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 March 31, 2011
 or
 
 o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD ____________ TO ____________





Commission File Number   000-51452





PDC 2005-B Limited Partnership


(Exact name of registrant as specified in its charter)


West Virginia

20-2088726(State or other jurisdiction of incorporation or organization)

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


1775 Sherman Street, Suite 3000, Denver, Colorado  80203


(Address of principal executive offices)     (Zip code)





(303) 860-5800


(Registrant's telephone number, including area code)




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


Yes þ  No   ̈





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





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





Large accelerated filer ̈
Accelerated filer ̈Non-accelerated filer ̈
Smaller reporting companyþ





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





As of March 31, 2011 the Partnership had 2,022.64 units of limited partnership interest and no units of additional general partnership interest outstanding.













PDC 2005-B LIMITED PARTNERSHIP


(A West Virginia Limited Partnership)





INDEX TO REPORT ON FORM 10-Q





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




Index




SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS




This periodic report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”) regarding PDC 2005-B Limited Partnership’s (“Partnership” or the “Registrant”) business, financial condition and results of operations.  Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, is the Managing General Partner of the Partnership.  All statements other than statements of historical facts included in and incorporated by reference into this report are “forward-looking statements” within the meaning of the safe harbor provisions of the United States Private Securities Litigation Reform Act of 1995.  Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein, which include statements of estimated natural gas, natural gas liquid(s) or “NGL(s)”, and crude oil production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and the Managing General Partner’s strategies, plans and objectives. However, these are not the exclusive means of identifying forward-looking statements herein.  Although forward-looking statements contained in this report reflect the Managing General Partner's good faith judgment, such statements can only be based on facts and factors currently known to the Managing General Partner.  Consequently, forward-looking statements are inherently subject to risks and uncertainties, including known and unknown risks and uncertainties incidental to the development, production and marketing of natural gas, NGLs and crude oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:




·
changes in production volumes and worldwide demand;
 ·
volatility of commodity prices for natural gas and crude oil;
 ·
changes in estimates of proved reserves;
 ·
inaccuracy of reserve estimates and expected production rates;
 ·
declines in the value of the Partnership’s natural gas and crude oil properties resulting in impairments
 ·
the availability of Partnership future cash flows for investor distributions or funding of refracturing  activities;
 ·
the timing and extent of the Partnership’s success in further developing and producing the Partnership’s reserves;
 ·
the Managing General Partner’s ability to acquire drilling rig services, supplies and services at reasonable prices;
 ·
risks incidental to the refracturing and operation of natural gas and crude oil wells;
 ·
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 U.S. as well as other oil producing countries throughout the world;
 ·
changes in environmental laws, the regulation and enforcement of those laws and the costs to comply with those laws;
 ·
the impact of environmental events, governmental responses to the events and the Managing General Partner’s ability to insure adequately against such events;
 ·
competition in the oil and gas industry;
 ·
the success of the Managing General Partner in marketing the Partnership’s oil and gas;
 ·
the effect of natural gas and crude oil derivative activities;
 ·
the availability of funding for the consideration payable by PDC and its wholly-owned subsidiary to consummate the prospective mergers of the 2005 partnerships and the timing of consummating these mergers, if at all;
 ·
losses possible from pending or future litigation; and
 ·
the success of strategic plans, expectations and objectives for future operations of the Managing General Partner.


- 1 -
 Index


PDC 2005-B LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)


Further, the Partnership urges the reader to carefully review and consider the cautionary statements and disclosures made in this report, the Partnership’s annual report on Form 10-K for the year ended December 31, 2010 filed with the Securities and Exchange Commission (“SEC”) on March 30, 2011 (“2010 Form 10-K”) and the Partnership’s other filings with the SEC for further information on risks and uncertainties that could affect the Partnership’s business, financial condition and results of operations, which are incorporated by this reference as though fully set forth herein.  Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report.  The Partnership undertakes no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events.  All forward looking statements are qualified in their entirety by this cautionary statement.




- 2 -
 Index


PART I – FINANCIAL INFORMATION





Item 1.    Financial Statements (unaudited)




PDC 2005-B Limited Partnership


Condensed Balance Sheets


(unaudited)




March 31,


December 31,2011


2010*AssetsCurrent assets:Cash and cash equivalents

$
442,976


$
332,724Accounts receivable


288,892



263,151Crude oil inventory


36,132



56,629Due from Managing General Partner-derivatives


656,668



627,166Due from Managing General Partner-other, net


99,381



163,036Total current assets


1,524,049



1,442,706Natural gas and crude oil properties, successful efforts method, at cost


45,061,383



45,057,210Less:  Accumulated depreciation, depletion and amortization


(24,210,114
)


(23,606,787
)Natural gas and crude oil properties, net


20,851,269



21,450,423Due from Managing General Partner-derivatives


841,097



982,178Other assets


52,445



45,853Total noncurrent assets


21,744,811



22,478,454Total Assets

$
23,268,860


$
23,921,160Liabilities and Partners' EquityCurrent liabilities:Accounts payable and accrued expenses

$
68,356


$
28,315Due to Managing General Partner-derivatives


671,264



564,535Total current liabilities


739,620



592,850Due to Managing General Partner-derivatives


662,199



745,409Asset retirement obligations


558,395



551,063Total liabilities


1,960,214



1,889,322Commitments and contingent liabilitiesPartners' equity:Managing General Partner


4,272,798



4,417,437Limited Partners -  2,022.64 units issued and outstanding


17,035,848



17,614,401Total Partners' equity


21,308,646



22,031,838Total Liabilities and Partners' Equity

$
23,268,860


$
23,921,160


*Derived from audited 2010 balance sheet




See accompanying notes to unaudited condensed financial statements.




