UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

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

~~For~~OF ~~the quarterly period ended March 31, 2011~~1934

For the quarterly period ended June 30, 2011

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

OF 1934 FOR THE TRANSITION PERIOD ____________ TO ____________

Commission File Number 000-50616

PDC 2003-B Limited Partnership

(Exact name of registrant as specified in its charter)



	West Virginia		55-0825013
	(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 reports) and (2) has been subject to such filing requirements for the past 90 days.

Yes þ R No ¨ £

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 ¨R No ¨£

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

Large accelerated filer ¨£ Accelerated filer ¨£ Non-accelerated filer ¨£ Smaller reporting company þR

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

As of ~~March 31~~June 30, 2011 the Partnership had 867.33 units of limited partnership interest and no units of additional general partnership interest outstanding.

PDC 2003-B ~~LIMITED~~Limited ~~PARTNERSHIP~~Partnership

(A West Virginia Limited Partnership)

INDEX TO REPORT ON FORM 10-Q

			Page
PART I – FINANCIAL INFORMATION
PART I – FINANCIAL INFORMATION
		Page
	Special Note Regarding Forward-Looking Statements	~~Special Note Regarding Forward-Looking Statements~~1	1
Item 1.	Financial Statements (unaudited)	~~Financial Statements (unaudited)~~
	Condensed Balance Sheets (unaudited)	~~Condensed Balance Sheets (unaudited)~~2	3
	Condensed Statements of Operations (unaudited)	~~Condensed Statements of Operations (unaudited)~~3	4
	Condensed Statements of Cash Flows (unaudited)	~~Condensed Statements of Cash Flows (unaudited)~~4	5
	Notes to Unaudited Condensed Financial Statements	~~Notes to Unaudited Condensed Financial Statements~~5	6
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~~24	21
Item 4.	Controls and Procedures	~~Controls and Procedures~~24	21
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	~~Legal Proceedings~~25	23
Item 1A.	Risk Factors	~~Risk Factors~~25	23
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	~~Unregistered Sales of Equity Securities and Use of Proceeds~~25	23
Item 3.	Defaults Upon Senior Securities	~~Defaults Upon Senior Securities~~25	23
Item 4.	[Removed and Reserved]	~~[Removed and Reserved]~~25	23
Item 5.	Other Information	~~Other Information~~25	23
Item 6.	Exhibits	~~Exhibits Index~~26	24
	SIGNATURES	~~SIGNATURES~~27	25

Index

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This periodic report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”) regarding PDC 2003-AB Limited Partnership’'s (“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 incorporated by reference into this report are “forward-looking statements” within the meaning of the safe harbor provisions of the United States Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein,. These ~~which include~~ statements of include: estimated natural gas, natural gas liquid(s) or “NGL(s)”, and crude oil production and reserves, ; drilling plans,; future cash flows, and anticipated liquidity,; anticipated capital expenditures; ~~and~~the adequacy of the Managing General Partner’'s ~~strategies,~~casualty ~~plans~~insurance ~~and~~coverage; ~~objectives. However, these are not~~ the ~~exclusive~~effectiveness ~~means~~ of ~~identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect~~ the Managing General Partner's ~~good~~derivative ~~faith~~policies ~~judgment,~~in ~~such~~achieving ~~statements~~the ~~can~~Partnership's ~~only~~risk bemanagement ~~based~~objectives; ~~on facts~~ and ~~factors currently known to~~ the Managing General Partner~~. Consequently,~~'s ~~forward-looking statements are inherently subject to risks and uncertainties~~strategies, ~~including~~plans ~~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 statementsobjectives. ~~Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:~~

·The ~~changes~~above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect the Managing General Partner's good faith judgment, such statements can only be based on facts and factors currently known to the Managing General Partner. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including known and unknown risks and uncertainties incidental to the development, production ~~volumes~~and marketing of natural gas, NGLs and ~~worldwide~~crude ~~demand;~~oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements.

·Important ~~volatility~~factors ofthat ~~commodity~~could ~~prices~~cause ~~for~~actual ~~natural~~results ~~gas~~to ~~and~~differ ~~crude~~materially ~~oil;~~from the forward-looking statements include, but are not limited to:

·• changes in ~~estimates~~production ofvolumes ~~proved~~and ~~reserves~~worldwide demand;

·• ~~inaccuracy~~volatility of ~~reserve~~commodity ~~estimates~~prices ~~and~~for ~~expected~~natural ~~production~~gas, ~~rates~~NGLs and crude oil;

·• ~~declines~~changes in ~~the~~estimates ~~value~~ of ~~the~~proved ~~Partnership’s natural gas and crude oil properties resulting in impairments~~reserves;

·• ~~the~~inaccuracy ~~availability~~ of ~~Partnership~~reserve ~~future~~estimates ~~cash~~and ~~flows~~expected ~~for~~production ~~investor distributions or funding of refracturing activities~~rates;

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

·• the ~~Managing~~availability ~~General~~of ~~Partner’s~~Partnership ~~ability~~future tocash ~~acquire~~flows ~~drilling~~for ~~rig~~investor ~~services,~~distributions ~~supplies~~or ~~and~~funding ~~services~~of atrefracturing ~~reasonable prices~~activities;

·• ~~risks incidental to~~ the ~~refracturing~~timing and ~~operation~~extent of ~~natural~~the ~~gas~~Partnership's success in further developing and ~~crude~~producing ~~oil~~the ~~wells~~Partnership's reserves;

·• the ~~availability~~Managing ofGeneral ~~sufficient~~Partner's ~~pipeline~~ability ~~and~~to ~~other~~acquire ~~transportation~~drilling ~~facilities~~rig toservices, ~~carry~~supplies ~~Partnership production~~ and ~~the~~services ~~impact~~at ofreasonable ~~these facilities on price~~prices;

·• ~~the~~risks ~~effect~~incidental ofto ~~existing and future laws, governmental regulations and~~ the ~~political~~refracturing and ~~economic~~operation ~~climate~~ of ~~the~~natural ~~U.S.~~gas asand ~~well~~crude ~~as other~~ oil ~~producing countries throughout the world~~wells;

·• ~~changes~~the inavailability ~~environmental~~of ~~laws,~~sufficient ~~the~~pipeline ~~regulation~~ and ~~enforcement~~other oftransportation ~~those~~facilities ~~laws~~to carry Partnership production and the ~~costs~~impact toof ~~comply~~these ~~with~~facilities ~~those~~on ~~laws~~price;

·• ~~the~~changes ~~impact~~in of environmental ~~events~~laws, ~~governmental responses to~~ the ~~events~~regulation and ~~the~~enforcement ~~Managing~~of ~~General~~those ~~Partner’s~~laws ~~ability~~and ~~insure~~the ~~adequately~~costs ~~against~~to ~~such~~comply ~~events~~with those laws;

·• ~~competition~~the inimpact of environmental events, governmental responses to the ~~oil~~events and ~~gas~~the ~~industry~~Managing General Partner's ability to insure adequately against such events;

·• the ~~success~~timing ofand ~~the~~receipt ~~Managing~~of ~~General~~necessary ~~Partner~~regulatory ~~in marketing the Partnership’s oil and gas~~permits;

·• ~~the~~competition ~~effect~~in ofthe ~~natural~~oil ~~gas~~ and ~~crude~~gas ~~oil derivative 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~~natural ofgas, ~~the~~NGLs ~~2005 partnerships~~ and ~~the~~crude ~~timing of consummating these mergers, if at all~~oil;

·• ~~losses~~the ~~possible~~effect ~~from~~of ~~pending~~natural orgas ~~future~~and ~~litigation;~~crude ~~and~~oil derivative activities;

·• the ~~success~~cost of ~~strategic~~pending ~~plans,~~or ~~expectations and objectives for~~ future ~~operations of the Managing General Partner.~~litigation;

-• 1the -Managing General Partner's ability to retain or attract senior management and key technical employees; and

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

~~PDC~~Further, ~~2003~~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-BK ~~LIMITED~~for ~~PARTNERSHIP~~the year ended December 31, 2010 filed with the United States 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.

~~(A West Virginia Limited Partnership)~~-1-

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 2003-B Limited Partnership
Condensed Balance Sheets
(unaudited)
	March 31,			December 31,
	2011				2010*
Assets
Current assets:
Cash and cash equivalents	$	152,149		$	57,127
Accounts receivable		92,414			127,657
Crude oil inventory		27,752			21,075
Due from Managing General Partner-derivatives		287,048			274,292
Total current assets		559,363			480,151
Natural gas and crude oil properties, successful efforts method, at cost		14,135,344			14,134,724
Less: Accumulated depreciation, depletion and amortization		(8,631,872	)		(8,488,523	)
Natural gas and crude oil properties, net		5,503,472			5,646,201
Due from Managing General Partner-derivatives		368,267			430,200
Other assets		52,158			49,227
Total noncurrent assets		5,923,897			6,125,628
Total Assets	$	6,483,260		$	6,605,779
Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	77,741		$	93,665
Due to Managing General Partner-derivatives		287,209			240,522
Due to Managing General Partner-other, net		192,601			157,809
Total current liabilities		557,551			491,996
Due to Managing General Partner-derivatives		289,326			325,668
Asset retirement obligations		233,263			229,847
Total liabilities		1,080,140			1,047,511
Commitments and contingent liabilities
Partners' equity:
Managing General Partner		1,083,321			1,114,350
Limited Partners - 867.33 units issued and outstanding		4,319,799			4,443,918
Total Partners' equity		5,403,120			5,558,268
Total Liabilities and Partners' Equity	$	6,483,260		$	6,605,779

PDC 2003-B Limited Partnership

~~___________________________________________~~Condensed Balance Sheets

(unaudited)



	June 30, 2011			December 31, 2010*
Assets

Current assets:
Cash and cash equivalents	$	192,206		$	57,127
Accounts receivable	103,474			127,657
Crude oil inventory	28,293			21,075
Due from Managing General Partner-derivatives	294,482			274,292
Total current assets	618,455			480,151

Natural gas and crude oil properties, successful efforts method, at cost	14,136,864			14,134,724
Less: Accumulated depreciation, depletion and amortization	(8,799,412		)	(8,488,523		)
Natural gas and crude oil properties, net	5,337,452			5,646,201

Due from Managing General Partner-derivatives	344,865			430,200
Other assets	55,219			49,227
Total noncurrent assets	5,737,536			6,125,628

Total Assets	$	6,355,991		$	6,605,779

Liabilities and Partners' Equity

Current liabilities:
Accounts payable and accrued expenses	$	146,613		$	93,665
Due to Managing General Partner-derivatives	241,647			240,522
Due to Managing General Partner-other, net	115,725			157,809
Total current liabilities	503,985			491,996

Due to Managing General Partner-derivatives	248,130			325,668
Asset retirement obligations	236,730			229,847
Total liabilities	988,845			1,047,511

Commitments and contingent liabilities

Partners' equity:
Managing General Partner	1,076,126			1,114,350
Limited Partners - 867.33 units issued and outstanding	4,291,020			4,443,918
Total Partners' equity	5,367,146			5,558,268

Total Liabilities and Partners' Equity	$	6,355,991		$	6,605,779

*Derived from audited 2010 balance sheet

See accompanying notes to unaudited condensed financial statements.

