PDC 2003-B LP - FORM 10-Q - December 15, 2010

Attached files

file	filename
EX-32.1 - EXHIBIT 32.1 - PDC 2003-B LP	ex32_1.htm
EX-31.1 - EXHIBIT 31.1 - PDC 2003-B LP	ex31_1.htm
EX-31.2 - EXHIBIT 31.2 - PDC 2003-B LP	ex31_2.htm

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, 2010

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

FOR THE TRANSITION PERIOD ____________ TO ____________

Commission File Number 000-50616

PDC 2003-B Limited Partnership

(Exact name of registrant as specified in its charter)

West Virginia
(State or other jurisdiction of incorporation or organization)

55-0825013

(I.R.S. Employer Identification No.)

1775 Sherman Street, Suite 3000, Denver, Colorado 80203

(Address of principal executive offices) (Zip code)

(303) 860-5800

(Registrant’s telephone number, including area code)

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

Yes 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 June 30, 2010 the Partnership had 867.33 units of limited partnership interest and no units of additional general partnership interest outstanding.

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

INDEX TO REPORT ON FORM 10-Q

		Page
	PART I – FINANCIAL INFORMATION

	Note Regarding Forward-Looking Statements	1
Item 1.	Financial Statements (unaudited)
	Condensed Balance Sheets (unaudited)	2
	Condensed Statements of Operations (unaudited)	3
	Condensed Statements of Cash Flows (unaudited)	4
	Notes to Unaudited Condensed Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	22
Item 4.	Controls and Procedures	22

	PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	23
Item 1A.	Risk Factors	23
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	23
Item 3.	Defaults Upon Senior Securities	23
Item 4.	[Removed and Reserved]	23
Item 5.	Other Information	23
Item 6.	Exhibits	24

	SIGNATURES	25

Index

NOTE REGARDING FORWARD-LOOKING STATEMENTS

This periodic report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”) regarding PDC 2003-B Limited Partnership’s (the “Partnership” or the “Registrant”) business, financial condition, results of operations and prospects.

All statements other than statements of historical facts included in and incorporated by reference into this report are forward-looking statements. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein, which include statements of estimated natural gas and oil production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and the Managing General Partner Petroleum Development Corporation’s (“PDC”) strategies, plans and objectives. However, these words are not the exclusive means of identifying forward-looking statements herein. PDC now conducts business under the name “PDC Energy.”

Although forward-looking statements contained in this report reflect the Managing General Partner’s good faith judgment, such statements can only be based on facts and factors currently known to the Managing General Partner. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including risks and uncertainties incidental to the development, production and marketing of natural gas and oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

●

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

●

changes in estimates of proved reserves;

●

declines in the values of the Partnership’s natural gas and oil properties resulting from impairments;

●

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

●

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

●

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

●

future production and refracturing costs;

●

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

●

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

●

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

●

changes in environmental laws and the regulations and enforcement related to those laws;

●

the identification of and severity of environmental events and governmental responses to the events;

●

the availability of funding for the consideration payable by PDC and its wholly-owned subsidiary to consummate the prospective mergers under the Acquisition Plan, and the timing of consummating any such mergers if at all;

●

the effect of natural gas and oil derivatives activities;

●

conditions in the capital markets; and

●

losses possible from pending or future litigation.

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

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Index

PART I – FINANCIAL INFORMATION

Item 1.

Financial Statements (unaudited)

PDC 2003-B Limited Partnership

Condensed Balance Sheets

(unaudited)


	June 30, 2010			December 31, 2009*
Assets

Current assets:
Cash and cash equivalents	$	57,519		$	57,505
Accounts receivable		80,179			158,083
Oil inventory		17,499			15,343
Due from Managing General Partner-derivatives		214,823			204,247
Total current assets		370,020			435,178

Natural gas and oil properties, successful efforts method, at cost		14,130,397			14,129,625
Less: Accumulated depreciation, depletion and amortization		(8,164,657	)		(7,852,403	)
Oil and gas properties, net		5,965,740			6,277,222

Due from Managing General Partner-derivatives		379,535			161,426
Other assets		42,736			36,152
Total noncurrent assets		6,388,011			6,474,800

Total Assets	$	6,758,031		$	6,909,978

Liabilities and Partners’ Equity

Current liabilities:
Accounts payable and accrued expenses	$	57,563		$	12,568
Due to Managing General Partner-derivatives		158,438			164,260
Due to Managing General Partner-other, net		232,398			98,610
Total current liabilities		448,399			275,438

Due to Managing General Partner-derivatives		402,129			482,463
Asset retirement obligations		223,166			216,681
Total liabilities		1,073,694			974,582

Commitments and contingent liabilities

Partners’ equity:
Managing General Partner		1,139,564			1,189,777
Limited Partners - 867.33 units issued and outstanding		4,544,773			4,745,619
Total Partners’ equity		5,684,337			5,935,396

Total Liabilities and Partners’ Equity	$	6,758,031		$	6,909,978

*Derived from audited 2009 balance sheet

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2003-B Limited Partnership

Condensed Statements of Operations

(unaudited)


