Blueknight Energy Partners 10Q 2011 Q0 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 September 30, 2010

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 o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the 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 November 5, 2010, there were 21,538,462 preferred units, 21,727,724 common units and 12,570,504 subordinated units outstanding.

TABLE OF CONTENTS
					Page

PART I			FINANCIAL INFOMRATION		1
		Item 1.	Unaudited Financial Statements.		1
				Consolidated Balance Sheets as of December 31, 2009 and September 30, 2010	1
				Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2009 and 2010	2
				Consolidated Statements of Changes in Partners’ Capital (Deficit) for the Nine Months Ended September 30, 2010	3
				Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2009 and 2010	4
				Notes to Unaudited Consolidated Financial Statements	5
		Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations.		26
		Item 3.	Quantitative and Qualitative Disclosure about Market Risk.		43
		Item 4.	Controls and Procedures.		43

PART II			OTHER INFORMATION		44
	Item 1.		Legal Proceedings.		44
	Item 1A.		Risk Factors.		47
	Item 6.		Exhibits.		47

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, 2009			As of September 30, 2010
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	5,548		$	2,069
Accounts receivable, net of allowance for doubtful accounts of $429 for both dates		10,549			10,411
Receivables from related parties, net of allowance for doubtful accounts of $0 for both dates		1,253			1,123
Prepaid insurance		3,474			1,423
Other current assets		2,292			1,216
Total current assets		23,116			16,242
Property, plant and equipment, net of accumulated depreciation of $99,948 and $114,591 at December 31, 2009 and September 30, 2010, respectively		274,492			267,428
Goodwill		6,340			6,340
Debt issuance costs, net		6,384			3,863
Other assets, net		369			2,083
Total assets	$	310,701		$	295,956
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
Current liabilities:
Accounts payable	$	7,061		$	6,081
Payables to related parties		—			809
Accrued interest payable		2,242			8,619
Accrued interest payable to related parties		—			61
Accrued property taxes payable		3,175			2,605
Unearned revenue		5,205			2,556
Unearned revenue from related parties		1,185			2,140
Accrued payroll		3,425			4,013
Other accrued liabilities		2,339			3,404
Capital lease obligations		248			—
Current portion of long-term debt		9,000			413,729
Total current liabilities		33,880			444,017
Long-term payable to related parties		—			4,691
Long-term debt		419,000			—
Commitments and contingencies (Notes 4, 10 and 13)
Partners’ capital (deficit):
Common unitholders (21,727,724 units issued and outstanding for both dates)		471,701			465,144
Subordinated unitholders (12,570,504 units issued and outstanding for both dates)		(290,257	)		(294,064	)
General partner interest (2.0% interest with 690,725 general partner units outstanding for both dates)		(323,623	)		(323,832	)
Total partners’ capital (deficit)		(142,179	)		(152,752	)
Total liabilities and partners’ capital (deficit)	$	310,701		$	295,956

See accompanying notes to unaudited consolidated financial statements.

BLUEKNIGHT ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2010			2009			2010
	(unaudited)
Service revenue:
Third party revenue	$	39,021		$	31,113		$	93,625		$	97,895
Related party revenue		998			6,943			26,077			15,637
Total revenue		40,019			38,056			119,702			113,532
Expenses:
Operating		24,479			23,441			71,425			73,442
General and administrative		7,106			3,883			22,939			11,037
Total expenses		31,585			27,324			94,364			84,479
Gain on settlement transaction		—			—			2,585			—
Operating income		8,434			10,732			27,923			29,053
Other expenses:
Interest expense		12,749			13,530			38,626			39,502
Loss before income taxes		(4,315	)		(2,798	)		(10,703	)		(10,449	)
Provision for income taxes		51			50			159			151
Net loss	$	(4,366	)	$	(2,848	)	$	(10,862	)	$	(10,600	)
Allocation of net loss for calculation of earnings per unit:
General partner interest in net loss	$	(87	)	$	(57	)	$	(216	)	$	(209	)
Loss available to limited partners	$	(4,279	)	$	(2,791	)	$	(10,646	)	$	(10,391	)

Basic and diluted net loss per common unit	$	(0.12	)	$	(0.08	)	$	(0.30	)	$	(0.30	)
Basic and diluted net loss per subordinated unit	$	(0.12	)	$	(0.08	)	$	(0.30	)	$	(0.30	)

Weighted average common units outstanding - basic and diluted		21,577			21,728			21,557			21,728
Weighted average subordinated units outstanding - basic and diluted		12,571			12,571			12,571			12,571

See accompanying notes to unaudited consolidated financial statements.

BLUEKNIGHT ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL (DEFICIT)

(in thousands)

	Common Unitholders			Subordinated Unitholders			General Partner Interest			Total Partners’ Capital (Deficit)
	(unaudited)
Balance, December 31, 2009	$	471,701		$	(290,257	)	$	(323,623	)	$	(142,179	)
Net loss		(6,574	)		(3,817	)		(209	)		(10,600	)
Equity-based incentive compensation		17			10			—			27
Balance, September 30, 2010	$	465,144		$	(294,064	)	$	(323,832	)	$	(152,752	)

See accompanying notes to unaudited consolidated financial statements.

BLUEKNIGHT ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Nine Months Ended September 30,
	2009			2010
	(unaudited)
Cash flows from operating activities:
Net loss	$	(10,862	)	$	(10,600	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Provision for uncollectible receivables from third parties		(125	)		—
Depreciation and amortization		17,055			16,228
Amortization of debt issuance costs		5,289			3,640
Asset impairment charge		—			779
Gain on sale of assets		(54	)		(103	)
Gain on settlement transaction		(2,585	)		—
Equity-based incentive compensation		(24	)		27

Changes in assets and liabilities:
Decrease (increase) in accounts receivable		(3,439	)		138
Decrease in receivables from related parties		12,996			130
Decrease (increase) in prepaid insurance		(1,205	)		1,020
Decrease in other current assets		120			1,076
Increase in other non-current assets		(320	)		(276	)
Increase (decrease) in accounts payable		1,842			(1,169	)
Decrease in payables to related parties		(15,197	)		—
Increase in accrued interest payable		6,112			6,377
Increase in accrued interest payable to related parties		—			61
Increase (decrease) in accrued property taxes		1,286			(570	)
Decrease in interest rate swap settlements payable		(1,376	)		—
Increase (decrease) in unearned revenue		2,123			(2,649	)
Increase in unearned revenue from related parties		—			955
Increase in accrued payroll		4,168			588
Increase in other accrued liabilities		987			832
Net cash provided by operating activities		16,791			16,484
Cash flows from investing activities:
Capital expenditures		(3,513	)		(11,279	)
Proceeds from sale of assets		217			1,628
Net cash used in investing activities		(3,296	)		(9,651	)
Cash flows from financing activities:
Debt issuance costs		(10,332	)		(1,119	)
Payment on insurance agreement		—			(174	)
Payments on capital lease obligations		(709	)		(248	)
Borrowings under credit facility		24,700			40,700
Payments under credit facility		(50,301	)		(54,971	)
Borrowings from related parties (see Note 7)		—			5,500
Net cash used in financing activities		(36,642	)		(10,312	)
Net decrease in cash and cash equivalents		(23,147	)		(3,479	)
Cash and cash equivalents at beginning of period		28,785			5,548
Cash and cash equivalents at end of period	$	5,638		$	2,069
Supplemental disclosure of cash flow information:
Increase (decrease) in accounts payable related to purchases of property, plant and equipment	$	315		$	189
Increase in accrued liabilities related to insurance premium financing agreement	$	—		$	407
Non-cash addition to property, plant and equipment related to settlement (see 2009 Form 10-K)	$	(9,536	)	$	—

See accompanying notes to unaudited consolidated financial statements.

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-two states. The Partnership provides integrated terminalling, storage, 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 three operating segments: (i) crude oil terminalling and storage services, (ii) crude oil gathering and transportation services and (iii) asphalt services. 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 accompanying financial statements have been prepared assuming that the Partnership will continue as a going concern. In October of 2010, the Partnership refinanced its outstanding debt and concurrently raised capital through the issuance of additional partnership units (see Note 15). This resulted in decreased leverage, reduced interest rates on outstanding borrowings and increased liquidity. Based on these events and the Partnership’s current assessment of ongoing litigation (see Note 13), the Partnership believes there is no longer substantial doubt about the Partnership’s ability to continue as a going concern for the next twelve months as previously disclosed in the Partnership’s 2009 Form 10-K.

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 nine months ended September 30, 2009 and 2010, the consolidated statement of changes in partners’ capital (deficit) for the nine months ended September 30, 2010, the statement of cash flows for the nine months ended September 30, 2009 and 2010, and the consolidated balance sheet as of September 30, 2010 are unaudited. In the opinion of management, the unaudited interim 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 stat ements and notes thereto included in the 2009 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.	PROPERTY, PLANT AND EQUIPMENT

	Estimated Useful Lives (Years)		December 31, 2009			September 30, 2010
			(dollars in thousands)
Land			$	15,430		$	15,430
Land improvements		10-20		5,431			5,210
Pipelines and facilities		5-31		98,327			100,991
Storage and terminal facilities		10-35		165,392			166,015
Transportation equipment		3-10		22,781			21,836
Office property and equipment and other		3-31		20,601			20,306
Pipeline linefill and tank bottoms				7,763			7,763
Construction-in-progress				38,715			44,468
Property, plant and equipment, gross				374,440			382,019
Accumulated depreciation				(99,948	)		(114,591	)
Property, plant and equipment, net			$	274,492		$	267,428

Property, plant and equipment includes transportation equipment under capital leases of $0.3 million and zero, net of accumulated depreciation of $5.9 million and $5.9 million at December 31, 2009 and September 30, 2010, respectively. At September 30, 2010, $43.5 million of construction-in-progress consists of a 130-mile, 8-inch pipeline that was acquired by the Partnership on May 12, 2008. Management currently intends to put the asset into service in the fourth quarter of 2010.

Depreciation expense for the nine months ended September 30, 2009 and 2010 was $16.8 million and $16.2 million, respectively.

DEBT

The following discussion of the Partnership’s debt is as of September 30, 2010, and the credit agreement in effect at such time is herein referred to as the “Prior Credit Agreement.” In October of 2010, the Partnership entered into a new credit agreement and repaid all debt then outstanding under the Prior Credit Agreement with proceeds from the combination of the new credit facility, convertible debentures, and the issuance of preferred equity (see Note 15). The Partnership does not expect a significant impact to its financial condition, results of operations, or its cash flows from the accounting for the extinguishment of its prior credit agreement.

The maturity date of the Partnership’s Prior Credit Agreement was June 30, 2011, and all outstanding borrowings under the Prior Credit Agreement are classified as current obligations as of September 30, 2010. As of September 30, 2010, the Partnership’s Prior Credit Agreement was comprised of a $388.6 million term loan facility and a $39.6 million revolving credit facility. As of September 30, 2010, $388.6 million was outstanding under the prior term loan facility and $25.1 million was outstanding under the prior revolving credit facility. In addition, as of September 30, 2010, the Partnership had outstanding letters of credit issued under the Prior Credit Agreement of $1.0 million. As of September 30, 2010, the Partnership had an aggregate unused credit availability under its p rior revolving credit facility of approximately $13.5 million.

In addition, the Partnership experienced increased interest expense and other costs due to the events of default that existed under its Prior Credit Agreement and the entering into amendments thereto. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in the 2009 Form 10-K for a discussion of these agreements and the associated expenses.

On March 29, 2010, the Partnership entered into a Waiver and Amendment to Credit Agreement (the “March 2010 Amendment”) with its lenders who are a party thereto. The March 2010 Amendment, among other things, (i) subject to certain limitations, waived the requirement for the report of the Partnership's independent registered public accounting firm accompanying the Partnership’s financial statements for the year ended December 31, 2009 to not contain an explanatory paragraph expressing significant doubt about the Partnership's ability to continue as a going concern, (ii) subject to certain limitations, waived the requirement for the report of the Partnership's independent registered public accounting firm accompanying the Partnership’s financial statements for the 2010 fiscal year to not contain an explanatory paragraph expressing significant doubt about the Partnership's ability to continue as a going concern, and (iii) increased the applicable interest rate under the credit agreement by 2.0% per annum (the “Deferred Interest”); provided, that the Deferred Interest was not payable until the earlier of (a) the June 30, 2011 maturity date of the Prior Credit Agreement or (b) the repayment in full of all amounts outstanding under the Prior Credit Agreement and the termination of the lenders’ commitments under the Prior Credit Agreement. As the Partnership refinanced all of the debt under its Prior Credit Agreement in October of 2010 (see Note 15), all Deferred Interest was automatically forgiven by the lenders.

After giving effect to the March 2010 Amendment, amounts outstanding under the Partnership’s prior credit facility bore interest at either the LIBOR rate plus 6.50% per annum, with a LIBOR floor of 3.00%, or the Base rate plus 5.50% per annum, with a Base rate floor of 4.00% per annum. The Partnership paid a fee of 1.50% per annum on unused commitments under its prior revolving credit facility. After giving effect to the March 2010 Amendment, interest on amounts outstanding under the Partnership’s prior credit facility was paid monthly. The Partnership also accrued 2.0% interest per annum of Deferred Interest. In addition to the Deferred Interest, the Partnership’s prior credit facility required the Partnership to pay additional interest on October 6, 2009, April 6, 2010, October 6, 2010 and April 6, 2011, equal to the product of (i) the sum of the total amount of term loans then outstanding plus the aggregate commitments under the prior revolving credit facility and (ii) 0.50%, 0.50%, 1.00% and 1.00%, respectively. In October 2009, April 2010, and October 2010, the Partnership paid additional interest of $2.3 million, $2.2 million, and $4.3 million, respectively. The Partnership recognized these additional interest payments over the term of the prior debt agreement utilizing the effective interest method. As a result of the refinancing of the Partnership’s debt in October of 2010 (see Note 15), accrued and unpaid additional interest recognized utilizing the effective interest method and Deferred Interest, together totaling $4.2 million, will be credited to interest income in the fourth quarter of 2010.

During the three months ended September 30, 2009 and 2010, the weighted average interest rate incurred by the Partnership was 12.0% and 14.2%, respectively.

