UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2009

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

OF 1934 FOR THE TRANSITION PERIOD ____________ TO ____________

Commission File Number 000-51219

PDC 2004-B Limited Partnership

(Exact name of registrant as specified in its charter)

West Virginia	20-0547318
(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 and (2) has been subject to such filing requirements for the past 90 days.

Yes o No x

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

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

Large accelerated filer o	Accelerated filer o

Non-accelerated filer o	Smaller reporting company x

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

As of November 30, 2009 the Partnership had 899.94 units of limited partnership interest and no units of additional general partnership interest outstanding.

PDC 2004-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

INDEX TO REPORT ON FORM 10-Q

		Page
	PART I – FINANCIAL INFORMATION

Item 1.	Condensed Financial Statements (unaudited)
	Condensed Balance Sheets	1
	Condensed Statements of Operations	2
	Condensed Statements of Cash Flows	3
	Notes to Unaudited Condensed Financial Statements	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	23
Item 4T.	Controls and Procedures	23

	PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	25
Item 1A.	Risk Factors	25
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	25
Item 3.	Defaults Upon Senior Securities	25
Item 4.	Submission of Matters to a Vote of Security Holders	25
Item 5.	Other Information	25
Item 6.	Exhibits	26

	SIGNATURES	27

Index

PART I – FINANCIAL INFORMATION

Item 1. Condensed Financial Statements (unaudited)

PDC 2004-B Limited Partnership

Condensed Balance Sheets

(unaudited)

	June 30,			December 31,
	2009				2008*
Assets

Current assets:
Cash and cash equivalents	$	91,810		$	91,612
Accounts receivable		110,452			147,587
Oil inventory		11,314			21,608
Due from Managing General Partner-derivatives		809,502			995,593
Due from Managing General Partner-other, net		558,230			964,412
Total current assets		1,581,308			2,220,812


Oil and gas properties, successful efforts method, at cost		20,096,645			20,106,098
Less: Accumulated depreciation, depletion and amortization		(8,861,119	)		(8,156,676	)
Oil and gas properties, net		11,235,526			11,949,422

Due from Managing General Partner-derivatives		45,662			319,803
Other assets		13,830			7,464
Total noncurrent assets		11,295,018			12,276,689

Total Assets	$	12,876,326		$	14,497,501

Liabilities and Partners' Equity

Current liabilities:
Accounts payable and accrued expenses	$	17,702		$	30,331
Due to Managing General Partner-derivatives		71,330			-
Total current liabilities		89,032			30,331

Due to Managing General Partner-derivatives		695,880			100,327
Asset retirement obligations		166,129			161,487
Total liabilities		951,041			292,145

Commitments and contingent liabilities

Partners' equity:
Managing General Partner		2,388,928			2,844,942
Limited Partners - 899.94 units issued and outstanding		9,536,357			11,360,414
Total Partners' equity		11,925,285			14,205,356

Total Liabilities and Partners' Equity	$	12,876,326		$	14,497,501

*Derived from audited December 31, 2008 balance sheet contained in the Partnership’s Form 10-K for the year ended December 31, 2008.

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2004-B Limited Partnership

Condensed Statements of Operations

(unaudited)

	Three months ended June 30,						Six months ended June 30,
	2009			2008			2009			2008
Revenues:
Oil and gas sales	$	306,926		$	1,480,313		$	653,360		$	2,433,949
Oil and gas price risk management loss, net		(368,114	)		(849,553	)		(418,944	)		(1,248,379	)
Total revenues		(61,188	)		630,760			234,416			1,185,570

Operating costs and expenses:
Production and operating costs		139,995			295,585			265,025			487,272
Direct costs - general and administrative		116,295			12,556			258,321			19,360
Depreciation, depletion and amortization		347,088			394,122			704,443			732,811
Accretion of asset retirement obligations		2,321			2,195			4,642			4,390
Total operating costs and expenses		605,699			704,458			1,232,431			1,243,833

Loss from operations		(666,887	)		(73,698	)		(998,015	)		(58,263	)

Interest income		6,663			9,516			13,772			19,739

Net loss	$	(660,224	)	$	(64,182	)	$	(984,243	)	$	(38,524	)

Net loss allocated to partners	$	(660,224	)	$	(64,182	)	$	(984,243	)	$	(38,524	)
Less: Managing General Partner interest in net loss		(132,045	)		(12,837	)		(196,849	)		(7,705	)
Net loss allocated to Investor Partners	$	(528,179	)	$	(51,345	)	$	(787,394	)	$	(30,819	)

Net loss per Investor Partner unit	$	(587	)	$	(57	)	$	(875	)	$	(34	)

Investor Partner units outstanding		899.94			899.94			899.94			899.94

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2004-B Limited Partnership

Condensed Statements of Cash Flows

(unaudited)

	Six months ended June 30,
	2009			2008
Cash flows from operating activities:
Net loss	$	(984,243	)	$	(38,524	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		704,443			732,811
Accretion of asset retirement obligations		4,642			4,390
Unrealized loss on derivative transactions		1,127,115			930,624
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable		37,135			(42,905	)
Increase in accounts receivable - other		-			(37,461	)
Decrease (increase) in oil inventory		10,294			(24,531	)
Increase in other assets		(6,366	)		(1,098	)
(Decrease) increase in accounts payable and accrued expenses		(12,629	)		101,797
Decrease (increase) in due from Managing General Partner - other, net		406,182			(379,286	)
Net cash provided by operating activities		1,286,573			1,245,817

Cash flows from investing activities:
Capital expenditures for oil and gas properties		-			(6,234	)
Refund of capital expenditures for oil and gas properties		9,453			-
Net cash provided by investing activities		9,453			(6,234	)

Cash flows from financing activities:
Distributions to Partners		(1,295,828	)		(1,234,775	)
Net cash used in financing activities		(1,295,828	)		(1,234,775	)

Net increase in cash and cash equivalents		198			4,808
Cash and cash equivalents, beginning of period		91,612			43,507
Cash and cash equivalents, end of period	$	91,810		$	48,315

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2004-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2009

(unaudited)

Note 1 − General and Basis of Presentation

The PDC 2004-B Limited Partnership (the “Partnership” or the “Registrant”) was organized as a limited partnership on July 28, 2004, in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of oil and natural gas properties. Upon completion of the sale of Partnership units on July 28, 2004, the Partnership was funded and commenced its business operations. The Partnership owns natural gas and oil wells located in Colorado, and from the wells, the Partnership produces and sells natural gas and oil.

Purchasers of partnership units subscribed to and fully paid for 4.77 units of limited partner interests and 895.17 units of additional general partner interests at $20,000 per unit. In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), Petroleum Development Corporation, a Nevada Corporation, is the Managing General Partner of the Partnership (hereafter, the “Managing General Partner,” “MGP” or “PDC”) and has a 20% Managing General Partner ownership in the Partnership. Upon completion of the drilling phase of the Partnership's wells, all additional general partners units were converted into units of limited partner interests and thereafter became limited partners of the Partnership. Throughout the term of the Partnership, revenues, costs, and cash distributions are allocated 80% to the limited and additional general partners (collectively, the “Investor Partners”), which are shared pro rata based upon the portion of units owned in the Partnership, and 20% to the Managing General Partner.

As of June 30, 2009, there were 664 Investor Partners. As of June 30, 2009, the Managing General Partner has repurchased 17.02 units of the total 899.94 outstanding units of Partnership interests from Investor Partners at an average price of $9,955 per unit and, as a result, participates in the sharing of revenues, costs and cash distributions as both an Investor Partner and as the Managing General Partner.

The Managing General Partner is authorized, under the terms of the Drilling and Operating Agreement (the “D&O Agreement”), to conduct and manage the Partnership’s business.

The accompanying interim unaudited condensed financial statements have been prepared without audit in accordance with accounting principles generally accepted in the United States of America, or U.S., for interim financial information and with the instructions to Form 10-Q and Article 8 of Regulation S-X of the Securities and Exchange Commission, or SEC. Accordingly, pursuant to certain rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. In the Partnership’s opinion, the accompanying interim unaudited condensed financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the Partnership's financial position, results of operations and cash flows for the periods presented. The interim results of operations and cash flows for the six months ended June 30, 2009 and 2008 are not necessarily indicative of the results to be expected for the full year or any other future period.