- 3 2-

~~Index~~PDC 2003-B Limited Partnership

PDC 2003-B Limited Partnership
Condensed Statements of Operations
(unaudited)
	Three months ended March 31,
	2011			2010
Revenues:
Natural gas, NGLs and crude oil sales	$	249,752		$	366,034
Commodity price risk management (loss) gain, net		(45,782	)		367,050
Total revenues		203,970			733,084
Operating costs and expenses:
Natural gas, NGLs and crude oil production costs		92,666			99,246
Direct costs - general and administrative		48,059			72,565
Depreciation, depletion and amortization		143,349			172,624
Accretion of asset retirement obligations		3,416			3,219
Total operating costs and expenses		287,490			347,654
(Loss) income from operations		(83,520	)		385,430
Interest income		21			7
Net (loss) income	$	(83,499	)	$	385,437
Net (loss) income allocated to partners	$	(83,499	)	$	385,437
Less: Managing General Partner interest in net (loss) income		(16,700	)		77,087
Net (loss) income allocated to Investor Partners	$	(66,799	)	$	308,350
Net (loss) income per Investor Partner unit	$	(77	)	$	356
Investor Partner units outstanding		867.33			867.33

Condensed Statements of Operations

(unaudited)



	Three months ended June 30,					Six months ended June 30,
	2011		2010			2011			2010
Revenues:
Natural gas, NGLs and crude oil sales	$	312,538	$	240,446		$	562,290		$	606,480
Commodity price risk management gain, net	77,947		130,362			32,165			497,412
Total revenues	390,485		370,808			594,455			1,103,892

Operating costs and expenses:
Natural gas, NGLs and crude oil production costs	176,739		162,570			269,405			261,816
Direct costs - general and administrative	39,880		218,659			87,939			291,224
Depreciation, depletion and amortization	167,540		139,630			310,889			312,254
Accretion of asset retirement obligations	3,467		3,266			6,883			6,485
Total operating costs and expenses	387,626		524,125			675,116			871,779

Income (loss) from operations	2,859		(153,317		)	(80,661		)	232,113

Interest income	57		7			78			14

Net income (loss)	$	2,916	$	(153,310	)	$	(80,583	)	$	232,127

Net income (loss) allocated to partners	$	2,916	$	(153,310	)	$	(80,583	)	$	232,127
Less: Managing General Partner interest in net income (loss)	583		(30,662		)	(16,117		)	46,425
Net income (loss) allocated to Investor Partners	$	2,333	$	(122,648	)	$	(64,466	)	$	185,702

Net income (loss) per Investor Partner unit	$	3	$	(141	)	$	(74	)	$	214

Investor Partner units outstanding	867.33		867.33			867.33			867.33

See accompanying notes to unaudited condensed financial statements.

- 4 3-

~~Index~~PDC 2003-B Limited Partnership

PDC 2003-B Limited Partnership
Condensed Statements of Cash Flows
(unaudited)
	Three months ended March 31,
	2011			2010
Cash flows from operating activities:
Net (loss) income	$	(83,499	)	$	385,437
Adjustments to net (loss) income to reconcile to net cash provided by operating activities:
Depreciation, depletion and amortization		143,349			172,624
Accretion of asset retirement obligations		3,416			3,219
Unrealized loss (gain) on derivative transactions		59,522			(210,000	)
Changes in operating assets and liabilities:
Decrease in accounts receivable		35,243			29,096
(Increase) decrease in crude oil inventory		(6,677	)		2,014
Increase in other assets		(2,931	)		(3,342	)
(Decrease) increase in accounts payable and accrued expenses		(15,924	)		100
Increase (decrease) in Due to Managing General Partner - other, net		34,792			(97,720	)
Net cash provided by operating activities		167,291			281,428
Cash flows from investing activities:
Capital expenditures for natural gas and crude oil properties		(620	)		(740	)
Net cash used in investing activities		(620	)		(740	)
Cash flows from financing activities:
Distributions to Partners		(71,649	)		(280,681	)
Net cash used in financing activities		(71,649	)		(280,681	)
Net increase in cash and cash equivalents		95,022			7
Cash and cash equivalents, beginning of period		57,127			57,505
Cash and cash equivalents, end of period	$	152,149		$	57,512

Condensed Statements of Cash Flows

~~See accompanying notes to~~ (unaudited ~~condensed financial statements~~)

- 5 -



	Six months ended June 30,
	2011			2010
Cash flows from operating activities:
Net income (loss)	$	(80,583	)	$	232,127
Adjustments to net income (loss) to reconcile to net cash provided by operating activities:
Depreciation, depletion and amortization	310,889			312,254
Accretion of asset retirement obligations	6,883			6,485
Unrealized gain on derivative transactions	(11,268		)	(314,841		)
Changes in operating assets and liabilities:
Decrease in accounts receivable	24,183			77,904
Increase in crude oil inventory	(7,218		)	(2,156		)
Increase in other assets	(5,992		)	(6,584		)
Increase in accounts payable and accrued expenses	52,948			44,995
Increase (decrease) in Due to Managing General Partner - other, net	(42,084		)	133,788
Net cash provided by operating activities	247,758			483,972

Cash flows from investing activities:
Capital expenditures for natural gas and crude oil properties	(2,140		)	(772		)
Net cash used in investing activities	(2,140		)	(772		)

Cash flows from financing activities:
Distributions to Partners	(110,539		)	(483,186		)
Net cash used in financing activities	(110,539		)	(483,186		)

Net increase in cash and cash equivalents	135,079			14
Cash and cash equivalents, beginning of period	57,127			57,505
Cash and cash equivalents, end of period	192,206			57,519

~~Index~~See accompanying notes to unaudited condensed financial statements.

-4-

PDC 2003-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 2011

(unaudited)

Note 1−General and Basis of Presentation

PDC 2003-B Limited Partnership (the “Partnership” or the “Registrant”) was organized as a limited partnership, in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of natural gas and crude oil properties. Business operations of the Partnership commenced upon closing of an offering for the sale of Partnership units. Upon funding, the Partnership 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 name PDC Energy, to conduct and manage the Partnership’'s business. In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), the Managing General Partner is authorized to manage all activities of the Partnership and initiates and completes substantially all Partnership transactions.

As of ~~March 31~~June 30, 2011, there were ~~771~~769 Investor Partners. PDC is the designated Managing General Partner of the Partnership and owns a 20% Managing General Partner ownership in the Partnership. According to the terms of the ~~Limited Partnership~~ Agreement, revenues, costs and cash distributions of the Partnership are allocated 80% to the limited partners (“Investor Partners”), which are shared pro rata, based upon the number of units in the Partnership, and 20% to the Managing General Partner. The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual Investor Partner. Through ~~March 31~~June 30, 2011, the Managing General Partner has repurchased 51.47 units of Partnership interests from the Investor Partners at an average price of $5,~~692~~673 per unit. As of ~~March 31~~June 30, 2011, the Managing General Partner owns 24.78% of the Partnership.

The Partnership expects continuing operations of its natural gas and crude oil properties until such time the Partnership’'s wells are depleted or become uneconomical to produce, at which time they may be sold or plugged, reclaimed and abandoned. The Partnership’'s maximum term of existence extends through December 31, 2050, 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 statement of the Partnership’'s financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities and Exchange Commission (“SEC”). Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in the audited financial statements have been condensed or omitted. The information presented in this quarterly report on Form 10-Q should be read in conjunction with the Partnership’'s audited financial statements and notes thereto included in the Partnership’'s 2010 Form 10-K. The Partnership’'s accounting policies are described in the Notes to Financial Statements in the Partnership’'s 2010 Form 10-K and updated, as necessary, in this Form 10-Q. The results of operations for the three and six months ended ~~March 31~~June 30, 2011, and the cash flows for the same ~~period~~periods, are not necessarily indicative of the results to be expected for the full year or any other future period.

Certain reclassifications have been made to correct the prior period disclosures to conform to the current year presentation, specifically related to the fair value level classification of certain derivative instruments. The reclassification had no impact on the Partnership's previously reported financial position, cash flows, net income or partners' equity. See Note 4, Fair Value Measurements and Disclosures, for additional information regarding the fair value classification of the Partnership's natural gas and crude oil derivative instruments.

On June 20, 2011, the Partnership, PDC and its wholly-owned subsidiary, DP 2004 Merger Sub, LLC (“DP Merger Sub”), a Delaware limited liability company, entered into an agreement and plan of merger (the “Merger Agreement”), in which PDC seeks to acquire the Partnership, subject to the vote and approval of a majority of the limited partnership units held, by Investor Partners of the Partnership, other than PDC and its affiliates (“non-affiliated investor partners”). Pending the outcome of the proposed Merger Agreement, the Managing General Partner suspended, as of April 7, 2011, the opportunity for an individual non-affiliated investor partner to request that PDC repurchase their respective limited partnership units. For more information on the proposed Merger Agreement, see Note 3, Transactions with Managing General Partner and Affiliates−Proposed Merger with PDC and DP 2004 Merger Sub, LLC, which follows.

-5-

PDC 2003-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2011

(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 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. These changes were 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 adoption of this change did not have a material impact on the Partnership’'s financial statements.

-Recently 6Issued -Accounting Standards

~~Index~~Fair Value Measurement

On May 12, 2011, the FASB issued changes related to fair value measurement. The changes represent the converged guidance of the FASB and the International Accounting Standards Board ("IASB") (collectively the "Boards") on fair value measurement. Many of the changes eliminate unnecessary wording differences between International Financial Reporting Standards ("IFRS") and U.S. GAAP. The changes expand existing disclosure requirements for fair value measurements categorized in Level 3 by requiring (1) a quantitative disclosure of the unobservable inputs and assumptions used in the measurement, (2) a description of the valuation processes in place and (3) a narrative description of the sensitivity of the fair value to changes in unobservable inputs and the interrelationships between those inputs. In addition, the changes also require the categorization by level in the fair value hierarchy of items that are not measured at fair value in the statement of financial position whose fair value must be disclosed. These changes are to be applied prospectively and are effective for public entities during interim and annual periods beginning after December 15, 2011. Early application is not permitted. With the exception of the disclosure requirements, the adoption of these changes is not expected to have a significant impact on the Partnership's financial statements.

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 condensed balance sheets under the captions “Due from Managing General Partner-derivatives,” in the case of net unrealized gains or “Due to Managing General Partner-derivatives,” in the case of net unrealized losses.

The following table presents transactions with the Managing General Partner reflected in the condensed 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.



	June 30, 2011			December 31, 2010
Natural gas, NGLs and crude oil sales revenues collected from the Partnership's third-party customers	$	65,570		$	83,273
Commodity price risk management, realized gain	6,694			39,716
Other ⁽¹⁾	(187,989		)	(280,798		)
Total Due to Managing General Partner-other, net	$	(115,725	)	$	(157,809	)


(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.