	Three months ended June 30,						Six months ended June 30,
	2010			2009			2010		2009
Revenues:
Natural gas and oil sales	$	240,446		$	259,042		$	606,480	$	498,778
Commodity price risk management gain (loss), net		130,362			(301,981	)		497,412		(292,882	)
Total revenues		370,808			(42,939	)		1,103,892		205,896

Operating costs and expenses:
Natural gas and oil production costs		162,570			104,440			261,816		225,478
Direct costs - general and administrative		218,659			10,369			291,224		28,209
Depreciation, depletion and amortization		139,630			272,924			312,254		533,904
Accretion of asset retirement obligations		3,266			2,231			6,485		4,462
Total operating costs and expenses		524,125			389,964			871,779		792,053

(Loss) income from operations		(153,317	)		(432,903	)		232,113		(586,157	)

Interest income		7			7,727			14		15,661

Net (loss) income	$	(153,310	)	$	(425,176	)	$	232,127	$	(570,496	)

Net (loss) income allocated to partners	$	(153,310	)	$	(425,176	)	$	232,127	$	(570,496	)
Less: Managing General Partner interest in net (loss) income		(30,662	)		(85,035	)		46,425		(114,099	)
Net (loss) income allocated to Investor Partners	$	(122,648	)	$	(340,141	)	$	185,702	$	(456,397	)

Net (loss) income per Investor Partner unit	$	(141	)	$	(392	)	$	214	$	(526	)

Investor Partner units outstanding		867.33			867.33			867.33		867.33

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2003-B Limited Partnership

Condensed Statements of Cash Flows

(unaudited)

	Six months ended June 30,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	232,127		$	(570,496	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		312,254			533,904
Accretion of asset retirement obligations		6,485			4,462
Unrealized (gain) loss on derivative transactions		(314,841	)		824,475
Changes in operating assets and liabilities:
Decrease in accounts receivable		77,904			32,402
(Increase) decrease in oil inventory		(2,156	)		12,013
Increase in other assets		(6,584	)		(7,008	)
Increase (decrease) in accounts payable and accrued expenses		44,995			(9,750	)
Decrease in due from Managing General Partner - other, net		0			243,603
Increase in due to Managing General Partner - other, net		133,788			-
Net cash provided by operating activities		483,972			1,063,605

Cash flows from investing activities:
Capital expenditures for oil and gas properties		(772	)		(5,333	)
Net cash used in investing activities		(772	)		(5,333	)

Cash flows from financing activities:
Distributions to Partners		(483,186	)		(1,057,583	)
Net cash used in financing activities		(483,186	)		(1,057,583	)

Net increase in cash and cash equivalents		14			689
Cash and cash equivalents, beginning of period		57,505			56,772
Cash and cash equivalents, end of period	$	57,519		$	57,461

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2003-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2010

(unaudited)

Note 1−General and Basis of Presentation

The PDC 2003-B Limited Partnership (the “Partnership”) was organized as a limited partnership on June 13, 2003, in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of oil and natural gas properties. Upon completion of the sale of Partnership units on September 3, 2003, 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 19.79 units of limited partner interests and 847.54 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 that now conducts business under the name “PDC Energy”, is the Managing General Partner of the Partnership (hereafter, the “Managing General Partner” or “PDC”) and has a 20% Managing General Partner ownership in the Partnership. Upon completion of the drilling phase of the Partnership’s wells, all additional general partners units were converted into units of limited partner interests and thereafter became limited partners of the Partnership. Throughout the term of the Partnership, revenues, costs, and cash distributions are allocated 80% to the limited and additional general partners (collectively, the “Investor Partners”), which are shared pro rata based upon the portion of units owned in the Partnership, and 20% to the Managing General Partner.

As of June 30, 2010, there were 781 Investor Partners. As of June 30, 2010 the Managing General Partner has repurchased 33.38 units of the total 867.33 outstanding units of Partnership interests from Investor Partners at an average price of $7,282 per unit and, as a result, participates in the sharing of revenues, costs and cash distributions as both an investor partner and as the Managing General Partner.

The Managing General Partner, under the terms of the Drilling and Operating Agreement (the “D&O Agreement”), has full authority to conduct the Partnership’s business and actively manage the Partnership. The Partnership expects continuing operations of its natural gas and oil properties until such time that the Partnership’s wells are depleted or become uneconomical to produce, at which time that well may be sold or plugged, reclaimed and abandoned. The Partnership’s maximum term of existence extends through December 31, 2050, unless dissolved by certain conditions stipulated within the Agreement (which are unlikely to occur at this time) or by written consent of the Investor Partners owning a majority of outstanding units at that time.

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

Note 2−Recent Accounting Standards

Recently Adopted Accounting Standards

Fair Value Measurements and Disclosures

In January 2010, the Financial Accounting Standards Board (“FASB”) issued changes clarifying existing disclosure requirements related to fair value measurements. The update also added a new requirement to disclose fair value transfers in and out of Levels 1 and 2 and describe the reasons for the transfers. The adoption of these changes as of January 1, 2010, did not have a material impact on the Partnership’s accompanying unaudited condensed financial statements.