The accompanying interim unaudited condensed financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Partnership's Form 10-K for the year ended December 31, 2008, as filed with the SEC on October 26, 2009 (“the 2008 Form 10-K”).

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Index

PDC 2004-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2009

(unaudited)

Note 2 − Recent Accounting Standards

Recently Adopted Accounting Standards

In December 2007, the Financial Accounting Standards Board, or FASB, issued Statement of Financial Accounting Standards, or FAS, No. 141 (revised 2007), Business Combinations, or FAS No. 141(R). FAS No. 141(R) requires an acquirer to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their acquisition-date fair values. FAS No. 141(R) also requires disclosure of the information necessary for investors and other users to evaluate and understand the nature and financial effect of the business combination. Additionally, FAS No. 141(R) requires that acquisition-related costs be expensed as incurred. The provisions of FAS No. 141(R) are effective for acquisitions completed on or after January 1, 2009; however, the income tax provisions of FAS No. 141(R) became effective as of that date for all acquisitions, regardless of the acquisition date. FAS No. 141(R) amends FAS No. 109, Accounting for Income Taxes, to require the acquirer to recognize changes in the amount of its deferred tax benefits recognizable due to a business combination either in income from continuing operations in the period of the combination or directly in contributed capital, depending on the circumstances. FAS No. 141(R) further amends FAS No. 109 and FASB Interpretation No. (“FIN”) 48, Accounting for Uncertainty in Income Taxes, to require, subsequent to a prescribed measurement period, changes to acquisition-date income tax uncertainties to be reported in income from continuing operations and changes to acquisition-date acquiree deferred tax benefits to be reported in income from continuing operations or directly in contributed capital, depending on the circumstances. In April 2009, the FASB issued FASB Staff Position, or FSP, No. FAS 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies (“FSP-141(R)-1”), amending the guidance of FAS No. 141(R) to require that assets acquired and liabilities assumed in a business combination that arise from contingencies be recognized at fair value if fair value can be reasonably estimated and if not, the asset and liability would generally be recognized in accordance with FAS No. 5, Accounting for Contingencies, and FASB Interpretation No. 14, Reasonable Estimation of the Amount of a Loss. Further, FSP 141(R)-1 requires that certain acquired contingencies be treated as contingent consideration and measured both initially and subsequently at fair value. The Partnership adopted the provisions of FAS No. 141(R) and FSP 141(R)-1 effective January 1, 2009, for which the provisions will be applied prospectively in the Partnership’s accounting for future acquisitions, if any. This adoption had no impact on the Partnership’s financial statements.

In December 2007, the FASB issued FAS No. 160, Non-controlling Interests in Consolidated Financial Statements—An Amendment of ARB No. 51 (“FAS No. 160”). FAS No. 160 requires the accounting and reporting for minority interests to be recharacterized as non-controlling interests and classified as a component of equity. Additionally, FAS No. 160 establishes reporting requirements that provide sufficient disclosures which clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. The Partnership’s adoption of the provisions of FAS No. 160 effective January 1, 2009 had no material impact on the Partnership’s financial statements.

In February 2008, the FASB issued FSP No. 157-2, Effective Date of FASB Statement No. 157, which delayed the effective date of FAS No. 157, Fair Value Measurements, by one year (to January 1, 2009) for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Effective January 1, 2009, the Partnership adopted the provisions of FAS No. 157 with respect to nonfinancial assets and liabilities as delayed by FSP 157-2. The adoption of FSP 157-2 did not have a material impact on the Partnership’s financial statements. See Note 4, Fair Value Measurements.

In March 2008, the FASB issued FAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—An Amendment of FASB Statement No. 133, which changes the disclosure requirements for derivative instruments and hedging activities. Enhanced disclosures are required to provide information about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The Partnership adopted the provisions of FAS No. 161 effective January 1, 2009. The adoption of FAS No. 161 did not have a material impact on the Partnership’s financial statements. For more information on the Partnership’s derivative accounting, see Note 5, Derivative Financial Instruments.

In May 2009, the FASB issued FAS No. 165, Subsequent Events (“FAS No. 165”). FAS No. 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. Specifically, FAS No. 165 sets forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements, and the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. FAS No. 165 is effective for interim or annual periods ending after June 15, 2009, and is applied prospectively. The Partnership adopted FAS No. 165 as of June 30, 2009.

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Index

PDC 2004-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2009

(unaudited)

Recently Issued Accounting Standards

In January 2009, the SEC published its final rule regarding the modernization of oil and gas reporting (the "final rule"), which modifies the SEC’s reporting and disclosure rules for oil and natural gas reserves. The most notable changes of the final rule include the replacement of the single day period-end pricing to value oil and natural gas reserves to a 12-month average of the first day of the month price for each month within the reporting period and also permits voluntary disclosure of probable and possible reserves, a disclosure previously prohibited by SEC rules. The final rule also reiterates that the definition of proved undeveloped oil and gas reserves require that the Partnership adopt a development plan with respect to these reserves. Additionally, the final rule reiterates the documentation requirements which must be met to classify reserves as proved undeveloped. The development plan which has been adopted should indicate that these reserves are scheduled to be developed within five years, unless specific circumstances justify a longer time.

The revised reporting and disclosure requirements are effective for the Partnership’s Annual Report on Form 10-K for the year ending December 31, 2009. Early adoption is not permitted. We are evaluating the impact that adoption of this final rule will have on the Partnership’s financial statements, related disclosure and management’s discussion and analysis.

In June 2009, the FASB issued FAS No. 167, Amendments to FASB Interpretation No. 46(R), to improve financial reporting by enterprises involved with variable interest entities by addressing (1) the effects on certain provisions of FIN 46 (revised December 2003) (“FIN 46(R)”), Consolidation of Variable Interest Entities, as a result of the elimination of the qualifying special-purpose entity concept in FAS No. 166, Accounting for Transfers of Financial Assets, and (2) constituent concerns about the application of certain key provisions of FIN 46(R), including those in which the accounting and disclosures under the Interpretation do not always provide timely and useful information about an enterprise’s involvement in a variable interest entity. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2009, with earlier adoption prohibited. We are evaluating the impact that the adoption of FAS No. 167 will have on the Partnership’s financial statements, related disclosure and management’s discussion and analysis.

In June 2009, the FASB issued FAS No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles. This standard replaces FAS No. 162, The Hierarchy of Generally Accepted Accounting Principles, and establishes only two levels of U.S. GAAP, authoritative and non-authoritative. The FASB Accounting Standards Codification (the “Codification”) will become the source of authoritative, nongovernmental U.S. generally accepted accounting principles (“GAAP”), except for rules and interpretive releases of the SEC, which are sources of authoritative GAAP for SEC registrants. All other non-grandfathered, non-SEC accounting literature not included in the Codification will become non-authoritative. This standard is effective for financial statements issued for fiscal years and interim periods ending after September 15, 2009. As the Codification was not intended to change or alter existing GAAP, we do not expect the adoption to have a material impact on the Partnership’s financial statements.

In August 2009, the FASB issued Accounting Standards Update No. 2009-05, Measuring Liabilities at Fair Value (“ASU 2009-05”) which provides amendments to Accounting Standards Codification, or ASC, Topic 820, Fair Value Measurements and Disclosure, to reduce potential ambiguity in financial reporting when measuring the fair value of liabilities. These changes clarify existing guidance that in circumstances in which a quoted price in an active market for the identical liability is not available, an entity is required to measure fair value using either a valuation technique that uses a quoted price of either a similar liability or a quoted price of an identical or similar liability when traded as an asset, or another valuation technique that is consistent with the principles of fair value measurements, such as an income approach (e.g., present value technique). This guidance also states that both a quoted price in an active market for the identical liability and a quoted price for the identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required are Level 1 fair value measurements. These changes become effective for the Partnership on October 1, 2009. The Partnership has not determined the impact, if any, that these changes will have on the Partnership’s financial statements.

