10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

Q QuarterlyReport Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended September 30, 2014

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    Q     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   Q      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 Q
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  Q

As of October 30, 2014, there were 30,158,619 Series A Preferred Units and 32,766,663 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, 2013 and September 30, 2014	1
	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2013 and 2014	2
	Consolidated Statement of Changes in Partners’ Capital for the Nine Months Ended September 30, 2014	3
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2013 and 2014	4
	Notes to the Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	32
Item 4.	Controls and Procedures	32
PART II	OTHER INFORMATION	33
Item 1.	Legal Proceedings	33
Item 1A.	Risk Factors	33
Item 6.	Exhibits	33

i

PART I. FINANCIAL INFORMATION

Item 1.    Unaudited Financial Statements

BLUEKNIGHT ENERGY PARTNERS, L.P. CONSOLIDATED BALANCE SHEETS (in thousands, except per unit data)
	As of			As of
	December 31, 2013			September 30, 2014
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	3,182		$	1,362
Accounts receivable, net of allowance for doubtful accounts of $69 and $222 at December 31, 2013 and September 30, 2014, respectively	12,244			12,803
Receivables from related parties, net of allowance for doubtful accounts of $0 and $171 at December 31, 2013 and September 30, 2014, respectively	3,149			3,118
Prepaid insurance	1,694			2,512
Assets held for sale, net of accumulated depreciation and impairments of $166 and $26 at December 31, 2013 and September 30, 2014, respectively	338			76
Other current assets	4,321			3,854
Total current assets	24,928			23,725
Property, plant and equipment, net of accumulated depreciation of $171,056 and $186,649 at December 31, 2013 and September 30, 2014, respectively	297,400			305,567
Investment in unconsolidated affiliate	19,498			19,975
Goodwill	7,216			7,216
Debt issuance costs, net	3,580			3,303
Intangibles and other assets, net	2,126			1,683
Total assets	$	354,748		$	361,469
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	6,537		$	8,089
Accrued interest payable	482			175
Accrued property taxes payable	1,810			2,864
Unearned revenue	2,326			2,368
Unearned revenue with related parties	90			239
Accrued payroll	7,379			6,466
Other current liabilities	4,959			3,422
Total current liabilities	23,583			23,623
Unearned revenue with related parties, noncurrent	153			126
Other long-term liabilities	2,554			4,249
Interest rate swap liabilities	—			930
Long-term debt	273,000			212,000
Commitments and contingencies (Note 13)
Partners’ capital:
Series A Preferred Units (30,158,619 units issued and outstanding for both dates)	204,599			204,599
Common unitholders (22,786,101 and 32,766,663 units issued and outstanding at December 31, 2013 and September 30, 2014, respectively)	461,149			526,302
General partner interest (2.1% and 1.8% interest at December 31, 2013 and September 30, 2014, respectively, with 1,127,755 general partner units outstanding at both dates)	(610,290		)	(610,360		)
Total Partners’ capital	55,458			120,541
Total liabilities and Partners’ capital	$	354,748		$	361,469

The accompanying notes are an integral part of these financial statements.

1

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,
	2013			2014			2013			2014
	(unaudited)
Service revenue:
Third party revenue	$	39,270		$	38,501		$	105,501		$	107,935
Related party revenue	15,399			9,857			39,381			32,663
Total revenue	54,669			48,358			144,882			140,598
Expenses:
Operating	32,132			32,295			95,440			102,272
General and administrative	4,649			4,267			13,806			13,124
Total expenses	36,781			36,562			109,246			115,396
Asset impairment expense	(123		)	—			(123		)	—
Gain on sale of assets	598			808			722			1,780
Operating income	18,363			12,604			36,235			26,982
Other income (expense):
Equity earnings (loss) in unconsolidated affiliate	(151		)	423			(325		)	477
Interest expense (net of capitalized interest of $272, $84, $969, and $244, respectively)	(1,897		)	(1,640		)	(9,188		)	(8,325		)
Income from continuing operations before income taxes	16,315			11,387			26,722			19,134
Provision for income taxes	285			116			451			351
Income from continuing operations	16,030			11,271			26,271			18,783
Discontinued Operations:
Loss from discontinued operations	(5,489		)	—			(3,542		)	—
Net income	$	10,541		$	11,271		$	22,729		$	18,783
Allocation of net income for calculation of earnings per unit:
General partner interest in net income	$	220		$	247		$	537		$	437
Preferred interest in net income	$	5,391		$	5,391		$	16,173		$	16,173
Income available to limited partners	$	4,930		$	5,633		$	6,019		$	2,173
Basic net income from continuing operations per common unit	$	0.44		$	0.23		$	0.41		$	0.09
Basic net loss from discontinued operations per common unit	$	(0.23	)	$	—		$	(0.15	)	$	—
Basic net income per common unit	$	0.21		$	0.23		$	0.26		$	0.09
Diluted net income from continuing operations per common unit	$	0.29		$	0.20		$	0.41		$	0.09
Diluted net loss from discontinued operations per common unit	$	(0.10	)	$	—		$	(0.15	)	$	—
Diluted net income per common unit	$	0.19		$	0.20		$	0.26		$	0.09
Weighted average common units outstanding - basic	22,697			23,909			22,684			23,245
Weighted average common units outstanding - diluted	53,718			54,927			22,684			23,245

The accompanying notes are an integral part of these financial statements.

2

BLUEKNIGHT ENERGY PARTNERS, L.P. CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL (in thousands)
	Common Unitholders			Series A Preferred Unitholders			General Partner Interest			Total Partners’ Capital
	(unaudited)
Balance, December 31, 2013	$	461,149		$	204,599		$	(610,290	)	$	55,458
Net income	2,237			16,173			373			18,783
Equity-based incentive compensation	831			—			17			848
Profits interest contribution	—			—			112			112
Proceeds from sale of 9,775,000 common units, net of underwriters’ discount and offering expenses of $3.2 million	71,193			—			—			71,193
Distributions	(9,108		)	(16,173		)	(572		)	(25,853		)
Balance, September 30, 2014	$	526,302		$	204,599		$	(610,360	)	$	120,541

The accompanying notes are an integral part of these financial statements.

3

BLUEKNIGHT ENERGY PARTNERS, L.P. CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)
	Nine Months ended September 30,
	2013			2014
	(unaudited)
Cash flows from operating activities:
Net income	$	22,729		$	18,783
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for uncollectible receivables from third parties	400			153
Provision for uncollectible receivables from related parties	—			171
Depreciation and amortization	17,812			19,342
Amortization and write-off of debt issuance costs	3,117			603
Unrealized loss related to interest rate swaps	—			930
Asset impairment charge	5,855			—
Gain on sale of assets	(1,732		)	(1,780		)
Equity-based incentive compensation	1,547			848
Equity (earnings) loss in unconsolidated affiliate	325			(477		)
Changes in assets and liabilities
Increase in accounts receivable	(5,844		)	(712		)
Increase in receivables from related parties	(2,304		)	(140		)
Decrease in prepaid insurance	2,022			1,969
Decrease in other current assets	348			467
Decrease in other assets	11			128
Decrease in accounts payable	(1,490		)	(503		)
Decrease in accrued interest payable	(8		)	(307		)
Decrease in accrued interest payable to related parties	(304		)	—
Increase in accrued property taxes	793			1,054
Increase (decrease) in unearned revenue	(388		)	1,346
Increase (decrease) in unearned revenue from related parties	(97		)	122
Increase (decrease) in accrued payroll	74			(913		)
Decrease in other accrued liabilities	(605		)	(1,765		)
Net cash provided by operating activities	42,261			39,319
Cash flows from investing activities:
Capital expenditures	(56,438		)	(25,372		)
Proceeds from sale of assets	1,980			1,982
Investment in unconsolidated affiliate	(20,000		)	—
Net cash used in investing activities	(74,458		)	(23,390		)
Cash flows from financing activities:
Payment on insurance premium financing agreement	(1,669		)	(1,875		)
Debt issuance costs	(3,639		)	(326		)
Payments on long-term payable to related party	(2,681		)	—
Borrowings under credit facility	331,411			42,733
Payments under credit facility	(268,000		)	(103,733		)
Proceeds from equity issuance, net of offering costs	—			71,193
Capital contribution related to profits interest	112			112
Distributions	(24,872		)	(25,853		)
Net cash provided by (used in) financing activities	30,662			(17,749		)
Net decrease in cash and cash equivalents	(1,535		)	(1,820		)
Cash and cash equivalents at beginning of period	3,177			3,182
Cash and cash equivalents at end of period	$	1,642		$	1,362
Supplemental disclosure of cash flow information:
Increase in accounts payable related to purchase of property, plant and equipment	$	3,465		$	2,055
Increase in accounts receivable related to accrued proceeds on sale of assets	$	(194	)	$	—
Increase in accrued liabilities related to insurance premium financing agreement	$	2,609		$	2,494
Decrease in accounts receivable related to purchase of property, plant and equipment	$	1,274		$	—

The accompanying notes are an integral part of these financial statements. 

4

BLUEKNIGHT ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1.    ORGANIZATION AND NATURE OF BUSINESS

Blueknight Energy Partners, L.P. and subsidiaries (collectively, the “Partnership”) is a publicly traded master limited partnership with operations in twenty-two 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 February2007 as a Delaware master limited partnership initially to own, operate and develop a diversified portfolio of complementary midstream energy assets.

2.    BASIS OF CONSOLIDATION AND 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 30,2013 and 2014, the consolidated statement of changes in partners’ capital for the nine months ended September 30,2014, the statement of cash flows for the nine months ended September 30,2013 and 2014, and the consolidated balance sheet as of September 30, 2014 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 2013 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, 2013 filed with the Securities and Exchange Commission (the “SEC”) on March 12, 2014 (the “2013 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 its 2013 Form 10-K. A reclassification has been made to the consolidated statements of operations for the three and nine months ended September 30, 2013 to reflect a recasting of amounts related to discontinued operations (see Note 3). The reclassification has no impact on net income.

The Partnership’s investment in Advantage Pipeline, L.L.C. (“Advantage Pipeline”), over which the Partnership has significant influence but not control, is accounted for by the equity method. The Partnership does not consolidate any part of the assets or liabilities of its equity investee. The Partnership’s share of net income or loss is reflected as one line item on the Partnership’s Consolidated Statements of Operations entitled “Equity earnings in unconsolidated affiliate” and will increase or decrease, as applicable, the carrying value of the Partnership’s investment in the unconsolidated affiliate on the balance sheet. Distributions to the Partnership will reduce the carrying value of its investment and will be reflected in the Partnership’s Consolidated Statements of Cash Flows in the line item “Distributions from unconsolidated affiliate.” In turn, contributions will increase the carrying value of the Partnership’s investment and will be reflected in the Partnership’s Consolidated Statements of Cash Flows in investing activities. The Partnership evaluates its equity investment for impairment in accordance with FASB guidance with respect to the equity method of accounting for investments in common stock. An impairment of an equity investment results when factors indicate that the investment’s fair value is less than its carrying value and the reduction in value is other than temporary in nature. 

3.     DISCONTINUED OPERATIONS

Northumberland, PA Asphalt Facility

On November 1, 2013, the Partnership entered into a litigation settlement in which title to its Northumberland, Pennsylvania asphalt facility was conveyed on November 21, 2013 to the counterparty to the settlement agreement in return for complete indemnification from any and all environmental liabilities or lawsuits related to the facility. The Partnership recognized a loss on the disposal of the facility of $0.6 million in 2013. The financial results of the Partnership’s operations related to the Northumberland asphalt facility are reflected as discontinued operations in the consolidated statements of operations. All prior periods presented have been recast to reflect the discontinued operations.