-6-

PDC 2003-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 2011

(unaudited)

The following table presents Partnership transactions, excluding derivative transactions which are more fully detailed in Note ~~3−Transactions~~5, Derivative Financial Instruments, with the Managing General Partner and ~~Affiliates~~its affiliates for the three and six months ended June 30, 2011 and 2010. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Natural gas, NGLs and crude oil production costs” line item on the condensed statements of operations.

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



	Three months ended June 30,				Six months ended June 30,
	2011		2010		2011		2010
Well operations and maintenance	$	154,310	$	142,383	$	227,321	$	228,407
Gathering, compression and processing fees	7,418		7,963		14,910		17,276
Direct costs - general and administrative	39,880		218,659		87,939		291,224
Cash distributions ⁽¹⁾	9,632		46,405		27,343		110,665

~~The~~(1) ~~following~~Cash ~~table~~distributions ~~presents~~include ~~transactions~~$1,854 ~~with~~and $5,236 during the ~~Managing~~three ~~General~~and ~~Partner~~six ~~reflected~~months inended ~~the~~June ~~condensed~~30, ~~balance~~2011, ~~sheet~~respectively ~~line~~and ~~item~~$5,904 –and ~~“Due~~$14,027 ~~from~~during ~~(to)~~the ~~Managing~~three ~~General~~and ~~Partner-other~~six months ended June 30, ~~net~~2010,” ~~which~~respectively, ~~remain~~related ~~undistributed~~to orequity ~~unsettled~~cash ~~with~~distributions ~~the~~on ~~Partnership’s~~Investor ~~investors~~Partner asunits ofrepurchased ~~the~~by ~~dates indicated~~PDC.

	March 31,			December 31,
	2011			2010
Natural gas, NGLs and crude oil sales revenues collected from the Partnership's third-party customers	$	80,629		$	83,273
Commodity price risk management, realized gain		7,374			39,716
Other (1)		(280,604	)		(280,798	)
Total Due to Managing General Partner-other, net	$	(192,601	)	$	(157,809	)

Proposed Merger with PDC and DP 2004 Merger Sub, LLC

~~(1)~~On ~~All~~June ~~other~~20, ~~unsettled~~2011, ~~transactions~~the Partnership, ~~excluding~~PDC ~~derivative~~and ~~instruments~~DP Merger Sub entered into the Merger Agreement, ~~between~~in which PDC seeks to acquire the Partnership, subject to the vote and approval of a majority of the ~~Managing~~limited ~~General~~partnership ~~Partner~~units held by non-affiliated investor partners. Pursuant ~~The~~to the Merger Agreement, if the merger is approved by the holders of a majority of ~~these~~the ~~are~~limited ~~operating~~partnership ~~costsor~~units ~~general~~held by the non-affiliated investor partners of the Partnership, as well as, the satisfaction of other customary closing conditions, then the Partnership will merge with and ~~administrative~~into ~~costs~~DP ~~which~~Merger Sub, the separate existence of the Partnership will terminate and the non-affiliated investor partners will have ~~not~~the ~~been~~right ~~deducted~~to receive cash payments in the aggregate amount of $6,414,114 or $7,864 per limited partnership unit, subject to any adjustments made to the merger consideration for certain increases in commodity prices between the date of signing the merger agreement and the filing of the definitive proxy statement, plus the sum of the amounts withheld, if any, from per unit cash distributions by the Partnership from October 1, 2010 through August 31, 2011 for the Partnership's Well Refracturing Plan, less the sum of the per unit cash distributions made after August 31, 2011 and before the transaction closes. DP Merger Sub shall be the surviving entity of the merger and shall be wholly-owned by PDC, and the limited partners will have no continuing interest in the Partnership, since the Partnership will cease as a separate business entity. The merger will become effective following the filing of a certificate of merger with the Secretaries of State of West Virginia and Delaware as soon as practicable after the last condition precedent to the merger has been satisfied, or waived. Following consummation of the merger, the non-affiliated investor partners will no longer participate in the Partnership's future earnings or any further economic benefit.

The ~~following~~Merger ~~table~~Agreement ~~presents~~has ~~Partnership~~been ~~transactions,~~approved ~~excluding~~by ~~derivative~~PDC's ~~transactions~~Board ~~which~~of ~~are~~Directors ~~more~~(the ~~fully~~“Board”); ~~detailed in Note 5~~PDC, ~~Derivative~~as ~~Financial~~sole ~~Instruments,~~member ~~with~~of the ~~Managing~~DP ~~General~~Merger ~~Partner~~Sub; and ~~its~~by ~~affiliates~~the ~~for~~Special Committee formed by the ~~three~~Board, ~~months~~comprised ~~ended~~of ~~March~~four ~~31,~~directors ~~2011~~of ~~and~~PDC ~~2010. “Well~~who ~~operations~~are ~~and~~not ~~maintenance”~~officers ~~and~~or ~~“Gathering,~~employees ~~compression~~of the Partnership or PDC and ~~processing~~have ~~fees”~~no ~~are~~economic ~~included~~interest in the ~~“Natural gas~~Partnership, ~~NGLs~~to ~~and~~represent ~~crude~~the ~~oil~~interests ~~production~~of ~~costs”~~the ~~line~~non-affiliated ~~item~~investor onpartners ~~the~~holding ~~condensed~~limited ~~statements~~partnership ~~of operations~~units.

	Three months ended March 31,
	2011		2010
Well operations and maintenance	$	73,011	$	86,024
Gathering, compression and processing fees		7,492		9,313
Direct costs - general and administrative		48,059		72,565
Cash distributions (1)		17,711		64,260

-7-

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

- 7 -

Index

PDC 2003-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 2011

(unaudited)

~~Note~~The ~~4−Fair~~Merger ~~Value~~Agreement ofamong ~~Financial~~the ~~Instruments~~Partnership, PDC and its subsidiary DP Merger Sub, may be terminated, and the merger abandoned:

~~The~~• ~~following~~should ~~table~~all ~~presents,~~parties ~~for~~agree ~~each~~by ~~hierarchy~~mutual ~~level,~~consent ~~the~~to ~~Partnership’s~~terminate ~~derivative~~the ~~assets~~Merger ~~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.~~Agreement;

	March 31, 2011								December 31, 2010
	Quoted Prices in Active Markets		Significant Unobservable Inputs						Quoted Prices in Active Markets		Significant Unobservable Inputs
	Level 1		Level 3			Total			Level 1		Level 3			Total
Assets:
Commodity based derivatives	$	647,641	$	7,674		$	655,315		$	676,975	$	27,517		$	704,492
Total assets		647,641		7,674			655,315			676,975		27,517			704,492
Liabilities:
Commodity based derivatives		-		(88,917	)		(88,917	)		-		(71,891	)		(71,891	)
Basis protection derivative contracts		-		(487,618	)		(487,618	)		-		(494,299	)		(494,299	)
Total liabilities		-		(576,535	)		(576,535	)		-		(566,190	)		(566,190	)
Net asset (liability)	$	647,641	$	(568,861	)	$	78,780		$	676,975	$	(538,673	)	$	138,302


•	by any party thereto, should the proposed merger not occur by December 15, 2011;

~~The~~• ~~following~~by ~~table~~any ~~presents~~party athereto, ~~reconciliation~~should consummation of the ~~Partnership’s~~merger ~~Level~~become 3illegal ~~fair~~or ~~value~~be ~~measurements.~~otherwise prohibited by law or regulation;

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


•	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;

~~See~~• ~~Note~~by 5the Special Committee, ~~Derivative~~on ~~Financial~~behalf ~~Instruments~~of the Partnership and prior to approval by non-affiliated investor partners, ~~for~~should ~~additional~~the ~~disclosure~~Special ~~related~~Committee believe it has received a superior offer that is more favorable to the ~~Partnership’s~~non-affiliated ~~derivative~~investor ~~financial~~partners; ~~instruments.~~or

~~Non-Derivative~~• ~~Financial~~by ~~Assets~~PDC ~~and~~or ~~Liabilities. The~~the ~~carrying~~Partnership, ~~values~~should ofeither PDC or the ~~financial~~Partnership ~~instruments~~fail ~~comprising~~to ~~current~~perform ~~assets~~its obligations under the Merger Agreement and ~~current~~such ~~liabilities~~failure ~~approximate~~has ~~fair~~a ~~value~~non-curable ~~due~~material toadverse effect on PDC or the ~~short-term~~Partnership, ~~maturities~~respectively, ofor ~~these~~materially ~~instruments~~and adversely affects the transactions contemplated by the Merger Agreement.

On June 23, 2011, the Partnership filed a preliminary proxy statement on Schedule 14A relating to the merger with the SEC. Although there is no assurance of the likelihood or timing of the merger transaction, upon clearance by the SEC, a definitive proxy statement will be mailed to the Partnership’s limited partners. Closing of the merger is conditioned on approval by a majority vote of non-affiliated 8investor partners 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, as described above. If approved by a majority vote of non-affiliated investor partners and after the filing of a certificate of merger with the Secretaries of State of West Virginia and Delaware, no additional filing or registration with, notification to, or authorization, consent or approval of, any governmental entity will be required in connection with the execution and delivery of the Merger Agreement by the Partnership, PDC or DP Merger Sub or the consummation by the Partnership, PDC or DP Merger Sub of the transactions contemplated thereby. Following consummation of the merger, the non-affiliated investor partners will no longer participate in the Partnership’s future earnings or any further economic benefit.

~~Index~~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.

Note 4−Fair Value Measurements and Disclosures

Derivative Financial Instruments

Determination of fair value. Fair value accounting standards have established a fair value hierarchy that prioritizes the inputs used in applying a valuation methodology. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:

Level 1 - Quoted prices (unadjusted) in active markets for identical assets or liabilities.

Level 2 - Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability and (iv) inputs that are derived from observable market data by correlation or other means.

Level 3 - Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.

-8-

PDC 2003-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 2011

(unaudited)

Derivative Financial Instruments. The Partnership measures the fair value of its derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of the Managing General Partner's credit standing on the fair value of derivative liabilities and the effect of the Managing General Partner's counterparties' credit standings on the fair value of derivative assets, both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. The counterparties to the Partnership's derivative instruments are primarily financial institutions. The Managing General Partner validates the fair value measurement through (1) the review of counterparty statements and other supporting documentation, (2) the determination that the source of the inputs are valid, (3) the 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. While the Managing General Partner uses common industry practices to develop its valuation techniques, changes in the pricing methodologies or the underlying assumptions could result in significantly different fair values. While the Managing General Partner believes its valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

The following table presents, for each hierarchy level, the Partnership's derivative assets and liabilities, both current and non-current portions, measured at fair value on a recurring basis.