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Index

PDC 2004-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2009

(unaudited)

Note 3 − Transactions with Managing General Partner and Affiliates

The Managing General Partner transacts business on behalf of the Partnership under the authority of the D&O Agreement. Revenues and other cash inflows received on behalf of the Partnership are distributed to the Partners net of (after deducting) corresponding operating costs and other cash outflows incurred on behalf of the Partnership.

The fair value of the Partnership’s portion of unexpired derivative instruments is recorded on the balance sheet under the captions “Due from Managing General Partner–derivatives,” in the case of net unrealized gains or “Due to Managing General Partner–derivatives,” in the case of net unrealized losses.

Undistributed oil and natural gas revenues collected by the Managing General Partner from the Partnership’s customers in the amount of $196,473 and $258,733 as of June 30, 2009 and December 31, 2008, respectively, are included in the balance sheet caption “Due from Managing General Partner - other, net.” Realized gains or losses from derivative transactions that have not yet been distributed to the Partnership are included in the balance sheet captions “Due from Managing General Partner-other, net” or “Due to Managing General Partner-other, net,” respectively. Undistributed realized gains amounted to $283,438 and $350,255 as of June 30, 2009 and December 31, 2008, respectively. All other unsettled transactions between the Partnership and the Managing General Partner are recorded net on the balance sheet under the caption “Due from (to) Managing General Partner – other, net.”

The following table presents transactions with the Managing General Partner and its affiliates for the periods described below. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in “Production and operating costs” on the Statements of Operations. Additionally, refer to Note 5, Derivative Financial Instruments for derivative transactions between the Partnership and the Managing General Partner.

	Three months ended June 30,				Six months ended June 30,
	2009		2008		2009		2008

Well operations and maintenance	$	98,852	$	118,076	$	181,681	$	190,886
Gathering, compression and processing fees		23,441		39,157		45,926		70,092
Direct costs - general and administrative		116,295		12,556		258,321		19,360
Cash distributions*		170,742		153,456		276,524		255,041

*Cash distributions include $12,008 and $17,359 during the three and six months ended June 30, 2009, respectively, and $5,076 and $8,087 during the three and six months ended June 30, 2008, respectively, related to equity cash distributions on Investor Partner units repurchased by PDC. For additional disclosure regarding the Unit Repurchase Program, refer to Note 1, General and Basis of Presentation.

Note 4 − Fair Value Measurements

Determination of Fair Value. The Partnership determines the fair value of its assets and liabilities, unless specifically excluded, pursuant to FAS No. 157. FAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

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Index

PDC 2004-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2009

(unaudited)

FAS No. 157 establishes a fair value hierarchy that requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:

Level 1 – Quoted prices (unadjusted) in active markets for identical assets or liabilities. Included in Level 1 are commodity derivative instruments for New York Mercantile Exchange, or NYMEX, natural gas swaps.

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. Included in Level 3 are the Partnership’s commodity derivative instruments for Colorado Interstate Gas, or CIG, based fixed-price natural gas swaps, collars and floors, oil swaps, and natural gas basis protection swaps.

Derivative Financial Instruments. The Partnership measures fair value based upon quoted market prices, where available. The valuation determination includes: (1) identification of the inputs to the fair value methodology through the review of counterparty statements and other supporting documentation, (2) determination of the validity of the source of the inputs, (3) corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. The methods described above may produce a fair value calculation that may not be indicative of future fair values. The valuation determination also gives consideration to nonperformance risk on Partnership liabilities in addition to nonperformance risk on PDC’s own business interests and liabilities, as well as the credit standing of derivative instrument counterparties. The Managing General Partner primarily uses two investment grade financial institutions as counterparties to its derivative contracts, who hold the majority of the Managing General Partner’s derivative assets. The Managing General Partner has evaluated the credit risk of the Partnership’s derivative assets from counterparties holding its derivative assets using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on the Managing General Partner’s evaluation, the Partnership has determined that the impact of counterparty non-performance on the fair value of the Partnership’s derivative instruments is insignificant. As of June 30, 2009, no adjustment for credit risk was recorded by the Partnership. Furthermore, while the Managing General Partner believes these valuation methods are appropriate and consistent with that used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

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Index

PDC 2004-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2009

(unaudited)

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

	Level 1			Level 3			Total

As of December 31, 2008
Assets:
Commodity based derivatives	$	-		$	1,315,396		$	1,315,396
Total assets		-			1,315,396			1,315,396

Liabilities:		-			-
Basis protection derivative contracts		-			(100,327	)		(100,327	)
Total liabilities		-			(100,327	)		(100,327	)

Net asset	$	-		$	1,215,069		$	1,215,069

As of June 30, 2009
Assets:
Commodity based derivatives	$	45		$	855,119		$	855,164
Total assets		45			855,119			855,164

Liabilities:
Commodity based derivatives		(65,940	)	$	(2,798	)		(68,738	)
Basis protection derivative contracts		-			(698,472	)		(698,472	)
Total liabilities		(65,940	)		(701,270	)		(767,210	)

Net (liability) asset	$	(65,895	)	$	153,849		$	87,954

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

	Six months ended
	June 30, 2009
Fair value, net asset, as of December 31, 2008	$	1,215,069
Changes in fair value included in statement of operations line item:
Oil and gas price risk management loss, net		(353,049	)
Settlements		(708,171	)
Fair value, net asset, as of June 30, 2009	$	153,849

Change in unrealized gains (losses) relating to assets (liabilities) still held as of June 30, 2009, included in statement of operations line item:
Oil and gas price risk management, net	$	(501,651	)

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

Non-Derivative Assets and Liabilities. The carrying values of the financial instruments comprising “Cash and cash equivalents,” “Accounts receivable,” “Accounts payable and accrued expenses” and “Due to (from) Managing General Partner-other, net” approximate fair value due to the short-term maturities of these instruments.

In accordance with FAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Partnership periodically assesses its proved oil and gas properties for possible impairment, upon a triggering event, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon estimated prices at which the Partnership reasonably estimates the commodity to be sold. The estimates of future prices may differ from current market prices of oil and natural gas. Certain events, including but not limited to, downward revisions in estimates to the Partnership’s reserve quantities, expectations of falling commodity prices or rising operating costs may result in a triggering event and, therefore, a possible impairment of the Partnership’s oil and natural gas properties. If, when assessing impairment, net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flow analysis and is measured by the amount by which the net capitalized costs exceed their fair value. During the six months ended June 30, 2009 and 2008, there were no triggering events; therefore, no impairment of oil and gas properties was recognized.

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Index

PDC 2004-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2009

(unaudited)

The Partnership accounts for asset retirement obligations by recording the estimated fair value of the plugging and abandonment obligations when incurred, at the time the well is completely drilled. The Partnership estimates the fair value of the plugging and abandonment obligations based on a discounted cash flows analysis. Upon initial recognition of an asset retirement obligation, the Partnership increases the carrying amount of the long-lived asset by the same amount as the liability. Periodically, the liabilities are accreted for the change in present value, through charges to “Accretion of asset retirement obligations” on the statement of operations. The initial capitalized costs are depleted based on the useful lives of the related assets, through charges to depreciation, depletion and amortization, or DD&A. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations.

Note 5 − Derivative Financial Instruments

The Partnership is exposed to the effect of market fluctuations in the prices of oil and natural gas. Price risk represents the potential risk of loss from adverse changes in the market price of oil and natural gas commodities. The Managing General Partner employs established policies and procedures to manage the risks associated with these market fluctuations using derivative instruments. Partnership policy prohibits the use of oil and natural gas derivative instruments for speculative purposes.

The Partnership recognizes all derivative instruments as either assets or liabilities on the accompanying interim unaudited condensed balance sheets at fair value. The Partnership has elected not to designate any of the Partnership’s derivative instruments as hedges. Accordingly, changes in the fair value of those derivative instruments allocated to the Partnership are recorded in the Partnership’s statements of operations. Changes in the fair value of derivative instruments related to the Partnership’s oil and gas sales activities are recorded in “Oil and gas price risk management, net.”

Valuation of a contract’s fair value is performed internally. While the Managing General Partner uses common industry practices to develop the Partnership’s valuation techniques, changes in pricing methodologies or the underlying assumptions could result in different fair values. See Note 4, Fair Value Measurements, for a discussion of how the Managing General Partner determines the fair value of the Partnership’s derivative instruments.

