10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2012

OR 

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

For the transition period from __________ to _________

Commission File Number 001-33503

BLUEKNIGHT ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)	20-8536826 (IRS Employer Identification No.)
201 NW 10th, Suite 200 Oklahoma City, Oklahoma 73103 (Address of principal executive offices, zip code) Registrant’s telephone number, including area code: (405) 278-6400

(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    ý     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   ý      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 ý
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  ý

As of November 2, 2012, there were 30,159,958 Series A Preferred Units and 22,670,137 common units outstanding.                        

TABLE OF CONTENTS
		Page
PART I	FINANCIAL INFORMATION	1
Item 1.	Unaudited Financial Statements.	1
	Consolidated Balance Sheets as of December 31, 2011 and September 30, 2012	1
	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2011 and 2012	2
	Consolidated Statements of Changes in Partners’ Capital for the Nine Months Ended September 30, 2012	3
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2012	4
	Notes to Unaudited Consolidated Financial Statements	5
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations.	21
Item 3.	Quantitative and Qualitative Disclosure about Market Risk.	31
Item 4.	Controls and Procedures.	32
Item 5.	Other Information.	33
PART II	OTHER INFORMATION	34
Item 1.	Legal Proceedings.	34
Item 1A.	Risk Factors.	34
Item 6.	Exhibits.	34

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PART I.                       FINANCIAL INFORMATION

Item 1.    Financial Statements

BLUEKNIGHT ENERGY PARTNERS, L.P. CONSOLIDATED BALANCE SHEET (in thousands, except per unit data)
	As of			As of
	December 31, 2011			September 30, 2012
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	1,239		$	5,139
Accounts receivable, net of allowance for doubtful accounts of $476 and $469 at December 31, 2011 and September 30, 2012, respectively	14,191			11,129
Receivables from related parties, net of allowance for doubtful accounts of $0 for both dates	4,397			2,998
Prepaid insurance	1,725			1,738
Assets held for sale	603			1,349
Other current assets	1,838			2,785
Total current assets	23,993			25,138
Property, plant and equipment, net of accumulated depreciation of $135,302 and $148,580 at December 31, 2011 and September 30, 2012, respectively	266,355			262,629
Goodwill	7,216			7,216
Debt issuance costs, net	5,000			3,668
Intangibles and other assets, net	2,191			1,906
Total assets	$	304,755		$	300,557
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	10,138		$	6,752
Accrued loss contingency	1,090			—
Accrued interest payable	231			209
Accrued interest payable to related parties	362			308
Accrued property taxes payable	1,813			2,718
Unearned revenue	790			3,393
Unearned revenue with related parties	1,149			279
Accrued payroll	5,226			5,282
Other current liabilities	3,740			4,385
Current portion of long-term payable to related parties	1,636			1,817
Total current liabilities	26,175			25,143
Long-term payable to related parties	2,681			1,295
Other long-term liabilities	100			211
Long-term debt (including $15.0 million with related parties for both dates)	218,000			213,000
Commitments and contingencies (Notes 5 and 13)
Partners’ capital:
Series A Preferred Units (30,159,958 units issued and outstanding for both dates)	202,746			204,599
Common unitholders (22,657,638 and 22,670,137 units issued and outstanding at December 31, 2011 and September 30, 2012, respectively)	465,483			466,675
General partner interest (2.1% with 1,127,755 general partner units outstanding for both dates)	(610,430		)	(610,366		)
Total Partners’ capital	57,799			60,908
Total liabilities and Partners’ capital	$	304,755		$	300,557

See accompanying notes to unaudited consolidated financial statements.

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BLUEKNIGHT ENERGY PARTNERS, L.P. CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per unit data)
	Three months ended September 30,					Nine months ended September 30,
	2011			2012		2011			2012
	(unaudited)
Service revenue:
Third party revenue	$	35,124		$	34,797	$	99,748		$	100,844
Related party revenue	11,387			12,329		31,377			34,616
Total revenue	46,511			47,126		131,125			135,460
Expenses:
Operating	28,760			32,122		87,578			91,928
General and administrative	4,679			4,119		14,065			13,608
Total expenses	33,439			36,241		101,643			105,536
Gain on sale of assets	1,143			46		1,852			5,265
Operating income	14,215			10,931		31,334			35,189
Other (income) expenses:
Interest expense	9,120			2,909		27,284			8,877
Change in fair value of embedded derivative within convertible debt	(15,358		)	—		(20,224		)	—
Change in fair value of rights offering liability	(8,224		)	—		(1,838		)	—
Income before income taxes	28,677			8,022		26,112			26,312
Provision for income taxes	72			115		219			264
Net income	$	28,605		$	7,907	$	25,893		$	26,048
Allocation of net income for calculation of earnings per unit:
General partner interest in net income	$	643		$	165	$	754		$	659
Preferred interest in net income	$	2,975		$	5,391	$	11,124		$	16,173
Beneficial conversion feature attributable to preferred units	$	11,141		$	—	$	33,061		$	1,853
Income (loss) available to limited partners	$	13,846		$	2,351	$	(19,046	)	$	7,363
Basic and diluted net income (loss) per common unit	$	0.38		$	0.10	$	(0.56	)	$	0.32
Basic and diluted net income (loss) per subordinated unit	$	0.42		$	—	$	(0.52	)	$	—
Weighted average common units outstanding - basic and diluted	21,890			22,670		21,890			22,666
Weighted average subordinated units outstanding - basic and diluted	10,248			—		11,788			—

See accompanying notes to unaudited consolidated financial statements.

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BLUEKNIGHT ENERGY PARTNERS, L.P. CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL (in thousands)
	Common Unitholders			Series A Preferred Unitholders			General Partner Interest			Total Partners’ Capital
	(unaudited)
Balance, December 31, 2011	$	465,483		$	202,746		$	(610,430	)	$	57,799
Net income	9,651			15,853			544			26,048
Equity-based incentive compensation	1,057			—			22			1,079
Amortization of beneficial conversion feature of Preferred units	(1,853		)	1,853			—			—
Distributions	(7,663		)	(15,853		)	(502		)	(24,018		)
Balance, September 30, 2012	$	466,675		$	204,599		$	(610,366	)	$	60,908

See accompanying notes to unaudited consolidated financial statements.

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BLUEKNIGHT ENERGY PARTNERS, L.P. CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)
	Nine months ended September 30,
	2011			2012
	(unaudited)
Cash flows from operating activities:
Net income	$	25,893		$	26,048
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for uncollectible receivables from third parties	—			(7		)
Depreciation and amortization	17,066			17,174
Amortization and write-off of debt issuance costs	1,461			1,332
Amortization of subordinated debenture discount	13,207			—
Change in fair value of embedded derivative within convertible debt	(20,224		)	—
Change in fair value of rights offering liability	(1,838		)	—
Asset impairment charge	—			1,168
Gain on sale of assets	(1,852		)	(5,265		)
Equity-based incentive compensation	377			1,079
Changes in assets and liabilities
Decrease (increase) in accounts receivable	(4,156		)	3,069
Decrease (increase) in receivables from related parties	(931		)	1,399
Decrease in prepaid insurance	450			1,862
Decrease (increase) in other current assets	474			(948		)
Decrease (increase) in other assets	1,118			(72		)
Decrease in accounts payable	(2,036		)	(2,079		)
Decrease in accrued interest payable	(186		)	(22		)
Increase (decrease) in accrued interest payable to related parties	3,973			(54		)
Increase in accrued property taxes	736			905
Increase in unearned revenue	405			2,603
Decrease in unearned revenue from related parties	(2,154		)	(870		)
Increase in accrued payroll	788			56
Decrease in other accrued liabilities	(795		)	(906		)
Net cash provided by operating activities	31,776			46,472
Cash flows from investing activities:
Acquisitions	(133		)	—
Capital expenditures	(13,686		)	(18,730		)
Proceeds from sale of assets	2,244			7,389
Net cash used in investing activities	(11,575		)	(11,341		)
Cash flows from financing activities:
Payment on insurance premium financing agreement	(768		)	(1,008		)
Debt issuance costs	(280		)	—
Payments on long-term payable to related party	(808		)	(1,205		)
Borrowings under credit facility	6,000			31,000
Payments under credit facility	(19,862		)	(36,000		)
Distributions	(8,313		)	(24,018		)
Net cash used in financing activities	(24,031		)	(31,231		)
Net increase (decrease) in cash and cash equivalents	(3,830		)	3,900
Cash and cash equivalents at beginning of period	4,840			1,239
Cash and cash equivalents at end of period	$	1,010		$	5,139
Supplemental disclosure of cash flow information:
Increase in accounts payable related to purchase of property, plant and equipment	$	1,264		$	(1,307	)
Increase in accrued liabilities related to insurance premium financing agreement	$	1,278		$	1,580

See accompanying notes to unaudited consolidated financial statements.

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BLUEKNIGHT ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND NATURE OF BUSINESS

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

2. BASIS OF PRESENTATION

The financial statements have been prepared in accordance with accounting principles and practices generally accepted in the United States of America (“GAAP”).  The consolidated statements of operations for the three and nine months ended September 30, 2011 and 2012, the consolidated statement of changes in partners’ capital for the nine months ended September 30, 2012, the statement of cash flows for the nine months ended September 30, 2011 and 2012, and the consolidated balance sheet as of September 30, 2012 are unaudited.  In the opinion of management, the unaudited consolidated financial statements have been prepared on the same basis as the audited financial statements and include all adjustments necessary to state fairly the financial position and results of operations for the respective interim periods.  All adjustments are of a recurring nature unless otherwise disclosed herein.  The 2011 year-end consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP.  These consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes thereto included in the Partnership’s annual report on Form 10-K for the year ended December 31, 2011 filed with the Securities and Exchange Commission (the “SEC”) on March 13, 2012 (the “2011 Form 10-K”).  Interim financial results are not necessarily indicative of the results to be expected for an annual period.  The Partnership’s significant accounting policies are consistent with those disclosed in Note 4 of the Notes to Consolidated Financial Statements in our 2011 Form 10-K. A reclassification has been made in the consolidated financial statements for the three and nine months ended September 30, 2011 to conform to the 2012 financial statement presentation.  This was a reclassification of gain on sale of assets from operating expenses to a separate component of operating income.  The reclassification has no impact on net income.

3. RECENT EVENTS

On September 13, 2012, the Partnership announced that the Board of Directors (the “Board”) of Blueknight Energy Partners G.P., L.L.C., the general partner of the Partnership (the “General Partner”), appointed Mr. Mark Hurley as the Chief Executive Officer of the General Partner, effective September 20, 2012. Mr. Hurley replaced Mr. James C. Dyer, whose intended resignation was previously announced by the Partnership.

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4. PROPERTY, PLANT AND EQUIPMENT

	Estimated Useful Lives (Years)	December 31, 2011			September 30, 2012
		(dollars in thousands)
Land	N/A	$	16,601		$	16,355
Land improvements	10-20	5,671			5,980
Pipelines and facilities	5-30	152,733			159,314
Storage and terminal facilities	10-35	169,139			170,298
Transportation equipment	3-10	20,615			19,088
Office property and equipment and other	3-20	22,901			26,528
Pipeline linefill and tank bottoms	N/A	7,458			5,993
Construction-in-progress	N/A	6,539			7,653
Property, plant and equipment, gross		401,657			411,209
Accumulated depreciation		(135,302		)	(148,580		)
Property, plant and equipment, net		$	266,355		$	262,629

Depreciation expense for the three months ended September 30,2011 and 2012 was $5.6 million and $5.8 million, respectively, and depreciation expense for the nine months ended September 30,2011 and 2012 was $17.0 million and $17.1 million, respectively. In the three and nine months ended September 30,2012, the Partnership recorded asset impairment expense of $0.1 million and $1.2 million, respectively, related to its pipelines and facilities and transportation equipment.

5. DEBT

On October 25, 2010, the Partnership entered into a new credit agreement, which includes a $200.0 million term loan facility and a $75.0 million revolving loan facility.  On April 5, 2011, the Partnership entered into a Joinder Agreement whereby the Partnership’s revolving credit facility was increased from $75.0 million to $95.0 million.  As of November 2, 2012, approximately $200.0 million of term loan borrowings, $8.0 million of revolver borrowings and $0.6 million of letters of credit were outstanding under the credit facility, leaving the Partnership with approximately $86.4 million available capacity for additional revolver borrowings and letters of credit under the credit facility. A subsidiary of Vitol Holding B.V. (together with its subsidiaries, “Vitol”) is a lender under the credit agreement and has committed to loan the Partnership $15.0 million pursuant to such agreement.  The proceeds of loans made under the credit agreement may be used for working capital and other general corporate purposes of the Partnership.

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

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

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

Until May 15, 2011, borrowings under the credit agreement bore interest, at the Partnership’s option, at either (i) the ABR (the highest of the administrative agent’s prime rate, the federal funds rate plus 0.5%, or the one-month eurodollar rate (as

6

defined in the credit agreement) plus 1.0%), plus an applicable margin of 3.25%, or (ii) the eurodollar rate plus an applicable margin of 4.25%.  After May 15, 2011, the applicable margin for loans accruing interest based on the ABR ranges from 3.0% to 3.5%, and the applicable margin for loans accruing interest based on the eurodollar rate ranges from 4.0% to 4.5%, in each case depending on the Partnership’s consolidated total leverage ratio (as defined in the credit agreement).  The Partnership pays a per annum fee on all letters of credit issued under the credit agreement, which fee equals the applicable margin for loans accruing interest based on the eurodollar rate, and the Partnership pays a commitment fee of 0.5% per annum on the unused availability under the credit agreement.  The credit agreement does not have a floor for the ABR or the eurodollar rate.  In connection with entering into the credit agreement, the Partnership paid certain upfront fees to the lenders thereunder, and the Partnership paid certain arrangement and other fees to the arranger and administrative agent of the credit agreement.  Vitol received its pro rata portion of such fees as a lender under the credit agreement.

The credit agreement includes financial covenants that are 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 4.50 to 1.00 for each future fiscal quarter. The minimum permitted consolidated interest coverage ratio (as defined in the credit agreement) is 3.00 to 1.00 for each future fiscal quarter.

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

• create, incur or assume liens;

• engage in mergers or acquisitions;

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

• make investments;

• modify the terms of the convertible subordinated debentures (as defined below) and certain other indebtedness, or prepay certain indebtedness;

• engage in transactions with affiliates; 

• enter into certain burdensome contracts;

• change the nature of the Partnership’s business;

• enter into operating leases; and

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

At September 30, 2012, the Partnership’s leverage ratio was 2.95 and the interest coverage ratio was 6.83.  The Partnership was in compliance with all covenants of its credit agreement as of September 30, 2012.

The credit agreement permits the Partnership to make quarterly distributions of available cash (as defined in the Partnership’s partnership agreement) to unitholders so long as:  (i) no default or event of default exists under the credit agreement, (ii) the Partnership has, on a pro forma basis after giving effect to such distribution, at least $10.0 million of availability under the revolving loan facility, and (iii) the Partnership’s consolidated total leverage ratio, on a pro forma basis, would not be greater than 4.00 to 1.00 for any future fiscal quarter.  The Partnership is currently allowed to make distributions to its unitholders in accordance with these covenants; however, the Partnership will only make distributions to the extent it has sufficient cash from operations after establishment of cash reserves as determined by the General Partner in accordance with the Partnership’s cash distribution policy, including the establishment of any reserves for the proper conduct of the Partnership’s business.  See Note 6 for additional information regarding distributions.

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

• failure to meet the quarterly financial covenants;

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

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

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

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

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

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

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

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

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

Interest expense related to debt issuance cost amortization for the three and nine months ended September 30, 2011 was $0.5 million and $1.5 million, respectively, and for the three and nine month periods ended September 30, 2012 was $0.4 million and $1.3 million, respectively. The Partnership capitalized debt issuance costs of $0.3 million in the nine months ended September 30, 2011. The Partnership did not incur any debt issuance costs in the nine months ended September 30, 2012.

During the three and nine months ended September 30,2012, the weighted average interest rate under the credit agreement incurred by the Partnership was 4.45% and 4.53%, respectively, and the total weighted average interest rate, including interest associated with the ENPS Throughput Agreement (as defined in Note 8), was 5.46% and 5.52%, respectively, resulting in interest expense of approximately $2.9 million and $8.9 million, respectively.

In October 2010 the Partnership issued convertible subordinated debentures in a private placement in the aggregate principal amount of $50.0 million.  If not previously redeemed, the convertible subordinated debentures, including all outstanding principal and unpaid interest, would have converted to Preferred Units on December 31, 2011.  Upon issuance, this conversion feature was considered an embedded derivative, which the Partnership was required to bifurcate and carry at its fair value each reporting period. In connection with the establishment of the conversion price for the Preferred Units following the special meeting of the Partnership’s unitholders in September 2011, the conversion option was deemed to meet the scope exception for certain contracts involving an entity’s own equity in ACS 815-Derivatives and Hedging, and, therefore, the Partnership reclassified the embedded derivative as partners’ capital in the third quarter of 2011. The Partnership redeemed the convertible subordinated debentures on November 9, 2011.

Changes to the fair value of the embedded derivative are reflected on the Partnership’s consolidated statements of operations as “Change in fair value of embedded derivative within convertible debt.” The value of the embedded derivative was contingent on changes in the expected fair value of the Partnership’s preferred units. The Partnership recorded other income of $15.4 million and $20.2 million due to the change in the fair value of this embedded derivative in the three and nine months ended September 30, 2011, respectively.

In addition, the recording of the embedded derivative liability related to the convertible subordinated debentures resulted in the Partnership recording a $20.9 million debt discount on the convertible subordinated debentures.   The debt discount was being amortized to interest expense through the mandatory conversion date of December 31, 2011, using the effective interest rate method until the redemption of the convertible subordinated debentures on November 9, 2011. Upon redemption, the remaining unamortized debt discount was considered in the calculation of a $2.4 million extinguishment gain, which was determined to represent a capital transaction and, therefore, was recorded as a capital contribution to the Partnership by the Partnership’s general partner. For the purpose of calculating net income per limited partner unit, this amount was added back to net loss available to limited partners as it represents the recovery of a portion of the additional financing costs resulting from bifurcation of the conversion option and related discount on the convertible subordinated debentures. The Partnership recognized non-cash interest expense of $4.5 million and $13.2 million in the three and nine months ended September 30, 2011, respectively, due to the amortization of the debt discount.

6. DISTRIBUTIONS

The Partnership did not make a cash distribution to its common unitholders from May 15, 2008 through February 13, 2012

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due, in part, to the events of default that existed under its former credit agreement, restrictions under such credit agreement, and the uncertainty of its future cash flows relating to SemCorp’s bankruptcy filings (“SemCorp” refers to SemGroup Corporation and its predecessors including SemGroup, L.P., subsidiaries and affiliates other than the Partnership and the General Partner during periods in which the Partnership and the General Partner were affiliated with SemGroup, L.P.).  As a result of the approval of the Partnership Agreement Amendment Proposal (as defined in the Partnership’s Proxy Statement dated July 28, 2011) on September 14, 2011, all cumulative common unit arrearages were eliminated.  The Partnership’s common unitholders will be required to pay taxes on their share of the Partnership’s taxable income even though they did not receive a cash distribution for the quarters ended June 30, 2008 through September 30, 2011.  The Partnership is currently allowed to make distributions to its unitholders in accordance with its debt covenants; however, the Partnership will only make distributions to the extent it has sufficient cash from operations after establishment of cash reserves as determined by the General Partner in accordance with the Partnership’s cash distribution policy, including the establishment of any reserves for the proper conduct of the Partnership’s business.  The Partnership resumed distributions for common units on February 14, 2012 for the quarter ended December 31, 2011.

On October 23, 2012, the Board approved a distribution of $0.17875 per Preferred Unit, or a total distribution of $5.4 million.  The Partnership will pay this distribution on the preferred units on November 14, 2012 to preferred unitholders of record as of November 2, 2012.

In addition, the Partnership declared a cash distribution of $0.1125 per unit on its outstanding common units, a 2.3% increase over the previous quarter's distribution. The distribution will be paid on November 14, 2012 to unitholders of record on November 2, 2012. The distribution is for the three months ended September 30,2012. The total distribution to be paid will be approximately $2.7 million, with approximately $2.6 million and $0.1 million to be paid to the Partnership’s common unitholders and general partner, respectively, and less than $0.1 million to be paid to phantom and restricted unitholders pursuant to awards granted under the Partnership’s long-term incentive plan.

7. 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 income (loss) per common and subordinated unit (in thousands, except per unit data):

	Three months ended September 30,				Nine months ended September 30,
	2011		2012		2011			2012
Net income	$	28,605	$	7,907	$	25,893		$	26,048
General partner interest in net income	643		165		754			659
Preferred interest in net income	2,975		5,391		11,124			16,173
Beneficial conversion feature attributable to preferred units	11,141		—		33,061			1,853
Income (loss) available to limited partners	$	13,846	$	2,351	$	(19,046	)	$	7,363
Basic and diluted weighted average number of units:
Common units	21,890		22,670		21,890			22,666
Subordinated units(1)	10,248		—		11,788			—
Restricted and phantom units	456		617		380			550
Basic and diluted net income (loss) per common unit	$	0.38	$	0.10	$	(0.56	)	$	0.32
Basic and diluted net income (loss) per subordinated unit(1)	$	0.42	$	—	$	(0.52	)	$	—

____________________

(1) On September 14, 2011, Vitol and Charlesbank transferred all of the Partnership’s outstanding subordinated units to the Partnership and the Partnership canceled such subordinated units.  

8. RELATED PARTY TRANSACTIONS

The Partnership provides crude oil gathering, transportation, terminalling and storage services to Vitol.  For the three and

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nine months ended September 30,2011, the Partnership recognized revenues of $11.4 million and $31.4 million, respectively for services provided to Vitol.  For the three and nine months ended September 30,2012, the Partnership recognized revenues of $12.3 million and $34.6 million, respectively for services provided to Vitol.  As of September 30, 2012, the Partnership had receivables from Vitol of $3.0 million.