The Partnership’s prior credit facility required the Partnership to make (i) minimum quarterly amortization payments on September 30, 2010 in the amount of $2.5 million, December 31, 2010 in the amount of $2.5 million and March 31, 2011 in the amount of $2.5 million, (ii) mandatory prepayments of amounts outstanding under the prior revolving credit facility (with no commitment reduction) whenever cash on hand exceeded $15.0 million, (iii) mandatory prepayments with 100% of asset sale proceeds, (iv) mandatory prepayment with 50% of the proceeds raised through equity sales and (v) annual prepayments with 75% of excess cash flow (as defined in the Prior Credit Agreement). The Partnership’s prior credit facility prohibited the Partnership from making draws under the prior revolving credit facility if it would have had more than $15.0 million of cash on hand after making the draw and applying the proceeds thereof. On May 4, 2010, the Partnership made a $1.5 million mandatory prepayment in connection with the sale of an asphalt facility located in Morehead City, North Carolina. On September 30, 2010, the Partnership paid the mandatory quarterly amortization payment of $2.5 million. Based on the borrowing rates available to the Partnership for debt with similar terms and maturities and consideration of the Partnership’s non-performance risk, the Partnership’s debt at September 30, 2010, approximated its fair value.

Under the Prior Credit Agreement, the Partnership was subject to certain limitations, including limitations on its ability to grant liens, incur additional indebtedness, engage in a merger, consolidation or dissolution, enter into transactions with affiliates, sell or otherwise dispose of its assets (other than the sale or other disposition of the assets of the asphalt business, provided that such disposition is at arm’s length to a non-affiliate for fair market value in exchange for cash and the proceeds of the disposition are used to pay down outstanding loans), businesses and operations, materially alter the character of its business, and make acquisitions, investments and capital expenditures. The Prior Credit Agreement prohibited the Partnership from making distributions of available cash to its unitholders if any default or event of default (as defined in the credit agreement) existed. The Prior Credit Agreement required the Partnership to maintain a leverage ratio (the ratio of its consolidated funded indebtedness to its consolidated adjusted EBITDA, in each case as defined in the credit agreement), determined as of the last day of each month for the twelve month period ending on the date of determination, that ranges on a monthly basis from not more than 5.50 to 1.00 to not more than 9.75 to 1.00. In addition, the Partnership’s ability to make acquisitions and investments in unrestricted subsidiaries was limited and the Partnership was permitted to make distributions only if its leverage ratio was less than 3.50 to 1.00 and certain other conditions were met. As of September 30, 2010, the Partnership’s leverage ratio was 6.63 to 1.00, which is in compliance with the covenant specified in the Partnership’s prior credit facility.

The Prior Credit Agreement also required the Partnership to maintain an interest coverage ratio (the ratio of its consolidated EBITDA to its consolidated interest expense, in each case as defined in the credit agreement) in a range on a monthly basis from not less than 2.50 to 1.00 to not less than 1.00 to 1.00. As of September 30, 2010, the Partnership’s interest coverage ratio was 1.35 to 1.00, which is in compliance with the covenant specified in the Partnership’s prior credit facility.

Further, the Partnership was required to maintain monthly consolidated adjusted EBITDA for the prior twelve months ranging from $45.4 million to $82.9 million as determined at the end of each month. In addition, capital expenditures were limited to $8.0 million in 2010 and $4.0 million in the six months ending June 30, 2011; however, the Prior Credit Agreement allowed the Partnership to spend approximately $5.4 million of surplus carried forward from the 2009 maximum allowable capital expenditure. As of September 30, 2010, the Partnership is in compliance with these covenants. These capital expenditure limitations do not exist in the Partnership's new credit agreement (see Note 15).

Interest expense related to debt issuance cost amortization for the three and nine month periods ended September 30, 2009, was $1.0 million and $5.3 million, respectively, and for the three and nine month periods ended September 30, 2010, was $1.3 million and $3.6 million, respectively. Interest expense in the three months ended March 31, 2009, includes $0.4 million of debt issuance cost amortization expense attributable to 2008, which is not material to the 2009 financial statements. In connection with the forbearance agreement and the Prior Credit Agreement amendments, $1.4 million, $8.8 million, $0.6 million, and $0.5 million in debt issuance costs were capitalized in March 2009, April 2009, March 2010, and April 2010, respectively.

5.	DISTRIBUTIONS

The Partnership has not made a distribution to its common unitholders, subordinated unitholders or general partner since May 15, 2008 due to the events of default that existed under its Prior Credit Agreement, restrictions under the Prior Credit Agreement, and the uncertainty of its future cash flows relating to SemGroup, L.P.’s (collectively, with its successors (including SemGroup Corporation), affiliates and subsidiaries other than the Partnership and the Partnership’s general partner during periods in which the Partnership and its general partner were affiliated with SemGroup, L.P., “SemCorp”) bankruptcy filings. The Partnership’s 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 quart ers ended June 30, 2008 through June 30, 2010, and will not receive a distribution for the quarter ended September 30, 2010. Pursuant to the Prior Credit Agreement, the Partnership was prohibited from making distributions to its unitholders if its leverage ratio (as defined in the credit agreement) exceeded 3.50 to 1.00. As of September 30, 2010, the Partnership’s leverage ratio was 6.63 to 1.00. 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 September 30, 2010, each common unit was entitled to an arrearage of $3.13, or total arrearages for all common units of $67.9 million based upon 21,727,724 common units outstanding as of November 5, 2010.

6.	NET INCOME PER LIMITED PARTNER 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 September 30, 2009			Three Months Ended September 30, 2010			Nine Months Ended September 30, 2009			Nine Months Ended September 30, 2010
Net loss	$	(4,366	)	$	(2,848	)	$	(10,862	)	$	(10,600	)
Less: General partner interest in net loss		(87	)		(57	)		(216	)		(209	)
Net loss available to limited partners	$	(4,279	)	$	(2,791	)	$	(10,646	)	$	(10,391	)

Basic and diluted weighted average number of units:
Common units		21,557			21,728			21,557			21,728
Subordinated units		12,571			12,571			12,571			12,571
Restricted and phantom units		480			13			472			13

Basic and diluted net loss per common unit	$	(0.12	)	$	(0.08	)	$	(0.30	)	$	(0.30	)
Basic and diluted net loss per subordinated unit	$	(0.12	)	$	(0.08	)	$	(0.30	)	$	(0.30	)

7.	RELATED PARTY TRANSACTIONS

See Note 15 for additional information regarding related party transactions that occurred subsequent to September 30, 2010.

On November 24, 2009, a subsidiary of Vitol Holding B.V. (collectively, with its affiliates and subsidiaries other than the Partnership and the Partnership’s general partner, “Vitol”) acquired 100% of the membership interests in the Partnership’s general partner and the Partnership’s outstanding subordinated units (the “Vitol Change of Control”). As such, Vitol effectively controls the Partnership’s general partner and the Partnership. As a result of the Vitol Change of Control, for the three and nine months ended September 30, 2010, related party revenue consists of services provided to Vitol, and for the three and nine months ended September 30, 2009, related party revenue consists of services provided to SemCorp.

The Partnership provides crude oil gathering, transportation, terminalling and storage services to Vitol. For the three and nine months ended September 30, 2009, the Partnership recognized revenues of $3.2 million and $9.0 million, respectively, and for the three and nine months ended September 30, 2010, the Partnership recognized revenues of $6.9 million and $15.6 million, respectively, for services provided to Vitol. Revenues recognized in the three and nine months ended September 30, 2009 are classified as third party revenues. Revenues recognized in the three and nine months ended September 30, 2010 are classified as related party revenues. As of September 30, 2010, the Partnership had receivables from Vitol of $1.1 million and unearned revenue from Vitol of $2.1 million.

For the nine month period ended September 30, 2009, the Partnership recorded general and administrative expenses of $1.8 million for the services provided under an omnibus agreement by SemCorp. The obligation for SemCorp to provide services under the omnibus agreement and the corresponding administrative fee payable by the Partnership were terminated in connection with the events related to the change of control of the Partnership’s general partner in July 2008. SemCorp continued to provide such services to the Partnership until the effective date of the settlement with SemCorp in April of 2009 at which time SemCorp rejected the omnibus agreement and SemCorp and the Partnership entered into a shared services agreement and a transition services agreement relating to the provision of such services. 60;Certain of these transition services have been terminated and the Partnership is in the process of transitioning the remainder of services provided under the shared services agreement away from SemCorp.

Prior to entering into the shared services agreement with SemCorp, the Partnership also reimbursed SemCorp for direct operating payroll and payroll-related costs and other operating costs associated with services SemCorp’s employees provided to the Partnership. For the nine month period ended September 30, 2009, the Partnership recorded $7.8 million in compensation costs and $0.6 million in other operating costs related to services provided by SemCorp’s employees which are reflected as operating expenses in the accompanying statement of operations.

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”). In addition, Vitol has the option to renew the agreement for an additional one year term. 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 of Directors of the Partnership’s general partner (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 $13.1 million, $3.2 million and $9.2 million from Vitol with respect to services provided pursuant to the 2008 Vitol Storage Agreement during the year ended December 31, 2009 and the three and nine months ended September 30, 2010, respectively. The Partnership believes that the rates it charges Vit ol 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.

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. During the three and nine months ended September 30, 2010, the Partnership generat ed revenues under this agreement of approximately $3.0 million and $5.0 million, 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. 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.

Eagle North Pipeline System Throughput Capacity Agreement

In May of 2008, the Partnership acquired the Eagle North Pipeline System (“ENPS), a 130-mile, 8-inch pipeline that originates in Ardmore, Oklahoma and terminates in Drumright, Oklahoma from SemCorp for $45.0 million. At the time it acquired ENPS, the Partnership intended to complete a 10 mile extension of the pipeline from Drumright, Oklahoma to its crude oil terminal in Cushing, Oklahoma. Due to the effects of the bankruptcy filings of the Partnership’s former general partner, expenditures to place ENPS in service were suspended in the fourth quarter of 2008.

In August of 2010, the Partnership and Vitol entered into a Throughput Capacity Agreement (the “Throughput Agreement”). Pursuant to the Throughput Agreement, Vitol will purchase 100% of the throughput capacity on ENPS. The Partnership currently intends to put ENPS in service in the fourth quarter 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 received from Vitol is accounted for as a payable to a related party and is reflected as such on the Partnership’s consolidated balance sheet as of September 30, 2010. In addition, if the payments made by Vitol in any contract year under the Throughput Agreement a re 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 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 Throughput Agreement, then Vitol shall have the right to terminate the 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 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 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 nine months ended September 30, 2010, the Partnership incurred interest expense under this agreement of approximately $0.1 million. The agreement has an effective annual interest rate of 14.1 % and matures at December 31, 2014.

8.	LONG-TERM INCENTIVE PLAN

In July of 2007, the Partnership’s 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. 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 nine months ended September 30, 2009 and 2010, the Partnership recognized expense under the Plan of approximately $1.0 million and $0.0 million, 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.

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

	Number of Shares*		Weighted Average Grant Date Fair Value
Nonvested at December 31, 2009		12,500	$	9.29
Granted		—		—
Vested		—		—
Forfeited		—		—
Nonvested at September 30, 2010		12,500	$	9.29

_____________________

*	All non-vested restricted common unit awards outstanding at September 30, 2010 will vest upon the closing of the Vitol-Charlesbank Agreement, as defined below. See Note 15.

9.	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 $0.2 million and $0.8 million for the three and nine months ended September 30, 2010, respectively, for discretionary contributions under the plan.

10.	COMMITMENTS AND CONTINGENCIES

The Partnership is subject to various legal actions and claims, including governmental investigations and a securities class action and other lawsuits due to events related to SemCorp’s bankruptcy filings (see Note 13). The Partnership intends to vigorously defend these actions. There can be no assurance regarding the outcome of the litigation. An estimate of possible loss, if any, or the range of loss cannot be made and, therefore, the Partnership has not accrued a loss contingency related to these actions.

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. As described in “Part I, Item 1A. Risk Factors” of the Partnership’s 2009 Form 10-K and in “Part II, Item 1A. Risk Factors” of this quarterly report, these legal actions and claims may 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 did not have an accrual for legal settlem ents as of December 31, 2009 or September 30, 2010.

The Partnership has contractual obligations to perform dismantlement and removal activities in the event that some of its asphalt products 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. Accordin gly, 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.

11.	OPERATING SEGMENTS

The Partnership’s operations consist of three operating segments: (i) crude oil terminalling and storage services, (ii) crude oil gathering and transportation services and (iii) asphalt services.

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 GATHERING AND TRANSPORTATION SERVICES —The Partnership owns and operates two pipeline systems, the Mid-Continent system and the Longview system, 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 gathering and transportation system located in Oklahoma and the Texas Panhandle as the Mid-Continent system. It refers to its second gathering and transportation system, which is located in Texas, as the Longview system. In addition to its pipelines, the Partnership uses its owned and leased tanker trucks to gather crude oil for its customers at remote wellhead locations ge nerally 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. In connection with its gathering services, the Partnership also provides 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&# 8217;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.