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Index

PDC 2003-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2010

(unaudited)

Recently Issued Accounting Standards

Fair Value Measurements and Disclosures

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

Internal Control over Financial Reporting in Exchange Act Periodic Reports

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

Note 3−Transactions with Managing General Partner and Affiliates

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

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

	June 30, 2010			December 31, 2009

Natural gas and oil sales revenues collected from the Partnership’s third-party customers	$	66,999		$	106,460
Commodity Price Risk Management, Realized Gains		20,546			132,191
Other (1)		(319,943	)		(337,261	)
Total Due to Managing General Partner-other, net	$	(232,398	)	$	(98,610	)

(1)

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

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Index

PDC 2003-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2010

(unaudited)

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

	Three months ended June 30,				Six months ended June 30,
	2010		2009		2010		2009

Well operations and maintenance	$	142,383	$	83,445	$	228,407	$	181,460
Gathering, compression and processing fees		7,963		8,090		17,276		16,466
Direct costs - general and administrative		218,659		10,369		291,224		28,209
Cash distributions*		46,405		111,624		110,665		230,063

*Cash distributions include $5,904 and $14,027 during the three and six months ended June 30, 2010, respectively, and $10,125 and $18,547 during the three and six months ended June 30, 2009, respectively, related to equity cash distributions on Investor Partner units repurchased by PDC.

Note 4−Fair Value Measurements

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

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Index

PDC 2003-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2010

(unaudited)

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

	Quoted Prices in Active Markets (Level 1)			Significant Unobservable Inputs (Level 3)			Total

As of December 31, 2009
Assets:
Commodity based derivatives	$	163,840		$	201,833		$	365,673
Total assets		163,840			201,833			365,673

Liabilities:
Commodity based derivatives		(11,426	)		(49,433	)		(60,859	)
Basis protection derivative contracts		—			(585,864	)		(585,864	)
Total liabilities		(11,426	)		(635,297	)		(646,723	)

Net asset (liability)	$	152,414		$	(433,464	)	$	(281,050	)

As of June 30, 2010
Assets:
Commodity based derivatives	$	512,182		$	82,176		$	594,358
Total assets		512,182			82,176			594,358

Liabilities:
Commodity based derivatives		—			(26,924	)		(26,924	)
Basis protection derivative contracts		—			(533,643	)		(533,643	)
Total liabilities		—			(560,567	)		(560,567	)

Net asset (liability)	$	512,182		$	(478,391	)	$	33,791

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

	Six months ended
	June 30, 2010
Fair value, net liability, as of December 31, 2009	$	(433,464	)
Changes in fair value included in statement of operations line item:
Commodity price risk management, net		81,340
Settlements		(126,267	)
Fair value, net liability, as of June 30, 2010	$	(478,391	)

Change in unrealized gains (losses) relating to assets (liabilities) still held as of June 30, 2010 included in statement of operations line item:
Commodity price risk management, net	$	61,633

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

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

Note 5−Derivative Financial Instruments

As of June 30, 2010, the Partnership had derivative instruments, comprised of commodity collars, commodity fixed-price swaps and a basis swap, in place for a portion of its anticipated production through 2013 for a total of 455,978 MMbtu of natural gas and 6,698 Bbls of oil. Partnership policy prohibits the use of natural gas and oil derivative instruments for speculative purposes.

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Index

PDC 2003-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2010

(unaudited)

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

			Fair Value
Derivative instruments not designated as hedge (1):		Balance Sheet Line Item	June 30, 2010			December 31, 2009

Derivative Assets:	Current
	Commodity contracts	Due from Managing General Partner-derivatives	$	214,823		$	204,247

	Non Current
	Commodity contracts	Due from Managing General Partner-derivatives		379,535			161,426

Total Derivative Assets			$	594,358		$	365,673

Derivative Liabilities:	Current
	Commodity contracts	Due to Managing General Partner-derivatives	$	(12,299	)	$	(11,745	)

	Basis protection contracts	Due to Managing General Partner-derivatives		(146,139	)		(152,515	)

	Non Current
	Commodity contracts	Due to Managing General Partner-derivatives		(14,625	)		(49,114	)

	Basis protection contracts	Due to Managing General Partner-derivatives		(387,504	)		(433,349	)

Total Derivative Liabilities			$	(560,567	)	$	(646,723	)

(1) As of June 30, 2010 and December 31, 2009, none of the Partnership’s derivative instruments were designated as hedges.

The following table summarizes the impact of the Partnership’s derivative instruments on the Partnership’s accompanying statements of operations for the three and six months ended June 30, 2010 and 2009.