As of September 30, 2009, the Managing General Partner had derivative contracts in place for a portion of the Partnership’s anticipated production through 2012 for a total of 491 MMbtu of natural gas and 9 MBbls of crude oil. During late October 2009, the Managing General Partner entered into additional NYMEX fixed-price gas swaps (ranging from $6.67 to $7.11 per MMbtu) and NYMEX gas collars (floors ranging from $6.00 to $6.10 and ceilings ranging from $8.27 to $8.60 per MMbtu) covering all monthly periods from November 2010 to December 2013. The Partnership will be allocated positions by the Managing General Partner for MMbtu’s equal to the number of remaining MMbtu’s of CIG basis protection swaps at September 30, 2009 which were not previously covered by NYMEX fixed-price gas swaps or gas collars.

Derivative Strategies. The Partnership’s results of operations and operating cash flows are affected by changes in market prices for oil and natural gas. To mitigate a portion of the exposure to adverse market changes, the Managing General Partner has entered into various derivative contracts.

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Index

PDC 2004-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2009

(unaudited)

For Partnership oil and gas sales, the Managing General Partner enters into, for a portion of the Partnership’s production, derivative contracts to protect against price declines in future periods. While these derivatives are structured to reduce exposure to changes in price associated with the derivative commodity, they also limit the benefit the Partnership might otherwise have received from price increases in the physical market. The Partnership believes the derivative instruments in place continue to be effective in achieving the risk management objectives for which they were intended.

As of June 30, 2009, the Partnership’s oil and natural gas derivative instruments were comprised of commodity collars, commodity swaps and basis protection swaps.

Collars contain a fixed floor price (put) and ceiling price (call). If the market price falls below the fixed put strike price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the put strike price and market price from the counterparty. If the market price exceeds the fixed call strike price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the call strike price and market price to the counterparty. If the market price is between the call and put strike price, no payments are due to or from the counterparty.

Swaps are arrangements that guarantee a fixed price. If the market price is below the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the market price and the fixed contract price from the counterparty. If the market price is above the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the market price and the fixed contract price to the counterparty.

Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG basis protection swaps, which traditionally have negative differentials to NYMEX, PDC, as Managing General Partner, receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.

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Index

PDC 2004-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2009

(unaudited)

The following table summarizes the location and fair value amounts of the Partnership’s derivative instruments in the accompanying balance sheets as of June 30, 2009, and December 31, 2008.

			Fair Value
		Balance Sheet	June 30,			December 31,
Derivative instruments not designated as hedge (1):		Line Item	2009			2008

Derivative Assets:	Current
	Commodity contracts	Due from Managing General Partner-derivatives	$	809,502		$	995,593

	Non Current
	Commodity contracts	Due from Managing General Partner-derivatives		45,662			319,803
Total Derivative Assets			$	855,164		$	1,315,396

Derivative Liabilities:	Current
	Commodity contracts	Due to Managing General Partner-derivatives	$	(13,783	)	$	-

	Basis protection contracts	Due to Managing General Partner-derivatives		(57,547	)		-

	Non Current
	Commodity contracts	Due to Managing General Partner-derivatives		(54,955	)		-

	Basis protection contracts	Due to Managing General Partner-derivatives		(640,925	)		(100,327	)
Total Derivative Liabilities			$	(767,210	)	$	(100,327	)

(1) As of June 30, 2009 and December 31, 2008, none of the Partnership’s derivative instruments were designated hedges.

The following table summarizes the impact of the Partnership’s derivative instruments on the Partnership’s accompanying statements of operations for the three months and six months ended June 30, 2009 and 2008.

	Three months ended June 30,
	2009									2008
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 (Losses) For the Current Period			Total

Oil and gas price risk management, net
Realized gains (losses)	$	302,139		$	(18,698	)	$	283,441		$	(113,977	)	$	(168,883	)	$	(282,860	)
Unrealized (losses) gains		(302,139	)		(349,416	)		(651,555	)		113,977			(680,670	)		(566,693	)
Total oil and gas price risk management, net	$	-		$	(368,114	)	$	(368,114	)	$	-		$	(849,553	)	$	(849,553	)

	Six months ended June 30,
	2009									2008
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 (Losses) For the Current Period			Total

Oil and gas price risk management, net
Realized gains (losses)	$	556,781		$	151,390		$	708,171		$	(28,199	)	$	(289,556	)	$	(317,755	)
Unrealized (losses) gains		(556,781	)		(570,334	)		(1,127,115	)		28,199			(958,823	)		(930,624	)
Total oil and gas price risk management, net	$	-		$	(418,944	)	$	(418,944	)	$	-		$	(1,248,379	)	$	(1,248,379	)

Concentration of Credit Risk. A significant portion of the Partnership’s liquidity is concentrated in derivative instruments that enables the Partnership to manage a portion of its exposure to price volatility from producing oil and natural gas. These arrangements expose the Partnership to credit risk of nonperformance by the counterparties. The Managing General Partner primarily uses two financial institutions, who are also major lenders in the Managing General Partner’s credit facility agreement, as counterparties to the derivative contracts.

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Index

PDC 2004-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2009

(unaudited)

Note 6 − Commitments and Contingencies

Colorado Royalty Settlement. On May 29, 2007, Glen Droegemueller, individually and as representative plaintiff on behalf of all others similarly situated, filed a class action complaint against the Managing General Partner in the District Court, Weld County, Colorado alleging that the Managing General Partner underpaid royalties on natural gas produced from wells operated by the Managing General Partner in parts of the State of Colorado (the “Droegemueller Action”). The plaintiff sought declaratory relief and to recover an unspecified amount of compensation for underpayment of royalties paid by the Managing General Partner pursuant to leases. The Managing General Partner moved the case to Federal Court on June 28, 2007. On October 10, 2008, the court preliminarily approved a settlement agreement between the plaintiffs and the Managing General Partner, on behalf of itself and the Partnership. Although the Partnership was not named as a party in the suit, the lawsuit states that this action relates to all wells operated by the Managing General Partner, which includes a majority of the Partnership’s 16 wells in the Wattenberg field. The portion of the settlement relating to the Partnership’s wells for all periods through June 30, 2009 that has been expensed by the Partnership is approximately $19,000 including associated legal costs of approximately $1,000. This entire settlement of $17,713 was deposited by the Managing General Partner into an escrow account on November 3, 2008. Notice of the settlement was mailed to members of the class action suit in the fourth quarter of 2008. The final settlement was approved by the court on April 7, 2009. Settlement distribution checks were mailed in July 2009. During September 2009, all settlement costs were passed through to the Partners and related required judicial action from the settlement of the suit was implemented in this distribution.

Colorado Stormwater Permit. On December 8, 2008, the Managing General Partner received a Notice of Violation /Cease and Desist Order (the “Notice”) from the Colorado Department of Public Health and Environment, related to the stormwater permit for the Garden Gulch Road. The Managing General Partner manages this private road for Garden Gulch LLC. The Managing General Partner is one of eight users of this road, all of which are oil and gas companies operating in the Piceance region of Colorado. Operating expenses, including amounts arising from this notice, if any, are allocated among the eight users of the road based upon their respective usage. The Partnership has seven wells in this region. The Notice alleges a deficient and/or incomplete stormwater management plan, failure to implement best management practices and failure to conduct required permit inspections. The Notice requires corrective action and states that the recipient shall cease and desist such alleged violations. The Notice states that a violation could result in civil penalties up to $10,000 per day. The Managing General Partner’s responses were submitted on February 6, 2009, and April 8, 2009. No civil penalties have been imposed or requested at this time. Given the preliminary stage of this proceeding and the inherent uncertainty in administrative actions of this nature, the Managing General Partner is unable to predict the ultimate outcome of this administrative action at this time and therefore no amounts have been recorded on the Partnership’s financial records.

Derivative Contracts. The Partnership is exposed to oil and natural gas price fluctuations on underlying sales contracts should the counterparties to the Managing General Partner’s derivative instruments not perform. The Managing General Partner has had no counterparty default losses and expects full performance by the counterparties to these agreements in the future.