- 3 -
 Index


PDC 2005-B Limited Partnership
 Condensed Statements of Operations
 (unaudited)


Three months ended March 31,2011


2010Revenues:Natural gas, NGLs and crude oil sales

$
880,859


$
1,171,574Commodity price risk management (loss) gain, net


(110,654
)


828,302Total revenues


770,205



1,999,876Operating costs and expenses:Natural gas, NGLs and crude oil production costs


355,096



302,984Direct costs - general and administrative


47,760



35,743Depreciation, depletion and amortization


603,327



782,307Accretion of asset retirement obligations


7,332



6,909Total operating costs and expenses


1,013,515



1,127,943Net (loss) income

$
(243,310
)

$
871,933Net (loss) income allocated to partners

$
(243,310
)

$
871,933Less:  Managing General Partner interest in net (loss) income


(48,662
)


174,387Net (loss) income allocated to Investor Partners

$
(194,648
)

$
697,546Net (loss) income per Investor Partner unit

$
(96
)

$
345Investor Partner units outstanding


2,022.64



2,022.64


See accompanying notes to unaudited condensed financial statements.




- 4 -
 Index




PDC 2005-B Limited Partnership


Condensed Statements of Cash Flows
 (unaudited)


Three months ended March 31,2011


2010Cash flows from operating activities:Net (loss) income

$
(243,310
)

$
871,933Adjustments to net (loss) income to reconcile to net cash provided by operating activities:Depreciation, depletion and amortization


603,327



782,307Accretion of asset retirement obligations


7,332



6,909Unrealized loss (gain) on derivative transactions


135,098



(461,884
)Changes in operating assets and liabilities:Increase in accounts receivable


(25,741
)


(25,989
)Decrease in crude oil inventory


20,497



7,498Increase in other assets


(6,592
)


(6,786
)Increase in accounts payable andaccrued expenses


40,041



4,644Decrease in Due from Managing GeneralPartner - other, net


63,655



8,068Net cash provided by operating activities


594,307



1,186,700Cash flows from investing activities:Capital expenditures for natural gas and crude oil properties


(4,173
)


(5,762
)Net cash used in investing activities


(4,173
)


(5,762
)Cash flows from financing activities:Distributions to Partners


(479,882
)


(1,180,938
)Net cash used in financing activities


(479,882
)


(1,180,938
)Net increase in cash and cash equivalents


110,252



-Cash and cash equivalents, beginning of period


332,724



201,006Cash and cash equivalents, end of period

$
442,976


$
201,006





See accompanying notes to unaudited condensed financial statements.




- 5 -
 Index




PDC 2005-B LIMITED PARTNERSHIP
 NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
 March 31, 2011
 (unaudited)


Note 1−General and Basis of Presentation





PDC 2005-B Limited Partnership (the “Partnership” or the “Registrant”) was organized as a limited partnership, in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of natural gas and crude oil properties.  Business operations of the Partnership commenced upon closing of an offering for the sale of Partnership units.  Upon funding, the Partnership entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner which authorizes Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, to conduct and manage the Partnership’s business.  In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), the Managing General Partner is authorized to manage all activities of the Partnership and initiates and completes substantially all Partnership transactions.





As of March 31, 2011, there were 1,619 Investor Partners.  PDC is the designated Managing General Partner of the Partnership and owns a 20% Managing General Partner ownership in the Partnership.  According to the terms of the Limited Partnership Agreement, revenues, costs and cash distributions of the Partnership are allocated 80% to the limited partners (“Investor Partners”), which are shared pro rata, based upon the number of units in the Partnership, and 20% to the Managing General Partner.  The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual Investor Partner.  Through March 31, 2011, the Managing General Partner has repurchased 51.7 units of Partnership interests from Investor Partners at an average price of $9,979 per unit.  As of March 31, 2011, the Managing General Partner owns 22.0% of the Partnership.





The Partnership expects continuing operations of its natural gas and crude oil properties until such time the Partnership’s wells are depleted or become uneconomical to produce, at which time they may be sold or plugged, reclaimed and abandoned.  The Partnership’s maximum term of existence extends through December 31, 2055, unless dissolved by certain conditions stipulated within the Agreement which are unlikely to occur at this time, or by written consent of the Investor Partners owning a majority of outstanding units at that time.





In the Managing General Partner’s opinion, the accompanying interim unaudited condensed financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary for a fair statement of the Partnership’s financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities and Exchange Commission (“SEC”).  Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in the audited financial statements have been condensed or omitted.  The information presented in this quarterly report on Form 10-Q should be read in conjunction with the Partnership’s audited financial statements and notes thereto included in the Partnership’s 2010 Form 10-K.  The Partnership’s accounting policies are described in the Notes to Financial Statements in the Partnership’s 2010 Form 10-K and updated, as necessary, in this Form 10-Q.  The results of operations for the three months ended March 31, 2011, and the cash flows for the same period, are not necessarily indicative of the results to be expected for the full year or any other future period.