	Three months ended June 30,
	2010							2009
Statement of operations line item	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total		Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Losses For the Current Period			Total

Commodity price risk management, net
Realized gains (losses)	$	18,070		$	7,451	$	25,521	$	227,274		$	(19,602	)	$	207,672
Unrealized (losses) gains		(18,070	)		122,911		104,841		(227,274	)		(282,379	)		(509,653	)
Total commodity price risk management gain (loss), net	$	—		$	130,362	$	130,362	$	—		$	(301,981	)	$	(301,981	)

	Six months ended June 30,
	2010							2009
Statement of operations line item	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total		Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains (Losses) For the Current Period			Total

Commodity price risk management, net
Realized gains	$	106,540		$	76,031	$	182,571	$	435,382		$	96,211		$	531,593
Unrealized (losses) gains		(106,540	)		421,381		314,841		(435,382	)		(389,093	)		(824,475	)
Total commodity price risk management gain (loss), net	$	—		$	497,412	$	497,412	$	—		$	(292,882	)	$	(292,882	)

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

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Index

PDC 2003-B LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2010

(unaudited)

Note 6−Commitments and Contingencies

Environmental

Due to the nature of the natural gas and oil business, the Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures to avoid environmental contamination and mitigate the risks from environmental contamination. The Managing General Partner conducts periodic reviews to identify changes in the Partnership’s environmental risk profile. Liabilities are accrued when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. As of June 30, 2010, the Partnership had accrued an environmental remediation liability included in Balance Sheet line item captioned “Accounts payable and accrued expenses.” This accrual represents costs estimated to be incurred in addition to normal recurring environmental-related expenditures which have been incurred and recorded at June 30, 2010. During the second quarter of 2010, the Managing General Partner identified existing ground contamination at one Partnership well. The accrual of approximately $50,000 is the estimated cost attributable to the Partnership, based principally on estimated third party costs, to remediate the ground contamination. The Managing General Partner is not aware of any environmental claims existing as of June 30, 2010, which have not been provided for or would otherwise have a material impact on the Partnership’s financial statements. However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on the Partnership’s properties.

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

Note 7−Subsequent Events

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

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Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Partnership Overview

PDC 2003-B Limited Partnership engages in the development, production and sale of oil and natural gas. The Partnership began oil and gas operations in September 2003 and operates 25 gross (22.3 net) productive wells located in the Rocky Mountain Region in the state of Colorado. One additional Wattenberg Field Partnership well (0.9 net well) is temporarily not in production at June 30, 2010 due to equipment problems. 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 does not charge an additional fee for the marketing of the natural gas and oil because these services are covered by the monthly well operating charge. PDC, on behalf of the Partnership in accordance with the D&O Agreement, is authorized to enter into multi-year fixed price contracts or utilize derivatives, including collars, swaps or basis protection swaps, in order to offset some or all of the commodity price variability for particular periods of time. Seasonal factors, such as effects of weather on prices received and costs incurred, and availability of pipeline capacity, owned by PDC or other third parties, may impact the Partnership’s results. In addition, both sales volumes and prices tend to be affected by demand factors with a seasonal component.

Recent Developments

PDC Sponsored Drilling Program Acquisition Plan

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

In June 2010, PDC and a wholly-owned subsidiary of PDC entered into separate merger agreements with each of PDC 2004-A Limited Partnership, PDC 2004-B Limited Partnership, PDC 2004-C Limited Partnership and PDC 2004-D Limited Partnership (collectively, the “2004 partnerships”). PDC serves as the managing general partner of each of the 2004 partnerships. Definitive proxy statements for each of the 2004 partnerships requesting approval from the applicable non-affiliated Investor Partners for, among other things were mailed to the non-affiliated Investor Partners of the 2004 partnerships in early October 2010. Special meetings were held on December 8, 2010, at which the majority of the non-affiliated Investor Partners of each of the 2004 partnerships voted to approve the applicable merger agreement.

In November 2010, PDC and a wholly-owned subsidiary of PDC entered into separate merger agreements with each of PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership, and the 2005 Rockies Region Private Limited Partnership (collectively, the “2005 partnerships”). PDC serves as the managing general partner of each of the 2005 partnerships. On December 3, 2010, each of the 2005 partnerships filed with the SEC, a preliminary proxy statement relating to such partnership’s prospective merger. Upon completion of the SEC review process, a definitive proxy statement will be mailed to the 2005 partnerships’ non-affiliated Investor Partners requesting their approval of the merger transactions. Pursuant to each merger agreement, if the merger is approved by the holders of a majority of the limited partnership units held by the non-affiliated Investor Partners of each respective partnership, as well as the satisfaction of other customary closing conditions, then such partnership will merge with and into a wholly-owned subsidiary of PDC. PDC has offered to pay approximately $36.4 million for the limited partnership units of the 2005 partnerships in connection with the mergers. Although there is no assurance of the likelihood or timing of the completion of the SEC proxy disclosure review process or whether the Partnership will obtain the necessary approvals from non-affiliated investors, each merger of the 2005 partnerships is expected to close during the first half of 2011.

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Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

Well Refracturing Plan

The Managing General Partner has prepared a plan for the Partnership’s Wattenberg Field wells that were initially completed in the Codell producing formation during the Partnership’s initial development (the “Well Refracturing Plan”). Under the Well Refracturing Plan, the Partnership plans to initiate Codell formation refracturing activities during 2011. These refracturing, or “refracing,” activities will consist of a second hydraulic fracturing treatment to the currently producing Codell formation.