Note 7−Subsequent Events

We have evaluated the Partnership’s activities subsequent to June 30, 2009, through December 18, 2009 (the date the financial statements were issued), and have concluded that no subsequent events have occurred that would require recognition in the Partnership’s financial statements or disclosure in the notes to the unaudited condensed financial statements.

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Index

PDC 2004-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

Special Note Regarding Forward Looking Statements

This periodic report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”) regarding PDC 2004-B Limited Partnership’s (the “Partnership’s” or the “Registrant’s”) business, financial condition, results of operations and prospects. All statements other than statements of historical facts included in and incorporated by reference into this report are forward-looking statements. Words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “seeks,” “estimates” and similar expressions or variations of such words are intended to identify forward-looking statements herein, which include statements of estimated oil and natural gas production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and the Managing General Partner Petroleum Development Corporation’s (“MGP’s” or “PDC’s”) strategies, plans and objectives. However, these are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect the Managing General Partner's good faith judgment, such statements can only be based on facts and factors currently known to the Managing General Partner. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including risks and uncertainties incidental to the development, production and marketing of natural gas and oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

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

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

future production and development costs;

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

the effect of existing and future laws, governmental regulations and the political and economic climate of the United States of America;

the effect of natural gas and oil derivatives activities;

conditions in the capital markets; and

losses possible from pending or future litigation.

Further, the Partnership urges you to carefully review and consider the cautionary statements made in this report, the Partnership’s annual report on Form 10-K for the year ended December 31, 2008 filed with the Securities and Exchange Commission (“SEC”) on October 26, 2009 (“2008 Form 10-K”), and the Partnership’s other filings with the SEC and public disclosures. The Partnership cautions you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. The Partnership undertakes no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events.

Overview

PDC 2004-B Limited Partnership engages in the development, production and sale of oil and natural gas. The Partnership began oil and gas operations in July 2004 and currently operates 23 gross (20.9 net) wells located in the Rocky Mountain Region in the state of Colorado. The Managing General Partner markets the Partnership’s natural gas production to commercial end users, interstate or intrastate pipelines or local utilities, primarily under market sensitive contracts in which the price of natural gas sold varies as a result of market forces. PDC, on behalf of the Partnership through the D&O Agreement, may enter into multi-year fixed price contracts or utilize derivatives, including collars, swaps or basis protection swaps, in order to offset some or all of the commodity price variability for particular periods of time. Seasonal factors, such as effects of weather on prices received and costs incurred, and availability of pipeline capacity, owned by PDC or other third parties, may impact the Partnership's results. In addition, both sales volumes and prices could be affected by demand factors with a seasonal component.

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Index

PDC 2004-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Results of Operations

The following table sets forth selected information regarding the Partnership’s results of operations, including production volumes, oil and natural gas sales, average sales prices received, average sales price including realized derivative gains and losses, production and operating costs, depreciation, depletion and amortization costs, other operating income and expenses for the three and six months ended June 30, 2009, or the current three and six month periods and the three and six months ended June 30, 2008, or the prior three and six month periods.

	Summary of Operating Results
	Three months ended June 30,									Six months ended June 30,
	2009			2008			Change			2009			2008			Change
Number of producing wells (end of period)		23			23			-			23			23			-

Production: (1)
Oil (Bbl)		2,515			2,557			-2	%		5,217			4,927			6	%
Natural gas (Mcf)		87,440			143,040			-39	%		171,444			255,501			-33	%
Natural gas equivalents (Mcfe) (2)		102,530			158,382			-35	%		202,746			285,063			-29	%

Average Selling Price (excluding realized gain (loss) on derivatives)
Oil (per Bbl)	$	51.64		$	113.51			-55	%	$	43.85		$	98.31			-55	%
Natural gas (per Mcf)		2.02			8.32			-76	%		2.48			7.63			-68	%
Natural gas equivalents (per Mcfe)		2.99			9.35			-68	%		3.22			8.54			-62	%

Realized Gain (Loss) on Derivatives, net
Oil derivatives - realized gain (loss)	$	43,108		$	(45,232	)		195	%	$	108,535		$	(56,117	)		*
Natural gas derivatives - realized gain (loss)		240,333			(237,628	)		201	%		599,636			(261,638	)		*
Total realized gain (loss) on derivatives, net	$	283,441		$	(282,860	)		200	%	$	708,171		$	(317,755	)		*

Average Selling Price (including realized gain (loss) on derivatives)
Oil (per Bbl)	$	68.78		$	95.82			-28	%	$	64.65		$	86.92			-26	%
Natural gas (per Mcf)		4.77			6.66			-28	%		5.97			6.61			-10	%
Natural gas equivalents (per Mcfe)		5.76			7.56			-24	%		6.72			7.42			-10	%

Average cost per Mcfe
Production and operating costs (3)	$	1.37		$	1.87			-27	%	$	1.31		$	1.71			-24	%
Depreciation, depletion and amortization		3.39			2.49			36	%		3.47			2.57			35	%

Revenues:
Oil and natural gas sales	$	306,926		$	1,480,313			-79	%	$	653,360		$	2,433,949			-73	%
Realized gain (loss) on derivatives, net		283,441			(282,860	)		-200	%		708,171			(317,755	)		*
Unrealized loss on derivatives, net		(651,555	)		(566,693	)		15	%		(1,127,115	)		(930,624	)		21	%
Total revenues	$	(61,188	)	$	630,760			-110	%	$	234,416		$	1,185,570			-80	%

Operating costs and expenses:
Production and operating costs	$	139,995		$	295,585			-53	%	$	265,025		$	487,272			-46	%
Direct costs - general and administrative		116,295			12,556			*			258,321			19,360			*
Depreciation, depletion and amortization		347,088			394,122			-12	%		704,443			732,811			-4	%
Accretion of asset retirement obligations		2,321			2,195			6	%		4,642			4,390			6	%
Total operating costs and expenses	$	605,699		$	704,458			-14	%	$	1,232,431		$	1,243,833			-1	%

Loss from operations	$	(666,887	)	$	(73,698	)		-805	%	$	(998,015	)	$	(58,263	)		-1613	%

Interest income		6,663			9,516			-30	%		13,772			19,739			-30	%

Net loss	$	(660,224	)	$	(64,182	)		-929	%	$	(984,243	)	$	(38,524	)		-2455	%

Cash distributions	$	793,670		$	741,902			7	%	$	1,295,828		$	1,234,775			5	%

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

_______________

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

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

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

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Index

PDC 2004-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

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

MBbl – One thousand barrels

Mcf – One thousand cubic feet

MMcf – One million cubic feet

Mcfe – One thousand cubic feet of natural gas equivalents

MMcfe – One million cubic feet of natural gas equivalents

MMbtu – One million British Thermal Units

The Partnership continued to experience the depressed natural gas prices from the significant declines in late July 2008 through the second quarter of 2009. The Partnership’s production decreased to 203 MMcfe for the first six months of 2009 compared to 285 MMcfe for prior year six month period, a decrease of 29%, while the Partnership’s average sales price declined $5.32 per Mcfe, a decrease of 62%. While the Partnership certainly has felt the impact of the significant changes in commodity prices, the Managing General Partner believes that it was successful in managing the Partnership’s operations in such a manner that the Managing General Partner was able to minimize the negative impacts as the Partnership’s derivative position eased the impact. The Partnership’s realized derivative gains for the current six month period of $0.7 million added an average of $3.50 per Mcfe produced during the first six months of 2009. From May through August 2009, natural gas prices rebounded slightly while crude oil prices increased substantially to price levels that remained, however, significantly lower than those of the comparable period in 2008. At June 30, 2009, the estimated net fair value of the Partnership’s open derivative positions is a net asset of $0.1 million.