Vitol Omnibus Agreement

On February 15, 2010, the Partnership entered into an Omnibus Agreement (the “Vitol Omnibus Agreement”) with Vitol.  Pursuant to the Vitol Omnibus Agreement, the Partnership agreed to provide certain of its employees, consultants and agents (the “Designated Persons”) to Vitol for use by Vitol’s crude oil marketing division.  In return, Vitol agreed to reimburse the Partnership in an amount equal to (i) the wages, salaries, bonuses, make whole payments, payroll taxes and the cost of all employee benefits of each Designated Person, in each case as adjusted to properly reflect the time spent by such Designated Person in the performance services for Vitol, (ii) all direct expenses, including, without limitation, any travel and entertainment expenses, incurred by each Designated Person in connection with such Designated Person’s provision of services for Vitol, (iii) a monthly charge of $1,500.00 per Designated Person for each Designated Person that performs services for Vitol during any portion of such month, plus (iv) the sum of subsections (i) through (iii) above multiplied by 0.10.  In addition, the Vitol Omnibus Agreement provides that if during any month any Designated Person has spent more than 80% of his time performing services for Vitol, then Vitol will have the right for the succeeding three months to request that such individual be transitioned directly to the employment of Vitol.  During the three and nine months ended September 30,2011, the Partnership received payments of $0.3 million and $1.2 million, respectively, pursuant to the Vitol Omnibus Agreement.  During the nine months ended September 30,2012, the Partnership received payments of $0.1 million pursuant to the Vitol Omnibus Agreement.  The Vitol Omnibus 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’s partnership agreement. The Partnership and Vitol terminated the Vitol Omnibus Agreement on March 27, 2012.

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 provided 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 in 2010 to extend the term of the agreement until June 1, 2011 and again in 2011 to extend the term of the agreement to June 1, 2012.  Because Vitol was a third party (and not a related or affiliated party) at the time of entering into the 2008 Vitol Storage Agreement, such agreement was not approved by the Board or the Board’s conflicts committee in accordance with the Partnership’s procedures for approval of related party transactions.  Vitol became a related party when it acquired the General Partner in November 2009 (the “Vitol Change of Control”).  Since the amendments occurred subsequent to the Vitol Change of Control, they were reviewed and approved by the Board’s conflicts committee in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of the partnership agreement.  The Partnership earned revenues of approximately $3.3 million from Vitol with respect to services provided pursuant to the 2008 Vitol Storage Agreement for the three months ended September 30,2011.  The Partnership earned revenues of approximately $9.9 million and $5.5 million from Vitol with respect to services provided pursuant to the 2008 Vitol Storage Agreement for the nine months ended September 30,2011 and 2012, respectively.The Partnership believes that the rates it charged Vitol under the 2008 Vitol Storage Agreement were fair and reasonable to the Partnership and its unitholders and were comparable with the rates the Partnership charged 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.  The Partnership generated revenues under this agreement of approximately $3.1 million and $2.8 million during the three months ended September 30,2011 and 2012, respectively.  The Partnership generated revenues under this agreement of approximately $9.2 million and $8.7 million during the nine months ended September 30,2011 and 2012, 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. 

The Partnership entered into two new crude oil storage services agreements with Vitol, the “2012 Vitol 12-month Storage Agreement” and the “2012 Vitol 6-month Storage Agreement”, which became effective June 1, 2012, when the 2008 Vitol Storage Agreement expired according to its terms. The Partnership believes that the rates it charges Vitol under both of these

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agreements are fair and reasonable to the Partnership and its unitholders and are comparable with the rates the Partnership charges third parties. The Board’s conflicts committee reviewed and approved each of these agreements in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of the partnership agreement.

Service revenues under the 2012 Vitol 12-month Storage Agreement are based on the 1 million barrels of storage capacity of the crude oil storage tanks that are dedicated to Vitol under the agreement. The initial term of the Vitol 12-month Storage Agreement is from June 1, 2012 through June 1, 2013. The Partnership generated revenues under this agreement of approximately $1.4 million and $1.8 million for the three and nine months ended September 30,2012, respectively.

Service revenues under the 2012 Vitol 6-month Storage Agreement are based on the 500,000 barrels of storage capacity of the crude oil storage tanks that are dedicated to Vitol under the agreement. The initial term of the 2012 Vitol 6-month Storage Agreement is from June 1, 2012 through December 1, 2012. The Partnership generated revenues under this agreement of approximately $0.7 million and $0.9 million for the three and nine months ended September 30,2012, respectively.

During the third quarter of 2012, the Partnership entered into another 6-month storage agreement (the “Vitol September 2012 Storage Agreement”) with Vitol effective September 1, 2012. The Partnership believes that the rates it charges Vitol under this agreement are fair and reasonable to the Partnership and its unitholders and are comparable with the rates the Partnership charges third parties. The Board’s conflicts committee reviewed and approved this agreement in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of the partnership agreement. Service revenues under the Vitol September 2012 Storage Agreement are based on the 500,000 barrels of storage capacity of the crude oil storage tanks that are dedicated to Vitol under the agreement. The initial term of the Vitol September 2012 Storage Agreement is from September 1, 2012 to March 1, 2013. The Partnership generated revenues under this agreement of approximately $0.2 million for each of the three and nine months ended September 30,2012.

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 leased 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 had 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 were accounted for as operating leases.  During the three and nine months ended September 30,2011, the Partnership recorded expenses under this agreement of approximately $0.1 million and $0.4 million, respectively.  The Master Agreement was approved by the Board’s conflicts committee in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of its partnership agreement.  In September of 2011, the Partnership entered into a new master lease agreement with an unrelated third party and terminated the Master Agreement with Vitol.

Vitol Throughput Capacity Agreement

In August of 2010, the Partnership and Vitol entered into a Throughput Capacity Agreement (the “ENPS Throughput Agreement”).  Pursuant to the ENPS Throughput Agreement, Vitol purchased 100% of the throughput capacity on the Partnership’s Eagle North Pipeline System (“ENPS”).  The Partnership put ENPS in service in December of 2010.  In September 2010, Vitol paid the Partnership a prepaid fee equal to $5.5 million and Vitol will pay additional usage fees for every barrel delivered by or on behalf of Vitol on ENPS.  This $5.5 million fee received from Vitol is accounted for as a long-term payable to a related party and is reflected as such on the Partnership’s consolidated balance sheet as of September 30, 2012.  In addition, if the payments made by Vitol in any contract year under the ENPS Throughput Agreement are in the aggregate less than $2.4 million, then Vitol will pay the Partnership a deficiency payment equal to $2.4 million minus the aggregate amount of all payments made by Vitol during such contract year.  In March 2012, the Partnership received a deficiency payment of $0.3 million from Vitol in relation to the 2011 contract year. The ENPS Throughput Agreement has a term that extends for four years after ENPS is completed and may be extended by mutual agreement of the parties for additional one-year terms.  If the capacity on ENPS is unavailable for use by Vitol for more than 60 days, whether consecutive or nonconsecutive, during the term of the ENPS Throughput Agreement, then Vitol shall have the right to terminate the ENPS Throughput Agreement within six months after such lack of capacity.  The Partnership has previously contracted to provide throughput services on ENPS to a third party and Vitol’s rights to the capacity of ENPS are subordinate to the rights of such third party.  In addition, for so long as a default by Vitol relating to payments under the ENPS Throughput Agreement has not occurred and is continuing, the Partnership will remit to Vitol any and all tariffs and deficiency payments received by the Partnership or its affiliates from such third party pursuant to its agreement with the Partnership.  The ENPS Throughput Agreement was approved by the Board’s conflicts committee in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of its partnership agreement.

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During the three and nine months ended September 30,2011, the Partnership incurred interest expense under this agreement of approximately $0.2 million and $0.6 million, respectively.  During the three and nine months ended September 30,2012, the Partnership incurred interest expense under this agreement of approximately $0.1 million and $0.4 million, respectively. The agreement has an effective annual interest rate of 14.1% and matures on December 31, 2014.

Vitol Operating and Maintenance Agreement

In August of 2011, the Partnership and Vitol entered into an operating and maintenance agreement (the "Vitol O&M Agreement") relating to the operation and maintenance of Vitol's crude oil terminal located in Midland, Texas (the "Midland Terminal"). Pursuant to the Vitol O&M Agreement, the Partnership provides certain operating and maintenance services with respect to the Midland Terminal. The term of the Vitol O&M Agreement commenced on September 1, 2012 and shall continue for five years. During the three and nine months ended September 30,2012, the Partnership generated revenues of $0.1 million under this agreement. The Partnership believes that the rates it charges Vitol under this agreement are fair and reasonable to the Partnership and its unitholders and are comparable with the rates the Partnership charges third parties. The Board’s conflicts committee reviewed and approved this agreement in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of the partnership agreement.

Vitol Shared Services Agreement

In August of 2012, the Partnership and Vitol entered into a shared services agreement (the "Vitol Shared Services Agreement") pursuant to which the Partnership provides Vitol certain strategic assessment, economic evaluation and project design services. The term of the Vitol Shared Services Agreement commenced on August 1, 2012 and shall continue for one year. The Vitol Shared Services Agreement renews annually unless terminated by either party as provided in the agreement. During the three and nine months ended September 30,2012, the Partnership generated revenues of $0.3 million under this agreement. The Partnership believes that the rates it charges Vitol under this agreement are fair and reasonable to the Partnership and its unitholders. The Board’s conflicts committee reviewed and approved this agreement in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of the partnership agreement.

Vitol’s Commitment under the Partnership’s Credit Agreement

Vitol is a lender under the Partnership’s current credit agreement and has committed to loan the Partnership $15.0 million pursuant to such agreement.  During the three and nine months ended September 30, 2012, Vitol received its pro rata portion of the interest payments in connection with being a lender under the credit agreement and received approximately $0.2 million and $0.5 million, respectively, in connection therewith.

9. LONG-TERM INCENTIVE PLAN

In July of 2007, the General Partner adopted the Blueknight Energy Partners G.P., L.L.C. Long-Term Incentive Plan (the “Plan”). The compensation committee of the Board administers the Plan. The Plan authorizes the grant of an aggregate of 2.6 million common units deliverable upon vesting.  On September 14, 2011, the Partnership’s unitholders approved an amendment to the Plan to increase the number of common units issuable under such plan by 1.35 million common units from 1.25 million common units to 2.6 million common units.  Although other types of awards are contemplated under the Plan, currently outstanding awards include “phantom” units, which convey the right to receive common units upon vesting, and “restricted” units, which are grants of common units restricted until the time of vesting. Certain of 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.  

In March 2011 and March 2012, grants for 299,900 and 351,300 phantom common units, respectively, were made, which vest on January 1, 2014 and January 1, 2015, respectively.  These grants are equity awards under ASC 718 – Stock Compensation, and, accordingly, the fair value of the awards as of the grant date is expensed over the vesting period. The weighted average grant date fair-value of the awards is $8.25 and $6.76 per unit, respectively, which is the closing market price on the grant date of the awards. The value of these award grants was approximately $2.5 million and $2.4 million, respectively,

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on their grant date, and the unrecognized estimated compensation cost at September 30, 2012 was $2.7 million, which will be recognized over the remaining vesting period. As of September 30, 2012, the Partnership expects approximately 87% of these awards will vest. 

In September 2012, Mr. Mark Hurley was granted 500,000 phantom units under the Plan upon his employment as the Chief Executive Officer of the General Partner. These grants are equity awards under ASC 718 – Stock Compensation, and, accordingly, the fair value of the awards as of the grant date is expensed over the vesting period. These units vest ratably over five years pursuant to the Employee Phantom Unit Agreement between Mr. Hurley and the General Partner and do not include DERs. The weighted average grant date fair value for the units of $5.62 was determined based on the closing market price of the Partnership’s common units on the grant date of the award, less the present value of the expected distributions to be paid to holders of an outstanding common unit prior to the vesting of the underlying award. The value of this award grant was approximately $2.8 million on the grant date, substantially all of which was unrecognized at September 30, 2012, and will be expensed over the five year vesting period.

The Partnership’s equity-based incentive compensation expense for the three and nine months ended September 30, 2012 was $0.4 million and $1.1 million, respectively.

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

	Number of Units	Weighted Average Grant Date Fair Value
Nonvested at December 31, 2011	307,151	$	8.17
Granted	851,300	6.09
Vested	10,000	8.25
Forfeited	56,400	7.58
Nonvested at September 30, 2012	1,092,051	$	6.58

10. EMPLOYEE BENEFIT PLAN

Under the Partnership’s 401(k) Plan, which was instituted in 2009, employees who meet specified service requirements may contribute a percentage of their total compensation, up to a specified maximum, to the 401(k) Plan. The Partnership may match each employee’s contribution, up to a specified maximum, in full or on a partial basis. The Partnership recognized expense of $0.4 million and $0.3 million for the three months ended September 30,2011 and 2012, respectively, for discretionary contributions under the 401(k) Plan.  The Partnership recognized expense of $0.9 million and $1.0 million for the nine months ended September 30,2011 and 2012, respectively, for discretionary contributions under the 401(k) Plan.

The Partnership may also make annual lump-sum contributions to the 401(k) Plan irrespective of the employee’s contribution match. The Partnership may make a discretionary annual contribution in the form of profit sharing calculated as a percentage of an employee’s eligible compensation. This contribution is retirement income under the qualified 401(k) Plan. Annual profit sharing contributions to the 401(k) Plan are submitted to and approved by the Board. The Partnership recognized expense of $0.2 million for each of the three months ended September 30,2011 and 2012 for discretionary profit sharing contributions under the 401(k) Plan. The Partnership recognized expense of $0.7 million for each of the nine months ended September 30,2011 and 2012 for discretionary profit sharing contributions under the 401(k) Plan.

11. FAIR VALUE MEASUREMENTS

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

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

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

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liabilities.

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

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

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

The Partnership had no recurring financial assets or liabilities subject to fair value measurements as of December 31, 2011 or September 30, 2012.

The fair value of the embedded derivative within the subordinated convertible debentures was derived using a valuation model and has been classified as Level 3. The valuation model used is a discounted cash flow model (income approach) that assumes future distribution payments by the Partnership and utilizes interest rates and credit spreads for subordinated debt to preferred equity to determine the fair value of the derivative embedded within the subordinated convertible debentures. The change in fair value of the derivative liability for the three and nine months ended September 30,2011 of $15.4 million and $20.2 million, respectively, is included in other income in the Partnership’s consolidated statements of operations.  In connection with the establishment of the conversion price for the Preferred Units following the special meeting of the Partnership’s unitholders in September 2011, the number of Preferred Units issuable upon conversion of the subordinated convertible debentures was an amount equal to (i) the sum of the outstanding principal and any accrued and unpaid interest being converted, divided by (ii) 6.50.  The establishment of the conversion rate resulted in the embedded derivative meeting the scope exception in ASC 815-15 – Embedded Derivatives, and, therefore, the Partnership reclassified the embedded derivative as partners’ capital on September 14, 2011.

The fair value of the rights offering liability related to certain rights that have been offered to common unitholders under the approved Global Transaction Agreement was derived using a valuation model and has been classified as Level 3.  The valuation model used is a probability-weighted model (income approach) and assumes the number of rights that are exercised as well as the expected fair value of the Preferred Units at the time such rights are exercised.  The change in fair value of the rights offering liability for the three and nine months ended September 30,2011 of $8.2 million and $1.8 million, respectively, is included in other income in the Partnership’s consolidated statements of operations.

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

	Measurements UsingSignificant Unobservable Inputs (Level 3)
	For the Three Months Ended September 30, 2011			For the Nine Months Ended September 30, 2011
Beginning Balance	$	39,511		$	37,991
Total gains or losses (realized/unrealized):
Included in earnings	(23,582		)	(22,062		)
Included in other comprehensive income	—			—
Purchases, issuances, and settlements(1)	(7,326		)	(7,326		)
Transfers in and/or out of Level 3	—			—
Balance at September 30, 2011	$	8,603		$	8,603
The amount of  total income for the period included in earnings attributable to the change in unrealized gains for liabilities still held at the reporting date	$	(8,224	)	$	(1,838	)

____________________

(1) As noted above, the Partnership reclassified the embedded derivative within subordinated convertible debentures to partners’ capital as of September 14, 2011.

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Fair Value of Other Financial Instruments

The following disclosure of the estimated fair value of financial instruments is made in accordance with accounting guidance for financial instruments. The Partnership has determined the estimated fair values by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

At September 30, 2012, the carrying values on the unaudited condensed consolidated balance sheets for cash and cash equivalents (classified as Level 1), accounts receivable and accounts payable approximate their fair value because of their short term nature.

Based on the borrowing rates currently available to the Partnership for credit agreement debt with similar terms and maturities and consideration of the Partnership’s non-performance risk, long-term debt associated with the Partnership’s credit agreement at September 30, 2012 approximates its fair value. The fair value of the Partnership’s long-term debt was calculated using observable inputs (LIBOR for the risk free component) and unobservable company-specific credit spread information.  As such, the Partnership considers this debt to be Level 3.

12. OPERATING SEGMENTS

The Partnership’s operations consist of four operating segments: (i) crude oil terminalling and storage services, (ii) crude oil pipeline services, (iii) crude oil trucking and producer field services, and (iv) asphalt services.  

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

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

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

ASPHALT SERVICES —The Partnership provides asphalt product and residual fuel terminalling, storage and blending services at its 44 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 before income taxes, which is its nearest comparable GAAP financial measure, is included in the following table. The Partnership believes that investors benefit from having access to the same financial measures being utilized by management. Operating margin is an important measure of the economic performance of the Partnership’s core operations. This measure forms the basis of the Partnership’s internal financial reporting and is used by its management in deciding how to allocate capital resources among segments.  Income 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 (in thousands):  

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	Crude Oil Terminalling and Storage Services		Crude Oil Pipeline Services		Crude Oil Trucking and Producer Field Services		Asphalt  Services		Total
Three Months Ended September 30, 2011
Service revenue
Third party revenue	$	2,941	$	4,408	$	10,170	$	17,605	$	35,124
Related party revenue	6,683		1,220		3,484		—		11,387
Total revenue for reportable segments	9,624		5,628		13,654		17,605		46,511
Operating expenses (excluding depreciation and amortization)	1,138		3,813		12,486		5,672		23,109
Operating margin (excluding depreciation and amortization)(1)	8,486		1,815		1,168		11,933		23,402
Total assets (end of period)	75,304		102,730		16,071		126,670		320,775
Three Months Ended September 30, 2012
Service revenue
Third party revenue	$	3,278	$	4,216	$	10,722	$	16,581	$	34,797
Related party revenue	5,260		1,742		5,195		132		12,329
Total revenue for reportable segments	8,538		5,958		15,917		16,713		47,126
Operating expenses (excluding depreciation and amortization)	973		4,776		14,508		6,073		26,330
Operating margin (excluding depreciation and amortization)(1)	7,565		1,182		1,409		10,640		20,796
Total assets (end of period)	68,870		99,619		19,323		112,745		300,557
Nine months ended September 30, 2011
Service revenue
Third party revenue	$	8,316	$	13,301	$	32,634	$	45,497	$	99,748
Related party revenue	20,748		3,401		7,228		—		31,377
Total revenue for reportable segments	29,064		16,702		39,862		45,497		131,125
Operating expenses (excluding depreciation and amortization)	3,283		12,610		37,706		16,913		70,512
Operating margin (excluding depreciation and amortization)(1)	25,781		4,092		2,156		28,584		60,613
Total assets (end of period)	75,304		102,730		16,071		126,670		320,775
Nine months ended September 30, 2012
Service revenue
Third party revenue	$	9,009	$	12,274	$	35,202	$	44,359	$	100,844
Related party revenue	18,153		4,252		11,754		457		34,616
Total revenue for reportable segments	27,162		16,526		46,956		44,816		135,460
Operating expenses (excluding depreciation and amortization)	2,698		13,626		40,877		17,553		74,754
Operating margin (excluding depreciation and amortization)(1)	24,464		2,900		6,079		27,263		60,706
Total assets (end of period)	68,870		99,619		19,323		112,745		300,557

____________________

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

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	Three months ended September 30,					Nine months ended September 30,
	2011			2012		2011			2012
Operating margin (excluding depreciation and amortization)	$	23,402		$	20,796	$	60,613		$	60,706
Depreciation and amortization	5,651			5,792		17,066			17,174
General and administrative expenses	4,679			4,119		14,065			13,608
Gain on sale of assets	1,143			46		1,852			5,265
Interest expense	9,120			2,909		27,284			8,877
Change in fair value of embedded derivative within convertible debt	(15,358		)	—		(20,224		)	—
Change in fair value of rights offering liability	(8,224		)	—		(1,838		)	—
Income before income taxes	$	28,677		$	8,022	$	26,112		$	26,312

13. COMMITMENTS AND CONTINGENCIES

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

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 General Partner.  Their claims arise from the 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 General Partner’s failure to deliver certificates for the phantom units within 60 days after vesting caused them to be damaged, and they sought recovery of approximately $2.0 million in damages and penalties.  On April 30, 2009, all of the wage claims were dismissed on jurisdictional grounds by the Department of Labor.

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

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

On July 11, 2011, ExxonMobil filed suit against the Partnership in Harris County District Court, State of Texas,

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requesting damages in excess of $35,000 from the Partnership and other, third party service providers in connection with the relocation of existing pipelines of ExxonMobil and the Partnership.  The Partnership has filed its answer to the claims and asserted cross-claims against third party service providers including the subcontractors of ExxonMobil.  ExxonMobil had previously sent a settlement demand seeking approximately $1.9 million in damages.  A trial date is set for February, 2013. The Partnership intends to vigorously defend these claims. 

On February 6, 2012, the Partnership filed suit against SemCorp and others in Oklahoma County district court. In the suit, the Partnership is seeking a judgment that SemCorp immediately return approximately 140,000 barrels of crude oil linefill belonging to the Partnership, and the Partnership is seeking judgment in an amount in excess of $75,000 for actual damages, special damages, punitive damages, pre-judgment interest, reasonable attorney’s fees and costs, and such other relief that the Court deems equitable and just. On March 22, 2012, SemCorp filed a motion to dismiss and transfer to Tulsa County. On April 18, 2012, SemCorp filed a motion for summary judgment, and, on May 1, 2012, the district court of Oklahoma County ordered a transfer to Tulsa County. The Partnership is contesting SemCorp’s motion for summary judgment, which has been referred to a special master for report and recommendation. Discovery, before the special master, is ongoing and no trial date is set.

On July 13, 2012, the Partnership and one of its employees were named in a motor vehicle negligence suit in the District Court of Woodward County, Oklahoma, arising out of an accident involving one of the Partnership’s crude oil tanker trucks.  The accident resulted in the death of one of the occupants of the other vehicle, and certain unknown injuries to the other occupant.  The plaintiff is seeking damages in excess of $75,000 from the Partnership.  The Partnership has submitted the claim to its insurance carriers, and the Partnership believes that any recovery would be within applicable policy limits after payment of its $100,000 deductible.   Although it is not possible to predict the ultimate outcome of this matter, the Partnership does not expect that an award in this matter will have a material adverse impact on its consolidated results of operations or financial condition.

