Blueknight Energy Partners (BKEP) 10-Q 2011 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 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, 2011

OR

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

For the transition period from __________ to _________

Commission File Number 001-33503

BLUEKNIGHT ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)	20-8536826 (IRS Employer Identification No.)
Two Warren Place 6120 South Yale Avenue, Suite 500 Tulsa, Oklahoma 74136 (Address of principal executive offices, zip code) Registrant’s telephone number, including area code: (918) 237-4000

(Former name, former address and former fiscal year, if changed since last report)

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    x     No   o

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   x      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 definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer          o                       Accelerated filer                       x

Non-accelerated filer   o   (Do not check if a smaller reporting company)        Smaller reporting company o

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 August 2, 2011, there were 21,538,462 preferred units, 21,890,224 common units and 12,570,504 subordinated units outstanding. 

TABLE OF CONTENTS
				Page
PART I		FINANCIAL INFORMATION		1
	Item 1.	Unaudited Financial Statements.		1
			Consolidated Balance Sheets as of December 31, 2010 and June 30, 2011	1
			Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2010 and 2011	2
			Consolidated Statements of Changes in Partners’ Capital (Deficit) for the Six Months Ended June 30, 2011	3
			Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2010 and 2011	4
			Notes to Unaudited Consolidated Financial Statements	5
	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations.		23
	Item 3.	Quantitative and Qualitative Disclosure about Market Risk.		37
	Item 4.	Controls and Procedures.		38
PART II		OTHER INFORMATION		39
	Item 1.	Legal Proceedings.		39
	Item 1A.	Risk Factors.		39
	Item 6.	Exhibits.		39

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PART I.                       FINANCIAL INFORMATION

Item 1.                          Financial Statements

BLUEKNIGHT ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands, except per unit data)

	As of December 31, 2010			As of June 30, 2011
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	4,840		$	5,706
Accounts receivable, net of allowance for doubtful accounts of $429 for both dates		8,824			12,957
Receivables from related parties, net of allowance for doubtful accounts of $0 for both dates		1,912			2,134
Insurance recovery receivable		13,000			13,000
Prepaid insurance		1,413			3,070
Other current assets		2,147			2,396
Total current assets		32,136			39,263
Property, plant and equipment, net of accumulated depreciation of $119,735 and $129,209 at December 31, 2010 and June 30, 2011, respectively		274,069			272,424
Goodwill		7,083			7,216
Debt issuance costs, net		6,675			5,989
Intangibles and other assets, net		3,875			2,556
Total assets	$	323,838		$	327,448
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
Current liabilities:
Accounts payable	$	8,829		$	8,091
Accrued loss contingency (see Note 13)		20,200			20,200
Accrued interest payable		357			279
Accrued interest payable to related parties		1,214			3,900
Accrued property taxes payable		2,254			2,128
Unearned revenue		3,506			3,891
Unearned revenue with related parties		2,154			49
Accrued payroll		4,130			4,739
Other accrued liabilities		3,709			4,500
Convertible subordinated debentures (see Note 5)		31,725			40,481
Fair value of derivative embedded within subordinated convertible debt		27,550			22,684
Fair value of rights offering contingency		10,441			16,827
Current portion of long-term payable to related parties		1,183			1,525
Total current liabilities		117,252			129,294
Long-term payable to related parties		4,317			3,528
Other long-term liabilities		150			150
Long-term debt (including $15.0 million with related parties for both dates)		239,862			240,000
Commitments and contingencies (Notes 5 and 13)
Partners’ capital (deficit):
Series A Preferred Units (21,538,462 units issued and outstanding for both dates)		91,376			113,296
Common unitholders (21,890,224 units issued and outstanding for both dates)		478,575			459,845
Subordinated unitholders (12,570,504 units issued and outstanding for both dates)		(286,264	)		(297,082	)
General partner interest (1.974% interest with 1,127,755 general partner units outstanding for both dates)		(321,430	)		(321,583	)
Total Partners’ deficit		(37,743	)		(45,524	)
Total liabilities and Partners’ deficit	$	323,838		$	327,448

See accompanying notes to unaudited consolidated financial statements.

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BLUEKNIGHT ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2011			2010			2011
	(unaudited)
Service revenue:
Third party revenue	$	32,820		$	32,670		$	66,781		$	64,624
Related party revenue		5,623			10,421			8,694			19,990
Total revenue		38,443			43,091			75,475			84,614
Expenses:
Operating		24,157			29,495			50,000			58,109
General and administrative		3,385			4,777			7,153			9,386
Total expenses		27,542			34,272			57,153			67,495
Operating income		10,901			8,819			18,322			17,119
Other (income) expenses:
Interest expense		13,549			9,112			25,972			18,164
Change in fair value of embedded derivative within convertible debt		—			3,431			—			(4,866	)
Change in fair value of rights offering contingency		—			1,544			—			6,386
Loss before income taxes		(2,648	)		(5,268	)		(7,650	)		(2,565	)
Provision for income taxes		53			77			102			147
Net loss	$	(2,701	)	$	(5,345	)	$	(7,752	)	$	(2,712	)
Allocation of net income (loss) for calculation of earnings per unit:
General partner interest in net income (loss)	$	(54	)	$	(46	)	$	(154	)	$	111
Preferred interest in net income		—			2,975			—			8,149
Beneficial conversion feature attributable to preferred units		—			11,021			—			21,920
Loss available to common and subordinated unitholders	$	(2,647	)	$	(19,295	)	$	(7,598	)	$	(32,892	)
Basic and diluted net loss per common unit	$	(0.08	)	$	(0.55	)	$	(0.22	)	$	(0.94	)
Basic and diluted net loss per subordinated unit	$	(0.08	)	$	(0.55	)	$	(0.22	)	$	(0.94	)
Weighted average common units outstanding - basic and diluted		21,728			21,890			21,728			21,890
Weighted average subordinated units outstanding - basic and diluted		12,571			12,571			12,571			12,571

See accompanying notes to unaudited consolidated financial statements.

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BLUEKNIGHT ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL (DEFICIT)

(in thousands)

	Common Unitholders			Subordinated Unitholders			Series A Preferred Unitholders			General Partner Interest			Total Partners’ Deficit
	(unaudited)
Balance, December 31, 2010	$	478,575		$	(286,264	)	$	91,376		$	(321,430	)	$	(37,743	)
Net income (loss)		(4,975	)		(2,858	)		5,174			(53	)		(2,712	)
Equity-based incentive compensation		130			75			—			4			209
Amortization of beneficial conversion feature of Preferred units		(13,885	)		(8,035	)		21,920			—			—
Distributions		—			—			(5,174	)		(104	)		(5,278	)
Balance, June 30, 2011	$	459,845		$	(297,082	)	$	113,296		$	(321,583	)	$	(45,524	)

See accompanying notes to unaudited consolidated financial statements.

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BLUEKNIGHT ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Six Months Ended June 30,
	2010			2011
	(unaudited)
Cash flows from operating activities:
Net loss	$	(7,752	)	$	(2,712	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization		10,913			11,415
Amortization and write-off of debt issuance costs		2,352			966
Amortization of subordinated debenture discount		—			8,756
Decrease in fair value of embedded derivative within convertible debt		—			(4,866	)
Increase in fair value of rights offering contingency		—			6,386
Asset impairment charge		779			—
Gain on sale of assets		(80	)		(710	)
Equity-based incentive compensation		17			209
Changes in assets and liabilities
Increase in accounts receivable		(1,035	)		(4,133	)
Decrease (increase) in receivables from related parties		326			(222	)
Decrease (increase) in prepaid insurance		2,217			(139	)
Decrease (increase) in other current assets		630			(249	)
Decrease (increase) in other assets		(1,595	)		1,037
Decrease in accounts payable		(1,416	)		(1,210	)
Increase (decrease) in accrued interest payable		2,697			(78	)
Increase in accrued interest payable to related parties		—			2,686
Decrease in accrued property taxes		(750	)		(126	)
Increase (decrease) in unearned revenue		(1,096	)		385
Increase (decrease) in unearned revenue from related parties		951			(2,105	)
Increase in accrued payroll		749			609
Increase (decrease) in other accrued liabilities		673			(145	)
Net cash provided by operating activities		8,580			15,754
Cash flows from investing activities:
Acquisitions		—			(133	)
Capital expenditures		(6,149	)		(9,298	)
Proceeds from sale of assets		1,597			752
Net cash used in investing activities		(4,552	)		(8,679	)
Cash flows from financing activities:
Payment on insurance premium financing agreement		—			(342	)
Debt issuance costs		(1,119	)		(280	)
Payments on capital lease obligations		(237	)		—
Payments on long-term payable to related party		—			(447	)
Borrowings under credit facility		26,700			6,000
Payments under credit facility		(34,771	)		(5,862	)
Distributions		—			(5,278	)
Net cash used in financing activities		(9,427	)		(6,209	)
Net increase (decrease) in cash and cash equivalents		(5,399	)		866
Cash and cash equivalents at beginning of period		5,548			4,840
Cash and cash equivalents at end of period	$	149		$	5,706
Supplemental disclosure of cash flow information:
Increase in accounts payable related to purchase of property, plant and equipment	$	418		$	472
Increase in accrued liabilities related to insurance premium financing agreement	$	407		$	1,278

See accompanying notes to unaudited consolidated financial statements.

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BLUEKNIGHT ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1.   ORGANIZATION AND NATURE OF BUSINESS

Blueknight Energy Partners, L.P. (formerly SemGroup Energy Partners, L.P.) and subsidiaries (the “Partnership”) is a publicly traded master limited partnership with operations in twenty-three states. The Partnership provides integrated terminalling, storage, processing, gathering and transportation services for companies engaged in the production, distribution and marketing of crude oil and asphalt products. The Partnership manages its operations through four operating segments: (i) crude oil terminalling and storage services, (ii) crude oil pipeline services, (iii) crude oil trucking and producer field services and (iv) asphalt services. The Partnership’s common units, which represent limited partnership interests in the Partnership, are listed on the NASDAQ Global Market. The Partnership was formed in February of 2007 as a Delaware master limited partnership initially to own, operate and develop a diversified portfolio of complementary midstream energy assets.

2.   BASIS OF PRESENTATION

The financial statements have been prepared in accordance with accounting principles and practices generally accepted in the United States of America (“GAAP”).  The consolidated statements of operations for the three and six months ended June 30, 2010 and 2011, the consolidated statement of changes in partners’ capital (deficit) for the six months ended June 30, 2011, the statement of cash flows for the six months ended June 30, 2010 and 2011, and the consolidated balance sheet as of June 30, 2011 are unaudited.  In the opinion of management, the unaudited consolidated financial statements have been prepared on the same basis as the audited financial statements and include all adjustments necessary to present fairly the financial position and results of operations for the respective interim periods.  All adjustments are of a recurring nature unless otherwise disclosed herein.  These consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes thereto included in the Partnership’s annual report on Form 10-K for the year ended December 31, 2010 filed with the Securities and Exchange Commission (the “SEC”) on March 16, 2011 (the “2010 Form 10-K”).  Interim financial results are not necessarily indicative of the results to be expected for an annual period.  The year-end balance sheet data was derived from the audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.

3.   RECENT EVENTS

On October 25, 2010, the Partnership entered into a Global Transaction Agreement by and among the Partnership, Blueknight Energy Partners, G.P., L.L.C., which is the Partnership’s general partner (the “General Partner”), Vitol (“Vitol” refers to Vitol Holding B.V., its affiliates and subsidiaries other than the Partnership’s general partner and the Partnership) and Charlesbank (“Charlesbank” refers to Charlesbank Capital Partners, LLC, its affiliates and subsidiaries other than the Partnership’s general partner and the Partnership), pursuant to which the Partnership effected a refinancing of its existing debt.  The Global Transaction Agreement contemplated three events comprised of Phase I Transactions, a unitholder vote and Phase II Transactions.  Phase I transactions were completed concurrently with the execution of the Global Transaction Agreement.  For a detailed description of the Global Transaction Agreement, see the Partnership’s 2010 Form 10-K.

On May 12, 2011, the Partnership, the General Partner, Vitol and Charlesbank entered into the First Amendment to Global Transaction Agreement (the “Amendment”) pursuant to which the Unitholder Vote Transactions and the Phase II Transactions contemplated in the Global Transaction Agreement were modified.

Pursuant to the Global Transaction Agreement, as amended by the amendment, the General Partner has filed a definitive proxy statement with the Securities and Exchange Commission (the “SEC”) relating to a special meeting (the “Unitholder Meeting”) expected to be held on September 14, 2011 during which the Partnership’s unitholders will consider and vote upon (i) certain amendments to the Partnership’s partnership agreement (the “Partnership Agreement Amendment Proposal”) as more fully set forth below and (ii) an amendment to the General Partner’s Long-Term Incentive Plan to increase the number of common units issuable under such plan by 1,350,000 common units from 1,250,000 common units to 2,600,000 common units (the “LTIP Proposal”).  Pursuant to the Partnership Agreement Amendment Proposal, the Partnership’s partnership agreement would be amended to:

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• reset (1) the minimum quarterly distribution to $0.11 per unit per quarter from $0.3125 per unit per quarter, (2) the first target distribution to $0.1265 per unit per quarter from $0.3594 per unit per quarter, (3) the second target distribution to $0.1375 per unit per quarter from $0.3906 per unit per quarter and (4) the third target distribution to $0.1825 per unit per quarter from $0.4688 per unit per quarter;

• waive the cumulative common unit arrearage;

• remove provisions in the partnership agreement relating to the subordinated units, including concepts such as a subordination period (and any provisions that expressly apply only during the subordination period) and common unit arrearage, in connection with the transfer to the Partnership, and its subsequent cancellation, of all of the Partnership’s outstanding subordinated units;

• provide that distributions shall not accrue or be paid to the holders of the Partnership’s incentive distribution rights for an eight quarter period beginning with the quarter in which the special meeting occurs;