	June 30, 2011								December 31, 2010 (a)
	Level 2 (b)			Level 3 (c)		Total			Level 2 (b)			Level 3 (c)		Total

Assets:
Commodity based derivatives	$	630,801		$	8,546	$	639,347		$	676,975		$	27,517	$	704,492
Total assets	630,801			8,546		639,347			676,975			27,517		704,492

Liabilities:
Commodity based derivatives	(42,114		)	—		(42,114		)	(71,891		)	—		(71,891		)
Basis protection derivative contracts	(447,663		)	—		(447,663		)	(494,299		)	—		(494,299		)
Total liabilities	(489,777		)	—		(489,777		)	(566,190		)	—		(566,190		)
Net asset	$	141,024		$	8,546	$	149,570		$	110,785		$	27,517	$	138,302

(a) The Partnership reclassified its NYMEX-based natural gas fixed-price swaps from Level 1 to Level 2 (decreasing the previously reported net asset in Level 1 by approximately $677,000)and CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 (decreasing the previously reported net liability in Level 3 by approximately $566,000). The amounts presented reflect these reclassifications and conform to current period presentation.

(b) Includes the Partnership's fixed-price swaps and basis swaps.

-9-

PDC 2003-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2011

(unaudited)

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



	Six months ended
	June 30, 2011			June 30, 2010 (1)
Fair value, net asset, beginning of period	$	27,517		$	60,300
Changes in fair value included in statement of operations line item:
Commodity price risk management, net	(42,200		)	(93,632		)
Settlements	23,229			60,915
Fair value, net asset, end of period	$	8,546		$	27,583

Change in unrealized gain (loss) relating to assets (liabilities) still held as of
June 30, 2011 and 2010, respectively, included in statement of operations line item:
Commodity price risk management, net	$	869		$	22,222

(1) The Partnership reclassified its CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 (decreasing the previously reported net liability at the beginning of the period by approximately $494,000). The amounts presented reflect these reclassifications and conform to current period presentation.

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.

Note 5−Derivative Financial Instruments

As of ~~March 31~~June 30, 2011, the Partnership had derivative instruments in place for a portion of its anticipated production through 2013 for a total of ~~345~~ 310,~~925~~533 MMbtu of natural gas and 21,~~476~~671 ~~Bbls~~Bbl of crude oil.

The following table presents the location and fair value amounts of the Partnership’s derivative instruments on the accompanying condensed balance sheets. These derivative instruments were comprised of commodity collars, commodity fixed-~~price swaps and basis swaps.~~10-

			Fair Value
		Balance Sheet	March 31,		December 31,
Derivative instruments not designated as hedge (1):		Line Item	2011		2010
Derivative Assets:	Current
	Commodity contracts	Due from Managing General Partner-derivatives	$	287,048	$	274,292
	Non Current
	Commodity contracts	Due from Managing General Partner-derivatives		368,267		430,200
Total Derivative Assets			$	655,315	$	704,492
Derivative Liabilities:	Current
	Commodity contracts	Due to Managing General Partner-derivatives	$	88,917	$	71,891
	Basis protection contracts	Due to Managing General Partner-derivatives		198,292		168,631
	Non Current
	Commodity contracts	Due to Managing General Partner-derivatives		-		-
	Basis protection contracts	Due to Managing General Partner-derivatives		289,326		325,668
Total Derivative Liabilities			$	576,535	$	566,190

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

The following table presents the impact of the Partnership’s derivative instruments on the Partnership’s accompanying condensed statements of operations.

	Three months ended March 31,
	2011									2010
Statement of operations line item	Reclassification of Realized Loss (Gain) Included in Prior Periods Unrealized			Realized and Unrealized Gain (Loss) For the Current Period			Total			Reclassification of Realized Loss (Gain) Included in Prior Periods Unrealized			Realized and Unrealized Gain For the Current Period		Total
Commodity price risk management, net
Realized gain	$	10,762		$	2,978		$	13,740		$	145,222		$	11,828	$	157,050
Unrealized (loss) gain		(10,762	)		(48,760	)		(59,522	)		(145,222	)		355,222		210,000
Total commodity price risk management (loss) gain, net	$	-		$	(45,782	)	$	(45,782	)	$	-		$	367,050	$	367,050

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

- 9 -

Index

PDC 2003-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 2011

(unaudited)

The following table presents the location and fair value amounts of the Partnership's derivative instruments on the accompanying condensed balance sheets. These derivative instruments were comprised of commodity collars, commodity fixed-price swaps and basis swaps.



			Fair Value
			June 30,		December 31,
Derivative instruments not designated as hedge⁽¹⁾:		Balance Sheet Line Item	2011		2010
Derivative Assets:	Current
	Commodity contracts	Due from Managing General Partner-derivatives	$	294,482	$	274,292
	Non Current
	Commodity contracts	Due from Managing General Partner-derivatives	344,865		430,200
Total Derivative Assets			$	639,347	$	704,492

Derivative Liabilities:	Current
	Commodity contracts	Due to Managing General Partner-derivatives	$	42,114	$	71,891
	Basis protection contracts	Due to Managing General Partner-derivatives	199,533		168,631
	Non Current
	Basis protection contracts	Due to Managing General Partner-derivatives	248,130		325,668
Total Derivative Liabilities			$	489,777	$	566,190

⁽¹⁾As of June 30, 2011 and December 31, 2010, none of the Partnership's derivative instruments were designated as hedges.

The following tables presents the impact of the Partnership's derivative instruments on the Partnership's accompanying condensed statements of operations.



	Three months ended June 30,
	2011								2010
Statement of operations line item:	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period			Total		Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total
Commodity price risk management gain, net
Realized gains	$	5,828		$	1,329		$	7,157	$	18,070		$	7,451	$	25,521
Unrealized gains (losses)	(5,828		)	76,618			70,790		(18,070		)	122,911		104,841
Total commodity price risk management gain, net	$	—		$	77,947		$	77,947	$	—		$	130,362	$	130,362

	Six months ended June 30,
	2011								2010
Statement of operations line item:	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains (Losses) For the Current Period			Total		Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total
Commodity price risk management gain, net
Realized gains (losses)	$	26,982		$	(6,085	)	$	20,897	$	106,540		$	76,031	$	182,571
Unrealized gains (losses)	(26,982		)	38,250			11,268		(106,540		)	421,381		314,841
Total commodity price risk management gain, net	$	—		$	32,165		$	32,165	$	—		$	497,412	$	497,412

-11-

PDC 2003-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2011

(unaudited)

Concentration of Credit Risk. 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.

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 industry, the Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures in place to avoid environmental contamination and mitigate the risks from environmental contamination. The Managing General Partner conducts periodic reviews to identify changes in the Partnership’'s environmental risk profile. Liabilities are accrued when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. During the ~~three~~six months ended ~~March~~June 3130, 2011, ~~there~~one ~~were no~~ new environmental remediation ~~projects~~project was identified by the Managing General Partner ~~related~~the tofor Partnership in which approximately $79,000 of expense was recognized in the ~~Partnership~~line item captioned "Natural gas, NGLs and crude oil production costs" in the condensed Statements of Operations. As of ~~March~~June 3130, 2011 the Partnership had accrued environmental liabilities for four wells in the amount of approximately $138,000, which is included in the line item captioned "Accounts payable and accrued expenses" on the condensed Balance Sheets. At December 31, 2010, the Partnership ~~has~~had accrued environmental remediation liabilities for ~~three~~five ~~of the~~ Partnership’s ~~well pads involving five~~ wells in the amount of approximately $~~70,000 and $~~89,000, ~~respectively,~~ which is included in line item captioned “Accounts payable and accrued expenses” on the condensed Balance Sheets. The Managing General Partner is not currently aware of any environmental claims existing as of ~~March~~June 3130, 2011, which have not been provided for or would otherwise have a material impact on the Partnership’'s condensed financial statements. However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on the Partnership’'s properties.

- 10 12-

Index

PDC 2003-B ~~LIMITED~~Limited ~~PARTNERSHIP~~Partnership

(A West Virginia Limited Partnership)

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

Partnership Overview

PDC 2003-B Limited Partnership engages in the development, production and sale of natural gas, NGLs and crude oil. The Partnership began natural gas and crude oil operations in September 2003 and operates 2326 gross (2023.42 net) productive wells located in the Rocky Mountain Region in the state of Colorado. ~~In addition, three gross (2.7 net) Wattenberg Field Partnership wells are temporarily not in production at March 31, 2011 due to equipment problems.~~ The Managing General Partner markets the Partnership’'s natural gas and crude oil production to commercial end users, interstate or intrastate pipelines, 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~~June ~~managing general partner of various public limited partnerships~~2011, ~~has~~PDC ~~disclosed~~acquired ~~its intention to pursue, beginning in the fall of 2010 and extending through the next~~ three ~~years, the acquisition of the limited partnership units (the “Acquisition Plan”) held by Investor Partners of the particular partnership other than those held by PDC or its affiliates (“non-~~affiliated ~~investor partners”), in certain limited~~ partnerships: ~~that~~ PDC ~~had~~2005-A ~~previously sponsored,~~Limited ~~including this~~ Partnership~~. For additional information regarding PDC’s intention to pursue acquisitions of PDC sponsored partnerships~~, ~~refer to the disclosure included in Items 2.02, 7.01 and/or 8.01 of~~ PDC’s ~~Forms 8~~2005-KB ~~dated~~Limited ~~March~~Partnership ~~4, 2010, June 9, 2010, July 15, 2010~~ and ~~November~~Rockies ~~17,~~Region ~~2010. However,~~Private ~~such~~Limited ~~information shall not, by reason of this reference, be deemed to be incorporated by reference in, or otherwise be deemed to be part of, this report~~Partnership. Under the Acquisition Plan, any existing or future merger offer will be subject to the terms and conditions of the related merger agreement, and such agreement does or will likely contemplate the partnership being merged with and into a wholly-owned subsidiary of PDC~~. Each~~ ~~such~~purchased ~~merger~~these ~~will also be subject to, among other things, PDC having sufficient available capital, the economics of the merger and the approval by a majority of the limited~~ partnerships ~~units~~for ~~held by~~ the ~~non-affiliated~~aggregate ~~investor~~amount ~~partners~~ of ~~each respective limited partnership~~$43. ~~Consummation~~0 of any proposed merger of a limited partnership under the Acquisition Plan will result in the termination of the existence of that partnership and the right of non-affiliated investor partners to receive a cash payment for their limited partnership units in that partnershipmillion.

InOn ~~November~~June ~~2010~~20, 2011, PDC and DP 2004 Merger Sub, LLC, a wholly-owned subsidiary of PDC (“DP Merger Sub”), entered into separate merger agreements with ~~each~~this ofPartnership, PDC ~~2005~~2003-A Limited Partnership, PDC ~~2005~~2003-BC Limited Partnership, ~~and~~PDC ~~the~~2003-D ~~2005~~Limited ~~Rockies~~Partnership ~~Region~~and ~~Private~~PDC 2002-D Limited Partnership (collectively, the ~~“2005~~"2003 and 2002-D Partnerships”"). PDC serves as the Managing General Partner of each of the ~~2005~~2003 ~~Partnerships. The~~and ~~special meetings whereby non~~2002-~~affiliated~~D ~~investor partners of the 2005 partnerships will have an opportunity to vote and approve the respective merger agreements are currently scheduled for June 15, 2011~~Partnerships.