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

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

14. INCOME TAXES

The anticipated after-tax economic benefit of an investment in the Partnership’s common units depends largely on the Partnership being treated as a partnership for federal income tax purposes. If less than 90% of the gross income of a publicly traded partnership, such as the Partnership, for any taxable year is “qualifying income” from sources such as the transportation, marketing (other than to end users), or processing of crude oil, natural gas or products thereof, interest, dividends or similar sources, that partnership will be taxable as a corporation under Section 7704 of the Internal Revenue Code for federal income tax purposes for that taxable year and all subsequent years.

If the Partnership were treated as a corporation for federal income tax purposes, then it would pay federal income tax on its income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates.

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Distributions would generally be taxed again to unitholders as corporate distributions and none of the Partnership’s income, gains, losses, deductions or credits would flow through to its unitholders. Because a tax would be imposed upon the Partnership as an entity, cash available for distribution to its unitholders would be substantially reduced. Treatment of the Partnership as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to unitholders and thus would likely result in a substantial reduction in the value of the Partnership’s common units.

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

In relation to the Partnership’s taxable subsidiary, the tax effects of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts at September 30, 2012 are presented below (dollars in thousands):

Deferred tax assets
Difference in bases of property, plant and equipment	$	1,140
Deferred tax asset	1,140
Less: valuation allowance	(1,140		)
Net deferred tax asset	$	—

Given that the Partnership’s subsidiary that is taxed as a corporation has a limited earnings history for purposes of determining the likelihood of realizing the benefits of the deferred tax assets, the Partnership has provided a full valuation allowance against its deferred tax asset. 

15.    RECENTLY ISSUED ACCOUNTING STANDARDS

In May 2011, the FASB issued ASU 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRS),” which provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between GAAP and IFRS.  This new guidance changes some fair value measurement principles and disclosure requirements.  The Partnership adopted this guidance beginning with the Partnership’s Quarterly Report for the period ended March 31, 2012, and the impact was not material.

In September 2011, the FASB issued ASU 2011-08, “Testing for Goodwill Impairment,” which allows an entity to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test.  Under these assessments, an entity would not be required to calculate the fair value of a reporting unit unless the entity determines, based on a qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount.  The Partnership adopted this guidance beginning in its December 31, 2011 annual impairment test, and the impact was not material. 

In July 2012, the FASB issued ASU 2012-02, “Testing Indefinite-Lived Intangible Assets for Impairment,” which allows an entity to first assess qualitative factors to determine whether it is necessary to perform a quantitative impairment test. Under these amendments, an entity would not be required to calculate the fair value of an indefinite-lived intangible asset unless the entity determines, based on qualitative assessment, that it is not more likely than not, the indefinite-lived intangible asset is impaired. The amendments include a number of events and circumstances for an entity to consider in conducting the qualitative assessment. The Partnership plans to adopt this guidance beginning in its December 31, 2012 annual impairment test, and does not anticipate the impact to be material.

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16.    SUBSEQUENT EVENTS

On October 23, 2012, J. Michael Cockrell notified the Board of his resignation as President and Chief Operating Officer of the General Partner, effective as of October 31, 2012. Mr. Cockrell was a named executive officer of the Partnership for the fiscal year ended December 31, 2011.

On November 2, 2012, the Partnership amended its credit facility to permit Mr. Hurley to receive a non-voting economic interest in Blueknight GP Holding, LLC (“HoldCo”), the owner of the Partnership's general partner. Mr. Hurley's interest in HoldCo will vest over a five year period and entitle Mr. Hurley, to the extent vested, to (i) 2% of the total amount of proceeds and/or distributions in excess of $100,000,000 received by HoldCo in connection with a transaction resulting in a change of control of the Partnership, and (ii) 2% of the portion of any interim quarterly distribution received by HoldCo in excess of $1,250,000.

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

As used in this quarterly report, unless we indicate otherwise: (1) “Blueknight Energy Partners,” “our,” “we,” “us” and similar terms refer to Blueknight Energy Partners, L.P. (f/k/a/ SemGroup Energy Partners, L.P.), together with its subsidiaries, (2) our “General Partner” refers to Blueknight Energy Partners G.P., L.L.C. (f/k/a SemGroup Energy Partners G.P., L.L.C.), (3) “SemCorp” refers to SemGroup Corporation and its predecessors (including SemGroup, L.P.), subsidiaries and affiliates (other than our General Partner and us during periods in which we were affiliated with SemGroup, L.P.), (4) Vitol refers to Vitol Holding B.V., its affiliates and subsidiaries (other than our General Partner and us) and (5) Charlesbank refers to Charlesbank Capital Partners, LLC, its affiliates and subsidiaries (other than our General Partner and us).  The following discussion analyzes the historical financial condition and results of operations of the Partnership and should be read in conjunction with our financial statements and notes thereto, and Management’s Discussion and Analysis of Financial Condition and Results of Operations presented in our Annual Report on Form 10-K for the year ended December 31, 2011, which was filed with the Securities and Exchange Commission (the “SEC”) on March 13, 2012 (the “2011 Form 10-K”).

Forward-Looking Statements

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

Such forward-looking statements are subject to various risks and uncertainties that could cause actual results to differ materially from those anticipated as of the date of the filing of this report. Although we believe that the expectations reflected in these forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will prove to be correct. Important factors that could cause our actual results to differ materially from the expectations reflected in these forward-looking statements include, among other things, those set forth in “Part I, Item 1A. Risk Factors” in the 2011 Form 10-K.

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

Overview

We are a publicly traded master limited partnership with operations in twenty-three states. We provide integrated terminalling, storage, gathering and transportation services for companies engaged in the production, distribution and marketing of crude oil and liquid asphalt cement.  We manage our operations through four operating segments: (i) crude oil terminalling and storage services, (ii) crude oil pipeline services, (iii) crude oil trucking and producer field services, and (iv) asphalt services.  

Recent Events

On September 13, 2012, the Board of Directors (the “Board”) of our General Partner appointed Mr. Mark Hurley as the Chief Executive Officer of our General Partner, effective September 20, 2012. Mr. Hurley replaced Mr. James C. Dyer, whose intended resignation was previously announced by the Partnership.

On October 23, 2012, J. Michael Cockrell notified the Board of his resignation as President and Chief Operating Officer of our General Partner, effective as of October 31, 2012.

On November 2, 2012, we amended our credit facility to permit Mr. Hurley to receive a non-voting economic interest in Blueknight GP Holding, LLC (“HoldCo”), the owner of our General Partner. Mr. Hurley’s interest in HoldCo will vest over a five year period and entitle Mr. Hurley, to the extent vested, to (i) 2% of the total amount of proceeds and/or distributions in

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excess of $100,000,000 received by HoldCo in connection with a transaction resulting in a change of control of the Partnership, and (ii) 2% of the portion of any interim quarterly distribution received by HoldCo in excess of $1,250,000.

Our Revenues

Our revenues consist of (i) terminalling and storage revenues, (ii) gathering, transportation and producer field services revenues and (iii) fuel surcharge revenues. For the each of the three and nine months ended September 30,2012, we derived approximately 26% of our revenues from services we provided to Vitol, with the remainder of our services being provided to third parties.

Terminalling and storage revenues consist of (i) storage service fees from actual storage used on a month-to-month basis; (ii) storage service fees resulting from short-term and long-term contracts for committed space that may or may not be utilized by the customer in a given month; and (iii) terminal throughput service charges to pump crude oil to connecting carriers or to deliver asphalt product out of our terminals. Terminal throughput service charges are recognized as the crude oil exits the terminal and is delivered to the connecting crude oil carrier or third-party terminal and as the asphalt product is delivered out of our terminal. Storage service revenues are recognized as the services are provided on a monthly basis. We earn terminalling and storage revenues in two of our segments: (i) crude oil terminalling and storage services, and (ii) asphalt services.

As of November 2, 2012, we have approximately 5.4 million barrels of crude oil storage under service contracts with remaining terms ranging from month-to-month to 33 months, including 4.1 million barrels under contract to Vitol. As of November 2, 2012, we had 0.8 million barrels of crude oil storage with terms expiring at the end of 2012 and an additional 0.6 million barrels of crude oil storage with month-to-month terms. We are in negotiations to contract the remaining storage capacity; however, there is no certainty that contracts will be renewed, or, if renewed, will be at the same or similar rates with the expiring contracts. If we are unable to renew the majority of the expiring storage contracts, we may experience lower utilization of our assets 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, results of operations and ability to conduct our business.

We have long-term contracts in place for 42 of our 44 asphalt facilities.  The leases and storage agreements related to these facilities have various expiration dates that extend to the end of 2018. 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.

Gathering and transportation services revenues consist of service fees recognized for the gathering of crude oil for our customers and the transportation of crude oil to refiners, to common carrier pipelines for ultimate delivery to refiners, or to terminalling and storage facilities owned by us and others. Revenue for the gathering and transportation of crude oil is recognized when the service is performed and is based upon regulated and non-regulated tariff rates and the related transport volumes.  Producer field services revenue consists of a number of services ranging from gathering condensates from natural gas producers to hauling produced water to disposal wells.  Revenue for producer field services is recognized when the service is performed. We earn gathering and transportation revenues in two of our segments: (i) crude oil pipeline services, and (ii) crude oil trucking and producer field services.

During the three months ended September 30,2012, we transported approximately 68 thousand barrels per day on our pipelines, of which Vitol consists of 32% of volumes transported. Additionally, since the beginning of 2012, we have been evaluating our gathering systems located in Oklahoma to determine whether or not they are economically feasible to continue to operate after taking into consideration transported volumes, ongoing maintenance costs and risk. As a result we have idled approximately 100 miles of gathering pipeline that we have determined not economically viable, and we recognized a $1.0 million impairment charge related to these assets in the second quarter of 2012. The significant majority of any volumes that were displaced as a result of idling the pipeline has been retained by our crude oil transport trucks. We do not anticipate the idling of this gathering pipeline to have a significant impact on the overall future results of our operations.

As of September 30, 2012, we were transporting approximately 57 thousand barrels per day on our crude transport trucks, of which Vitol consists of approximately 46% of volumes transported. While we see opportunity to increase the utilization of our crude oil trucking and producer field services assets due to high demand for our services in the markets we currently serve, demand outpaces supply for qualified drivers in this industry and is delaying our realization of complete utilization of these assets.  We are actively pursuing additional drivers, and we anticipate increased utilization of these assets for the remainder of 2012.  However, there can be no assurance that our efforts will be successful.  

Fuel surcharge revenues are comprised of revenues recognized for the reimbursement of fuel and power consumed to operate the our asphalt product storage tanks and terminals.  We recognize fuel surcharge revenues in the period in which the

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related fuel and power expenses are incurred.

Our Expenses

Operating and general and administrative expenses related to our business remained relatively consistent during the first nine months of 2012 as compared to the same period in 2011, and we expect to incur a similar level of expenses in the fourth quarter of 2012, however, the employment of our new Chief Executive Officer and the resignation of our former President and Chief Operating Officer will result in incremental expenses. 

We currently anticipate maintenance capital expenditures to be approximately $10.0 million to $11.0 million in 2012, of which we have spent $6.9 million as of September 30, 2012. Our interest expense decreased by $6.2 million during the three months ended September 30, 2012 as compared to the three months ended September 30, 2011 primarily as a result of our redeeming $50.0 million of subordinated convertible debentures with proceeds from the rights offering conducted in the fourth quarter of 2011 and the $4.5 million decrease in non-cash interest expense due to the amortization of the associated debt discount incurred in 2011.

Income Taxes

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

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

• taxable income projections in future years,

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

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

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

Given that our subsidiary that is taxed as a corporation has limited earnings history for purposes of determining the likelihood of realizing the benefits of the deferred tax assets, we have provided a full valuation allowance against our deferred tax asset as of September 30, 2012.

Distributions

We did not make a distribution to our common unitholders or subordinated unitholders from May 15, 2008 through February 13, 2012 due, in part, to the events of default that existed under our former credit agreement, restrictions under such credit agreement, and the uncertainty of our future cash flows relating to SemCorp’s bankruptcy filings.  Our unitholders will be required to pay taxes on their share of our taxable income even though they did not receive a distribution for the quarters ended June 30, 2008 through September 31, 2011.  We resumed distributions for common units on February 14, 2012 for the quarter ended December 31, 2011.  The amount of distributions paid and the decision to make any distribution is determined by our General Partner’s board of directors (the “Board”), which has broad discretion to establish cash reserves for the proper conduct of our business and for future distributions to our unitholders. In addition, our cash distribution policy is subject to restrictions on distributions under our credit facility. 

On October 23, 2012, the Board approved a distribution of $0.17875 per Preferred Unit, or a total distribution of $5.4

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million.  We will pay this distribution on the preferred units on November 14, 2012 to Preferred Unitholders of record as of November 2, 2012.

In addition, we declared a cash distribution of $0.1125 per unit on our outstanding common units, an increase of 2.3% over the previous quarter's distribution. The distribution will be paid on November 14, 2012 to unitholders of record on November 2, 2012. The distribution is for the three months ended September 30,2012. The total distribution to be paid will be approximately $2.7 million, with approximately $2.6 million and $0.1 million to be paid to the Partnership’s common unitholders and general partner, respectively, and less than $0.1 million to be paid to phantom and restricted unitholders pursuant to awards granted under the Partnership’s long-term incentive plan.

Vitol Storage Agreements

On June 1, 2012, the crude oil storage services agreement with Vitol entered into in 2008 expired according to its terms. In anticipation of such expiration, we entered into two new crude oil storage services agreements with Vitol under which we began providing additional crude oil storage services to Vitol effective June 1, 2012. Service revenues under the first agreement are based on the one million barrels of storage capacity of the crude oil storage tanks that are dedicated to Vitol under the service agreement. The initial term of the first agreement is from June 1, 2012 through June 1, 2013. Service revenues under the second agreement are based on the 500,000 barrels of storage capacity of the crude oil storage tanks that are dedicated to Vitol under the service agreement. The initial term of the second agreement is from June 1, 2012 through December 1, 2012.

During the third quarter of 2012, the Partnership entered into another 6-month storage agreement (the “Vitol September 2012 Storage Agreement”) with Vitol effective September 1, 2012. The Partnership believes that the rates it charges Vitol under this agreement is fair and reasonable to the Partnership and its unitholders and is comparable with the rates the Partnership charges third parties. The Board’s conflicts committee reviewed and approved this agreement in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of the partnership agreement. Service revenues under the Vitol September 2012 Storage Agreement are based on the 500,000 barrels of storage capacity of the crude oil storage tanks that are dedicated to Vitol under the agreement. The initial term of the Vitol September 2012 Storage Agreement is from September 1, 2012 to March 1, 2013. The Partnership generated revenues under this agreement of approximately $0.2 million for each of the three and nine months ended September 30,2012.

Results of Operations

The table below summarizes our financial results for the three and nine months ended September 30,2011 and 2012:

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	Three months ended September 30,					Nine months ended September 30,
	2011			2012		2011			2012
	(in thousands)
Service revenues:
Crude oil terminalling and storage revenues:
Third party	$	2,941		$	3,278	$	8,316		$	9,009
Related party	6,683			5,260		20,748			18,153
Total crude oil terminalling and storage	9,624			8,538		29,064			27,162
Crude oil pipeline services revenues:
Third party	4,408			4,216		13,301			12,274
Related party	1,220			1,742		3,401			4,252
Total crude oil pipeline services revenues	5,628			5,958		16,702			16,526
Crude oil trucking and producer field services revenues:
Third party	10,170			10,722		32,634			35,202
Related Party	3,484			5,195		7,228			11,754
Total crude oil trucking and producer field services revenues:	13,654			15,917		39,862			46,956
Asphalt services revenues:
Third party	17,605			16,581		45,497			44,359
Related party	—			132		—			457
Total asphalt services	17,605			16,713		45,497			44,816
Total revenues	46,511			47,126		131,125			135,460
Operating expenses:
Crude oil terminalling and storage	2,210			1,922		6,384			5,715
Crude oil pipeline services	5,035			6,108		16,245			17,505
Crude oil trucking and producer field services	12,777			14,974		38,906			42,063
Asphalt services	8,738			9,118		26,043			26,645
Total operating expenses	28,760			32,122		87,578			91,928
General and administrative expenses	4,679			4,119		14,065			13,608
Gain on sale of assets	1,143			46		1,852			5,265
Operating income	14,215			10,931		31,334			35,189
Other (income) expense:
Interest expense	9,120			2,909		27,284			8,877
Change in fair value of embedded derivative within convertible debt	(15,358		)	—		(20,224		)	—
Change in fair value of rights offering liability	(8,224		)	—		(1,838		)	—
Income tax expense	72			115		219			264
Net income	$	28,605		$	7,907	$	25,893		$	26,048

Three Months Ended September 30, 2012 Compared to the Three Months Ended September 30, 2011

Service revenues.  Service revenues include revenues from crude oil terminalling and storage services, crude oil pipeline services, crude oil trucking and producer field services and asphalt services.  Service revenues, including reimbursement revenues of $1.5 million and $1.9 million for the three months ended September 30, 2012 and 2011, respectively, for fuel and power, property tax, and insurance expenses related to the operations of our liquid asphalt facilities, were $47.1 million for the three months ended September 30, 2012, compared to $46.5 million for the three months ended September 30, 2011, an

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increase of $0.6 million, or 1%. 

Crude oil terminalling and storage revenue decreased by $1.1 million to $8.5 million for the three months ended September 30, 2012 compared to $9.6 million for the three months ended September 30, 2011 primarily as a result of lower renegotiated storage rates as well as a result of our dismantling two 55,000 barrel tanks in 2011.

Crude oil pipeline services revenue increased by $0.4 million to $6.0 million for the three months ended September 30, 2012 compared to $5.6 million for the three months ended September 30, 2011 primarily due to tariff rate increases and consulting revenues earned under our Shared Services Agreement with Vitol.

Crude oil trucking and producer field services revenue increased by $2.2 million to $15.9 million for the three months ended September 30, 2012 compared to $13.7 million for the three months ended September 30, 2011.  This increase is primarily the result of higher rates for the majority of our crude oil trucking service contracts that became effective August 1, 2011 as well as increased utilization of our trucking assets.

Our asphalt services revenue, including reimbursement of fuel and power, property tax and insurance premiums, decreased by $0.9 million to $16.7 million for the three months ended September 30, 2012 compared to $17.6 million for the three months ended September 30, 2011.  The decrease in revenue is primarily attributed to lower volumes of product throughput at our facilities and is a reflection of broader economic market conditions not specific to our facilities.

Operating expenses.   Operating expenses were $32.1 million for the three months ended September 30, 2012, compared to $28.8 million for the three months ended September 30, 2011, an increase of $3.3 million, or 11%.  

Crude oil terminalling and storage operating expenses decreased by $0.3 million to $1.9 million for the three months ended September 30, 2012 compared to $2.2 million for the three months ended September 30, 2011. This decrease is primarily attributed to lower storage tank maintenance costs and is driven by the timing of tank inspection activities.

Our crude oil pipeline services operating expenses increased by $1.1 million to $6.1 million for the three months ended September 30, 2012 compared to $5.0 million for the three months ended September 30, 2011.  This is primarily due to a $0.6 million increase in repair and maintenance expense attributed to pipeline leaks.

Our crude oil trucking and producer field services operating expenses increased by $2.2 million to $15.0 million for the three months ended September 30, 2012, compared to $12.8 million for the three months ended September 30, 2011. This increase was primarily driven by the increase in utilization of our trucking assets, which resulted in higher driver commissions, fuel and fleet maintenance costs.

Our asphalt operating expenses were $9.1 million for the three months ended September 30, 2012 compared to $8.7 million for the three months ended September 30, 2011. Compensation expense increased $0.2 million primarily as a result of switching one of our facilities from leased to operated and the related hiring of operational personnel.

General and administrative expenses.  General and administrative expenses decreased by $0.6 million, or 13%, to $4.1 million for the three months ended September 30, 2012, compared to $4.7 million for the three months ended September 30, 2011. This change is a result of a decrease of $0.6 million in legal and professional expenses. We currently anticipate incremental general and administrative expenses for the remainder of 2012 as a result of the employment of our new Chief Executive Officer and the resignation of our former President and Chief Operating Officer. 

Gain on sale of assets. In the three months ended September 30, 2011, we had gains on the sale of assets of $1.1 million primarily due to the sale of used equipment in our trucking and producer field services segment.

Interest expense.   Interest expense represents interest on borrowings under our credit facility as well as amortization of debt issuance costs and the debt discount related to the subordinated convertible debentures that were redeemed in November of 2011.  Interest expense decreased by $6.2 million to $2.9 million for the three months ended September 30, 2012 compared to $9.1 million for the three months ended September 30, 2011.   This decrease is primarily due to non-cash interest expense related to the subordinated convertible debentures, including the related debt discount, of $5.7 million for the three months ended September 30, 2011 whereas we had no related expense for the three months ended September 30, 2012 due to the redemption of the subordinated convertible debentures in the fourth quarter of 2011.  We also had a decrease of $0.2 million due to a decrease in the weighted average debt outstanding for the three months ended September 30, 2012 compared to the three months ended September 30, 2011.

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Other (income) expense.   Other (income)/expense for the three months ended September 30, 2011 included an increase of $8.2 million in the fair value of the rights offering liability and a decrease of $15.4 million in the fair value of the embedded derivative liability derived from the conversion option in the subordinated convertible debentures.

Nine Months Ended September 30, 2012 Compared to the Nine Months Ended September 30, 2011

Service revenues.  Service revenues include revenues from crude oil terminalling and storage services, crude oil pipeline services, crude oil trucking and producer field services and asphalt services.  Service revenues, including reimbursement revenues of $4.3 million and $5.4 million for the nine months ended September 30,2012 and 2011, respectively, for fuel and power, property tax, and insurance expenses related to the operations of our liquid asphalt facilities were $135.5 million for the nine months ended September 30,2012, compared to $131.1 million for the nine months ended September 30,2011, an increase of $4.4 million or 3%. 

Crude oil terminalling and storage revenue decreased by $1.9 million to $27.2 million for the nine months ended September 30,2012 compared to $29.1 million for the nine months ended September 30,2011 as a result of lower renegotiated storage rates as well as a result of our dismantling two 55,000 barrel tanks in 2011.

Crude oil pipeline services revenue decreased by $0.2 million to $16.5 million for the nine months ended September 30,2012 compared to $16.7 million for the nine months ended September 30,2011. In the nine months ended September 30, 2011, we earned approximately $1.7 million of revenue related to reimbursed pipeline expense projects while we did not have any material reimbursable projects during the first nine months of 2012. This decrease is offset by additional revenue as a result of increased utilization of our pipeline services assets, as well as consulting revenues of $0.3 million for the nine months ended September 30, 2012 earned through our Shared Services Agreement with Vitol.