During the fourth quarter 2010, the Managing General Partner began withholding funds from several of the PDC sponsored partnerships, on a pro-rata basis allocated to the Managing General Partner and Investor Partners based on their proportional ownership interest, from distributable cash flows resulting from current production. The funds retained are necessary for the Partnership to pay for refracturing costs will materially reduce, up to 100%, distributable cash flows for a period of time not to exceed five years. If any or all of the Partnership’s Wattenberg wells are not refractured, the Partnership will experience a reduction in proved natural gas and oil reserves currently assigned to these wells. Both the number and timing of refracturings will be based on the availability of cash withheld from Partnership distributions. The Managing General Partner believes that, based on projected refracturing costs and projected cash withholding, all Partnership refracturings will be completed within a five year period. This Partnership began withholding funds for this additional Codell formation development in October 2010 by withholding $20,000 and depositing into the Partnership’s bank account.

Current estimated costs for these well refracturings are between $150,000 and $200,000 per refracturing. This Partnership potentially has 21 well refracturing opportunities. Total withholding for these activities from the Partnership’s distributable cash flows is estimated to be between $3.2 million and $4.2 million. The Managing General Partner will continually evaluate the timing of commencing these refracturings based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the refracturing.

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

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Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Partnership Operating Results Overview

Natural gas and oil sales increased 22% or $0.1 million for the first six months of 2010 compared to the first six months of 2009, even though production volumes decreased 24% period-to-period. This increase was driven primarily by the improved commodity price environment. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $6.16 for the current year period compared to $3.85 for the same period a year ago. Realized derivative gains from natural gas and oil sales contributed an additional $1.86 per Mcfe or $0.2 million to the first six months of 2010 total revenues. Comparatively, the total per Mcfe price realized, consisting of the average sales price and realized derivative gains, increased to $8.02 for the current year six months from $7.96 for the same prior year period.

Direct costs−administrative and general increased by $0.3 million during the 2010 six month period due to the Partnership’s independent registered public accounting firm fees rendered for audit services. These audit services were conducted under the 2010 Partnership SEC reporting compliance effort related to the filing of the Partnership’s financial statements for the years 2005 through 2009.

Results of Operations

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

	Three months ended June 30,							Six months ended June 30,
	2010		2009		Change			2010		2009		Change
Number of producing wells (end of period)		25		26		-4	%		25		26		-4	%

Production (1)
Natural gas (Mcf)		36,677		49,663		-26	%		76,870		100,489		-24	%
Oil (Bbl)		1,456		2,644		-45	%		3,594		4,829		-26	%
Natural gas equivalents (Mcfe) (2)		45,413		65,527		-31	%		98,434		129,463		-24	%

Natural Gas and Oil Sales
Natural gas	$	134,210	$	119,388		12	%	$	344,838	$	281,083		23	%
Oil		106,236		139,654		-24	%		261,642		217,695		20	%
Total natural gas and oil sales	$	240,446	$	259,042		-7	%	$	606,480	$	498,778		22	%

Realized Gain on Derivatives, net
Natural gas	$	69	$	149,676		-100	%	$	133,260	$	385,574		-65	%
Oil		25,452		57,996		-56	%		49,311		146,019		-66	%
Total realized gain on derivatives, net	$	25,521	$	207,672		-88	%	$	182,571	$	531,593		-66	%

Average Selling Price (excluding realized gain on derivatives)
Natural gas (per Mcf)	$	3.66	$	2.40		52	%	$	4.49	$	2.80		60	%
Oil (per Bbl)		72.96		52.82		38	%		72.80		45.08		61	%
Natural gas equivalents (per Mcfe)		5.29		3.95		34	%		6.16		3.85		60	%

Average Selling Price (including realized gain on derivatives)
Natural gas (per Mcf)	$	3.66	$	5.42		-32	%	$	6.22	$	6.63		-6	%
Oil (per Bbl)		90.45		74.75		21	%		86.52		75.32		15	%
Natural gas equivalents (per Mcfe)		5.86		7.12		-18	%		8.02		7.96		1	%

Average Lifting Cost (per Mcfe) (3)	$	3.58	$	1.59		125	%	$	2.66	$	1.74		53	%

Operating costs and expenses
Direct costs - general and administrative	$	218,659	$	10,369			*	$	291,224	$	28,209			*
Depreciation, depletion and amortization	$	139,630	$	272,924		-49	%	$	312,254	$	533,904		-42	%

Cash distributions	$	202,505	$	507,496		-60	%	$	483,186	$	1,057,583		-54	%

*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.

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Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

(3)

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

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

●

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

●

MBbl – One thousand barrels

●

Mcf – One thousand cubic feet

●

MMcf – One million cubic feet

●

Mcfe – One thousand cubic feet of natural gas equivalents

●

MMcfe – One million cubic feet of natural gas equivalents

●

MMbtu – One million British Thermal Units

Natural Gas and Oil Sales

Six months ended June 30, 2010 as compared to six months ended June 30, 2009

The $0.1 million, or 22% increase in sales for the 2010 six month period as compared to the prior year period, was primarily a reflection of the significantly higher average sales price per Mcfe of 60%, which was partially offset by a production volume decrease of 24%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $6.16 for the current year six month period compared to $3.85 for the same period a year ago.

Natural gas and oil revenues increased by 23% and 20%, respectively. The Partnership’s natural gas revenue increase resulted from rising commodity prices per Mcf, of 60%, which were partially offset by lower Partnership natural gas production volumes of 24%. This compares to the more moderate oil revenue increase in which the rise in commodity prices per Bbl, of 61% was partially offset by a slightly steeper decline in oil production volumes of 26% during the current six month period.