Pursuant to the Merger Agreement, if the merger is approved by the holders of a majority of the limited partnership units held by the non-affiliated 11investor partners of the Partnership, as well as, the satisfaction of other customary closing conditions, then the Partnership will merge with and into DP Merger Sub, the separate existence of the Partnership will terminate and the non-affiliated investor partners will have the right to receive cash payments in the aggregate amount of $6,414,114 or $7,864 per limited partnership unit, subject to any adjustments made to the merger consideration for certain increases in commodity prices between the date of signing the merger agreement and the filing of the definitive proxy statement, plus the sum of the amounts withheld, if any, from per unit cash distributions by the Partnership from October 1, 2010 through August 31, 2011 for the Partnership's Well Refracturing Plan, less the sum of the per unit cash distributions made after August 31, 2011 and before the transaction closes. DP Merger Sub shall be the surviving entity of the merger and shall be wholly-owned by PDC, and the limited partners will have no continuing interest in the Partnership, since the Partnership will cease as a separate business entity. The merger will become effective following the filing of a certificate of merger with the Secretaries of State of West Virginia and Delaware as soon as practicable after the last condition precedent to the merger has been satisfied, or waived. Following consummation of the merger, the non-affiliated investor partners will no longer participate in the Partnership's future earnings or any further economic benefit.

The Merger 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.

-13-

Index

PDC 2003-B ~~LIMITED~~Limited ~~PARTNERSHIP~~Partnership

(A West Virginia Limited Partnership)

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


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


•	by any party thereto, should the proposed merger not occur by December 15, 2011;


•	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 PDC or the Partnership, respectively, or materially and adversely affects the transactions contemplated by the Merger Agreement.

On June 23, 2011, the Partnership filed a preliminary proxy statement on Schedule 14A relating to the merger with the SEC. Although there is no assurance of the likelihood or timing of the merger transaction, upon clearance by the SEC, a definitive proxy statement will be mailed to the Partnership’s limited partners. Closing of the merger is conditioned on approval by a majority vote of non-affiliated investor partners 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, as described above. If approved by a majority vote of non-affiliated investor partners and after the filing of a certificate of merger with the Secretaries of State of West Virginia and Delaware, no additional filing or registration with, notification to, or authorization, consent or approval of, any governmental entity will be required in connection with the execution and delivery of the Merger Agreement by the Partnership, PDC or DP Merger Sub or the consummation by the Partnership, PDC or DP Merger Sub of the transactions contemplated thereby. Following consummation of the merger, the non-affiliated investor partners will no longer participate in the Partnership’s future earnings or any further economic benefit.

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 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 six months ended June 30, 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 prepared a plan for the Partnership’'s Wattenberg Field wells which may provide for additional reserve development of natural gas, NGLs and crude oil production (the “Well Refracturing Plan”). The Well Refracturing Plan consists of the Partnership’'s refracturing of wells currently producing in the Codell formation. Under the Well Refracturing Plan, the Partnership plans to initiate refracturing activities during 2011. Refracturing, or “refracing,” activities consist of a second hydraulic fracturing treatment in a current production zone, all within an existing well bore.

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.-14-

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 21 refracturing opportunities. Total withholding for these activities from the Partnership’s cash available for distributions is estimated to be between $3.7 million and $5.0 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, $95,000 was withheld from the Partnership’s cash distributions pursuant to the Well Refracturing Plan. Cumulatively, $115,000 has been withheld from Partnership distributions through April 30, 2011 and resides in the Partnership’s bank account.

- 12 -

Index

PDC 2003-B ~~LIMITED~~Limited ~~PARTNERSHIP~~Partnership

(A West Virginia Limited Partnership)

IfRefracturing ~~any~~of orWattenberg ~~all~~Field ofwells, ~~the~~which ~~Partnership’s~~may ~~Wattenberg~~provide ~~wells~~for ~~are~~additional ~~not~~reserve ~~refractured~~development and production, ~~the~~generally ~~Partnership~~occurs ~~will~~five ~~experience~~to aten ~~reduction~~years inafter ~~proved~~initial ~~reserves~~well ~~currently~~drilling ~~assigned~~so that well resources are optimally utilized. This refracturing would be expected to ~~these~~occur ~~wells~~based on a favorable general economic environment and commodity price structure. ~~Both~~ The Managing General Partner has the ~~number~~authority to determine whether to refracture the individual wells and to determine the timing of ~~the~~any refracturing ~~activities~~activity. The ~~will~~timing of the refracturing can be ~~based~~affected onby the ~~availability~~desire to optimize the economic return by refracturing the wells when commodity prices are at levels to obtain the highest rate of ~~cash~~return ~~withheld~~to ~~from~~the Partnership ~~distributions~~. ~~The~~ On ~~Managing~~average, ~~General~~the ~~Partner~~production ~~believes~~resulting ~~that,~~from ~~based~~PDC's onCodell ~~projected~~refracturings ~~refracturing~~have ~~costs~~been ~~and~~at ~~projected~~modeled ~~cash~~economics; ~~withholding~~however, all ~~scheduled~~refracturings ~~Partnership~~have not been economically successful and similar future refracturing ~~activity~~activities ~~will~~may not be ~~completed~~economically ~~within~~successful. If athe ~~five~~refracturing ~~year~~work ~~period. Any~~is ~~funds~~performed, ~~not~~PDC ~~used~~will charge the Partnership for ~~refracturing~~the ordirect ~~other~~costs ~~operational~~of ~~needs~~refracturing, ~~will~~and bethe ~~distributed~~Investor toPartners and the Managing General Partner ~~and~~will ~~Investor~~each ~~Partners~~pay their proportionate share of costs based on ~~their~~the ~~proportional~~ ownership ~~interest~~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.

~~Implementation~~During of the ~~Well~~fourth ~~Refracturing~~quarter ~~Plan~~2010, ~~has and will continue to reduce or eliminate Partnership distributions to~~ the Managing General Partner ~~and~~began ~~Investor~~a ~~Partners~~program ~~while the work is being conducted and paid~~ for ~~through~~its ~~the~~affiliated ~~Partnership~~partnerships ~~funds. Depending~~to ~~upon~~begin ~~the~~accumulating ~~level~~cash offrom ~~withholding~~cash ~~and~~flows ~~the results of operations, it is possible that the Managing General Partner and Investor Partners could have taxable income~~ from ~~the~~operating ~~Partnership~~activities ~~without~~to ~~any~~pay ~~corresponding~~for ~~distributions in~~ future ~~years~~refracturing costs. ~~Non-affiliated~~ This ~~Investor~~program ~~Partners~~will ~~are~~materially ~~urged~~reduce, toup ~~consult a tax advisor~~ to ~~determine all of the relevant federal~~100%, ~~state~~cash ~~and~~available ~~local~~for ~~tax~~distributions ~~consequences~~ of the ~~Well~~partnerships ~~Refracturing~~for ~~Plan. The above discussion is not intended as~~ a ~~substitute~~period ~~for careful tax planning, and non-affiliated Investor Partners should depend upon the advice~~ of ~~their~~time ~~own~~not ~~tax~~to ~~advisors~~exceed ~~concerning~~five ~~the effects of the Well Refracturing Plan~~years.

Current estimated costs for these well refracturings are between $175,000 and $240,000 per activity. As of June 30, 2011, this Partnership had scheduled to complete 21 refracturing opportunities. Total withholding for these activities from the Partnership's cash available for distributions is estimated to be between $3.7 million and $5.0 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 June 30, 2011, $40,000 was withheld from the Partnership's cash distributions pursuant to the Well Refracturing Plan. Cumulatively, $193,000 has been withheld from Partnership distributions through July 31, 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's funds. Depending upon the level of withholding and the results of operations, it is possible that the Managing General Partner and Investor Partners could have taxable income from the Partnership without any corresponding distributions in future years. Non-affiliated investor partners are urged to consult a tax advisor to determine all of the relevant federal, state and local tax consequences of the Well Refracturing Plan. The above discussion is not intended as a substitute for careful tax planning, and non-affiliated investor partners should depend upon the advice of their own tax advisors concerning the effects of the Well Refracturing Plan.

Partnership Operating Results Overview

Natural gas, NGLs and crude oil sales decreased 327% or approximately $~~0.1~~44,000 ~~million~~ for the first ~~three~~six months of 2011 compared to the first ~~three~~six months of 2010, while sales volumes declined 2212% period-to-period. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $56.7719 for the current year period compared to $65.6088 for the same period a year ago. Realized derivative gains from natural gas and crude oil sales contributed an additional $0.3123 per Mcfe or approximately $1421,000 to the first ~~three~~six months of 2011 total revenues compared to an additional $21.8377 or approximately $~~157~~183,000 to the first ~~three~~six months of 2010. Comparatively, the total realized price per Mcfe, consisting of the average sales price and realized derivative gains, decreased to $6.0842 for the current year ~~three~~six months from $97.4365 for the same prior year period.

~~The~~Direct ~~Partnership’s combined natural gas, NGLs and crude oil production expenses and direct~~ costs − general and administrative, decreased by approximately $31203,000 during ~~2011. This decrease is primarily~~ the ~~result~~2011 ofsix ~~lower~~month ~~general~~period ~~and administrative expenses~~ due to ~~lower~~decreased fees for professional services.