5

The amounts of revenue and costs reported in discontinued operations are set forth in the table below for the period indicated:

	Three Months ended September 30,		Nine Months ended September 30,
	2013		2013
	(in thousands, except per unit data)
Total revenue	$	164	$	493
Expenses:
Operating	49		105
Income from discontinued operations	$	115	$	388
Basic net income from discontinued operations per common unit	$	0.01	$	0.02
Diluted net income from discontinued operations per common unit	$	—	$	0.02

The following table discloses the major classes of discontinued assets and liabilities related to the Northumberland asphalt facility at the disposal date:

	November 21, 2013
	(in thousands)
Assets
Accounts Receivable	$	4
Assets of discontinued operations	$	4
Liabilities
Accounts Payable	$	13
Deferred Revenue	28
Other liabilities	84
Liabilities of discontinued operations	$	125

Thompson to Webster Pipeline System

In September 2013, the Partnership experienced an oil spill on its Thompson to Webster Pipeline System. As the costs associated with future maintenance of the pipeline and the potential future realizable cash flows from this pipeline were assessed, the Partnership determined that it was not economically feasible for it to continue to operate the pipeline. The Partnership assessed the recoverability of the carrying value of this asset and determined it was impaired. This resulted in $5.7 million of impairment expense being recorded in 2013, which reduced the carrying value of this pipeline to the discounted future net cash flows the Partnership expected to realize from this asset. During the discussions with the current shipper on necessary future maintenance and the possibility of idling the system, the shipper expressed interest in purchasing the system. On December 30, 2013, the sale to the shipper was finalized. The financial information of the Thompson to Webster Pipeline System is reflected as discontinued operations in the consolidated statements of operations. All prior periods presented have been recast to reflect the discontinued operations.

The amounts of revenue and costs reported in discontinued operations are set forth in the table below for the period indicated:

6

	Three Months ended September 30			Nine Months ended September 30,
	2013			2013
	(in thousands, except per unit data)
Total revenue	$	410		$	1,750
Expenses:
Operating	418			958
Asset impairment expense	5,732			5,732
Gain on sale of assets	136			1,010
Loss from discontinued operations	$	(5,604	)	$	(3,930	)
Basic net loss from discontinued operations per common unit	$	(0.24	)	$	(0.17	)
Diluted net loss from discontinued operations per common unit	$	(0.10	)	$	(0.17	)

The following table discloses the major classes of discontinued assets and liabilities related to the Thompson to Webster Pipeline System at the disposal date:

	December 30, 2013
	(in thousands)
Assets
Accounts Receivable	$	400
Property, plant and equipment, net	1,000
Assets of discontinued operations	$	1,400
Liabilities
Accounts Payable	$	1
Deferred Revenue	148
Other liabilities	339
Liabilities of discontinued operations	$	488

4.    PROPERTY, PLANT AND EQUIPMENT

	Estimated Useful Lives (Years)	December 31, 2013			September 30, 2014
		(dollars in thousands)
Land	N/A	$	16,374		$	17,680
Land improvements	10-20	6,306			6,351
Pipelines and facilities	5-30	144,261			159,176
Storage and terminal facilities	10-35	234,208			238,592
Transportation equipment	3-10	16,735			14,241
Office property and equipment and other	3-20	26,371			28,182
Pipeline linefill and tank bottoms	N/A	10,193			10,186
Construction-in-progress	N/A	14,008			17,808
Property, plant and equipment, gross		468,456			492,216
Accumulated depreciation		(171,056		)	(186,649		)
Property, plant and equipment, net		$	297,400		$	305,567

Depreciation expense for the three months ended September 30,2013 and 2014 was $6.1 million and $6.6 million, respectively, and depreciation expense for the nine months ended September 30,2013 and 2014 was $17.8 million and $19.3

7

million, respectively. In the three and nine months ended September 30, 2013 , the Partnership recorded asset impairment expense of $5.9 million related to its pipelines and facilities, 5.7 million of which relates to the Thompson to Webster Pipeline System located in southern Texas. The Thompson to Webster Pipeline System was sold in December 2013 and is reflected as discontinued operations (see Note 3).

5.    DEBT

On June 28, 2013, the Partnership entered into an amended and restated credit agreement which consists of a $400.0 million revolving loan facility. On September 15, 2014, the Partnership amended its credit facility to, among other things, amend the maximum permitted consolidated total leverage ratio as discussed below and to increase the limit on material project adjustments to EBITDA (as defined in the credit agreement).

As of October 30, 2014, approximately $212.0 million of revolver borrowings and $0.7 million of letters of credit were outstanding under the credit facility, leaving the Partnership with approximately $187.3 million available capacity for additional revolver borrowings and letters of credit under the credit facility, although the Partnership’s ability to borrow such funds may be limited by the financial covenants in the credit facility. In connection with entering into the amended and restated credit agreement and the amendment thereto, the Partnership paid certain fees to the lenders thereunder, and the Partnership paid certain arrangement and other fees to the arranger and administrative agent of the credit agreement.  The proceeds of loans made under the amended and restated credit agreement may be used for working capital and other general corporate purposes of the Partnership. All references herein to the credit agreement on or after June 28, 2013 refer to the amended and restated credit agreement, as amended on September 15, 2014.

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 $500.0 million for all revolving loan commitments under the credit agreement.

The credit agreement will mature on June 28, 2018, 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, property or casualty insurance claims, and condemnation proceedings, unless the Partnership reinvests such proceeds in accordance with the credit agreement, but these mandatory prepayments will not require any reduction of the lenders’ commitments under the credit agreement.

Borrowings under the credit agreement bear interest, at the Partnership’s option, at either the reserve-adjusted eurodollar rate (as defined in the credit agreement) plus an applicable margin that ranges from 2.0% to 3.0% or the alternate base rate (the highest of the agent bank’s prime rate, the federal funds effective rate plus 0.5%, and the 30-day eurodollar rate plus 1%) plus an applicable margin that ranges from 1.0% to 2.0%.  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 ranging from 0.375% to 0.5% on the unused commitments under the credit agreement.  The credit agreement does not have a floor for the alternate base rate or the eurodollar rate.  The applicable margins for the Partnership’s interest rate, the letter of credit fee and the commitment fee vary quarterly based on the Partnership’s consolidated total leverage ratio (as defined in the credit agreement, being generally computed as the ratio of consolidated total debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges).

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.

Prior to the date on which the Partnership issues qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notes previously or concurrently issued) that equals or exceeds $200.0 million, the maximum permitted consolidated total leverage ratio is 4.50 to 1.00; provided that:

• after the Partnership delivers the Knight Warrior Pipeline Initiation Certificate (as defined in the credit agreement, but generally meaning that the Partnership has spent at least $15.0 million of the projected capital

8

expenditures for its Knight Warrior pipeline project), the maximum permitted consolidated total leverage ratio is 5.00 to 1.00 for the fiscal quarters ending March 31, 2015 through September 30, 2016, 4.75 to 1.00 for the fiscal quarter ending December 31, 2016, and 4.50 to 1.00 for each fiscal quarter thereafter;

• after the Partnership delivers the Knight Warrior Pipeline Leverage Election Certificate (as defined in the credit agreement, but generally meaning that the Partnership has spent at least 50% of the projected capital expenditures for the Knight Warrior pipeline project), the Partnership may elect to increase the maximum permitted consolidated total leverage ratio to 5.50 to 1.00 for two consecutive fiscal quarters ending on or before September 30, 2016; and

• if the Partnership makes a specified acquisition (as defined in the credit agreement, but generally being an acquisition with consideration in excess of $15.0 million), the Partnership may elect to increase the maximum permitted consolidated total leverage ratio to 5.00 to 1.00 from and after the last day of the fiscal quarter immediately preceding the fiscal quarter in which such acquisition occurs to and including the last day of the second full fiscal quarter following the fiscal quarter in which such acquisition occurred.

From and after the date on which the Partnership issues qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notes previously or concurrently issued) that equals or exceeds $200.0 million, the maximum permitted consolidated total leverage ratio is 5.00 to 1.00; provided that after the Partnership delivers the Knight Warrior Pipeline Initiation Certificate, the maximum permitted consolidated total leverage ratio is 5.50 to 1.00 for the fiscal quarters ending March 31, 2015 through September 30, 2016, and 5.00 to 1.00 for each fiscal quarter thereafter.

The maximum permitted consolidated senior secured leverage ratio (as defined in the credit agreement, but generally computed as the ratio of consolidated total secured debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) is 3.50 to 1.00, but this covenant is only tested from and after the date on which the Partnership issues qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notes previously or concurrently issued) that equals or exceeds $200.0 million.

The minimum permitted consolidated interest coverage ratio (as defined in the credit agreement, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest expense) is 2.50 to 1.00.

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

• create, issue, incur or assume indebtedness;

• create, incur or assume liens;

• engage in mergers or acquisitions;

• sell, transfer, assign or convey assets;

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

• make investments;

• modify the terms of certain indebtedness, or prepay certain indebtedness;

• engage in transactions with affiliates;

• enter into certain hedging contracts;

• enter into certain burdensome agreements;

• change the nature of the Partnership’s business;

• enter into operating leases; and

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

At September 30, 2014, the Partnership’s consolidated total leverage ratio was 3.18 to 1.00 and the consolidated interest coverage ratio was 7.12 to 1.00.  The Partnership was in compliance with all covenants of its credit agreement as of September 30, 2014.

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 no default or event of default exists under the credit agreement on a pro forma basis after giving effect to such distribution. The Partnership is currently allowed to make distributions to its unitholders in accordance with this covenant; 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 Board of Directors (the “Board”) of Blueknight Energy Partners G.P., L.L.C. (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 7 for additional information regarding distributions.

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

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

• failure to meet the quarterly financial covenants;

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

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

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

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

• certain ERISA events involving the Partnership or its restricted subsidiaries resulting in a material adverse effect on the Partnership;

• bankruptcy or other insolvency events involving the General Partner, the Partnership or any of its restricted subsidiaries; and

• a change of control (as defined in the credit agreement, but generally being (i) the General Partner ceasing to own 100% of the Partnership’s general partner interest or ceasing to control the Partnership or (ii) Vitol Holding B.V. (together with its affiliates, “Vitol”) and Charlesbank Capital Partners, LLC ceasing to collectively own and control 50.0% or more of the membership interests of the General Partner).

If an event of default relating to bankruptcy or other insolvency events occurs with respect to the General Partner or the Partnership, 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. 

Upon the execution of the amended and restated credit agreement on June 28, 2013, the Partnership expensed $1.8 million of debt issuance costs related to the extinguished term loan and $0.2 million in debt issuance costs related to its revolving loan facility, leaving a remaining balance of $0.5 million ascribed to those lenders with commitments under both the prior and the amended and restated credit facility. During the nine months ended September 30, 2013, the Partnership capitalized debt issuance costs of $0.2 million related to the prior credit facility. During the three months ended September 30,2013 and 2014, the Partnership capitalized debt issuance costs of $0.3 million related to the current credit facility for both periods. During the nine months ended September 30,2013 and 2014, the Partnership capitalized debt issuance costs of $3.4 million and $0.3 million related to the current credit facility, respectively. The debt issuance costs are being amortized over the term of the amended and restated credit agreement. Interest expense related to debt issuance cost amortization for each of the three months ended September 30,2013 and 2014 was $0.2 million. Interest expense related to debt issuance cost amortization for the nine months ended September 30,2013 and 2014 was $1.1 million and $0.6 million, respectively, excluding the $1.8 million of debt issuance costs related to the extinguished term loan and $0.2 million in debt issuance costs related to the revolving loan facility that were expensed upon the execution of the amended and restated credit agreement in June of 2013.

During the three months ended September 30,2013 and 2014, the weighted average interest rate under the Partnership’s credit agreement was 3.18% and 3.41%, respectively, resulting in interest expense of approximately $2.2 million and $2.5 million, respectively. During the nine months ended September 30,2013 and 2014, the weighted average interest rate under the Partnership’s credit agreement, excluding the $2.0 million of debt issuance costs related to the prior credit facility that was expensed in the nine months ended September 30, 2013, was 4.39% and 3.41%, respectively, resulting in interest expense of approximately $8.2 million and $7.3 million, respectively. As of September 30, 2014, borrowings under the Partnership’s amended and restated credit agreement bore interest at a weighted average interest rate of 3.72%.