Crude oil trucking and producer field services revenue increased by $7.1 million to $47.0 million for the nine months ended September 30,2012 compared to $39.9 million for the nine months ended September 30,2011.  This increase is primarily the result of both higher rates for the majority of our crude oil trucking service contracts that became effective August 1, 2011 and increased utilization of our trucking assets.

Our asphalt services revenue, including reimbursement of fuel and power, property tax and insurance premiums, decreased by $0.7 million to $44.8 million for the nine months ended September 30,2012 compared to $45.5 million for the nine months ended September 30,2011.  The decrease in revenue is primarily attributed to lower volumes of product throughput at our facilities and is a reflection of broader economic market conditions not specific to our facilities.

Operating expenses.   Operating expenses were $91.9 million for the nine months ended September 30,2012, compared to $87.6 million for the nine months ended September 30,2011, an increase of $4.3 million, or 5%.  

Crude oil terminalling and storage operating expenses decreased $0.7 million to $5.7 million for the nine months ended September 30,2012 compared to $6.4 million for the nine months ended September 30,2011.  This decrease is primarily attributed to lower storage tank maintenance costs and is driven by the timing of tank inspection activities.

Our crude oil pipeline services operating expenses increased $1.3 million to $17.5 million for the nine months ended September 30,2012 compared to $16.2 million for the nine months ended September 30,2011.  In the second quarter of 2012, we idled approximately 100 miles of gathering lines associated with our Mid-Continent pipeline system, and, as a result, we recognized a $1.0 million impairment charge related to these assets in nine months ended September 30, 2012.

Our crude oil trucking and producer field services operating expenses increased by $3.2 million to $42.1 million for the nine months ended September 30,2012, compared to $38.9 million for the nine months ended September 30,2011.  This increase was primarily driven by the increase in utilization of our trucking assets, which resulted in higher driver commissions, fuel and fleet maintenance costs.

Our asphalt operating expenses increased by $0.6 million to $26.6 million for the nine months ended September 30,2012 compared to $26.0 million for the nine months ended September 30,2011. We incurred an incremental $0.6 million in maintenance and repair expenses in the nine months ended September 30,2012 compared to the nine months ended September 30,2011 as a result of a tank inspection program that we implemented in the first quarter of 2011 in response to new regulation of the asphalt industry. We also incurred additional compensation costs of $0.6 million for the nine months ended September 30,2012 primarily as a result of switching one of our facilities from leased to operated and the related hiring of operational personnel. These increases were offset by decreases in fuel expenses of $0.9 million.

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General and administrative expenses.  General and administrative expenses decreased by $0.5 million, or 4%, to $13.6 million for the nine months ended September 30,2012, compared to $14.1 million for the nine months ended September 30,2011. This decrease is primarily attributed to a decrease in legal expenses. We currently anticipate incremental general and administrative expenses for the remainder of 2012 as a result of the employment of our new Chief Executive Officer and the resignation of our former President and Chief Operating Officer. 

Gain on sale of assets. In the nine months ended September 30,2012, we had gains on the sale of assets of $5.3 million. The gains are primarily a result of the sale of 60,000 barrels of excess crude oil linefill attributed to our Longview pipeline system in East Texas. The linefill was sold to Vitol for the market price for East Texas crude of $98.96 per barrel. This transaction resulted in a gain of approximately $4.5 million. The remaining gain on sale of assets is attributed to the sale of used equipment in our trucking and producer field services segment.

Interest expense.   Interest expense represents interest on borrowings under our credit facility as well as amortization of debt issuance costs and the debt discount related to the subordinated convertible debentures that were redeemed in November of 2011.  Interest expense decreased by $18.4 million to $8.9 million for the nine months ended September 30,2012 compared to $27.3 million for the nine months ended September 30,2011.   This decrease is primarily due to non-cash interest expense related to the subordinated convertible debentures, including the related debt discount, of $17.1 million for the nine months ended September 30,2011 whereas we had no related expense for the nine months ended September 30,2012 due to the redemption of the subordinated convertible debentures in the fourth quarter of 2011.  We also had a decrease of $0.8 million due to a decrease in the weighted average debt outstanding for the nine months ended September 30,2012 compared to the nine months ended September 30,2011.

Other (income) expense.   Other (income)/expense for the nine months ended September 30, 2011 included a decrease of $20.2 million in the fair value of the rights offering liability and a decrease of $1.8 million in the fair value of the embedded derivative liability derived from the conversion option in the subordinated convertible debentures.

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 as defined by Item 303 of Regulation S-K.

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 30,2011 and 2012:

	Nine months ended September 30,
	2011			2012
	(in millions)
Net cash provided by operating activities	$	31.8		$	46.5
Net cash used in investing activities	(11.6		)	(11.3		)
Net cash used in financing activities	(24.0		)	(31.2		)

Operating Activities.  Net cash provided by operating activities was $46.5 million for the nine months ended September 30,2012, as compared to $31.8 million for the nine months ended September 30,2011.  While net income increased $0.2 million for the nine months ended September 30,2012 compared to the nine months ended September 30,2011, net income for the nine months ended September 30, 2011 was impacted by $22.1 million in non-cash income related to changes in the fair value of the embedded derivative within convertible debt and the fair value of the contingent dividend. An increase in cash flows provided by changes in working capital of $8.4 million for the nine months ended September 30,2012 compared to the nine months ended September 30,2011 offsets that increase.

Investing Activities.  Net cash used in investing activities was $11.3 million for the nine months ended September 30,2012,

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as compared to $11.6 million of net cash used for the nine months ended September 30,2011.  The decrease in cash used in investing activities was primarily the result of an increase of $5.1 million in proceeds from the sale of assets in the nine months ended September 30,2012 and was offset by a $5.0 million increase in capital expenditures.

Financing Activities.  Net cash used in financing activities was $31.2 million for the nine months ended September 30,2012, as compared to $24.0 million for the nine months ended September 30,2011.  The increase in net cash used in financing activities for the nine months ended September 30,2012 is primarily the result of an increase of $15.7 million in distributions to our unitholders and a decrease in net repayments on long term debt of $8.9 million.  

Our Liquidity and Capital Resources

Cash flow from operations and our credit facility are our primary sources of liquidity. At September 30, 2012, we had approximately $81.3 million of availability under our revolving credit facility.  As of November 2, 2012, we have aggregate unused credit availability under our revolving credit facility of approximately $86.4 million and cash on hand of approximately $5.9 million.  

Capital Requirements. Our capital requirements consist of the following:

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

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

Expansion capital expenditures for organic growth projects totaled $11.8 million in the nine months ended September 30,2012, compared to $6.0 million in the nine months ended September 30,2011.  We currently expect expansion capital expenditures for organic growth projects to be approximately $18.0 million to $20.0 million in 2012.  Maintenance capital expenditures totaled $6.9 million in the nine months ended September 30,2012 compared to $7.7 million in the nine months ended September 30,2011.  We currently expect maintenance capital expenditures to be approximately $10.0 million to $11.0 million in 2012.

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

Description of Credit Facility.  On October 25, 2010, we entered into a new credit agreement, which we refer to as our credit agreement.  Our credit agreement includes a $200.0 million term loan facility and, after giving effect to an April 5, 2011 amendment, a $95.0 million revolving credit facility.  Vitol is a lender under our credit agreement and has committed to loan us $15.0 million pursuant to such agreement.  The proceeds of loans made under our credit agreement may be used for working capital and other general corporate purposes.

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

Our credit agreement includes procedures for adding financial institutions as revolving lenders or for increasing the revolving commitment of any currently committed revolving lender subject to an aggregate maximum of $200.0 million for all revolving loan commitments under our credit agreement.

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

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agreement).  These mandatory prepayments will be applied to the term loan under our credit agreement until it is repaid in full, then applied to reduce commitments under the revolving loan facility.

Through May 15, 2011, borrowings under our credit agreement bore interest, at our option, at either (i) the ABR (the highest of the administrative agent’s prime rate, the federal funds rate plus 0.5%, or the one-month eurodollar rate (as defined in the credit agreement) plus 1%), plus an applicable margin of 3.25%, or (ii) the eurodollar rate plus an applicable margin of 4.25%.  

After May 15, 2011, the applicable margin for loans accruing interest based on the ABR ranges from 3.0% to 3.5%, and the applicable margin for loans accruing interest based on the eurodollar rate ranges from 4.0% to 4.5%, in each case depending on our consolidated total leverage ratio (as defined in the credit agreement).  We pay a per annum fee on all letters of credit issued under the credit agreement, which fee equals the applicable margin for loans accruing interest based on the eurodollar rate, and we pay a commitment fee of 0.5% per annum on the unused availability under the credit agreement.  The credit agreement does not have a floor for the ABR or the eurodollar rate.  In connection with entering into our credit agreement, we paid certain upfront fees to the lenders thereunder, and we paid certain arrangement and other fees to the arranger and administrative agent of our credit agreement.  Vitol received its pro rata portion of such fees as a lender under our credit agreement.  During the three and nine months ended September 30,2012, our weighted average interest rate was 5.46% and 5.52%, respectively, including interest under the throughput capacity agreement with Vitol related to our Eagle North pipeline system and the amortization of debt issuance costs, resulting in interest expense of approximately $2.9 million and $8.9 million, respectively. 

Our credit agreement includes financial covenants that are 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 4.50 to 1.00 for the fiscal quarter ending September 30, 2012 and each fiscal quarter thereafter. The minimum permitted consolidated interest coverage ratio (as defined in our credit agreement) is 3.00 to 1.00 for the fiscal quarter ending September 30, 2012 and each fiscal quarter thereafter.

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

• create, issue, incur or assume indebtedness;

• create, incur or assume liens;

• engage in mergers or acquisitions;

• sell, transfer, assign or convey assets;

• repurchase our partnership’s equity, make distributions to 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 our partnership agreement.

At September 30, 2012, our leverage ratio was 2.95 to 1.00 and the interest coverage ratio was 6.83 to 1.00.  We were in compliance with all covenants of our credit agreement as of September 30, 2012.

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

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any reserves for the proper conduct of our business.

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

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

• failure to meet the quarterly financial covenants;

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

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

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

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

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

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

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

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

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

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

Contractual Obligations. A summary of our contractual cash obligations over the next several fiscal years, as of September 30, 2012, 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)	$	232.5	$	9.4	$	223.1	$	—	$	—
Operating lease obligations	14.4		4.9		6.7		1.9		0.9
Related party throughput capacity agreement(2)	3.5		2.1		1.4		—		—
Non-compete agreement(3)	0.2		0.1		0.1		—		—
Employee contract obligations(4)	0.2		0.1		0.1		—		—

____________________

(1) Represents required future principal repayments of borrowings of $213.0 million and variable rate interest payments of $19.5 million.  At September 30, 2012, our borrowings had an interest rate of approximately 4.22%. This interest rate was used to calculate future interest payments.  All amounts outstanding under our credit agreement mature in October 2014.  

(2) Represents required future repayments of the Vitol prepaid fee related to the throughput capacity agreement for our Eagle North pipeline system of $3.1 million and interest of $0.4 million.  This agreement matures at December 31, 2014.

(3) Represents required future payments under a non-compete agreement related to our acquisition of certain field services assets.

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

Recent Accounting Pronouncements

For information regarding recent accounting developments that may affect our future financial statements, see Note 15 of the Notes to Unaudited Consolidated Financial Statements included in Part I, Item 1 of this quarterly report.

Item 3.    Quantitative and Qualitative Disclosures about Market Risk

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

As of November 2, 2012 we had $200.0 million outstanding under our credit facility that was subject to a variable interest rate.  Until May 15, 2011, borrowings under our credit agreement bore interest, at our option, at either (i) the ABR (the highest of the administrative agent’s prime rate, the federal funds rate plus 0.5%, or the one-month eurodollar rate (as defined in our credit agreement) plus 1.0%), plus an applicable margin of 3.25%, or (ii) the eurodollar rate plus an applicable margin of 4.25%.  After May 15, 2011, the applicable margin for loans accruing interest based on the ABR ranges from 3.0% to 3.5%, and the applicable margin for loans accruing interest based on the eurodollar rate ranges from 4.0% to 4.5%, in each case depending on our consolidated total leverage ratio (as defined in our credit agreement).  

During the three and nine months ended September 30,2012, our weighted average interest rate was 5.46% and 5.52%, respectively, including interest under the throughput capacity agreement with Vitol related to our Eagle North pipeline system and the amortization of debt issuance costs, resulting in interest expense of approximately $2.9 million and $8.9 million, 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. Based on borrowings as of September 30, 2012 and the terms of our credit agreement, an increase or decrease of 100 basis points in the interest rate would result in increased or decreased annual interest expense of approximately $2.1 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, 2012, 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, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 

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Item 5.    Other Information

Credit Agreement Amendment

On November 2, 2012, we amended our credit facility to permit Mark Hurley, our new chief executive officer, to receive a non-voting economic interest in HoldCo. Mr. Hurley’s interest in HoldCo will vest over a five year period and entitle Mr. Hurley, to the extent vested, to (i) 2% of the total amount of proceeds and/or distributions in excess of $100,000,000 received by HoldCo in connection with a transaction resulting in a change of control of the Partnership, and (ii) 2% of the portion of any interim quarterly distribution received by HoldCo in excess of $1,250,000.

The foregoing description is a summary of the credit facility amendment and is qualified in its entirety by reference to the credit facility amendment, a copy of which is included as Exhibit 10.5 to this Quarterly Report on Form 10-Q.

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PART II.                       OTHER INFORMATION

Item 1.    Legal Proceedings

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

Item 1A.    Risk Factors

Information about risk factors for the three months ended September 30, 2012 does not differ materially from that set forth in Part I, Item 1A, of our Annual Report on Form 10-K for the year ended December 31, 2011.

Item 6.    Exhibits

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

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		BLUEKNIGHT ENERGY PARTNERS, L.P.
		By:	Blueknight Energy Partners, G.P., L.L.C
			its General Partner
Date:	November 6, 2012	By:	/s/ Alex G. Stallings
			Alex G. Stallings
			Chief Financial Officer and Secretary
Date:	November 6, 2012	By:	/s/ James R. Griffin
			James R. Griffin
			Chief Accounting Officer

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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	Fourth Amended and Restated Agreement of Limited Partnership of the Partnership, dated September 14, 2011 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed September 14, 2011, 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).
10.1	Employment Agreement, dated October 4, 2012, between Mark Hurley and BKEP Management, Inc. (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K/A, dated September 13, 2012 and filed October 4, 2012, and incorporated herein by reference).
10.2	Employee Phantom Unit Agreement dated October 4, 2012, between Mark Hurley and the General Partner (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K/A, dated September 13, 2012 and filed October 4, 2012, and incorporated herein by reference).
10.3	Shared Services Agreement, dated to be effective as of August 1, 2012, by and between the Partnership and Vitol Inc. (filed as Exhibit 10.3 to the Partnership’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 and filed August 7, 2012, and incorporated herein by reference).
10.4	Crude Oil Storage Services Agreement, dated to be effective as of September 1, 2012, by and between BKEP Pipeline, LLC and Vitol Inc. (filed as Exhibit 10.4 to the Partnership’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 and filed August 7, 2012, and incorporated herein by reference).
10.5*	Second Amendment to Credit Agreement, dated as of November 2, 2012, among the Partnership, the lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent.
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.”
101#	The following financial information from Blueknight Energy Partners, L.P.’s Annual Report on Form 10-Q for the quarter ended September 30, 2012, formatted in XBRL (eXtensible Business Reporting Language): (i) Document and Entity Information; (ii) Consolidated Balance Sheets as of December 31, 2011 and September 30, 2012; (iii) Consolidated Statements of Operations for the three and nine months ended September 30, 2011 and 2012; (iv)Consolidated Statement of Changes in Partners’ Capital for the nine months ended September 30, 2012; (v) Consolidated Statements of Cash Flows for the nine months ended September 30, 2011 and 2012; and (vi) Notes to Consolidated Financial Statements.

____________________

* Filed herewith.

# Furnished herewith.

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EX-10.5

Exhibit 10.5

SECOND AMENDMENT

TO

CREDIT AGREEMENT

dated as of

November 2, 2012

among

Blueknight Energy Partners, L.P.,

as Borrower,

The Lenders Party Hereto

and

JPMORGAN CHASE BANK, N.A.,

as Administrative Agent

SECOND AMENDMENT CREDIT AGREEMENT

THIS SECOND Amendment to Credit Agreement (this “Second Amendment”) dated as of November 2, 2012, is among BLUEKNIGHT ENERGY PARTNERS, L.P., a Delaware limited partnership (the “Borrower”); JPMORGAN CHASE BANK, N.A., as administrative agent (in such capacity, together with its successors in such capacity, the “Administrative Agent”) for the lenders party to the Credit Agreement referred to below (collectively, the “Lenders”); and the undersigned Lenders.

R E C I T A L S

The Borrower, the Administrative Agent and the Lenders are parties to that certain Credit Agreement dated as of October 25, 2010 (as amended by the First Amendment to Credit Agreement dated as of April 1, 2011, the “Credit Agreement”), pursuant to which the Lenders have made certain extensions of credit available to the Borrower.

NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

Section 1.Defined Terms. Each capitalized term used herein but not otherwise defined herein has the meaning given such term in the Credit Agreement. Unless otherwise indicated, all references to Sections and Articles in this Second Amendment refer to Sections and Articles of the Credit Agreement.

Section 2.Amendments to Credit Agreement.

2.1    Amendment to Section 1.1. The definition of “Change of Control” is hereby amended by adding the following at the end thereof:

Notwithstanding anything to the contrary contained in this definition, the direct or indirect issuance to and ownership by Mr. Mark Hurley (and his successors and assigns) of a non-voting economic interest in the General Partner shall not constitute a “Change of Control”.

Section 3.Conditions Precedent. This Second Amendment shall not become effective until the date on which each of the following conditions is satisfied (or waived in accordance with Section 10.1 of the Credit Agreement) (the “Effective Date”):

3.1    The Administrative Agent shall have received from the Required Lenders and the Borrower, counterparts (in such number as may be requested by the Administrative Agent) of this Second Amendment signed on behalf of such Persons.

3.2    The Administrative Agent shall have received such other documents as the Administrative Agent or special counsel to the Administrative Agent may reasonably request.

3.3    No Default shall have occurred and be continuing, after giving effect to the terms of this Second Amendment.

Section 4.Miscellaneous.

4.1    Confirmation. The provisions of the Credit Agreement, as amended by this Second Amendment, shall remain in full force and effect following the effectiveness of this Second Amendment.

4.2    Ratification and Affirmation; Representations and Warranties. The Borrower hereby: (a) acknowledges the terms of this Second Amendment; (b) ratifies and affirms its obligations under, and acknowledges, renews and extends its continued liability under, each Loan Document to which it is a party and agrees that each Loan Document to which it is a party remains in full force and effect, except as expressly amended hereby, after giving effect to the amendments contained herein; (c) agrees that from and after the Effective Date each reference to the Credit Agreement in the Guarantee and Collateral Agreement, the Mortgages and the other Loan Documents shall be deemed to be a reference to the Credit Agreement, as amended by this Second Amendment; and (d) represents and warrants to the Lenders that as of the date hereof, after giving effect to the terms of this Second Amendment: (i) all of the representations and warranties made by the Borrower contained in each Loan Document to which it is a party are true and correct in all material respects, unless such representations and warranties are stated to relate to a specific earlier date, in which case, such representations and warranties shall continue to be true and correct in all material respects as of such earlier date and (ii) no Default has occurred and is continuing.

4.3    Loan Document. This Second Amendment is a “Loan Document” as defined and described in the Credit Agreement and all of the terms and provisions of the Credit Agreement relating to Loan Documents shall apply hereto.

4.4    Counterparts. This Second Amendment may be executed by one or more of the parties hereto in any number of separate counterparts, and all of such counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of this Second Amendment by facsimile or email transmission shall be effective as delivery of a manually executed counterpart hereof.

4.5    NO ORAL AGREEMENT. THIS SECOND AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN DOCUMENTS EXECUTED IN CONNECTION HEREWITH AND THEREWITH REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR UNWRITTEN ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO ORAL AGREEMENTS BETWEEN THE PARTIES.

4.6    GOVERNING LAW. THIS SECOND AMENDMENT (INCLUDING, BUT NOT LIMITED TO, THE VALIDITY AND ENFORCEABILITY HEREOF) SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

[SIGNATURES BEGIN NEXT PAGE]

IN WITNESS WHEREOF, the parties hereto have caused this Second Amendment to be duly executed as of the date first written above.

BLUEKNIGHT ENERGY PARTNERS, L.P.
By:	Blueknight Energy Partners G.P., L.L.C., its
	general partner
By:	/s/ Alex G. Stallings
Name:	Alex G. Stallings
Title:	Chief Financial Officer

Signature Page to Second Amendment to

Credit Agreement

S-1

JPMORGAN CHASE BANK, N.A., as Administrative Agent and as a Lender
By:	/s/ Robert Traband
Name:	Robert Traband
Title:	Managing Director

Signature Page to Second Amendment to

Credit Agreement

S-2

CREDIT AGRICOLE CORPORATE AND INVESTMENT BANK, as a Lender
By:	/s/ Michel Kermarrec
Name:	Michel KERMARREC
Title:	Vice President
By:	/s/ Mark Lvoff
Name:	Mark LVOFF
Title:	Managing Director

Signature Page to Second Amendment to

Credit Agreement

S-3

LLOYDS TBS BANK PLC, as a Lender
By:	/s/ Stephen Giacolone
Name:	Stephen Giacolone
Title:	Assistant Vice President - G011
By:	/s/ Dennis McClellan
Name:	Dennis McClellan
Title:	Assistant Vice President - M040

Signature Page to Second Amendment to

Credit Agreement

S-4

SOCIETE GENERALE, as a Lender
By:	/s/ Chad Clark
Name:	Chad Clark
Title:	Managing Director

Signature Page to Second Amendment to

Credit Agreement

S-5

NATIXIS, as a Lender
By:	/s/ Daniel Payer
Name:	Daniel Payer
Title:	Managing Director
By:	/s/ Louis P. Laville, III
Name:	Louis P. Laville, III
Title:	Managing Director

Signature Page to Second Amendment to

Credit Agreement

S-6

CITIBANK, N.A., as a Lender
By:	/s/ Clinton Gerst
Name:	Clinton Gerst
Title:	Managing Director

Signature Page to Second Amendment to

Credit Agreement

S-7

MIZUHO CORPORATE BANK LTD., as a Lender
By:	/s/ Leon Mo
Name:	Leon Mo
Title:	Authorized Signatory

Signature Page to Second Amendment to

Credit Agreement

S-8

WELLS FARGO BANK, N.A., as a Lender
By:	/s/ David C. Brooks
Name:	David C. Brooks
Title:	Director

Signature Page to Second Amendment to

Credit Agreement

S-9

VITOL REFINING, B.V., as a Lender

By:

Name:

Title:

Signature Page to Second Amendment to

Credit Agreement

S-10

COOPERATIEVE CENTRALE RAIFFEISEN-BOERENLEENBANK B.A.,
“RABOBANK NEDERLAND”, NEW YORK BRANCH, as a Lender
By:	/s/ Kristin Carlton Malo
Name:	Kristin Carlton Malo
Title:	Executive Director
By:	/s/ Rodney P. Hutchinson
Name:	Rodney P. Hutchinson
Title:	Executive Director

Signature Page to Second Amendment to

Credit Agreement

S-11

LIBERTY ISLAND FUNDING 2011-1 LTD., as a Lender

By:

Name:

Title:

Signature Page to Second Amendment to

Credit Agreement

S-12

EX-31.1

Exhibit 31.1

CERTIFICATION

PURSUANT TO AND IN CONNECTION WITH THE REPORTS

TO BE FILED UNDER SECTION 13 AND 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Mark Hurley, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Blueknight Energy Partners, L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 6, 2012
/s/ Mark Hurley
Mark Hurley
Chief Executive Officer
Blueknight Energy Partners, G.P., L.L.C.,
general partner of Blueknight Energy Partners, L.P.