Depressed commodity prices for the six months of 2009 as compared to the higher prices in prior year’s six month period were the primary contributors to the $0.8 million change in oil and gas price risk management, net. Of the $0.8 million change, $1.0 million was related to an increase in realized derivative gains and the remaining $0.2 million was related to an increase in unrealized derivative losses. Unrealized gains and losses are non-cash items. These non-cash charges to the Partnership’s statement of operations will continue to fluctuate with the fluctuation in commodity prices until the existing positions mature or are closed, at which time they will become realized or cash items. The Partnership has elected not to designate any of the Partnership’s derivative instruments as hedges. While the required accounting treatment under Statement of Financial Accounting Standards, or FAS, No. 133, Accounting for Derivative Instruments and Certain Hedging Activities for derivatives that are not designated as hedges, may result in significant swings in operating results over the life of the derivatives, the combination of the settled derivative contracts and the revenue received from the oil and gas sales at delivery are expected to result in a more predictable cash flow stream than would the sales contracts without the associated derivatives.

The table below, which demonstrates the markets’ expected volatility in commodity pricing, sets forth the average NYMEX and CIG prices for the next 24 months (forward curve) from the selected dates:

		June 30,		September 30,		March 31,		September 30,		October 31,
Commodity	Index	2008		2008		2009		2009		2009

Natural gas: (per MMbtu)
	NYMEX	$	12.52	$	8.21	$	5.44	$	6.25	$	6.00
	CIG		8.86		5.46		4.15		5.64		5.49
Oil: (per Bbl)	NYMEX		140.15		103.63		59.35		74.64		81.26

Oil and Natural Gas Sales

Partnership production decreased to 103 MMcfe and 203 MMcfe for the current year three and six month periods, respectively, from 158 MMcfe and 285 MMcfe for the prior year three and six month periods, respectively. The Partnership’s oil and gas sales revenue for the current three and six month periods, excluding price risk management impacts, decreased from the comparable periods in 2008, by $1.2 million and $1.8 million, respectively, due to the significant decline in commodity prices and by decreased volumes. Approximately $0.7 million and $1.1 million of the decrease in oil and natural gas sales revenue for the current three month and six month periods, respectively, was due to pricing and $0.5 million and $0.7 million was due to decreased production, respectively.

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Index

PDC 2004-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

Oil and Natural Gas Pricing

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

The price the Partnership receives for the natural gas produced in the Rocky Mountain Region is based on a variety of prices, which primarily includes natural gas sold at 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, has historically been less than the price received for natural gas produced in the eastern regions, which is NYMEX based. Since March 31, 2009, this negative differential has narrowed in recent months and has even more recently become a positive differential. CIG was $1.79 lower than NYMEX in January 2009, narrowed to close at $0.37 lower in October 2009 and has more recently closed at $0.02 higher than NYMEX for November 2009.

Oil and Gas Price Risk Management, Net

The Managing General Partner uses oil and natural gas derivative instruments to manage price risk for PDC as well as its sponsored drilling partnerships. The Managing General Partner sets these instruments for PDC, and the various partnerships managed by PDC. Prior to September 30, 2008, as volumes produced changed, the mix between PDC and the partnerships changed on a pro-rata basis. Effective September 30, 2008, PDC changed the allocation procedure whereby the allocation of the derivative positions between PDC and each partnership was set at a fixed quantity. Existing positions are allocated based on fixed quantities for each position and new positions will have specific designations relative to the applicable partnership.

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Index

PDC 2004-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

The following table presents the primary composition of “Oil and gas price risk management loss, net” for the periods described:

	Three months ended June 30,						Six months ended June 30,
Oil and gas price risk management, net	2009			2008			2009			2008
Realized gains (losses)
Oil	$	43,108		$	(45,232	)	$	108,535		$	(56,117	)
Natural Gas		240,333			(237,628	)		599,636			(261,638	)
Total realized gain (loss), net		283,441			(282,860	)		708,171			(317,755	)

Unrealized gains (losses)
Reclassification of realized (gains) losses included in prior periods unrealized		(302,139	)		113,977			(556,781	)		28,199
Unrealized loss for the period		(349,416	)		(680,670	)		(570,334	)		(958,823	)
Total unrealized loss, net		(651,555	)		(566,693	)		(1,127,115	)		(930,624	)
Oil and gas price risk management loss, net	$	(368,114	)	$	(849,553	)	$	(418,944	)	$	(1,248,379	)

Realized gains recognized in the current year three and six month periods, are a result of lower oil and gas commodity prices at settlement date compared to the respective contract price. During the current year three month period, the Partnership recorded unrealized derivative losses of $0.1 million on the Partnership’s oil swaps as the forward strip price of oil increased during the quarter, along with unrealized losses on the Partnership’s CIG basis swaps of $0.2 million, as the forward basis differential between NYMEX and CIG has continued to narrow. During the current year six month period, the Partnership recorded unrealized derivative losses of $0.1 million on its oil swaps and $0.6 million on its CIG basis swaps due to the narrowing of the negative differential between NYMEX and CIG basis, as previously discussed. These decreases were offset in part by unrealized gains on the Partnership’s natural gas collars of $0.2 million.

Oil and gas price risk management, net includes realized gains and losses and unrealized changes in the fair value of derivative instruments related to the Partnership’s oil and natural gas production. See Note 4, Fair Value Measurements and Note 5, Derivative Financial Instruments, to the accompanying unaudited condensed financial statements for additional details of the Partnership’s derivative financial instruments.

Oil and Natural Gas Sales Derivative Instruments. The Managing General Partner uses various derivative instruments to manage fluctuations in oil and natural gas prices. The Partnership has in place a series of collars, fixed price swaps and basis protection swaps on a portion of the Partnership’s oil and natural gas production as set forth in the following table.

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Index

PDC 2004-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

This table identifies the Partnership’s derivative positions related to oil and gas sales activities in effect as of September 30, 2009, on the Partnership’s production. The Partnership’s production volumes for the three months ended June 30, 2009, were 2,515 Bbls of oil and 87,440 Mcf of natural gas.

	Collars								Fixed-Price Swaps				Basis Protection Swaps
	Floors				Ceilings
			Weighted				Weighted				Weighted				Weighted		Fair Value
Commodity/	Quantity		Average		Quantity		Average		Quantity		Average		Quantity		Average		At
Operating Area/	(Gas-MMbtu		Contract		(Gas-MMbtu		Contract		(Gas-MMbtu		Contract		(Gas-MMbtu		Contract		September 30,
Index	Oil-Bbls)		Price		Oil-Bbls)		Price		Oil-Bbls)		Price		Oil-Bbls)		Price		2009(1)

Natural Gas
Rocky Mountain Region
CIG
4Q 2009		53,257	$	6.67		53,257	$	8.16		19,688	$	9.20		-	$	-	$	216,404
2010		61,365		6.63		61,365		8.11		29,532		9.20		181,047		1.88		(35,508	)
2011		28,989		4.75		28,989		9.45		-		-		215,685		1.88		(237,892	)
2012		-		-		-		-		-		-		227,947		1.88		(235,262	)
2013		-		-		-		-		-		-		211,753		1.88		(202,882	)

NYMEX
2010		7,747		5.75		7,747		8.30		160,968		5.62		-		-		(85,279	)
2011		10,536		5.75		10,536		8.30		58,166		6.96		-		-		1,434
2012		-		-		-		-		61,041		6.96		-		-		(2,708	)

Total Natural Gas																		(581,693	)

Oil
Rocky Mountain Region
NYMEX
4Q 2009		-		-		-		-		1,411		90.51		-		-		27,412
2010		-		-		-		-		4,904		92.96		-		-		90,352
2011		-		-		-		-		2,822		70.75		-		-		(18,294	)
Total Oil																		99,470

Total Natural Gas and Oil																	$	(482,223	)

(1) Approximately 83% of the total fair value of the derivative instruments was measured using significant unobserved inputs (Level 3 assets and liabilities). See Note 4, Fair Value Measurements, to the accompanying interim unaudited condensed financial statements.

During late October 2009, the Managing General Partner entered into additional NYMEX fixed-price gas swaps (ranging from $6.67 to $7.11 per MMbtu) and NYMEX gas collars (floors ranging from $6.00 to $6.10 and ceilings ranging from $8.27 to $8.60 per MMbtu) covering all monthly periods from November 2010 to December 2013. The Partnership will be allocated positions by the Managing General Partner for MMbtu’s equal to the number of remaining MMbtu’s of CIG basis protection swaps at September 30, 2009 which were not previously covered by NYMEX fixed-price gas swaps or gas collars.