The following table reflects certain financial data for each segment for the periods indicated:

	Crude Terminalling and Storage			Crude Gathering and Transportation		Asphalt Terminalling and Storage		Total
	(in thousands)
Three Months Ended September 30, 2009
Service revenue
Third party revenue	$	10,286		$	13,254	$	15,481	$	39,021
Related party revenue (1)		715			279		4		998
Total revenue for reportable segments		11,001			13,533		15,485		40,019
Operating expenses (excluding depreciation and amortization)		439			12,542		5,854		18,835
Operating margin (excluding depreciation and amortization)		10,562			991		9,631		21,184		(2)
Total assets (end of period)		76,838			97,872		142,124		316,834

Three Months Ended September 30, 2010
Service revenue
Third party revenue	$	3,274		$	13,033	$	14,806	$	31,113
Related party revenue (1)		6,393			550		—		6,943
Total revenue for reportable segments		9,667			13,583		14,806		38,056
Operating expenses (excluding depreciation and amortization)		1,155			12,107		4,864		18,126
Operating margin (excluding depreciation and amortization)		8,512			1,476		9,942		19,930		(2)
Total assets (end of period)		77,359			89,678		128,919		295,956

Nine Months Ended September 30, 2009
Service revenue
Third party revenue	$	30,604		$	41,391	$	21,630	$	93,625
Related party revenue (1)		2,571			1,689		21,817		26,077
Total revenue for reportable segments		33,175			43,080		43,447		119,702
Operating expenses (excluding depreciation and amortization)		1,843			38,364		14,163		54,370
Gain on settlement transaction		(2,585	)		—		—		(2,585	)
Operating margin (excluding depreciation and amortization)		33,917			4,716		29,284		67,917		(2)
Total assets (end of period)		76,838			97,872		142,124		316,834

Nine Months Ended September 30, 2010
Service revenue
Third party revenue	$	14,777		$	39,906	$	43,212	$	97,895
Related party revenue (1)		14,759			878		—		15,637
Total revenue for reportable segments		29,536			40,784		43,212		113,532
Operating expenses (excluding depreciation and amortization)		2,888			38,090		16,236		57,214
Operating margin (excluding depreciation and amortization)		26,648			2,694		26,976		56,318		(2)
Total assets (end of period)		77,359			89,678		128,919		295,956

_____________________

(1)	For the three and nine months ended September 30, 2009, related party revenue consists of services provided to SemCorp. For the three and nine months ended September 30, 2010, related party revenue consists of services provided to Vitol.
(2)	The following table reconciles segment operating margin (excluding depreciation and amortization) to loss before income taxes (in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2010			2009			2010
Operating margin (excluding depreciation and amortization)	$	21,184		$	19,930		$	67,917		$	56,318
Depreciation and amortization		5,644			5,315			17,055			16,228
General and administrative expenses		7,106			3,883			22,939			11,037
Interest expense		12,749			13,530			38,626			39,502
Loss before income taxes	$	(4,315	)	$	(2,798	)	$	(10,703	)	$	(10,449	)

12.	RECENTLY ISSUED ACCOUNTING STANDARDS

In January 2010, the Financial Accounting Standards Board (“FASB”) issued ASU 2010-06 – Fair Value Measurements and Disclosures (ASC 820): Improving Disclosures about Fair Value Measurements, which provides additional guidance to improve disclosures regarding fair value measurements. The ASU amends ASC 820-10, Fair Value Measurements and Disclosures—Overall (formerly FAS 157, Fair Value Measurements) to add two new disclosures: (1) transfers in and out of Level 1 and 2 measurements and the reasons for the transfers, and (2) a gross presentation of activity within the Level 3 roll forward. The ASU also includes clarifications to existin g disclosure requirements on the level of disaggregation and disclosures regarding inputs and valuation techniques. The ASU applies to all entities required to make disclosures about recurring and nonrecurring fair value measurements. The effective date of the ASU is the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward information, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. This statement will not have a significant impact on the Partnership due to it only requiring enhanced disclosures.

13.	ONGOING LITIGATION

On July 21, 2008, the Partnership received a letter from the staff of the SEC giving notice that the SEC is conducting an inquiry relating to the Partnership and requesting, among other things, that the Partnership voluntarily preserves, retains and produces to the SEC certain documents and information relating primarily to its disclosures respecting SemCorp’s liquidity issues, which were the subject of the Partnership’s July 17, 2008 press release. On October 22, 2008, the Partnership received a subpoena from the SEC pursuant to a formal order of investigation requesting certain documents relating to, among other things, SemCorp’s liquidity issues. The Partnership received another subpoena from the SEC on November 5, 2010 requesting that it produce additional documents by November 20, 2010. The Partnership has been cooperating, and intends to continue cooperating, with the SEC in its investigation.

Between July 21, 2008 and September 4, 2008, the following class action complaints were filed:

1. Poelman v. SemGroup Energy Partners, L.P., et al., Civil Action No. 08-CV-6477, in the United States District Court for the Southern District of New York (filed July 21, 2008). The plaintiff voluntarily dismissed this case on August 26, 2008;

2. Carson v. SemGroup Energy Partners, L.P. et al., Civil Action No. 08-cv-425, in the Northern District of Oklahoma (filed July 22, 2008);

3. Charles D. Maurer SIMP Profit Sharing Plan f/b/o Charles D. Maurer v. SemGroup Energy Partners, L.P. et al., Civil Action No. 08-cv-6598, in the United States District Court for the Southern District of New York (filed July 25, 2008);

4. Michael Rubin v. SemGroup Energy Partners, L.P. et al., Civil Action No. 08-cv-7063, in the United States District Court for the Southern District of New York (filed August 8, 2008);

5. Dharam V. Jain v. SemGroup Energy Partners, L.P. et al., Civil Action No. 08-cv-7510, in the United States District Court for the Southern District of New York (filed August 25, 2008); and

6. William L. Hickman v. SemGroup Energy Partners, L.P. et al., Civil Action No. 08-cv-7749, in the United States District Court for the Southern District of New York (filed September 4, 2008).

Pursuant to a motion filed with the MDL Panel, the Maurer case has been transferred to the Northern District of Oklahoma and consolidated with the Carson case. The Rubin, Jain, and Hickman cases have also been transferred to the Northern District of Oklahoma.

A hearing on motions for appointment as lead plaintiff was held in the Carson case on October 17, 2008. At that hearing, the court granted a motion to consolidate the Carson and Maurer cases for pretrial proceedings, and the consolidated litigation is now pending as In Re: SemGroup Energy Partners, L.P. Securities Litigation, Case No. 08-CV-425-GKF-PJC. The court entered an order on October 27, 2008, granting the motion of Harvest Fund Advisors LLC to be appointed lead plaintiff in the consolidated litigation. On January 23, 2009, the court entered a Scheduling Order providing, among other things, that the lead plaintiff may file a consolidated amended complaint within 70 days of the date of the order, and that defendants may answer or otherwise respond within 60 days of the date of the filing of a consolidated amended complaint. On January 30, 2009, the lead plaintiff filed a motion to modify the stay of discovery provided for under the Private Securities Litigation Reform Act. The court granted Plaintiff’s motion, and we and certain other defendants filed a Petition for Writ of Mandamus in the Tenth Circuit Court of Appeals that was denied after oral argument on April 24, 2009.

The lead plaintiff filed a consolidated amended complaint on May 4, 2009. In that complaint, filed as a putative class action on behalf of all purchasers of our units from July 17, 2007 to July 17, 2008 (the “class period”), lead plaintiff asserts claims under the federal securities laws against the Partnership, its General Partner, certain of the Partnership’s General Partner’s current and former officers and directors, certain underwriters in the Partnership’s initial and secondary public offerings, and certain entities who were investors in SemCorp and their individual representatives who served on SemCorp’s management committee. Among other allegations, the amended complaint alleges that the PartnershipR 17;s financial condition throughout the class period was dependent upon speculative commodities trading by SemCorp and its Chief Executive Officer, Thomas L. Kivisto, and that defendants negligently and intentionally failed to disclose this speculative trading in the Partnership’s public filings during the class period. The amended complaint further alleges there were other material omissions and misrepresentations contained in the Partnership’s filings during the class period. The amended complaint alleges claims for violations of sections 11, 12(a)(2), and 15 of the Securities Act of 1933 for damages and rescission with respect to all persons who purchased our units in the initial and secondary offerings, and also asserts claims under section 10b, Rule 10b-5, and section 20(a) of the Securities and Exchange Act of 1934. The amended complaint seeks certification as a class action under the Federal Rules of Civil Procedure, compensatory and rescissory damages for class members, pre-jud gment interest, costs of court, and attorneys’ fees.

On July 22, 2009, all of the defendants filed motions to dismiss the amended complaint. The lead plaintiff filed a response in opposition to the defendants’ motion to dismiss on September 1, 2009. On October 8, 2009, the defendants filed a reply in support of their motion to dismiss. The lead plaintiff filed a supplemental opposition to the defendants’ motion to dismiss on October 29, 2009. On April 30, 2010, the court dismissed all claims against Brent Cooper (SemCorp’s former treasurer) and dismissed the Section 10(b) and Rule 10b-5 claim against W. Anderson Bishop (a former member of the Board) and Brian F. Billings (a former member of the Board). The court denied the remainder of t he motions to dismiss, including the motion to dismiss that the Partnership filed. Under the operative scheduling order, the remaining defendants filed their answers on June 21, 2010.

SemGroup Energy Partners G.P., L.L.C., Thomas L. Kivisto (a former member of the Board), Gregory C. Wallace (a former member of the Board), Kevin L. Foxx (the Partnership’s General Partner’s former President and Chief Executive Officer), Alex G. Stallings (the Partnership’s General Partner’s Chief Financial Officer), Michael J. Brochetti (the Partnership’s General Partner’s former Chief Financial Officer), Mr. Billings and Mr. Bishop, have reached a tentative understanding with lead plaintiff to resolve the claims asserted in the amended complaint against those parties. This tentative understanding is subject to negotiating and completing a definitive settlement agreement and documentation and obtaining court approval and does not include all parties to the litigation. There can b e no assurance that a settlement will be finalized and approved or as to the ultimate outcome of the litigation.

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 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 Octo ber 22, 2010, the Partnership’s General Partner was ordered to pay $0.2 million in attorneys’ fees. The Partnership anticipates filing an appeal of this order also.

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 (see “Item 7. Management’s Discussion and Analysis of Financial Condition—Impact of the Bankruptcy of SemCorp and Certain of its Subsidiaries and Related Events—Examiner” in the 2009 Form 10-K). 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 settling parties have moved the court to approve the settlement and that motion 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 the Partnership’s 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 we re 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.

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 claims and lawsuits may result in the incurrence of significant legal expense. The litigation may also divert management’s attention from the Partnership’s operations which may cause the Partnership’s business to suffer. An unfavorable outcome in any of these matters may have an adverse effect on the Partnership’s business, financial condition, results of operations, cash flows, ability to make distributions to i ts unitholders, the trading price of its common units and 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.

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 relate d 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 September 30, 2010 are presented below (dollars in thousands):

Deferred tax assets
Difference in bases of property, plant and equipment	$	1,361
Net operating loss carryforwards		43
Deferred tax asset		1,404

Less: valuation allowance		(1,404	)

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.	SUBSEQUENT EVENTS

On October 25, 2010 (the “Transaction Date”), the Partnership entered into a Global Transaction Agreement, dated as of the Transaction Date, by and among the Partnership, the general partner of the Partnership, Vitol, and CB-Blueknight, LLC (“Charlesbank Holding”), pursuant to which the Partnership effected a refinancing of its existing debt as described in more detail herein.

In addition, Vitol and Charlesbank Holding have entered into an agreement (the “Vitol-Charlesbank Agreement”) whereby Charlesbank Holding will purchase 50% of the membership interests in the entity that owns the Partnership’s general partner and 50% of the Partnership’s outstanding subordinated units representing limited partner interests in the Partnership (“Subordinated Units”) from Vitol. Charlesbank Holding is owned indirectly by Charlesbank Capital Partners, LLC (together with its affiliates and subsidiaries other than the Partnership and the Partnership’s general partner, “Charlesbank”). Vitol will continue to indirectly own 50% of the membership interests in the Partnership’s general partner and own 50% of the Partnership’s outstanding sub ordinated units after consummation of the Vitol-Charlesbank Agreement.

The Board approved the Global Transaction Agreement and the transactions contemplated therein based on a recommendation from its Conflicts Committee, which consists entirely of independent directors. The Conflicts Committee retained independent legal and financial advisors to assist it in evaluating the Global Transaction Agreement and the transactions contemplated thereby and considered a number of factors in approving the Global Transaction Agreement and such transactions, including an opinion from the Conflicts Committee’s independent financial advisor that the Transactions are fair, in aggregate, from a financial point of view, to the public unaffiliated common unitholders of the Partnership.

The Global Transaction Agreement outlines a series of transactions related to the refinancing of the Partnership’s existing debt and the recapitalization of the Partnership’s securities. Generally, these transactions are separated into three types of transactions: (i) Phase I Transactions, (ii) Unitholder Vote Transactions and (iii) Phase II Transactions. Each of these transactions and the corresponding documents are outlined in more detail below.

Phase I Transactions

Pursuant to the terms of the Global Transaction Agreement, the Partnership completed the Phase I Transactions concurrently with the execution of the Global Transaction Agreement. The Phase I Transactions include: (i) the entry by the Partnership into a Credit Agreement (the “New Credit Agreement”) with JPMorgan Chase Bank, N.A. as Administrative Agent, J.P. Morgan Securities Inc., as Lead Arranger and Bookrunner, and the other lenders party thereto, including Vitol, (ii) the issuance and sale by the Partnership to Vitol and Charlesbank Holding (collectively, the “Purchasers”) of an aggregate of 21,538,462 Series A Preferred Units (the “Preferred Units”) for a cash purchase price of $6.50 per Preferred Unit in a privately negotiated transaction (the “Private Placement”) and t he entering into a Registration Rights Agreement by the Partnership with the Purchasers in connection therewith (the “Registration Rights Agreement”) and (iii) the issuance and sale by the Partnership to the Purchasers of Convertible Subordinated Debentures in the aggregate principal amount of $50.0 million (the “Convertible Debentures”). The Partnership used borrowings under the New Credit Agreement together with proceeds from the Private Placement and the sale of the Convertible Debentures (a) to repay all existing indebtedness under the Partnership’s Prior Credit Agreement (as defined below), (b) to pay certain transaction expenses incurred in connection with the Global Transaction Agreement and the transactions contemplated thereby, including a payment of approximately $0.7 million to the Purchasers as partial reimbursement of their expenses incurred in connection with the negotiation and preparation of the Global Transaction Agreement and the transactions contemp lated thereby and (c) for general partnership purposes.

New Credit Agreement

On the Transaction Date, the Partnership entered into the 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 New 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, leaving the Partnership with approximately $31.1 million available capacity for additional revolver borrowings and letters of credit under the New Credit Agreement. The proceeds of loans made under the New Credit Agreement may be used for working capital and other general corp orate purposes of the Partnership.

The New Credit Agreement is guaranteed by all of the Partnership’s existing subsidiaries. Obligations under the New 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 New 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 New Credit Agreement.