- 13 15-

Index

PDC 2003-B ~~LIMITED~~Limited ~~PARTNERSHIP~~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 March 31,
	Three months ended June 30,										Six months ended June 30,
	2011	~~2011~~			2010	~~2010~~		Change	~~Change~~		2011			2010		Change
Number of producing wells (end of period)	26		23		25		25	1		(2	)26			25		1
Production(1)
Natural gas (Mcf)	32,149		~~32,060~~		35,262		~~38,001~~	(9	)%	~~-16~~	%64,209			73,263		(12	)%
NGLs (Bbl)	698		~~576~~		607		~~770~~	15	%	~~-25~~	%1,274			1,377		(7	)%
Crude oil (Bbl)	1,870		~~1,301~~		1,456		~~2,138~~	28	%	~~-39~~	%3,171			3,594		(12	)%
Natural gas equivalents (Mcfe)(2)	47,557		~~43,322~~		47,640		~~55,449~~	*		~~-22~~	%90,879			103,089		(12	)%
Average Mcfe per day	523		~~481~~		524		~~616~~	*		~~-22~~	%502			570		(12	)%
Natural Gas, NGLs and Crude Oil Sales
Natural gas	$	$98,374	~~107,390~~		$	$109,650	~~175,624~~	(10	)%	~~-39~~	%$	205,764		$	285,274	(28	)%
NGLs	34,674		~~30,279~~		24,560		~~35,004~~	41	%	~~-13~~	%64,953			59,564		9	%
Crude oil	179,490		~~112,083~~		106,236		~~155,406~~	69	%	~~-28~~	%291,573			261,642		11	%
Total natural gas, NGLs and crude oil sales	$	$312,538	~~249,752~~		$	$240,446	~~366,034~~	30	%	~~-32~~	%$	562,290		$	606,480	(7	)%
Realized Gain (Loss) on Derivatives, net
Natural gas	$	$32,732	~~32,033~~		$	$69	~~133,191~~	*		~~-76~~	%$	64,763		$	133,260	(51	)%
Crude oil	(25,575		~~(18,293~~)	)	25,452		~~23,859~~	(200	)%	~~-177~~	%(43,866		)	49,311		(189	)%
Total realized gain on derivatives, net	$	$7,157	~~13,740~~		$	$25,521	~~157,050~~	(72	)%	~~-91~~	%$	20,897		$	182,571	(89	)%
Average Selling Price (excluding realized gain (loss) on derivatives)
Natural gas (per Mcf)		$	3.35			$	4.62			-28	%
Natural gas (per Mcf)(3)	$	3.06			$	3.11		(2	)%		$	3.20		$	3.89	(18	)%
NGLs (per Bbl)	49.68		~~52.57~~		40.46		~~45.46~~	23	%	16	%50.98			43.26		18	%
Crude oil (per Bbl)	95.98		~~86.15~~		72.96		~~72.69~~	32	%	19	%91.95			72.80		26	%
Natural gas equivalents (per Mcfe)	6.57		~~5.77~~		5.05		~~6.60~~	30	%	~~-13~~	%6.19			5.88		5	%
Average Selling Price (including realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	$4.08	~~4.35~~		$	$3.11	~~8.13~~	31	%	~~-46~~	%$	4.21		$	5.71	(26	)%
NGLs (per Bbl)	49.68		~~52.57~~		40.46		~~45.46~~	23	%	16	%50.98			43.26		18	%
Crude oil (per Bbl)	82.31		~~72.09~~		90.45		~~83.85~~	(9	)%	~~-14~~	%78.12			86.52		(10	)%
Natural gas equivalents (per Mcfe)	6.72		~~6.08~~		5.58		~~9.43~~	20	%	~~-36~~	%6.42			7.65		(16	)%
Average cost per Mcfe
Natural gas, NGLs and crude oil production cost(3)		$	2.14			$	1.79			20	%
Natural gas, NGLs and crude oil production cost(4)	$	3.72			$	3.41		9	%		$	2.96		$	2.54	17	%
Depreciation, depletion and amortization	$	3.52	~~3.31~~		$	2.93	~~3.11~~	20	%	6	%$	3.42		$	3.03	13	%
Operating costs and expenses:
Direct costs - general and administrative	$	$39,880	~~48,059~~		$	$218,659	~~72,565~~	(82	)%	~~-34~~	%$	87,939		$	291,224	(70	)%
Depreciation, depletion and amortization	$	167,540	~~143,349~~		$	139,630	~~172,624~~	20	%	~~-17~~	%$	310,889		$	312,254	*
Cash distributions	$	$38,890	~~71,649~~		$	$202,505	~~280,681~~	(81	)%	~~-74~~	%$	110,539		$	483,186	(77	)%

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

Amounts may not calculate due to rounding.

- 14 16-

Index

PDC 2003-B ~~LIMITED~~Limited ~~PARTNERSHIP~~Partnership

(A West Virginia Limited Partnership)

_______________

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

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

(3) The ~~Production~~Partnership's ~~costs~~average ~~represent~~sales price for natural gas is based on the "net-back" method of accounting for transportation, ~~NGLs~~gathering and ~~crude~~processing ~~oil~~arrangements ~~operating~~with ~~expenses~~natural ~~which~~gas ~~include~~purchasers. ~~production~~See ~~taxes~~the Partnership's revenue recognition policy described in Note 2, Summary of Significant Accounting Policies, to financial statements in the Partnership's 2010 Form 10-K and Part 1, Item 2, Financial Condition, Liquidity and Capital Resources - Cash Flows, included in this report.

⁽⁴⁾ Production costs represent natural gas, NGLs and crude oil operating expenses which include production taxes.

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

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

·• MBbl – One thousand barrels

·• Mcf – One thousand cubic feet

·• MMcf – One million cubic feet

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

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

·• MMbtu – One million British Thermal Units

Natural Gas, NGLs and Crude Oil Sales

~~For~~Six ~~the three~~ months ended ~~March~~June 3130, 2011 as compared to ~~the~~six ~~same~~months ~~period~~ended inJune ~~2010~~30, natural gas, NGLs and crude oil sales, on an energy equivalency-basis, decreased 22%, due to normal production declines for this stage in the wells’ production life cycle. Additional production declines were the result of four partnership wells which were temporarily shut-in during February for maintenance.2010

~~Three~~For the six months ended ~~March~~June 3130, 2011 as compared to ~~three~~the ~~months~~same ~~ended~~period ~~March~~in 312010, ~~2010~~natural gas, NGLs and crude oil sales, on an energy equivalency-basis, decreased 12% due to normal production declines for this stage in the wells' production life cycle.

The ~~$0.1~~approximately ~~million~~$44,000, or 327%, decrease in sales for the 2011 ~~three~~six month period as compared to the prior year period, was primarily a reflection of a sales volume ~~decrease~~decreases of 2212% ~~and~~partially aoffset ~~decline~~by an increase in sales prices of 135%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $56.7719 for the current year ~~three~~six month period compared to $65.6088 for the same period a year ago.

Natural gas, revenues decreased by 28% and were partially offset by increases in NGLs and crude oil revenues ~~decreased~~of ~~by 39~~9%, ~~13%~~ and 2811%, respectively. The Partnership’'s natural gas revenue decrease resulted from ~~decreased~~lower ~~commodity~~Partnership ~~prices~~natural ~~per~~gas ~~Mcf,~~production volumes of 2812%, and ~~lower~~from ~~Partnership~~decreased ~~natural~~commodity ~~gas~~prices ~~production volumes~~ of 1618%. The ~~decrease~~increase in NGLs revenue was due to aincreased ~~decrease~~commodity ofprices ~~25%~~per inBbl ~~NGLs~~of ~~production~~18%, ~~volumes~~ partially offset by ~~increased~~a ~~commodity~~decrease ~~prices~~of ~~per~~7% ~~Bbl,~~in ofNGLs ~~16%~~production volumes. The crude oil revenue ~~decrease~~increase is due primarily to athe ~~sales~~rise ~~volume~~in ~~decrease~~commodity prices per Bbl of 3926%, partially offset by the ~~rise~~sales involume ~~commodity~~decreases ~~prices per Bbl,~~ of 1912% during the current ~~three~~six month period.

Three months ended June 30, 2011 as compared to three months ended June 30, 2010

For the three months ended June 30, 2011 compared to the same period in 2010, natural gas, NGLs and crude oil sales, on an energy equivalency-basis, remained relatively unchanged due to increased crude oil sales volumes due to timing of oil tank pick-ups by the refinery, partially offset by decreases in natural gas sales volumes due to normal production declines for this stage in the wells' production life cycle.

The approximately $72,000, or 30%, increase in sales for the 2011 three month period as compared to the prior year period was primarily a reflection of an increase in sales prices of 30% and relatively unchanged sales volumes. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $6.57 for the current year three month period compared to $5.05 for the same period a year ago.

NGLs and crude oil revenues increased by 41% and 69%, respectively, and were partially offset by decreases in natural gas revenues of 10%. The Partnership's natural gas revenue decrease resulted from lower Partnership natural gas production volumes of 9%, and decreased commodity prices per Mcf, of 2%. The increase in NGLs revenue was due to increased commodity prices per Bbl of 23%, and an increase of 15% in NGLs production volumes. The crude oil revenue increase is due primarily to the rise in commodity prices per Bbl of 32%, in addition to sales volume increases of 28% during the current three month period.

-17-

Index

PDC 2003-B Limited Partnership

(A West Virginia Limited Partnership)

Commodity Price Risk Management, Net

The Partnership uses various derivative instruments to manage fluctuations in natural gas and crude oil prices. The Partnership has in place a variety of ~~floors,~~ collars, fixed-price swaps and basis swaps on a portion of the Partnership’'s estimated natural gas and crude oil production. ~~Because~~ The ~~the~~ Partnership sells its natural gas and crude oil at similar prices to the indices inherent in the Partnership’'s derivative instruments. As a result, for the volumes underlying the Partnership's derivative positions, 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.

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

-The 15following -table presents the realized and unrealized derivative gains and losses included in commodity price risk management, net.



	Three months ended June 30,						Six months ended June 30,
	2011			2010			2011			2010
Commodity price risk management gain, net:
Realized gains (losses)
Natural gas	$	32,732		$	69		$	64,763		$	133,260
Crude oil	(25,575		)	25,452			(43,866		)	49,311
Total realized gains, net	7,157			25,521			20,897			182,571

Unrealized gains (losses)
Reclassification of realized gains included in
prior periods unrealized	(5,828		)	(18,070		)	(26,982		)	(106,540		)
Unrealized gains for the period	76,618			122,911			38,250			421,381
Total unrealized gains, net	70,790			104,841			11,268			314,841
Total commodity price risk management gain, net	$	77,947		$	130,362		$	32,165		$	497,412

Six months ended June 30, 2011 as compared to six months ended June 30, 2010

Realized gains recognized in the six months ended June 30, 2011 are primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of the Partnership's natural gas derivative positions. Realized gains on natural gas settlements were approximately $148,000 for the six months ended June 30, 2011. These gains were offset in part by an approximate $83,000 loss on the Partnership's CIG basis protection swaps as the negative basis differential between NYMEX and Colorado Interstate Gas (“CIG”) was narrower than the strike price of the basis positions. The Partnership also realized an approximate $44,000 loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price. Unrealized gains during the six months ended June 30, 2011 are primarily related to the shifts in the forward curves and their impact on the fair value of the Partnership's open positions. The shifts downward in the natural gas curves resulted in an unrealized gain of approximately $70,000 which was partially offset by unrealized losses of approximately $28,000 on the Partnership's CIG basis protection swaps as the forward basis differential between the NYMEX and CIG had continued to narrow. Additionally, the shifts upward in the crude oil curves resulted in an unrealized loss of approximately $4,000.

The realized derivative gains for the 2010 six month period were approximately $183,000. These realized gains were primarily a result of lower natural gas and oil spot prices at settlement compared to the respective strike price, offset in part by realized losses due to the basis differential between NYMEX and CIG being narrower than the strike price of the derivative position. For the six month period, realized gains related to natural gas and oil derivatives were approximately $189,000 and $49,000, respectively, and realized losses on the Partnership's CIG basis protection swaps were approximately $56,000. Unrealized gains for the six month period were approximately $421,000 due primarily to a downward shift in the natural gas and oil forward curves. Unrealized gains on the Partnership's natural gas and oil positions for the period were approximately $376,000 and $45,000, respectively.