Production and Operating Costs

Generally, production and operating costs vary either with total oil and natural gas sales or production volumes. Property and severance taxes are estimated by the Managing General Partner based on rates determined using historical information. These amounts are subject to revision based on actual amounts determined during future filings by the Managing General Partner with the taxing authorities. Property and severance taxes vary directly with total oil and natural gas 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. General oil field services and all other costs vary and can fluctuate based on services required. These costs include water hauling and disposal, equipment repairs and maintenance, snow removal and service rig workovers.

For the six months ended June 30, 2009 compared to the same period in 2008, oil and natural gas production, on an energy equivalency-basis, decreased 29%, due to reduced production resulting from the Wattenberg Field’s high pipeline pressure in addition to normally-occurring production declines throughout an oil and natural gas well’s production life cycle. Production and operating costs were lower by $0.2 million, or 46%, due to volume-associated reductions of $0.1 million in production taxes, natural gas transport and lease operating expenses. In addition to volume-associated production tax decreases, lower commodity valuations further reduced production taxes by approximately $0.1 million. Production and operating costs per Mcfe were $1.31 for the six months ended June 30 of 2009 compared to $1.71 for the comparable period in 2008.

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Index

PDC 2004-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

For the three months ended June 30, 2009, compared to the same period in 2008, oil and natural gas production declined 35% which reduced volume-associated expenditures by $0.1 million. Along with reduced volume-associated expenditures, a decrease of approximately $0.1 million in production-related taxes due to lower commodity valuations, decreased overall production and operating costs by $0.2 million. Production and operating costs per Mcfe were $1.37 and $1.87 for the three month period ended June 30, 2009 and 2008, respectively.

Direct Costs−General and Administrative

Direct costs – general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation and legal matters. Direct costs increased during the three and six months ended June 30, 2009, compared to the same period in 2008, by approximately $0.1 million and $0.2 million, respectively, primarily due to an increase in professional fees for audit services principally to complete prior years’ audits.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (DD&A) expense results solely from the depreciation, depletion and amortization of well equipment and lease costs. The calculation of DD&A expense is directly related to reserves and production volumes. DD&A expense is primarily based upon year-end proved developed producing oil and gas reserves. These reserves are valued at the price of oil and natural gas as of December 31 each year. If prices increase, the estimated volume of oil and gas reserves may increase, resulting in a decrease in the rate of DD&A expense per unit of production. If prices decrease, as prices did from December 31, 2007 to December 31, 2008, the estimated volumes of oil and gas reserves may decrease resulting in an increase in the rate of DD&A expense per unit of production.

The DD&A rate per Mcfe increased to $3.39 and $3.47 for the three and six month periods ended June 30, 2009, respectively, compared to the DD&A per Mcfe rate of $2.49 and $2.57 during the same periods ended June 30, 2008. The variances in the per Mcfe rates for the three month periods in each year compared to the corresponding six month periods in each year are primarily the result of the changing production mix between the Partnership’s Wattenberg and Grand Valley fields which have significantly different DD&A rates. These increased rates, offset by lower production volumes, resulted in decreases of approximately $47,000 and $28,000, respectively, in DD&A expense for the three and six months ended June 30, 2009 compared to same periods in 2008. This is primarily the result of production level decreases of 35% and 29%, respectively, for the three and six month periods ended June 30, 2009, which were offset by increases in per Mcfe expense due to lower proved developed reserves at December 31, 2008 compared to December 31, 2007. While production and overall year-end reserves are expected to decline gradually year-to-year over the wells’ remaining life cycles, downward revisions to oil and natural gas proved developed reserves in the annual 2008 reserve report, resulted in the increased DD&A unit cost increases during the three and six month periods ended June 30, 2009 as compared to the same periods in 2008.

Interest Income

Significantly lower interest rates applied to undistributed revenues held by the Managing General Partner, resulted in lower interest income during the six months ended June 30, 2009, compared to the same periods in 2008. For the three months ended June 30, 2009 and 2008, respectively, interest income declined due to both lower undistributed revenues held by the Managing General Partner and significantly lower interest rates applied to those amounts, during the comparable periods.

Liquidity and Capital Resources

Oil and natural gas production from the Partnership’s existing properties, which commenced in fourth quarter 2004 and peaked during the second quarter 2005, declined rapidly through 2006. During 2007, 2008 and through September of 2009 oil and natural gas production declined gradually. Production is expected to continue to decline gradually over the remaining lives of the wells. Therefore, the Partnership may be unable to maintain its current level of oil and gas production and cash flows from operations if commodity prices remain in their current depressed state for a prolonged period beyond 2009. This decreased production would have a material negative impact on the Partnership’s operations and may result in reduced cash distributions to the Investor Partners in 2010 and beyond.

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Index

PDC 2004-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Working Capital

Working capital at June 30, 2009 was $1.5 million compared to working capital of $2.2 million at December 31, 2008. This decrease of $0.7 million was primarily due to a decrease in receivables from oil and gas sales at June 30, 2009 to $0.3 million as compared to $0.4 million at December 31, 2008. In addition, the receivables at June 30, 2009 for realized and short-term net unrealized derivative gains decreased to $0.3 million and $0.7 million, respectively, from the amounts at December 31, 2008 of $0.4 million and $1.0 million, respectively.

Cash Flows From Investing Activities

The Partnership received an approximately $9,000 refund from the Managing General Partner during the six month period ended June 30, 2009, for estimated capital expenditures previously charged for oil and gas properties which the Managing General Partner subsequently determined were not applicable to the Partnership.

Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in February 2005 and has distributed $18.4 million through June 30, 2009. The table below sets forth the cash distributions to the Managing General Partner and Investor Partners including Managing General Partner distribution relating to limited partnership units repurchased for the periods described as follows:

Three months ended June 30,
2009						2008
Managing General Partner Distributions		Investor Partners Distributions		Total Distributions		Managing General Partner Distributions		Investor Partners Distributions		Total Distributions

$	158,734	$	634,936	$	793,670	$	148,380	$	593,522	$	741,902

Six months ended June 30,
2009						2008
Managing General Partner Distributions		Investor Partners Distributions		Total Distributions		Managing General Partner Distributions		Investor Partners Distributions		Total Distributions

$	259,165	$	1,036,663	$	1,295,828	$	246,954	$	987,821	$	1,234,775

Investor Partner cash distributions include $12,008 and $17,359 during the three and six months ended June 30, 2009, respectively, and $5,076 and $8,087 during the three and six months ended June 30, 2008, respectively, related to equity cash distributions on Investor Partner units repurchased by the Managing General Partner.

Cash Flows From Operating Activities

The Partnership’s operations are expected to be conducted with available funds and revenues generated from its oil and natural gas production activities. Changes in cash flow from operations are largely due to the same factors that affect the Partnership’s net income that are more fully discussed under Results of Operations, excluding the non-cash items depreciation, depletion and amortization and unrealized gains and losses on derivative transactions. Based on current oil and natural gas prices and prices set by derivatives, and the Partnership’s anticipated production, the Partnership expects positive cash flows from operations for the remainder of 2009.

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Index

PDC 2004-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Changes in market prices for oil and natural gas, the Partnership’s production levels, impact of realized gains and losses on the Partnership’s oil and natural gas derivative instruments and changes in costs are the principal determinants of the level of the Partnership cash flow from operations. Oil and natural gas sales for the six months ended June 30, 2009 were approximately 73% lower than the same period in the prior year, resulting from a 62% decrease in average oil and natural gas prices and a 29% decrease in oil and natural gas production. While a decline in oil and natural gas prices would affect the amount of cash from operations that could be generated, the Partnership has oil and natural gas derivative positions in place, as of the date of this filing covering 71% of the Partnership’s expected oil production and 78% of its expected natural gas production for the remainder of 2009, at average prices of $90.51 per Bbl and $7.35 per Mcf, respectively. These contracts reduce the impact of price changes on cash provided by operations for a substantial portion of the `expected production for the remainder of 2009. However, the remaining 29% and 22% of estimated remaining 2009 oil and natural gas production, respectively, is not subject to the Partnership’s derivative instrument risk management; consequently, associated revenues will be directly impacted by changing commodity market prices.