EX-31.2

Exhibit 31.2

CERTIFICATION

PURSUANT TO AND IN CONNECTION WITH THE REPORTS

TO BE FILED UNDER SECTION 13 AND 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Alex G. Stallings, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Blueknight Energy Partners, L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 6, 2012
/s/ Alex G. Stallings
Alex G. Stallings
Chief Financial Officer and Secretary of
Blueknight Energy Partners, G.P., L.L.C.,
general partner of Blueknight Energy Partners, L.P.

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002 (18 U.S.C. SECTION 1350)*

In connection with the Quarterly Report of Blueknight Energy Partners, L.P., a Delaware limited partnership (the “Partnership”), on Form 10-Q for the quarter ended September 30, 2012 as filed with the Securities and Exchange Commission (the “Report”), each of the undersigned, Mark Hurley, Chief Executive Officer of Blueknight Energy Partners G.P., L.L.C., and Alex G. Stallings, Chief Financial Officer and Secretary of Blueknight Energy Partners G.P., L.L.C., certifies, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), that to his knowledge:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Partnership.

/s/ Mark Hurley

Mark Hurley

Chief Executive Officer of

Blueknight Energy Partners G.P., L.L.C.,

general partner of Blueknight Energy Partners, L.P.

November 6, 2012

/s/ Alex G. Stallings

Alex G. Stallings

Chief Financial Officer and Secretary of

Blueknight Energy Partners G.P., L.L.C.,

general partner of Blueknight Energy Partners, L.P.

November 6, 2012

* A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request. The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Report.

XML

LONG-TERM INCENTIVE PLAN (Details) (USD $)	9 Months Ended		0 Months Ended	1 Months Ended		3 Months Ended	9 Months Ended	1 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 14, 2011 Plan [Member] Phantom common units [Member]	Mar. 31, 2012 Plan [Member] Phantom common units [Member]	Mar. 31, 2011 Plan [Member] Phantom common units [Member]	Sep. 30, 2012 Plan [Member] Phantom common units [Member]	Sep. 30, 2012 Plan [Member] Phantom common units [Member]	Sep. 30, 2012 Chief Executive Officer [Member] Plan [Member] Phantom common units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of units authorized			1,250,000			2,600,000	2,600,000
Number of additional units authorized			1,350,000
Value of award grants (in dollars)				$ 2,400,000	$ 2,500,000			$ 2,800,000
Vesting period								5 years
Unrecognized estimated compensation cost (in dollars)						2,700,000	2,700,000	2,794,577.27
Expected awards that wil be vested (as a percent)						87.00%	87.00%
Equity-based incentive compensation expense (in dollars)	$ 1,079,000	$ 377,000				$ 400,000	$ 1,100,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Number of Units, Nonvested, Beginning balance							307,151
Number of Units, Granted				351,300	299,900		851,300	500,000
Number of Units, Vested							10,000
Number of Units, Forfeited							56,400
Number of Units, Nonvested, Ending balance						1,092,051	1,092,051
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, Nonvested, Beginning balance (in dollars per unit)							$ 8.17
Weighted Average Grant Date Fair Value, Granted (in dollars per unit)				$ 6.76	$ 8.25		$ 6.09	$ 5.62
Weighted Average Grant Date Fair Value, Vested (in dollars per unit)							$ 8.25
Weighted Average Grant Date Fair Value, Forfeited (in dollars per unit)							$ 7.58
Weighted Average Grant Date Fair Value, Nonvested, Ending balance (in dollars per unit)						$ 6.58	$ 6.58

XML

SUBSEQUENT EVENTS (Details) (Chief Executive Officer [Member], HoldCo [Member], Subsequent Event [Member], USD $)	0 Months Ended
	Nov. 02, 2012
Subsequent Event [Line Items]
Chief Executive Officer Non Voting Economic Interest In Company Vesting Period	5 years
Non Voting Economic Interest In Company Percentage Of Total Proceeds And Or Distributions Received By Company In Connection With A Transaction Resulting In A Change Of Control Of The Partnership	2.00%
Chief Executive Officer Non Voting Economic Interest In Company Percentage Of Quarterly Distributions Received By Company	2.00%
Minimum Quarterly Distributions Received By Company Before Chief Executive Officer Non Voting Economic Interest In Company Percentage Of Quarterly Distributions Received By Company Applies	$ 1,250,000
Minimum [Member]
Subsequent Event [Line Items]
Total Proceeds And Or Distributions Received by Company Connection With Transaction Resulting In Change Of Control Of Partnership Before Non Voting Economic Interest In Company Percentage	$ 100,000,000

XML

DISTRIBUTIONS (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2012
Distributions	$ 2,700	$ 24,018
Common Unitholders [Member]
Distributions	2,600
General Partner Interest [Member]
Distributions	100
Phantom Share Units and Restricted Units [Member]
Distributions	100
Distributions approved [Member] | Series A Preferred Unitholders [Member]
Distributions	$ 5,400
Distribution Made to Member or Limited Partner, Distributions Declared (in dollars per unit)	$ 0.17875
Distributions approved [Member] | Common Unitholders [Member]
Distribution Made to Member or Limited Partner, Distributions Declared (in dollars per unit)	$ 0.1125
Distribution Made to Member or Limited Partner, Distributions Declared, Percentage Increase Over Previous Quarter Distribution	2.30%

XML

LONG-TERM INCENTIVE PLAN (Tables)

9 Months Ended

Sep. 30, 2012

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule Of Phantom Common Units And Restricted Common Units Activity

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

	Number of Units	Weighted Average Grant Date Fair Value
Nonvested at December 31, 2011	307,151	$	8.17
Granted	851,300	6.09
Vested	10,000	8.25
Forfeited	56,400	7.58
Nonvested at September 30, 2012	1,092,051	$	6.58

XML

FAIR VALUE MEASUREMENTS (Reconciliation of Changes in the Fair Value of the Partnership’s Financial Liabilities Classified as Level 3 in the Fair Value Hierarchy) (Details) (Fair Value, Inputs, Level 3 [Member], USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2011		Sep. 30, 2011
Fair Value, Inputs, Level 3 [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 39,511		$ 37,991
Total gains or losses (realized/unrealized):
Included in earnings	(23,582)		(22,062)
Included in other comprehensive income	0		0
Purchases, issuances, and settlements	(7,326)	[1]	(7,326)
Transfers in and/or out of Level 3	0		0
Ending Balance	8,603		8,603
The amount of total income for the period included in earnings attributable to the change in unrealized gains for liabilities still held at the reporting date	$ (8,224)		$ (1,838)

[1] As noted above, the Partnership reclassified the embedded derivative within subordinated convertible debentures to partners’ capital as of September 14, 2011.

XML

RELATED PARTY TRANSACTIONS (Vitol Storage Agreements and Vitol Master Lease Agreement) (Details) (USD $)	3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended			3 Months Ended	9 Months Ended		0 Months Ended	3 Months Ended		9 Months Ended		0 Months Ended	3 Months Ended	9 Months Ended	0 Months Ended	3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012 Vitol [Member]	Sep. 30, 2011 Vitol [Member]	Sep. 30, 2012 Vitol [Member]	Sep. 30, 2011 Vitol [Member]	Jun. 01, 2012 Vitol [Member] Contracts	Sep. 30, 2011 Vitol [Member] 2008 Vitol Storage Agreements [Member]	Sep. 30, 2012 Vitol [Member] 2008 Vitol Storage Agreements [Member]	Sep. 30, 2011 Vitol [Member] 2008 Vitol Storage Agreements [Member]	May 02, 2010 Vitol [Member] 2010 Vitol Storage Agreements [Member]	Sep. 30, 2012 Vitol [Member] 2010 Vitol Storage Agreements [Member]	Sep. 30, 2011 Vitol [Member] 2010 Vitol Storage Agreements [Member]	Sep. 30, 2012 Vitol [Member] 2010 Vitol Storage Agreements [Member]	Sep. 30, 2011 Vitol [Member] 2010 Vitol Storage Agreements [Member]	Jun. 01, 2012 Vitol [Member] Vitol 2012 12 Month Storage Agreement [Member] bbl	Sep. 30, 2012 Vitol [Member] Vitol 2012 12 Month Storage Agreement [Member]	Sep. 30, 2012 Vitol [Member] Vitol 2012 12 Month Storage Agreement [Member]	Jun. 01, 2012 Vitol [Member] Vitol 2012 6 Month Storage Agreement [Member] bbl	Sep. 30, 2012 Vitol [Member] Vitol 2012 6 Month Storage Agreement [Member]	Sep. 30, 2012 Vitol [Member] Vitol 2012 6 Month Storage Agreement [Member]	Sep. 30, 2012 Vitol [Member] Vitol September 2012 Storage Agreement [Member] bbl	Sep. 30, 2012 Vitol [Member] Vitol September 2012 Storage Agreement [Member]	Sep. 30, 2011 Vitol [Member] Vitol Master Lease Agreement [Member]	Sep. 30, 2011 Vitol [Member] Vitol Master Lease Agreement [Member]	Sep. 30, 2012 Vitol [Member] Vitol Master Lease Agreement [Member] Vehicles [Member] Minimum [Member]	Sep. 30, 2012 Vitol [Member] Vitol Master Lease Agreement [Member] Vehicles [Member] Maximum [Member]
Related Party Transaction [Line Items]
Related party revenue	$ 12,329,000	$ 11,387,000	$ 34,616,000	$ 31,377,000	$ 12,300,000	$ 11,400,000	$ 34,600,000	$ 31,400,000		$ 3,300,000	$ 5,500,000	$ 9,900,000		$ 2,800,000	$ 3,100,000	$ 8,700,000	$ 9,200,000		$ 1,400,000	$ 1,800,000		$ 700,000	$ 900,000	$ 200,000	$ 200,000
Number of new crude oil storage services agreements with Vitol (in contracts)									2
Initial term (in years)													5 years					12 months			6 months			6 months
Barrels of storage capacity of crude oil storage tanks dedicated to related party (in barrels)																		1,000,000			500,000			500,000
Automatic renewal period (in years)													1 year
Termination period by either party prior notice (in days)													90 days
Lease term (in months)																												36 months	84 months
Expenses from transactions with related party																										$ 100,000	$ 400,000

XML

RECENT EVENTS

9 Months Ended

Sep. 30, 2012

RECENT EVENTS [Abstract]

RECENT EVENTS

RECENT EVENTS

On September 13, 2012, the Partnership announced that the Board of Directors (the “Board”) of Blueknight Energy Partners G.P., L.L.C., the general partner of the Partnership (the “General Partner”), appointed Mr. Mark Hurley as the Chief Executive Officer of the General Partner, effective September 20, 2012. Mr. Hurley replaced Mr. James C. Dyer, whose intended resignation was previously announced by the Partnership.

XML

OPERATING SEGMENTS (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011		Sep. 30, 2012 Operating-segments		Sep. 30, 2011		Dec. 31, 2011
Segment Reporting Information [Line Items]
Number of operating segments (in operating segments)					4
Service revenue
Third party revenue	$ 34,797		$ 35,124		$ 100,844		$ 99,748
Related party revenue	12,329		11,387		34,616		31,377
Total revenue for reportable segments	47,126		46,511		135,460		131,125
Operating expenses (excluding depreciation and amortization)	26,330		23,109		74,754		70,512
Operating margin (excluding depreciation and amortization)	20,796	[1]	23,402	[1]	60,706	[1]	60,613	[1]
Total assets (end of period)	300,557		320,775		300,557		320,775		304,755
Reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes
Operating margin (excluding depreciation and amortization)	20,796	[1]	23,402	[1]	60,706	[1]	60,613	[1]
Depreciation and amortization	5,792		5,651		17,174		17,066
General and administrative expenses	4,119		4,679		13,608		14,065
Gain on sale of assets	46		1,143		5,265		1,852
Interest expense	2,909		9,120		8,877		27,284
Change in fair value of embedded derivative within convertible debt	0		(15,358)		0		(20,224)
Change in fair value of rights offering contingency	0		(8,224)		0		(1,838)
Income before income taxes	8,022		28,677		26,312		26,112
Crude Oil Terminalling and Storage Services [Member]
Service revenue
Third party revenue	3,278		2,941		9,009		8,316
Related party revenue	5,260		6,683		18,153		20,748
Total revenue for reportable segments	8,538		9,624		27,162		29,064
Operating expenses (excluding depreciation and amortization)	973		1,138		2,698		3,283
Operating margin (excluding depreciation and amortization)	7,565	[1]	8,486	[1]	24,464	[1]	25,781	[1]
Total assets (end of period)	68,870		75,304		68,870		75,304
Reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes
Operating margin (excluding depreciation and amortization)	7,565	[1]	8,486	[1]	24,464	[1]	25,781	[1]
Crude Oil Pipeline Services [Member]
Segment Reporting Information [Line Items]
Number of pipelines systems owned and operated (in pipeline systems)	3				3
Service revenue
Third party revenue	4,216		4,408		12,274		13,301
Related party revenue	1,742		1,220		4,252		3,401
Total revenue for reportable segments	5,958		5,628		16,526		16,702
Operating expenses (excluding depreciation and amortization)	4,776		3,813		13,626		12,610
Operating margin (excluding depreciation and amortization)	1,182	[1]	1,815	[1]	2,900	[1]	4,092	[1]
Total assets (end of period)	99,619		102,730		99,619		102,730
Reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes
Operating margin (excluding depreciation and amortization)	1,182	[1]	1,815	[1]	2,900	[1]	4,092	[1]
Crude Oil Trucking and Producer Field Services [Member]
Service revenue
Third party revenue	10,722		10,170		35,202		32,634
Related party revenue	5,195		3,484		11,754		7,228
Total revenue for reportable segments	15,917		13,654		46,956		39,862
Operating expenses (excluding depreciation and amortization)	14,508		12,486		40,877		37,706
Operating margin (excluding depreciation and amortization)	1,409	[1]	1,168	[1]	6,079	[1]	2,156	[1]
Total assets (end of period)	19,323		16,071		19,323		16,071
Reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes
Operating margin (excluding depreciation and amortization)	1,409	[1]	1,168	[1]	6,079	[1]	2,156	[1]
Asphalt Services [Member]
Segment Reporting Information [Line Items]
Number of terminalling and storage facilities providing asphalt product and residual fuel terminalling storage and blending services (in terminalling and storage facilities)	44				44
Number of states that Asphalt product and residual fuel terminalling, storage and blending services at its terminalling and storage facilities are provided (in states)	22				22
Service revenue
Third party revenue	16,581		17,605		44,359		45,497
Related party revenue	132		0		457		0
Total revenue for reportable segments	16,713		17,605		44,816		45,497
Operating expenses (excluding depreciation and amortization)	6,073		5,672		17,553		16,913
Operating margin (excluding depreciation and amortization)	10,640	[1]	11,933	[1]	27,263	[1]	28,584	[1]
Total assets (end of period)	112,745		126,670		112,745		126,670
Reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes
Operating margin (excluding depreciation and amortization)	$ 10,640	[1]	$ 11,933	[1]	$ 27,263	[1]	$ 28,584	[1]

[1] The following table reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes (in thousands): Three months ended September 30, Nine months ended September 30, 2011 2012 2011 2012Operating margin (excluding depreciation and amortization)$23,402$20,796 $60,613 $60,706Depreciation and amortization5,651 5,792 17,066 17,174General and administrative expenses4,679 4,119 14,065 13,608Gain on sale of assets1,143 46 1,852 5,265Interest expense9,120 2,909 27,284 8,877Change in fair value of embedded derivative within convertible debt(15,358) — (20,224) —Change in fair value of rights offering liability(8,224) — (1,838) —Income before income taxes$28,677 $8,022 $26,112 $26,312

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ORGANIZATION AND NATURE OF BUSINESS (Narrative) (Details)	9 Months Ended
	Sep. 30, 2012 Operating-segments States
ORGANIZATION AND NATURE OF BUSINESS [Abstract]
Number of states in which entity operates (in states)	23
Number of operating segments (in operating segments)	4

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INCOME TAXES (Tables)

9 Months Ended

Sep. 30, 2012

Income Tax Disclosure [Abstract]

Schedule of Deferred Tax Assets

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 at September 30, 2012 are presented below (dollars in thousands):

Deferred tax assets
Difference in bases of property, plant and equipment	$	1,140
Deferred tax asset	1,140
Less: valuation allowance	(1,140		)
Net deferred tax asset	$	—

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COMMITMENTS AND CONTINGENCIES (Details) (USD $)		0 Months Ended			2 Months Ended			0 Months Ended
	Feb. 06, 2012 Pending Litigation [Member] Boe	Jul. 11, 2011 Pending Litigation [Member] Previous Exxon Mobile Case [Member]	Jul. 11, 2011 Minimum [Member] Pending Litigation [Member] Exxon Mobile Case Involving Pipe Relocation [Member]	Feb. 06, 2012 Minimum [Member] Pending Litigation [Member] Positive Outcome of Litigation [Member]	Apr. 30, 2009 Oklahoma Department of Labor [Member] Dismissed [Member] Claimants contended the Partnership's general partner's failure to deliver certificates of phantom units within 60 days after vesting caused them damages and sought recovery of damages and penalties [Member]	Apr. 30, 2009 Oklahoma Department of Labor [Member] Dismissed [Member] Claimants alleged phantom units previously awarded to them vested upon the Change of Control that occurred in July 2008, related to Partnership's general partner's Long-Term Incentive Plan [Member] Plaintiffs	Apr. 30, 2009 Oklahoma Department of Labor [Member] Dismissed [Member] Claimant alleged that his phantom units vested upon his termination [Member] Plaintiffs	Oct. 22, 2010 Tulsa County [Member] Claimants alleged phantom units previously awarded to them vested upon the Change of Control that occurred in July 2008, related to Partnership's general partner's Long-Term Incentive Plan [Member]	Apr. 14, 2010 Tulsa County [Member] Claimants alleged phantom units previously awarded to them vested upon the Change of Control that occurred in July 2008, related to Partnership's general partner's Long-Term Incentive Plan [Member] Claimants	Jul. 08, 2009 Tulsa County [Member] Claimants alleged phantom units previously awarded to them vested upon the Change of Control that occurred in July 2008, related to Partnership's general partner's Long-Term Incentive Plan [Member] Plaintiffs	Jul. 13, 2012 Subsequent Event [Member] District Court of Woodward County, Oklahoma [Member] Pending Litigation [Member] Motor Vehicle Negligence Suit [Member] Person	Jul. 13, 2012 Subsequent Event [Member] District Court of Woodward County, Oklahoma [Member] Minimum [Member] Pending Litigation [Member] Motor Vehicle Negligence Suit [Member]
Loss Contingencies [Line Items]
Number of plaintiffs (in plaintiffs)						9	1			9
Claimants contended the Partnership's general partner's failure to deliver certificates for the phantom units after vesting, (in days) maximum					60 days
Damages sought		$ 1,900,000	$ 35,000		$ 2,000,000					$ 1,300,000		$ 75,000
Number of plaintiff settled with (in claimants)									7
Damages awarded									1,000,000
Attorneys' fees								200,000
Judgement seeking immediate return of crude cil Linefill belonging to company (in BOE)	140,000
Gain contingency, unrecorded amount				75,000
Loss Contingency, Number of Deaths Related to Court Case											1
Loss Contingency, Insurance Deductible Payment											$ 100,000

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PROPERTY, PLANT AND EQUIPMENT (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 411,209,000		$ 411,209,000		$ 401,657,000
Accumulated depreciation	(148,580,000)		(148,580,000)		(135,302,000)
Property, plant and equipment, net	262,629,000		262,629,000		266,355,000
Depreciation	5,800,000	5,600,000	17,100,000	17,000,000
Asset impairment charge	100,000		1,168,000	0
Land [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	16,355,000		16,355,000		16,601,000
Land improvements [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	5,980,000		5,980,000		5,671,000
Land improvements [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives (in years)			10 years
Land improvements [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives (in years)			20 years
Pipelines and facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	159,314,000		159,314,000		152,733,000
Pipelines and facilities [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives (in years)			5 years
Pipelines and facilities [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives (in years)			30 years
Storage and terminal facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	170,298,000		170,298,000		169,139,000
Storage and terminal facilities [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives (in years)			10 years
Storage and terminal facilities [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives (in years)			35 years
Transportation equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	19,088,000		19,088,000		20,615,000
Transportation equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives (in years)			3 years
Transportation equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives (in years)			10 years
Office property and equipment and other [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	26,528,000		26,528,000		22,901,000
Office property and equipment and other [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives (in years)			3 years
Office property and equipment and other [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives (in years)			20 years
Pipeline linefill and tank bottoms [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	5,993,000		5,993,000		7,458,000
Construction-in-progress [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 7,653,000		$ 7,653,000		$ 6,539,000