The New Credit Agreement will mature on October 25, 2014, and all amounts outstanding under the New Credit Agreement shall become due and payable on such date. The Partnership may prepay all loans under the New Credit Agreement at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements. The New 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 New Credit Agreement). These mandatory prepayments will be applied to the term loan under the New Credit Agreement until it is repaid in full, then applied to reduce commitments under the revolving loan facility.

Until approximately May 15, 2011, borrowings under the New Credit Agreement will bear 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 New 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 New Credit Agreement). The Partnership pays a per a nnum fee on all letters of credit issued under the New 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 New Credit Agreement. The New Credit Agreement does not have a floor for the ABR or the eurodollar rate. In connection with entering into the New 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 New Credit Agreement. Vitol received its pro rata portion of such fees as a lender under the New Credit Agreement.

The New 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 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 New 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 New Credit Agreement contains various covenants that, among other restrictions, limit the Partnership’s 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 the Partnership’s equity, make distributions to unitholders 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 the Partnership’s business;
enter into operating leases; and
make certain amendments to the Amended Partnership Agreement.

The New Credit Agreement permits the Partnership to make quarterly distributions of available cash (as defined in the Amended Partnership Agreement) to unitholders so long as: (i) no default or event of default exists under the New 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 expects that it will be allowed to make distributions to its unitholders in accordance with these covenants beginning with the quarter ending March 31, 2011; 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 Partnership’s 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.

Each of the following is an event of default under the New 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 New 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;
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 New Credit Agreement).

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

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

It will constitute a change of control under the New Credit Agreement if the transactions contemplated by the Vitol-Charlesbank Agreement are not consummated within 30 days after the Transaction Date. In addition, at any time after the transactions contemplated by the Vitol-Charlesbank Agreement are consummated, it will constitute a change of control under the New 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.

Private Placement

Pursuant to the terms of the Global Transaction Agreement, the Partnership issued and sold 10,769,231 Preferred Units to each Purchaser (or 21,538,462 Preferred Units in the aggregate) on the Transaction Date for a cash purchase price of $6.50 per Preferred Unit, resulting in total gross proceeds of approximately $140 million. The Global Transaction Agreement contains customary terms for private placements by public companies, including customary representations, warranties, covenants and limitations on the transfer of the Preferred Units.

The Preferred Units are a new class of voting equity security that ranks senior to all currently outstanding classes or series of equity securities of the Partnership with respect to distribution rights and rights upon liquidation. The Partnership’s general partner has adopted the Third Amended and Restated Agreement of Limited Partnership of the Partnership (the “Amended Partnership Agreement”) to reflect the terms of the Preferred Units.

Holders of the Preferred Units are entitled to quarterly distributions of 2.125% per unit per quarter (or 8.5% per unit on an annual basis) for each quarter during the one year period after the date of issuance of the Preferred Units (pro-rated with respect to the period commencing on the date of issuance and ending on December 31, 2010 based on the number of days in such period). In the case of any quarter beginning one year after the date of the issuance of the Preferred Units, the holders of the Preferred Units are entitled to quarterly distributions of 4.375% per unit per quarter (or 17.5% per unit on an annual basis) but this amount will decrease to 2.75% per unit per quarter (or 11.0% per unit on an annual basis) upon affirmative vote of the Unitholder Proposals discussed below. If the Partnership fails t o pay in full any distribution on the Preferred Units, the amount of such unpaid distribution will accrue and accumulate from the last day of the quarter for which such distribution is due until paid in full.

The Preferred Units have voting rights that are identical to the voting rights of the common units representing limited partner interests of the Partnership (“Common Units”) and shall vote with the Common Units as a single class, with each Preferred Unit entitled to one vote for each Common Unit into which such Preferred Unit is convertible; provided, that the Preferred Units will not have the right to vote on the Unitholder Proposals. The Preferred Units will have class voting rights on any matter, including a merger, consolidation or business combination, that adversely affects, amends or modifies any of the rights, preferences, privileges or terms of the Preferred Units.

The Preferred Units are convertible in whole, but not in part, into Common Units at the option of the Partnership at any time when either (i) a number of Preferred Units equal to 50% or more of the number of Preferred Units issued on the Transaction Date and upon conversion of the Convertible Debentures, if applicable, are converted into Common Units by the holders thereof pursuant to the rights described in the preceding paragraph and there does not exist any accrued but unpaid distributions on such Preferred Units or (ii) (a) there does not exist any accrued but unpaid distributions on such Preferred Units, (b) the Partnership’s securities class action litigation has been finally disposed of, including any appeals with respect thereto and (c) the distribution on a Preferred Unit on an “as-converted” basis (i.e., the actual distribution on a Common Unit multiplied by the number of Common Units that a Preferred Unit is convertible into) is equal to or greater than the distribution on a Preferred Unit for two consecutive quarters.

The Preferred Units are convertible in whole or in part into Common Units at the holder’s election at any time after the earlier of (i) the second business day following the record date for the Special Distribution (as defined below) or (ii) the eleventh business day following December 31, 2011. The number of Common Units into which a Preferred Unit is convertible will be an amount equal to (i) 6.50, divided by (ii) the Conversion Price (as defined below) (subject to customary anti-dilution adjustments). The Conversion Price is an amount equal to (a) in the event the Unitholder Meeting (as defined below) occurs prior to December 31, 2011, the volume-weighted average trading price per Common Unit during the 20 consecutive trading days ending on the tenth trading day after the date of the Unitholder M eeting or (b) in the event the Unitholder Meeting does not occur prior to December 31, 2011, the volume-weighted average trading price per Common Unit during the 20 consecutive trading days ending on the tenth trading day after December 31, 2011; provided, that in either case the Conversion Price shall be no greater than $6.50 and no lower than $5.50 (in each case, subject to adjustment as provided in the Amended Partnership Agreement).

Upon any liquidation and winding up of the Partnership or the sale of substantially all of the assets of the Partnership, the holders of Preferred Units generally will be entitled to receive, in preference to the holders of any of the Partnership’s other equity securities, an amount equal to the sum of (i) $6.50 multiplied by the number of Preferred Units owned by such holder, plus (ii) all accrued but unpaid distributions on such Preferred Units, plus (iii) any accrued but unpaid distribution on such Preferred Units with respect to the quarter in which the liquidation occurs.

Registration Rights Agreement

Pursuant to the terms of the Global Transaction Agreement, on the Transaction Date, the Partnership entered into a Registration Rights Agreement with the Purchasers. Pursuant to the Registration Rights Agreement, the Company has agreed to file up to six shelf registration statements for the resale of the Common Units issued as a result of the conversion of the Preferred Units issued in the Private Placement, the Additional Private Placement, if applicable, and upon conversion of the Convertible Debentures, if applicable. In addition, the Partnership has agreed to use reasonable best efforts to cause each shelf registration statement to be declared effective by the Securities and Exchange Commission (the “SEC”) no later than 180 days after its filing. The Registration Rights Agreement contains repres entations, warranties, covenants and indemnities that are customary for private placements by public companies.

Convertible Debentures

Pursuant to the terms of the Global Transaction Agreement, the Partnership issued and sold the Convertible Debentures on the Transaction Date to the Purchasers for $25.0 million each, resulting in gross proceeds to the Partnership of $50.0 million. The obligations of the Partnership under the Convertible Debentures are subordinate to the obligations of the Partnership under the New Credit Agreement. The Global Transaction Agreement contains customary terms for convertible debt issued by public companies, including customary representations, warranties and covenants relating to the Convertible Debentures.

The Convertible Debentures will bear interest at 10% until the one year anniversary of the Transaction Date. 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 the Partnership at any time prior to December 31, 2011 at a price equal to $25 million plus any accrued and unpaid interest, but the New 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. T he 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 the Partnership receives notice of such conversion, failure to make a payment in excess of $10 million for the Partnership’s other indebtedness and noncompliance with covenants contained in such Convertible Debenture. The Convertible Debentures are subordinate to all indebtedness of the Partnership under the New Credit Agreement.

Unitholder Vote Transactions

Pursuant to the Global Transaction Agreement, the general partner of the Partnership has agreed to take, in accordance with applicable law and the rules and regulations of any national securities exchange upon which the Common Units are traded and the Partnership’s partnership agreement, all action necessary to call, hold and convene a special meeting (the “Unitholder Meeting”) of holders of the Partnership’s Common Units and Subordinated Units to consider and vote upon the Unitholder Proposals. In addition, the Partnership has agreed to (i) prepare and file with the SEC a proxy statement in preliminary form, (ii) use its commercially reasonable efforts to cause the proxy statement to be transmitted to holders of the Partnership’s Common Units and Subordinated Units as promptly as practicable following the filing of the proxy statement in definitive form with the SEC and (iii) take all commercially reasonable lawful action to solicit approval of the Unitholder Proposals by the holders of the Partnership’s Common Units and Subordinated Units.

The Unitholder Proposals include:

approval to amend the Amended Partnership Agreement to reset (i) the Minimum Quarterly Distribution (as defined in the Amended Partnership Agreement) to $0.09 per unit per quarter from $0.3125 per unit per quarter, (ii) the First Target Distribution (as defined in the Amended Partnership Agreement) to $0.1035 per unit per quarter from $0.3594 per unit per quarter, (iii) the Second Target Distribution (as defined in the Amended Partnership Agreement) to $0.1125 per unit per quarter from $0.3906 and (iv) the Third Target Distribution (as defined in the Amended Partnership Agreement) to $0.1350 per unit per quarter from $0.4688 per unit per quarter, each effective as of the first day of the quarter during which the unitholders approve the Unitholder Proposals;
approval of the waiver of the Cumulative Common Unit Arrearage (as defined in the Amended Partnership Agreement) due and owing through the quarter prior to the quarter during which the unitholders approve the Unitholder Proposals; and
approval to amend the Amended Partnership Agreement to provide that no Minimum Quarterly Distribution dividends shall accrue or be paid to the holders of Subordinated Units during the four quarter period following the date that the unitholders approve the Unitholder Proposals and that, instead, such Minimum Quarterly Distributions that would be otherwise be paid to the holders of Subordinated Units will be paid to holders of Common Units, with the Conflicts Committee determining the amount of any such distribution.

The Board and the Conflicts Committee has each recommended that the public unitholders approve the Unitholder Proposals. The Unitholder Proposals must be approved by a majority of the outstanding Common Units (excluding any Common Units held by the General Partner and its affiliates) and a majority of the outstanding Subordinated Units in order for such proposals to be approved in accordance with the Partnership’s partnership agreement. Pursuant to the Global Transaction Agreement, the Purchasers have agreed to vote all of the Subordinated Units in favor of the Unitholder Proposals. The Preferred Units are not entitled to vote upon the Unitholder Proposals.

Phase II Transactions

Pursuant to the Global Transaction Agreement, upon the approval of the Unitholder Proposals, the following Phase II Transactions will take place: (i) the General Partner will amend the Amended Partnership Agreement to reflect the approval of the Unitholder Proposals, (ii) no later than 20 days after the date of the approval of the Unitholder Proposals (the “Unitholder Approval Date”), the Partnership will issue and sell to the Purchasers an aggregate of 2,615,386 Preferred Units (1,307,693 Preferred Units to each Purchaser) for a cash purchase price of $6.50 per Preferred Unit in a private transaction (the “Additional Private Placement”), resulting in total gross proceeds of approximately $17.0 million, such proceeds to be used to make the Special Distribution (as defined below), (iii) no later than 15 days a fter the Unitholder Approval Date, the General Partner will declare a distribution in favor of the holders of the Common Units in the amount of $0.78 per Common Unit (the “Special Distribution”), such Special Distribution to be paid no later than 45 days after the Unitholder Approval Date and (iv) the Partnership will undertake to complete a rights offering pursuant to which the Partnership will distribute to its existing common unitholders 0.5310 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 (the “Rights Offering”). The Partnership intends to use the proceeds from the Rights Offering to redeem the Convertible Debentures and for general partnership purposes.

Miscellaneous

Pursuant to the Global Transaction Agreement, the Partnership and the Partnership’s general partner have agreed to use their commercially reasonable best efforts to cause the Partnership’s Common Units to be listed for trading on the New York Stock Exchange, the American Stock Exchange or the NASDAQ Stock Market as soon as is reasonably practicable.

Important Additional Information Regarding the Unitholder Proposals and the related transactions will be filed with the SEC.

In connection with the Unitholder Proposals and the related transactions, the Partnership will file a proxy statement and other documents with the SEC. INVESTORS AND SECURITY HOLDERS ARE ADVISED TO READ THE PROXY STATEMENT WHEN IT BECOMES AVAILABLE BECAUSE IT WILL CONTAIN IMPORTANT INFORMATION ABOUT THE PARTNERSHIP, THE UNITHOLDER PROPOSALS AND RELATED TRANSACTIONS. Investors and security holders may obtain copies of the 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 b y 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 Unitholder Proposals and related transactions. Information regarding the special interests of persons who may be deemed to be such participants in the Unitholder Proposals and related transactions will be included in the proxy statement when it becomes available. Additional information regarding the directors and executive officers of the General Partner is also included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009, 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.

Departure of Directors and Appointment of Directors

Upon closing of the Vitol-Charlesbank Agreement, Charlesbank will appoint two directors to the Board. In connection therewith, two directors who are affiliated with Vitol will resign. As such, upon the closing of the Vitol-Charlesbank Agreement, the Board will consist of two directors who are affiliated with Charlesbank, two directors who are affiliated with Vitol and three independent directors.

Change of Control Payments

The consummation of the transaction contemplated by the Vitol-Charlesbank Agreement (the “Change of Control”) will result in a change of control under the employment agreements of each of (i) J. Michael Cockrell, President and Chief Operating Officer of the Partnership’s general partner, (ii) Alex G. Stallings, Chief Financial Officer and Secretary of the Partnership’s general partner, (iii) James R. Griffin, Chief Accounting Officer of the Partnership’s general partner, and (iv) Jerry A. Parsons, Executive Vice President—Asphalt Operations of the Partnership’s general partner.