During the three months ended September 30,2013 and 2014, the Partnership capitalized interest of $0.3 million and $0.1 million, respectively.  During the nine months ended September 30,2013 and 2014, the Partnership capitalized interest of $1.0 million and $0.2 million, respectively. 

The Partnership is exposed to market risk for changes in interest rates related to its credit facility. Interest rate swap agreements are used to manage a portion of the exposure related to changing interest rates by converting floating-rate debt to fixed-rate debt. In March 2014 the Partnership entered into two interest rate swap agreements with an aggregate notional

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amount of $200.0 million. The first agreement has a notional amount of $100.0 million, became effective June 28, 2014, and matures on June 28, 2018. Under the terms of the first interest rate swap agreement, the Partnership pays a fixed rate of 1.45% and receives one-month LIBOR with monthly settlement. The second agreement has a notional amount of $100.0 million, becomes effective January 28, 2015, and matures on January 28, 2019. Under the terms of the second interest rate swap agreement, the Partnership will pay a fixed rate of 1.97% and will receive one-month LIBOR with monthly settlement. During each of the three and nine months ended September 30, 2014, the Partnership recorded swap interest expense of $0.3 million. The fair market value of the interest rate swaps at September 30, 2014 is a liability of $0.9 million and is recorded in long-term derivative liabilities on the consolidated balance sheet. The interest rate swaps do not receive hedge accounting treatment under ASC 815 - Derivatives and Hedging. Changes in the fair value of the interest rate swaps are recorded in interest expense in the statements of operations. 

6.    NET INCOME PER LIMITED PARTNER UNIT

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

	Three Months ended September 30,					Nine Months ended September 30,
	2013			2014		2013			2014
Net income from continuing operations	$	16,030		$	11,271	$	26,271		$	18,783
Loss from discontinued operations	(5,489		)	—		(3,542		)	—
Net income	10,541			11,271		22,729			18,783
General partner interest in net income	220			247		537			437
Preferred interest in net income	5,391			5,391		16,173			16,173
Income available to limited partners	$	4,930		$	5,633	$	6,019		$	2,173
Basic weighted average number of units:
Common units	22,697			23,909		22,684			23,245
Restricted and phantom units	699			725		667			659
Diluted weighted average number of units:
Common units	53,718			54,927		22,684			23,245
Basic net income from continuing operations per common unit	$	0.44		$	0.23	$	0.41		$	0.09
Basic net loss from discontinued operations per common unit	$	(0.23	)	$	—	$	(0.15	)	$	—
Basic net income per common unit	$	0.21		$	0.23	$	0.26		$	0.09
Diluted income from continuing operations per common unit	$	0.29		$	0.20	$	0.41		$	0.09
Diluted loss from discontinued operations per common unit	$	(0.10	)	$	—	$	(0.15	)	$	—
Diluted net income per common unit	$	0.19		$	0.20	$	0.26		$	0.09

7.    PARTNERS’ CAPITAL AND DISTRIBUTIONS

On September 22, 2014, the Partnership issued and sold 9,775,000 common units for a public offering price of $7.61, resulting in proceeds of approximately $71.2 million, net of underwriters' discount and offering expenses of $3.2 million.

On October 23, 2014, the Board approved a distribution of $0.17875 per Preferred Unit, or a total distribution of $5.4 million, for the quarter ending September 30, 2014.  The Partnership will pay this distribution on the preferred units on November 14, 2014 to unitholders of record as of November 4, 2014.

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In addition, on October 23, 2014, the Board declared a cash distribution of $0.1345 per unit on its outstanding common units, a 1.5% increase over the previous quarter’s distribution. The distribution will be paid on November 14, 2014 to unitholders of record on November 4, 2014. The distribution is for the three months ended September 30,2014. The total distribution will be approximately $4.7 million, with approximately $4.4 million and $0.2 million to be paid to the Partnership’s common unitholders and general partner, respectively, and $0.1 million to be paid to holders of phantom and restricted units pursuant to awards granted under the Partnership’s long-term incentive plan.

8.    RELATED PARTY TRANSACTIONS

The Partnership provides crude oil gathering, transportation, terminalling and storage services to Vitol as well as certain operating, strategic assessment, economic evaluation and project design services.  For the three months ended September 30,2013 and 2014, the Partnership recognized revenues of $15.1 million and $9.6 million, respectively, for services provided to Vitol.  For the nine months ended September 30,2013 and 2014, the Partnership recognized revenues of $39.0 million and $31.9 million, respectively, for services provided to Vitol.  As of both December 31, 2013 and September 30, 2014, the Partnership had receivables from Vitol of $3.0 million, net of allowance for doubtful accounts. As of December 31, 2013 and September 30, 2014, the Partnership had unearned revenues from Vitol of $0.2 million and $0.3 million, respectively.

The Partnership also provides operating and administrative services to Advantage Pipeline. For the each of the three months ended September 30,2013 and 2014, the Partnership earned revenues of $0.3 million for services provided to Advantage Pipeline. For the nine months ended September 30,2013 and 2014, the Partnership earned revenues of $0.3 million and $0.7 million, respectively, for services provided to Advantage Pipeline. As of December 31, 2013 and September 30, 2014, the Partnership had receivables from Advantage Pipeline of $0.2 million and $0.1 million, respectively.

9.    LONG-TERM INCENTIVE PLAN

In July 2007, the General Partner adopted the Long-Term Incentive Plan (the “LTIP”). The compensation committee of the Board administers the LTIP. Effective April 29, 2014, the Partnership's unitholders approved an amendment to the LTIP to increase the number of common units reserved for issuance under the incentive plan by 1,500,000 common units from 2,600,000 common units to 4,100,000 common units. The common units are deliverable upon vesting.  Although other types of awards are contemplated under the LTIP, 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 each of December 2011, 2012 and 2013, 7,500 restricted common units were granted which vest in one-third increments over three years.  These grants were made in connection with the anniversary of the independent directors joining the Board. The fair value of the restricted units for the 2011 and 2012 grants was less than $0.1 million while the fair value of the restricted units for the 2013 grant was $0.1 million.

In March 2012, 2013 and 2014, grants for 353,300, 251,106 and 276,773 phantom units, respectively, were made, which vest on January 1, 2015, January 1, 2016 and January 1, 2017, 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 $6.76, $8.75 and $9.06 per unit, respectively, which is the closing market price on the grant date of the awards. The value of these award grants was approximately $2.4 million, $2.2 million and $2.5 million, respectively, on their grant date. The unrecognized estimated compensation cost of outstanding phantom units at September 30, 2014 was $2.4 million, which will be recognized over the remaining vesting period.

In September 2012, Mark Hurley was granted 500,000 phantom units under the LTIP 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 estimated distributions to be paid to

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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, and the unrecognized estimated compensation cost at September 30, 2014 was $1.7 million and will be expensed over the remaining vesting period.

The Partnership’s equity-based incentive compensation expense for the three months ended September 30,2013 and 2014 was $0.5 million and $0.6 million, respectively. The Partnership’s equity-based incentive compensation expense for the nine months ended September 30,2013 and 2014 was $1.5 million and $1.6 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, 2013	1,058,162	$	7.03
Granted	276,773	9.06
Vested	298,936	7.36
Forfeited	11,304	8.34
Nonvested at September 30, 2014	1,024,695	$	7.47

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 $0.3 million and $0.4 million for the three months ended September 30,2013 and 2014 for discretionary contributions under the 401(k) Plan. The Partnership recognized expense of $1.0 million and $1.1 million for the nine months ended September 30,2013 and 2014 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 both the three months ended September 30,2013 and 2014, for discretionary profit sharing contributions under the 401(k) Plan. The Partnership recognized expense of $0.8 million and $0.5 million for the nine months ended September 30,2013 and 2014, respectively, 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 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, to minimize the use of unobservable inputs when determining fair value.  In periods in which they occur, the Partnership recognizes transfers into and out of Level 3 as of

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the end of the reporting period. Transfers out of Level 3 represent existing assets and liabilities that were classified previously as Level 3 for which the observable inputs became a more significant portion of the fair value estimates. Determining the appropriate classification of the Partnership’s fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data.

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

	Fair Value Measurements as of September 30, 2014
Description	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs   (Level 3)
Liabilities:
Interest rate swap liabilities	$	930	$	—	$	930	$	—
Total	$	930	$	—	$	930	$	—

The Partnership had no recurring financial assets or liabilities subject to fair value measurements as of December 31, 2013.

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)
	Three Months ended September 30, 2014		Nine Months ended September 30, 2014
Beginning Balance	$	2,002	$	—
Total gains or losses (realized/unrealized):
Included in earnings(1)	1,072		(930		)
Included in other comprehensive income	—		—
Purchases, issuances, and settlements	—		—
Transfers in and/or out of Level 3	930		930
Ending Balance	$	—	$	—
The amount of  total income (expense) for the period included in earnings attributable to the change in unrealized gains (losses) for liabilities still held at the reporting date	$	1,072	$	(930	)

____________________

(1) Amounts reported as included in earnings are reported as interest expense on the statements of operations.

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, 2014, the carrying values on the 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, 2014 approximates its fair value. The fair value of the Partnership’s long-term debt was calculated

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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 the Eagle North System, that gather crude oil purchased by its customers and transports it to refiners, to common carrier pipelines for ultimate delivery to refiners or to terminalling and storage facilities owned by the Partnership and others. The Partnership refers to its 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 the Eagle North system.

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 42 terminalling and storage facilities located in twenty-one 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.

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

	Three Months ended September 30,				Nine Months ended September 30,
	2013		2014		2013		2014
Crude Oil Terminalling and Storage Services
Service revenue
Third party revenue	$	3,216	$	1,875	$	9,149	$	7,020
Related party revenue	4,477		3,080		14,495		10,726
Total revenue for reportable segments	7,693		4,955		23,644		17,746
Operating expenses (excluding depreciation and amortization)	1,068		1,006		2,872		2,980
Operating margin (excluding depreciation and amortization)	6,625		3,949		20,772		14,766
Total assets (end of period)	$	65,314	$	67,451	$	65,314	$	67,451
Crude Oil Pipeline Services
Service revenue
Third party revenue	$	6,499	$	5,906	$	12,681	$	13,439
Related party revenue	4,807		2,098		7,179		5,934
Total revenue for reportable segments	11,306		8,004		19,860		19,373
Operating expenses (excluding depreciation and amortization)	3,968		2,484		11,056		11,600
Operating margin (excluding depreciation and amortization)	7,338		5,520		8,804		7,773
Total assets (end of period)	$	175,476	$	170,700	$	175,476	$	170,700
Crude Oil Trucking and Producer Field Services
Service revenue
Third party revenue	$	11,712	$	12,264	$	36,085	$	38,280
Related party revenue	5,805		4,433		16,370		15,057
Total revenue for reportable segments	17,517		16,697		52,455		53,337
Operating expenses (excluding depreciation and amortization)	15,226		15,607		45,469		48,235
Operating margin (excluding depreciation and amortization)	2,291		1,090		6,986		5,102
Total assets (end of period)	$	20,446	$	28,208	$	20,446	$	28,208
Asphalt  Services
Service revenue
Third party revenue	$	17,843	$	18,456	$	47,586	$	49,196
Related party revenue	310		246		1,337		946
Total revenue for reportable segments	18,153		18,702		48,923		50,142
Operating expenses (excluding depreciation and amortization)	5,895		6,627		18,510		20,115
Operating margin (excluding depreciation and amortization)	12,258		12,075		30,413		30,027
Total assets (end of period)	$	101,215	$	95,110	$	101,215	$	95,110
Total operating margin (excluding depreciation and amortization)(1)	$	28,512	$	22,634	$	66,975	$	57,668

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____________________

(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,
	2013			2014			2013			2014
Operating margin (excluding depreciation and amortization) from continuing operations	$	28,512		$	22,634		$	66,975		$	57,668
Depreciation and amortization on continuing operations	(5,975		)	(6,571		)	(17,533		)	(19,342		)
General and administrative expenses	(4,649		)	(4,267		)	(13,806		)	(13,124		)
Asset impairment expense	(123		)	—			(123		)	—
Gain on sale of assets	598			808			722			1,780
Interest expense	(1,897		)	(1,640		)	(9,188		)	(8,325		)
Equity gain (loss) in unconsolidated entity	(151		)	423			(325		)	477
Income from continuing operations before income taxes	$	16,315		$	11,387		$	26,722		$	19,134

13.    COMMITMENTS AND CONTINGENCIES

The Partnership is from time to time subject to various legal actions and claims incidental to its business. 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 SemGroup Corporation (together with its predecessors including SemGroup, L.P., subsidiaries and affiliates referred to herein as “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 related to the disputed 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 Partnership intends to vigorously defend these claims. No trial date has been set by the court. The parties are engaged in discovery and continuing settlement negotiations. The Partnership believes that any settlement will not have a material adverse effect on the Partnership’s financial condition or results of operations.