On November 16, 2010, the Partnership, PDC and its wholly-owned subsidiary, DP 2004 Merger Sub, LLC (“DP Merger Sub”), a Delaware limited liability company, entered into an agreement and plan of merger (the “Merger Agreement”), in which PDC seeks to acquire the Partnership, subject to the vote and approval of a majority of the limited partnership units held, as of the close of business on January 31, 2011, by Investor Partners of the Partnership, other than PDC and its affiliates (“non-affiliated investor partners”).  Pending the outcome of the proposed Merger Agreement, the Managing General Partner suspended, as of December 1, 2010, the opportunity for an individual non-affiliated investor partner to request that PDC repurchase their respective limited partnership units.  For more information on the proposed Merger Agreement, see Note 3, Transactions with Managing General Partner and Affiliates−Proposed Merger with PDC and DP 2004 Merger Sub, LLC, which follows.





- 6 -
 Index




PDC 2005-B LIMITED PARTNERSHIP
 NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
 March 31, 2011
 (unaudited)


Note 2−Recent Accounting Standards





Recently Adopted Accounting Standards





Fair Value Measurements and Disclosures





In January 2010, the FASB issued changes related to fair value measurements requiring gross presentation of activities within the Level 3 roll forward, whereby entities must present separately information about purchases, sales, issuances and settlements.  These changes were effective for the Partnership’s financial statements issued for annual reporting periods, and for interim reporting periods within the year, beginning after December 15, 2010.  The adoption of this change did not have a material impact on the Partnership’s financial statements.





Note 3−Transactions with Managing General Partner and Affiliates





Ongoing Partnership Business and Operations





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





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





March 31,


December 31,2011


2010Natural gas, NGLs and crude oil sales revenues collected from the Partnership's third-party customers

$
264,323


$
286,822Commodity price risk management, realized gain


12,053



91,058Other (1)


(176,995
)


(214,844
)Total Due from Managing General Partner-other, net

$
99,381


$
163,036




(1)
All other unsettled transactions, excluding derivative instruments, between the Partnership and the Managing General Partner.  The majority of these are operating costs or general and administrative costs which have not been deducted from distributions.




- 7 -
 Index




PDC 2005-B LIMITED PARTNERSHIP
 NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
 March 31, 2011
 (unaudited)





The following table presents Partnership transactions, excluding derivative transactions which are more fully detailed in Note 5, Derivative Financial Instruments, with the Managing General Partner and its affiliates for the three months ended March 31, 2011 and 2010.  “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Natural gas, NGLs and crude oil production costs” line item on the condensed statements of operations.





Three months ended March 31,2011


2010Well operations and maintenance

$
287,277


$
232,388Gathering, compression and processing fees


28,700



27,525Direct costs - general and administrative


47,760



35,743Cash distributions (1)


105,783



255,925




(1)
Cash distributions include $9,806 and $19,738 during the three months ended March 31, 2011 and 2010, respectively, related to equity cash distributions on Investor Partner units repurchased by PDC.




Proposed Merger with PDC and DP 2004 Merger Sub, LLC





On November 16, 2010, the Partnership, PDC and DP Merger Sub entered into the Merger Agreement, in which PDC seeks to acquire the Partnership, subject to the vote and approval of a majority of the limited partnership units held, as of the close of business on January 31, 2011, by non-affiliated investor partners. Pursuant to the Merger Agreement, if the merger is approved by the holders of a majority of the limited partnership units held by the non-affiliated investor partners of the Partnership, as well as, the satisfaction of other customary closing conditions, then the Partnership will merge with and into DP Merger Sub and non-affiliated investor partners will have the right to receive a cash payment for their limited partnership units.  DP Merger Sub shall be the surviving entity of the merger and shall be wholly-owned by PDC, and the limited partners will have no continuing interest in the Partnership, since the Partnership will cease as a separate business entity.  The merger will become effective following the filing of a certificate of merger with the Secretaries of State of West Virginia and Delaware as soon as practicable after the last condition precedent to the merger has been satisfied, or waived.  Following consummation of the merger, the non-affiliated investor partners will no longer participate in the Partnership’s future earnings or growth.




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




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




·
should all parties agree by mutual consent to terminate the Merger Agreement;
 
 ·
by any party thereto, should the proposed merger not occur by April 30, 2011; provided that if the SEC’s proxy disclosure review process has not yet been completed after good faith effort by PDC, such date will be extended until August 31, 2011 - neither PDC nor the Special Committee has exercised any such rights as of the date of this filing;
 
 ·
by any party thereto, should consummation of the merger become illegal or be otherwise prohibited by law or regulation;




- 8 -
 Index


PDC 2005-B LIMITED PARTNERSHIP
 NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
 March 31, 2011
 (unaudited)
  ·
by PDC or the Partnership, should either PDC or the Partnership fail to perform its obligations under the Merger Agreement and such failure has a non-curable material adverse effect on the PDC or the Partnership, respectively, or materially and adversely affects the transactions contemplated by the Merger Agreement.
  ·
by any party thereto, should any suit or action be pending against parties to the Merger Agreement challenging the legality or any aspect of the merger transaction;
 
 ·
by the Special Committee, on behalf of the Partnership and prior to approval by non-affiliated investor partners, should the Special Committee believe it has received a superior offer that is more favorable to the non-affiliated investor partners; or


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




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




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




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




- 9 -
 Index





PDC 2005-B LIMITED PARTNERSHIP
 NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
 March 31, 2011
 (unaudited)


Note 4−Fair Value of Financial Instruments





The following table presents, for each hierarchy level, the Partnership’s derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis as of March 31, 2011 and December 31, 2010.