Change of Control Payments - Mr. Cockrell

The Change of Control will result in a change of control under Mr. Cockrell’s employment agreement. Pursuant to such agreement, during the period from 2010 to 2013, Mr. Cockrell is entitled to certain deferred payments as compensation for long-term incentive awards which he forfeited upon leaving his prior employer, which payments total approximately $2.1 million, and may be made in the form of cash or equity incentives. Pursuant to the agreement, any unpaid deferred payments will be accelerated upon the Change of Control and payable within 10 days following such Change of Control in a lump sum payment to Mr. Cockrell. As such, on date the Change of Control occurs, deferred payments equal to approximately $1.9 million will be accelerated and become payable to Mr. Cockrell.

Change of Control Payments - Messrs. Stallings, Griffin and Parsons

The Change of Control will result in a change of control under the employment agreements of Messrs. Stallings, Griffin and Parsons. If within one year after the Change of Control any such officer is terminated by the General Partner without Cause (as defined below) or such officer terminates the agreement for Good Reason (as defined below), he will be entitled to payment of any unpaid base salary and vested benefits under any incentive plans, a lump sum payment equal to 24 months of base salary and continued participation in the Partnership’s general partner’s welfare benefit programs for the longer of the remainder of the term of the employment agreement or one year after termination. Upon such an event, Messrs. Stallings, Griffin and Parsons would be entitled to lump sum payments of approximately $0.6 millio n, $0.4 million and $0.5 million, respectively, in addition to continued participation in the Partnership’s general partner’s welfare benefit programs and the amounts of unpaid base salary and benefits under any incentive plans.

For purposes of the employment agreements with Messrs. Stallings, Griffin and Parsons:

“Cause” means (i) conviction of the executive officer by a court of competent jurisdiction of any felony or a crime involving moral turpitude; (ii) the executive officer’s willful and intentional failure or willful intentional refusal to follow reasonable and lawful instructions of the Board; (iii) the executive officer’s material breach or default in the performance of his obligations under the employment agreement; or (iv) the executive officer’s act of misappropriation, embezzlement, intentional fraud or similar conduct involving our General Partner.

“Good Reason” means (i) a material reduction in the executive officer’s base salary; (ii) a material diminution of the executive officer’s duties, authority or responsibilities as in effect immediately prior to such diminution; or (iii) the relocation of such individual’s principal work location to a location more than 50 miles from its current location.

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, LL C 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, 2009, which was filed with the Securities and Exchange Commission (the “SEC”) on March 30, 2010 (the “2009 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 othe r 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 2009 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-two 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 products. We manage our operations through three operating segments: (i) crude oil terminalling and storage services, (ii) crude oil gathering and transportation services and (iii) asphalt services. 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 “—Recent Events” for additional information). This resulted in decreased leverage, reduced interest rates on outstanding borrowings and increased liquidity. Based on these events and the management’s current assessment of ongoing litigation, we believe there is no longer substantial doubt about our ability to continue as a going concern for the next twelve months as previously disclosed in our 2009 Form 10-K.

On October 25, 2010, Vitol and Charlesbank entered into an agreement (the “Vitol-Charlesbank Agreement”) whereby Charlesbank will purchase 50% of the membership interests in the entity that owns our General Partner and 50% of our outstanding subordinated units representing limited partner interests in us from Vitol. Vitol will continue to own 50% of the membership interests in our General Partner and 50% of our outstanding subordinated units. For additional information regarding recent developments, see “—Recent Events” below.

On November 24, 2009, a subsidiary of Vitol acquired 100% of the membership interests in our General Partner and our outstanding subordinated units (the “Vitol Change of Control”). In connection with the Vitol Change of Control, the board of directors of our General Partner (the “Board”) was reconstituted and its management team was reorganized. See “Part III, Item 10. Directors, Executive Officers and Corporate Governance” in the 2009 Form 10-K for more information regarding the reconstitution of the Board and our General Partner’s management team. Effective upon the Vitol Change of Control, SemCorp ceased to have any ownership interest in us or our General Partner. Vitol has indicated that it intends to use us as a growth vehicle to pursue the acquisi tion and expansion of midstream energy businesses and assets. Vitol owns a diversified portfolio of midstream energy assets in the United States and internationally. We cannot say with any certainty which, if any, acquisition opportunities may be made available to us or if we will choose to pursue any such opportunity.

Our Revenues

We have been pursuing opportunities to provide crude oil terminalling and storage services, crude oil gathering and transportation services and asphalt services to third parties. For the three months ended September 30, 2010, we derived approximately 18% of our revenues from services we provided to Vitol and its subsidiaries, with the remainder of our services being provided to third parties.

As a result of new crude oil third-party storage contracts, we increased our third-party crude oil terminalling and storage revenue from approximately $1.0 million, or approximately 10% of total crude oil terminalling and storage revenue during the second quarter of 2008 (prior to SemCorp’s bankruptcy filings), to approximately $3.3 million, or approximately 34% of total crude oil terminalling and storage revenue for the third quarter of 2010.

In addition, we increased our third-party gathering and transportation revenue from approximately $5.0 million, or approximately 21% of total gathering and transportation revenue during the second quarter of 2008 (prior to SemCorp’s bankruptcy filings), to approximately $13.0 million, or approximately 96% of total crude oil gathering and transportation revenue for the third quarter of 2010.

The significant majority of the increase in third party revenues results from an increase in third-party crude oil services provided and a corresponding decrease in SemCorp’s crude oil services provided due to the termination of the monthly contract minimum revenues under a throughput agreement in September 2008 and reduced revenues under a new throughput agreement with SemCorp. 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. As an example, third quarter 2010 total reven ues are approximately $13.9 million (or approximately 28%) less than second quarter 2008 total revenues (prior to SemCorp’s bankruptcy filings), in each case excluding fuel reimbursement revenues related to fuel and power consumed to operate our liquid asphalt facilities.

The majority of the leases and storage agreements related to our asphalt facilities became effective during May of 2009 and extend through December 31, 2011. 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. The revenues we receive pursuant to these leases and storage agreements are less than the revenues received under the Terminalling Agreement with SemCorp. We expect annual revenues from these leases and storage agreements, excluding fuel reimbursement revenues related to fuel and power consumed to operate our liquid asphalt facilities, to be approximately $49.1 million for the twelve months ended December 31, 2010.

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

Events related to SemCorp’s bankruptcy filings, the securities litigation and governmental investigations, and our efforts to enter into storage contracts with third party customers and pursue strategic opportunities have resulted in increased expenses beginning in the third quarter of 2008 due to the costs related to legal and financial advisors as well as other related costs. General and administrative expenses (exclusive of non-cash compensation expense related to the vesting of the units under the SemGroup Energy Partners G. P., L.L.C. Long-Term Incentive Plan (the “Plan”)) increased by approximately $1.6 million, or approximately 70%, to approximately $3.9 million for the third quarter of 2010, compared to $2.3 million in the second quarter of 2008 (prior to SemCorp’s bankruptcy filings). ; We expect this increased level of general and administrative expenses to continue throughout 2010. However, we have been successful in reducing general and administrative expenses significantly from the levels experienced in the second half of 2008 and 2009. Further, we continue to decrease the amount of our operational shared services that are provided by SemCorp. We are targeting a complete transition of operational services from SemCorp early in 2011.

In addition, we have experienced increased interest expenses and other costs due to the events of default that existed under our credit agreement and the entering into amendments thereto. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in the 2009 Form 10-K for a discussion of these agreements and the associated expenses. We refinanced our outstanding debt in October of 2010. See “Recent Events” for additional detail.

Transfer of Certain Assets to Subsidiary Taxed as a Corporation

We have entered into storage contracts and leases with third party customers with respect to substantially all of our 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 whether the fees attributable to certain of the processing services we provide under certain of the storage contracts, constitute ��qualifying income.” In the second quarter of 2009, we submitted a request for a ruling from the IRS that rental income from the leases constitutes “qualifying income.” In October 2009, we received a favorable ruling from the IRS. As part of this ruling, however, we agreed to transfer, and have transferred, certain of our asphalt processing assets and related fee income, to a subsidiary taxed as a corporation. Th is 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 such subsidiary will generally be taxed again to unitholders as corporate distributions and none of the income, gains, losses, deductions or credits of such subsidiary will flow through to our unitholders. If a material amount of entity-level taxes are incurred by such subsidiary, then our cash available for distribution to its unitholders could be substantially reduced. We do not anticipate future entity-level taxes incurred by such subsidiary to be significant.

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 establi sh 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 September 30, 2010.

Vitol Storage Agreements

In connection with our acquisition of certain of our crude oil storage assets from SemCorp in May of 2008, we were assigned from SemCorp a storage agreement with Vitol under which we provide 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”). In addition, Vitol has the option to renew the agreement for an additional one year term. 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 Conflicts Committee in accordance with our 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 Conflicts Committee in accordance with our procedures for approval of related party transactions and the provisions of our partnership agreement. We earned revenues of approximately $13.1 million, $3.2 million and $9.2 million from Vitol with respect to services provided pursuant to the 2008 Vitol Storage Agreement during the year ended December 31, 2009 and the three and nine months ended September 30, 2010, respectively. We believe that the rates we charge Vitol under the 2008 Vitol Storage Agreement are fair and reasonable to us and our unitholders and are comparable with the rates we charge third parties.

In March of 2010, we entered into a second crude oil storage services agreement with Vitol under which we began providing additional crude oil storage services to Vitol effective May 1, 2010 (the “2010 Vitol Storage Agreement”). The initial term of 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 Conflicts Committee in accordance with our procedures for approval of related party transactions and the provisions of our partnership agreement. Service revenues earned under the 2010 Vitol Storage Agreement are based on the two million barrels of storage capacity of the crude oil storage t anks that are dedicated to Vitol under such agreement. During the three and nine months ended September 30, 2010, we generated revenues under this agreement of approximately $3.0 million and $5.0 million, respectively. We believe that the rates we charge Vitol under the 2010 Vitol Storage Agreement are fair and reasonable to us and our unitholders and are comparable with the rates we charge third parties.

Eagle North Pipeline System Throughput Capacity Agreement

In May of 2008, we acquired the Eagle North Pipeline System (“ENPS), a 130-mile, 8-inch pipeline that originates in Ardmore, Oklahoma and terminates in Drumright, Oklahoma from SemCorp for $45.0 million. At the time it acquired ENPS, we intended to complete a 10 mile extension of the pipeline from Drumright, Oklahoma to its crude oil terminal in Cushing, Oklahoma. Due to the effects of the bankruptcy filings of SemCorp, expenditures to place ENPS in service were suspended in the fourth quarter of 2008.

In August of 2010, we entered into a Throughput Capacity Agreement (the “Throughput Agreement”) with Vitol. Pursuant to the Throughput Agreement, Vitol will purchase 100% of the throughput capacity on ENPS. We currently intend to put ENPS in service in the fourth quarter of 2010. In September of 2010, Vitol paid us 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 received from Vitol is accounted for as a payable to a related party and is reflected as such on our consolidated balance sheet as of September 30, 2010. In addition, if the payments made by Vitol in any contract year under the Throughput Agreement are in the aggregate less than $2.4 million, then Vitol will pay us a deficiency payment equal to $2.4 million minus the aggregate amount of all payments made by Vitol during such contract year. The 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 Throughput Agreement, then Vitol shall have the right to terminate the Throughput Agreement within six months after such lack of capacity. We have 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 Throughput Agreement has not occurred and is continuing, we will remit to Vitol any and all tariffs and deficiency payments re ceived by us from such third party pursuant to its agreement with us. Entering into the Throughput Agreement was approved by the Board’s conflicts committee in accordance with our procedures for approval of related party transactions and the provisions of our partnership agreement.

During the three and nine months ended September 30, 2010, we incurred interest expense under this agreement of approximately $0.1 million. The agreement has an effective annual interest rate of 14.1 % and matures at December 31, 2014.

Recent Events

On October 25, 2010 (the “Transaction Date”), we entered into a Global Transaction Agreement, dated as of the Transaction Date, by and among us, our General Partner, Vitol and Charlesbank, pursuant to which we effected a refinancing of our existing debt as described in more detail herein.

In addition, we announced that Vitol and Charlesbank have entered into the Vitol-Charlesbank Agreement whereby Charlesbank will purchase 50% of the membership interests in the entity that owns our General Partner and 50% of our outstanding subordinated units representing limited partner interests in us from Vitol. Vitol will continue to indirectly own 50% of the membership interests in our General Partner and own 50% of our outstanding subordinated units after consummation of the Vitol-Charlesbank Agreement.

The Global Transaction Agreement outlines a series of transactions related to the refinancing of our existing debt and the recapitalization of our securities. Generally, these transactions are separated into three types of transactions: (i) Phase I Transactions, (ii) Unitholder Vote Transactions and (iii) Phase II Transactions. Each of these transactions and the corresponding documents are outlined in more detail below.

Phase I Transactions

Pursuant to the terms of the Global Transaction Agreement, we completed the Phase I Transactions concurrently with the execution of the Global Transaction Agreement. The Phase I Transactions include: (i) our entry into a Credit Agreement (the “New Credit Agreement”) with JPMorgan Chase Bank, N.A. as Administrative Agent, J.P. Morgan Securities Inc., as Lead Arranger and Bookrunner, and the other lenders party thereto, including Vitol, (ii) the issuance and sale by us to Vitol and Charlesbank (collectively, the “Purchasers”) of an aggregate of 21,538,462 Series A Preferred Units (the “Preferred Units”) for a cash purchase price of $6.50 per Preferred Unit in a privately negotiated transaction (the “Private Placement”) and the entering into a Registration Rights Agreement by t he us with the Purchasers in connection therewith (the “Registration Rights Agreement”) and (iii) the issuance and sale by us to the Purchasers of Convertible Subordinated Debentures in the aggregate principal amount of $50.0 million (the “Convertible Debentures”). We used borrowings under the New Credit Agreement together with proceeds from the Private Placement and the sale of the Convertible Debentures (a) to repay all existing indebtedness under the Partnership’s prior credit agreement (b) to pay certain transaction expenses incurred in connection with the Global Transaction Agreement and the transactions contemplated thereby, including a payment of approximately $0.7 million to the Purchasers as partial reimbursement of their expenses incurred in connection with the negotiation and preparation of the Global Transaction Agreement and the transactions contemplated thereby and (c) for general partnership purposes.

New Credit Agreement

See “—Liquidity and Capital Resources—Our Liquidity and Capital Resources—Description of New Credit Facility” for more information regarding the New Credit Agreement.