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 contested SemCorp’s motion for summary judgment, which was referred to a Special Master for report and recommendation.  On June 10, 2013, the Special Master filed a report with the District Court of Tulsa County, finding a shortage in the Partnership’s Cushing Terminal and Oklahoma pipeline system of approximately 148,000 barrels and an excess of approximately 130,000 in SemCorp’s physical inventory. The Special Master noted that she was unable to more precisely trace the shortage and length (excess held by SemCorp) due to the manner in which SemCorp operated the Cushing Terminal and maintained related records. On June 25, 2013, the Partnership filed a notice of non-objection and motion to adopt the Special Master’s report, which was granted on February 12, 2014. On September 17, 2013, the Partnership filed a motion for summary judgment as to the liability of SemCorp for the Partnership’s claims for breach of contract and negligence by a bailee.  On October 7, 2013, SemCorp renewed its motion for summary judgment, which the Partnership timely opposed.  On February 20, 2014, the Court denied summary judgment motions of both SemCorp and the Partnership. The Court allowed for additional discovery to take place and referred all discovery matters to the Special Master, as appropriate, and made other procedural rulings. The Partnership reasserted its fraud claims in accordance with the Court’s directives. Discovery proceedings continue and the Partnership has determined that SemCorp knew of its excess inventory and sold this inventory during the period prior to the Partnership's filing of the lawsuit while denying that the Partnership claims had any validity and failing to disclose the excess to the Partnership. The Partnership intends to seek additional damages from SemCorp related to various injuries to the Partnership as a result of SemCorp’s refusal to return the Partnership’s crude oil or to pay the Partnership for the fair market value of the missing oil. 

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In late November 2013, one of the Partnership’s pipelines in East Texas leaked approximately 500 barrels of oil. The response and clean-up cost is expected to total approximately $2.1 million, all of which is reflected in the Partnership’s 2013 results of operations. The Partnership made a claim against its pollution liability insurance provider (Aspen) to cover the expenses related to the spill and has paid its deductible of $250,000.  In early February 2014, Aspen filed a lawsuit against the Partnership to rescind the policy.  In September 2014, this matter was settled on terms reasonable to both parties.

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 or 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 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 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.

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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, 2014 are presented below (dollars in thousands):

Deferred tax assets
Difference in bases of property, plant and equipment	$	950
Deferred tax asset	950
Less: valuation allowance	(950		)
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 July 2013, the FASB issued ASU 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists.” The amendment provides explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The amendments in this update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The Partnership adopted this update in January 2014, and the impact was not material.

In April 2014, the FASB issued ASU 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” The amendments in this update change the criteria for reporting discontinued operations for all public and nonpublic entities. The amendments also require new disclosures about discontinued operations and disposals of components of an entity that do not qualify for discontinued operations reporting. The amendments in this update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2014. The Partnership is evaluating the impact of this guidance, which will be adopted beginning with the Partnership’s quarterly report for the period ending March 31, 2015.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers.” The amendments in this Update create Topic 606, Revenue from Contracts with Customers, and supersede the revenue recognition requirements in Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the Industry Topics of the Codification. In addition, the amendments supersede the cost guidance in Subtopic 605-35, Revenue Recognition-Construction-Type and Production-Type Contracts, and create new Subtopic 340-40, Other Assets and Deferred Costs-Contracts with Customers. In summary, the core principle of Topic 606 is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The amendments in this update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. The Partnership is evaluating the impact of this guidance, which will be adopted beginning with the Partnership’s quarterly report for the period ending March 31, 2017.

In August 2014, the FASB issued ASU 2014-15, “Presentation of Financial Statements - Going Concern.” The Update provides U.S. GAAP guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, management will be required to evaluate whether there are conditions or events that raise substantial doubt about a company’s ability to continue as a going concern within one year from the date the financial statements are issued. The amendments in this update are effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. The Partnership is evaluating the impact of this guidance, which will be adopted beginning with the Partnership's annual report for the period ending December 31, 2016.

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. , together with its subsidiaries, (2) our “General Partner” refers to Blueknight Energy Partners G.P., L.L.C., (3) Vitol refers to Vitol Holding B.V., its affiliates and subsidiaries (other than our General Partner and us) and (4) Charlesbank refers to Charlesbank Capital Partners, LLC, its affiliates and subsidiaries (other

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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, 2013, which was filed with the Securities and Exchange Commission (the “SEC”) on March 12, 2014 (the “2013 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 2013 Form 10-K.

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

Overview

We are a publicly traded master limited partnership with operations in twenty-two states. We provide integrated terminalling, storage, gathering and transportation services for companies engaged in the production, distribution and marketing of crude oil and liquid asphalt 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 August 6, 2014, we announced our plans to build a 160-mile, 16-inch diameter pipeline linking the emerging East Texas Eaglebine/Woodbine crude oil resource play to a crude oil and product terminal on the Houston Ship Channel owned and operated by Oiltanking Partners, L.P. The pipeline, which we refer to as the Knight Warrior pipeline, will have an initial capacity of 100,000 barrels per day and will be expandable up to 200,000 barrels per day. The pipeline will have the capacity to segregate and batch crude oil in order to help producers capture value for this premium product.

On September 22, 2014, we issued and sold 9,775,000 common units for a public offering price of $7.61, resulting in proceeds of approximately $71.2 million, net of underwriters' discount and offering expenses of $3.2 million. We intend to use the net proceeds from the offering for general partnership purposes, including the repayment of a portion of the outstanding borrowings under our credit facility and partially funding the Knight Warrior pipeline project.

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 nine months ended September 30,2014, we derived approximately $31.9 million and $0.7 million of our revenues from services we provided to Vitol and Advantage Pipeline L.L.C. (“Advantage Pipeline”), respectively, 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

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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 October 30, 2014, we had approximately 5.0 million barrels of crude oil storage under service contracts with remaining terms ranging from two months to 24 months, including 0.7 million barrels of crude oil storage contracts that expire by the end of 2014. We are in negotiations to either extend contracts with existing customers or enter into new customer contracts for the storage capacity; however, there is no certainty that we will have success in contracting available capacity or that extended or new contracts will be at the same or similar rates as 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.

There are a number of market dynamics currently taking place at the Cushing Interchange, including a backwardated market for West Texas Intermediate crude oil, increased Cushing storage capacity, additional pipeline capacity for delivery out of the Cushing Interchange and significant production increases in Kansas, Oklahoma and Texas. These trends are negatively impacting demand for crude oil storage and putting downward pressure on storage rates. The current market environment places more importance on services and connectivity and, as a result, we plan to invest approximately $8.0 million in capital projects in Cushing in 2014 to enhance our connectivity and crude oil blending services, of which $5.5 million has been spent as of September 30, 2014. We believe our mix and delivery of services will differentiate us from competitors and attract new customers.

We have leases and storage agreements with third party customers for all of our 42 asphalt facilities.  The majority of the leases and storage agreements related to these facilities have terms that expire between the end of 2016 and 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 30,2014, we transported approximately 51,100 barrels per day on our pipelines as compared to 52,000 barrels per day during the three months ended September 30,2013. Vitol accounted for 27% and 30% of volumes transported in our pipelines in the three months ended September 30,2014 and 2013, respectively.

For the three months ended September 30,2014, we transported approximately 61,100 barrels per day on our crude oil transport trucks, a decrease of 2% as compared to the three months ended September 30,2013. Vitol accounted for approximately 39% and 48% of volumes transported by our crude oil transport trucks in the three months ended September 30,2014 and 2013, respectively.

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

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 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,

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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 a 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, 2014.

Distributions

The amount of distributions we pay and the decision to make any distribution is determined by 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, 2014, the Board approved a distribution of $0.17875 per preferred unit, or a total distribution of $5.4 million, for the quarter ending September 30, 2014.  We will pay this distribution on the preferred units on November 14, 2014 to unitholders of record as of November 4, 2014.

In addition, on October 23, 2014, the Board approved a cash distribution of $0.1345 per unit on our outstanding common units. The distribution will be paid on November 14, 2014 to unitholders of record on November 4, 2014. The distribution is for the three months ended September 30,2014. The total distribution to be paid is approximately $4.7 million, with approximately $4.4 million and less than $0.2 million paid to our common unitholders and general partner, respectively, and $0.1 million paid to holders of phantom and restricted units pursuant to awards granted under the our long-term incentive plan.

Results of Operations

Non-GAAP Financial Measures

To supplement our financial information presented in accordance with GAAP, management uses additional measures that are known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future.  The primary measure used by management is operating margin excluding depreciation and amortization.

Management believes that the presentation of such additional financial measures provides useful information to investors regarding our performance and results of operations because these measures, when used in conjunction with related GAAP financial measures, (i) provide additional information about our core operating performance and ability to generate and distribute cash flow, (ii) provide investors with the financial analytical framework upon which management bases financial, operational, compensation and planning decisions and (iii) present measurements that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. These additional financial measures are reconciled to the most directly comparable measures as reported in accordance with GAAP, and should be viewed in addition to, and not in lieu of, our Consolidated Financial Statements and footnotes. 

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The table below summarizes our financial results for the three and nine months ended September 30,2013 and 2014, reconciled to the most directly comparable GAAP measure: 

	Three Months ended September 30,						Nine Months ended September 30,						Favorable/(Unfavorable)
Operating Results													Three Months				Nine Months
(in thousands)	2013			2014			2013			2014			$		%		$		%
Operating Margin, excluding depreciation and amortization
Crude oil terminalling and storage operating margin	$	6,625		$	3,949		$	20,772		$	14,766		(2,676	)	(40	)%	(6,006	)	(29	)%
Crude oil pipeline services operating margin	7,338			5,520			8,804			7,773			(1,818	)	(25	)%	(1,031	)	(12	)%
Crude oil trucking and producer field services operating margin	2,291			1,090			6,986			5,102			(1,201	)	(52	)%	(1,884	)	(27	)%
Asphalt services operating margin	12,258			12,075			30,413			30,027			(183	)	(1	)%	(386	)	(1	)%
Total operating margin, excluding depreciation and amortization	28,512			22,634			66,975			57,668			(5,878	)	(21	)%	(9,307	)	(14	)%
Depreciation and amortization	(5,975		)	(6,571		)	(17,533		)	(19,342		)	(596	)	(10	)%	(1,809	)	(10	)%
General and administrative expenses	(4,649		)	(4,267		)	(13,806		)	(13,124		)	382		8	%	682		5	%
Asset impairment expense	(123		)	—			(123		)	—			123		100	%	123		100	%
Gain on sale of assets	598			808			722			1,780			210		35	%	1,058		147	%
Operating income:	18,363			12,604			36,235			26,982			(5,759	)	(31	)%	(9,253	)	(26	)%
Other income (expense)
Equity earnings (loss) in unconsolidated entity	(151		)	423			(325		)	477			574		380	%	802		247	%
Interest expense	(1,897		)	(1,640		)	(9,188		)	(8,325		)	257		14	%	863		9	%
Income tax expense	(285		)	(116		)	(451		)	(351		)	169		59	%	100		22	%
Net income from continuing operations	16,030			11,271			26,271			18,783			(4,759	)	(30	)%	(7,488	)	(29	)%
Loss from discontinued operations	(5,489		)	—			(3,542		)	—			5,489		(100	)%	3,542		(100	)%
Net Income	$	10,541		$	11,271		$	22,729		$	18,783		730		7	%	(3,946	)	(17	)%

Total operating margin excluding depreciation and amortization decreased from 2013 to 2014 due to several factors, including decreases in our crude oil terminalling and storage segment as changes in market demand for crude oil storage services led to decreases in the rates we charge our customers for those services and decreases in revenue per barrel hauled in our trucking and producer field services segment. In addition, crude oil sales related to accumulated pipeline loss allowances on our pipeline systems were $2.7 million higher during the nine months ended September 30, 2013 as compared to the nine months ended September 30, 2014.