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DEBT (Credit Agreements) (Details) (USD $)	3 Months Ended		9 Months Ended				3 Months Ended	9 Months Ended			3 Months Ended	9 Months Ended		9 Months Ended			0 Months Ended		9 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011	Oct. 25, 2010 Secured Debt [Member]	Sep. 30, 2012 Revolving Credit Facility [Member]	Sep. 30, 2012 Revolving Credit Facility [Member]	Apr. 05, 2011 Revolving Credit Facility [Member]	Oct. 25, 2010 Revolving Credit Facility [Member]	Sep. 30, 2012 Vitol [Member]	Sep. 30, 2012 Vitol [Member]	Sep. 30, 2012 Vitol [Member] Revolving Credit Facility [Member]	Sep. 30, 2012 Vitol or Charlesbank [Member]	May 15, 2011 Federal funds rate [Member] Revolving Credit Facility [Member]	May 15, 2011 Eurodollar rate [Member] Revolving Credit Facility [Member]	May 15, 2011 Application margin [Member] Revolving Credit Facility [Member]	May 15, 2011 Eurodollar rate plus an applicable margin [Member] Revolving Credit Facility [Member]	Sep. 30, 2012 Minimum [Member] Applicable margin based on ABR [Member] Revolving Credit Facility [Member]	Sep. 30, 2012 Minimum [Member] Applicable margin based on Eurodollar rate [Member] Revolving Credit Facility [Member]	Sep. 30, 2012 Maximum [Member] Applicable margin based on ABR [Member] Revolving Credit Facility [Member]	Sep. 30, 2012 Maximum [Member] Applicable margin based on Eurodollar rate [Member] Revolving Credit Facility [Member]	Nov. 02, 2012 Subsequent Event [Member] Revolving Credit Facility [Member]	Nov. 02, 2012 Subsequent Event [Member] Letter of Credit [Member]
Debt Instrument [Line Items]
Debt instrument, face amount						$ 200,000,000
Revolving credit facility amount									95,000,000	75,000,000
Amount outstanding																							200,000,000
Revolver borrowings																							8,000,000
Letters of credit outstanding, amount																								600,000
Unused borrowing capacity																							86,400,000
Credit agreement lender commitment amount	15,000,000		15,000,000		15,000,000								15,000,000
Line of Credit Facility, Maximum Borrowing Capacity Including Additional Lenders							200,000,000	200,000,000
Basis spread on variable rate (as a percent)															0.50%	1.00%				4.00%		4.50%
Applicable margin interest rate increase (as a percent)																	0.0325	0.0425	0.030		0.035
Unused capacity, commitment fee (as a percent)								0.50%
Consolidated total leverage (as a ratio), Maximum permitted							4.50	4.50
Consolidated interest coverage (as a ratio), minimum permitted							3
Consolidated total leverage (as a ratio), actual							2.95	2.95
Consolidated interest coverage (as a ratio), actual							6.83
Credit agreement, permits quarterly distributions of available cash, minimum availability under revolving loan facility							10,000,000	10,000,000
Credit agreement, permits quarterly distributions of available cash, maximum covenant total leverage (as a ratio) on pro forma basis, actual							4	4
Credit agreement, Constitute a change of control, if ceases to own, directly or indirectly, exactly 50% of the membership interests of the General Partner or if General Partner ceases to be controlled (as a percent)														50.00%
Amortization and write-off of debt issuance costs	400,000	500,000	1,332,000	1,461,000
Debt issuance costs			0	280,000
Amortization of subordinated debenture discount			0	13,207,000
Debt weighted average interest rate credit agreement (as a percent)	4.45%		4.53%
Weighted average interest rate (as a percent)											5.46%	5.52%
Interest expense	$ 2,909,000	$ 9,120,000	$ 8,877,000	$ 27,284,000

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BASIS OF PRESENTATION

9 Months Ended

Sep. 30, 2012

Organization, Consolidation and Presentation of Financial Statements [Abstract]

BASIS OF PRESENTATION

BASIS OF PRESENTATION

The financial statements have been prepared in accordance with accounting principles and practices generally accepted in the United States of America (“GAAP”).  The consolidated statements of operations for the three and nine months ended September 30, 2011 and 2012, the consolidated statement of changes in partners’ capital for the nine months ended September 30, 2012, the statement of cash flows for the nine months ended September 30, 2011 and 2012, and the consolidated balance sheet as of September 30, 2012 are unaudited.  In the opinion of management, the unaudited consolidated financial statements have been prepared on the same basis as the audited financial statements and include all adjustments necessary to state fairly the financial position and results of operations for the respective interim periods.  All adjustments are of a recurring nature unless otherwise disclosed herein.  The 2011 year-end consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP.  These consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes thereto included in the Partnership’s annual report on Form 10-K for the year ended December 31, 2011 filed with the Securities and Exchange Commission (the “SEC”) on March 13, 2012 (the “2011 Form 10-K”).  Interim financial results are not necessarily indicative of the results to be expected for an annual period.  The Partnership’s significant accounting policies are consistent with those disclosed in Note 4 of the Notes to Consolidated Financial Statements in our 2011 Form 10-K. A reclassification has been made in the consolidated financial statements for the three and nine months ended September 30, 2011 to conform to the 2012 financial statement presentation.  This was a reclassification of gain on sale of assets from operating expenses to a separate component of operating income.  The reclassification has no impact on net income.

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DEBT (Convertible Subordinated Debentures) (Details) (USD $)	3 Months Ended		9 Months Ended		3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2011 Convertible subordinated debentures subject to mandatory redemption [Member]	Sep. 30, 2011 Convertible subordinated debentures subject to mandatory redemption [Member]	Dec. 31, 2011 Convertible subordinated debentures subject to mandatory redemption [Member]	Oct. 31, 2010 Convertible subordinated debentures subject to mandatory redemption [Member]
Debt Instrument [Line Items]
Debt instrument, face amount								$ 50,000,000
Change in fair value of embedded derivative within convertible debt	0	15,358,000	0	20,224,000	15,400,000	20,200,000
Unamortized discount							20,900,000
Gains on extinguishment of debt							2,400,000
Amortization of subordinated debenture discount			$ 0	$ 13,207,000	$ 4,500,000	$ 13,200,000

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EMPLOYEE BENEFIT PLAN (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Employer Matching Contribution [Member]
Defined Contribution Plans Disclosure [Line Items]
Employer discretionary contribution amount	$ 0.3	$ 0.4	$ 1.0	$ 0.9
Profit Sharing [Member]
Defined Contribution Plans Disclosure [Line Items]
Employer discretionary contribution amount	$ 0.2	$ 0.2	$ 0.7	$ 0.7

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Current assets:
Cash and cash equivalents	$ 5,139	$ 1,239
Accounts receivable, net of allowance for doubtful accounts of $476 and $469 at December 31, 2011 and September 30, 2012, respectively	11,129	14,191
Receivables from related parties, net of allowance for doubtful accounts of $0 for both dates	2,998	4,397
Prepaid insurance	1,738	1,725
Assets held for sale	1,349	603
Other current assets	2,785	1,838
Total current assets	25,138	23,993
Property, plant and equipment, net of accumulated depreciation of $135,302 and $148,580 at December 31, 2011 and September 30, 2012, respectively	262,629	266,355
Goodwill	7,216	7,216
Debt issuance costs, net	3,668	5,000
Intangibles and other assets, net	1,906	2,191
Total assets	300,557	304,755
Current liabilities:
Accounts payable	6,752	10,138
Accrued loss contingency	0	1,090
Accrued interest payable	209	231
Accrued interest payable to related parties	308	362
Accrued property taxes payable	2,718	1,813
Unearned revenue	3,393	790
Unearned revenue with related parties	279	1,149
Accrued payroll	5,282	5,226
Other current liabilities	4,385	3,740
Current portion of long-term payable to related parties	1,817	1,636
Total current liabilities	25,143	26,175
Long-term payable to related parties	1,295	2,681
Other long-term liabilities	211	100
Long-term debt (including $15.0 million with related parties for both dates)	213,000	218,000
Commitments and contingencies (Notes 5 and 13)
Partners' capital:
Series A Preferred Units (30,159,958 units issued and outstanding for both dates)	204,599	202,746
Common unitholders (22,657,638 and 22,670,137 units issued and outstanding at December 31, 2011 and September 30, 2012, respectively)	466,675	465,483
General partner interest (2.1% with 1,127,755 general partner units outstanding for both dates)	(610,366)	(610,430)
Total Partners' capital	60,908	57,799
Total liabilities and Partners' capital	$ 300,557	$ 304,755

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INCOME TAXES (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2012
Income Tax Disclosure [Abstract]
Gross income of a partnership, for any taxable year is qualifying income will be taxable as a corporation for federal income tax purposes for that taxable year and all subsequent years, maximum (as a percent)	90.00%
Federal statutory income tax rate (as a percent)	35.00%
Difference in bases of property, plant and equipment	$ 1,140
Deferred tax asset	1,140
Less: valuation allowance	(1,140)
Net deferred tax asset	$ 0

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Cash flows from operating activities:
Net income	$ 26,048	$ 25,893
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for uncollectible receivables from third parties	(7)	0
Depreciation and amortization	17,174	17,066
Amortization and write-off of debt issuance costs	1,332	1,461
Amortization of subordinated debenture discount	0	13,207
Change in fair value of embedded derivative within convertible debt	0	(20,224)
Change in fair value of rights offering liability	0	(1,838)
Asset impairment charge	1,168	0
Gain on sale of assets	(5,265)	(1,852)
Equity-based incentive compensation	1,079	377
Changes in assets and liabilities
Decrease (increase) in accounts receivable	3,069	(4,156)
Decrease (increase) in receivables from related parties	1,399	(931)
Decrease in prepaid insurance	1,862	450
Decrease (increase) in other current assets	(948)	474
Decrease (increase) in other assets	(72)	1,118
Decrease in accounts payable	(2,079)	(2,036)
Decrease in accrued interest payable	(22)	(186)
Increase (decrease) in accrued interest payable to related parties	(54)	3,973
Increase in accrued property taxes	905	736
Increase in unearned revenue	2,603	405
Decrease in unearned revenue from related parties	(870)	(2,154)
Increase in accrued payroll	56	788
Decrease in other accrued liabilities	(906)	(795)
Net cash provided by operating activities	46,472	31,776
Cash flows from investing activities:
Acquisitions	0	(133)
Capital expenditures	(18,730)	(13,686)
Proceeds from sale of assets	7,389	2,244
Net cash used in investing activities	(11,341)	(11,575)
Cash flows from financing activities:
Payment on insurance premium financing agreement	(1,008)	(768)
Debt issuance costs	0	(280)
Payments on long-term payable to related party	(1,205)	(808)
Borrowings under credit facility	31,000	6,000
Payments under credit facility	(36,000)	(19,862)
Distributions	(24,018)	(8,313)
Net cash used in financing activities	(31,231)	(24,031)
Net increase (decrease) in cash and cash equivalents	3,900	(3,830)
Cash and cash equivalents at beginning of period	1,239	4,840
Cash and cash equivalents at end of period	5,139	1,010
Supplemental disclosure of cash flow information:
Increase in accounts payable related to purchase of property, plant and equipment	(1,307)	1,264
Increase in accrued liabilities related to insurance premium financing agreement	$ 1,580	$ 1,278

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RELATED PARTY TRANSACTIONS (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011
Related Party Transaction [Line Items]
Related party revenue	$ 12,329	$ 11,387	$ 34,616	$ 31,377
Receivables from related parties	2,998		2,998		4,397
Vitol [Member]
Related Party Transaction [Line Items]
Related party revenue	12,300	11,400	34,600	31,400
Receivables from related parties	$ 3,000		$ 3,000

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SUBSEQUENT EVENTS

9 Months Ended

Sep. 30, 2012

Subsequent Events [Abstract]

Subsequent Events

SUBSEQUENT EVENTS

On October 23, 2012, J. Michael Cockrell notified the Board of his resignation as President and Chief Operating Officer of the General Partner, effective as of October 31, 2012. Mr. Cockrell was a named executive officer of the Partnership for the fiscal year ended December 31, 2011.

On November 2, 2012, the Partnership amended its credit facility to permit Mr. Hurley to receive a non-voting economic interest in Blueknight GP Holding, LLC (“HoldCo”), the owner of the Partnership's general partner. Mr. Hurley's interest in HoldCo will vest over a five year period and entitle Mr. Hurley, to the extent vested, to (i) 2% of the total amount of proceeds and/or distributions in excess of $100,000,000 received by HoldCo in connection with a transaction resulting in a change of control of the Partnership, and (ii) 2% of the portion of any interim quarterly distribution received by HoldCo in excess of $1,250,000.

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RELATED PARTY TRANSACTIONS (Vitol Omnibus Agreement) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		0 Months Ended	3 Months Ended	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012 Vitol [Member]	Sep. 30, 2011 Vitol [Member]	Sep. 30, 2012 Vitol [Member]	Sep. 30, 2011 Vitol [Member]	Feb. 15, 2010 Vitol [Member] Vitol Omnibus Agreement [Member]	Sep. 30, 2011 Vitol [Member] Vitol Omnibus Agreement [Member]	Sep. 30, 2012 Vitol [Member] Vitol Omnibus Agreement [Member]	Sep. 30, 2011 Vitol [Member] Vitol Omnibus Agreement [Member]
Related Party Transaction [Line Items]
Monthly charge per Designated Person for each Designated Person that performs services for Vitol during any portion of such month									1,500.00
Multiplier rate (as a decimal)									0.10
If during any month any Designated Person has spent more than 80% of his time performing services for Vitol, then Vitol will have the right for the succeeding three months to request that such individual be transitioned directly to the employment of Vitol (as a percent)									80.00%
Related party revenue	$ 12,329	$ 11,387	$ 34,616	$ 31,377	$ 12,300	$ 11,400	$ 34,600	$ 31,400		$ 300	$ 100	$ 1,200

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NET INCOME PER LIMITED PARTNER UNIT (Tables)

9 Months Ended

Sep. 30, 2012

Earnings Per Share [Abstract]

Schedule of Basic and Diluted Net Income (Loss) Per Common and Subordinated Units

The following sets forth the computation of basic and diluted net income (loss) per common and subordinated unit (in thousands, except per unit data):

	Three months ended September 30,				Nine months ended September 30,
	2011		2012		2011			2012
Net income	$	28,605	$	7,907	$	25,893		$	26,048
General partner interest in net income	643		165		754			659
Preferred interest in net income	2,975		5,391		11,124			16,173
Beneficial conversion feature attributable to preferred units	11,141		—		33,061			1,853
Income (loss) available to limited partners	$	13,846	$	2,351	$	(19,046	)	$	7,363
Basic and diluted weighted average number of units:
Common units	21,890		22,670		21,890			22,666
Subordinated units(1)	10,248		—		11,788			—
Restricted and phantom units	456		617		380			550
Basic and diluted net income (loss) per common unit	$	0.38	$	0.10	$	(0.56	)	$	0.32
Basic and diluted net income (loss) per subordinated unit(1)	$	0.42	$	—	$	(0.52	)	$	—

____________________

(1) On September 14, 2011, Vitol and Charlesbank transferred all of the Partnership’s outstanding subordinated units to the Partnership and the Partnership canceled such subordinated units.

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ORGANIZATION AND NATURE OF BUSINESS

9 Months Ended

Sep. 30, 2012

ORGANIZATION AND NATURE OF BUSINESS [Abstract]

ORGANIZATION AND NATURE OF BUSINESS

ORGANIZATION AND NATURE OF BUSINESS

Blueknight Energy Partners, L.P. (formerly SemGroup Energy Partners, L.P.) and subsidiaries (the “Partnership”) is a publicly traded master limited partnership with operations in twenty-three states. The Partnership provides integrated terminalling, storage, processing, gathering and transportation services for companies engaged in the production, distribution and marketing of crude oil and asphalt products. The Partnership manages its operations through four operating segments: (i) crude oil terminalling and storage services, (ii) crude oil pipeline services, (iii) crude oil trucking and producer field services and (iv) asphalt services. The Partnership’s common units and preferred units, which represent limited partnership interests in the Partnership, are listed on the NASDAQ Global Market under the symbols “BKEP” and “BKEPP,” respectively. 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.

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CONSOLIDATED BALANCE SHEETS Parenthetical (USD $)	Sep. 30, 2012	Dec. 31, 2011
Current assets:
Accounts receivable, allowance for doubtful accounts	$ 469,000	$ 476,000
Receivables from related parties, allowance for doubtful accounts	0	0
Property, plant and equipment, accumulated depreciation	148,580,000	135,302,000
LIABILITIES AND PARTNERS' CAPITAL
Long-term debt with related parties	$ 15,000,000	$ 15,000,000
Partners' capital:
Series A Preferred unitholders, units issued	30,159,958	30,159,958
Series A Preferred unitholders, units outstanding	30,159,958	30,159,958
Common unitholders, units issued	22,670,137	22,657,638
Common unitholders, units outstanding	22,670,137	22,657,638
General partner interest, units outstanding	1,127,755	1,127,755
General partner percentage interest	2.10%	2.10%

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FAIR VALUE MEASUREMENTS

9 Months Ended

Sep. 30, 2012

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

The Partnership had no recurring financial assets or liabilities subject to fair value measurements as of December 31, 2011 or September 30, 2012.

The fair value of the embedded derivative within the subordinated convertible debentures was derived using a valuation model and has been classified as Level 3. The valuation model used is a discounted cash flow model (income approach) that assumes future distribution payments by the Partnership and utilizes interest rates and credit spreads for subordinated debt to preferred equity to determine the fair value of the derivative embedded within the subordinated convertible debentures. The change in fair value of the derivative liability for the three and nine months ended September 30,2011 of $15.4 million and $20.2 million, respectively, is included in other income in the Partnership’s consolidated statements of operations.  In connection with the establishment of the conversion price for the Preferred Units following the special meeting of the Partnership’s unitholders in September 2011, the number of Preferred Units issuable upon conversion of the subordinated convertible debentures was an amount equal to (i) the sum of the outstanding principal and any accrued and unpaid interest being converted, divided by (ii) 6.50.  The establishment of the conversion rate resulted in the embedded derivative meeting the scope exception in ASC 815-15 – Embedded Derivatives, and, therefore, the Partnership reclassified the embedded derivative as partners’ capital on September 14, 2011.

The fair value of the rights offering liability related to certain rights that have been offered to common unitholders under the approved Global Transaction Agreement was derived using a valuation model and has been classified as Level 3.  The valuation model used is a probability-weighted model (income approach) and assumes the number of rights that are exercised as well as the expected fair value of the Preferred Units at the time such rights are exercised.  The change in fair value of the rights offering liability for the three and nine months ended September 30,2011 of $8.2 million and $1.8 million, respectively, is included in other income in the Partnership’s consolidated statements of operations.

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

	Measurements UsingSignificant Unobservable Inputs (Level 3)
	For the Three Months Ended September 30, 2011			For the Nine Months Ended September 30, 2011
Beginning Balance	$	39,511		$	37,991
Total gains or losses (realized/unrealized):
Included in earnings	(23,582		)	(22,062		)
Included in other comprehensive income	—			—
Purchases, issuances, and settlements(1)	(7,326		)	(7,326		)
Transfers in and/or out of Level 3	—			—
Balance at September 30, 2011	$	8,603		$	8,603
The amount of  total income for the period included in earnings attributable to the change in unrealized gains for liabilities still held at the reporting date	$	(8,224	)	$	(1,838	)

____________________

(1) As noted above, the Partnership reclassified the embedded derivative within subordinated convertible debentures to partners’ capital as of September 14, 2011.

Fair Value of Other Financial Instruments

The following disclosure of the estimated fair value of financial instruments is made in accordance with accounting guidance for financial instruments. The Partnership has determined the estimated fair values by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

At September 30, 2012, the carrying values on the unaudited condensed consolidated balance sheets for cash and cash equivalents (classified as Level 1), accounts receivable and accounts payable approximate their fair value because of their short term nature.

Based on the borrowing rates currently available to the Partnership for credit agreement debt with similar terms and maturities and consideration of the Partnership’s non-performance risk, long-term debt associated with the Partnership’s credit agreement at September 30, 2012 approximates its fair value. The fair value of the Partnership’s long-term debt was calculated using observable inputs (LIBOR for the risk free component) and unobservable company-specific credit spread information.  As such, the Partnership considers this debt to be Level 3.

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Document And Entity Information	9 Months Ended
	Sep. 30, 2012	Nov. 02, 2012
Entity Information [Line Items]
Entity Registrant Name	Blueknight Energy Partners, L.P.
Entity Central Index Key	0001392091
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		22,670,137
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2012

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OPERATING SEGMENTS

9 Months Ended

Sep. 30, 2012

Segment Reporting [Abstract]

OPERATING SEGMENTS

OPERATING SEGMENTS

The Partnership’s operations consist of four operating segments: (i) crude oil terminalling and storage services, (ii) crude oil pipeline services, (iii) crude oil trucking and producer field services, and (iv) asphalt services.  