Private Placement

Pursuant to the terms of the Global Transaction Agreement, we issued and sold 10,769,231 Preferred Units to each Purchaser (or 21,538,462 Preferred Units in the aggregate) on the Transaction Date for a cash purchase price of $6.50 per Preferred Unit, resulting in total gross proceeds of approximately $140.0 million. The Global Transaction Agreement contains customary terms for private placements by public companies, including customary representations, warranties, covenants and limitations on the transfer of the Preferred Units.

The Preferred Units are a new class of voting equity security that ranks senior to all currently outstanding classes or series of our equity securities with respect to distribution rights and rights upon liquidation. Our General Partner has adopted the Third Amended and Restated Agreement of Limited Partnership of the Partnership (the “Amended Partnership Agreement”) to reflect the terms of the Preferred Units.

Holders of the Preferred Units are entitled to quarterly distributions of 2.125% per unit per quarter (or 8.5% per unit on an annual basis) for each quarter during the one year period after the date of issuance of the Preferred Units (pro-rated with respect to the period commencing on the date of issuance and ending on December 31, 2010 based on the number of days in such period). In the case of any quarter beginning one year after the date of the issuance of the Preferred Units, the holders of the Preferred Units are entitled to quarterly distributions of 4.375% per unit per quarter (or 17.5% per unit on an annual basis) but this amount will decrease to 2.75% per unit per quarter (or 11.0% per unit on an annual basis) upon affirmative vote of the Unitholder Proposals discussed below. If we fail to pay in full any d istribution on the Preferred Units, the amount of such unpaid distribution will accrue and accumulate from the last day of the quarter for which such distribution is due until paid in full.

The Preferred Units have voting rights that are identical to the voting rights of the common units representing limited partner interests in us (“Common Units”) and shall vote with the Common Units as a single class, with each Preferred Unit entitled to one vote for each Common Unit into which such Preferred Unit is convertible; provided, that the Preferred Units will not have the right to vote on the Unitholder Proposals. The Preferred Units will have class voting rights on any matter, including a merger, consolidation or business combination, that adversely affects, amends or modifies any of the rights, preferences, privileges or terms of the Preferred Units.

The Preferred Units are convertible in whole or in part into Common Units at the holder’s election at any time after the earlier of (i) the second business day following the record date for the Special Distribution (as defined below) or (ii) the eleventh business day following December 31, 2011. The number of Common Units into which a Preferred Unit is convertible will be an amount equal to (i) 6.50, divided by (ii) the Conversion Price (as defined below) (subject to customary anti-dilution adjustments). The Conversion Price is an amount equal to (a) in the event the Unitholder Meeting (as defined below) occurs prior to December 31, 2011, the volume-weighted average trading price per Common Unit during the 20 consecutive trading days ending on the tenth trading day after the date of the Unitholder Meetin g or (b) in the event the Unitholder Meeting does not occur prior to December 31, 2011, the volume-weighted average trading price per Common Unit during the 20 consecutive trading days ending on the tenth trading day after December 31, 2011; provided, that in either case the Conversion Price shall be no greater than $6.50 and no lower than $5.50.

The Preferred Units are convertible in whole, but not in part, into Common Units at our option at any time when either (i) a number of Preferred Units equal to 50% or more of the number of Preferred Units issued on the Transaction Date and upon conversion of the Convertible Debentures, if applicable, are converted into Common Units by the holders thereof pursuant to the rights described in the preceding paragraph and there does not exist any accrued but unpaid distributions on such Preferred Units or (ii) (a) there does not exist any accrued but unpaid distributions on such Preferred Units, (b) our securities class action litigation has been finally disposed of, including any appeals with respect thereto and (c) the distribution on a Preferred Unit on an “as-converted” basis (i.e., the actual distribution on a Common Unit mul tiplied by the number of Common Units that a Preferred Unit is convertible into) is equal to or greater than the distribution on a Preferred Unit for two consecutive quarters.

Upon any liquidation and winding up of the partnership or the sale of substantially all of our assets, the holders of Preferred Units generally will be entitled to receive, in preference to the holders of any of our other equity securities, an amount equal to the sum of (i) $6.50 multiplied by the number of Preferred Units owned by such holder, plus (ii) all accrued but unpaid distributions on such Preferred Units, plus (iii) any accrued but unpaid distribution on such Preferred Units with respect to the quarter in which the liquidation occurs.

Registration Rights Agreement

Pursuant to the terms of the Global Transaction Agreement, on the Transaction Date, we entered into a Registration Rights Agreement with the Purchasers. Pursuant to the Registration Rights Agreement, we have agreed to file up to six shelf registration statements for the resale of the Common Units issued as a result of the conversion of the Preferred Units issued in the Private Placement, the Additional Private Placement, if applicable, and upon conversion of the Convertible Debentures, if applicable. In addition, we have agreed to use reasonable best efforts to cause each shelf registration statement to be declared effective by the Securities and Exchange Commission (the “SEC”) no later than 180 days after its filing. The Registration Rights Agreement contains representations, warranties, covenants and i ndemnities that are customary for private placements by public companies.

Convertible Debentures

Pursuant to the terms of the Global Transaction Agreement, we issued and sold the Convertible Debentures on the Transaction Date to the Purchasers for $25 million each, resulting in gross proceeds to us of $50.0 million. Our obligations under the Convertible Debentures are subordinate to our obligations under the New Credit Agreement. The Global Transaction Agreement contains customary terms for convertible debt issued by public companies, including customary representations, warranties and covenants relating to the Convertible Debentures.

The Convertible Debentures will bear interest at 10% until the one year anniversary of the Transaction Date. 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 $25.0 million plus any accrued and unpaid interest, but the New 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 the Partnership receives notice of such conversion, failure to make a payment in excess of $10.0 million for our other indebtedness and noncompliance with covenants contained in such Convertible Debenture. The Convertible Debentures are subordinate to all of our indebtedness under the New Credit Agreement.

Unitholder Vote Transactions

Pursuant to the Global Transaction Agreement, our General Partner has agreed to take, in accordance with applicable law and the rules and regulations of any national securities exchange upon which the Common Units are traded and our partnership agreement, all action necessary to call, hold and convene a special meeting (the “Unitholder Meeting”) of holders of our Common Units and Subordinated Units to consider and vote upon the Unitholder Proposals. In addition, we have agreed to (i) prepare and file with the SEC a proxy statement in preliminary form, (ii) use its commercially reasonable efforts to cause the proxy statement to be transmitted to holders of our Common Units and Subordinated Units as promptly as practicable following the filing of the proxy statement in definitive form with the SEC and (iii) take all commercially reasonable lawful action to solicit approval of the Unitholder Proposals by the holders of our Common Units and Subordinated Units.

The Unitholder Proposals include:

approval to amend the Amended Partnership Agreement to reset (i) the Minimum Quarterly Distribution (as defined in the Amended Partnership Agreement) to $0.09 per unit per quarter from $0.3125 per unit per quarter, (ii) the First Target Distribution (as defined in the Amended Partnership Agreement) to $0.1035 per unit per quarter from $0.3594 per unit per quarter, (iii) the Second Target Distribution (as defined in the Amended Partnership Agreement) to $0.1125 per unit per quarter from $0.3906 and (iv) the Third Target Distribution (as defined in the Amended Partnership Agreement) to $0.1350 per unit per quarter from $0.4688 per unit per quarter, each effective as of the first day of the quarter during which the unitholders approve the Unitholder Proposals;
approval of the waiver of the Cumulative Common Unit Arrearage (as defined in the Amended Partnership Agreement) due and owing through the quarter prior to the quarter during which the unitholders approve the Unitholder Proposals; and
approval to amend the Amended Partnership Agreement to provide that no Minimum Quarterly Distribution dividends shall accrue or be paid to the holders of Subordinated Units during the four quarter period following the date that the unitholders approve the Unitholder Proposals and that, instead, such Minimum Quarterly Distributions that would be otherwise be paid to the holders of Subordinated Units will be paid to holders of Common Units, with the Conflicts Committee determining the amount of any such distribution.

The Board and the Conflicts Committee has each recommended that the public unitholders approve the Unitholder Proposals. The Unitholder Proposals must be approved by a majority of the outstanding Common Units (excluding any Common Units held by our general partner and its affiliates) and a majority of the outstanding Subordinated Units in order for such proposals to be approved in accordance with our partnership agreement. Pursuant to the Global Transaction Agreement, the Purchasers have agreed to vote all of the Subordinated Units in favor of the Unitholder Proposals. The Preferred Units are not entitled to vote upon the Unitholder Proposals.

Phase II Transactions

Pursuant to the Global Transaction Agreement, upon the approval of the Unitholder Proposals, the following Phase II Transactions will take place: (i) our general partner will amend the Amended Partnership Agreement to reflect the approval of the Unitholder Proposals, (ii) no later than 20 days after the date of the approval of the Unitholder Proposals (the “Unitholder Approval Date”), we will issue and sell to the Purchasers an aggregate of 2,615,386 Preferred Units (1,307,693 Preferred Units to each Purchaser) for a cash purchase price of $6.50 per Preferred Unit in a private transaction (the “Additional Private Placement”), resulting in total gross proceeds of approximately $17.0 million, such proceeds to be used to make the Special Distribution (as defined below), (iii) no later than 15 days after the Unit holder Approval Date, our general partner will declare a distribution in favor of the holders of the Common Units in the amount of $0.78 per Common Unit (the “Special Distribution”), such Special Distribution to be paid no later than 45 days after the Unitholder Approval Date and (iv) we will undertake to complete a rights offering pursuant to which we will distribute to its existing common unitholders 0.5310 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 (the “Rights Offering”). We intend to use the proceeds from the Rights Offering to redeem the Convertible Debentures and for general partnership purposes.

Miscellaneous

Pursuant to the Global Transaction Agreement, we and our General Partner have agreed to use our commercially reasonable best efforts to cause our Common Units to be listed for trading on the New York Stock Exchange, the American Stock Exchange or the NASDAQ Stock Market as soon as is reasonably practicable.

Important Additional Information Regarding the Unitholder Proposals and the related transactions which will be filed with the SEC.

In connection with the Unitholder Proposals and the related transactions, the Partnership will file a proxy statement and other documents with the SEC. INVESTORS AND SECURITY HOLDERS ARE ADVISED TO READ THE PROXY STATEMENT WHEN IT BECOMES AVAILABLE BECAUSE IT WILL CONTAIN IMPORTANT INFORMATION ABOUT US, THE UNITHOLDER PROPOSALS AND RELATED TRANSACTIONS. Investors and security holders may obtain copies of the 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 Part ners, L.P., Two Warren Place, 6120 South Yale Avenue, Suite 500, Tulsa, Oklahoma 74136, Attention: Investor Relations.

We, 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 our unitholders in connection with the Unitholder Proposals and related transactions. Information regarding the special interests of persons who may be deemed to be such participants in the Unitholder Proposals and related transactions will be included in the proxy statement when it becomes available. Additional information regarding the directors and executive officers of our general partner is also included in our Annual Report on Form 10-K for the year ended December 31, 2009, 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.

Departure of Directors and Appointment of Certain Directors

Change of Control Payments

The consummation of the transaction contemplated by the Vitol-Charlesbank Agreement (the “Change of Control”) will result in a change of control under the employment agreements of each of (i) J. Michael Cockrell, President and Chief Operating Officer of our General Partner, (ii) Alex G. Stallings, Chief Financial Officer and Secretary of our General Partner, (iii) James R. Griffin, Chief Accounting Officer of our General Partner, and (iv) Jerry A. Parsons, Executive Vice President—Asphalt Operations of our General Partner.

Change of Control Payments - Mr. Cockrell

Change of Control Payments - Messrs. Stallings, Griffin and Parsons

The Change of Control will result in a change of control under the employment agreements of Messrs. Stallings, Griffin and Parsons. If within one year after the Change of Control any such officer is terminated by our general partner without Cause (as defined below) or such officer terminates the agreement for Good Reason (as defined below), he will be entitled to payment of any unpaid base salary and vested benefits under any incentive plans, a lump sum payment equal to 24 months of base salary and continued participation in our general partner’s welfare benefit programs for the longer of the remainder of the term of the employment agreement or one year after termination. Upon such an event, Messrs. Stallings, Griffin and Parsons would be entitled to lump sum payments of approximately $0.6 million, $0.4 million and $0.5 million, respectively, in addition to continued participation in our general partner’s welfare benefit programs and the amounts of unpaid base salary and benefits under any incentive plans.

For purposes of the employment agreements with Messrs. Stallings, Griffin and Parsons:

Results of Operations

The table below summarizes our financial results for the three and nine months ended September 30, 2009 and 2010.

	Three Months ended September 30,							Nine Months Ended September 30,
	2009				2010			2009			2010
	(in thousands)
Service revenues:
Crude oil terminalling and storage revenues:
Third party	$	10,286			$	3,274		$	30,604		$	14,777
Related party(1)		715				6,393			2,571			14,759
Total crude oil terminalling and storage		11,001				9,667			33,175			29,536
Crude oil gathering and transportation revenues:
Third party		13,254				13,033			41,391			39,906
Related party(1)		279				550			1,689			878
Total crude oil gathering and transportation		13,533				13,583			43,080			40,784
Asphalt services revenues:				��
Third party		15,481				14,806			21,630			43,212
Related party(1)		4				—			21,817			—
Total asphalt services		15,485				14,806			43,447			43,212
Total revenues		40,019				38,056			119,702			113,532

Operating expenses:
Crude oil terminalling and storage		1,552				2,221			5,081			6,156
Crude oil gathering and transportation		14,038				13,341			43,143			41,969
Asphalt services		8,889				7,879			23,201			25,317
Total operating expenses		24,479				23,441			71,425			73,442

General and administrative expenses		7,106				3,883			22,939			11,037

Gain on settlement transaction		—				—			2,585			—

Operating income		8,434				10,732			27,923			29,053
Interest expense		12,749				13,530			38,626			39,502
Income tax expense		51				50			159			151
Net loss	$	(4,366	)		$	(2,848	)	$	(10,862	)	$	(10,600	)

____________________

(1)	For the three and nine months ended September 30, 2009, related party revenue consists of services provided to SemCorp. For the three and nine months ended September 30, 2010, related party revenue consists of services provided to Vitol.