-18-

Index

PDC 2003-B ~~LIMITED~~Limited ~~PARTNERSHIP~~Partnership

(A West Virginia Limited Partnership)

~~The~~Three ~~following~~months ~~table~~ended ~~presents~~June ~~the~~30, ~~realized~~2011 ~~and~~as ~~unrealized~~compared ~~derivative~~to ~~gains~~three ~~and~~months ~~losses~~ended ~~included~~June ~~in commodity price risk management (loss) gain~~30, ~~net.~~2010

	Three months ended March 31,
Commodity price risk management, net	2011			2010
Realized gain (loss)
Natural gas	$	32,033		$	133,191
Crude oil		(18,293	)		23,859
Total realized gain, net		13,740			157,050
Unrealized gain (loss)
Reclassification of realized gain included in prior periods unrealized		(10,762	)		(145,222	)
Unrealized (loss) gain for the period		(48,760	)		355,222
Total unrealized (loss) gain, net		(59,522	)		210,000
Commodity price risk management (loss) gain, net	$	(45,782	)	$	367,050

Realized gains recognized in the three months ended June 30, 2011 are primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of the Partnership's natural gas derivative positions. Realized gains on natural gas settlements were approximately $87,000 for the three months ended June 30, 2011. These gains were offset in part by an approximate $54,000 loss on the Partnership's CIG basis protection swaps as the negative basis differential between NYMEX and CIG was narrower than the strike price of the basis positions. The Partnership also realized an approximate $26,000 loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price. Unrealized gains during the three months ended June 30, 2011 are primarily related to the shifts in the forward curves and their impact on the fair value of the Partnership's open positions. The shift downward in the crude oil curve resulted in an unrealized gain of approximately $18,000 during the three months ended June 30, 2011. Likewise, the shifts downward in the natural gas and basis curves resulted in a total unrealized gain of approximately $59,000.

~~Three~~ ~~months~~The ~~ended~~realized ~~March~~derivative 31gains for the 2010 second quarter were approximately $25,000. These ~~2011~~realized asgains are a result of lower natural gas and oil spot prices at settlement compared to ~~three~~the ~~months~~respective ~~ended~~strike ~~March~~price, 31offset 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 natural gas and oil derivatives were approximately $81,000 and realized losses on the Partnership's CIG basis swaps were approximately $56,000. For the 2010 second quarter, the unrealized gains 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 differential. Unrealized gains on the Partnership's oil positions and CIG basis protection swaps for the 2010 second quarter were approximately $49,000 and $65,000, respectively. Additionally, the shifts downward in the natural gas curves resulted in an unrealized gain of approximately $9,000.

~~Realized~~The ~~gains~~following ~~recognized~~table inpresents the ~~three months ended March 31, 2011 are primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of the~~ Partnership’'s ~~natural gas~~ derivative positions~~. Realized~~ ~~gains on natural gas settlements were $61,000 for the three months ended March 31, 2011. These gains were offset~~ in ~~part~~effect ~~by a $29,000 loss on the Partnership’s CIG basis protection swaps~~ as ~~the negative basis differential between NYMEX and Colorado Interstate Gas (“CIG”) was narrower than the strike price~~ of ~~the~~June ~~basis positions. The Partnership also realized a $18~~30,~~000~~ ~~loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price. Unrealized losses during the three months ended March 31,~~ 2011 ~~are primarily related to the shifts in the forward curves and their impact on the fair value of the Partnership’s open positions~~. The significant shift upward in the crude oil curve resulted in an unrealized loss of $33,000 during the three months ended March 31, 2011. Likewise, the shifts upward in the natural gas and basis curves resulted in a total unrealized loss of $16,000.

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



	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 June 30, 2011⁽²⁾
		Floors		Ceilings

Natural Gas
NYMEX
07/01 - 09/30/2011	—	$	—	$	—	34,795	$	6.73	34,795	$	(1.88	)	$	28,409
10/01 - 12/31/2011	—	—		—		33,790	6.78		33,790	(1.88		)	21,987
01/01 - 03/31/2012	2,176	6.00		8.27		30,401	6.98		32,577	(1.88		)	18,456
04/01 - 06/30/2012	1,169	6.00		8.27		30,731	6.98		31,900	(1.88		)	26,099
07/01 - 12/31/2012	3,272	6.00		8.27		58,862	6.98		62,134	(1.88		)	36,199
2013	—	—		—		115,337	7.12		115,337	(1.88		)	60,534
Total Natural Gas	6,617					303,916			310,533				191,684

Crude Oil
NYMEX
07/01 - 09/30/2011	—	—		—		825	70.75		—	—			(20,199		)
10/01 - 12/31/2011	—	—		—		846	70.75		—	—			(21,915		)
Total Crude Oil	—					1,671			—				(42,114		)

Total Natural Gas and Crude Oil													$	149,570

-(1) 16A -standard unit of measure for natural gas (one MMBtu equals one Mcf).

⁽²⁾Approximately 1% of the fair value of the Partnership's derivative assets and none 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.

-19-

Index

PDC 2003-B ~~LIMITED~~Limited ~~PARTNERSHIP~~Partnership

(A West Virginia Limited Partnership)

The following table presents the Partnership’s derivative positions in effect as of March 31, 2011.

	Collars						Fixed-Price Swaps				CIG Basis Protection Swaps
Commodity/ Index	Quantity (Gas-		Weighted Average Contract Price				Quantity (Gas-Mmbtu(1)		Weighted Average Contract		Quantity (Gas-		Weighted Average Contract			Fair Value at March 31,
	Mmbtu(1))		Floors		Ceilings		Oil-Bbls)		Price		Mmbtu(1))		Price			2011(2)
Natural Gas
NYMEX
04/01 - 06/30/2011		-	$	-	$	-		35,391	$	6.78		35,391	$	(1.88	)	$	34,342
07/01 - 09/30/2011		-		-		-		34,795		6.73		34,795		(1.88	)		25,520
10/01 - 12/31/2011		-		-		-		33,790		6.78		33,790		(1.88	)		18,343
01/01 - 03/31/2012		2,176		6.00		8.27		30,401		6.98		32,577		(1.88	)		10,552
04/01 - 12/31/2012		4,441		6.00		8.27		89,594		6.98		94,034		(1.88	)		46,151
2013		-		-		-		115,337		7.12		115,337		(1.88	)		32,790
Total Natural Gas		6,617						339,308				345,924					167,698
Crude Oil
NYMEX
04/01 - 06/30/2011		-		-		-		805		70.75		-		-			(28,514	)
07/01 - 09/30/2011		-		-		-		825		70.75		-		-			(29,837	)
10/01 - 12/31/2011		-		-		-		846		70.75		-		-			(30,567	)
Total Crude Oil		-						2,476				-					(88,918	)
Total Natural Gas and Crude Oil																$	78,780

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

(2) Approximately 1% 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.

Natural Gas, NGLs and Crude Oil Production Costs

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

~~Three~~Six months ended ~~March~~June 3130, 2011 as compared to ~~three~~six months ended ~~March~~June 3130, 2010

Production and operating costs per Mcfe increased to $2.1496 during the current period compared to $12.7954 for the prior year period due to the effect of ~~higher~~increased ~~per-well~~environmental ~~related~~remediation ~~expenditures partially offset by lower per-volume related natural gas, NGLs and crude oil production~~ costs. Current period production and operating costs ~~decreased~~include byan environmental remediation charge of approximately $779,000, ~~primarily~~compared ~~due~~ to ~~reductions~~environmental inremediation ~~natural~~charges ~~gas~~of ~~transportation~~approximately ~~and~~$50,000 ~~lease~~for ~~operating~~the ~~expenses~~same ~~resulting~~six ~~from~~month ~~decreased~~period ~~production~~in ~~volumes as compared to~~ the ~~same~~prior ~~period in 2010~~year.

-Three 17months -ended June 30, 2011 as compared to three months ended June 30, 2010

~~Index~~Production and operating costs per Mcfe increased to $3.72 during the current period compared to $3.41 for the prior year period due to the effect of increased environmental remediation costs. Current period production and operating costs include an environmental remediation charge of approximately $79,000 compared to environmental remediation charges of approximately $50,000 for the same three month period in the prior year.

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Direct Costs−General and Administrative

~~Three~~Six months ended ~~March~~June 3130, 2011 as compared to ~~three~~six months ended ~~March~~June 3130, 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 during the ~~three~~2011 six months ended ~~March~~June 3130, 2011, compared to the same period in 2010, by approximately $25203,000 principally due to decreased fees for ~~the above referenced~~ professional services.

Three months ended June 30, 2011 as compared to three months ended June 30, 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 during the three months ended June 30, 2011 compared to the same period in 2010, by approximately $179,000 principally due to decreased fees for professional services.

Depreciation, Depletion and Amortization

~~Three~~Six months ended ~~March~~June 3130, 2011 as compared to ~~three~~six months ended ~~March~~June 3130, 2010

The DD&A expense rate per Mcfe increased to $3.3142 for the 2011 ~~three~~six month period, compared to $3.1103 during the same period in 2010. The increase 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, as well as the effect of the downward revision in the Partnership's proved developed producing natural gas, NGLs and crude oil reserves particularly in the Grand Valley Field as of December 31, 2010. The production declines, noted in previous sections, ~~partially~~ offset by the increased DD&A expense rate, ~~resulted~~resulting in aflat ~~decreased~~ DD&A expense ofbetween ~~approximately $29,000 for~~ the 2011 ~~three~~six month period ~~compared~~and to the same ~~2010~~ period in 2010.

-20-

Index

PDC 2003-B Limited Partnership

(A West Virginia Limited Partnership)

Three months ended June 30, 2011 as compared to three months ended June 30, 2010

The DD&A expense rate per Mcfe increased to $3.52 for the 2011 three month period, compared to $2.93 during the same period in 2010. The increase 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, as well as the effect of the downward revision in the Partnership's proved developed producing natural gas, NGLs and crude oil reserves particularly in the Grand Valley Field as of December 31, 2010. The increased DD&A expense rate resulted in an increased DD&A expense of approximately $28,000 for the 2011 three month period compared to the same 2010 period.

Financial Condition, Liquidity and Capital Resources

The Partnership’'s primary sources of cash for the ~~three~~six months ended ~~March 31~~June 30, 2011 were 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 fund 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 ~~March~~June 3130, 2011, the Managing General Partner withheld $9540,000 from the Partnership’'s regular cash distributions pursuant to the Well Refracturing Plan and deposited this into the Partnership's cash account. Through ~~April~~July 3031, 2011, $~~115~~193,000 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~~beginning ~~2011,~~in ~~and thereafter and are expected to decrease distributions from the 2009 levels for the next several years~~2011. For additional information, see Item 2, Management’'s Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments—-Well Refracturing Plan.

Fluctuations in the Partnership’'s operating cash flows 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 Managing General Partner 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, NGLs and crude oil sales and realized natural gas and crude oil derivative gains and losses. However, the Partnership does not engage in speculative positions, nor does the Partnership hold derivative instruments for 100% of the Partnership’'s expected future production from producing wells and therefore may still experience significant fluctuations in cash flows from operations. As of ~~March~~June 3130, 2011, the Partnership had natural gas and crude oil derivative positions in place covering ~~88%~~all of the expected natural gas production and 3851% of expected crude oil production for the remainder of 2011, at an average price of $4.8887 per Mcf and $70.75 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 first quarter of 2010 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.

-The 18Partnership's -future operations are expected to be conducted with available funds and revenues generated from natural gas, NGLs and crude oil production activities and commodity gains. 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.