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

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

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

ASPHALT SERVICES —The Partnership provides asphalt product and residual fuel terminalling, storage and blending services at its 44 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 before income taxes, which is its nearest comparable GAAP financial measure, is included in the following table. The Partnership believes that investors benefit from having access to the same financial measures being utilized by management. Operating margin is an important measure of the economic performance of the Partnership’s core operations. This measure forms the basis of the Partnership’s internal financial reporting and is used by its management in deciding how to allocate capital resources among segments.  Income 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 (in thousands):  

	Crude Oil Terminalling and Storage Services		Crude Oil Pipeline Services		Crude Oil Trucking and Producer Field Services		Asphalt  Services		Total
Three Months Ended September 30, 2011
Service revenue
Third party revenue	$	2,941	$	4,408	$	10,170	$	17,605	$	35,124
Related party revenue	6,683		1,220		3,484		—		11,387
Total revenue for reportable segments	9,624		5,628		13,654		17,605		46,511
Operating expenses (excluding depreciation and amortization)	1,138		3,813		12,486		5,672		23,109
Operating margin (excluding depreciation and amortization)(1)	8,486		1,815		1,168		11,933		23,402
Total assets (end of period)	75,304		102,730		16,071		126,670		320,775
Three Months Ended September 30, 2012
Service revenue
Third party revenue	$	3,278	$	4,216	$	10,722	$	16,581	$	34,797
Related party revenue	5,260		1,742		5,195		132		12,329
Total revenue for reportable segments	8,538		5,958		15,917		16,713		47,126
Operating expenses (excluding depreciation and amortization)	973		4,776		14,508		6,073		26,330
Operating margin (excluding depreciation and amortization)(1)	7,565		1,182		1,409		10,640		20,796
Total assets (end of period)	68,870		99,619		19,323		112,745		300,557
Nine months ended September 30, 2011
Service revenue
Third party revenue	$	8,316	$	13,301	$	32,634	$	45,497	$	99,748
Related party revenue	20,748		3,401		7,228		—		31,377
Total revenue for reportable segments	29,064		16,702		39,862		45,497		131,125
Operating expenses (excluding depreciation and amortization)	3,283		12,610		37,706		16,913		70,512
Operating margin (excluding depreciation and amortization)(1)	25,781		4,092		2,156		28,584		60,613
Total assets (end of period)	75,304		102,730		16,071		126,670		320,775
Nine months ended September 30, 2012
Service revenue
Third party revenue	$	9,009	$	12,274	$	35,202	$	44,359	$	100,844
Related party revenue	18,153		4,252		11,754		457		34,616
Total revenue for reportable segments	27,162		16,526		46,956		44,816		135,460
Operating expenses (excluding depreciation and amortization)	2,698		13,626		40,877		17,553		74,754
Operating margin (excluding depreciation and amortization)(1)	24,464		2,900		6,079		27,263		60,706
Total assets (end of period)	68,870		99,619		19,323		112,745		300,557

____________________

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

	Three months ended September 30,					Nine months ended September 30,
	2011			2012		2011			2012
Operating margin (excluding depreciation and amortization)	$	23,402		$	20,796	$	60,613		$	60,706
Depreciation and amortization	5,651			5,792		17,066			17,174
General and administrative expenses	4,679			4,119		14,065			13,608
Gain on sale of assets	1,143			46		1,852			5,265
Interest expense	9,120			2,909		27,284			8,877
Change in fair value of embedded derivative within convertible debt	(15,358		)	—		(20,224		)	—
Change in fair value of rights offering liability	(8,224		)	—		(1,838		)	—
Income before income taxes	$	28,677		$	8,022	$	26,112		$	26,312

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CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011		Sep. 30, 2012		Sep. 30, 2011
Service revenue:
Third party revenue	$ 34,797		$ 35,124		$ 100,844		$ 99,748
Related party revenue	12,329		11,387		34,616		31,377
Total revenue	47,126		46,511		135,460		131,125
Expenses:
Operating	32,122		28,760		91,928		87,578
General and administrative	4,119		4,679		13,608		14,065
Total expenses	36,241		33,439		105,536		101,643
Gain on sale of assets	46		1,143		5,265		1,852
Operating income	10,931		14,215		35,189		31,334
Other (income) expenses:
Interest expense	2,909		9,120		8,877		27,284
Change in fair value of embedded derivative within convertible debt	0		(15,358)		0		(20,224)
Change in fair value of rights offering liability	0		(8,224)		0		(1,838)
Income before income taxes	8,022		28,677		26,312		26,112
Provision for income taxes	115		72		264		219
Net income	7,907		28,605		26,048		25,893
Allocation of net income for calculation of earnings per unit:
General partner interest in net income	165		643		659		754
Preferred interest in net income	5,391		2,975		16,173		11,124
Beneficial conversion feature attributable to preferred units	0		11,141		1,853		33,061
Income (loss) available to limited partners	$ 2,351		$ 13,846		$ 7,363		$ (19,046)
Basic and diluted net income (loss) per common unit	$ 0.10		$ 0.38		$ 0.32		$ (0.56)
Basic and diluted net income (loss) per subordinated unit	$ 0.00	[1]	$ 0.42	[1]	$ 0.00	[1]	$ (0.52)	[1]
Weighted average common units outstanding - basic and diluted	22,670		21,890		22,666		21,890
Weighted average subordinated units outstanding - basic and diluted	0	[1]	10,248	[1]	0	[1]	11,788	[1]

[1] On September 14, 2011, Vitol and Charlesbank transferred all of the Partnership’s outstanding subordinated units to the Partnership and the Partnership canceled such subordinated units.

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DISTRIBUTIONS

9 Months Ended

Sep. 30, 2012

Partners' Capital Account, Distributions [Abstract]

DISTRIBUTIONS

DISTRIBUTIONS

The Partnership did not make a cash distribution to its common unitholders from May 15, 2008 through February 13, 2012 due, in part, to the events of default that existed under its former credit agreement, restrictions under such credit agreement, and the uncertainty of its future cash flows relating to SemCorp’s bankruptcy filings (“SemCorp” refers to SemGroup Corporation and its predecessors including SemGroup, L.P., subsidiaries and affiliates other than the Partnership and the General Partner during periods in which the Partnership and the General Partner were affiliated with SemGroup, L.P.).  As a result of the approval of the Partnership Agreement Amendment Proposal (as defined in the Partnership’s Proxy Statement dated July 28, 2011) on September 14, 2011, all cumulative common unit arrearages were eliminated.  The Partnership’s common unitholders will be required to pay taxes on their share of the Partnership’s taxable income even though they did not receive a cash distribution for the quarters ended June 30, 2008 through September 30, 2011.  The Partnership is currently allowed to make distributions to its unitholders in accordance with its debt covenants; however, the Partnership will only make distributions to the extent it has sufficient cash from operations after establishment of cash reserves as determined by the General Partner in accordance with the Partnership’s cash distribution policy, including the establishment of any reserves for the proper conduct of the Partnership’s business.  The Partnership resumed distributions for common units on February 14, 2012 for the quarter ended December 31, 2011.

On October 23, 2012, the Board approved a distribution of $0.17875 per Preferred Unit, or a total distribution of $5.4 million.  The Partnership will pay this distribution on the preferred units on November 14, 2012 to preferred unitholders of record as of November 2, 2012.

In addition, the Partnership declared a cash distribution of $0.1125 per unit on its outstanding common units, a 2.3% increase over the previous quarter's distribution. The distribution will be paid on November 14, 2012 to unitholders of record on November 2, 2012. The distribution is for the three months ended September 30,2012. The total distribution to be paid will be approximately $2.7 million, with approximately $2.6 million and $0.1 million to be paid to the Partnership’s common unitholders and general partner, respectively, and less than $0.1 million to be paid to phantom and restricted unitholders pursuant to awards granted under the Partnership’s long-term incentive plan.

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DEBT

9 Months Ended

Sep. 30, 2012

Debt Disclosure [Abstract]

DEBT

DEBT

On October 25, 2010, the Partnership entered into a new credit agreement, which includes a $200.0 million term loan facility and a $75.0 million revolving loan facility.  On April 5, 2011, the Partnership entered into a Joinder Agreement whereby the Partnership’s revolving credit facility was increased from $75.0 million to $95.0 million.  As of November 2, 2012, approximately $200.0 million of term loan borrowings, $8.0 million of revolver borrowings and $0.6 million of letters of credit were outstanding under the credit facility, leaving the Partnership with approximately $86.4 million available capacity for additional revolver borrowings and letters of credit under the credit facility. A subsidiary of Vitol Holding B.V. (together with its subsidiaries, “Vitol”) is a lender under the credit agreement and has committed to loan the Partnership $15.0 million pursuant to such agreement.  The proceeds of loans made under the credit agreement may be used for working capital and other general corporate purposes of the Partnership.

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

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

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

Until May 15, 2011, borrowings under the credit agreement bore interest, at the Partnership’s option, at either (i) the ABR (the highest of the administrative agent’s prime rate, the federal funds rate plus 0.5%, or the one-month eurodollar rate (as defined in the credit agreement) plus 1.0%), plus an applicable margin of 3.25%, or (ii) the eurodollar rate plus an applicable margin of 4.25%.  After May 15, 2011, the applicable margin for loans accruing interest based on the ABR ranges from 3.0% to 3.5%, and the applicable margin for loans accruing interest based on the eurodollar rate ranges from 4.0% to 4.5%, in each case depending on the Partnership’s consolidated total leverage ratio (as defined in the credit agreement).  The Partnership pays a per annum fee on all letters of credit issued under the credit agreement, which fee equals the applicable margin for loans accruing interest based on the eurodollar rate, and the Partnership pays a commitment fee of 0.5% per annum on the unused availability under the credit agreement.  The credit agreement does not have a floor for the ABR or the eurodollar rate.  In connection with entering into the credit agreement, the Partnership paid certain upfront fees to the lenders thereunder, and the Partnership paid certain arrangement and other fees to the arranger and administrative agent of the credit agreement.  Vitol received its pro rata portion of such fees as a lender under the credit agreement.

The credit agreement includes financial covenants that are 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 4.50 to 1.00 for each future fiscal quarter. The minimum permitted consolidated interest coverage ratio (as defined in the credit agreement) is 3.00 to 1.00 for each future fiscal quarter.

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

• create, incur or assume liens;

• engage in mergers or acquisitions;

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

• make investments;

• modify the terms of the convertible subordinated debentures (as defined below) and certain other indebtedness, or prepay certain indebtedness;

• engage in transactions with affiliates; 

• enter into certain burdensome contracts;

• change the nature of the Partnership’s business;

• enter into operating leases; and

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

At September 30, 2012, the Partnership’s leverage ratio was 2.95 and the interest coverage ratio was 6.83.  The Partnership was in compliance with all covenants of its credit agreement as of September 30, 2012.

The credit agreement permits the Partnership to make quarterly distributions of available cash (as defined in the Partnership’s partnership agreement) to unitholders so long as:  (i) no default or event of default exists under the credit agreement, (ii) the Partnership has, on a pro forma basis after giving effect to such distribution, at least $10.0 million of availability under the revolving loan facility, and (iii) the Partnership’s consolidated total leverage ratio, on a pro forma basis, would not be greater than 4.00 to 1.00 for any future fiscal quarter.  The Partnership is currently allowed to make distributions to its unitholders in accordance with these covenants; however, the Partnership will only make distributions to the extent it has sufficient cash from operations after establishment of cash reserves as determined by the General Partner in accordance with the Partnership’s cash distribution policy, including the establishment of any reserves for the proper conduct of the Partnership’s business.  See Note 6 for additional information regarding distributions.

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

• failure to meet the quarterly financial covenants;

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

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

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

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

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

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

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

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

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

Interest expense related to debt issuance cost amortization for the three and nine months ended September 30, 2011 was $0.5 million and $1.5 million, respectively, and for the three and nine month periods ended September 30, 2012 was $0.4 million and $1.3 million, respectively. The Partnership capitalized debt issuance costs of $0.3 million in the nine months ended September 30, 2011. The Partnership did not incur any debt issuance costs in the nine months ended September 30, 2012.

During the three and nine months ended September 30,2012, the weighted average interest rate under the credit agreement incurred by the Partnership was 4.45% and 4.53%, respectively, and the total weighted average interest rate, including interest associated with the ENPS Throughput Agreement (as defined in Note 8), was 5.46% and 5.52%, respectively, resulting in interest expense of approximately $2.9 million and $8.9 million, respectively.

In October 2010 the Partnership issued convertible subordinated debentures in a private placement in the aggregate principal amount of $50.0 million.  If not previously redeemed, the convertible subordinated debentures, including all outstanding principal and unpaid interest, would have converted to Preferred Units on December 31, 2011.  Upon issuance, this conversion feature was considered an embedded derivative, which the Partnership was required to bifurcate and carry at its fair value each reporting period. In connection with the establishment of the conversion price for the Preferred Units following the special meeting of the Partnership’s unitholders in September 2011, the conversion option was deemed to meet the scope exception for certain contracts involving an entity’s own equity in ACS 815-Derivatives and Hedging, and, therefore, the Partnership reclassified the embedded derivative as partners’ capital in the third quarter of 2011. The Partnership redeemed the convertible subordinated debentures on November 9, 2011.

Changes to the fair value of the embedded derivative are reflected on the Partnership’s consolidated statements of operations as “Change in fair value of embedded derivative within convertible debt.” The value of the embedded derivative was contingent on changes in the expected fair value of the Partnership’s preferred units. The Partnership recorded other income of $15.4 million and $20.2 million due to the change in the fair value of this embedded derivative in the three and nine months ended September 30, 2011, respectively.

In addition, the recording of the embedded derivative liability related to the convertible subordinated debentures resulted in the Partnership recording a $20.9 million debt discount on the convertible subordinated debentures.   The debt discount was being amortized to interest expense through the mandatory conversion date of December 31, 2011, using the effective interest rate method until the redemption of the convertible subordinated debentures on November 9, 2011. Upon redemption, the remaining unamortized debt discount was considered in the calculation of a $2.4 million extinguishment gain, which was determined to represent a capital transaction and, therefore, was recorded as a capital contribution to the Partnership by the Partnership’s general partner. For the purpose of calculating net income per limited partner unit, this amount was added back to net loss available to limited partners as it represents the recovery of a portion of the additional financing costs resulting from bifurcation of the conversion option and related discount on the convertible subordinated debentures. The Partnership recognized non-cash interest expense of $4.5 million and $13.2 million in the three and nine months ended September 30, 2011, respectively, due to the amortization of the debt discount.

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PROPERTY, PLANT AND EQUIPMENT (Tables)

9 Months Ended

Sep. 30, 2012

Property, Plant and Equipment [Abstract]

Schedule of Property, Plant and Equipment

	Estimated Useful Lives (Years)	December 31, 2011			September 30, 2012
		(dollars in thousands)
Land	N/A	$	16,601		$	16,355
Land improvements	10-20	5,671			5,980
Pipelines and facilities	5-30	152,733			159,314
Storage and terminal facilities	10-35	169,139			170,298
Transportation equipment	3-10	20,615			19,088
Office property and equipment and other	3-20	22,901			26,528
Pipeline linefill and tank bottoms	N/A	7,458			5,993
Construction-in-progress	N/A	6,539			7,653
Property, plant and equipment, gross		401,657			411,209
Accumulated depreciation		(135,302		)	(148,580		)
Property, plant and equipment, net		$	266,355		$	262,629

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COMMITMENTS AND CONTINGENCIES

9 Months Ended

Sep. 30, 2012

Commitments and Contingencies Disclosure [Abstract]

COMMITMENT AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

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

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 General Partner.  Their claims arise from the 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 General Partner’s failure to deliver certificates for the phantom units within 60 days after vesting caused them to be damaged, and they sought recovery of approximately $2.0 million in damages and penalties.  On April 30, 2009, all of the wage claims were dismissed on jurisdictional grounds by the Department of Labor.

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

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

On July 11, 2011, ExxonMobil filed suit against the Partnership in Harris County District Court, State of Texas, requesting damages in excess of $35,000 from the Partnership and other, third party service providers in connection with the relocation of existing pipelines of ExxonMobil and the Partnership.  The Partnership has filed its answer to the claims and asserted cross-claims against third party service providers including the subcontractors of ExxonMobil.  ExxonMobil had previously sent a settlement demand seeking approximately $1.9 million in damages.  A trial date is set for February, 2013. The Partnership intends to vigorously defend these claims. 

On February 6, 2012, the Partnership filed suit against SemCorp and others in Oklahoma County district court. In the suit, the Partnership is seeking a judgment that SemCorp immediately return approximately 140,000 barrels of crude oil linefill belonging to the Partnership, and the Partnership is seeking judgment in an amount in excess of $75,000 for actual damages, special damages, punitive damages, pre-judgment interest, reasonable attorney’s fees and costs, and such other relief that the Court deems equitable and just. On March 22, 2012, SemCorp filed a motion to dismiss and transfer to Tulsa County. On April 18, 2012, SemCorp filed a motion for summary judgment, and, on May 1, 2012, the district court of Oklahoma County ordered a transfer to Tulsa County. The Partnership is contesting SemCorp’s motion for summary judgment, which has been referred to a special master for report and recommendation. Discovery, before the special master, is ongoing and no trial date is set.

On July 13, 2012, the Partnership and one of its employees were named in a motor vehicle negligence suit in the District Court of Woodward County, Oklahoma, arising out of an accident involving one of the Partnership’s crude oil tanker trucks.  The accident resulted in the death of one of the occupants of the other vehicle, and certain unknown injuries to the other occupant.  The plaintiff is seeking damages in excess of $75,000 from the Partnership.  The Partnership has submitted the claim to its insurance carriers, and the Partnership believes that any recovery would be within applicable policy limits after payment of its $100,000 deductible.   Although it is not possible to predict the ultimate outcome of this matter, the Partnership does not expect that an award in this matter will have a material adverse impact on its consolidated results of operations or financial condition.

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

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

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LONG-TERM INCENTIVE PLAN

9 Months Ended

Sep. 30, 2012

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

LONG-TERM INCENTIVE PLAN

LONG-TERM INCENTIVE PLAN

In July of 2007, the General Partner adopted the Blueknight Energy Partners G.P., L.L.C. Long-Term Incentive Plan (the “Plan”). The compensation committee of the Board administers the Plan. The Plan authorizes the grant of an aggregate of 2.6 million common units deliverable upon vesting.  On September 14, 2011, the Partnership’s unitholders approved an amendment to the Plan to increase the number of common units issuable under such plan by 1.35 million common units from 1.25 million common units to 2.6 million common units.  Although other types of awards are contemplated under the Plan, currently outstanding awards include “phantom” units, which convey the right to receive common units upon vesting, and “restricted” units, which are grants of common units restricted until the time of vesting. Certain of 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.  

In March 2011 and March 2012, grants for 299,900 and 351,300 phantom common units, respectively, were made, which vest on January 1, 2014 and January 1, 2015, respectively.  These grants are equity awards under ASC 718 – Stock Compensation, and, accordingly, the fair value of the awards as of the grant date is expensed over the vesting period. The weighted average grant date fair-value of the awards is $8.25 and $6.76 per unit, respectively, which is the closing market price on the grant date of the awards. The value of these award grants was approximately $2.5 million and $2.4 million, respectively, on their grant date, and the unrecognized estimated compensation cost at September 30, 2012 was $2.7 million, which will be recognized over the remaining vesting period. As of September 30, 2012, the Partnership expects approximately 87% of these awards will vest. 

In September 2012, Mr. Mark Hurley was granted 500,000 phantom units under the Plan upon his employment as the Chief Executive Officer of the General Partner. These grants are equity awards under ASC 718 – Stock Compensation, and, accordingly, the fair value of the awards as of the grant date is expensed over the vesting period. These units vest ratably over five years pursuant to the Employee Phantom Unit Agreement between Mr. Hurley and the General Partner and do not include DERs. The weighted average grant date fair value for the units of $5.62 was determined based on the closing market price of the Partnership’s common units on the grant date of the award, less the present value of the expected distributions to be paid to holders of an outstanding common unit prior to the vesting of the underlying award. The value of this award grant was approximately $2.8 million on the grant date, substantially all of which was unrecognized at September 30, 2012, and will be expensed over the five year vesting period.

The Partnership’s equity-based incentive compensation expense for the three and nine months ended September 30, 2012 was $0.4 million and $1.1 million, respectively.

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

	Number of Units	Weighted Average Grant Date Fair Value
Nonvested at December 31, 2011	307,151	$	8.17
Granted	851,300	6.09
Vested	10,000	8.25
Forfeited	56,400	7.58
Nonvested at September 30, 2012	1,092,051	$	6.58

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NET INCOME PER LIMITED PARTNER UNIT

9 Months Ended

Sep. 30, 2012

Earnings Per Share [Abstract]

NET INCOME PER LIMITED PARTNER UNIT

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 income (loss) per common and subordinated unit (in thousands, except per unit data):

	Three months ended September 30,				Nine months ended September 30,
	2011		2012		2011			2012
Net income	$	28,605	$	7,907	$	25,893		$	26,048
General partner interest in net income	643		165		754			659
Preferred interest in net income	2,975		5,391		11,124			16,173
Beneficial conversion feature attributable to preferred units	11,141		—		33,061			1,853
Income (loss) available to limited partners	$	13,846	$	2,351	$	(19,046	)	$	7,363
Basic and diluted weighted average number of units:
Common units	21,890		22,670		21,890			22,666
Subordinated units(1)	10,248		—		11,788			—
Restricted and phantom units	456		617		380			550
Basic and diluted net income (loss) per common unit	$	0.38	$	0.10	$	(0.56	)	$	0.32
Basic and diluted net income (loss) per subordinated unit(1)	$	0.42	$	—	$	(0.52	)	$	—

____________________

(1) On September 14, 2011, Vitol and Charlesbank transferred all of the Partnership’s outstanding subordinated units to the Partnership and the Partnership canceled such subordinated units.

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RELATED PARTY TRANSACTIONS

9 Months Ended

Sep. 30, 2012

Related Party Transactions [Abstract]

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

The Partnership provides crude oil gathering, transportation, terminalling and storage services to Vitol.  For the three and nine months ended September 30,2011, the Partnership recognized revenues of $11.4 million and $31.4 million, respectively for services provided to Vitol.  For the three and nine months ended September 30,2012, the Partnership recognized revenues of $12.3 million and $34.6 million, respectively for services provided to Vitol.  As of September 30, 2012, the Partnership had receivables from Vitol of $3.0 million.

Vitol Omnibus Agreement

On February 15, 2010, the Partnership entered into an Omnibus Agreement (the “Vitol Omnibus Agreement”) with Vitol.  Pursuant to the Vitol Omnibus Agreement, the Partnership agreed to provide certain of its employees, consultants and agents (the “Designated Persons”) to Vitol for use by Vitol’s crude oil marketing division.  In return, Vitol agreed to reimburse the Partnership in an amount equal to (i) the wages, salaries, bonuses, make whole payments, payroll taxes and the cost of all employee benefits of each Designated Person, in each case as adjusted to properly reflect the time spent by such Designated Person in the performance services for Vitol, (ii) all direct expenses, including, without limitation, any travel and entertainment expenses, incurred by each Designated Person in connection with such Designated Person’s provision of services for Vitol, (iii) a monthly charge of $1,500.00 per Designated Person for each Designated Person that performs services for Vitol during any portion of such month, plus (iv) the sum of subsections (i) through (iii) above multiplied by 0.10.  In addition, the Vitol Omnibus Agreement provides that if during any month any Designated Person has spent more than 80% of his time performing services for Vitol, then Vitol will have the right for the succeeding three months to request that such individual be transitioned directly to the employment of Vitol.  During the three and nine months ended September 30,2011, the Partnership received payments of $0.3 million and $1.2 million, respectively, pursuant to the Vitol Omnibus Agreement.  During the nine months ended September 30,2012, the Partnership received payments of $0.1 million pursuant to the Vitol Omnibus Agreement.  The Vitol Omnibus 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’s partnership agreement. The Partnership and Vitol terminated the Vitol Omnibus Agreement on March 27, 2012.

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 provided 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 in 2010 to extend the term of the agreement until June 1, 2011 and again in 2011 to extend the term of the agreement to June 1, 2012.  Because Vitol was a third party (and not a related or affiliated party) at the time of entering into the 2008 Vitol Storage Agreement, such agreement was not approved by the Board or the Board’s conflicts committee in accordance with the Partnership’s procedures for approval of related party transactions.  Vitol became a related party when it acquired the General Partner in November 2009 (the “Vitol Change of Control”).  Since the amendments occurred subsequent to the Vitol Change of Control, they were reviewed and approved by the Board’s conflicts committee in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of the partnership agreement.  The Partnership earned revenues of approximately $3.3 million from Vitol with respect to services provided pursuant to the 2008 Vitol Storage Agreement for the three months ended September 30,2011.  The Partnership earned revenues of approximately $9.9 million and $5.5 million from Vitol with respect to services provided pursuant to the 2008 Vitol Storage Agreement for the nine months ended September 30,2011 and 2012, respectively.The Partnership believes that the rates it charged Vitol under the 2008 Vitol Storage Agreement were fair and reasonable to the Partnership and its unitholders and were comparable with the rates the Partnership charged 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.  The Partnership generated revenues under this agreement of approximately $3.1 million and $2.8 million during the three months ended September 30,2011 and 2012, respectively.  The Partnership generated revenues under this agreement of approximately $9.2 million and $8.7 million during the nine months ended September 30,2011 and 2012, 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. 