• provide that during the period beginning on the date of this special meeting and ending on June 30, 2015 (the “Senior Security Restriction Period”), the Partnership will not issue any class or series of partnership securities that, with respect to distributions on such partnership securities or distributions upon liquidation of the Partnership, ranks senior to the common units during the Senior Security Restriction Period, or “Senior Securities”, without the consent of the holders of at least a majority of the outstanding common units (excluding the common units held by the General Partner and its affiliates and excluding any Senior Securities that are convertible into common units); provided that the Partnership may issue an unlimited number of Senior Securities during the Senior Security Restriction Period without obtaining such consent if (i) such issuances are made in connection with the conversion of the Partnership’s convertible subordinated debentures issued to Vitol and Charlesbank in the aggregate principal amount of $50 million (the “Convertible Debentures”) or the consummation of the rights offering and use of proceeds therefrom, (ii) such issuances are made upon conversion, redemption or exchange of Senior Securities into or for Senior Securities of equal or lesser rank, where the aggregate amount of distributions that would have been paid with respect to such newly issued Senior Securities, plus the related distributions to the General Partner, in respect of the four-quarter period ending prior to the first day of the quarter in which the issuance is to be consummated (assuming such newly issued Senior Securities had been outstanding throughout such period) would not have exceeded the distributions actually paid during such period on the Senior Securities that are to be converted, redeemed or exchanged, plus the related distributions to the General Partner, (iii) such issuances are made in connection with thecombination or subdivision of any class of Senior Securities, (iv) such issuances are made in connection with an acquisition or expansion capital improvement that increases estimated pro forma Adjusted Operating Surplus (as defined in the Partnership’s partnership agreement) (less estimated pro forma distributions on the Partnership’s Series A Preferred Units (the “Preferred Units”) and on any other Senior Securities) on a per-common unit basis, as determined in good faith by the General Partner, as compared to actual Adjusted Operating Surplus (as defined in the Partnership’s partnership agreement) (less actual distributions on the Preferred Units and on any other Senior Securities) on a per-common unit basisor (v) the net proceeds of such issuances are used to repay indebtedness of the Partnership or its subsidiaries; provided, however, that in the case of subsection (v) such new securities may not be issued to an affiliate of the General Partner unless the cost to service any new indebtedness that the Partnership determines that it could issue to retire existing indebtedness (with the General Partner’s determination being conclusive) is greater than the distribution obligations associated with the Senior Securities issued in connection with its retirement and one or more of the following conditions are also met: (A) the indebtedness that is being repaid matures within 12 months of such repayment, or (B) such indebtedness has experienced a default or event of default (even if the lenders of such indebtedness have agreed to forebear or waive such default or event of default) or (C) the General Partner expects to experience a default or event of default under such indebtedness within six months of such repayment (with the General Partner’s determination being conclusive);

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• provide that in addition to the Partnership’s current rights to convert the Preferred Units into common units, the Preferred Units will also be convertible at the Partnership’s option at any time on or after October 25, 2015 if (i) the daily volume-weighted average trading price of the common units is greater than 130% of the Conversion Price (as defined in the Partnership’s partnership agreement) for twenty out of the trailing thirty trading days ending two trading days before the Partnership furnishes notice of conversion and (ii) the average trading volume of common units has exceeded 20,000 common units for twenty out of the trailing thirty trading days ending two trading days before the Partnership furnishes notice of conversion; and

• provide that the conversion of Preferred Units shall become effective (i) in the case of Preferred Units that are being converted pursuant to Section 5.12(c)(i) of the Partnership’s partnership agreement (relating to conversions at the election of the holder of such units), as of the last day of the quarter in which the relevant notice of conversion is delivered by the applicable unitholder and (ii) in the case of Preferred Units that are being converted pursuant to Section 5.12(c)(ii) of the Partnership’s partnership agreement (relating to conversions at the election of the Partnership), as of the date that the notice of conversion is delivered by the Partnership.

If the Partnership Agreement Amendment Proposal is approved, then (i) the General Partner will adopt the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership in the form attached to the proxy statement (the “Amended and Restated Partnership Agreement”) to reflect the approval of the Partnership Agreement Amendment Proposal as well as other amendments that the General Partner may make in accordance with the provisions of the Partnership’s partnership agreement as set forth therein, (ii) Vitol and Charlesbank will transfer all of the Partnership’s outstanding subordinated units to the Partnership and the Partnership will cancel such subordinated units and (iii) the Partnership will undertake to complete an approximately $77 million rights offering, the proceeds of which shall be used as follows: (a) first, to pay for any and all expenses relating to conducting the rights offering, (b) second, to redeem the Partnership’s Convertible Debentures for an amount equal to the principal amount of such Convertible Debentures plus any interest payable thereon, (c) third, to repurchase, on a pro rata basis, up to a maximum of $22 million of Preferred Units from Vitol and Charlesbank at a purchase price of $6.50 per unit plus any pro rata distribution for the quarter in which such units are repurchased and (d) thereafter, for general partnership purposes. Pursuant to the terms of the rights offering, the Partnership will distribute to its common unitholders 0.5412 rights for each outstanding common unit, with each whole right entitling the holder to acquire, for a subscription price of $6.50, a newly issued Preferred Unit.

Important additional information regarding the Partnership Agreement Amendment Proposal and the LTIP Proposal has been filed with the SEC, including a definitive proxy statement relating to the proposed transactions filed with the SEC on July 28, 2011.  INVESTORS AND SECURITY HOLDERS ARE ADVISED TO READ THE DEFINITIVE PROXY STATEMENT BECAUSE IT CONTAINS IMPORTANT INFORMATION ABOUT THE PARTNERSHIP AND THE PROPOSED TRANSACTIONS.  Investors and security holders may obtain copies of the definitive proxy statement and other documents that the Partnership files with the SEC (when they are available) free of charge at the SEC’s web site at www.sec.gov. The definitive proxy statement and other relevant documents may also be obtained (when available) free of charge on the Partnership’s web site at www.bkep.com or by directing a request to Blueknight Energy Partners, L.P., Two Warren Place, 6120 South Yale Avenue, Suite 500, Tulsa, Oklahoma 74136, Attention: Investor Relations.

The Partnership, the General Partner and its directors, executive officers and other members of its management and employees may be deemed participants in the solicitation of proxies from the unitholders of the Partnership in connection with the proposed transactions. Information regarding the special interests of persons who may be deemed to be such participants in the proposed transactions is included in the definitive proxy statement. Additional information regarding the directors and executive officers of the General Partner is also included in the 2010 Form 10-K, and subsequent statements of changes in beneficial ownership on file with the SEC. These documents are available free of charge at the SEC’s web site at www.sec.gov and from Investor Relations at Blueknight Energy Partners, L.P. as described above.

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4.   PROPERTY, PLANT AND EQUIPMENT

	Estimated Useful Lives (Years)	December 31, 2010			June 30, 2011
		(dollars in thousands)
Land	N/A	$	15,611		$	16,926
Land improvements	10-20		5,268			5,675
Pipelines and facilities	5-31		149,402			151,516
Storage and terminal facilities	10-35		166,538			169,180
Transportation equipment	3-10		24,177			22,326
Office property and equipment and other	3-31		21,978			23,963
Pipeline linefill and tank bottoms	N/A		7,763			7,787
Construction-in-progress	N/A		3,067			4,260
Property, plant and equipment, gross			393,804			401,633
Accumulated depreciation			(119,735	)		(129,209	)
Property, plant and equipment, net		$	274,069		$	272,424

Depreciation expense for the six months ended June 30, 2010 and 2011 was $10.9 million and $11.4 million, respectively.

 5.   DEBT

On October 25, 2010, the Partnership entered into a new credit agreement, which includes a $200.0 million term loan facility and a $75.0 million revolving loan facility.  Vitol is a lender under the credit agreement and has committed to loan the Partnership $15.0 million pursuant to such agreement.  The entire amount of the term loan and approximately $43.9 million of the revolver was drawn on the transaction date in connection with repaying all existing indebtedness under the Partnership’s prior credit agreement.  The proceeds of loans made under the credit agreement may be used for working capital and other general corporate purposes of the Partnership.

On April 5, 2011, the Partnership entered into a Joinder Agreement whereby the Partnership’s revolving credit facility was increased from $75.0 million to $95.0 million.  As of August 2, 2011, approximately $36.8 million of revolver borrowings and letters of credit were outstanding under the credit facility, leaving the Partnership with approximately $58.2 million available capacity for additional revolver borrowings and letters of credit under the credit facility.

The credit agreement is guaranteed by all of the Partnership’s existing subsidiaries. Obligations under the credit agreement are secured by first priority liens on substantially all of the Partnership’s assets and those of the guarantors, including all material pipeline, gathering and processing assets, all material storage tanks and asphalt facilities, all material working capital assets and a pledge of all of the Partnership’s equity interests in its subsidiaries.

The credit agreement includes procedures for additional financial institutions to become revolving lenders, or for any existing lender to increase its revolving commitment thereunder, subject to an aggregate maximum of $200.0 million for all revolving loan commitments under the credit agreement.

The credit agreement will mature on October 25, 2014, and all amounts outstanding under the credit agreement will become due and payable on such date.  The Partnership may prepay all loans under the credit agreement at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements. The credit agreement requires mandatory prepayments of amounts outstanding thereunder with the net proceeds of certain asset sales, casualty events and debt incurrences, and, in certain circumstances, with a portion of the Partnership’s excess cash flow (as defined in the credit agreement).  These mandatory prepayments will be applied to the term loan under the credit agreement until it is repaid in full, then applied to reduce commitments under the revolving loan facility.

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Through May 15, 2011, borrowings under the credit agreement bore interest, at the Partnership’s option, at either (i) the ABR (the highest of the administrative agent’s prime rate, the federal funds rate plus 0.5%, or the one-month eurodollar rate (as defined in the credit agreement) plus 1%), plus an applicable margin of 3.25%, or (ii) the eurodollar rate plus an applicable margin of 4.25%.  After approximately May 15, 2011, the applicable margin for loans accruing interest based on the ABR ranges from 3.0% to 3.5%, and the applicable margin for loans accruing interest based on the eurodollar rate ranges from 4.0% to 4.5%, in each case depending on the Partnership’s consolidated total leverage ratio (as defined in the credit agreement).  The Partnership pays a per annum fee on all letters of credit issued under the credit agreement, which fee equals the applicable margin for loans accruing interest based on the eurodollar rate, and the Partnership pays a commitment fee of 0.50% per annum on the unused availability under the credit agreement.  The credit agreement does not have a floor for the ABR or the eurodollar rate.  In connection with entering into the credit agreement, the Partnership paid certain upfront fees to the lenders thereunder, and the Partnership paid certain arrangement and other fees to the arranger and administrative agent of the credit agreement.  Vitol received its pro rata portion of such fees as a lender under the credit agreement.

The credit agreement includes financial covenants that will be tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter (except for the consolidated interest coverage ratio, which builds to a four-quarter test).

The maximum permitted consolidated total leverage ratio is as follows:

• 5.00 to 1.00 for the fiscal quarter ending June 30, 2011;

• 4.75 to 1.00 for the fiscal quarters ending September 30, 2011 and December 31, 2011; and

• 4.50 to 1.00 for the fiscal quarter ending March 31, 2012 and each fiscal quarter thereafter.

The minimum permitted consolidated interest coverage ratio (as defined in the credit agreement) is as follows:

• 2.50 to 1.00 for the fiscal quarter ending June 30, 2011; and

• 3.00 to 1.00 for the fiscal quarters ending September 30, 2011 and each fiscal quarter thereafter.

 In addition, the credit agreement contains various covenants that, among other restrictions, limit the Partnership’s ability to:

• create, incur or assume liens;

• engage in mergers or acquisitions;

• repurchase the Partnership's equity, make distributions to unitholders and make certain other restricted payments;

• make investments;

• modify the terms of the Convertible Debentures (as defined below) and certain other indebtedness, or prepay certain indebtedness;

• engage in transactions with affiliates; 

• enter into certain burdensome contracts;

• change the nature of the Partnership's business;

• enter into operating leases; and

• make certain amendments to the Partnership’s partnership agreement.

At June 30, 2011, the Partnership’s leverage ratio was 4.27 and the interest coverage ratio was 4.64.  The Partnership was in compliance with all covenants of its credit agreement as of June 30, 2011.

The credit agreement permits the Partnership to make quarterly distributions of available cash (as defined in the Partnership’s partnership agreement) to unitholders so long as:  (i) no default or event of default exists under the credit agreement, (ii) the Partnership has, on a pro forma basis after giving effect to such distribution, at least $10.0 million of availability under the revolving loan facility, and (iii) the Partnership’s consolidated total leverage ratio, on a pro forma basis, would not be greater than (x) 4.5 to 1.0 for any fiscal quarter on or prior to the fiscal quarter ending June 30, 2011, (y) 4.25 to 1.0 for the fiscal quarters ending September 30, 2011 and December 31, 2011, or (z) 4.00 to 1.0 for any fiscal quarter ending on or after March 31, 2012.  The Partnership is currently allowed to make distributions to its unitholders in accordance with these covenants; however, the Partnership will only make distributions to the extent it has sufficient cash from operations after establishment of cash reserves as determined by the General Partner in accordance with the Partnership’s cash distribution policy, including the establishment of any reserves for the proper conduct of the Partnership’s business.

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Each of the following is an event of default under the credit agreement:

• failure to meet the quarterly financial covenants;

• failure to observe any other agreement, obligation or covenant in the credit agreement or any related loan document, subject to cure periods for certain failures;

• the Partnership's, or any of its subsidiaries', default under other indebtedness that exceeds a threshold amount;

• judgments against the Partnership or any of its subsidiaries, in excess of a threshold amount;

• certain ERISA events involving the Partnership or any of its subsidiaries, in excess of a threshold amount;

• bankruptcy or other insolvency events involving the Partnership or any of its subsidiaries; and 

• a change in control (as defined in the credit agreement).

If an event of default relating to bankruptcy or other insolvency events occurs, all indebtedness under the credit agreement will immediately become due and payable.  If any other event of default exists under the credit agreement, the lenders may accelerate the maturity of the obligations outstanding under the credit agreement and exercise other rights and remedies.  In addition, if any event of default exists under the credit agreement, the lenders may commence foreclosure or other actions against the collateral.

If any default occurs under the credit agreement, or if the Partnership is unable to make any of the representations and warranties in the credit agreement, the Partnership will be unable to borrow funds or have letters of credit issued under the credit agreement.

It will constitute a change of control under the credit agreement if either Vitol or Charlesbank ceases to own, directly or indirectly, exactly 50% of the membership interests of the General Partner or if the General Partner ceases to be controlled by both Vitol and Charlesbank.

Interest expense related to debt issuance cost amortization for the three and six month periods ended June 30, 2010 was $1.3 million and $2.4 million, respectively, and for the three and six month periods ended June 30, 2011 was $0.5 million and $1.0 million, respectively.  The Partnership capitalized debt issuance costs of $1.1 million during the six month period ended June 30, 2010, and $0.3 million during the three and six months ended June 30, 2011, respectively.

During the three months ended June 30, 2011, the weighted average interest rate under the credit agreement incurred by the Partnership was 4.5% and the total weighted average interest rate, including interest associated with the Convertible Debentures and related debt discount and the Vitol Throughput Capacity Agreement was 12.6% resulting in interest expense of approximately $9.1 million.

In October of 2010 the Partnership issued the Convertible Debentures in a private placement in the aggregate principal amount of $50.0 million.  If not previously redeemed, the Convertible Debentures, including all outstanding principal and unpaid interest, will convert to preferred units on December 31, 2011. The rate at which the convertible subordinated debentures convert into Series A preferred units is computed by reference to the market price of the common stock at the date of conversion, subject to a floor of $5.50 per unit and a ceiling of $6.50 per unit. This conversion feature is considered an embedded derivative within the Convertible Debentures, which the Partnership is required to separately value. The Partnership has bifurcated this embedded derivative and estimated the fair value of the embedded derivative liability. The resulting discount created by allocating a portion of the issuance proceeds to the embedded derivative is being amortized to interest expense over the term of the convertible subordinated debentures using the effective interest method.

The Partnership estimated the fair value of the embedded derivative liability to be $27.6 million at December 31, 2010.   At June 30, 2011 the fair value of this derivative liability was estimated to be $22.7 million.