March 31, 2011


December 31, 2010Quoted Prices in

Active Markets

Level 1


Significant

Unobservable Inputs

Level 3


Total


Quoted Prices in

Active Markets

Level 1


Significant

Unobservable Inputs

Level 3


TotalAssets:Commodity based derivatives

$
1,475,995


$
21,770


$
1,497,765


$
1,540,345


$
68,999


$
1,609,344Total assets


1,475,995



21,770



1,497,765



1,540,345



68,999



1,609,344Liabilities:Commodity based derivatives


-



(217,024
)


(217,024
)


-



(176,801
)


(176,801
)Basis protection derivative contracts


-



(1,116,439
)


(1,116,439
)


-



(1,133,143
)


(1,133,143
)Total liabilities


-



(1,333,463
)


(1,333,463
)


-



(1,309,944
)


(1,309,944
)Net asset (liability)

$
1,475,995


$
(1,311,693
)

$
164,302


$
1,540,345


$
(1,240,945
)

$
299,400




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





Three months endedMarch 31, 2011


March 31, 2010Fair value, net liability, beginning of year

$
(1,240,945
)

$
(984,005
)Changes in fair value included in statement of operations line item -Commodity price risk management, net


(129,622
)


(105,143
)Settlements


58,874



(366,418
)Fair value, net liability, end of period

$
(1,311,693
)

$
(1,455,566
)Change in unrealized loss relating to assets (liabilities) still held as of March 31, 2011 and 2010, respectively,included in statement of operations line item:Commodity price risk management, net

$
(127,468
)

$
(132,866
)





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





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




- 10 -
 Index




PDC 2005-B LIMITED PARTNERSHIP
 NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
 March 31, 2011
 (unaudited)


Note 5−Derivative Financial Instruments





As of March 31, 2011, the Partnership had derivative instruments in place for a portion of its anticipated production through 2013 for a total of 792,019 MMbtu of natural gas and 6,044 Bbls of crude oil.





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





Fair ValueBalance Sheet

March 31,


December 31,Derivative instruments not designated as hedge  (1):

Line Item

2011


2010Derivative Assets:
CurrentCommodity contracts

Due from Managing General

$
656,668


$
627,166Partner-derivativesNon CurrentCommodity contracts

Due from Managing General


841,097



982,178Partner-derivativesTotal Derivative Assets




$
1,497,765


$
1,609,344Derivative Liabilities:
CurrentCommodity contracts

Due to Managing General

$
217,024


$
176,801Partner-derivativesBasis protection contracts

Due to Managing General


454,240



387,734Partner-derivativesNon CurrentBasis protection contracts

Due to Managing General


662,199



745,409Partner-derivativesTotal Derivative Liabilities



$
1,333,463


$
1,309,944




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





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





Three months ended March 31,2011


2010Statement of operations line item

Reclassification of Realized Loss (Gain) Included in Prior Periods Unrealized


Realized and Unrealized Gain (Loss) For the Current Period


Total


Reclassification of Realized Loss (Gain) Included in Prior Periods Unrealized


Realized and Unrealized Gain For the Current Period


TotalCommodity price risk management, netRealized gain

$
18,239


$
6,205


$
24,444


$
338,695


$
27,723


$
366,418Unrealized (loss) gain


(18,239
)


(116,859
)


(135,098
)


(338,695
)


800,579



461,884Total commodity price risk management (loss) gain, net

$
-


$
(110,654
)

$
(110,654
)

$
-


$
828,302


$
828,302




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




- 11 -
 Index




PDC 2005-B LIMITED PARTNERSHIP
 NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
 March 31, 2011
 (unaudited)


Note 6−Commitments and Contingencies





Legal Proceedings





Neither the Partnership nor PDC, in its capacity as the Managing General Partner of the Partnership, are party to any pending legal proceeding that PDC believes would have a materially adverse effect on the Partnership’s business, financial condition, results of operations or liquidity.





Environmental





Due to the nature of the natural gas and crude oil industry, the Partnership is exposed to environmental risks.  The Managing General Partner has various policies and procedures to avoid environmental contamination and mitigate the risks from environmental contamination.  The Managing General Partner conducts periodic reviews to identify changes in the Partnership’s environmental risk profile.  Liabilities are accrued when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated.  During the three months ended March 31, 2011, there was one new environmental remediation project identified by the Managing General Partner in which $55,000 in expenses were recorded and are included in the line item captioned “Natural gas, NGLs and crude oil production costs.”  As of March 31, 2011, the Partnership has accrued environmental remediation liabilities for one of the Partnership’s well pads involving two wells in the amount of $37,000 which is included in line item captioned “Accounts payable and accrued expenses” on the condensed Balance Sheets.  As of December 31, 2010, the Partnership had immaterial accrued environmental remediation liabilities which are included in line item captioned “Accounts payable and accrued expenses” on the condensed Balance Sheets.  The Managing General Partner is not aware of any environmental claims existing as of March 31, 2011, which have not been provided for or would otherwise have a material impact on the Partnership’s financial statements.  However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on the Partnership’s properties.