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

The moderate 7% decline in sales for the 2010 second quarter as compared to the prior year second quarter was primarily a reflection of the production volume decrease of 31% which was substantially offset by the higher average sales price per Mcfe of 34%. Average sales prices per Mcfe, excluding the impact of realized derivative gains, were $5.29 for the current year quarter compared to $3.95 for the same quarter a year ago.

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

Natural Gas and Oil Pricing

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

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Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

The price at which PDC markets the natural gas produced in the Rocky Mountain Region by the Partnership is based on a variety of prices, which primarily includes natural gas sold at Colorado Interstate Gas, or CIG, prices with a portion sold at Mid-Continent, San Juan Basin, Southern California or other nearby regional prices. The CIG Index, and other indices for production delivered to Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is primarily New York Mercantile Exchange, or NYMEX, based, because of the lack of interstate transmission capacity which moved Rocky Mountain natural gas production to Northeastern U.S. industrial and heating markets. This negative differential has narrowed in the last year and is lower than historical variances. This negative differential between NYMEX and CIG averaged $1.13 and $1.38 for the three and six months ended June 30, 2009, respectively, and narrowed to an average of $0.48 and $0.32 for the three and six months ended June 30, 2010, respectively.

Commodity Price Risk Management, Net

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

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

	Three months ended June 30,						Six months ended June 30,
	2010			2009			2010			2009
Commodity price risk management gain (loss), net
Realized gain
Oil	$	25,452		$	57,996		$	49,311		$	146,019
Natural Gas		69			149,676			133,260			385,574
Total realized gain, net		25,521			207,672			182,571			531,593

Unrealized gain (loss)
Reclassification of realized gain included in prior periods unrealized		(18,070	)		(227,274	)		(106,540	)		(435,382	)
Unrealized gain (loss) for the period		122,911			(282,379	)		421,381			(389,093	)
Total unrealized gain (loss), net		104,841			(509,653	)		314,841			(824,475	)
Commodity price risk management gain (loss), net	$	130,362		$	(301,981	)	$	497,412		$	(292,882	)

Six months ended June 30, 2010 as compared to six months ended June 30, 2009

The realized derivative gains for the 2010 six month period were $0.2 million, as a result of lower natural gas and oil spot prices at settlement compared to the respective strike price. Unrealized gains for the 2010 six month period were due primarily to a downward shift in the natural gas and oil forward curves. Unrealized gains on the Partnership’s commodity positions for the 2010 six month period were $0.4 million.

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

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Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

The realized derivative gains for the 2010 second quarter on the Partnership’s commodity positions are the result of lower natural gas and oil spot prices at settlement compared to the respective strike price. For the 2010 second quarter, the unrealized gains of $0.1 million were primarily related to the Partnership’s commodity positions, as the forward strip price shifted downward during the quarter, and the Partnership’s basis position due to the widening of the NYMEX-CIG basis differential.

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

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

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

	Collars						Fixed-Price Swaps				CIG Basis Protection Swaps
			Weighted Average				Quantity		Weighted Average				Weighted Average			Fair Value at
Commodity/	Quantity		Contract Price				(Gas-Mmbtu(1)		Contract		Quantity		Contract			June 30,
Index	(Gas-Mmbtu(1))		Floors		Ceilings		Oil-Bbls)		Price		(Gas-Mmbtu(1))		Price			2010(2)

Natural Gas
CIG
10/01 - 12/31/2010		11,818	$	4.75	$	9.45		—	$	—		—	$	—		$	7,213
01/01 - 03/31/2011		17,727		4.75		9.45		—		—		—		—			8,834

NYMEX
07/01 - 09/30/2010		—		—		—		36,932		5.56		39,280		(1.88	)		(12,317	)
10/01 - 12/31/2010		3,181		5.75		8.30		22,242		6.15		26,387		(1.88	)		(901	)
01/01 - 03/31/2011		4,340		5.75		8.30		13,813		6.84		18,153		(1.88	)		(1,349	)
04/01 - 06/30/2011		—		—		—		35,391		6.78		35,391		(1.88	)		12,611
07/01 - 12/31/2011		—		—		—		68,585		6.76		68,585		(1.88	)		1,175
2012-2013		6,617		6.00		8.27		235,332		7.05		241,948		(1.88	)		(9,145	)
Total Natural Gas		43,683						412,295				429,744					6,121

Oil
NYMEX
07/01 - 09/30/2010		—		—		—		1,720		92.96		—		—			28,445
10/01 - 12/31/2010		—		—		—		1,720		92.96		—		—			26,149
01/01 - 03/31/2011		—		—		—		782		70.75		—		—			(5,742	)
04/01 - 06/30/2011		—		—		—		805		70.75		—		—			(6,558	)
07/01 - 12/31/2011		—		—		—		1,671		70.75		—		—			(14,624	)
Total Oil		—						6,698				—					27,670

Total Natural Gas and Oil																$	33,791

(1)

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

(2)

Approximately 14% of the fair value of the Partnership’s derivative assets and all of the Partnership’s derivative liabilities were measured using significant unobservable inputs (Level 3), see Note 4, Fair Value Measurements, to the accompanying unaudited condensed financial statements included in this report.

