital at the same period last year. Significant components that comprise working capital include the following:

Natural gas and oil receivables remained unchanged at approximately $0.7 million as of March 31, 2010 and December 31, 2009, respectively.

Realized derivative gains receivables remained unchanged at approximately $0.3 million as of March 31, 2010 and December 31, 2009, respectively.

Net short-term unrealized derivative gains receivables remained unchanged at approximately $0.1 million as of March 31, 2010 and December 31, 2009, respectively.

Due to Managing General Partner-other, net, excluding natural gas and oil sales received from third parties and realized derivative gains, remained unchanged at an approximately $0.1 million liability as of March 31, 2010 and December 31, 2009, respectively.

Cash Flows

Cash Flows From Investing Activities

The Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of natural gas and oil or environmental protection. These amounts totaled approximately $6,000 for the three months ended March 31, 2010. During the 2009 three month period, the Partnership received an approximate $3,000 net refund from the State of Colorado for state sales taxes which was treated as a reduction to the Partnership’s capitalized “Oil and gas properties.”

Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in December 2005 and has distributed $31.2 million through March 31, 2010. The table below presents the cash distributions to the Managing General Partner and Investor Partners, including Managing General Partner distribution relating to limited partnership units repurchased, for the periods described.

Quarter ended March 31,	Managing General Partner Distributions		Investor Partners Distributions		Total Distributions

2010	$	236,187	$	944,751	$	1,180,938

2009	$	197,768	$	791,076	$	988,844

Cash Flows From Operating Activities

Net cash provided by operating activities was $1.2 million for the three months ended March 31, 2010, compared to $1.0 million for the comparable period in 2009. The $0.2 million increase in cash provided by operating activities was due primarily to the following:

An increase in natural gas and oil sales receipts of approximately $0.3 million, or 37%, accompanied by a decrease in direct costs – general and administrative of $0.1 million, or 76%; and

A decrease in commodity price risk management realized gains receipts of approximately $0.2 million or 34%.

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Index

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Commitments and Contingencies

See Note 6, Commitments and Contingencies, to the accompanying unaudited condensed financial statements.

Recent Accounting Standards

See Note 2, Recent Accounting Standards to the accompanying unaudited condensed financial statements.

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 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.

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Index

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

Item 4T.

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 March 31, 2010, PDC, as Managing General Partner 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 13a-15(e) and 15d-15(e). This evaluation considered the various processes carried out under the direction of the Managing General Partner’s Disclosure Committee in an effort to ensure that information required to be disclosed in the SEC reports that we file or submit under the Exchange Act are 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 March 31, 2010.

(b) Changes in Internal Control over Financial Reporting

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 March 31, 2010, that have materially affected or are reasonably likely to materially affect the Partnership’s internal control over financial reporting.

- 19 -

Index

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

PART II – OTHER INFORMATION

Item 1.

Legal Proceedings

Information regarding the Registrant’s legal proceedings can be found in Note 6, Commitments and Contingencies, to the Partnership’s accompanying unaudited condensed financial statements.

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 following table presents information about the Managing General Partner’s limited partner unit repurchases during the three months ended March 31, 2010.

Period	Total Number of Units Repurchased		Average Price Paid per Unit

January 1−31, 2010		-	$	-
February 1−28, 2010		0.50		5,300
March 1−31, 2010		-		-
Total first 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.

- 20 -

Index

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 6.

Exhibits

(a)	Exhibit Index.

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

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

10.1

Drilling and operating agreement between the Partnership and PDC, as Managing General Partner of the Partnership

10-K

000-51452

10.1

02/26/2009

31.1

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

31.2

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

32.1

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

- 21 -

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

	By: /s/ Richard W. McCullough
	Richard W. McCullough Chairman and Chief Executive Officer May 14, 2010

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

Signature	Title	Date

/s/ Richard W. McCullough	Chairman and Chief Executive Officer	May 14, 2010
Richard W. McCullough	Petroleum Development Corporation
	Managing General Partner of the Registrant
	(Principal executive officer)

/s/ Gysle R. Shellum	Chief Financial Officer	May 14, 2010
Gysle R. Shellum	Petroleum Development Corporation
	Managing General Partner of the Registrant
	(Principal financial officer)

/s/ R. Scott Meyers	Chief Accounting Officer	May 14, 2010
R. Scott Meyers	Petroleum Development Corporation
	Managing General Partner of the Registrant
	(Principal accounting officer)

- 22 -

PDC 2005-B Limited Partnership 10-Q