A more detailed analysis of changes in operating margin by segment follows.

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Analysis of Operating Segments

Crude oil terminalling and storage segment

Our terminalling and storage segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services for crude oil. Revenue is generated through short- and long-term storage contracts.

The following table sets forth our operating results from our crude oil terminalling and storage segment for the periods indicated:

	Three Months ended September 30,				Nine Months ended September 30,				Favorable/(Unfavorable)
Operating results									Three Months				Nine Months
(in thousands)	2013		2014		2013		2014		$		%		$		%
Revenues
Third Party Revenues	$	3,216	$	1,875	$	9,149	$	7,020	(1,341	)	(42	)%	(2,129	)	(23	)%
Related Party Revenues	4,477		3,080		14,495		10,726		(1,397	)	(31	)%	(3,769	)	(26	)%
Total Revenues	7,693		4,955		23,644		17,746		(2,738	)	(36	)%	(5,898	)	(25	)%
Operating Expenses (excluding depreciation and amortization)	1,068		1,006		2,872		2,980		62		6	%	(108	)	(4	)%
Operating Margin (excluding depreciation and amortization)	$	6,625	$	3,949	$	20,772	$	14,766	(2,676	)	(40	)%	(6,006	)	(29	)%
Average crude oil stored per month at our Cushing terminal (in thousands of barrels)	4,547		959		4,910		1,873		(3,588	)	(79	)%	(3,037	)	(62	)%
Average crude oil delivered to our Cushing terminal (in thousands of barrels per day)	92		58		81		81		(34	)	(37	)%	—		—	%

The following is a discussion of items impacting crude oil terminalling and storage segment operating margin for the periods indicated:

• Revenues and operating margin have decreased due to changes in market dynamics at the Cushing Interchange, which include: a backwardated market for West Texas Intermediate crude, increased Cushing storage capacity, additional pipeline capacity for delivery out of the Cushing Interchange and significant production increases in Kansas, Oklahoma and Texas.  These trends have negatively impacted demand for crude oil storage and have created downward pressure on storage rates.  The current market environment places more importance on services and connectivity. As a result, we plan to invest approximately $8.0 million in capital expansion projects in Cushing in 2014 to enhance our connectivity and blending services, of which $5.5 million has been spent as of September 30, 2014.  We believe our mix and delivery of services will differentiate us from competitors and attract new customers.

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Crude oil pipeline services

Our crude oil pipeline services segment operations generally consist of fee-based activity associated with transporting crude oil products on pipelines. Revenues are generated primarily through tariffs and other transportation fees.

The following table sets forth our operating results from our crude oil pipeline services segment for the periods indicated:

	Three Months ended September 30,				Nine Months ended September 30,				Favorable/(Unfavorable)
Operating results									Three Months				Nine Months
(in thousands)	2013		2014		2013		2014		$		%		$		%
Revenues
Third Party Revenues	$	6,499	$	5,906	$	12,681	$	13,439	(593	)	(9	)%	758		6	%
Related Party Revenues	4,807		2,098		7,179		5,934		(2,709	)	(56	)%	(1,245	)	(17	)%
Total Revenues	11,306		8,004		19,860		19,373		(3,302	)	(29	)%	(487	)	(2	)%
Operating Expenses (excluding depreciation and amortization)	3,968		2,484		11,056		11,600		1,484		37	%	(544	)	(5	)%
Operating Margin (excluding depreciation and amortization)	$	7,338	$	5,520	$	8,804	$	7,773	(1,818	)	(25	)%	(1,031	)	(12	)%
Average throughput volume (in thousands of barrels per day)
Mid-Continent	17		18		18		19		1		6	%	1		6	%
Eagle North	15		15		14		15		—		—	%	1		7	%
East Texas	20		18		21		17		(2	)	(10	)%	(4	)	(19	)%

The following is a discussion of items impacting crude oil pipeline services segment operating margin for the periods indicated:

• Volumes on our East Texas system decreased from 2013 to 2014 primarily as a result of the loss of one customer that took volumes to one of its own pipelines in connection with a reversal of the flow of the customer’s pipeline.

• During the nine months ended September 30, 2013, we sold $6.9 million of crude oil related to accumulated pipeline loss allowances on our pipeline systems as compared to $4.2 million during the nine months ended September 30, 2014, a decrease of $2.7 million. During the three months ended September 30, 2013, we sold $6.9 million of crude oil related to accumulated pipeline loss allowances on our pipeline systems as compared to $2.3 million during the three months ended September 30, 2014, a decrease of $4.6 million

• Employment expense increased by $0.1 million, or 4% and $0.4 million, or 8%, for the three and nine months ended September 30, 2014, respectively, as compared to the same periods in 2013 due to additional personnel hired to support the operation of our Oklahoma Arbuckle pipeline and the operation of Advantage Pipeline's Pecos River pipeline and Vitol’s Midland pipeline system.

• Repair and maintenance expense increased by $0.3 million, or 98% and $0.8 million, or 36%, for the three and nine months ended September 30, 2014, respectively, as compared to the same periods in 2013 due to planned maintenance and repair expenses associated with our Oklahoma and East Texas pipeline systems.

• Property tax expense increased by $0.4 million for the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013 due to increases in the assessed values of our pipeline systems.

• The above increases in operating expenses were partially offset by a $1.5 million insurance claim settlement received in September 2014.

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Crude oil trucking and producer field services

Our crude oil trucking and producer field services segment operations generally consist of fee-based activity associated with transporting crude oil products on trucks. Revenues are generated primarily through transportation fees.

The following table sets forth our operating results from our crude oil trucking and producer field services segment for the periods indicated:

	Three Months ended September 30,				Nine Months ended September 30,				Favorable/(Unfavorable)
Operating results									Three Months				Nine Months
(in thousands)	2013		2014		2013		2014		$		%		$		%
Revenues
Third Party Revenues	$	11,712	$	12,264	$	36,085	$	38,280	552		5	%	2,195		6	%
Related Party Revenues	5,805		4,433		16,370		15,057		(1,372	)	(24	)%	(1,313	)	(8	)%
Total Revenues	17,517		16,697		52,455		53,337		(820	)	(5	)%	882		2	%
Operating Expenses (excluding depreciation and amortization)	15,226		15,607		45,469		48,235		(381	)	(3	)%	(2,766	)	(6	)%
Operating Margin (excluding depreciation and amortization)	$	2,291	$	1,090	$	6,986	$	5,102	(1,201	)	(52	)%	(1,884	)	(27	)%
Average volume (in thousands of barrels per day)	62		61		59		65		(1	)	(2	)%	6		10	%

The following is a discussion of items impacting crude oil trucking and producer field services segment operating margin for the periods indicated:

• We continue to experience consistent demand for our trucking services due to increased crude oil production in the Kansas, Oklahoma and Texas markets we serve. In addition, because the current crude oil market is backwardated, there is a higher demand to deliver barrels from the field to market as soon as possible (as opposed to storing barrels and delivering in a later month). Despite volume increases in 2014, our operating margin has declined due to an increase in pipeline-connected leases in areas we serve, a decrease in the average distance barrels are hauled, and increased costs associated with retaining drivers.

• In addition, because of demand in certain areas we have increased our utilization of third party trucking services. We realize lower operating margins when we utilize third party trucking services. We anticipate a decrease in our utilization of third party trucking services in the near term as we reposition our existing fleet of trucks to service areas with the greatest customer demand.

• We continue to evaluate our overall rate structure and utilization of third party trucking services and expect to implement changes in the upcoming quarters.

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Asphalt services segment

Our asphalt services segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services for asphalt product and residual fuel oil. Revenue is generated through short- and long-term storage contracts.

The following table sets forth our operating results from our asphalt services segment for the periods indicated:

	Three Months ended September 30,				Nine Months ended September 30,				Favorable/(Unfavorable)
Operating results									Three Months				Nine Months
(in thousands)	2013		2014		2013		2014		$		%		$		%
Revenues
Third Party Revenues	$	17,843	$	18,456	$	47,586	$	49,196	613		3	%	1,610		3	%
Related Party Revenues	310		246		1,337		946		(64	)	(21	)%	(391	)	(29	)%
Total Revenues	18,153		18,702		48,923		50,142		549		3	%	1,219		2	%
Operating Expenses (excluding depreciation and amortization)	5,895		6,627		18,510		20,115		(732	)	(12	)%	(1,605	)	(9	)%
Operating Margin (excluding depreciation and amortization)	$	12,258	$	12,075	$	30,413	$	30,027	(183	)	(1	)%	(386	)	(1	)%

The following is a discussion of items impacting asphalt services segment operating margin for the periods indicated:

• In December 2013, we conveyed title of our Northumberland, Pennsylvania asphalt storage facility to Koch as part of a litigation settlement. We do not anticipate a significant impact on operating margin in 2014 as a result of this conveyance, and we anticipate operating margin for the remainder of 2014 to be largely in-line with 2013 results.

• Related party revenues decreased due to lower overall contracted storage from short-term spot contracts during 2014 as compared to 2013.

• The increase in operating expenses in 2014 as compared to 2013 is primarily attributable to the timing of maintenance and repair and increased rent expense.

Other Income and Expenses

Depreciation and amortization. Depreciation and amortization increased by $1.8 million to $19.3 million for the nine months ended September 30,2014 compared to $17.5 million for the nine months ended September 30,2013, and by $0.6 million to $6.6 million for the three months ended September 30,2014 compared to $6.0 million for the three months ended September 30,2013. This increase is primarily due to our Arbuckle pipeline that was placed in service in the fourth quarter of 2013.

General and administrative expenses.  General and administrative expenses were relatively consistent during the three and nine months ended September 30,2013 and 2014. We do not anticipate material changes in general and administrative expenses for the remainder of 2014.

Gain on sale of assets. Gain on sale of assets was $1.8 million for the nine months ended September 30,2014 compared to $0.7 million for the nine months ended September 30,2013. Gain on sale of assets was $0.8 million for the three months ended September 30,2014 compared to $0.6 million for the three months ended September 30,2013. Gains in 2014 are comprised of sales of surplus, used property and equipment and $0.8 million recognized in relation to reimbursable capital projects. Gains in 2013 are comprised of sales of surplus, used property and equipment and a gain on the sale of pipeline gathering systems.

Equity earnings (loss) in unconsolidated affiliate. The equity earnings (loss) is attributed to our investment in Advantage Pipeline. Losses for 2013 are the result of expenses incurred during the construction phase of the Pecos River Pipeline. On September 17, 2013, commercial service started on Phase I of the system consisting of the Highway 18 Station near Grandfalls, Texas and 36 miles of pipeline connecting to the Longhorn Pipeline in Crane, Texas. During the three and nine months ended September 30,2014, equity earnings were realized as a result of increased throughput on the pipeline due to the completion of the Crane West station in the second quarter of 2014.

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Interest expense. Interest expense represents interest on borrowings under our credit facility as well as amortization of debt issuance costs and unrealized gains and losses related to the change in fair value of interest rate swaps. Total interest expense for the three months ended September 30,2014 decreased by $0.3 million compared to the three months ended September 30,2013. During the three months ended September 30,2014, we recorded unrealized gains due to the change in fair value of interest rate swaps of $1.1 million. The interest rate swap agreements were entered into during the first quarter of 2014. This decrease in interest expense was partially offset by an increase in interest on our credit facility of $0.3 million due to increases in our average debt outstanding and weighted average interest rate as well as interest expense incurred in connection with settlement payments under our interest rate swap agreements of $0.3 million.