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Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Natural Gas and Oil Production Costs

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

Six months ended June 30, 2010 as compared to six months ended June 30, 2009

For the six months ended June 30, 2010 compared to the same period in 2009, natural gas and oil production, on an energy equivalency-basis, decreased 24%, due to normal production declines for this stage in the wells’ production life cycle in addition to production reductions that resulted from well equipment problems at two Partnership wells. Production and operating costs were somewhat higher by 16%, primarily due to accruing environmental remediation costs in 2010. This production cost increase was partially offset by the downward adjustment of prior year accrued production taxes that was recognized in the first quarter 2010. Production and operating costs per Mcfe were $2.66 for the six months ended June 30 of 2010 compared to $1.74 for the comparable period in 2009.

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

For the quarter ended June 30, 2010 compared to the same period in 2009, natural gas and oil production on an energy equivalency-basis, decreased 31%, primarily as a result of the Partnership wells’ reduced performance due to the reasons noted above, in addition to second quarter operational constraints at some Wattenberg Field wells. Production and operating costs were higher by approximately $50,000, or 56%, primarily due to the environmental remediation accrual, described above, and higher 2010 well operations costs as a result of the increase in the per well operations fee charged by the Managing General Partner, consistent with the terms of the D&O Agreement. Production and operating costs per Mcfe were $3.58 and $1.59 for the quarter ended June 30, 2010 and 2009, respectively.

Direct Costs−General and Administrative

Six months ended June 30, 2010 as compared to six months ended June 30, 2009

Direct costs – general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer’s reserve reports and legal matters. Direct costs increased during the six months ended June 30, 2010, compared to the same period in 2009, by approximately $0.3 million principally due to increased fees for professional services related to the Partnership’s SEC reporting compliance efforts previously described in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Partnership Operating Results Overview.

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

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Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Depreciation, Depletion and Amortization

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

Six months ended June 30, 2010 as compared to six months ended June 30, 2009

The DD&A expense rate per Mcfe decreased to $3.17 for the 2010 six month period, compared to $4.12 during the same period in 2009, as calculated by the respective methodologies described above. The decrease in the per Mcfe rates for the 2010 period compared to the 2009 period is primarily the result of the reduction of the capitalized properties subject to DD&A as a consequence of the fourth quarter 2009 Grand Valley Field loss on natural gas and oil properties’ impairment. This reduction in the DD&A expense rate period-over-period due to impairment recognition was partially offset by the effect of the Partnership’s proved developed producing reserve revisions at December 31, 2009 compared to December 31, 2008, in which the downward estimate revision of the Partnership’s proved developed producing natural gas and oil reserves in the Partnership’s Grand Valley Field was partially offset by an upward estimate in Wattenberg Field reserves. The decreased DD&A expense rate, combined with the effect of the production declines noted in previous sections, resulted in a decreased DD&A expense of approximately $0.2 million for the 2010 six month period compared to the same 2009 period.

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

The DD&A expense rate per Mcfe decreased to $3.07 for the 2010 second quarter, compared to $4.17 during the same quarter in 2009 as calculated by the respective methodologies described above. The decrease in the per Mcfe rates for the 2010 second quarter compared to the 2009 second quarter is a result of the offsetting effects of the Grand Valley Field impairment recognition and annual reserve estimate revisions, noted above. The lower DD&A expense rate, combined with the effect of the production declines noted in previous sections, resulted in the DD&A expense reduction of $0.1 million for the 2010 second quarter compared to the same 2009 quarter.

Capital Resources and Liquidity

The Partnership’s primary sources of cash for both the three and the six months ended June 30, 2010 were from funds provided by operating activities which include the sale of natural gas and oil production and the realized gains from the Partnership’s derivative positions. These sources of cash were primarily used to fund the Partnership’s operating costs, general and administrative activities and provide monthly distributions to the Investor Partners and PDC, the Managing General Partner. Fluctuations in the Partnership’s operating cash flow are substantially driven by changes in commodity prices, in production volumes and in realized gains and losses from commodity positions. Commodity prices have historically been volatile and the Partnership attempts to manage this volatility through derivatives. Therefore, the primary source of the Partnership’s cash flow from operations becomes the net activity between the Partnership’s natural gas and oil sales and realized derivative gains and losses. However, the Partnership does not engage in speculative positions, nor does the Partnership hold economic hedges for 100% of the Partnership’s expected future production from producing wells and therefore may still experience significant fluctuations in cash flows from operations. As of June 30, 2010, the Partnership had natural gas and oil derivative positions in place covering substantially all of the expected natural gas production and 78% of expected oil production for the remainder of 2010, at an average price of $3.95 per Mcf and $92.96 per Bbl, respectively. The Partnership’s current derivative position average prices have declined from the significantly higher average commodity contract strike price levels in effect during the 2009 comparative period, which were the result of contracts entered into during the high 2008 commodity price market; accordingly, the Partnership anticipates realized gains for the next 12 months to remain substantially below gains realized in 2009 and the first quarter of 2010. See Results of Operations for further discussion of the impact of prices and volumes on sales from operations and the impact of derivative activities on the Partnership’s revenues.