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




- 12 -
 Index





PDC 2005-B LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)




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





Partnership Overview





PDC 2005-B Limited Partnership engages in the development, production and sale of natural gas, NGLs and crude oil.  The Partnership began natural gas and crude oil operations in May 2005 and operates 49 gross (45.4 net) productive wells located in the Rocky Mountain Region in the state of Colorado.  In addition, two gross (1.9 net) Wattenberg Field Partnership wells are temporarily not in production at March 31, 2011 due to equipment problems or operational issues. One additional well drilled was evaluated as commercially unproductive and was therefore declared to be a developmental dry hole. The Managing General Partner markets the Partnership’s natural gas and crude oil production to commercial end users, interstate or intrastate pipelines, local utilities or oil companies, primarily under market sensitive contracts in which the price of natural gas, NGLs and crude oil sold varies as a result of market forces.  PDC does not charge an additional fee for the marketing of the natural gas, NGLs and crude oil because these services are covered by the monthly well operating charge.  PDC, on behalf of the Partnership in accordance with the D&O Agreement, is authorized to enter into multi-year fixed price contracts or utilize derivatives, including collars, swaps or basis protection swaps, in order to offset some or all of the commodity price variability for particular periods of time.  Seasonal factors, such as effects of weather on prices received and costs incurred, and availability of pipeline capacity, owned by PDC or other third parties, may impact the Partnership's results.  In addition, both sales volumes and prices tend to be affected by demand factors with a seasonal component.





Recent Developments





PDC Sponsored Drilling Program Acquisition Plan





In November 2010, PDC and DP 2004 Merger Sub, LLC, a wholly-owned subsidiary of PDC (“DP Merger Sub”), entered into separate merger agreements with this Partnership, PDC 2005-A Limited Partnership and Rockies Region Private Limited Partnership (collectively, the “2005 Partnerships”).  PDC serves as the Managing General Partner of each of the 2005 Partnerships.




Pursuant to the Partnership’s merger agreement with PDC (the “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 the Partnership, as well as, the satisfaction of other customary closing conditions, then the Partnership will merge with and into DP Merger Sub and non-affiliated investor partners will have the right to receive a cash payment for their limited partnership units.  DP Merger Sub shall be the surviving entity of the merger and shall be wholly-owned by PDC, and the limited partners will have no continuing interest in the Partnership, since the Partnership will cease as a separate business entity.  The merger will become effective following the filing of a certificate of merger with the Secretaries of State of West Virginia and Delaware as soon as practicable after the last condition precedent to the merger has been satisfied, or waived.  Following consummation of the merger, the non-affiliated investor partners will no longer participate in the Partnership’s future earnings or growth.




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




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




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





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




- 13 -
 Index




PDC 2005-B LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)




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





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





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





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





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




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




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




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


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




Well Refracturing Plan





The Managing General Partner has prepared a plan for the Partnership’s Wattenberg Field wells which may provide for additional reserve development of natural gas, NGLs and crude oil production (the “Well Refracturing Plan”).  The Well Refracturing Plan consists of the Partnership’s refracturing of wells currently producing in the Codell formation.  Under the Well Refracturing Plan, the Partnership plans to initiate refracturing activities during 2012.  Refracturing, or “refracing,” activities consist of a second hydraulic fracturing treatment in a current production zone, all within an existing well bore.




- 14 -
 Index




PDC 2005-B LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)




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





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





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





If any or all of the Partnership’s Wattenberg wells are not refractured, the Partnership will experience a reduction in proved reserves currently assigned to these wells.  Both the number and timing of the refracturing activities will be based on the availability of cash withheld from Partnership distributions.  The Managing General Partner believes that, based on projected refracturing costs and projected cash withholding, all scheduled Partnership refracturing activity will be completed within a five year period.  Any funds not used for refracturing or other operational needs will be distributed to the Managing General Partner and Investor Partners based on their proportional ownership interest.





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




- 15 -
 Index




PDC 2005-B LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)




Partnership Operating Results Overview





Natural gas, NGLs and crude oil sales decreased 25% or $0.3 million for the first three months of 2011 compared to the first three months of 2010, while sales volumes declined 11% period-to-period.  The average sales price per Mcfe, excluding the impact of net realized derivative gains, was $5.68 for the current year period compared to $6.70 for the same period a year ago.  Net realized derivative gains from natural gas and crude oil sales contributed an additional $0.16 per Mcfe or $24,000 to the first three months of 2011 total revenues compared to an additional $2.10 or $366,000 to the first three months of 2010.  Comparatively, the total realized price per Mcfe, consisting of the average sales price and realized derivative gains, decreased to $5.84 for the current year three months from $8.80 for the same prior year period. During the three months ended March 31, 2011, natural gas revenue included $59,000 from a settlement more fully discussed in the notes to the Summary Operating Results table.




- 16 -
 Index





PDC 2005-B LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)





Results of Operations





Summary Operating Results





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





Three months ended March 31,2011


2010


ChangeNumber of producing wells (end of period)


49



48



1Production(1)Natural gas (Mcf)(2)


119,608



121,980



-2
%NGLs (Bbl)


747



1,343



-44
%Crude oil (Bbl)


5,145



7,471



-31
%Natural gas equivalents (Mcfe)(3)


154,960



174,864



-11
%Average Mcfe per day


1,722



1,943



-11
%Natural Gas, NGLs and Crude Oil SalesNatural gas (4)

$
408,735


$
577,821



-29
%NGLs


33,113



49,155



-33
%Crude oil


439,011



544,598



-19
%Total natural gas, NGLs and crude oil sales

$
880,859


$
1,171,574



-25
%Realized Gain (Loss) on Derivatives, netNatural gas

$
70,560


$
305,693



-77
%Crude oil


(46,116
)


60,725



-176
%Total realized gain on derivatives, net

$
24,444


$
366,418



-93
%Average Selling Price (excluding realized gain (loss) on derivatives)Natural gas (per Mcf)  (4)

$
3.42


$
4.74



-28
%NGLs (per Bbl)


44.33



36.60



21
%Crude oil (per Bbl)


85.33



72.89



17
%Natural gas equivalents (per Mcfe)


5.68



6.70



-15
%Average Selling Price (including realized gain (loss) on derivatives)Natural gas (per Mcf)

$
4.01


$
7.24



-45
%NGLs (per Bbl)


44.33



36.60



21
%Crude oil (per Bbl)


76.36



81.02



-6
%Natural gas equivalents (per Mcfe)


5.84



8.80



-34
%Average cost per McfeNatural gas, NGLs and crude oil production cost(5)

$
2.29


$
1.73



32
%Depreciation, depletion and amortization


3.89



4.47



-13
%Operating costs and expenses:Direct costs - general and administrative

$
47,760


$
35,743



34
%Depreciation, depletion and amortization


603,327



782,307



-23
%Cash distributions

$
479,882


$
1,180,938



-59
%





Amounts may not calculate due to rounding.