~~PDC 2003~~-~~B LIMITED PARTNERSHIP~~21-

Index

PDC 2003-B Limited Partnership

(A West Virginia Limited Partnership)

The Partnership’s future operations are expected to be conducted with available funds and revenues generated from natural gas, NGLs and crude oil production activities and commodity gains. 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.

Working Capital

The Partnership had working capital at ~~March~~June 3130, 2011 of approximately $2114,000 compared to negative working capital of $12,000 at December 31, 2010, an increase of approximately $14126,000. This increase was primarily due to the following changes:

·• Cash and cash equivalents increased by $95135,000 between ~~March~~June 3130, 2011 and December 31, 2010.,

·• Accounts receivable decreased by $3842,000 between ~~March~~June 3130, 2011 and December 31, 2010.

·• Realized and unrealized derivative gains ~~receivables~~receivable decreased by $3214,000 between ~~March 31~~June, 2011 and December 31, 2010.

·• ~~Unrealized~~Due ~~derivative~~to ~~gains~~the ~~receivables~~Managing General Partner decreased by approximately $3493,000 between ~~March~~June 3130, 2011 and December 31, 2010.,

·• Crude oil inventory increased by approximately $7,000 between ~~March~~June 3130, 2011 and December 31, 2010., and

·• Accounts payable and accrued expenses ~~decreased~~increased by $1653,000 between ~~March~~June 3130, 2011 and December 31, 2010.

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

Cash Flows

Cash Flows From Operating Activities

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

-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 has resulted in local market oversupply situations from time to time. Like most producers in the region, the Partnership relies on major interstate pipeline companies to construct these pipelines to increase capacity, rendering the timing and availability of these facilities beyond the Partnership's control. Crude oil pricing is predominantly driven by the physical market, supply and demand, the financial markets and global unrest.

The price at which PDC markets the natural gas produced in the Rocky Mountain Region by the Partnership is based on a market basket of prices, which primarily includes natural gas sold at CIG prices with a portion sold at Mid-Continent, San Juan Basin, Southern California or other nearby region prices. The CIG Index and other indices for production delivered to other Rocky Mountain pipelines have historically been less than the price received for natural gas produced in the eastern regions, which is primarily New York Mercantile Exchange, or NYMEX, based. This negative differential has narrowed over the last few years and is lower than historical variances. The negative differential of CIG relative to NYMEX averaged $0.31 and $0.32 for the six months ended June 30, 2011 and 2010, respectively.

The price the Partnership receives on its natural gas sales is impacted by the Managing General Partner's transportation, gathering and processing agreements. The Partnership currently uses the "net-back" method of accounting for these arrangements related to the Partnership's natural gas sales. The Partnership sells natural gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based.

-22-

Index

PDC 2003-B ~~LIMITED~~Limited ~~PARTNERSHIP~~Partnership

(A West Virginia Limited Partnership)

~~Natural~~Net ~~gas,~~cash ~~NGLs~~provided ~~and~~by ~~crude~~operating ~~oil~~activities ~~prices~~was ~~exhibit~~approximately a$248,000 ~~high~~for ~~degree of volatility. These price variations have a material impact on~~ the ~~Partnership’s~~six ~~financial~~months ~~results. Natural~~ended ~~gas~~June ~~and~~30, ~~NGLs prices vary by region and locality~~2011, ~~depending~~compared ~~upon the distance~~ to ~~markets~~approximately $484,000 ~~the~~for ~~availability of pipeline capacity and~~ the ~~supply~~comparable ~~and~~period ~~demand relationships~~ in ~~that region or locality~~2010. ~~This can be especially true in the Rocky Mountain Region.~~ The ~~combination~~decrease of ~~increased~~approximately ~~drilling~~$236,000 ~~activity and the lack of local markets have resulted~~ in ~~local~~cash ~~market~~provided ~~oversupply~~by ~~situations~~operating ~~from~~activities ~~time~~was todue ~~time. Like~~primarily ~~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.following:

~~The~~• ~~price~~A atdecrease ~~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~~NGLs ~~Juan Basin, Southern California or other nearby region prices. The CIG Index~~ and ~~other~~crude ~~indices~~oil ~~for~~sales ~~production~~receipts ~~delivered~~of toapproximately ~~other Rocky Mountain pipelines have historically been less than the price received for natural gas produced in the eastern regions~~$120, ~~which is primarily New York Mercantile Exchange~~000, or ~~NYMEX~~17%, based. This negative differential has narrowed over the last few years and is lower than historical variances. The negative differential of CIG relative to NYMEX averaged $0.28 and $0.16 for the three months ended March 31, 2011 and 2010, respectively.

~~Net~~• ~~cash~~A ~~provided~~decrease byin ~~operating~~commodity ~~activities~~price ~~was~~risk ~~approximately~~management ~~$0.2~~realized ~~million~~gains ~~for~~receipts ~~the~~of ~~three~~approximately ~~months ended March 31~~$240, ~~2011~~000, ~~compared~~or to82%, ~~approximately $0.3 million for the comparable period in 2010. The approximately $0.1 million decrease in cash provided by operating activities was due primarily to the following:~~and

·• AAn offsetting decrease in ~~natural~~production ~~gas,~~costs ~~NGLs~~ and ~~crude~~direct ~~oil~~costs ~~sales~~- ~~receipts~~general ofand ~~$0.1~~administrative ~~million,~~payments orof ~~24%~~approximately $124,000.

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

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

Cash Flows From Investing Activities

The Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of natural gas, NGLs and crude oil or environmental protection. These amounts ~~totaled~~were ~~approximately~~not ~~$1,000~~significant ~~each~~ for the ~~three~~six months ended ~~March~~June 3130, 2011 and 2010, respectively.

Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in March 2004 and has distributed $18.6 million through ~~March~~June 3130, 2011. The table below presents cash distributions to the Partnership’'s investors. Managing General Partner distributions include amounts distributed to PDC for its Managing General Partner’'s 20% ownership share in the Partnership. Investor Partner distributions include amounts distributed to Investor Partners for their 80% ownership share in the Partnership and include amounts distributed to PDC for limited partnership units repurchased.

Quarter	Managing		Investor
Distributions
ended	General Partner		Partners		Total
Three months ended June 30,	Managing General Partner		Investor Partners		Total
March 31,	Distributions		Distributions		Distributions
2011	$	7,778	$	31,112	$	38,890
2011	$	14,329	$	57,320	$	71,649
2010	$	40,501	$	162,004	$	202,505
2010	$	56,137	$	224,544	$	280,681
Six months ended June 30,	Managing General Partner		Investor Partners		Total
2011	$	22,107	$	88,432	$	110,539
2010	$	96,638	$	386,548	$	483,186

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. During the quarter ended June 30, 2011, on a pro-rata basis based on percentage of ownership in the Partnership, the Partnership withheld $8,000 and $32,000 from the Managing General Partner and Investor Partners' share of cash available for distributions, respectively.

The Partnership began funding for the Well Refracturing Plan during October 2010. During the quarter ended March 31, 2011, on a pro-rata basis based on percentage of ownership in the Partnership, the Partnership withheld $19,000 and $76,000 from the Managing General Partner and Investor Partners’ share of cash available for distributions, respectively.

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Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Off-Balance Sheet Arrangements

As of ~~March~~June 3130, 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.

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Index

PDC 2003-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 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 2010 Form 10-K.

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 ~~March 31~~June 30, 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 Exchange Act Rules 13a-15(e) and 15d-15(e). This evaluation considered the various processes carried out under the direction of the Managing General Partner’'s disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports that the Partnership files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’'s rules and forms, and that such information is accumulated and communicated to the Partnership’'s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely discussion regarding required disclosure.

-Based 21on -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 June 30, 2011.

Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

(b) Changes in Internal Control over Financial Reporting

During the three months ended ~~March 31~~June 30, 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 Exchange Act) that have materially affected or are reasonably likely to materially affect the Partnership’'s internal control over financial reporting.

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Index

PDC 2003-B ~~LIMITED~~Limited ~~PARTNERSHIP~~Partnership

(A West Virginia Limited Partnership)

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

Item 1A. Risk Factors

Not applicable.

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

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

The following table presents information about the Managing General Partner’'s limited partner unit repurchases during the three months ended ~~March 31~~June 30, 2011.

	Total Number of Units Repurchased			Average Price Paid per Unit
Period	Total Number of Units Repurchased		Average Price Paid Per Unit
Period
April 2011	0.25		$	1,780
January 1−31, 2011		0.75		$	2,900
May 2011	—		—
February 1−28, 2011		1.25			2,548
June 2011	—		—
March 1−31, 2011		-			-
Total second quarter repurchases	0.25
Total first quarter Unit Repurchase Program repurchases		2.00

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. [Removed and Reserved]

Item 5. Other Information

Not applicable.

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Index

PDC 2003-B ~~LIMITED~~Limited ~~PARTNERSHIP~~Partnership

(A West Virginia Limited Partnership)

Item 6. ~~Exhibits~~ ~~Index~~Exhibits

The exhibits presented below are in addition to those presented in the Partnership’'s Form 10-K and subsequent quarterly filings on Form 10-Q.

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

ExhibitNumber

Exhibit Description

Form

SEC FileNumber

Exhibit

Filing Date

FiledHerewith

31.1

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

31.2

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

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.

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Index

PDC 2003-B ~~LIMITED~~Limited ~~PARTNERSHIP~~Partnership

(A West Virginia Limited Partnership)

SIGNATURES

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

PDC 2003-B Limited Partnership

By its Managing General Partner

Petroleum Development Corporation (dba PDC Energy)

By: /s/ ~~Richard~~James WM. ~~McCullough~~Trimble James M. TrimbleChief Executive Officerof Petroleum Development Corporation (dba PDC Energy) August 12, 2011

Richard W. McCullough

Chairman and Chief Executive Officer

of Petroleum Development Corporation (dba PDC Energy)

May 10, 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 10, 2011
/s/ James M. Trimble	Chief Executive Officer	August 12, 2011
Richard W. McCullough	Petroleum Development Corporation (dba PDC Energy)
James M. Trimble	Petroleum Development Corporation (dba PDC Energy)Managing General Partner of the Registrant
	Managing General Partner of the Registrant
	(Principal executive officer)
	(Principal executive officer)
/s/ Gysle R. Shellum	Chief Financial Officer	August 12, 2011
/s/ Gysle R. Shellum	Chief Financial Officer		May 10, 2011
Gysle R. Shellum	Petroleum Development Corporation (dba PDC Energy)Managing General Partner of the Registrant
Gysle R. Shellum	Petroleum Development Corporation (dba PDC Energy)
	(Principal financial officer)
	Managing General Partner of the Registrant
/s/ R. Scott Meyers	Chief Accounting Officer	August 12, 2011
	(Principal financial officer)
R. Scott Meyers	Petroleum Development Corporation (dba PDC Energy)Managing General Partner of the Registrant
/s/ R. Scott Meyers	Chief Accounting Officer		May 10, 2011
	(Principal accounting officer)
R. Scott Meyers	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
	(Principal accounting officer)

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Filing Compare · PDC 2003-B LP