Changes to the fair value of the embedded derivative are reflected on the Partnership’s consolidated statements of operations as “Change in fair value of embedded derivative within convertible debt.” The value of the embedded derivative is contingent on changes in the expected fair value of the Partnership's preferred units.  The Partnership recorded other expense of $3.4 million and other income of $4.9 million due to the change in the fair value of this embedded derivative in the three and six months ended June 30, 2011, respectively.

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In addition, the recording of the embedded derivative liability related to the convertible subordinated debt resulted in the Partnership recording a $20.9 million debt discount on Convertible Debentures. The debt discount is amortized to interest expense through the mandatory conversion date of December 31, 2011 using the effective interest method.  The Partnership recognized non-cash interest expense of $4.4 million and $8.8 million in the three and six months ended June 30, 2011, respectively, due to the amortization of the debt discount. 

6.   DISTRIBUTIONS

The Partnership has not made a distribution to its common unitholders or subordinated unitholders since May 15, 2008 due, in part, to the events of default that existed under its former credit agreement, restrictions under such credit agreement, and the uncertainty of its future cash flows relating to SemCorp’s bankruptcy filings (“SemCorp” refers to SemGroup Corporation and its predecessors including SemGroup, L.P., subsidiaries and affiliates other than the Partnership and the General Partner during periods in which the Partnership and the General Partner were affiliated with SemGroup, L.P.).  The Partnership’s common and subordinated unitholders will be required to pay taxes on their share of the Partnership’s taxable income even though they did not receive a distribution for the quarters ended June 30, 2008 through March 31, 2011, and will not receive a distribution for the quarter ended June 30, 2011.  The Partnership is currently allowed to make distributions to its unitholders in accordance with its debt covenants; however, the Partnership will only make distributions to the extent it has sufficient cash from operations after establishment of cash reserves as determined by the General Partner in accordance with the Partnership’s cash distribution policy, including the establishment of any reserves for the proper conduct of the Partnership’s business.  The Partnership’s partnership agreement provides that, during the subordination period, which the Partnership is currently in, the Partnership’s common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.3125 per common unit per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units.  After giving effect to the nonpayment of distributions for the quarters ended June 30, 2008 through June 30, 2011, each common unit was entitled to an arrearage of $4.06, or total arrearages for all common units of $88.9 million based upon 21,890,224 common units outstanding as of August 3, 2011.

On May 13, 2011, the Partnership paid a distribution of $0.24 per Preferred Unit, or a total distribution of $5.2 million on its Preferred Units for the portion of the quarter ended December 31, 2010 during which the Preferred Units were outstanding and for the quarter ended March 31, 2011. On August 4, 2011, the board of directors of the General Partner (the “Board”) approved a distribution of $0.14 per Preferred Unit, or a total distribution of $3.0 million.  The Partnership anticipates paying this distribution on the preferred units on August 12, 2011 to preferred unitholders of record as of August 8, 2011.

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7.   NET INCOME PER COMMON AND SUBORDINATED UNIT

For purposes of calculating earnings per unit, the excess of distributions over earnings or excess of earnings over distributions for each period are allocated to the entities’ general partner based on the general partner’s ownership interest at the time. The following sets forth the computation of basic and diluted net loss per common and subordinated unit (in thousands, except per unit data):

	Three Months Ended June 30, 2010			Three Months Ended June 30, 2011			Six Months Ended June 30, 2010			Six Months Ended June 30, 2011
Net loss	$	(2,701	)	$	(5,345	)	$	(7,752	)	$	(2,712	)
Less: Beneficial conversion feature attributable to preferred units		—			11,021			—			21,920
Less: Preferred interest in net income		—			2,975			—			8,149
Less: General partner interest in net income (loss)		(54	)		(46	)		(154	)		111
Net loss available to common and subordinated unitholders	$	(2,647	)	$	(19,295	)	$	(7,598	)	$	(32,892	)
Basic and diluted weighted average number of units:
Common units		21,728			21,890			21,728			21,890
Subordinated units		12,571			12,571			12,571			12,571
Restricted and phantom units		13			457			13			343
Basic and diluted net loss per common unit	$	(0.08	)	$	(0.55	)	$	(0.22	)	$	(0.94	)
Basic and diluted net loss per subordinated unit	$	(0.08	)	$	(0.55	)	$	(0.22	)	$	(0.94	)

8.   RELATED PARTY TRANSACTIONS

The Partnership provides crude oil gathering, transportation, terminalling and storage services to Vitol.  For the three and six months ended June 30, 2010, the Partnership recognized revenues of $5.6 million and $8.7 million, respectively, for services provided to Vitol.  For the three and six months ended June 30, 2011, the Partnership recognized revenues of $10.4 million and $20.0 million, respectively, for services provided to Vitol.  As of June 30, 2011, the Partnership had receivables from Vitol of $2.1 million.

Vitol Storage Agreements

In connection with the Partnership’s acquisition of certain of its crude oil storage assets from SemCorp in May 2008, the Partnership was assigned from SemCorp a storage agreement with Vitol under which the Partnership provides crude oil storage services to Vitol (the “2008 Vitol Storage Agreement”).  The initial term of the 2008 Vitol Storage Agreement was from June 1, 2008 through June 30, 2010. This agreement was amended, effective as of June 1, 2010, to extend the term of the agreement until June 1, 2011 (the “2010 Amendment”).  Vitol and the Partnership are currently in discussions to extend or replace this storage agreement.  Because Vitol was a third party (and not a related or affiliated party) at the time of entering into the 2008 Vitol Storage Agreement, such agreement was not approved by the Board or the Board’s conflicts committee in accordance with the Partnership’s procedures for approval of related party transactions.  Vitol became a related party after the Vitol Change of Control in November 2009.  Since the 2010 Amendment occurred subsequent to the Vitol Change of Control, it was reviewed and approved by the Board’s conflicts committee in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of the partnership agreement.  The Partnership earned revenues of approximately $3.1 million and $3.3 million from Vitol with respect to services provided pursuant to the 2008 Vitol Storage Agreement for the three month periods ended June 30, 2010 and 2011, respectively.  The Partnership earned revenues of approximately $6.0 million and $6.6 million from Vitol with respect to services provided pursuant to the 2008 Vitol Storage Agreement for the six month periods ended June 30, 2010 and 2011, respectively.  The Partnership believes that the rates it charges Vitol under the 2008 Vitol Storage Agreement are fair and reasonable to the Partnership and its unitholders and are comparable with the rates the Partnership charges third parties.

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In March of 2010, the Partnership entered into a second crude oil storage services agreement with Vitol under which the Partnership began providing additional crude oil storage services to Vitol effective May 1, 2010 (the “2010 Vitol Storage Agreement”).  The initial term of the 2010 Vitol Storage Agreement is five years commencing on May 1, 2010, subject to automatic renewal periods for successive one year periods until terminated by either party with ninety days prior notice.  The 2010 Vitol Storage Agreement was reviewed and approved by the Board’s conflicts committee in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of the partnership agreement.  The Partnership generated revenues under this agreement of approximately $2.0 million and $3.1 million during the three month periods ended June 30, 2010 and 2011, respectively.  The Partnership generated revenues under this agreement of approximately $2.0 million and $6.2 million during the six month periods ended June 30, 2010 and 2011, respectively.  The Partnership believes that the rates it charges Vitol under the 2010 Vitol Storage Agreement are fair and reasonable to the Partnership and its unitholders and are comparable with the rates the Partnership charges third parties.

Vitol Master Lease Agreement

In July of 2010, the Partnership and Vitol entered into a Master Agreement (the “Master Agreement”) relating to the lease of certain vehicles by the Partnership from Vitol.  Pursuant to the Master Agreement, the Partnership may lease certain vehicles, including light duty trucks, tractors, tank trailers and bobtail tank trucks, from Vitol for periods ranging from 36 months to 84 months depending on the type of vehicle.  The Partnership will have the opportunity to purchase each vehicle at the end of the lease at the estimated residual value of such vehicle.  Leases under the Master Agreement are accounted for as operating leases.  During the three and six months ended June 30, 2011, the Partnership recorded expenses under this agreement of approximately $0.1 million and $0.3 million, respectively.  The Master Agreement was approved by the Board’s conflicts committee in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of its partnership agreement.

Vitol Throughput Capacity Agreement

In August of 2010, the Partnership and Vitol entered into a Throughput Capacity Agreement (the “ENPS Throughput Agreement”).  Pursuant to the ENPS Throughput Agreement, Vitol purchased 100% of the throughput capacity on the Partnership’s Eagle North Pipeline System (“ENPS”).  The Partnership put ENPS in service in December of 2010.  In September of 2010, Vitol paid the Partnership a prepaid fee equal to $5.5 million and Vitol will pay additional usage fees for every barrel delivered by or on behalf of Vitol on ENPS.  This $5.5 million fee received from Vitol is accounted for as a long-term payable to a related party and is reflected as such on the Partnership’s consolidated balance sheet as of June 30, 2011.  In addition, if the payments made by Vitol in any contract year under the ENPS Throughput Agreement are in the aggregate less than $2.4 million, then Vitol will pay the Partnership a deficiency payment equal to $2.4 million minus the aggregate amount of all payments made by Vitol during such contract year.  The ENPS Throughput Agreement has a term that extends for four years after ENPS is completed and may be extended by mutual agreement of the parties for additional one-year terms.  If the capacity on ENPS is unavailable for use by Vitol for more than 60 days, whether consecutive or nonconsecutive, during the term of the ENPS Throughput Agreement, then Vitol shall have the right to terminate the ENPS Throughput Agreement within six months after such lack of capacity.  The Partnership has previously contracted to provide throughput services on ENPS to a third party and Vitol’s rights to the capacity of ENPS are subordinate to the rights of such third party.  In addition, for so long as a default by Vitol relating to payments under the ENPS Throughput Agreement has not occurred and is continuing, the Partnership will remit to Vitol any and all tariffs and deficiency payments received by the Partnership or its affiliates from such third party pursuant to its agreement with the Partnership.  The ENPS Throughput Agreement was approved by the Board’s conflicts committee in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of its partnership agreement.

During the three and six months ended June 30, 2011, the Partnership incurred interest expense under this agreement of approximately $0.2 million and $0.4 million, respectively.  The agreement has an effective annual interest rate of 14.1% and matures on December 31, 2014.

Vitol’s Commitment under the Partnership’s Credit Agreement

Vitol is a lender under the Partnership’s current credit agreement and has committed to loan the Partnership $15.0 million pursuant to such agreement.   During the three and six months ended June 30, 2011, Vitol received its pro rata portion of the interest payments in connection with being a lender under the credit agreement and received approximately $0.2 million and $0.3 million, respectively, in connection therewith.

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9.   LONG-TERM INCENTIVE PLAN

In July of 2007, the General Partner adopted the Blueknight Energy Partners G.P., L.L.C. Long-Term Incentive Plan (the “Plan”). The compensation committee of the Board administers the Plan. The Plan authorizes the grant of an aggregate of 1.25 million common units deliverable upon vesting. The Partnership has filed a proxy statement to solicit unitholder vote to increase the number of common units available under the Plan to 2,600,000 common units.  Although other types of awards are contemplated under the Plan, currently outstanding awards include “phantom” units, which convey the right to receive common units upon vesting, and “restricted” units, which are grants of common units restricted until the time of vesting. The phantom unit awards also include distribution equivalent rights (“DERs”).

Subject to applicable earning criteria, a DER entitles the grantee to a cash payment equal to the cash distribution paid on an outstanding common unit prior to the vesting date of the underlying award. Recipients of restricted units are entitled to receive cash distributions paid on common units during the vesting period which distributions are reflected initially as a reduction of partners’ capital. Distributions paid on units which ultimately do not vest are reclassified as compensation expense.  Awards granted to date are equity awards and, accordingly, the fair value of the awards as of the grant date is expensed over the vesting period.  For the six months ended June 30, 2010 and 2011, the Partnership recognized expense under the Plan of approximately $17,000 and $209,000, respectively.

In November of 2009, 10,000 restricted common units were granted which vest in one-third increments over three years.  This grant was made in connection with the reorganization of the Board.  In December of 2009, 2,500 restricted common units were granted which vest in one-third increments over three years.  On November 12, 2010 Charlesbank acquired a 50% ownership interest in the entity that owns the General Partner and 50% of the Partnership’s outstanding subordinated units from Vitol (the “Charlesbank Change of Control”).  Due to the Charlesbank Change of Control, all outstanding awards as of November 12, 2010 vested.  In December 2010, 12,500 common units were issued in connection with the vesting of the outstanding awards due to the Charlesbank Change of Control.

In December 2010, 7,500 restricted common units were granted which vest in one-third increments over three years.  This grant was made in connection with the anniversary of the independent directors joining the Board.

In March 2011, grants for 299,900 phantom common units were made, all of which vest on January 1, 2014.  These grants are equity awards under ASC 718 – Stock Compensation , and, accordingly, the fair value of the awards as of the grant date is expensed over the vesting period. The weighted average grant date fair-value of the awards is $8.25 per unit, which is the closing market price on the March 10, 2011 grant date of the awards. The value of these award grants was approximately $2.5 million on their grant date, and the unrecognized estimated compensation cost at June 30, 2011 was $1.6 million, which will be recognized over the remaining vesting period. As of June 30, 2011, the Partnership expects approximately 75% of these awards will vest.  The Partnership’s equity-based incentive compensation expense for the three and six months ended June 30, 2011 was $0.1 million and $0.2 million, respectively.

Activity pertaining to phantom common units and restricted common unit awards granted under the Plan is as follows:

	Number of Shares			Weighted Average Grant Date Fair Value
Nonvested at December 31, 2010		7,500		$	7.30
Granted		299,900			8.25
Vested		—			—
Forfeited		(1,000	)		8.25
Nonvested at June 30, 2011		306,400		$	8.23

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10.   EMPLOYEE BENEFIT PLAN

Under the Partnership’s 401(k) Plan, which was formed in 2009, employees who meet specified service requirements may contribute a percentage of their total compensation, up to a specified maximum, to the plan. The Partnership may match each employee’s contribution, up to a specified maximum, in full or on a partial basis. The Partnership recognized expense of $0.4 million and $0.3 million, respectively, for the three month period ended June 30, 2010 and 2011, respectively, for discretionary contributions under the plan.  The Partnership recognized expense of $0.6 million and $0.7 million, respectively, for the six month period ended June 30, 2010 and 2011, respectively, for discretionary contributions under the plan.

11.   FAIR VALUE MEASUREMENTS

The Partnership utilizes a three-tier framework for assets and liabilities required to be measured at fair value. In addition, the Partnership uses valuation techniques, such as the market approach (comparable market prices), the income approach (present value of future income or cash flow), and the cost approach (cost to replace the service capacity of an asset or replacement cost) to value these assets and liabilities as appropriate. The Partnership uses an exit price when determining the fair value. The exit price represents amounts that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants.

The Partnership utilizes a three-tier fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels. The following is a brief description of those three levels: 

Level 1 Observable inputs such as quoted prices (unadjusted) in active markets for identical assets or liabilities.

Level 2 Inputs other than quoted prices that are observable for these assets or liabilities, either directly or indirectly.  These include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active.

Level 3 Unobservable inputs in which there is little market data, which requires the reporting entity to develop its own assumptions.

This hierarchy requires the use of observable market data, when available, and to minimize the use of unobservable inputs when determining fair value. 