- 17 -
 Index




PDC 2005-B LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)




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


(2)
Approximately 9,926 Mcf, or 8%, of the Partnership’s natural gas production was the result of a settlement with a third-party gas purchaser recorded during the three months ended March 31, 2011, related to prior years’ volume imbalances.


(3)
Six Mcf of natural gas equals one Bbl of crude oil or NGL.


(4)
Approximately $59,000, or 15%, of the Partnership’s natural gas sales and with an effect of $0.23 per Mcf to the Partnership’s average overall Mcf price for natural gas sales revenue was the result of the settlement with a third-party gas purchaser noted in footnote 2 above.


(5)
Production costs represent natural gas, NGLs and crude oil operating expenses which include production taxes.





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





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


·
MBbl – One thousand barrels


·
Mcf – One thousand cubic feet


·
MMcf – One million cubic feet


·
Mcfe – One thousand cubic feet of natural gas equivalents


·
MMcfe – One million cubic feet of natural gas equivalents


·
MMbtu – One million British Thermal Units





Natural Gas, NGLs and Crude Oil Sales





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





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





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





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




- 18 -
 Index




PDC 2005-B LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)


Commodity Price Risk Management, Net





The Partnership uses various derivative instruments to manage fluctuations in natural gas and crude oil prices.  The Partnership has in place a variety of floors, collars, fixed-price swaps and basis swaps on a portion of the Partnership’s estimated natural gas and crude oil production.  Because the Partnership sells its natural gas and crude oil at similar prices to the indices inherent in the Partnership’s derivative instruments, the Partnership ultimately realizes a price related to its collars of no less than the floor and no more than the ceiling and, for the Partnership’s commodity swaps, the Partnership ultimately realizes the fixed price related to its swaps.





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





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





Three months ended March 31,Commodity price risk management, net

2011


2010Realized gain (loss)Natural gas

$
70,560


$
305,693Crude oil


(46,116
)


60,725Total realized gain, net


24,444



366,418Unrealized (loss) gainReclassification of realized gain included in prior periods unrealized prior periods unrealized


(18,239
)


(338,695
)Unrealized (loss) gain for the period


(116,859
)


800,579Total unrealized (loss) gain, net


(135,098
)


461,884Commodity price risk management (loss) gain, net

$
(110,654
)

$
828,302




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





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





During the three months ended March 31, 2010, the Partnership recorded realized gains of $366,000 as a result of natural gas and crude oil spot prices being lower at settlement compared to the respective strike price.  During the three months ended March 31, 2010, the Partnership recorded unrealized gains of $801,000, of which $967,000 was related to the Partnership’s natural gas and crude oil positions, partially offset by unrealized losses on the Partnership’s CIG basis protection swaps of $166,000 as the forward basis differential between NYMEX and CIG had continued to narrow.




- 19 -
 Index




PDC 2005-B LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)




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





Collars


Fixed-Price Swaps


CIG Basis Protection SwapsCommodity/

Index

Quantity

(Gas-

MMbtu(1))


Weighted Average

Contract Price


Quantity

(Gas-

MMbtu(1)

Oil-Bbls)


Weighted Average Contract

Price


Quantity

(Gas-

MMbtu(1))


Weighted Average Contract

Price


Fair Value at March 31, 2011(2)Floors


CeilingsNatural GasNYMEX04/01 - 06/30/2011


-


$
-


$
-



81,122


$
6.78



81,122


$
(1.88
)

$
78,70807/01 - 09/30/2011


-



-



-



79,721



6.73



79,721



(1.88
)


58,45710/01 - 12/31/2011


-



-



-



77,385



6.78



77,385



(1.88
)


41,99101/01 - 03/31/2012


6,161



6.00



8.27



68,423



6.98



74,583



(1.88
)


23,27504/01 - 12/31/2012


12,609



6.00



8.27



202,561



6.98



215,169



(1.88
)


103,8382013


-



-



-



264,037



7.12



264,037



(1.88
)


75,058Total Natural Gas


18,770











773,249







792,017







381,327Crude OilNYMEX04/01 - 06/30/2011


-



-



-



2,001



70.75



-



-



(70,875
)07/01 - 09/30/2011


-



-



-



2,027



70.75



-



-



(73,308
)10/01 - 12/31/2011


-



-



-



2,016



70.75



-



-



(72,842
)Total Crude Oil


-











6,044







-







(217,025
)Total Natural Gas and Crude Oil


























$
164,302





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


(2)
Approximately 2% of the fair value of the Partnership’s derivative assets and all of the Partnership’s derivative liabilities were measured using significant unobservable inputs (Level 3); see Note 4, Fair Value of Financial Instruments, to the accompanying unaudited condensed financial statements included in this report.