The value of the Partnership’s current derivatives positions could change based on changes in oil and natural gas futures markets, the investors’ view of underlying oil and natural gas supply and demand trends and changes in volumes produced. Partnership oil and natural gas derivatives as of June 30, 2009 are detailed in Note 5, Derivative Financial Instruments to the accompanying interim unaudited condensed financial statements.

Net cash provided by operating activities was $1.3 million for the six months ended June 30, 2009 compared to $1.2 million during the same period in 2008, an increase of $0.1 million. Variances between the two periods in cash provided by operating activities were due primarily to the following:

An increase in realized oil and gas price risk management, net of $1.0 million; a decrease in production and operating cost of $0.2 million; and a decrease in accounts receivable collections of $0.9; and

A decrease in oil and gas sale revenues of $1.8 million, accompanied by an increase in direct costs – general and administrative of $0.2 million.

Information related to the oil and gas reserves of the Partnership’s wells is discussed in detail in the Partnership’s Annual Report on Form 10-K Supplemental Oil and Gas Information−Unaudited, Net Proved Oil and Gas Reserves and Information and Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves.

Partnership well recompletions in the Codell formation of Wattenberg Field wells, which may provide for additional reserve development and production, generally occur five to seven years after initial well drilling so that well resources are optimally utilized. These well recompletions would be expected to occur based on a favorable general economic environment and commodity price structure. Since borrowing is not permitted by the Limited Partnership Agreement, well recompletion activities will be funded through the retention of revenues and reduction of Partner cash distributions. There are no immediate plans to initiate recompletion activities in the Wattenberg Field wells owned by the Partnership. As the optimal period approaches, the Managing General Partner will re-evaluate the feasibility of commencing those recompletions based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the recompletion. However, no assurances can be given that recompletion activities will be feasible or economic.

Commitments and Contingencies

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

Recent Accounting Standards

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

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Index

PDC 2004-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 accounting principles generally accepted in the United States of America, 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.

The Partnership believes that the Partnership’s accounting policies for revenue recognition, derivatives instruments, fair value measurements, oil and natural gas properties, and asset retirement obligations are based on, among other things, judgments and assumptions made by management that include inherent risks and uncertainties. There have been no significant changes to these policies 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 Form 10-K for the year ended December 31, 2008.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not Applicable

Item 4T. Controls and Procedures

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

2008 Material Weakness

As discussed in the Management’s Report on Internal Control Over Financial Reporting included in the Partnership’s 2008 Annual Report on Form 10-K, the Partnership did not maintain effective internal controls over financial reporting as of December 31, 2008, over transactions that are directly related to and processed by the Partnership, in that the Partnership failed to maintain sufficient documentation to adequately assess the operating effectiveness of internal control over financial reporting. More specifically, the Partnership’s financial close and reporting narrative failed to adequately describe the process, identify key controls and assess segregation of duties. This material weakness has not been remediated as of June 30, 2009. The 2008 Annual Report on Form 10-K did not include an attestation report of the Partnership’s independent registered public accounting firm regarding internal control over financial reporting pursuant to Item 308T (a)(4) of Regulation S-K. Pursuant to Final Order dated October 19, 2009, temporary Item 308T was extended through December 15, 2010. Accordingly, the Partnership will file the attestation report of the Partnership’s independent registered public accounting firm regarding internal control with the Partnership’s Annual Report on Form 10-K as of December 31, 2010.

(a) Evaluation of Disclosure Controls and Procedures

As of June 30, 2009, 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 its Chief Executive Officer and 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 the Partnership files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the Partnership’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.

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Index

PDC 2004-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Based upon that evaluation, the Managing General Partner’s Chief Executive Officer and Chief Financial Officer concluded that the Partnership’s disclosure controls and procedures were not effective as of June 30, 2009 due to the existence of the material weakness described above in 2008 Material Weakness included in this Item 4 (T). Because of the nature of the material weakness noted, the Partnership is not able to quantify the dollar amounts of exposure or potential range of the dollar amount of potential revisions to the financial statements, from this material weakness.

(b) Remediation of Material Weakness in Internal Control

PDC, the Managing General Partner, with participation from the Audit Committee of its Board of Directors, has been addressing the material weakness disclosed in the Partnership’s 2008 Annual Report on Form 10-K. The Managing General Partner believes that with effective implementation of planned changes in internal controls over financial reporting outlined below, that it will be able to remediate this known material weakness as of December 31, 2009. However, this control weakness will not be considered remediated until the changes in internal controls over financial reporting are operating effectively for a sufficient period of time and the Managing General Partner has concluded, through testing, that these controls are operating effectively.

The Partnership made no changes in its internal control over financial reporting (such as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during the quarter ended June 30, 2009.

The Partnership has developed a plan to improve controls over certain key financial statement spreadsheets that support all significant balance sheet and income statement accounts. The Partnership also created and documented a procedural framework to ensure the completeness and accuracy of the Partnership’s derivative activities with implementation planned for the second half of 2009. Additionally, the Partnership has completed the development of a revised financial close and reporting narrative that adequately describes the process, identifies key controls and assesses segregation of duties. This narrative was implemented during July and August of 2009 and the controls and procedures are currently being tested. Testing is expected to be completed by December 31, 2009. At present, the Partnership has not quantified the total cost of this initiative; however the majority of this cost is expected to be paid by the Managing General Partner.

Until PDC, the Managing General Partner, is able to conclude that the Partnership has remediated this known material weakness in internal control over financial reporting, the Managing General Partner will continue to perform additional analysis and procedures in order to ensure that the Partnership’s financial statements contained in its subsequent SEC filings are prepared in accordance with generally accepted accounting principles in the United States.

The Managing General Partner continues to evaluate the ongoing effectiveness and sustainability of these planned changes in internal control over financial reporting, and, as a result of the ongoing evaluation, may identify additional changes to improve internal control over financial reporting. Further information regarding the material weakness of the Partnership referenced above may be found in the Partnership’s Annual Report on 10-K for the year ended December 31, 2008 under Item 9A (T), Controls and Procedures − Management’s Report on Internal Control Over Financial Reporting.

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Index

PDC 2004-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

Not Applicable

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

Unit Repurchase Program: Beginning February 2008, the third anniversary of the date of the first Partnership cash distributions, Investor Partners of the Partnership may request that the Managing General Partner repurchase their respective individual Investor Partner units, up to an aggregate total limit during any calendar year for all requesting Investor Partner unit repurchases of 10% of the initial subscription units.

Second quarter 2009 unit repurchases were 4.25 units repurchased at an average price of $10,794 per unit during April. There were no unit repurchases during May or June, 2009.

Other Repurchases: Individual investor partners periodically offered and PDC repurchased, units on a negotiated basis before the third anniversary of the date of the first cash distribution.

Items 3, 4 and 5 have been omitted as there is nothing to report.

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Index

PDC 2004-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 6. Exhibits

(a) Exhibit Index.

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File

Number

Exhibit

Filing Date

Filed

Herewith

3.1

Limited Partnership Agreement

10-K

000-51219

3.1

08/05/2009

3.2

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

10-K

000-51219

3.2

08/05/2009

10.1

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

10-K

000-51219

10.1

08/05/2009

31.1

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

31.2

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

32.1

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

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Index

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 2004-B Limited Partnership

By its Managing General Partner

Petroleum Development Corporation

	By: /s/ Richard W. McCullough
	Richard W. McCullough Chairman and Chief Executive Officer December 18, 2009

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

Signature	Title	Date

/s/ Richard W. McCullough	Chairman and Chief Executive Officer	December 18, 2009
Richard W. McCullough	Petroleum Development Corporation
	Managing General Partner of the Registrant
	(Principal executive officer)

/s/ Gysle R. Shellum	Chief Financial Officer	December 18, 2009
Gysle R. Shellum	Petroleum Development Corporation
	Managing General Partner of the Registrant
	(Principal financial officer)

/s/ R. Scott Meyers	Chief Accounting Officer	December 18, 2009
R. Scott Meyers	Petroleum Development Corporation
	Managing General Partner of the Registrant
	(Principal accounting officer)

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PDC 2004-B Limited Partnership 10-Q