The Partnership's recurring financial assets and liabilities subject to fair value measurements and the necessary disclosures are as follows (in thousands):

	Fair Value Measurements as of December 31, 2010
Description	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs   (Level 3)
Liabilities:
Fair value of derivative embedded within subordinated convertible debt	$	27,550	$	—	$	—	$	27,550
Fair value of rights offering contingency	$	10,441	$	—	$	—	$	10,441
Total	$	37,991	$	—	$	—	$	37,991

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	Fair Value Measurements as of June 30, 2011
Description	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs   (Level 3)
Liabilities:
Fair value of derivative embedded within subordinated convertible debt	$	22,684	$	—	$	—	$	22,684
Fair value of rights offering contingency	$	16,827	$	—	$	—	$	16,827
Total	$	39,511	$	—	$	—	$	39,511

The fair value of the embedded derivative within the subordinated convertible debt was derived using a valuation model and has been classified as Level 3. The valuation model used is a discounted cash flow model (income approach) that assumes future distribution payments by the Partnership and utilizes interest rates and credit spreads for subordinated debt to preferred stock to determine the fair value of the derivative embedded within the convertible debt. The change in fair value of the derivative liability for the three and six months ended June 30, 2011 of $3.4 million and $4.9 million, respectively, is included in other (income) expense in the Partnership’s consolidated statements of operations.

The fair value of the rights offering contingency related to certain rights that may be offered to common unitholders under the proposed Global Transaction Agreement was derived using a valuation model and has been classified as Level 3.  The valuation model used is a probability-weighted model (income approach) and assumes both the probability of approval of the unitholder proposals by the common unitholders and the number of rights that are exercised as well as the expected fair value of the preferred units at the time such rights are exercised.  The change in fair value of the rights offering contingency for the three and six months ended June 30, 2011 of $1.5 million and $6.4 million, respectively, is included in other (income) expense in the Partnership’s consolidated statements of operations.

The following table sets forth a reconciliation of changes in the fair value of the Partnership’s financial liabilities classified as Level 3 in the fair value hierarchy (in thousands):

	Measurements Using Significant Unobservable Inputs (Level 3)
	For the Three  Months Ended June 30, 2011		For the Six Months Ended June 30, 2011
Beginning Balance	$	34,536	$	37,991
Total gains or losses (realized/unrealized)
Included in earnings		4,975		1,520
Included in other comprehensive income		—		—
Purchases, issuances, and settlements		—		—
Transfers in and/or out of Level 3		—		—
Balance at June 30, 2011	$	39,511	$	39,511
The amount of  total expense for the period included in earnings attributable to the change in unrealized gains (losses) for liabilities still held at the reporting date	$	4,975	$	1,520

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12.   OPERATING SEGMENTS

The Partnership’s operations consist of four operating segments: (i) crude oil terminalling and storage services, (ii) crude oil pipeline services, (iii) crude oil trucking and producer field services, and (iv) asphalt services.  During the fourth quarter of 2010, the Partnership changed the structure of its internal organization in a manner that caused the composition of its reportable segments to change.  Previously, the crude oil pipeline services segment and the crude oil trucking and producer field services segment were presented on a combined basis.  The change in the Partnership’s internal organization was prompted by the December 2010 acquisition of a producer field services business and the December 2010 placement of the ENPS into service.  All periods prior to this change in the Partnership’s internal organization have been restated to reflect the Partnership’s current operating segments.

CRUDE OIL TERMINALLING AND STORAGE SERVICES —The Partnership provides crude oil terminalling and storage services at its terminalling and storage facilities located in Oklahoma and Texas.

CRUDE OIL PIPELINE SERVICES —The Partnership owns and operates three pipeline systems, the Mid-Continent system, the Longview system and ENPS, that gather crude oil purchased by its customers and transports it to refiners, to common carrier pipelines for ultimate delivery to refiners or to terminalling and storage facilities owned by the Partnership and others. The Partnership refers to its pipeline system located in Oklahoma and the Texas Panhandle as the Mid-Continent system. It refers to its second pipeline system, which is located in Texas, as the Longview system.  In December 2010, the Partnership placed into service a third pipeline system, ENPS, originating in Cushing, Oklahoma and terminating in Ardmore, Oklahoma.

CRUDE OIL TRUCKING AND PRODUCER FIELD SERVICES — The Partnership uses its owned and leased tanker trucks to gather crude oil for its customers at remote wellhead locations generally not covered by pipeline and gathering systems and to transport the crude oil to aggregation points and storage facilities located along pipeline gathering and transportation systems.  Crude oil producer field services consist of a number of producer field services, ranging from gathering condensates from natural gas companies to hauling produced water to disposal wells.

ASPHALT SERVICES —The Partnership provides asphalt product and residual fuel terminalling, storage and blending services at its terminalling and storage facilities located in twenty-two states.

The Partnership’s management evaluates performance based upon segment operating margin, which includes revenues from related parties and external customers and operating expenses excluding depreciation and amortization. The non-GAAP measure of operating margin (in the aggregate and by segment) is presented in the following table. The Partnership computes the components of operating margin by using amounts that are determined in accordance with GAAP. A reconciliation of operating margin to income (loss) before income taxes, which is its nearest comparable GAAP financial measure, is included in the following table. The Partnership believes that investors benefit from having access to the same financial measures being utilized by management. Operating margin is an important measure of the economic performance of the Partnership’s core operations. This measure forms the basis of the Partnership’s internal financial reporting and is used by its management in deciding how to allocate capital resources between segments.  Income (loss) before income taxes, alternatively, includes expense items, such as depreciation and amortization, general and administrative expenses and interest expense, which management does not consider when evaluating the core profitability of the Partnership’s operations.

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The following table reflects certain financial data for each segment for the periods indicated (in thousands):  

	Crude Oil Terminalling and Storage Services		Crude Oil Pipeline Services		Crude Oil Trucking and Producer Field Services		Asphalt  Services		Total
Three Months Ended June 30, 2010
Service revenue
Third party revenue	$	4,694	$	2,972	$	10,828	$	14,326	$	32,820
Related party revenue		5,340		223		60		—		5,623
Total revenue for reportable segments		10,034		3,195		10,888		14,326		38,443
Operating expenses (excluding depreciation and amortization)		718		2,537		10,170		5,333		18,758
Operating margin (excluding depreciation and amortization)		9,316		658		718		8,993		19,685	(1)
Total assets (end of period)		77,489		75,901		11,816		132,085		297,291
Three Months Ended June 30, 2011
Service revenue
Third party revenue	$	2,859	$	5,040	$	10,594	$	14,177	$	32,670
Related party revenue		6,743		1,166		2,512		—		10,421
Total revenue for reportable segments		9,602		6,206		13,106		14,177		43,091
Operating expenses (excluding depreciation and amortization)		1,364		4,821		11,721		5,879		23,785
Operating margin (excluding depreciation and amortization)		8,238		1,385		1,385		8,298		19,306	(1)
Total assets (end of period)		78,918		101,621		15,472		131,437		327,448
Six Months Ended June 30, 2010
Service revenue
Third party revenue	$	11,503	$	5,907	$	20,965	$	28,406	$	66,781
Related party revenue		8,366		256		72		—		8,694
Total revenue for reportable segments		19,869		6,163		21,037		28,406		75,475
Operating expenses (excluding depreciation and amortization)		1,733		5,322		20,660		11,372		39,087
Operating margin (excluding depreciation and amortization)		18,136		841		377		17,034		36,388	(1)
Total assets (end of period)		77,489		75,901		11,816		132,085		297,291
Six Months Ended June 30, 2011
Service revenue
Third party revenue	$	5,375	$	8,894	$	22,464	$	27,891	$	64,624
Related party revenue		14,066		2,181		3,743		—		19,990
Total revenue for reportable segments		19,441		11,075		26,207		27,891		84,614
Operating expenses (excluding depreciation and amortization)		2,117		8,791		24,510		11,276		46,694
Operating margin (excluding depreciation and amortization)		17,324		2,284		1,697		16,615		37,920	(1)
Total assets (end of period)		78,918		101,621		15,472		131,437		327,448

____________________

(1) The following table reconciles segment operating margin (excluding depreciation and amortization) to loss before income taxes (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2011			2010			2011
Operating margin (excluding depreciation and amortization)	$	19,685		$	19,306		$	36,388		$	37,920
Depreciation and amortization		5,399			5,710			10,913			11,415
General and administrative expenses		3,385			4,777			7,153			9,386
Interest expense		13,549			9,112			25,972			18,164
Change in fair value of embedded derivative within convertible debt		—			3,431			—			(4,866	)
Change in fair value of contingent dividends		—			1,544			—			6,386
Loss before income taxes	$	(2,648	)	$	(5,268	)	$	(7,650	)	$	(2,565	)

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13.   COMMITMENTS AND CONTINGENCIES

The Partnership is subject to various legal actions and claims, including a securities class action and other lawsuits, an SEC investigation and a Grand Jury investigation due to events related to SemCorp’s bankruptcy filings.  The Partnership intends to vigorously defend these actions.  On May 3, 2011, the Partnership entered into a Stipulation of Settlement (the “Stipulation”) to settle the consolidated securities class action litigation, In Re: SemGroup Energy Partners, L.P. Securities Litigation, Case No. 08-MD-1989-GKF-FHM (the “Class Action Litigation”), pending in the U.S. District Court for the Northern District of Oklahoma.  As set forth more fully in the Stipulation, if the proposed settlement is given final approval by the court, among other things, the shareholder class will receive a total payment of approximately $28.0 million from the defendants.  On June 9, 2011, the Court entered an order preliminarily approving, subject to further consideration at a settlement hearing, the proposed settlement pursuant to the Stipulation involving, among other things, a dismissal of the Class Action Litigation with prejudice.  The settlement hearing is currently scheduled for October 5, 2011 to determine whether the terms and conditions of the settlement provided for in the Stipulation are fair, reasonable, adequate and in the best interests of the class and to consider whether to enter a final judgment approving the settlement in its entirety.  The Partnership has accrued a contingent loss of $20.2 million as of June 30, 2011 related to its portion of the proposed settlement. Of that amount, the Partnership expects to receive insurance proceeds of $13.0 million to $13.9 million and accordingly recognized an insurance recovery receivable of $13.0 million as of June 30, 2011.  Of the difference, the Partnership expects to issue common units of the Partnership with a value equal to approximately $5.2 million.  The net loss of $7.2 million attributable to this action was recognized in the fourth quarter of 2010.  In June of 2011 the Partnership paid $0.5 million towards the settlement in escrow.  This $0.5 million is reflected as a current asset on the Partnership’s balance sheet as of June 30, 2011 and will be applied to the accrued settlement liability in the event the proposed settlement is finalized.  No parties admit any wrongdoing as part of the proposed settlement.  The proposed settlement is subject to a number of conditions and approvals, including, among other items, preliminary and final court approval. Details regarding any proposed settlement will be communicated to potential class members prior to final court approval. At this time, there can be no assurance that the conditions to effect the settlement will be met or that the settlement of the Class Action Litigation will receive the required court and other approvals.  The ultimate resolution of these actions could have a material adverse effect on the Partnership’s business, financial condition, results of operations, cash flows, ability to make distributions to its unitholders, the trading price of the Partnership’s common units and the Partnership’s ability to conduct its business.

On October 27, 2008, Keystone Gas Company (“Keystone”) filed suit against the Partnership in Oklahoma State District Court in Creek County alleging that it is the rightful owner of certain segments of the Partnership’s pipelines and related rights of way, located in Payne and Creek Counties, that the Partnership acquired from SemCorp in connection with the Partnership’s initial public offering in 2007. Keystone seeks to quiet title to the specified rights of way and pipelines and seeks damages up to the net profits derived from the disputed pipelines. There has been no determination of the extent of potential damages for the Partnership’s use of such pipelines. The Partnership has filed a counterclaim against Keystone alleging that it is wrongfully using a segment of a pipeline that is owned by the Partnership in Payne and Creek Counties. The parties are engaged in discovery. The Partnership intends to vigorously defend these claims. No trial date has been set by the court.

In March and April 2009, nine current or former executives of SemCorp and certain of its affiliates filed wage claims with the Oklahoma Department of Labor against the Partnership’s general partner.  Their claims arise from the Partnership’s general partner’s Long-Term Incentive Plan, Employee Phantom Unit Agreement (“Phantom Unit Agreement”).  Most claimants alleged that phantom units previously awarded to them vested upon the Change of Control that occurred in July 2008.  One claimant alleged that his phantom units vested upon his termination.  The claimants contended the Partnership’s general partner’s failure to deliver certificates for the phantom units within 60 days after vesting caused them to be damaged, and they sought recovery of approximately $2.0 million in damages and penalties.  On April 30, 2009, all of the wage claims were dismissed on jurisdictional grounds by the Department of Labor.

On July 8, 2009, the nine executives filed suit against the Partnership’s general partner in Tulsa County district court claiming they are entitled to recover the value of phantom units purportedly due them under the Phantom Unit Agreement. The claimants assert claims against the Partnership’s general partner for alleged failure to pay wages and breach of contract and seek to recover the alleged value of units in the total amount of approximately $1.3 million, plus additional damages and attorneys’ fees.  The Partnership has distributed phantom units to certain of the claimants.   On April 14, 2010, a Tulsa County district court judge ruled in favor of seven of the claimants, and awarded them approximately $1.0 million in damages.  The Partnership has appealed this ruling.  On October 22, 2010, the Partnership’s general partner was ordered to pay $0.2 million in attorneys’ fees.  The Partnership has appealed this order also.

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The Official Committee of Unsecured Creditors of SemCrude, L.P. (“Unsecured Creditors Committee”) filed an adversary proceeding in connection with SemCorp’s bankruptcy cases against Thomas L. Kivisto, Gregory C. Wallace, and Westback Purchasing Company, L.L.C.  In that proceeding, filed February 18, 2009, the Unsecured Creditors Committee asserted various claims against the defendants on behalf of SemCorp’s bankruptcy estate, including claims based upon theories of fraudulent transfer, breach of fiduciary duties, waste, breach of contract, and unjust enrichment.  On June 8, 2009, the Unsecured Creditors Committee filed a Second Amended Complaint asserting additional claims against Kevin L. Foxx and Alex G. Stallings, among others, based upon certain findings and recommendations in the examiner’s report.  On October 6, 2009, a Third Amended Complaint was filed, and in December 2009, the Litigation Trust was substituted as the Plaintiff in the action.  The claims in the Third Amended Complaint against Mr. Foxx and Mr. Stallings are based upon theories of fraudulent transfer, unjust enrichment, waste, breach of fiduciary duty, and breach of contract.  Messrs. Foxx and Stallings moved to dismiss the claims against them.

On July 14, 2010, the Litigation Trust filed another adversary proceeding against Mr. Foxx, seeking to avoid certain transfers from SemCorp to Mr. Foxx and to bar Mr. Foxx from asserting claims in SemCorp’s bankruptcy.