Three Months Ended September 30, 2010 Compared to the Three Months Ended September 30, 2009

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 $1.8 million and $2.0 million for the three months ended September 30, 2010 and 2009, respectively, were $38.1 million for the three months ended September 30, 2010, compared to $40.0 million for the three months ended September 30, 2009, a decrease of $1.9 million, or 5%. Service revenues include revenues from crude oil terminalling and storage services, crude oil gathering and transportation services and asphalt services.

Crude oil terminalling and storage revenues decreased by $1.3 million to $9.7 million for the three months ended September 30, 2010, compared to $11.0 million for the three months ended September 30, 2009 due to decreases in barrels stored. Crude oil gathering and transportation services revenue for the three months ended September 30, 2010 of $13.6 million were consistent with amounts for the three months ended September 30, 2009. We expect to continue to experience a similar level of utilization of our crude oil assets for the remainder of 2010.

Our asphalt services revenue decreased by $0.5 million to $13.0 million for the three months ended September 30, 2010, compared to $13.5 million for the three months ended September 30, 2009, excluding reimbursement revenues for fuel and power, property tax, and insurance expenses related to the operations of our liquid asphalt facilities of $1.8 million and $2.0 million for the three months ended September 30, 2010 and 2009, respectively. This decrease is primarily attributed to changes in contract terms related to customers that were contracted under storage agreements in 2009 and that are now contracted under lease agreements in 2010. We have entered into leases and storage agreements with third party customers relating to 44 of our 45 asphalt facilities. We expect annual revenues from these leases and storage agreements, excluding the reimbursement revenues, to be approximately $49.1 million for the twelve months ended December 31, 2010.

Operating expenses. Operating expenses include salary and wage expenses and related taxes and depreciation and amortization expenses. Operating expenses decreased by $1.1 million, or 4%, to $23.4 million for the three months ended September 30, 2010, compared to $24.5 million for the three months ended September 30, 2009. Crude oil terminalling and storage operating expenses increased by $0.6 million to $2.2 million for the three months ended September 30, 2010, compared to $1.6 million for the three months ended September 30, 2009. Our crude oil gathering and transportation operating expenses decreased by $0.7 million to $13.3 million for the three months ended September 30, 2010, compared to $14.0 million for the three months ende d September 30, 2009. Our asphalt operating expenses decreased $1.0 million to $7.9 million for the three months ended September 30, 2010, compared to $8.9 million for the three months ended September 30, 2009.

The decrease in operating expenses was primarily driven by decreases in outside services and ad valorem and use taxes. These decreases were partially offset by an increase in compensation expense as a result of directly employing our own personnel as we transitioned away from the services provided by SemCorp under a shared services agreement.

Ad valorem and use taxes decreased by $1.0 million to $0.5 million for the three months ended September 30, 2010, compared to $1.5 million for the three months ended September 30, 2009 due to both the successful protests of assessed values and the implementation of abatement agreements that became effective on January 1, 2010.

Outside services decreased by $0.4 million to $0.5 million for the three months ended September 30, 2010, compared to $0.9 million for the three months ended September 30, 2009. This is the result of our continued progress in building our operational management team, and is reflective of the fact that we are relying less on outside service providers.

The three months ended September 30, 2010 include $0.4 million in other income related to reimbursable expenses and services provided to Vitol.

Compensation expenses increased by $0.9 million to $8.3 million for the three months ended September 30, 2010, compared to $7.4 million for the three months ended September 30, 2009. 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.

General and administrative expenses. General and administrative expenses decreased by $3.2 million, or 45%, to $3.9 million for the three months ended September 30, 2010, compared to $7.1 million for the three months ended September 30, 2009. This decrease is primarily attributable to a decrease in legal, financial advisory and other professional expenses of $2.5 million to $2.1 million for the three months ended September 30, 2010, compared to $4.6 million for the three months ended September 30, 2009. In addition, incentive compensation expense decreased by $0.4 million and insurance premiums decreased by $0.4 million for the three months ended September 30, 2010, compared to the three months ended September 30, 2009.

Interest expense. Interest expense represents interest on capital lease obligations and borrowings under our credit facility as well as amortization of debt issuance costs. Interest expense increased by $0.8 million to $13.5 million for the three months ended September 30, 2010, compared to $12.7 million for the three months ended September 30, 2009. Increases in our weighted average interest rate resulted in increased interest expense of $2.3 million for the three months ended September 30, 2010, compared to the three months ended September 30, 2009. In addition, capitalized interest for the three months ended September 30, 2010 of $1.5 million decreased total interest expense, compared to no capitalized interest for the three months ended September 30, 2009.

Nine Months Ended September 30, 2010 Compared to the Nine Months Ended September 30, 2009

Service revenues. Service revenues were $113.5 million for the nine months ended September 30, 2010, compared to $119.7 million for the nine months ended September 30, 2009, a decrease of $6.2 million, or 5%. Service revenues include revenues from crude oil terminalling and storage services, crude oil gathering and transportation services and asphalt services.

Crude oil terminalling and storage revenues decreased by $3.7 million to $29.5 million for the nine months ended September 30, 2010, compared to $33.2 million for the nine months ended September 30, 2009. In connection with the SemCorp’s bankruptcy filings, SemCorp rejected the Throughput Agreement, and we concurrently began to replace this business with services provided to third party customers. Our crude oil terminalling and storage assets are fully contracted, and we expect crude oil terminalling and storage revenues to remain consistent for the remainder of 2010.

Our crude oil gathering and transportation services revenue decreased by $2.3 million to $40.8 million for the nine months ended September 30, 2010, compared to $43.1 million for the nine months ended September 30, 2009. The decrease is primarily due to the impact of SemCorp’s bankruptcy filings and the resulting decrease in the volume of crude oil we gathered and transported for our customers. Historically, SemCorp was a first purchaser of crude oil and it utilized our gathering and transportation assets to deliver its crude oil to market. As we are not in the business of purchasing crude oil, the utilization of our crude oil gathering and transportation assets is now dependent on third party purchasers of crude oil, some of whom own alternative gathering and transportation assets. Our reliance on third party purchasers of crude oil has resulted in a decrease in the utilization of our crude oil gathering and transportation assets, and we continue to expect a similar level of utilization of these assets for the remainder of 2010.

Our asphalt services revenue decreased by $1.1 million to $37.7 million for the nine months ended September 30, 2010, compared to $38.8 million for the nine months ended September 30, 2009, excluding reimbursement revenues related to fuel and power, property tax, and insurance expenses related to the operations of our liquid asphalt facilities of $5.5 million and $4.6 million for the nine months ended September 30, 2010 and 2009, respectively. This decrease is due to our earning less revenue under our current operating and lease contracts than we did under the contract with SemCorp that was effective in the first quarter of 2009. We currently have entered into leases and storage agreements with third party customers relating to 44 of our 45 asphalt facilities. We expect annual revenues from these lea ses and storage agreements, excluding the reimbursement revenues, to be approximately $49.1 million for the twelve months ended December 31, 2010.

Operating expenses. Operating expenses include salary and wage expenses and related taxes and depreciation and amortization expenses. Operating expenses increased by $2.0 million, or 3%, to $73.4 million for the nine months ended September 30, 2010, compared to $71.4 million for the nine months ended September 30, 2009. Crude oil terminalling and storage operating expenses increased by $1.1 million to $6.2 million for the nine months ended September 30, 2010, compared to $5.1 million for the nine months ended September 30, 2009. Our crude oil gathering and transportation operating expenses decreased by $1.1 million to $42.0 million for the nine months ended September 30, 2010, compared to $43.1 million for the nine months ended September 30, 2009. O ur asphalt operating expenses increased by $2.1 million to $25.3 million for the nine months ended September 30, 2010, compared to $23.2 million for the nine months ended September 30, 2009.

Compensation expense increased by $3.1 million to $25.1 million for the nine months ended September 30, 2010, as compared to $22.0 million for the nine months ended September 30, 2009. 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.

Our repair and maintenance expenses increased by $0.8 million to $6.1 million for the nine months ended September 30, 2010, as compared to the nine months ended September 30, 2009. Our utilities expenses increased by $0.9 million to $10.2 million for the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009 due to increased rates. Insurance premium expenses increased by $0.2 million to $1.9 million for the nine months ended September 30, 2010 compared to $1.7 million for the nine months ended September 30, 2009. This increase was experienced as we renewed several property, auto and environmental insurance policies.

Operating expenses for the nine months ended September 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.

These increases in expenses were partially offset by decreases in other expenses. Management fees and shared services fees paid to SemCorp decreased $0.9 million for the nine months ended September 30, 2010, as compared to the nine months ended September 30, 2009. We expect to complete our transition away from the services provided by SemCorp early in 2011.

Outside services decreased by $0.5 million to $2.5 million for the nine months ended September 30, 2010, compared to $3.0 million for the nine months ended September 30, 2009. This is the result of our continued progress in building our operational management team, and is reflective of the fact that we are relying less on outside service providers.

Ad valorem and use taxes decreased by $1.0 million to $3.0 million for the nine months ended September 30, 2010 compared to $4.0 million for the nine months ended September 30, 2009 due to both the successful protests of assessed values and the implementation of abatement agreements that became effective on January 1, 2010.

Depreciation and amortization decreased $0.8 million for the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009. This decrease is comprised of a $0.2 million decrease in amortization of intangible assets as we recognized a full impairment charge in 2009, with the remaining $0.6 million decrease attributed to fully depreciated assets.

General and administrative expenses. General and administrative expenses decreased by $11.9 million, or 52%, to $11.0 million for the nine months ended September 30, 2010, compared to $22.9 million for the nine months ended September 30, 2009. This decrease is due to decreased costs related to legal and financial advisors as well as other related costs incurred in connection with events related to the SemCorp’s bankruptcy filings, the securities litigation and governmental investigations, and our efforts to enter into storage contracts with third party customers and pursue other strategic opportunities.

Gain on settlement transaction. Operating income for the nine months ended September 30, 2009 includes a $2.6 million gain recognized in connection with the settlement with SemCorp in April of 2009 (see 2009 Form 10-K).

Interest expense. Interest expense represents interest on capital lease obligations and borrowings under our credit facility as well as amortization of debt issuance costs. Total interest expense increased by $0.9 million to $39.5 million for the nine months ended September 30, 2010 compared to $38.6 million for the nine months ended September 30, 2009. Increases in our weighted average interest rate resulted in increased interest expense of $4.6 million for the nine months ended September 30, 2010, compared to the nine months ended September 30, 2009. A decrease in the weighted average debt outstanding resulted in a decrease in interest expense of $0.9 million for the nine months ended September 30, 2010, compared to the nine months ended September 30, 2009. In addition, capitalized interest for the nine months ended September 30, 2010 was $2.8 million, compared to no capitalized interest for the nine months ended September 30, 2009.

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.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

The following table summarizes our sources and uses of cash for the nine months ended September 30, 2009 and 2010:

	Nine Months Ended September 30,
	2009			2010
	(in millions)
Net cash provided by operating activities	$	16.8		$	16.5
Net cash used in investing activities		(3.3	)		(9.7	)
Net cash used in financing activities		(36.6	)		(10.3	)

Operating Activities. Net cash provided by operating activities was $16.5 million for the nine months ended September 30, 2010, as compared to the $16.8 million for the nine months ended September 30, 2009. The decrease in net cash provided by operating activities is primarily due to an increase in prepaid premiums associated with the renewal of several property, auto and environmental insurance policies.

Investing Activities. Net cash used in investing activities was $9.7 million for the nine months ended September 30, 2010, compared to $3.3 million for the nine months ended September 30, 2009. Net cash used in investing activities during the nine months ended September 30, 2009 is primarily comprised of maintenance capital expenditures. Net cash used in investing activities for the nine months ended September 30, 2010 is primarily comprised of expansion capital expenditures of approximately $7.3 million, $6.4 million of which is related to our Eagle North Pipeline System, and maintenance capital expenditures of approximately $4.0 million, partially offset by approximately $1.5 million of proceeds from the sale of an asphalt facility located in Morehead City, North Carolina.

Financing Activities. Net cash used in financing activities was $10.3 million for the nine months ended September 30, 2010, as compared to $36.6 million for the nine months ended September 30, 2009. Net cash used in financing activities for the nine months ended September 30, 2010 is primarily comprised of net payments under our credit facility and debt issuance costs related to our amended credit facility. The nine months ended September 30, 2010, also includes $5.5 million of borrowings associated with the Eagle North Pipeline System Throughput Capacity Agreement we executed with Vitol in August of 2010.

Our Liquidity and Capital Resources

Cash flow from operations and our credit facility are our primary sources of liquidity. At September 30, 2010, we had approximately $13.5 million of availability under our prior revolving credit facility. At September 30, 2010, we had a working capital deficit of $427.8 million due to the classification of our debt as a current obligation. As of November 5, 2010, we have an aggregate unused credit availability under our new revolving credit facility of approximately $35.1 million and cash on hand of approximately $9.8 million. Usage of our revolving credit facility is subject to ongoing compliance with covenants.

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 $7.4 million in the nine months ended September 30, 2010, inclusive of $2.8 million of capitalized interest, compared to $0.5 million in the nine months ended September 30, 2009. We expect expansion capital expenditures for organic growth projects to be approximately $8.5 million to $10.0 million in 2010, including approximately $4.0 million of capitalized interest. Maintenance capital expenditures totaled $4.2 million in the nine months ended September 30, 2010 compared to $2.9 million in the nine months ended September 30, 2009. We expect maintenance capital expenditures to be approximately $6.5 million to $7.5 million in 2010.

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. Pursuant to our Prior Credit Agreement, we were prohibited from making distributions to our unitholders if our leverage ratio (as defined in the Prior Credit Agreement) exceeds 3.50 to 1.00. The New Credit Agreement permits us to make quarterly distributions of available cash (as defined in the Amended Partnership Agreement) to unitholders so long as:& #160; (i) no default or event of default exists under the New 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 expect that we will be allowed to make distributions to our unitholders in accordance with the covenants of our New Credit Agreement beginning with the quarter ending March 31, 2011; 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.