Natural Gas, NGLs and Crude Oil Production Costs





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





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





Production and operating costs per Mcfe increased to $2.29 during the current period compared to $1.73 for the prior year period due to the effect of higher per-well related expenditures partially offset by lower per-volume related natural gas, NGLs and crude oil production costs.  Current period production and operating costs increased by approximately $52,000, primarily due to increases in environmental costs of approximately $55,000 at two of the Partnership’s wells partially offset by decreases in natural gas transportation and lease operating expenses resulting from decreased production volumes as compared to the same period in 2010.




- 20 -
 Index


PDC 2005-B LIMITED PARTNERSHIP


(A West Virginia Limited Partnership)




Direct Costs−General and Administrative





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





Direct costs – general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer’s reserve reports and legal matters.  Direct costs increased during the three months ended March 31, 2011, compared to the same period in 2010, by approximately $12,000 principally due to increased fees for the above referenced professional services.





Depreciation, Depletion and Amortization





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





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





Financial Condition, Liquidity and Capital Resources





The Partnership’s primary sources of cash for the three months ended March 31, 2011 were from funds provided by operating activities which include the sale of natural gas, NGLs and crude oil production and the realized gains from the Partnership’s derivative positions.  These sources of cash were primarily used to fund the Partnership’s operating costs, general and administrative activities and provided monthly distributions to the Investor Partners and PDC, the Managing General Partner.  During the quarter ended March 31, 2011, the Managing General Partner withheld $60,000 from the Partnership’s cash distributions pursuant to the Well Refracturing Plan.  Through April 30, 2011, $130,000 has been withheld from Partnership distributions to fund this plan.  These and subsequent withholdings will provide the funding for planned Wattenberg Field well refracturing costs to be incurred during 2012, and thereafter and are expected to decrease distributions from the 2009 levels for the next several years.  For additional information, see Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments—Well Refracturing Plan.





Fluctuations in the Partnership’s operating cash flows are substantially driven by changes in commodity prices, in production volumes and in realized gains and losses from commodity positions.  Commodity prices have historically been volatile and the Managing General Partner attempts to manage this volatility through derivatives.  Therefore, the primary source of the Partnership’s cash flow from operations becomes the net activity between the Partnership’s natural gas, NGLs and crude oil sales and realized natural gas and crude oil derivative gains and losses.  However, the Partnership does not engage in speculative positions, nor does the Partnership hold derivative instruments for 100% of the Partnership’s expected future production from producing wells and therefore may still experience significant fluctuations in cash flows from operations.  As of March 31, 2011, the Partnership had natural gas and crude oil derivative positions in place covering 73% of the expected natural gas production and 41% of expected crude oil production for the remainder of 2011, at an average price of $4.88 per Mcf and $70.75 per Bbl, respectively.  The Partnership’s current derivative position average prices have declined from the significantly higher average commodity contract strike price levels in effect during the 2010 comparative period which were the result of contracts entered into during the high 2008 commodity price market; accordingly, the Partnership anticipates realized gains for the next 12 months to remain substantially below gains realized in 2009 and the first quarter of 2010.  See Results of Operations for further discussion of the impact of prices and volumes on sales from operations and the impact of derivative activities on the Partnership’s revenues.





The Partnership’s future operations are expected to be conducted with available funds and revenues generated from natural gas, NGLs and crude oil production activities and commodity gains.  Natural gas, NGLs and crude oil production from the Partnership’s existing properties are generally expected to continue a gradual decline in the rate of production over the remaining life of the wells.  Therefore, the Partnership anticipates a lower annual level of natural gas, NGLs and crude oil production and, in the absence of significant price increases or additional reserve development, lower revenues.  The Partnership also expects cash flows from operations to decline if commodity prices remain at current levels or decrease in the future.  Under these circumstances decreased production would have a material negative impact on the Partnership’s operations and may result in reduced cash distributions to the Managing General Partner and Investor Partners through the remainder of 2011 and beyond, and may substantially reduce or restrict the Partnership’s ability to participate in the refracturing activities which are more fully described in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments−Well Refracturing Plan.




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 Index




PDC 2005-B LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)


Working Capital





The Partnership had working capital of approximately $0.8 million at both March 31, 2011 and December 31, 2010.  The following offsetting changes resulted in substantially no change to the working capital:





·
Cash and cash equivalents increased by $0.1 million between March 31, 2011 and December 31, 2010.


·
Realized and Unrealized derivative gains receivables decreased by $0.1 million between March 31, 2011 and December 31, 2010.





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





Cash Flows





Cash Flows From Operating Activities





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





Natural gas, NGLs and crude oil prices exhibit a high degree of volatility.  These price variations have a material impact on the Partnership’s financial results.  Natural gas and NGLs prices vary by region and locality, depending upon the distance to markets, the availability of pipeline capacity and the supply and demand relationships in that region or locality.  This can be especially true in the Rocky Mountain Region.  The combination of increased drilling activity and the lack of local markets have resulted in local market oversupply situations from time to time.  Like most producers in the region, the Partnership relies on major interstate pipeline companies to construct these pipelines to increase capacity, rendering the timing and availability of these facilities beyond the Partnership’s control.  Crude oil pricing is predominantly driven by the physical market, supply and demand, the financial markets and global unrest.