Messrs. Kivisto, Wallace, Cooper, Foxx and Stallings have reached an agreement with the Litigation Trust to settle the claims against them in the adversary proceedings described above.  The agreement calls for the payment of $30 million to the Trust out of the proceeds of certain SemCorp insurance policies.  In exchange, the Trust will provide a release of claims against Messrs. Kivisto, Wallace, Cooper, Foxx and Stallings.  The court has approved the settlement over an objection, and the objection has been appealed.  That appeal is pending.

On July 24, 2009, the Partnership filed suit against Navigators Insurance Company (“Navigators”) and Darwin National Assurance Company (“Darwin”) in Tulsa County district court. In that suit, the Partnership is seeking a declaratory judgment that Darwin and Navigators did not have the right to rescind binders issued to the Partnership for three excess insurance policies in its Directors and Officers insurance program for the period from July 18, 2008 to July 18, 2009. The face amount of two of the policies was $10,000,000, and the face amount of the third policy was $5,000,000. The suit seeks a declaratory judgment that the binders were enforceable insurance contracts of Navigators and Darwin that have not been rescinded or cancelled. The suit also alleges that the attempted rescissions were in breach of contract and violated the duty of good faith and fair dealing, for which the Partnership is seeking the recovery of damages and attorneys’ fees.  Navigators and Darwin have answered the petition and the parties are engaged in discovery.  This case has been temporarily stayed.  The Partnership expects that this suit will be dismissed if a settlement of the class action litigation pending against it is finalized and approved.  The Stipulation relating to the settlement of the Class Action Litigation and a motion seeking preliminary court approval of the proposed settlement were filed on May 3, 2011.  On June 9, 2011, the Court entered an order preliminarily approving, subject to further consideration at a settlement hearing, the proposed settlement pursuant to the Stipulation involving, among other things, a dismissal of the Class Action Litigation with prejudice.  The settlement hearing is currently scheduled for October 5, 2011 to determine whether the terms and conditions of the settlement provided for in the Stipulation are fair, reasonable, adequate and in the best interests of the class and to consider whether to enter a final judgment approving the settlement in its entirety.

Koch Industries, Inc. (together with its subsidiaries, “Koch”), a previous owner of the Partnership’s asphalt facility located in Northumberland, Pennsylvania, has alleged that the Partnership has responsibility to assess the polychlorinated biphenyl (“PCB”) contamination at such facility although the contamination occurred prior to the Partnership becoming the owner of such facility.  Koch claims that it was absolved of its responsibility to assess and clean up the site during SemCorp’s bankruptcy proceedings.  The Partnership contends that Koch retained responsibility for such environmental issues and that SemCorp’s bankruptcy proceedings did not absolve Koch of these liabilities.  On July 6, 2011, the Partnership filed an adversary complaint in connection with SemCorp’s bankruptcy cases against Koch seeking a declaration that SemCorp’s bankruptcy proceedings did not impact Koch’s responsibility to assess and clean the Northumberland site.  A responsive pleading by Koch is expected within the next thirty days.  The Partnership intends to vigorously defend against Koch’s allegation that the Partnership should be required to assess or clean up the PCB contamination.       

On July 11, 2011, ExxonMobil filed suit against the Partnership in Harris County District Court, State of Texas, requesting damages in excess of $35,000 from the Partnership and other, third party service providers in connection with the relocation of existing pipelines of ExxonMobil and the Partnership.  The answer date is August 15, 2011.  ExxonMobil had previously sent a settlement demand seeking approximately $1.9 million in damages.  The Partnership intends to vigorously defend these claims.

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In connection with the Partnership’s refinancing, several of its significant unitholders have filed Schedule 13Ds with the SEC indicating that they may take various actions and pursue options or remedies with respect to their investment in the Partnership, including, without limitation, pursuing litigation against the Partnership’s general partner, the Board, management of the Partnership’s general partner and/or one or more affiliates thereof.  The Partnership believes the allegations made in these Schedule 13Ds are without merit and intends to vigorously defend any litigation that may be pursued.  For more information regarding the Partnership’s refinancing, please see “Management’s Discussion and Analysis of Financial Condition—Recent Events—Global Transaction Agreement.”

The Partnership may become the subject of additional private or government actions regarding these matters in the future.  Litigation may be time-consuming, expensive and disruptive to normal business operations, and the outcome of litigation is difficult to predict.  The defense of these lawsuits may result in the incurrence of significant legal expense, both directly and as the result of the Partnership’s indemnification obligations.  The litigation may also divert management’s attention from the Partnership’s operations which may cause its business to suffer.  An unfavorable outcome in any of these matters may have a material adverse effect on the Partnership’s business, financial condition, results of operations, cash flows, ability to make distributions to its unitholders, the trading price of the Partnership’s common units and its ability to conduct its business. All or a portion of the defense costs and any amount the Partnership may be required to pay to satisfy a judgment or settlement of these claims may not be covered by insurance.

The Partnership is from time to time subject to various legal actions and claims incidental to its business, including those arising out of environmental-related matters. Management believes that these legal proceedings will not have a material adverse effect on the financial position, results of operations or cash flows of the Partnership. Once management determines that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred and the amount of such liability can be reasonably estimated, an accrual is established equal to its estimate of the likely exposure.

The Partnership has contractual obligations to perform dismantlement and removal activities in the event that some of its asphalt product and residual fuel oil terminalling and storage assets are abandoned. These obligations include varying levels of activity including completely removing the assets and returning the land to its original state. The Partnership has determined that the settlement dates related to the retirement obligations are indeterminate. The assets with indeterminate settlement dates have been in existence for many years and with regular maintenance will continue to be in service for many years to come. Also, it is not possible to predict when demands for the Partnership’s terminalling and storage services will cease, and the Partnership does not believe that such demand will cease for the foreseeable future.  Accordingly, the Partnership believes the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, the Partnership cannot reasonably estimate the fair value of the associated asset retirement obligations.  Management believes that if the Partnership’s asset retirement obligations were settled in the foreseeable future the potential cash flows that would be required to settle the obligations based on current costs are not material.  The Partnership will record asset retirement obligations for these assets in the period in which sufficient information becomes available for it to reasonably determine the settlement dates.

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14.   INCOME TAXES

The Partnership has entered into storage contracts and leases with third party customers with respect to substantially all of its asphalt facilities. At the time of entering into such agreements, it was unclear under current tax law as to whether the rental income from the leases, and the fees attributable to certain of the processing services the Partnership provides under certain of the storage contracts, constitute “qualifying income.” In the second quarter of 2009, the Partnership submitted a request for a ruling from the IRS that rental income from the leases constitutes “qualifying income.” In October 2009, the Partnership received a favorable ruling from the IRS. As part of this ruling, however, the Partnership agreed to transfer, and has transferred, certain of its asphalt processing assets and related fee income to a subsidiary taxed as a corporation. This transfer occurred in the first quarter of 2010.  Such subsidiary is required to pay federal income tax on its income at the corporate tax rate, which is currently a maximum of 35%, and will likely pay state (and possibly local) income tax at varying rates. Distributions from this subsidiary will generally be taxed again to unitholders as corporate distributions and none of the income, gains, losses, deductions or credits of this subsidiary will flow through to the Partnership’s unitholders.

In relation to the Partnership’s taxable subsidiary, the tax effects of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts and the tax credits and other items that give rise to significant portions of the deferred tax assets at June 30, 2011 are presented below (dollars in thousands):

Deferred tax assets
Difference in bases of property, plant and equipment	$	1,257,158
Net operating loss carryforwards		58,951
Deferred tax asset		1,316,109
Less: valuation allowance		(1,316,109	)
Net deferred tax asset	$	—

Given the Partnership’s subsidiary taxed as a corporation has no earnings history to determine the likelihood of realizing the benefits of the deferred tax assets and the fact that the Partnership anticipates this subsidiary will generate net operating losses for the foreseeable future, the Partnership has provided a full valuation allowance against its deferred tax asset.

15.   RECENTLY ISSUED ACCOUNTING STANDARDS

In January 2010, the FASB issued ASU 2010-06, “Improving Disclosures about Fair Value Measurements,” which requires separate disclosure of purchases, sales, issuances and settlements in the reconciliation of the Partnership’s Level 3 fair value measurements.  The Partnership adopted this guidance with its March 31, 2011, Quarterly Report, and the impact was not material.  Other provisions of ASU 2010-06 were adopted in 2010.  

In May 2011, the FASB issued ASU 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRS),” which provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between GAAP and IFRS.  This new guidance changes some fair value measurement principles and disclosure requirements.  The Partnership is evaluating the impact of this guidance, which will be adopted beginning with the Partnership’s March 31, 2012, Quarterly Report.

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

As used in this quarterly report, unless we indicate otherwise: (1) “Blueknight Energy Partners,” “our,” “we,” “us” and similar terms refer to Blueknight Energy Partners, L.P. (f/k/a/ SemGroup Energy Partners, L.P.), together with its subsidiaries, (2) our “General Partner” refers to Blueknight Energy Partners G.P., L.L.C. (f/k/a SemGroup Energy Partners G.P., L.L.C.), (3) “SemCorp” refers to SemGroup Corporation and its predecessors (including SemGroup, L.P.), subsidiaries and affiliates (other than our General Partner and us during periods in which we were affiliated with SemGroup, L.P.), (4) Vitol refers to Vitol Holding B.V., its affiliates and subsidiaries (other than our General Partner and us) and (5) Charlesbank refers to Charlesbank Capital Partners, LLC its affiliates and subsidiaries (other than our General Partner and us).  The following discussion analyzes the historical financial condition and results of operations of the Partnership and should be read in conjunction with our financial statements and notes thereto, and Management’s Discussion and Analysis of Financial Condition and Results of Operations presented in our Annual Report on Form 10-K for the year ended December 31, 2010, which was filed with the Securities and Exchange Commission (the “SEC”) on March 16, 2011 (the “2010 Form 10-K”).

Forward-Looking Statements

This report contains “forward-looking statements” within the meaning of the federal securities laws.  Statements included in this quarterly report that are not historical facts (including any statements regarding plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), including, without limitation, the information set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “will,” “should,” “believe,” “expect,” “intend,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition, or state other “forward-looking” information. We and our representatives may from time to time make other oral or written statements that are also forward-looking statements.

Such forward-looking statements are subject to various risks and uncertainties that could cause actual results to differ materially from those anticipated as of the date of the filing of this report. Although we believe that the expectations reflected in these forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will prove to be correct. Important factors that could cause our actual results to differ materially from the expectations reflected in these forward-looking statements include, among other things, those set forth in “Part I, Item 1A. Risk Factors” in the 2010 Form 10-K.

All forward-looking statements included in this report are based on information available to us on the date of this report. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements contained throughout this report.

Overview

We are a publicly traded master limited partnership with operations in twenty-three states. We provide integrated terminalling, storage, gathering and transportation services for companies engaged in the production, distribution and marketing of crude oil and liquid asphalt cement.  We manage our operations through four operating segments: (i) crude oil terminalling and storage services, (ii) crude oil pipeline services, (iii) crude oil trucking and producer field services, and (iv) asphalt services.  Our common units, which represent limited partnership interests in our partnership, are listed on the NASDAQ Global Market. We were formed in February 2007 as a Delaware master limited partnership initially to own, operate and develop a diversified portfolio of complementary midstream energy assets.

In October of 2010, we refinanced our outstanding debt and concurrently raised capital through the issuance of additional partnership units (see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Recent Events” in our 2010 Form 10-K for additional information).  This resulted in decreased leverage, reduced interest rates on outstanding borrowings and increased liquidity.

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On November 12, 2010 Charlesbank acquired a 50% ownership interest in the entity that owns our General Partner and 50% of our outstanding subordinated units from Vitol (the “Charlesbank Change of Control”).  For more information regarding the Charlesbank Change of Control, please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Recent Events—Charlesbank Change of Control” in our 2010 Form 10-K.

Our Revenues

We have been pursuing opportunities to provide crude oil terminalling and storage services, crude oil pipeline services, crude oil trucking and producer field services and asphalt services to third parties.  For the three months ended June 30, 2011, we derived approximately 24% of our revenues from services we provided to Vitol, with the remainder of our services being provided to third parties.

Average rates for the new third-party crude oil terminalling and storage and gathering and transportation contracts are comparable with those previously received from SemCorp.  However, the volumes being terminalled, stored, gathered and transported have decreased as compared to periods prior to SemCorp’s bankruptcy filings, which has negatively impacted total revenues.  We believe that volumes stabilized in 2010, and we anticipate continued increased utilization of our assets in 2011.  We have successfully increased the utilization of our Mid-Continent pipeline system, and throughput during the second quarter of 2011 reached effective capacity on segments of the system.  While we see opportunity to increase the utilization of our crude oil trucking and producer field services assets due to high demand for our services in the markets we currently serve, demand outpaces supply for qualified drivers in this industry and is delaying our realization of complete utilization of these assets.  We are actively pursuing additional drivers, and we anticipate increased utilization of these assets in the second half of 2011.  However, there can be no assurance that our efforts will be successful.  Furthermore, effective August 1, 2011, we renegotiated the rates for the majority of our crude oil trucking services contracts, and expect to realize increased revenues in the second half of 2011 as a result.

The majority of the leases and storage agreements related to our asphalt facilities have terms that terminate between October 31, 2016 and December 31, 2016.  We operate the asphalt facilities pursuant to the storage agreements while our contract counterparties operate the asphalt facilities that are subject to the lease agreements.  

We continue to pursue additional revenues with third parties and have preliminary indications that our gathering and transportation volumes have stabilized.  We are aggressively pursuing incremental volumes for our systems; however, these additional efforts may not be successful.  If we are unable to generate sufficient third party revenues, we will continue to experience lower volumes in our system which could have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business.

Our Expenses

Our maintenance expenditures are increasing due both to a tank inspection program that we implemented in the first quarter of 2011 in response to new regulation of the asphalt industry and to previously deferred maintenance of our crude oil pipeline systems.  We currently anticipate maintenance capital expenditures to be approximately $12.0 million to $14.0 million in 2011.

Prior to SemCorp’s bankruptcy filings, we relied upon SemCorp to provide us certain services pursuant to a shared services agreement.  Subsequent to SemCorp’s bankruptcy filings we began transitioning to us the services provided by SemCorp under such shared services agreement.   This transition was completed in the second quarter of 2011.

In addition, we experienced increased interest expenses and other costs due to the events of default that existed under our prior credit agreement and from entering into associated amendments to such prior credit agreement.  In October of 2010, we entered into a new credit agreement and have experienced decreased interest expense in 2011 as a result.  Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Liquidity and Capital Resources” in the 2010 Form 10-K for a discussion of these agreements and the associated expenses.  

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Income taxes

As part of the process of preparing the consolidated financial statements, we are required to estimate the federal and state income taxes in each of the jurisdictions in which our subsidiary that is taxed as a corporation operates. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for tax and accounting purposes. These differences and the net operating loss (“NOL”) carryforwards result in deferred tax assets and liabilities, which are included in our consolidated balance sheet. We must then assess, using all available positive and negative evidence, the likelihood that the deferred tax assets will be recovered from future taxable income. If we believe that recovery is not likely, we must establish a valuation allowance. To the extent we establish a valuation allowance or increase or decrease this allowance in a period, we must include an expense or reduction of expense within the tax provisions in the consolidated statement of operations.