Interest expense decreased by $0.9 million for the nine months ended September 30,2014 compared to the nine months ended September 30,2013. The nine months ended September 30,2013 included the write-off of $2.0 million in debt issuance costs and the recognition of $0.2 million of deferred gains related to our prior credit facility. Interest expense related to our credit facility also decreased by $0.5 million due to a decrease in our interest rate under our new credit facility that became effective June 28, 2013. These decreases were partially offset by increases to interest expense related to the interest rate swap agreements and capitalized interest. The nine months ended September 30,2014 included unrealized losses due to the change in fair value of interest rate swaps of $0.9 million. The interest rate swap agreements were entered into during the first quarter of 2014. Capitalized interest decreased by $0.7 million for the nine months ended September 30,2014 compared to the nine months ended September 30,2013 due to placing the Arbuckle pipeline in service in the last quarter of 2013.

Loss from discontinued operations. During 2013, we sold our Thompson to Webster Pipeline System in south Texas. In addition, we conveyed title of our Northumberland, Pennsylvania asphalt storage facility to our counterpart as part of a litigation settlement. The operations of these business components are presented as discontinued operations for all periods presented. The loss in 2013 is due to the impairment of the Thompson to Webster Pipeline System.

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 30,2013 and 2014: 

	Nine Months ended September 30,
	2013			2014
	(in millions)
Net cash provided by operating activities	$	42.3		$	39.3
Net cash used in investing activities	(74.5		)	(23.4		)
Net cash provided by (used in) financing activities	30.7			(17.7		)

Operating Activities.  Net cash provided by operating activities was $39.3 million for the nine months ended September 30,2014, as compared to $42.3 million for the nine months ended September 30,2013.  The decrease in cash provided by operating activities is primarily the result of changes in working capital.

Investing Activities.  Net cash used in investing activities was $23.4 million for the nine months ended September 30,2014, as compared to $74.5 million of net cash used in investing activities for the nine months ended September 30,2013.  The nine months ended September 30,2013 included a $20.0 million investment in Advantage Pipeline. The remaining decrease in cash used in investing activities was primarily the result of a $31.1 million decrease in capital expenditures. Capital expenditures for the nine months ended September 30,2014 and 2013, respectively, included maintenance capital expenditures of $5.4 million and $13.1 million, respectively, and expansion capital expenditures of $20.0 million and $43.4 million, respectively.

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Financing Activities.  Net cash used by financing activities was $17.7 million for the nine months ended September 30,2014, as compared to $30.7 million of net cash provided by financing activities for the nine months ended September 30,2013.  Cash used in financing activities for the nine months ended September 30,2014 consisted primarily of $25.9 million in distributions to our unitholders and net payments on long term debt of $61.0 million as a result of our approach to cash management. This was partially offset by cash provided by financing activities from the issuance of 9,775,000 common units for a public offering price of $7.61, resulting in proceeds of approximately $71.2 million net of offering costs.  Financing activities for the nine months ended September 30,2013 consisted primarily of $24.9 million in distributions to our unitholders and net borrowings of $63.4 million which were influenced by the timing of our investment in Advantage Pipeline and capital expenditures.

Our Liquidity and Capital Resources

Cash flow from operations and our credit facility are our primary sources of liquidity. At September 30, 2014, we had a working capital surplus of $0.1 million. This is primarily a function of our approach to cash management. At September 30, 2014, we had approximately $187.7 million of availability under our revolving credit facility, although our ability to borrow such funds may be limited by the financial covenants in our credit facility.  As of September 30, 2014, we could borrow up to $300.1, or an additional $87.8 million, under our credit facility within our covenant restrictions. As of October 30, 2014, we have aggregate unused commitments under our revolving credit facility of approximately $187.3 million and cash on hand of approximately $5.5 million.  

Capital Requirements. Our capital requirements consist of the following:

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

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

Expansion capital expenditures for organic growth projects totaled $20.0 million in the nine months ended September 30,2014 compared to $43.4 million in the nine months ended September 30,2013.  We currently expect our expansion capital expenditures for organic growth projects to be approximately $28.0 million to $33.0 million for all of 2014.  Maintenance capital expenditures totaled $3.9 million, net of reimbursable expenditures of $1.5 million, in the nine months ended September 30,2014 compared to $11.1 million, net of reimbursable expenditures of $2.0 million, in the nine months ended September 30,2013.  We currently expect maintenance capital expenditures to be approximately $7.0 million to $9.0 million, net of reimbursable expenditures, in 2014.

Our Ability to Grow Depends on Our Ability to Access External Expansion Capital. Our partnership agreement requires 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 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 June 28, 2013, we entered into an amended and restated credit agreement which consists of a $400.0 million revolving loan facility. On September 15, 2014, we amended our credit facility to, among other things, amend the maximum permitted consolidated total leverage ratio as discussed below and to increase the limit on material project adjustments to EBITDA (as defined in the credit agreement). The proceeds of loans made under our credit agreement may be used for working capital and other general corporate purposes. All references herein to the credit agreement on or after June 28, 2013 refer to the amended and restated credit agreement, as amended on September 15, 2014.

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 $500.0 million for all revolving loan commitments under our credit agreement.

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The credit agreement will mature on June 28, 2018, 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 certain asset sales, property or casualty insurance claims, and condemnation proceedings, unless we reinvest such proceeds in accordance with the credit agreement, but these mandatory prepayments will not require any reduction of the lenders’ commitments under the credit agreement.

Borrowings under our credit agreement bear interest, at our option, at either the reserve-adjusted eurodollar rate (as defined in the credit agreement) plus an applicable margin that ranges from 2.0% to 3.0% or the alternate base rate (the highest of the agent bank’s prime rate, the federal funds effective rate plus 0.5%, and the 30-day eurodollar rate plus 1%) plus an applicable margin that ranges from 1.0% to 2.0%.   

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 on the unused commitments under the credit agreement.  The credit agreement does not have a floor for the alternate base rate or the eurodollar rate.  The applicable margins for the interest rate, the letter of credit fee and the commitment fee vary quarterly based on our consolidated total leverage ratio (as defined in the credit agreement, being generally computed as the ratio of consolidated total debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges).

The credit agreement includes financial covenants that will be tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter.

Prior to the date on which we issue qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notes previously or concurrently issued) that equals or exceeds $200.0 million, the maximum permitted consolidated total leverage ratio is 4.50 to 1.00; provided that:

• after we deliver the Knight Warrior Pipeline Initiation Certificate (as defined in the credit agreement, but generally meaning that we have spent at least $15.0 million of the projected capital expenditures for our Knight Warrior pipeline project), the maximum permitted consolidated total leverage ratio is 5.00 to 1.00 for the fiscal quarters ending March 31, 2015 through September 30, 2016, 4.75 to 1.00 for the fiscal quarter ending December 31, 2016, and 4.50 to 1.00 for each fiscal quarter thereafter;

• after we deliver the Knight Warrior Pipeline Leverage Election Certificate (as defined in the credit agreement, but generally meaning that we have spent at least 50% of the projected capital expenditures for the Knight Warrior pipeline project), we may elect to increase the maximum permitted consolidated total leverage ratio to 5.50 to 1.00 for two consecutive fiscal quarters ending on or before September 30, 2016; and

• if we make a specified acquisition (as defined in the credit agreement, but generally being an acquisition with consideration in excess of $15.0 million), we may elect to increase the maximum permitted consolidated total leverage ratio to 5.00 to 1.00 from and after the last day of the fiscal quarter immediately preceding the fiscal quarter in which such acquisition occurs to and including the last day of the second full fiscal quarter following the fiscal quarter in which such acquisition occurred.

From and after the date on which we issue qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notes previously or concurrently issued) that equals or exceeds $200.0 million, the maximum permitted consolidated total leverage ratio is 5.00 to 1.00; provided that after we deliver the Knight Warrior Pipeline Initiation Certificate, the maximum permitted consolidated total leverage ratio is 5.50 to 1.00 for the fiscal quarters ending March 31, 2015 through September 30, 2016, and 5.00 to 1.00 for each fiscal quarter thereafter.

The maximum permitted consolidated senior secured leverage ratio (as defined in the credit agreement, but generally computed as the ratio of consolidated total secured debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) is 3.50 to 1.00, but this covenant is only tested from and after the date on which we issue qualified senior notes in an aggregate principal amount (when combined with all other qualified senior previously or concurrently issued) that equals or exceeds $200.0 million.

The minimum permitted consolidated interest coverage ratio (as defined in the credit agreement, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest expense) is 2.50 to 1.00.

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

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• create, issue, incur or assume indebtedness;

• create, incur or assume liens;

• engage in mergers or acquisitions;

• sell, transfer, assign or convey assets;

• repurchase our equity, make distributions to unitholders and make certain other restricted payments;

• make investments;

• modify the terms of certain 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, 2014, our consolidated total leverage ratio was 3.18 to 1.00 and our consolidated interest coverage ratio was 7.12 to 1.00.  We were in compliance with all covenants of our credit agreement as of September 30, 2014.

The credit agreement permits us to make quarterly distributions of available cash (as defined in the our partnership agreement) to unitholders so long as no default or event of default exists under the credit agreement on a pro forma basis after giving effect to such distribution. We are currently allowed to make distributions to our unitholders in accordance with this covenant; however, we will only make distributions to the extent we have sufficient cash from operations after establishment of cash reserves as determined by the General Partner in accordance with our cash distribution policy, including the establishment of any reserves for the proper conduct of our business.  

Each of the following is an event of default under the 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;

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

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

• certain ERISA events involving us or our restricted subsidiaries resulting in a material adverse effect on us;

• bankruptcy or other insolvency events involving our General Partner, us or any of our restricted subsidiaries; and

• a change of control (as defined in the credit agreement, but generally being (i) our General Partner ceasing to own 100% of our general partner interest or ceasing to control us, or (ii) Vitol and Charlesbank ceasing to collectively own and control 50.0% or more of the membership interests of our General Partner).

If an event of default relating to bankruptcy or other insolvency events occurs with respect to our General Partner or us, 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.

Contractual Obligations. A summary of our contractual cash obligations over the next several fiscal years, as of September 30, 2014, is as follows: 

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	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)	$	238.6	$	7.1	$	14.2	$	217.3	$	—
Operating lease obligations	34.4		7.1		8.3		17.3		1.7
Non-compete agreement(2)	0.1		0.1		—		—		—
Employee contract obligations(3)	0.2		0.1		0.1		—		—

____________________

(1) Represents required future principal repayments of borrowings of $212.0 million and variable rate interest payments of $26.6 million.  At September 30, 2014, our borrowings had an interest rate of approximately 3.72%. This interest rate was used to calculate future interest payments.  All amounts outstanding under our credit agreement mature in June 2018.  

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

(3) Represents required future payments related to employment agreements with certain employees.

Recent Accounting Pronouncements

For information regarding recent accounting developments that may affect our future financial statements, see Note 15 to our Consolidated Financial Statements.

Item 3.    Quantitative and Qualitative Disclosures about Market Risk

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

As of October 30, 2014, we had $212.0 million outstanding under our credit facility that was subject to a variable interest rate.  Borrowings under our credit agreement bear interest, at our option, at either the reserve adjusted eurodollar rate (as defined in the credit agreement) plus an applicable margin or the alternate base rate (the highest of the agent bank’s prime rate, the federal funds effective rate plus 0.5%, and the 30-day eurodollar rate plus 1%) plus an applicable margin. Interest rate swap agreements are used to manage a portion of the exposure related to changing interest rates by converting floating-rate debt to fixed-rate debt. In March 2014, we entered into two interest rate swap agreements with an aggregate notional value of $200.0 million. The first agreement became effective June 28, 2014 and matures on June 28, 2018. Under the terms of the first interest rate swap agreement, we pay a fixed rate of 1.45% and receive one-month LIBOR with monthly settlement. The second agreement becomes effective January 28, 2015 and matures on January 28, 2019. Under the terms of the second interest rate swap agreement, we will pay a fixed rate of 1.97% and will receive one-month LIBOR with monthly settlement. The fair market value of the interest rate swaps at September 30, 2014 is a liability of $0.9 million and is recorded in long-term derivative liabilities on the consolidated balance sheet. The interest rate swaps do not receive hedge accounting treatment under ASC 815 - Derivatives and Hedging. Changes in the fair value of the interest rate swaps are recorded in interest expense in the statements of operations.