We currently intend to put the Eagle North Pipeline System into service in the fourth quarter of 2010, and we will make capital expenditures related to this project during 2010. Capital expenditures were limited under our Prior Credit Agreement to $8.0 million in 2010 and $4.0 million in 2011. In addition, our Prior Credit Agreement allowed us to spend the approximately $5.4 million of surplus carried forward from the 2009 maximum allowable capital expenditure. Capital expenditures are not limited under our New Credit Agreement.

Description of Prior Credit Facility. In October of 2010, we refinanced our outstanding debt. See “—Description of New Credit Facility” for additional information. See Note 4 of the Notes to Unaudited Consolidated Financial Statements included in Part I, Item 1 of this quarterly report for a description of our prior credit facility.

Description of New Credit Facility. On the Transaction Date, we entered into the 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 New 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 the Transaction Date in connection with repaying all existing indebtedness under our prior credit agreement, leaving us with approximately $31.1 million available capacity for additional revolver borrowings and letters of credit under the New Credit Agreement. The proceeds of loans made under the New Credit Agreement may be used for working capital and other general corporate purposes of the Partnership.

The New Credit Agreement is guaranteed by all of our existing subsidiaries. Obligations under the New 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 New Credit Agreement will mature on October 25, 2014, and all amounts outstanding under the New Credit Agreement shall become due and payable on such date. We may prepay all loans under the New Credit Agreement at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements. The New 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 New Credit Agreement). These mandatory prepayments will be applied to the term loan under the New Credit Agreement until it is repaid in full, then applied to reduce commitments under the revolving loan facility.

Until approximately May 15, 2011, borrowings under the New Credit Agreement will bear 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 New Credit Agreement) plus 1%), plus an applicable margin of 3.25%, or (2) 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 New Credit Agreement). We pay a per annum fee on all letters of credit i ssued under the New 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 New Credit Agreement. The New Credit Agreement does not have a floor for the ABR or the eurodollar rate. In connection with entering into the New 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 the New Credit Agreement. Vitol received its pro rata portion of such fees as a lender under the New Credit Agreement.

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 New 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 New 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 equity, make distributions to unitholders 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 the Amended Partnership Agreement.

The New Credit Agreement permits us to make quarterly distributions of available cash (as defined in the Amended Partnership Agreement) to unitholders so long as: (i) no default or event of default exists under the New 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 expect that we will be allowed to make distributions to our unitholde rs in accordance with these covenants beginning with the quarter ending March 31, 2011; 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.

Each of the following is an event of default under the New 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 New 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 default under other indebtedness that exceeds a threshold amount;
judgments against us in excess of a threshold amount;
certain ERISA events involving us in excess of a threshold amount;

bankruptcy or other insolvency events involving us; and
a change in control (as defined in the New Credit Agreement).

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

It will constitute a change of control under the New Credit Agreement if the transactions contemplated by the Vitol-Charlesbank Agreement are not consummated within 30 days after the Transaction Date. In addition, at any time after the transactions contemplated by the Vitol-Charlesbank Agreement are consummated, it will constitute a change of control under the New 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.

As of November 5, 2010, we had $239.9 million in outstanding borrowings under our credit facility consisting of $39.9 million under our revolving credit facility and $200.0 million under our term loan facility, with an aggregate unused credit availability under our revolving credit facility of approximately $35.1 million.

Contractual Obligations. A summary of our contractual cash obligations over the next several fiscal years, as of September 30, 2010, 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)	$	457.8	$	457.8	$	—	$	—	$	—
Operating lease obligations		11.8		4.4		5.1		1.5		0.8
Related party throughput capacity agreement(2)		7.3		1.6		4.3		1.4		—
Employee contract obligations(3)		3.0		1.1		1.9		—		—
Shared services agreement obligations(4)		1.3		0.6		0.6		0.1		—
Premium Financing Agreements(5)		0.2		0.2		—		—		—

____________________

(1)

Represents required future principal repayments under our Prior Credit Agreement of borrowings of $413.7 million, variable rate interest payments of $35.4 million, and required fixed-rate additional interest payments of $8.5 million under such agreement. For purposes of calculating interest payments on our variable rate debt, the interest rate on our borrowings of 11.5% as of September 30, 2010 was used. All amounts outstanding under the Prior Credit Agreement mature in June 2011. As such, all outstanding borrowings under the Prior Credit Agreement are classified as current. This does not give effec t to our New Credit Agreement.

(2)	Represents required future principal repayments of borrowings of $5.5 million and interest payments of $1.8 million associated with the Eagle North Pipeline System Throughput Capacity Agreement with Vitol.

(3)	Represents required future payments to certain employees for long-term incentive awards forfeited upon leaving their former employer.

(4)

Represents required future payments under the shared services agreement into which we and SemCorp entered in connection with the April, 2009 settlement. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Impact of the Bankruptcy of SemCorp and Certain of its Subsidiaries and Related Events” in the 2009 Form 10-K. We are in the process of transitioning these services to us.

(5)	Represents required future insurance premium payments under financing agreements.

Recent Accounting Pronouncements

For information regarding recent accounting developments that may affect our future financial statements, see Note 12 of the Notes to Unaudited Consolidated Financial Statements included in Part I, Item 1 of this quarterly report.

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 September 30, 2010, amounts outstanding under our Prior Credit Agreement bore interest at either the LIBOR rate plus 6.5% per annum, with a LIBOR floor of 3.0%, or the Base rate plus 5.5% per annum, with a Base rate floor of 4.0% per annum. We paid a fee of 1.5% on unused commitments under our prior revolving credit facility. Interest on amounts outstanding under our Prior Credit Agreement was paid monthly. In addition, we accrued 2.0% of Deferred Interest on amounts outstanding. Our prior credit facility required us to pay additional interest on October 6, 2009, April 6, 2010, October 6, 2010 and April 6, 2011, equal to the product of (i) the sum of the total amount of term loans then outstanding plus the aggregate commitments under the prior revolving credit facility and (ii) 0.5%, 0.5%, 1.0% and 1.0%, respectively. In October, 2009, April, 2010, and October, 2010, we paid additional interest of $2.3 million, $2.2 million, and $4.3 million, respectively. See “Item 2. —Management’s Discussion and Analysis of Financial Condition and Results of Operation—Liquidity and Capital Resources—Our Liquidity and Capital Resources—Description of New Credit Facility” for information about our current credit facility.

During the nine months ended September 30, 2009 and 2010, the weighted average interest rate incurred by us was 12.0% and 13.4 % resulting in interest expense of approximately $38.6 million and $42.3 million (inclusive of $2.8 million in capitalized interest), respectively.

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 November 5, 2010 and the terms of our New Credit Agreement, an increase or decrease of 100 basis points in the interest rate will result in increased annual interest expense of approximately $2.4 million.

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 September 30, 2010, 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 September 30, 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

On July 21, 2008, we received a letter from the staff of the SEC giving notice that the SEC is conducting an inquiry relating to us and requesting, among other things, that we voluntarily preserve, retain and produce to the SEC certain documents and information relating primarily to our disclosures respecting SemCorp’s liquidity issues, which were the subject of our July 17, 2008 press release. On October 22, 2008, we received a subpoena from the SEC pursuant to a formal order of investigation requesting certain documents relating to, among other things, SemCorp’s liquidity issues. We received another subpoena from the SEC on November 5, 2010 requesting that we produce additional documents by November 20, 2010. & #160;We have been cooperating, and intend to continue cooperating, with the SEC in its investigation.

Between July 21, 2008 and September 4, 2008, the following class action complaints were filed:

2. Carson v. SemGroup Energy Partners, L.P. et al., Civil Action No. 08-cv-425, in the Northern District of Oklahoma (filed July 22, 2008);

4. Michael Rubin v. SemGroup Energy Partners, L.P. et al., Civil Action No. 08-cv-7063, in the United States District Court for the Southern District of New York (filed August 8, 2008);

5. Dharam V. Jain v. SemGroup Energy Partners, L.P. et al., Civil Action No. 08-cv-7510, in the United States District Court for the Southern District of New York (filed August 25, 2008); and

6. William L. Hickman v. SemGroup Energy Partners, L.P. et al., Civil Action No. 08-cv-7749, in the United States District Court for the Southern District of New York (filed September 4, 2008).

The lead plaintiff filed a consolidated amended complaint on May 4, 2009. In that complaint, filed as a putative class action on behalf of all purchasers of our units from July 17, 2007 to July 17, 2008 (the “class period”), lead plaintiff asserts claims under the federal securities laws against us, our General Partner, certain of our current and former officers and directors, certain underwriters in our initial and secondary public offerings, and certain entities who were investors in SemCorp and their individual representatives who served on SemCorp’s management committee. Among other allegations, the amended complaint alleges that our financial condition throughout the class period was dependent upon speculative commodities t rading by SemCorp and its Chief Executive Officer, Thomas L. Kivisto, and that defendants negligently and intentionally failed to disclose this speculative trading in our public filings during the class period. The amended complaint further alleges there were other material omissions and misrepresentations contained in our filings during the class period. The amended complaint alleges claims for violations of sections 11, 12(a)(2), and 15 of the Securities Act of 1933 for damages and rescission with respect to all persons who purchased our units in the initial and secondary offerings, and also asserts claims under section 10b, Rule 10b-5, and section 20(a) of the Securities and Exchange Act of 1934. The amended complaint seeks certification as a class action under the Federal Rules of Civil Procedure, compensatory and rescissory damages for class members, pre-judgment interest, costs of court, and attorneys’ fees.

On July 22, 2009, all of the defendants filed motions to dismiss the amended complaint. The lead plaintiff filed a response in opposition to the defendants’ motion to dismiss on September 1, 2009. On October 8, 2009, the defendants filed a reply in support of their motion to dismiss. The lead plaintiff filed a supplemental opposition to the defendants’ motion to dismiss on October 29, 2009. On April 30, 2010, the court dismissed all claims against Brent Cooper (SemCorp’s former treasurer) and dismissed the Section 10(b) and Rule 10b-5 claim against W. Anderson Bishop (a former member of the Board) and Brian F. Billings (a former member of the Board). The court denied the remainder of t he motions to dismiss, including the motion to dismiss that we filed. Under the operative scheduling order, the remaining defendants filed their answers on June 21, 2010.

SemGroup Energy Partners G.P., L.L.C., Thomas L. Kivisto (a former member of the Board), Gregory C. Wallace (a former member of the Board), Kevin L. Foxx (our General Partner’s former President and Chief Executive Officer), Alex G. Stallings (our General Partner’s Chief Financial Officer), Michael J. Brochetti (our General Partner’s former Chief Financial Officer), Mr. Billings and Mr. Bishop, have reached a tentative understanding with lead plaintiff to resolve the claims asserted in the amended complaint against those parties. This tentative understanding is subject to negotiating and completing a definitive settlement agreement and documentation and obtaining court approval and does not include all parties to the litigation. There can be no assurance that a settlement will be finalized and approved or as to the ultimate outcome of the litigation.

On October 27, 2008, Keystone Gas Company (“Keystone”) filed suit against us in Oklahoma State District Court in Creek County alleging that it is the rightful owner of certain segments of our pipelines and related rights of way, located in Payne and Creek Counties, that we acquired from SemCorp in connection with our 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 our use of such pipelines. We have filed a counterclaim against Keystone alleging that it is wrongfully using a segment of a pipeline that is owned by us in Payne and Creek Countie s. The parties are engaged in discovery. We intend 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 our General Partner. Their claims arise from our 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 our 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 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 our 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 our 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. We have 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. We have appealed this ruling. On October 22, 2010, our General Partner was ordered to pay $0.2 millio n in attorneys’ fees. We anticipate filing an appeal of this order also.

On July 24, 2009, we filed suit against Navigators Insurance Company (“Navigators”) and Darwin National Assurance Company (“Darwin”) in Tulsa County district court. In that suit, we are seeking a declaratory judgment that Darwin and Navigators did not have the right to rescind binders issued to us for three excess insurance policies in our 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 attem pted rescissions were in breach of contract and violated the duty of good faith and fair dealing, for which we are seeking the recovery of damages and attorneys fees. Navigators and Darwin have answered the petition and the parties are engaged in discovery.

We 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 claims and lawsuits may result in the incurrence of significant legal expense. The litigation may also divert management’s attention from our operations which may cause our business to suffer. An unfavorable outcome in any of these matters may have an adverse effect on our business, financial condition, results of operations, cash flows, ability to make distributions to our unitholders, the trading price of our common units and ability to conduct our business. All or a portion of the defense costs and any amount we may be required to pay to satisfy a judgment or settlement of these claims may not be covered by insurance.

Item 1A. Risk Factors

The risk factor set forth below updates the risk factors in “Part I, Item 1A. Risk Factors” in our 2009 Form 10-K. In addition to the risk factor below, you should carefully consider the other risk factors discussed in our 2009 Form 10-K, which could materially affect our business, financial position and results of operations.

We may be subject to significant costs related to environmental investigations and/or remediation activities at our asphalt facilities.

We acquired our asphalt assets from SemCorp in 2008 and 2009. The majority of these assets were previously acquired by SemCorp from a large privately-owned company (“Seller”) in 2005. Seller retained certain liabilities, including certain environmental liabilities, when it sold the assets to SemCorp. Since 2005, Seller has been conducting environmental investigation and/or remediation activities at certain of our asphalt facilities in connection with these retained environmental liabilities. Seller recently alleged that it does not have continued responsibility for these retained environmental liabilities at one of our asphalt facilities because of SemCorp’s bankruptcy. Because Seller has conducted all environmental investigation and/or remediation activities a t this site, we do not know the extent of any environmental issues and we are unable to estimate the costs or timing of any investigation and/or remediation activities, which may be material. In addition, Seller may make similar allegations regarding retained environmental liabilities at other of our asphalt facilities. Although we intend to defend any such allegations, if we are found to be liable for such environmental liabilities, it 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.

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.

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: November 9, 2010	By:	/s/ Alex G. Stallings
		Alex G. Stallings
		Chief Financial Officer and Secretary

Date: November 9, 2010	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*		Throughput Capacity Agreement, dated August 31, 2010, to be effective as of March 30, 2010.
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.

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. junior Avg

Blueknight Energy Partners (BKEP) 10-Q2011 Q0 Quarterly report

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