Under ASC 740, Accounting for Income Taxes , an enterprise must use judgment in considering the relative impact of negative and positive evidence. The weight given to the potential effect of negative and positive evidence should be commensurate with the extent to which it can be objectively verified. The more negative evidence that exists (a) the more positive evidence is necessary and (b) the more difficult it is to support a conclusion that a valuation allowance is not needed for some portion, or all of the deferred tax asset. Among the more significant types of evidence that we consider are:

• taxable income projections in future years,

• whether the carryforward period is so brief that it would limit realization of tax benefits,

• future revenue and operating cost projections that will produce more than enough taxable income to realize the deferred tax asset based on existing service rates and cost structures, and

• our earnings history exclusive of the loss that created the future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition.

Given that our subsidiary taxed as a corporation has no earnings history to determine the likelihood of realizing the benefits of the deferred tax assets and the fact that we anticipate this subsidiary generating net operating losses for the foreseeable future, we have provided a full valuation allowance against our deferred tax asset as of June 30, 2011.

Recent Events

Global Transaction Agreement

 On October 25, 2010 (the “Transaction Date”), we entered into a Global Transaction Agreement by and among us, our General Partner, Vitol and Charlesbank, pursuant to which we effected a refinancing of our existing debt.  The Global Transaction Agreement contemplated three sets of transactions comprised of the Phase I Transactions, the Unitholder Vote Transactions, and the Phase II Transactions, each as defined in the Global Transaction Agreement.  The Phase I Transactions were completed concurrently with the execution of the Global Transaction Agreement.  For a detailed description of the Global Transaction Agreement, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Recent Events” in our 2010 Form 10-K.

On May 12, 2011, we, our General Partner, Vitol and Charlesbank entered into the First Amendment to Global Transaction Agreement (the “Amendment”) pursuant to which the Unitholder Vote Transactions and the Phase II Transactions contemplated in the Global Transaction Agreement were modified.

Pursuant to the Global Transaction Agreement, as amended by the amendment, our General Partner has filed a definitive proxy statement with the Securities and Exchange Commission (the “SEC”) relating to a special meeting (the “Unitholder Meeting”) expected to be held on September 14, 2011 during which our unitholders will consider and vote upon (i) certain amendments to our partnership agreement (the “Partnership Agreement Amendment Proposal”) as more fully set forth below and (ii) an amendment to our General Partner’s Long-Term Incentive Plan to increase the number of common units issuable under such plan by 1,350,000 common units from 1,250,000 common units to 2,600,000 common units (the “LTIP Proposal”).  Pursuant to the Partnership Agreement Amendment Proposal, our partnership agreement would be amended to:

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• reset (1) the minimum quarterly distribution to $0.11 per unit per quarter from $0.3125 per unit per quarter, (2) the first target distribution to $0.1265 per unit per quarter from $0.3594 per unit per quarter, (3) the second target distribution to $0.1375 per unit per quarter from $0.3906 per unit per quarter and (4) the third target distribution to $0.1825 per unit per quarter from $0.4688 per unit per quarter;

• waive the cumulative common unit arrearage;

• remove provisions in the partnership agreement relating to the subordinated units, including concepts such as a subordination period (and any provisions that expressly apply only during the subordination period) and common unit arrearage, in connection with the transfer to us, and our subsequent cancellation, of all of the our outstanding subordinated units;

• provide that distributions shall not accrue or be paid to the holders of our incentive distribution rights for an eight quarter period beginning with the quarter in which the special meeting occurs;

• provide that during the period beginning on the date of this special meeting and ending on June 30, 2015 (the “Senior Security Restriction Period”), we will not issue any class or series of partnership securities that, with respect to distributions on such partnership securities or distributions upon liquidation of our partnership, ranks senior to the common units during the Senior Security Restriction Period, or “Senior Securities”, without the consent of the holders of at least a majority of the outstanding common units (excluding the common units held by our General Partner and its affiliates and excluding any Senior Securities that are convertible into common units); provided that we may issue an unlimited number of Senior Securities during the Senior Security Restriction Period without obtaining such consent if (i) such issuances are made in connection with the conversion of our convertible subordinated debentures issued to Vitol and Charlesbank in the aggregate principal amount of $50 million (the “Convertible Debentures”) or the consummation of the rights offering and use of proceeds therefrom, (ii) such issuances are made upon conversion, redemption or exchange of Senior Securities into or for Senior Securities of equal or lesser rank, where the aggregate amount of distributions that would have been paid with respect to such newly issued Senior Securities, plus the related distributions to the General Partner, in respect of the four-quarter period ending prior to the first day of the quarter in which the issuance is to be consummated (assuming such newly issued Senior Securities had been outstanding throughout such period) would not have exceeded the distributions actually paid during such period on the Senior Securities that are to be converted, redeemed or exchanged, plus the related distributions to the General Partner, (iii) such issuances are made in connection with thecombination or subdivision of any class of Senior Securities, (iv) such issuances are made in connection with an acquisition or expansion capital improvement that increases estimated pro forma Adjusted Operating Surplus (as defined in our partnership agreement) (less estimated pro forma distributions on our Series A Preferred Units (the “Preferred Units”) and on any other Senior Securities) on a per-common unit basis, as determined in good faith by our General Partner, as compared to actual Adjusted Operating Surplus (as defined in our partnership agreement) (less actual distributions on the Preferred Units and on any other Senior Securities) on a per-common unit basisor (v) the net proceeds of such issuances are used to repay indebtedness of our partnership or our subsidiaries; provided, however, that in the case of subsection (v) such new securities may not be issued to an affiliate of our General Partner unless the cost to service any new indebtedness that we determine that it could issue to retire existing indebtedness (with our General Partner’s determination being conclusive) is greater than the distribution obligations associated with the Senior Securities issued in connection with its retirement and one or more of the following conditions are also met: (A) the indebtedness that is being repaid matures within 12 months of such repayment, or (B) such indebtedness has experienced a default or event of default (even if the lenders of such indebtedness have agreed to forebear or waive such default or event of default) or (C) our General Partner expects to experience a default or event of default under such indebtedness within six months of such repayment (with our General Partner’s determination being conclusive);

• provide that in addition to our current rights to convert the Preferred Units into common units, the Preferred Units will also be convertible at our option at any time on or after October 25, 2015 if (i) the daily volume-weighted average trading price of the common units is greater than 130% of the Conversion Price (as defined in our partnership agreement) for twenty out of the trailing thirty trading days ending two trading days before we furnishes notice of conversion and (ii) the average trading volume of common units has exceeded 20,000 common units for twenty out of the trailing thirty trading days ending two trading days before we furnishe notice of conversion; and

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• provide that the conversion of Preferred Units shall become effective (i) in the case of Preferred Units that are being converted pursuant to Section 5.12(c)(i) of our partnership agreement (relating to conversions at the election of the holder of such units), as of the last day of the quarter in which the relevant notice of conversion is delivered by the applicable unitholder and (ii) in the case of Preferred Units that are being converted pursuant to Section 5.12(c)(ii) of our partnership agreement (relating to conversions at the election of our partnership), as of the date that the notice of conversion is delivered by us.

If the Partnership Agreement Amendment Proposal is approved, then (i) our General Partner will adopt the Fourth Amended and Restated Agreement of Limited Partnership of Blueknight Energy Partners, L.P. in the form attached to the proxy statement (the “Amended and Restated Partnership Agreement”) to reflect the approval of the Partnership Agreement Amendment Proposal as well as other amendments that our General Partner may make in accordance with the provisions of our partnership agreement as set forth therein, (ii) Vitol and Charlesbank will transfer all of our outstanding subordinated units to us and we will cancel such subordinated units and (iii) we will undertake to complete an approximately $77 million rights offering, the proceeds of which shall be used as follows: (a) first, to pay for any and all expenses relating to conducting the rights offering, (b) second, to redeem our Convertible Debentures for an amount equal to the principal amount of such Convertible Debentures plus any interest payable thereon, (c) third, to repurchase, on a pro rata basis, up to a maximum of $22 million of Preferred Units from Vitol and Charlesbank at a purchase price of $6.50 per unit plus any pro rata distribution for the quarter in which such units are repurchased and (d) thereafter, for general partnership purposes. Pursuant to the terms of the rights offering, we will distribute to our common unitholders 0.5412 rights for each outstanding common unit, with each whole right entitling the holder to acquire, for a subscription price of $6.50, a newly issued Preferred Unit.

Important additional information regarding the Partnership Agreement Amendment Proposal and the LTIP Proposal has been filed with the SEC, including a definitive proxy statement relating to the proposed transactions filed with the SEC on July 28, 2011.  INVESTORS AND SECURITY HOLDERS ARE ADVISED TO READ THE DEFINITIVE PROXY STATEMENT BECAUSE IT CONTAINS IMPORTANT INFORMATION ABOUT OUR PARTNERSHIP AND THE PROPOSED TRANSACTIONS.  Investors and security holders may obtain copies of the definitive proxy statement and other documents that we file with the SEC (when they are available) free of charge at the SEC’s web site at www.sec.gov. The definitive proxy statement and other relevant documents may also be obtained (when available) free of charge on our web site at www.bkep.com or by directing a request to Blueknight Energy Partners, L.P., Two Warren Place, 6120 South Yale Avenue, Suite 500, Tulsa, Oklahoma 74136, Attention: Investor Relations.

Our partnership, our General Partner and its directors, executive officers and other members of its management and employees may be deemed participants in the solicitation of proxies from the unitholders of our partnership in connection with the proposed transactions. Information regarding the special interests of persons who may be deemed to be such participants in the proposed transactions is included in the definitive proxy statement. Additional information regarding the directors and executive officers of our General Partner is also included in the 2010 Form 10-K, and subsequent statements of changes in beneficial ownership on file with the SEC. These documents are available free of charge at the SEC’s web site at www.sec.gov and from Investor Relations at Blueknight Energy Partners, L.P. as described above.

Nasdaq Relisting

Our common units were approved for listing on the NASDAQ Global Market and began trading on May 16, 2011 under the symbol “BKEP”.

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Distributions

We have not made a distribution to our common unitholders or subordinated unitholders since May 15, 2008 due, in part, to the events of default that existed under our former credit agreement, restrictions under such credit agreement, and the uncertainty of our future cash flows relating to SemCorp’s bankruptcy filings.  Our unitholders will be required to pay taxes on their share of our taxable income even though they did not receive a distribution for the quarters ended June 30, 2008 through March 31, 2011, and will not receive a distribution for the quarter ended June 30, 2011.  If the Partnership Agreement Amendment Proposal is approved, based on current estimates, management anticipates that it will recommend to our board of directors that we resume paying distributions on our common units beginning with the fourth quarter of 2011 (which distribution would be paid in the first quarter of 2012). Due to the anticipated increase in spending on maintenance capital expenditures as well as legal and professional fees related to the refinancing, management does not expect that it will recommend to our board of directors that we pay a distribution on our common units relating to the third quarter of 2011. The amount of distributions paid and the decision to make any distribution will be determined by our board of directors, which will have broad discretion to establish cash reserves for the proper conduct of our business and for future distributions to our unitholders. In addition, our cash distribution policy is subject to restrictions on distributions under our credit facility.  Our partnership agreement provides that, during the subordination period, which we are currently in, our common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.3125 per common unit per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units.  After giving effect to the nonpayment of distributions for the quarters ended June 30, 2008 through June 30, 2011, each common unit was entitled to an arrearage of $4.06, or total arrearages for all common units of $88.9 million based upon 21,890,224 common units outstanding as of August 3, 2011.  If the Partnership Agreement Amendment Proposal is approved, all arrearages will be eliminated.

On May 13, 2011, we paid a distribution of $0.24 per Preferred Unit, or a total distribution of $5.2 million on our Preferred Units for the portion of the quarter ended December 31, 2010 during which the Preferred Units were outstanding and for the quarter ended March 31, 2011.

On August 4, 2011, the Board approved a distribution of $0.14 per Preferred Unit, or a total distribution of $3.0 million based on 21,538,462 Preferred Units outstanding as of August 4, 2011.  We anticipate paying this distribution on the Preferred Units on August 12, 2011 to preferred unitholders of record as of August 8, 2011.

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  Results of Operations

The table below summarizes our financial results for the three and six months ended June 30, 2010 and 2011 (in thousands).  

	Three Months ended June 30,						Six Months Ended June 30,
	2010			2011			2010			2011
	(in thousands)
Service revenues:
Crude oil terminalling and storage revenues:
Third party	$	4,694		$	2,859		$	11,503		$	5,375
Related party		5,340			6,743			8,366			14,066
Total crude oil terminalling and storage		10,034			9,602			19,869			19,441
Crude oil pipeline services revenues:
Third party		2,972			5,040			5,907			8,894
Related party		223			1,166			256			2,181
Total crude oil pipeline services revenues		3,195			6,206			6,163			11,075
Crude oil trucking and producer field services revenues:
Third party		10,828			10,594			20,965			22,464
Related Party		60			2,512			72			3,743
Total crude oil trucking and producer field services revenues		10,888			13,106			21,037			26,207
Asphalt services revenues:
Third party		14,326			14,177			28,406			27,891
Related party		—			—			—			—
Total asphalt services		14,326			14,177			28,406			27,891
Total revenues		38,443			43,091			75,475			84,614
Operating expenses:
Crude oil terminalling and storage		1,813			2,402			3,934			4,148
Crude oil pipelines services		3,265			6,026			6,774			11,203
Crude oil trucking and field services		10,735			12,148			21,854			25,417
Asphalt services		8,344			8,919			17,438			17,341
Total operating expenses		24,157			29,495			50,000			58,109
General and administrative expenses		3,385			4,777			7,153			9,386
Operating income		10,901			8,819			18,322			17,119
Other (income) expense
Interest expense		13,549			9,112			25,972			18,164
Change in fair value of embedded derivative within convertible debt		—			3,431			—			(4,866	)
Change in fair value of rights offering contingency		—			1,544			—			6,386
Income tax expense		53			77			102			147
Net loss	$	(2,701	)	$	(5,345	)	$	(7,752	)	$	(2,712	)

Three Months Ended June 30, 2011 Compared to the Three Months Ended June 30, 2010

Service revenues.  Service revenues include revenues from crude oil terminalling and storage services, crude oil pipeline services, crude oil trucking and producer field services and asphalt services.  Service revenues, including reimbursement revenues for fuel and power, property tax, and insurance expenses related to the operations of our liquid asphalt facilities of $2.0 million and $1.9 million for the three months ended June 30, 2011 and 2010, respectively, were $43.1 million for the three months ended June 30, 2011, compared to $38.4 million for the three months ended June 30, 2010, an increase of $4.7 million, or 12%.  

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Crude oil terminalling and storage revenue was $9.6 million for the three months ended June 30, 2011 compared to $10.0 for the three months ended June 30, 2010.  We anticipate our crude oil terminalling and storage revenue for the remainder of 2011 will be consistent with the second quarter of 2011.

Crude oil pipeline services revenue increased by $3.0 million to $6.2 million for the three months ended June 30, 2011 compared to $3.2 million for the three months ended June 30, 2010.  Revenues from the Eagle North pipeline system, which was placed in service in placed in service in December 2010, account for $0.7 million of this increase.  We also earned approximately $1.4 million of revenue related to reimbursed pipeline expense projects.  The remaining increase in revenue is due to increased utilization of our assets, and during the second quarter of 2011 throughput reached effective capacity on segments of our Mid-Continent system.