During the nine months ended September 30,2014, the weighted average interest rate under our credit agreement was 3.41%. As of September 30, 2014, borrowings under our credit facility bore interest at a weighted average interest rate of 3.72%.

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, 2014, the terms of our credit agreement, current interest rates and the effect of our interest rate swaps, an increase or decrease of 100 basis points in the interest rate would result in increased annual interest expense of approximately $1.1 million or decreased annual interest expense of $0.2 million, respectively. 

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, 2014, were effective.

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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, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 

PART II. OTHER INFORMATION

Item 1.    Legal Proceedings.

The information required by this item is included under the caption “Commitments and Contingencies” in Note 13 to our financial statements, and is incorporated herein by reference thereto.

Item 1A.    Risk Factors

Information about risk factors for the three months ended September 30, 2014 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, 2013 except as listed below.

Risks Related to the Knight Warrior Pipeline Project

Construction and additional development of the Knight Warrior pipeline project subjects us to risks of construction delays, cost over-runs, limitations on our growth and negative effects on our operating results, liquidity and financial position.

The Knight Warrior pipeline project will take more than a year to complete, and the construction of the project is subject to a number of factors not always within our control, including issues with obtaining rights-of-way from third-party landowners, the permitting processes, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weather and other factors. Some of these factors could result in meaningful delays in the construction of the project. Delays in the completion of the project could have a material adverse effect on our business, financial condition, results of operations and liquidity. The construction of the Knight Warrior pipeline project will require the expenditure of significant amounts of capital, which is subject to variables that may significantly increase expected costs. Should the actual cost of the project exceed our estimates and contingencies, our liquidity and capital position could be adversely affected.

Our expansion projects may not immediately produce operating cash flows.

Expansion projects, including the Knight Warrior pipeline, require us to make significant capital investments over time. For example, our Knight Warrior pipeline project is estimated to cost approximately $300 million and is expected to be complete by March 2016. We will incur financing costs during the planning and construction phases of these projects; however, the operating cash flows we expect these projects to generate will not materialize, if at all, until sometime after the projects are completed and placed into service. As a result, to the extent we finance our projects with borrowings, our leverage may increase during the period prior to the generation of those operating cash flows and, to the extent we finance our projects with equity, our cash available for distribution on a common unit basis may decrease during the period prior to the generation of those operating cash flows. If we experience unanticipated or extended delays in generating operating cash flow from construction projects, we may need to reduce or reprioritize our capital budget in order to meet our capital requirements, and our liquidity and capital position could be adversely affected.

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, 2014	By:	/s/ Alex G. Stallings
			Alex G. Stallings
			Chief Financial Officer and Secretary
Date:	November 6, 2014	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##	Crude Oil Throughput and Deficiency Agreement, dated August 28, 2014 between Knight Warrior LLC and Eaglebine Crude Oil Marketing LLC.
10.2	First Amendment to Amended and Restated Credit Agreement, dated as of September 15, 2014, by and among the Partnership, Wells Fargo Bank, National Association, as Administrative Agent, and the several lenders from time to time party thereto (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed September 1, 2014, and incorporated herein by reference).
31.1*	Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certifications of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1#	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”
101#	The following financial information from Blueknight Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, formatted in XBRL (eXtensible Business Reporting Language): (i) Document and Entity Information; (ii) Consolidated Balance Sheet as of December 31, 2013 and September 30, 2014; (iii) Consolidated Statements of Operations for the nine months ended September 30, 2013 and 2014; (iv) Consolidated Statement of Changes in Partners’ Capital for the nine months ended September 30, 2014; (v) Consolidated Statements of Cash Flows for the nine months ended September 30, 2013 and 2014; and (vi) Notes to Consolidated Financial Statements.

____________________

*     Filed herewith.

#     Furnished herewith

## Application has been made to the Securities and Exchange Commission for confidential treatment of certain provisions of this exhibit. Omitted material for which confidential treatment has been requested has been separately filed with the Securities and Exchange Commission.

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EX-10.1

Exhibit 10.1

*** Where this marking appears throughout this Exhibit 10.1, information has been omitted pursuant to a request for confidential treatment and such information has been filed with the Securities and Exchange Commission separately.

CRUDE OIL THROUGHPUT AND DEFICIENCY AGREEMENT

dated as of August 28, 2014

Knight Warrior LLC

and

Eaglebine Crude Oil Marketing LLC

CRUDE OIL THROUGHPUT AND DEFICIENCY AGREEMENT

THIS CRUDE OIL THROUGHPUT AND DEFICIENCY AGREEMENT (this “Agreement”), dated as of August 28, 2014 (the “Effective Date”), is by and between Eaglebine Crude Oil Marketing LLC, a Delaware limited liability company (“Shipper”), and Knight Warrior LLC, a Texas limited liability company (“Carrier”). Shipper and Carrier are sometimes referred to herein individually as “Party,” and collectively as the “Parties.”

RECITALS

WHEREAS, Carrier intends to construct and operate a crude oil pipeline and associated gathering lines in Texas, extending from the Origin Points to the Delivery Points, as such terms are hereinafter defined, with the pipeline facilities collectively referred to herein as the “Knight Warrior Pipeline” as further depicted on Exhibit A attached hereto; and

WHEREAS, Shipper desires to transport Crude Oil (as hereafter defined) on the Knight Warrior Pipeline to a Delivery Point; and

WHEREAS, Carrier is willing to transport Shipper’s Crude Oil after received by Carrier at an Origin Point of the Knight Warrior Pipeline, all on and subject to the terms and conditions set forth in this Agreement.

NOW, THEREFORE, in consideration of the mutual promises, covenants, and agreements herein contained, and intending to be legally bound hereby, Shipper and Carrier hereby covenant and agree as follows:

Article 1

Certain Definitions

The terms defined in this Article 1 shall have, for all purposes of this Agreement, the meanings set forth below:

1.1 “Additional Term” is defined in Section 2.1.

1.2 “Affiliate” means any Person that directly or indirectly, through one or more intermediaries, controls or is controlled by or is under common control with another Person. The term “control” (including its derivatives and similar terms) means possessing the power to direct or cause the direction of the management and policies of a Person, whether through ownership, by contract, or otherwise. Without limiting the foregoing, any Person shall be deemed to be an Affiliate of any specified Person if such Person owns fifty percent (50%) or more of the voting securities of the specified Person, or if fifty percent (50%) or more of the voting securities of the specified Person and such Person are under common control.

1.3 “Agreement” is defined in the preamble of this agreement.

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1.4 Annual Volume Commitment” means the product of the Daily Volume Commitment and the number of days in the applicable Contract Year.

1.5 “Applicable Law” means (i) any law, statute, regulation, code, ordinance, license, decision, order, writ, injunction, decision, directive, judgment, policy or decree of any Governmental Authority and any judicial or administrative interpretations thereof, or (ii) any applicable license, permit or compliance requirement of any Governmental Authority applicable to either Party, including environmental laws.

1.6 “Bankrupt” shall mean a person or entity that (i) is dissolved, other than pursuant to a consolidation, amalgamation or merger, (ii) becomes insolvent or is unable to pay its debts or fails or admits in writing its inability generally to pay its debts as they become due, (iii) makes a general assignment, arrangement or composition with or for the benefit of its creditors, (iv) institutes or has instituted against it a proceeding seeking a judgment of insolvency or bankruptcy or any other relief under any bankruptcy or insolvency law or other similar law affecting creditor's rights, or a petition is presented for its winding-up or liquidation, (v) has a resolution passed for its winding-up, official management or liquidation, other than pursuant to a consolidation, amalgamation or merger, (vi) seeks or becomes subject to the appointment of an administrator, provisional liquidator, conservator, receiver, trustee, custodian or other similar official for all or substantially all of its assets, (vii) has a secured party take possession of all or substantially all of its assets, or has a distress, execution, attachment, sequestration or other legal process levied, enforced or sued on or against all or substantially all of its assets, (viii) causes or is subject to any event which, under Applicable Law, has an analogous effect to any of the events specified in clauses (i) through (vii) above, inclusive, or (ix) takes any action in furtherance of, or indicating its consent to, approval of, or acquiescence in any of the foregoing acts.

1.7 “Barrels” means forty-two (42) gallons of 231 cubic inches per gallon at sixty degrees Fahrenheit (60°F).

1.8 “Batching Facilities” means the segregated storage and related facilities for batching services.

1.9 “Business Day” means any calendar day other than Saturdays and Sundays that commercial banks in Houston, Texas are open for business.

1.10 “Carrier” is defined in the preamble of this Agreement.

1.11 “Central Clock Time” means Central Standard Time, as adjusted for Central Daylight Time, as applicable.

1.12 “Change in Law” shall mean the adoption or implementation of any laws, rules or regulations by any Governmental Authority with jurisdiction subsequent to the Effective Date that was not reasonably foreseeable as of the Effective Date and which

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generally affects pipeline carriers with operations which are similar to Carrier’s, irrespective of location or distance.

1.13 “Change in Law Event” shall mean the occurrence of a Change in Law that necessitates the expenditure of Compliance Costs in order to operate the Knight Warrior Pipeline, irrespective of whether such costs are to be incurred as a onetime expenditure or periodically for an extended period.

1.14 “Commencement Date” is defined in Section 3.3 of this Agreement.

1.15 “Committed Shipper” is defined in the Rules and Regulations.

1.16 “Committed Shipper Credit” is defined in Section 5.1 of this Agreement.

1.17 “Complete” means the Knight Warrior Pipeline, the Truck Stations, the origin facilities, the delivery facilities, and associated systems and facilities such as the Batching Facilities, etc., are substantially complete and all permits and approvals have been obtained, such that the Knight Warrior Pipeline is ready to commence commercial service with respect to the receipt, transportation, handling, and delivery of Shipper’s Crude Oil in accordance with this Agreement.

1.18 “Compliance Costs” means actual non-Affiliate third party out-of-pocket expenditures, without mark-up, in excess of two million dollars ($2,000,000) incurred by Carrier and arising directly from the physical operation of the Knight Warrior Pipeline.

1.19 “Compliance Cost Recovery Period” means the period during which a Compliance Costs Surcharge is imposed for the purpose of recovering Compliance Costs.

1.20 “Compliance Costs Surcharge” has the meaning set forth in Section 4.6(a).

1.21 “Contract Year” means a period commencing at 7:00 a.m., Central Clock Time, on the Commencement Date and ending at 7:00 a.m., Central Clock Time, on the first Day of the Month of the following calendar year that coincides with or next follows the expiration of 12 months and thereafter for succeeding periods of 12 consecutive Months each.

1.22 “Credit Enhancement” has the meaning set forth in Section 6.4.

1.23 “Crude Oil” means the grade or grades of crude oil or liquid products that meet the specifications and other requirements set forth in the Rules and Regulations.

1.24 “Daily Volume Commitment” means a minimum of Forty Thousand (40,000) Barrels per Day (bpd).

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1.25 “Day” or “Daily” means a period of twenty-four (24) hours, commencing at 7:00 a.m., Central Clock Time, on a calendar day and ending at 7:00 a.m., Central Clock Time, on the next succeeding calendar day.

1.26 “Defaulting Party” is defined in Section 15.2(a) of this Agreement.

1.27 “Deficiency Payment” is defined in Section 5.2(b) of this Agreement.

1.28 “Delivery Point” has the meaning set forth in the Rules and Regulations.

1.29 “Disputed Amount” is defined in Section 6.2(b) of this Agreement.

1.30 “Effective Date” is defined in the preamble of this Agreement.

1.31 “Event of Default” is defined in Section 15.1 of this Agreement.

1.32 “Extended Period” is defined in Section 9.3(a) of this Agreement.