The price at which PDC markets the natural gas produced in the Rocky Mountain Region by the Partnership is based on a market basket of prices, which primarily includes natural gas sold at CIG prices with a portion sold at Mid-Continent, San Juan Basin, Southern California or other nearby region prices.  The CIG Index, and other indices for production delivered to other Rocky Mountain pipelines, have historically been less than the price received for natural gas produced in the eastern regions, which is primarily New York Mercantile Exchange, or NYMEX, based.  This negative differential has narrowed over the last few years and is lower than historical variances.  The negative differential of CIG relative to NYMEX averaged $0.28 and $0.16 for the three months ended March 31, 2011 and 2010, respectively.




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 Index




PDC 2005-B LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)




Net cash provided by operating activities was approximately $0.6 million for the three months ended March 31, 2011, compared to approximately $1.2 million for the comparable period in 2010.  The approximately $0.6 million decrease in cash provided by operating activities was due primarily to the following:





·
A decrease in natural gas, NGLs and crude oil sales receipts of $0.2 million, or 22%,





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





·
An increase in production costs and direct costs – general and administrative payments of $0.1 million.





Cash Flows From Investing Activities





The Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of natural gas, NGLs and crude oil or environmental protection.  These amounts totaled approximately $4,000 and $6,000 for the three months ended March 31, 2011 and 2010, respectively.





Cash Flows From Financing Activities





The Partnership initiated monthly cash distributions to investors in December 2005 and has distributed $33.2 million through March 31, 2011.  The table below presents cash distributions to the Partnership’s investors.  Managing General Partner distributions include amounts distributed to PDC for its Managing General Partner’s 20% ownership share in the Partnership.  Investor Partner distributions include amounts distributed to Investor Partners for their 80% ownership share in the Partnership and include amounts distributed to PDC for limited partnership units repurchased.





Quarter

Managing


Investorended

General Partner


Partners


TotalMarch 31,

Distributions


Distributions


Distributions2011

$
95,977


$
383,905


$
479,8822010

$
236,187


$
944,751


$
1,180,938





The decrease in total distributions for 2011 as compared to 2010 is primarily due to the significant decrease in cash flows from operating activities during 2011 and from funds held by the Managing General Partner for the Well Refracturing Plan.





The Partnership began funding for the Well Refracturing Plan during October 2010.  During the quarter ended March 31, 2011, on a pro-rata basis, based on percentage of ownership in the Partnership, the Partnership withheld $12,000 and $48,000 from the Managing General Partner and Investor Partners’ share of cash available for distributions, respectively.




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 Index




PDC 2005-B LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)


Off-Balance Sheet Arrangements





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





Commitments and Contingencies





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





Recent Accounting Standards





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





Critical Accounting Policies and Estimates





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





There have been no significant changes to the Partnership’s critical accounting policies and estimates or in the underlying accounting assumptions and estimates used in these critical accounting policies from those disclosed in the financial statements and accompanying notes contained in the Partnership’s 2010 Form 10-K.




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 Index





PDC 2005-B LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)




Item 3.             Quantitative and Qualitative Disclosures About Market Risk





Not applicable.




Item 4.             Controls and Procedures





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





(a) Evaluation of Disclosure Controls and Procedures





As of March 31, 2011, PDC, as Managing General Partner on behalf of the Partnership, carried out an evaluation, under the supervision and with the participation of the Managing General Partner’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Partnership’s disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e).  This evaluation considered the various processes carried out under the direction of the Managing General Partner’s disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports that the Partnership files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that such information is accumulated and communicated to the Partnership’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely discussion regarding required disclosure.





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





(b) Changes in Internal Control over Financial Reporting




During the three months ended March 31, 2011, PDC, the Managing General Partner, made no changes in the Partnership’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect the Partnership’s internal control over financial reporting.




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 Index


PDC 2005-B LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)




PART II – OTHER INFORMATION




Item 1.             Legal Proceedings





Neither the Partnership nor PDC, in its capacity as the Managing General Partner of the Partnership, are party to any pending legal proceeding that PDC believes would have a materially adverse effect on the Partnership’s business, financial condition, results of operations or liquidity.




Item 1A.          Risk Factors





Not applicable.




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





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





There were no limited partner unit repurchases during the three months ended March 31, 2011.




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 2005-B LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)


Item 6.             Exhibits Index





The exhibits presented below are in addition to those presented in the Partnership’s Form 10-K.




Incorporated by ReferenceExhibit Number

Exhibit Description

Form

SEC File

Number

Exhibit

Filing Date

Filed

Herewith31.1

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.









X31.2

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.









X32.1

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









X




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 Index





PDC 2005-B LIMITED PARTNERSHIP
 (A West Virginia Limited Partnership)





SIGNATURES




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





PDC 2005-B Limited Partnership


By its Managing General Partner


Petroleum Development Corporation (dba PDC Energy)





By/s/ Richard W. McCullough


Richard W. McCullough


Chairman and Chief Executive Officer


of Petroleum Development Corporation (dba PDC Energy)





May 16, 2011





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





Signature

Title
Date/s/ Richard W. McCullough

Chairman and Chief Executive Officer
May 16, 2011Richard W. McCullough

Petroleum Development Corporation (dba PDC Energy)Managing General Partner of the Registrant(Principal executive officer)/s/ Gysle R. Shellum

Chief Financial Officer
May 16, 2011Gysle R. Shellum

Petroleum Development Corporation (dba PDC Energy)Managing General Partner of the Registrant(Principal financial officer)/s/ R. Scott Meyers

Chief Accounting Officer
May 16, 2011R. Scott Meyers

Petroleum Development Corporation (dba PDC Energy)Managing General Partner of the Registrant(Principal accounting officer)







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