Crude oil trucking and producer field services revenue increased by $2.2 million to $13.1 million for the three months ended June 30, 2011 compared to $10.9 million for the three months ended June 30, 2010. This increase is due to incremental revenues of $2.2 million attributed to the producer field services business we acquired in December of 2010.

Our asphalt services revenue, including reimbursement of fuel and power, property tax and insurance premiums, of $14.2 million for the three months ended June 30, 2011 was consistent with revenue of $14.3 million for the three months ended June 30, 2010.  We have entered into leases and storage agreements with third party customers relating to 44 of our 45 asphalt facilities and expect revenues associated with these assets to remain consistent for the remainder of 2011.

Operating expenses.   Operating expenses increased by $5.3 million, or 22% to $29.5 million for the three months ended June 30, 2011, compared to $24.2 million for the three months ended June 30, 2010.  Crude oil terminalling and storage operating expenses increased by $0.6 million to $2.4 million for the three months ended June 30, 2011, compared to $1.8 million for the three months ended June 30, 2010.  Our crude oil pipeline services operating expenses increased by $2.7 million to $6.0 million for the three months ended June 30, 2011, compared to $3.3 million for the three months ended June 30, 2010.  Our crude oil trucking and producer field services operating expenses increased by $1.4 million to $12.1 million for the three months ended June 30, 2011, compared to $10.7 million for the three months ended June 30, 2010.  Our asphalt operating expenses increased $0.6 million to $8.9 million for the three months ended June 30, 2011, compared to $8.3 million for the three months ended June 30, 2010.

Repair and maintenance expenses increased by $2.4 million to $4.4 million for the three months ended June 30, 2011.  Of this increase approximately $1.4 million is offset by revenue earned in connection with reimbursed pipeline expense projects reflected as revenue in our statement of operations.  Additional increases in repair and maintenance expense were due both to a tank inspection program that we implemented in the first quarter of 2011 in response to new regulation of the asphalt industry and to previously deferred maintenance of our crude oil pipeline systems.  Included in repair and maintenance expense for the three months ended June 30, 2011 is $0.5 million of expenses associated with leaks that occurred on our crude oil pipeline systems.

Salaries and wages increased by $1.3 million to $9.5 million for the three months ended June 30, 2011, compared to $8.2 million for the three months ended June 30, 2010, as we were in the process of transitioning away from services provided by SemCorp, establishing our operational management team and directly employing our own personnel throughout 2010 and the first six months of 2011.  This transition was completed in the second quarter of 2011.

Furthermore, fuel and utility expenses increased by $1.2 million to $5.0 million for the three months ended June 30, 2011 as compared to the second quarter of 2010.  Partially offsetting operating expenses is the recognition of $0.7 million in gains on the sale of assets during the three months ended June 30, 2011 in connection with the disposal and replacement of fully depreciated assets.

General and administrative expenses.  General and administrative expenses increased by $1.4 million, or 41%, to $4.8 million for the three months ended June 30, 2011, compared to $3.4 million for the three months ended June 30, 2010.  This increase is primarily attributable to an increase in compensation expense to $2.1 million for the three months ended June 30, 2011 compared to $1.0 million for the three months ended June 30, 2010 due to an increase in our headcount as we transitioned away from SemCorp and established our operational management team.  Additionally, legal, financial advisory and other professional expenses increased $0.3 million to $1.9 million for the three months ended June 30, 2011, compared to the three months ended June 30, 2010.  

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Interest expense.  Interest expense represents interest on borrowings under our credit facility as well as amortization of debt issuance costs and the debt discount related to our Convertible Debentures (as defined below).  Interest expense decreased by $4.4 million to $9.1 million for the three months ended June 30, 2011 compared to $13.5 million for the three months ended June 30, 2010.  Decreases in the weighted average interest rate of our credit facility and the weighted average debt outstanding due to the refinancing of our credit facility in October 2010 resulted in decreased interest expense of $10.9 million for the three months ended June 30, 2011 compared to the three months ended June 30, 2010.  Also, as a result of the refinancing, amortization of our debt issuance costs decreased by $0.8 million for the three months ended June 30, 2011 when compared to the three months ended June 30, 2010.  These decreases were partially offset by non-cash interest expense related to the Convertible Debentures, including the related debt discount, of $5.7 million for the three months ended June 30, 2011.  The three months ended June 30, 2010 also include $1.3 million of capitalized interest whereas we did not capitalize any interest in the three months ended June 30, 2011.

Other (income) expense.   Other expense for the three months ended June 30, 2011 included a $1.5 million increase in the fair value of the rights offering contingency and a $3.4 million increase in the fair value of the embedded derivative liability derived from the conversion option in the Convertible Debentures.

Six Months Ended June 30, 2011 Compared to the Six Months Ended June 30, 2010

Service revenues.  Service revenues, including reimbursement revenues for fuel and power, property tax, and insurance expenses related to the operations of our liquid asphalt facilities of $3.5 million and $3.7 million for the six months ended June 30, 2011 and 2010, respectively, were $84.6 million for the six months ended June 30, 2011, compared to $75.5 million for the six months ended June 30, 2010, an increase of $9.1 million, or 12%.  

Crude oil terminalling and storage revenue decreased by $0.5 million to $19.4 million for the six months ended June 30, 2011, compared to $19.9 million for the six months ended June 30, 2010.   Our crude oil terminalling and storage assets are fully contracted, and we expect crude oil terminalling and storage revenue to remain consistent for the remainder of 2011.

 Crude oil pipeline services revenue increased by $4.9 million to $11.1 million for the six months ended June 30, 2011 compared to $6.2 million for the six months ended June 30, 2010.  Revenues from the Eagle North pipeline system, which was placed in service in December 2010, account for $1.5 million of this increase.  We also earned $1.4 million in revenue related to reimbursed pipeline expense projects.  The remaining increase in revenue is due to increased utilization of our assets, with throughput reaching effective capacity on segments of our Mid-Continent system during the second quarter of 2011.

Crude oil trucking and producer field services revenue increased by $5.2 million to $26.2 million for the six months ended June 30, 2011 compared to $21.0 million for the six months ended June 30, 2010. The majority of this increase is due to incremental revenues of $4.5 million attributed to the producer field services business we acquired in December of 2010.

Our asphalt services revenue decreased by $0.5 million to $27.9 million for the six months ended June 30, 2011, compared to $28.4 million for the six months ended June 30, 2010.  This revenue is inclusive of fuel surcharge revenues related to fuel and power consumed to operate our asphalt facilities of $3.5 million and $3.7 million for the six months ended June 30, 2011 and 2010, respectively.  We have entered into leases and storage agreements with third party customers relating to 44 of our 45 asphalt facilities and expect revenues to be consistent for the remainder of 2011.

Operating expenses.  Operating expenses increased by $8.1 million, or 16%, to $58.1 million for the six months ended June 30, 2011, compared to $50.0 million for the six months ended June 30, 2010.  Crude oil terminalling and storage operating expenses increased by $0.2 million to $4.1 million for the six months ended June 30, 2011, compared to $3.9 million for the six months ended June 30, 2010.  Our crude oil pipeline services operating expenses increased by $4.4 million to $11.2 million for the six months ended June 30, 2011 compared to $6.8 million for the six months ended June 30, 2010.  Our crude oil trucking and producer field services operating expenses increased by $3.5 million to $25.4 million for the six months ended June 30, 2011, compared to $21.9 million for the six months ended June 30, 2010.  Our asphalt operating expenses were consistent at $17.3 million for the six months ended June 30, 2011 compared to $17.4 million for the six months ended June 30, 2010.

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The increase in operating expenses was primarily driven by increases in salaries and wages, maintenance and repair and fuel expenses.  

Compensation expense increased by $2.9 million to $19.7 million for the six months ended June 30, 2011 as compared to $16.8 million for the six months ended June 30, 2010.  This increase is a result of directly employing our own personnel as we transitioned away from the services provided by SemCorp under a shared services agreement.  We completed this transition in the second quarter of 2011. 

Repair and maintenance expenses increased by $3.7 million to $7.7 million for the six months ended June 30, 2011, as compared to the six months ended June 30, 2010 due both to a tank inspection program that we implemented in the first quarter of 2011 in response to new regulation of the asphalt industry and to previously deferred maintenance of our crude oil pipeline systems.  Approximately $1.4 million of the repair and maintenance expense in the six months ended June 30, 2011 is offset by reimbursed pipeline expense projects reflected as revenue in our statement of operations.  Included in the repair and maintenance expense for the six months ended June 30, 2011 is $1.5 million of expenses associated with leaks that occurred on our pipeline systems.

In addition, fuel expense increased $1.8 million to $5.5 million for the six months ended June 30, 2011 compared to the six months ended June 30, 2010 due primarily to increased prices.  Operating expenses for the six months ended June 30, 2010 include a $0.8 million impairment charge related to an asphalt facility located in Morehead City, North Carolina that we sold in April of 2010.  Partially offsetting operating expenses is the recognition of $0.7 million in gains on the sale of assets during the six months ended June 30, 2011 in connection with the disposal and replacement of depreciated assets as compared to $0.1 million during the six months ended June 30, 2010.

General and administrative expenses.  General and administrative expenses increased by $2.2 million, or 31%, to $9.4 million for the six months ended June 30, 2011 compared to $7.2 million for the six months ended June 30, 2010. This increase is primarily attributable to an increase in compensation expense of $2.4 million to $4.6 million for the six months ended June 30, 2011 compared to $2.2 million for the six months ended June 30, 2010 due to an increase in our headcount as we transitioned away from SemCorp and established our operational management team.

Interest expense.  Interest expense represents interest on borrowings under our credit facility as well as amortization of debt issuance costs and the debt discount related to our Convertible Debentures.  Total interest expense of $18.2 million for the six months ended June 30, 2011 decreased by $7.8 million compared to total interest expense of $26.0 million for the six months ended June 30, 2010.  Decreases in the weighted average interest rate of our credit facility and the weighted average debt outstanding due to the refinancing of our credit facility in October 2010 resulted in decreased interest expense of $19.4 million for the six months ended June 30, 2011 compared to the six months ended June 30, 2010.  Also, in relation to the refinancing, amortization of our debt issuance costs decreased by $1.4 million for the six months ended June 30, 2011 compared to the six months ended June 30, 2010.  These decreases were partially offset by non-cash interest expense related to the Convertible Debentures, including the related debt discount, of $11.3 million for the six months ended June 30, 2011.  The six months ended June 30, 2010 also included $1.3 million of capitalized interest whereas we did not capitalize any interest in the six months ended June 30, 2011.

Effects of Inflation

In recent years, inflation has been modest and has not had a material impact upon the results of our operations.

Off Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

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Liquidity and Capital Resources

Cash Flows and Capital Expenditures

The following table summarizes our sources and uses of cash for the six months ended June 30, 2010 and 2011:

	Six Months Ended June 30,
	2010			2011
	(in millions)
Net cash provided by operating activities	$	8.6		$	15.8
Net cash used in investing activities		(4.6	)		(8.7	)
Net cash used in financing activities		(9.4	)		(6.2	)

Operating Activities.  Net cash provided by operating activities was $15.8 million for the six months ended June 30, 2011, as compared to the $8.6 million for the six months ended June 30, 2010.  The increase in net cash provided by operating activities is primarily due to a decrease in net loss to $2.7 million for the six months ended June 30, 2011 from $7.8 million for the six months ended June 30, 2010.  This was primarily the result of lower interest expense as a result of the refinancing of our debt in the fourth quarter of 2010.

Investing Activities.  Net cash used in investing activities was $8.7 million for the six months ended June 30, 2011, as compared to the $4.6 million for the six months ended June 30, 2010.  The change in cash used in investing activities is primarily due to an increase in capital expenditures.

Financing Activities.  Net cash used in financing activities was $6.2 million for the six months ended June 30, 2011, as compared to $9.4 million for the six months ended June 30, 2010.  Net cash used in financing activities for the six months ended June 30, 2011 is primarily comprised of $5.3 million of distributions to holders of our Series A preferred units.  

Our Liquidity and Capital Resources

Cash flow from operations and our credit facility are our primary sources of liquidity. At June 30, 2011, we had approximately $54.2 million of availability under our revolving credit facility.  At June 30, 2011, we had a working capital deficit of $90.0 million.  This is primarily a function of both the $63.2 million of Convertible Debentures, including the fair value of an embedded derivative, that will convert to equity in December of 2011 and our approach to cash management.  On April 5, 2011, our revolving credit facility was increased from $75.0 million to $95.0 million. As of August 2, 2011, we have aggregate unused credit availability under our revolving credit facility of approximately $58.2 million and cash on hand of approximately $9.5 million.  

Capital Requirements. Our capital requirements consist of the following:

• maintenance capital expenditures, which are capital expenditures made to maintain the existing integrity and operating capacity of our assets and related cash flows further extending the useful lives of the assets; and

• expansion capital expenditures, which are capital expenditures made to expand or to replace partially or fully depreciated assets or to expand the operating capacity or revenue of existing or new assets, whether through construction, acquisition, or modification.

Expansion capital expenditures for organic growth projects totaled $4.3 million in the six months ended June 30, 2011, compared to $2.0 million in the six months ended June 30, 2010.  We expect expansion capital expenditures for organic growth projects to be approximately $6.0 million to $8.0 million in 2011.  Maintenance capital expenditures totaled $5.0 million in the six months ended June 30, 2011 compared to $4.7 million in the three months ended June 30, 2010.  We expect maintenance capital expenditures to be approximately $12.0 million to $14.0 million in 2011.

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Our Ability to Grow Depends on Our Ability to Access External Expansion Capital . Our partnership agreement provides that we distribute all of our available cash to our unitholders. Available cash is reduced by cash reserves established by our General Partner to provide for the proper conduct of our business (including for future capital expenditures) and to comply with the provisions of our credit facility.  We expect that substantially all of our cash generated from operations will be used to reduce our debt or pay distributions.  Accordingly, we may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations because we distribute all of our available cash.

Description of Credit Facility.  On October 25, 2010, we entered into a new credit agreement, which we refer to as our credit agreement.  Our credit agreement includes a $200.0 million term loan facility and a revolving loan facility.  On April 5, 2011, the revolving loan facility was increased from $75.0 million to $95.0 million.  Vitol is a lender under our credit agreement and has committed to loan us $15.0 million pursuant to such agreement.  The entire amount of the term loan and approximately $43.9 million of the revolver was drawn on October 25, 2010 in connection with repaying all existing indebtedness under our prior credit agreement.  The proceeds of loans made under our credit agreement may be used for working capital and other general corporate purposes.

The credit agreement is guaranteed by all of our existing subsidiaries. Obligations under our credit agreement are secured by first priority liens on substantially all of our assets and those of the guarantors, including all material pipeline, gathering and processing assets, all material storage tanks and asphalt facilities, all material working capital assets and a pledge of all of our equity interests in our subsidiaries.

The credit agreement includes procedures for additional financial institutions to become revolving lenders, or for any existing lender to increase its revolving commitment thereunder, subject to an aggregate maximum of $200.0 million for all revolving loan commitments under our credit agreement.