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Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

Working Capital

The Partnership had negative working capital of $0.1 million at June 30, 2010 compared to working capital of $0.2 million at December 31, 2009. This decrease of approximately $0.3 million was primarily due to the following changes in accounts receivable balances:

●

Natural gas and oil receivables decreased to $0.1 million as of June 30, 2010, from $0.3 million as of December 31, 2009.

●

Realized derivative gains receivables decreased by $0.1 million as of June 30, 2010 compared to December 31, 2009.

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

Cash Flows

Cash Flows From Investing Activities

The Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of natural gas and oil or environmental protection. These amounts totaled approximately $1,000 and $5,000 for the six months ended June 30, 2010 and 2009, respectively.

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Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in March 2004 and has distributed $18.5 million through June 30, 2010. The table below presents the cash distributions to the Managing General Partner and Investor Partners, including Managing General Partner distributions relating to limited partnership units repurchased, for the periods described.

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

2010	$	40,501	$	162,004	$	202,505

2009	$	101,499	$	405,997	$	507,496

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

2010	$	96,638	$	386,548	$	483,186

2009	$	211,516	$	846,067	$	1,057,583

The Partnership began funding for the Well Refracturing Plan during October 2010. On a pro-rata basis based on percentage of ownership in the Partnership, the Partnership withheld $4,000 and $16,000 from the Managing General Partner and Investor Partners’ share, respectively, of distributable cash flows from the Partnership’s August 2010 natural gas and oil revenues distributed in October 2010. The October 2010 and subsequent withholdings will provide the funding for planned Wattenberg Field well refracturing costs to be incurred during 2011, and thereafter.

Cash Flows From Operating Activities

Net cash provided by operating activities was $0.5 million for the six months ended June 30, 2010, compared to $1.1 million for the comparable period in 2009. The approximately $0.6 million decrease in cash provided by operating activities was due primarily to the following:

●

An increase in natural gas and oil sales receipts of $0.1 million, or 21%;

●

A decrease in commodity price risk management realized gains receipts of $0.3 million, or 50%; and an increase in direct costs – general and administrative of $0.3 million; and

●

A decrease in the liability Due to Managing General Partner-other, net, excluding natural gas and oil sales received from third parties and realized derivative gains, of approximately $0.1 million.

Commitments and Contingencies

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

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Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Recent Accounting Standards

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

Critical Accounting Policies and Estimates

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

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

Off-Balance Sheet Arrangements

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

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Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

Item 4.

Controls and Procedures

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

(a) Evaluation of Disclosure Controls and Procedures

As of June 30, 2010, PDC, as Managing General Partner of the Partnership, carried out an evaluation under the supervision and with the participation of the Managing General Partner’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Partnership’s disclosure controls and procedures pursuant to Securities Exchange Act Rule 13a-15(e) and 15d-15(e). This evaluation considered the various processes carried out under the direction of the Managing General Partner’s Disclosure Committee in an effort to ensure that information required to be disclosed in the SEC reports that we file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that such information is accumulated and communicated to the Partnership’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely discussion regarding required financial disclosure.

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

(b) Changes in Internal Control over Financial Reporting

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

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Index

PDC 2003-B LIMITED 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 March 2007, the third anniversary of the date of the first Partnership cash distributions, Investor Partners of the Partnership may request that the Managing General Partner repurchase their respective individual Investor Partner units, up to an aggregate total limit during any calendar year for all requesting Investor Partner unit repurchases of 10% of the initial subscription units.

The following table presents information about the Managing General Partner’s limited partner unit repurchases during the three months ended June 30, 2010.

Period	Total Number of Units Repurchased		Average Price Paid per Unit

April 1−30, 2010		—	$	—
May 1−31, 2010		—		—
June 1−30, 2010		2.00		3,455
Total second quarter Unit Repurchase Program repurchases		2.00

Item 3.

Defaults Upon Senior Securities

Not applicable.

Item 4.

[Removed and Reserved]

Item 5.

Other Information

Not applicable.

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Index

PDC 2003-B LIMITED 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

000-50616

3.1

02/12/2010

3.2

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

10-K

000-50616

3.2

02/12/2010

10.1

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

10-K

000-50616

10.1

02/12/2010

31.1

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

31.2

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

32.1

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

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Index

PDC 2003-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

SIGNATURES

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

PDC 2003-B Limited Partnership

By its Managing General Partner

Petroleum Development Corporation (dba PDC Energy)

By /s/ Richard W. McCullough

Richard W. McCullough

Chairman and Chief Executive Officer

of Petroleum Development Corporation (dba PDC Energy)

December 15, 2010

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

Signature	Title	Date

/s/ Richard W. McCullough	Chairman and Chief Executive Officer	December 15, 2010
Richard W. McCullough	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
	(Principal executive officer)

/s/ Gysle R. Shellum	Chief Financial Officer	December 15, 2010
Gysle R. Shellum	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
	(Principal financial officer)

/s/ R. Scott Meyers	Chief Accounting Officer	December 15, 2010
R. Scott Meyers	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
	(Principal accounting officer)

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PDC 2003-B LP - FORM 10-Q - December 15, 2010

Attached files

PDC 2003-B LP Reports