The Partnership entered into two new crude oil storage services agreements with Vitol, the “2012 Vitol 12-month Storage Agreement” and the “2012 Vitol 6-month Storage Agreement”, which became effective June 1, 2012, when the 2008 Vitol Storage Agreement expired according to its terms. The Partnership believes that the rates it charges Vitol under both of these agreements are fair and reasonable to the Partnership and its unitholders and are comparable with the rates the Partnership charges third parties. The Board’s conflicts committee reviewed and approved each of these agreements in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of the partnership agreement.

Service revenues under the 2012 Vitol 12-month Storage Agreement are based on the 1 million barrels of storage capacity of the crude oil storage tanks that are dedicated to Vitol under the agreement. The initial term of the Vitol 12-month Storage Agreement is from June 1, 2012 through June 1, 2013. The Partnership generated revenues under this agreement of approximately $1.4 million and $1.8 million for the three and nine months ended September 30,2012, respectively.

Service revenues under the 2012 Vitol 6-month Storage Agreement are based on the 500,000 barrels of storage capacity of the crude oil storage tanks that are dedicated to Vitol under the agreement. The initial term of the 2012 Vitol 6-month Storage Agreement is from June 1, 2012 through December 1, 2012. The Partnership generated revenues under this agreement of approximately $0.7 million and $0.9 million for the three and nine months ended September 30,2012, respectively.

During the third quarter of 2012, the Partnership entered into another 6-month storage agreement (the “Vitol September 2012 Storage Agreement”) with Vitol effective September 1, 2012. The Partnership believes that the rates it charges Vitol under this agreement are fair and reasonable to the Partnership and its unitholders and are comparable with the rates the Partnership charges third parties. The Board’s conflicts committee reviewed and approved this agreement in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of the partnership agreement. Service revenues under the Vitol September 2012 Storage Agreement are based on the 500,000 barrels of storage capacity of the crude oil storage tanks that are dedicated to Vitol under the agreement. The initial term of the Vitol September 2012 Storage Agreement is from September 1, 2012 to March 1, 2013. The Partnership generated revenues under this agreement of approximately $0.2 million for each of the three and nine months ended September 30,2012.

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 leased 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 had 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 were accounted for as operating leases.  During the three and nine months ended September 30,2011, the Partnership recorded expenses under this agreement of approximately $0.1 million and $0.4 million, respectively.  The Master Agreement was approved by the Board’s conflicts committee in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of its partnership agreement.  In September of 2011, the Partnership entered into a new master lease agreement with an unrelated third party and terminated the Master Agreement with Vitol.

Vitol Throughput Capacity Agreement

In August of 2010, the Partnership and Vitol entered into a Throughput Capacity Agreement (the “ENPS Throughput Agreement”).  Pursuant to the ENPS Throughput Agreement, Vitol purchased 100% of the throughput capacity on the Partnership’s Eagle North Pipeline System (“ENPS”).  The Partnership put ENPS in service in December of 2010.  In September 2010, Vitol paid the Partnership a prepaid fee equal to $5.5 million and Vitol will pay additional usage fees for every barrel delivered by or on behalf of Vitol on ENPS.  This $5.5 million fee received from Vitol is accounted for as a long-term payable to a related party and is reflected as such on the Partnership’s consolidated balance sheet as of September 30, 2012.  In addition, if the payments made by Vitol in any contract year under the ENPS Throughput Agreement are in the aggregate less than $2.4 million, then Vitol will pay the Partnership a deficiency payment equal to $2.4 million minus the aggregate amount of all payments made by Vitol during such contract year.  In March 2012, the Partnership received a deficiency payment of $0.3 million from Vitol in relation to the 2011 contract year. The ENPS Throughput Agreement has a term that extends for four years after ENPS is completed and may be extended by mutual agreement of the parties for additional one-year terms.  If the capacity on ENPS is unavailable for use by Vitol for more than 60 days, whether consecutive or nonconsecutive, during the term of the ENPS Throughput Agreement, then Vitol shall have the right to terminate the ENPS Throughput Agreement within six months after such lack of capacity.  The Partnership has previously contracted to provide throughput services on ENPS to a third party and Vitol’s rights to the capacity of ENPS are subordinate to the rights of such third party.  In addition, for so long as a default by Vitol relating to payments under the ENPS Throughput Agreement has not occurred and is continuing, the Partnership will remit to Vitol any and all tariffs and deficiency payments received by the Partnership or its affiliates from such third party pursuant to its agreement with the Partnership.  The ENPS Throughput Agreement was approved by the Board’s conflicts committee in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of its partnership agreement.

During the three and nine months ended September 30,2011, the Partnership incurred interest expense under this agreement of approximately $0.2 million and $0.6 million, respectively.  During the three and nine months ended September 30,2012, the Partnership incurred interest expense under this agreement of approximately $0.1 million and $0.4 million, respectively. The agreement has an effective annual interest rate of 14.1% and matures on December 31, 2014.

Vitol Operating and Maintenance Agreement

In August of 2011, the Partnership and Vitol entered into an operating and maintenance agreement (the "Vitol O&M Agreement") relating to the operation and maintenance of Vitol's crude oil terminal located in Midland, Texas (the "Midland Terminal"). Pursuant to the Vitol O&M Agreement, the Partnership provides certain operating and maintenance services with respect to the Midland Terminal. The term of the Vitol O&M Agreement commenced on September 1, 2012 and shall continue for five years. During the three and nine months ended September 30,2012, the Partnership generated revenues of $0.1 million under this agreement. The Partnership believes that the rates it charges Vitol under this agreement are fair and reasonable to the Partnership and its unitholders and are comparable with the rates the Partnership charges third parties. The Board’s conflicts committee reviewed and approved this agreement in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of the partnership agreement.

Vitol Shared Services Agreement

In August of 2012, the Partnership and Vitol entered into a shared services agreement (the "Vitol Shared Services Agreement") pursuant to which the Partnership provides Vitol certain strategic assessment, economic evaluation and project design services. The term of the Vitol Shared Services Agreement commenced on August 1, 2012 and shall continue for one year. The Vitol Shared Services Agreement renews annually unless terminated by either party as provided in the agreement. During the three and nine months ended September 30,2012, the Partnership generated revenues of $0.3 million under this agreement. The Partnership believes that the rates it charges Vitol under this agreement are fair and reasonable to the Partnership and its unitholders. The Board’s conflicts committee reviewed and approved this agreement in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of the partnership agreement.

Vitol’s Commitment under the Partnership’s Credit Agreement

Vitol is a lender under the Partnership’s current credit agreement and has committed to loan the Partnership $15.0 million pursuant to such agreement.  During the three and nine months ended September 30, 2012, Vitol received its pro rata portion of the interest payments in connection with being a lender under the credit agreement and received approximately $0.2 million and $0.5 million, respectively, in connection therewith.

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EMPLOYEE BENEFIT PLAN

9 Months Ended

Sep. 30, 2012

Compensation and Retirement Disclosure [Abstract]

EMPLOYEE BENEFIT PLAN

EMPLOYEE BENEFIT PLAN

Under the Partnership’s 401(k) Plan, which was instituted in 2009, employees who meet specified service requirements may contribute a percentage of their total compensation, up to a specified maximum, to the 401(k) Plan. The Partnership may match each employee’s contribution, up to a specified maximum, in full or on a partial basis. The Partnership recognized expense of $0.4 million and $0.3 million for the three months ended September 30,2011 and 2012, respectively, for discretionary contributions under the 401(k) Plan.  The Partnership recognized expense of $0.9 million and $1.0 million for the nine months ended September 30,2011 and 2012, respectively, for discretionary contributions under the 401(k) Plan.

The Partnership may also make annual lump-sum contributions to the 401(k) Plan irrespective of the employee’s contribution match. The Partnership may make a discretionary annual contribution in the form of profit sharing calculated as a percentage of an employee’s eligible compensation. This contribution is retirement income under the qualified 401(k) Plan. Annual profit sharing contributions to the 401(k) Plan are submitted to and approved by the Board. The Partnership recognized expense of $0.2 million for each of the three months ended September 30,2011 and 2012 for discretionary profit sharing contributions under the 401(k) Plan. The Partnership recognized expense of $0.7 million for each of the nine months ended September 30,2011 and 2012 for discretionary profit sharing contributions under the 401(k) Plan.

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NET INCOME PER LIMITED PARTNER UNIT (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011		Sep. 30, 2012		Sep. 30, 2011
Earnings Per Share [Abstract]
Net income	$ 7,907		$ 28,605		$ 26,048		$ 25,893
General partner interest in net income	165		643		659		754
Preferred interest in net income	5,391		2,975		16,173		11,124
Beneficial conversion feature attributable to preferred units	0		11,141		1,853		33,061
Income (loss) available to limited partners	$ 2,351		$ 13,846		$ 7,363		$ (19,046)
Basic and diluted weighted average number of units:
Common units (in units)	22,670		21,890		22,666		21,890
Subordinated units (in units)	0	[1]	10,248	[1]	0	[1]	11,788	[1]
Restricted and phantom units (in units)	617		456		550		380
Basic and diluted net income (loss) per common unit (in dollars per unit)	$ 0.10		$ 0.38		$ 0.32		$ (0.56)
Basic and diluted net income (loss) per subordinated unit (in dollars per unit)	$ 0.00	[1]	$ 0.42	[1]	$ 0.00	[1]	$ (0.52)	[1]

[1] On September 14, 2011, Vitol and Charlesbank transferred all of the Partnership’s outstanding subordinated units to the Partnership and the Partnership canceled such subordinated units.

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RECENTLY ISSUED ACCOUNTING STANDARDS

9 Months Ended

Sep. 30, 2012

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

RECENTLY ISSUED ACCOUNTING STANDARDS

RECENTLY ISSUED ACCOUNTING STANDARDS

In May 2011, the FASB issued ASU 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRS),” which provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between GAAP and IFRS.  This new guidance changes some fair value measurement principles and disclosure requirements.  The Partnership adopted this guidance beginning with the Partnership’s Quarterly Report for the period ended March 31, 2012, and the impact was not material.

In September 2011, the FASB issued ASU 2011-08, “Testing for Goodwill Impairment,” which allows an entity to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test.  Under these assessments, an entity would not be required to calculate the fair value of a reporting unit unless the entity determines, based on a qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount.  The Partnership adopted this guidance beginning in its December 31, 2011 annual impairment test, and the impact was not material. 

In July 2012, the FASB issued ASU 2012-02, “Testing Indefinite-Lived Intangible Assets for Impairment,” which allows an entity to first assess qualitative factors to determine whether it is necessary to perform a quantitative impairment test. Under these amendments, an entity would not be required to calculate the fair value of an indefinite-lived intangible asset unless the entity determines, based on qualitative assessment, that it is not more likely than not, the indefinite-lived intangible asset is impaired. The amendments include a number of events and circumstances for an entity to consider in conducting the qualitative assessment. The Partnership plans to adopt this guidance beginning in its December 31, 2012 annual impairment test, and does not anticipate the impact to be material.

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FAIR VALUE MEASUREMENTS (Tables)

9 Months Ended

Sep. 30, 2012

Fair Value Disclosures [Abstract]

Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation

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

	Measurements UsingSignificant Unobservable Inputs (Level 3)
	For the Three Months Ended September 30, 2011			For the Nine Months Ended September 30, 2011
Beginning Balance	$	39,511		$	37,991
Total gains or losses (realized/unrealized):
Included in earnings	(23,582		)	(22,062		)
Included in other comprehensive income	—			—
Purchases, issuances, and settlements(1)	(7,326		)	(7,326		)
Transfers in and/or out of Level 3	—			—
Balance at September 30, 2011	$	8,603		$	8,603
The amount of  total income for the period included in earnings attributable to the change in unrealized gains for liabilities still held at the reporting date	$	(8,224	)	$	(1,838	)

____________________

(1) As noted above, the Partnership reclassified the embedded derivative within subordinated convertible debentures to partners’ capital as of September 14, 2011.

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FAIR VALUE MEASUREMENTS (Narrative) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Fair Value Disclosures [Abstract]
Change in fair value of embedded derivative within convertible debt	$ 0	$ 15,358	$ 0	$ 20,224
Change in fair value of rights offering liability	$ 0	$ 8,224	$ 0	$ 1,838

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CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL (USD $) In Thousands, unless otherwise specified	Total	Common Unitholders [Member]	Series A Preferred Unitholders [Member]	General Partner Interest [Member]
Balance at Dec. 31, 2011	$ 57,799	$ 465,483	$ 202,746	$ (610,430)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	26,048	9,651	15,853	544
Equity-based incentive compensation	1,079	1,057	0	22
Amortization of beneficial conversion feature of Preferred units	0	(1,853)	1,853	0
Distributions	(24,018)	(7,663)	(15,853)	(502)
Balance at Sep. 30, 2012	$ 60,908	$ 466,675	$ 204,599	$ (610,366)

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PROPERTY, PLANT AND EQUIPMENT

9 Months Ended

Sep. 30, 2012

Property, Plant and Equipment [Abstract]

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT

	Estimated Useful Lives (Years)	December 31, 2011			September 30, 2012
		(dollars in thousands)
Land	N/A	$	16,601		$	16,355
Land improvements	10-20	5,671			5,980
Pipelines and facilities	5-30	152,733			159,314
Storage and terminal facilities	10-35	169,139			170,298
Transportation equipment	3-10	20,615			19,088
Office property and equipment and other	3-20	22,901			26,528
Pipeline linefill and tank bottoms	N/A	7,458			5,993
Construction-in-progress	N/A	6,539			7,653
Property, plant and equipment, gross		401,657			411,209
Accumulated depreciation		(135,302		)	(148,580		)
Property, plant and equipment, net		$	266,355		$	262,629

Depreciation expense for the three months ended September 30,2011 and 2012 was $5.6 million and $5.8 million, respectively, and depreciation expense for the nine months ended September 30,2011 and 2012 was $17.0 million and $17.1 million, respectively. In the three and nine months ended September 30,2012, the Partnership recorded asset impairment expense of $0.1 million and $1.2 million, respectively, related to its pipelines and facilities and transportation equipment.

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OPERATING SEGMENTS (Tables)

9 Months Ended

Sep. 30, 2012

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

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

	Crude Oil Terminalling and Storage Services		Crude Oil Pipeline Services		Crude Oil Trucking and Producer Field Services		Asphalt  Services		Total
Three Months Ended September 30, 2011
Service revenue
Third party revenue	$	2,941	$	4,408	$	10,170	$	17,605	$	35,124
Related party revenue	6,683		1,220		3,484		—		11,387
Total revenue for reportable segments	9,624		5,628		13,654		17,605		46,511
Operating expenses (excluding depreciation and amortization)	1,138		3,813		12,486		5,672		23,109
Operating margin (excluding depreciation and amortization)(1)	8,486		1,815		1,168		11,933		23,402
Total assets (end of period)	75,304		102,730		16,071		126,670		320,775
Three Months Ended September 30, 2012
Service revenue
Third party revenue	$	3,278	$	4,216	$	10,722	$	16,581	$	34,797
Related party revenue	5,260		1,742		5,195		132		12,329
Total revenue for reportable segments	8,538		5,958		15,917		16,713		47,126
Operating expenses (excluding depreciation and amortization)	973		4,776		14,508		6,073		26,330
Operating margin (excluding depreciation and amortization)(1)	7,565		1,182		1,409		10,640		20,796
Total assets (end of period)	68,870		99,619		19,323		112,745		300,557
Nine months ended September 30, 2011
Service revenue
Third party revenue	$	8,316	$	13,301	$	32,634	$	45,497	$	99,748
Related party revenue	20,748		3,401		7,228		—		31,377
Total revenue for reportable segments	29,064		16,702		39,862		45,497		131,125
Operating expenses (excluding depreciation and amortization)	3,283		12,610		37,706		16,913		70,512
Operating margin (excluding depreciation and amortization)(1)	25,781		4,092		2,156		28,584		60,613
Total assets (end of period)	75,304		102,730		16,071		126,670		320,775
Nine months ended September 30, 2012
Service revenue
Third party revenue	$	9,009	$	12,274	$	35,202	$	44,359	$	100,844
Related party revenue	18,153		4,252		11,754		457		34,616
Total revenue for reportable segments	27,162		16,526		46,956		44,816		135,460
Operating expenses (excluding depreciation and amortization)	2,698		13,626		40,877		17,553		74,754
Operating margin (excluding depreciation and amortization)(1)	24,464		2,900		6,079		27,263		60,706
Total assets (end of period)	68,870		99,619		19,323		112,745		300,557

____________________

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

	Three months ended September 30,					Nine months ended September 30,
	2011			2012		2011			2012
Operating margin (excluding depreciation and amortization)	$	23,402		$	20,796	$	60,613		$	60,706
Depreciation and amortization	5,651			5,792		17,066			17,174
General and administrative expenses	4,679			4,119		14,065			13,608
Gain on sale of assets	1,143			46		1,852			5,265
Interest expense	9,120			2,909		27,284			8,877
Change in fair value of embedded derivative within convertible debt	(15,358		)	—		(20,224		)	—
Change in fair value of rights offering liability	(8,224		)	—		(1,838		)	—
Income before income taxes	$	28,677		$	8,022	$	26,112		$	26,312

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RELATED PARTY TRANSACTIONS (Vitol Agreements) (Details) (USD $)	3 Months Ended		9 Months Ended			3 Months Ended		9 Months Ended		1 Months Ended		3 Months Ended		9 Months Ended			3 Months Ended	9 Months Ended	0 Months Ended	3 Months Ended	9 Months Ended	0 Months Ended	3 Months Ended	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011	Sep. 30, 2012 Vitol [Member]	Sep. 30, 2011 Vitol [Member]	Sep. 30, 2012 Vitol [Member]	Sep. 30, 2011 Vitol [Member]	Mar. 31, 2012 Vitol [Member] (ENPS) Vitol Throughput Capacity Agreement [Member]	Aug. 31, 2010 Vitol [Member] (ENPS) Vitol Throughput Capacity Agreement [Member]	Sep. 30, 2012 Vitol [Member] (ENPS) Vitol Throughput Capacity Agreement [Member]	Sep. 30, 2011 Vitol [Member] (ENPS) Vitol Throughput Capacity Agreement [Member]	Sep. 30, 2012 Vitol [Member] (ENPS) Vitol Throughput Capacity Agreement [Member]	Sep. 30, 2011 Vitol [Member] (ENPS) Vitol Throughput Capacity Agreement [Member]	Sep. 30, 2010 Vitol [Member] (ENPS) Vitol Throughput Capacity Agreement [Member]	Sep. 30, 2012 Vitol [Member] Vitol’s Commitment under the Partnership’s Credit Agreement [Member] Revolving Credit Facility [Member]	Sep. 30, 2012 Vitol [Member] Vitol’s Commitment under the Partnership’s Credit Agreement [Member] Revolving Credit Facility [Member]	Aug. 31, 2012 Vitol [Member] Vitol Operating and Maintenance Agreement [Member]	Sep. 30, 2012 Vitol [Member] Vitol Operating and Maintenance Agreement [Member]	Sep. 30, 2012 Vitol [Member] Vitol Operating and Maintenance Agreement [Member]	Aug. 01, 2012 Vitol [Member] Vitol Shared Services Agreement [Member]	Sep. 30, 2012 Vitol [Member] Vitol Shared Services Agreement [Member]	Sep. 30, 2012 Vitol [Member] Vitol Shared Services Agreement [Member]
Related Party Transaction [Line Items]
Purchase of thoughput capacity related to pipeline system (as a percent)											100.00%
Due from related party																$ 5,500,000
Payments made in any contract year, minimum, required deficiency payment, equal to amount, minus the aggregate amount of all payments made by Vitol during such contract year														2,400,000
Deficiency payment received										300,000
Initial term (in years)											4 years								5 years			1 year
Option to extend agreement term by mutual agreement of parties (in years)											1 year
Consecutive or nonconsecutive, during term Vitol shall have the right to terminate Agreement, if capacity is unavailable (in days)											60 days
Capacity is unavailable, right to terminate after such lack of capacity (in months)											6 months
Interest expense												100,000	200,000	400,000	600,000
Effective annual interest rate (as a percent)														14.10%
Related party revenue	12,329,000	11,387,000	34,616,000	31,377,000		12,300,000	11,400,000	34,600,000	31,400,000											100,000	100,000		300,000	300,000
Credit agreement lender commitment amount	15,000,000		15,000,000		15,000,000												15,000,000	15,000,000
Pro rata portion of interest payments received by Vitol under credit agreement																	$ 200,000	$ 500,000

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INCOME TAXES

9 Months Ended

Sep. 30, 2012

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

The anticipated after-tax economic benefit of an investment in the Partnership’s common units depends largely on the Partnership being treated as a partnership for federal income tax purposes. If less than 90% of the gross income of a publicly traded partnership, such as the Partnership, for any taxable year is “qualifying income” from sources such as the transportation, marketing (other than to end users), or processing of crude oil, natural gas or products thereof, interest, dividends or similar sources, that partnership will be taxable as a corporation under Section 7704 of the Internal Revenue Code for federal income tax purposes for that taxable year and all subsequent years.

If the Partnership were treated as a corporation for federal income tax purposes, then it would pay federal income tax on its income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions would generally be taxed again to unitholders as corporate distributions and none of the Partnership’s income, gains, losses, deductions or credits would flow through to its unitholders. Because a tax would be imposed upon the Partnership as an entity, cash available for distribution to its unitholders would be substantially reduced. Treatment of the Partnership as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to unitholders and thus would likely result in a substantial reduction in the value of the Partnership’s common units.

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

In relation to the Partnership’s taxable subsidiary, the tax effects of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts at September 30, 2012 are presented below (dollars in thousands):

Deferred tax assets
Difference in bases of property, plant and equipment	$	1,140
Deferred tax asset	1,140
Less: valuation allowance	(1,140		)
Net deferred tax asset	$	—

Given that the Partnership’s subsidiary that is taxed as a corporation has a limited earnings history for purposes of determining the likelihood of realizing the benefits of the deferred tax assets, the Partnership has provided a full valuation allowance against its deferred tax asset.