The credit agreement will mature on October 25, 2014, and all amounts outstanding under our credit agreement shall become due and payable on such date.  We may prepay all loans under our credit agreement at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements. The credit agreement requires mandatory prepayments of amounts outstanding thereunder with the net proceeds of certain asset sales, casualty events and debt incurrences, and, in certain circumstances, with a portion of our excess cash flow (as defined in the credit agreement).  These mandatory prepayments will be applied to the term loan under our credit agreement until it is repaid in full, then applied to reduce commitments under the revolving loan facility.

Until May 15, 2011, borrowings under our credit agreement bore interest, at our option, at either (i) the ABR (the highest of the administrative agent’s prime rate, the federal funds rate plus 0.5%, or the one-month eurodollar rate (as defined in the credit agreement) plus 1%), plus an applicable margin of 3.25%, or (ii) the eurodollar rate plus an applicable margin of 4.25%.  After May 15, 2011, the applicable margin for loans accruing interest based on the ABR ranges from 3.0% to 3.5%, and the applicable margin for loans accruing interest based on the eurodollar rate ranges from 4.0% to 4.5%, in each case depending on our consolidated total leverage ratio (as defined in the credit agreement).  We pay a per annum fee on all letters of credit issued under the credit agreement, which fee equals the applicable margin for loans accruing interest based on the eurodollar rate, and we pay a commitment fee of 0.50% per annum on the unused availability under the credit agreement.  The credit agreement does not have a floor for the ABR or the eurodollar rate.  In connection with entering into our credit agreement, we paid certain upfront fees to the lenders thereunder, and we paid certain arrangement and other fees to the arranger and administrative agent of our credit agreement.  Vitol received its pro rata portion of such fees as a lender under our credit agreement. During the three months ended June 30, 2011, our weighted average interest rate under the credit agreement was 4.5% and our total weighted average interest rate, including interest under our convertible debentures and the throughput capacity agreement with Vitol related to our Eagle North pipeline system was 12.6%, resulting in interest expense of approximately $9.1 million.

The credit agreement includes financial covenants that will be tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter (except for the consolidated interest coverage ratio, which builds to a four-quarter test).

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The maximum permitted consolidated total leverage ratio is as follows:

• 5.00 to 1.00 for the fiscal quarters ending December 31, 2010, March 31, 2011 and June 30, 2011;

• 4.75 to 1.00 for the fiscal quarters ending September 30, 2011 and December 31, 2011; and

• 4.50 to 1.00 for the fiscal quarter ending March 31, 2012 and each fiscal quarter thereafter.

The minimum permitted consolidated interest coverage ratio (as defined in the credit agreement) is as follows:

• 2.50 to 1.00 for the fiscal quarters ending December 31, 2010, March 31, 2011 and June 30, 2011; and

• 3.00 to 1.00 for the fiscal quarter ending September 30, 2011 and each fiscal quarter thereafter.

 In addition, the credit agreement contains various covenants that, among other restrictions, limit our ability to:

• create, issue, incur or assume indebtedness;

• create, incur or assume liens;

• engage in mergers or acquisitions;

• sell, transfer, assign or convey assets;

• repurchase our partnership's equity, make distributions to unitholder and make certain other restricted payments;

• make investments;

• modify the terms of the Convertible Debentures and certain other indebtedness, or prepay certain indebtedness;

• engage in transactions with affiliates;

• enter into certain hedging contracts;

• enter into certain burdensome agreements;

• change the nature of our business;

• enter into operating leases; and

• make certain amendments to our partnership agreement.

At June 30, 2011, our leverage ratio was 4.27 to 1.00 and the interest coverage ratio was 4.64 to 1.00.  We were in compliance with all covenants of our credit agreement as of June 30, 2011.

The credit agreement permits us to make quarterly distributions of available cash (as defined in our partnership agreement) to unitholders so long as:  (i) no default or event of default exists under our credit agreement, (ii) we have, on a pro forma basis after giving effect to such distribution, at least $10.0 million of availability under the revolving loan facility, and (iii) our consolidated total leverage ratio, on a pro forma basis, would not be greater than (x) 4.50 to 1.00 for any fiscal quarter on or prior to the fiscal quarter ending June 30, 2011, (y) 4.25 to 1.00 for the fiscal quarters ending September 30, 2011 and December 31, 2011, or (z) 4.00 to 1.00 for any fiscal quarter ending on or after March 31, 2012.  We are currently allowed to make distributions to our unitholders in accordance with these covenants; however, we will only make distributions to the extent we have sufficient cash from operations after establishment of cash reserves as determined by our general partner in accordance with our cash distribution policy, including the establishment of any reserves for the proper conduct of our business.

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Each of the following is an event of default under the credit agreement:

• failure to pay any principal, interest, fees, expenses or other amounts when due;

• failure to meet the quarterly financial covenants;

• failure to observe any other agreement, obligation or covenant in the credit agreement or any related loan document, subject to cure periods for certain failures;

• the failure of any representation or warranty to be materially true and correct when made;

• our, or any of our subsidiaries', default under other indebtedness that exceeds a threshold amount;

• judgments against us or any of our subsidiaries, in excess of a threshold amount;

• certain ERISA events involving us or any of our subsidiaries, in excess of a threshold amount;

• bankruptcy or other insolvency events involving us or any of our subsidiaries; and

• a change in control (as defined in the credit agreement).

If an event of default relating to bankruptcy or other insolvency events occurs, all indebtedness our credit agreement will immediately become due and payable.  If any other event of default exists under our credit agreement, the lenders may accelerate the maturity of the obligations outstanding under our credit agreement and exercise other rights and remedies.  In addition, if any event of default exists under our credit agreement, the lenders may commence foreclosure or other actions against the collateral.

If any default occurs under the credit agreement, or if we are unable to make any of the representations and warranties in the credit agreement, we will be unable to borrow funds or have letters of credit issued under the credit agreement.

It will constitute a change of control under our credit agreement if either Vitol or Charlesbank ceases to own, directly or indirectly, exactly 50% of the membership interests of our general partner or if our general partner ceases to be controlled by both Vitol and Charlesbank.

Convertible Debentures.   In connection with the Global Transaction Agreement, we issued and sold the Convertible Debentures to Vitol and Charlesbank for $25 million each, resulting in gross proceeds to us of $50 million. Our obligations under the Convertible Debentures are subordinate to our obligations under our credit agreement. The Convertible Debentures bear interest at 10% until October 25, 2011. After such time, the Convertible Debentures will bear interest at 12%. Interest can only be paid in cash with the proceeds from an equity offering. Each Convertible Debenture is redeemable in whole or in part by us at any time prior to December 31, 2011 at a price equal to $25 million plus any accrued and unpaid interest, but our credit agreement provides that any such redemption may only be made with the proceeds from an equity offering. If not otherwise redeemed, the Convertible Debentures shall mature on December 31, 2011 and, on such date, all outstanding principal and any accrued and unpaid interest shall automatically convert into preferred units. The number of preferred units issuable on conversion of the Convertible Debentures will be an amount equal to (i) the sum of the outstanding principal and any accrued and unpaid interest being converted, divided by (ii) 6.50.

Upon the occurrence and during the continuation of an event of default, (i) each Convertible Debenture will bear interest at the lesser of 14% or the maximum interest rate the holder is permitted to charge under applicable law, (ii) the holder may declare the principal amount of such Convertible Debenture due and payable, (iii) the holder shall have the right to convert such Convertible Debenture to Preferred Units in accordance with the calculation in the preceding paragraph and (iv) the holder may exercise all of its rights and remedies under applicable law. Such events of default include, among others, the failure to make payments when due, failure to deliver a certificate evidencing the preferred units upon conversion of such Convertible Debenture by the third business day after we receive notice of such conversion, failure to make a payment in excess of $10 million for our other indebtedness and noncompliance with covenants contained in such Convertible Debentures. The Convertible Debentures are subordinate to all indebtedness of our partnership under our credit agreement.

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Contractual Obligations. A summary of our contractual cash obligations over the next several fiscal years, as of June 30, 2011, is as follows:

	Payments Due by Period
Contractual Obligations	Total		Less than 1 year		1-3 years		4-5 years		More than 5 years
	(in millions)
Debt obligations (1)	$	276.3	$	10.9	$	21.9	$	243.5	$	—
Convertible Debentures (2)		69.3		69.3		—		—		—
Operating lease obligations		13.1		4.7		5.4		2.2		0.8
Related party Throughput Capacity Agreement (3)		6.2		2.1		3.7		0.4		—
Non-compete agreement (4)		0.2		0.1		0.1		—		—

_______________

(1)	Represents required future principal repayments of borrowings of $240.0 million and variable rate interest payments of $36.3 million.  At June 30, 2011, our borrowings had an interest rate of approximately 4.4%. This interest rate was used to calculate future interest payments.  All amounts outstanding under the credit facility mature in October 2014.
(2)	Represents $40.5 million in outstanding convertible debentures, $6.1 million of accrued and unpaid interest, and the estimated fair value of the embedded derivative of $22.7 million as of June 30, 2011.  The convertible debentures will mature on December 31, 2011 and, on such date, all outstanding principal and any accrued and unpaid interest will automatically convert into preferred units.
(3)	Represents required future repayments of the Vitol prepaid fee related to the throughput capacity agreement for our Eagle North pipeline system of $5.1 million and interest of $1.1 million.  This agreement matures at December 31, 2014.
(4)	Represents required future payments under a non-compete agreement related to our acquisition of certain field services assets.

Recent Accounting Pronouncements

For information regarding recent accounting developments that may affect our future financial statements, see Note 15 of the Notes to Unaudited Consolidated Financial Statements included in Part I, Item I of this quarterly support.

 Item 3.                         Quantitative and Qualitative Disclosures about Market Risk

We are exposed to market risk due to variable interest rates under our credit facility.

As of August 2, 2011 we had $236.8 million outstanding under our credit facility that was subject to a variable interest rate.  Until May 15, 2011, borrowings under our credit agreement bore interest, at our option, at either (i) the ABR (the highest of the administrative agent’s prime rate, the federal funds rate plus 0.5%, or the one-month eurodollar rate (as defined in the credit agreement) plus 1%), plus an applicable margin of 3.25%, or (ii) the eurodollar rate plus an applicable margin of 4.25%.  After May 15, 2011, the applicable margin for loans accruing interest based on the ABR ranges from 3.0% to 3.5%, and the applicable margin for loans accruing interest based on the eurodollar rate ranges from 4.0% to 4.5%, in each case depending on our consolidated total leverage ratio (as defined in the credit agreement).  

During the three months ended June 30, 2011, the weighted average interest rate under the credit agreement incurred by us was 4.5% and the total weighted average interest rate, including interest associated with the Convertible Debentures and the throughput capacity agreement with Vitol related to our Eagle North pipeline system, was 12.6% resulting in interest expense of approximately $9.1 million.

Changes in economic conditions could result in higher interest rates, thereby increasing our interest expense and reducing our funds available for capital investment, operations or distributions to our unitholders. Additionally, if domestic interest rates continue to increase, the interest rates on any of our future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Based on borrowings as of June 30, 2011 and the terms of our credit agreement, an increase or decrease of 100 basis points in the interest rate will result in increased or decreased annual interest expense of approximately $2.4 million.

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Item 4.                          Controls and Procedures

Evaluation of disclosure controls and procedures.  Our General Partner’s management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, evaluated as of the end of the period covered by this report, the effectiveness of our disclosure controls and procedures as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of our General Partner concluded that our disclosure controls and procedures, as of June 30, 2011, were effective.

Changes in internal control over financial reporting.  There were no changes in our internal control over financial reporting that occurred during the three months ended June 30, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II.                       OTHER INFORMATION

Item 1.                          Legal Proceedings

For a discussion of certain litigation and similar proceedings, please refer to Note 13, “Commitments and Contingencies,” of the Notes to Unaudited Consolidated Financial Statements, which is incorporated by reference herein.

Item 1A.                      Risk Factors

The risk factor set forth in “Part II, Item 1A. Risk Factors” in our Quarterly Report on Form 10-Q for the period ending March 31, 2011, which updated the corresponding risk factor in “Part I, Item 1A. Risk Factors” in our 2010 Form 10-K, regarding the relisting of our common units on the NASDAQ Global Market, is no longer applicable.  Our common units were relisted on the NASDAQ Global Market effective May 16, 2011.

Except as disclosed above, there has been no material changes in the risk factors set forth in “Part I, Item 1A. Risk Factors” in our 2010 Form 10-K.

Item 6.                          Exhibits

The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report and is incorporated herein by reference.

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SIGNATURES

Pursuant to the requirements 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.

	BLUEKNIGHT ENERGY PARTNERS, L.P.
	By:	Blueknight Energy Partners, G.P., L.L.C
		its General Partner
Date: August 5, 2011	By:	/s/ Alex G. Stallings
		Alex G. Stallings
		Chief Financial Officer and Secretary
Date: August 5, 2011	By:	/s/ James R. Griffin
		James R. Griffin
		Chief Accounting Officer

INDEX TO EXHIBITS

Exhibit Number	Exhibit Name
3.1	Amended and Restated Certificate of Limited Partnership of the Partnership, dated November 19, 2009 but effective as of December 1, 2009 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed November 25, 2009, and incorporated herein by reference).
3.2	Third Amended and Restated Agreement of Limited Partnership of the Partnership, dated October 25, 2010 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed October 25, 2010, and incorporated herein by reference).
3.3	Amended and Restated Certificate of Formation of the General Partner, dated November 20, 2009 but effective as of December 1, 2009 (filed as Exhibit 3.2 to the Partnership’s Current Report on Form 8-K, filed November 25, 2009, and incorporated herein by reference).
3.4	Second Amended and Restated Limited Liability Company Agreement of the General Partner, dated December 1, 2009 (filed as Exhibit 3.2 to the Partnership’s Current Report on Form 8-K, filed December 7, 2009, and incorporated herein by reference).
4.1	Specimen Unit Certificate (included in Exhibit 3.2).
10.1	First Amendment to Credit Agreement, dated as of April 1, 2011, by and among Blueknight Energy Partners, L.P., JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed April 5, 2011, and incorporated herein by reference).
10.2	Joinder Agreement, dated as of April 5, 2011, by and among Blueknight Energy Partners, L.P., JPMorgan Chase Bank, N.A., as administrative agent, and Cooperatieve Centrale Raiffeisen-Boerenleenbank B.A. “Rabobank Nederland”, New York Branch (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed April 5, 2011, and incorporated herein by reference).
10.3	Stipulation of Settlement, dated May 3, 2011 (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed May 6, 2011, and incorporated herein by reference).
10.4	Order Preliminarily Approving Settlement, U.S. District Court for the Northern District of Oklahoma, dated June 9, 2011 (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed June 13, 2011, and incorporated herein by reference).
10.5	First Amendment to Global Transaction Agreement, dated May 12, 2011, by and among Blueknight Energy Partners, L.P., Blueknight Energy Partners G.P., L.L.C., Blueknight Energy Holding, Inc. and CB-Blueknight, LLC (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed May 12, 2011, and incorporated herein by reference).
31.1*	Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certifications of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”

____________________

* Filed herewith.