1.33 “Extraordinary Operating Conditions” means operating conditions that result in the capacity of the Knight Warrior Pipeline available for shipments of Crude Oil, or a segment thereof, being reduced below the then committed volumes on the applicable segment(s), for any reason, including weather conditions, repairs or maintenance, but specifically excluding events of Force Majeure other than those related to weather or repairs or maintenance.

1.34 “FERC Index” means the current “Multiplier to Use” as identified in the “Oil Pipeline Index” published annually by the FERC at: http://www.ferc.gov/industries/oil/geninfo/pipeline-index.asp.

1.35 “Force Majeure” is defined in Section 9.1 of this Agreement.

1.36 “Force Majeure Volume” is defined in Section 9.3(b) of this Agreement.

1.37 “Governmental Authority” means (i) the United States of America, (ii) any state, county, parish, municipality or other governmental subdivision within the United States of America, and (iii) any court or any governmental department, commission, board, bureau, agency or other instrumentality of the United States of America or of any state, county, or municipality.

1.38 “Increase Threshold” is defined in Section 4.6(b) of this Agreement.

1.39 “Initial Term” is defined in Section 2.1 of this Agreement.

1.40 “Investment Grade” means a credit rating for Long Term Debt of at least “BBB-”, if rated by S&P, and “Baa3”, if rated by Moody’s.

1.41 “Knight Warrior Pipeline” is defined in the recitals of this Agreement.

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1.42 “Letter of Credit” means an irrevocable standby letter of credit, in form and substance, and issued by a financial institution, reasonably acceptable to Carrier, which, without limitation, allows Carrier to demand full or partial payment thereunder in the event (i) of a Shipper default, or (ii) Carrier is entitled to damages in connection with or arising out of this Agreement or the termination or breach of this Agreement (including a breach arising out of the termination or rejection of this Agreement under the U.S. Bankruptcy Code or other applicable insolvency legal requirements), or (iii) Shipper does not deliver to Carrier a new Letter of Credit or extension, in the amount required by subsection 6.4(a), that satisfies the requirements of subsection 6.4(a).

1.43 “Long Term Debt” has the meaning set forth in Section 6.4.

1.44 “Losses” means any actual loss, cost, expense, liability, damage to person (including death) or property (including damage to the environment), demand, suit, sanction, claim, judgment, or lien.

1.45 “Moody’s” means Moody’s Investor Services, Inc., or its successor.

1.46 “Month” means a period of time beginning at 7:00 a.m., Central Clock Time on the first Day of the calendar month and ending at 7:00 a.m., Central Clock Time on the first Day of the next succeeding calendar month.

1.47 “Monthly Volume Commitment” means the product of the Daily Volume Commitment and the number of days in the applicable Month.

1.48 “Nomination” means Notice from Shipper to Carrier requesting that Carrier transport for Shipper in a given Month a stated volume of Shipper’s Crude Oil from the Origin Point to the Delivery Point under this Agreement, at the times and in the manner provided in the Rules and Regulations.

1.49 “Notice” is defined in Section 13.1 of this Agreement.

1.50 “Origin Point” has the meaning set forth in the Rules and Regulations.

1.51 “Parties” is defined in the preamble of this Agreement.

1.52 “Party” is defined in the preamble of this Agreement.

1.53 “Performing Party” is defined in Section 15.2(a) of this Agreement.

1.54 “Person” means any individual, firm, corporation, trust, partnership, limited partnership, master limited partnership, limited liability company, association, joint venture, other business enterprise or Governmental Authority.

1.55 “Prepaid Transportation Credit” is defined in Section 5.2(c)(i) of this Agreement.

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1.56 “Quarter” means a three (3) consecutive Month period as follows: January through March, April through June, July through September, and October through December.

1.57 “Quarterly Deficiency Volume” is defined in Section 5.2(a) of this Agreement.

1.58 “Quarterly Volume Commitment” means the product of the Daily Volume Commitment and the number of days in the applicable Quarter.

1.59 “Rating Agencies” means Moody’s and S&P.

1.60 “RRC” means the Railroad Commission of Texas or any successor agency.

1.61 “Rules and Regulations” is defined in Section 4.2 of this Agreement.

1.62 “S&P” means Standard & Poor’s Rating Services (a division of McGraw-Hill, Inc.) or its successor.

1.63 “Shipper” is defined in the preamble of this Agreement.

1.64 “Shipper History” is defined in the Rules and Regulations and shall be deemed to be the Annual Volume Commitment for the first twelve (12) months, and thereafter shall be deemed to be the greater of the Annual Volume Commitment and actual shipments.

1.65 “Shipper’s Capacity” is defined in Section 15.2(b) of this Agreement

1.66 “Shipper’s Crude Oil” means all Crude Oil delivered by Shipper to the Origin Point for transportation on the Knight Warrior Pipeline by Carrier to the Delivery Point.

1.67 “Tank Bottoms” is defined in Section 3.4(a) of this Agreement.

1.68 “Taxes” means any or all taxes, fees, levies, charges, assessments and/or other impositions levied, charged, imposed, assessed, or collected by any Governmental Authority having jurisdiction.

1.69 “Term” is defined in Section 2.1 of this Agreement.

1.70 “Third Party Rates” is defined in Section 16.15 of this Agreement.

1.71 “Throughput Fees” are as set forth in Exhibit C.

1.72 “Truck Stations” means those facilities identified and described as Truck Stations in Exhibit A.

1.73 “Uncommitted Shipper” has the meaning set forth in the Rules and Regulations.

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Article 2

Term

2.1 Term. The initial term of this Agreement shall commence on the Commencement Date and, unless terminated as provided below, shall remain in full force and effect until the end of the fifth (5^th) Contract Year (the “Initial Term”). Shipper has the option to extend the Initial Term of this Agreement for two additional terms of five (5) consecutive Contract Years each (each an “Additional Term”) by providing Notice to Carrier no later than 12 Months prior to the end of the Initial Term or the first Additional Term, as applicable. The Initial Term, as it may be extended under Section 9.3(a), and any Additional Terms are collectively referred to herein as the “Term.”

2.2 Early Termination. This Agreement may be terminated early as follows:

(a) by Carrier if (i) Shipper fails to perform any of its material obligations under this Agreement and (ii) such failure is not (x) excused by an event of Force Majeure under Article 9 or (y) cured by Shipper within sixty (60) Days after Notice thereof by Carrier to Shipper, or if such failure cannot be cured within such 60-Day period, Shipper has not commenced remedial action to cure such failure (and continued to diligently and timely pursue the completion of such remedial action);

(b) by Shipper if (i) Carrier fails to perform any of its material obligations under this Agreement and (ii) such failure is not (x) excused by an event of Force Majeure under Article 9 or (y) cured by Carrier within sixty (60) Days after Notice thereof by Shipper to Carrier, or if such failure cannot be cured within such 60-Day period, Carrier has not commenced remedial action to cure such failure (and continued to diligently and timely pursue the completion of such remedial action);

(c) by Carrier if Shipper fails to pay any undisputed amount when due under this Agreement (or fails to meet any of its other financial obligations hereunder) if such failure is not remedied within ten (10) Business Days after Notice of such failure is given by Carrier to Shipper;

Article 3

Construction and Commencement Date

3.1 Construction of Facilities. Carrier, at its sole cost and expense, shall design, engineer, construct, and equip, or caused to be designed, engineered, constructed, and equipped, the facilities described in and in accordance with the general specifications in Exhibit A.

3.2 Pipeline Construction. As of the Effective Date, subject to the terms of this Agreement, Carrier shall begin project design, permitting, engineering, and other work with respect to the Knight Warrior Pipeline and shall use commercially

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reasonable efforts to cause the Knight Warrior Pipeline to be Complete. Carrier will inform Shipper on a periodic basis of construction progress of the Knight Warrior Pipeline, the nature and extent of any delays, and plans to mitigate such delays.  

3.3 Commencement Date.The “Commencement Date” under this Agreement shall be the first day of the Month following the date that is thirty (30) Days after Carrier Notifies Shipper that the Knight Warrior Pipeline is Complete.

3.4 Tank Bottoms and Line Fill.

(a) Tank Bottoms. Upon Completion of the Knight Warrior Pipeline (but in no event earlier than sixty (60) Days prior to the Commencement Date), and upon commissioning of any additional tanks, Carrier shall deliver to Shipper a request for Shipper’s pro-rata portion of Carrier’s tank bottoms required to be carried by Shipper. Shipper shall be responsible for up to ten (10%) of the shell capacity of any Carrier tank or tanks designated by Carrier as a Shipper designated tank. Shipper or an affiliate of the Shipper shall provide to Carrier, at no cost to Carrier, Crude Oil required for tank bottoms to facilitate operation of the Knight Warrior Pipeline (the “Tank Bottoms”). Carrier will deliver to Shipper or an affiliate of the Shipper, at the Delivery Point, the Tank Bottoms within thirty (30) Days after Shipper ceases making shipments, provided that the parties may agree, if possible, to make physical delivery of the Tank Bottoms, arrange for a trade of like barrels to Shipper or an affiliate of the Shipper, otherwise financially settle the return of the Tank Bottoms, or a different time period for delivery.

(b) Line Fill. Subject to and in accordance with the provisions of the Rules and Regulations, when Shipper ceases making shipments, Carrier shall deliver to Shipper at the Delivery Point all of Shipper’s Crude Oil in the Knight Warrior Pipeline or otherwise available for shipment. Redelivery shall be completed as batches transit the Knight Warrior Pipeline with expected transit time based on batch size; provided, however, in no event shall the transit time exceed ninety (90) Days. As shipments are nominated an estimated window of delivery dates will be provided by Carrier. Shipper, an affiliate of the Shipper or a party whom the Shipper has the right to transport that party’s Product will at all times retain title to its Crude Oil in transit and Tank Bottoms and Carrier will provide a monthly statement to Shipper of Crude Oil and Tank Bottoms.

3.5 Pre-Commencement Date Service. Upon notification by Carrier to Shipper that a portion of the Knight Warrior Pipeline is operational prior to the Commencement Date, Shipper, at its sole option, may elect to tender Crude Oil to Carrier for service hereunder with respect to such portion of the Knight Warrior Pipeline. If Shipper elects to transport Crude Oil on the Knight Warrior Pipeline prior to the Commencement Date, Shipper will provide its pro rata share of Crude Oil required for line fill on the applicable portion of the Knight Warrior Pipeline (and any

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necessary tank bottoms) and pay the tariff (at the Committed Shipper rate) to Carrier for such transportation service, provided that except as otherwise provided in the following sentence, such shipments do not count against the Daily Volume Commitment, Monthly Volume Commitment, Quarterly Volume Commitment, or Annual Volume Commitment.

Article 4

Transportation Services, Throughput Fees and Compliance Costs

4.1 Transportation Services. Upon the Commencement Date, under and subject to the terms and conditions of this Agreement, Carrier shall provide receipt, transportation, and delivery services, including batching, subject to the proration provisions set forth in the Rules and Regulations, for volumes of Shipper’s Crude Oil, which have been properly Nominated and delivered by Shipper at an Origin Point, from such Origin Point to the Delivery Point. Carrier shall also operate and maintain the Knight Warrior Pipeline at a level that is consistent with the level of operation and maintenance that is typical for other similar crude oil pipelines that meet all Applicable Laws and industry regulations and standards. The operator of the Knight Warrior Pipeline shall be BKEP Pipeline, L.L.C. and, notwithstanding the provisions of Article 12, any replacement operator shall be subject to the prior written approval of Shipper, which approval shall not be unreasonably withheld.

4.2 Rules and Regulations. The Parties acknowledge that as of the Effective Date, Carrier is a common carrier for hire regulated by the RRC. Shipper is a Committed Shipper for purposes of the Knight Warrior Pipeline. As such, all transportation to be performed hereunder shall be subject to the rules and regulations in Carrier’s applicable tariffs in effect from time to time and on file with the RRC (as amended from time to time, the “Rules and Regulations”). A copy of such Rules and Regulations on file as of the Effective Date with the RRC is attached hereto and incorporated herein as Exhibit B. The Parties agree that the Throughput Fees, the Annual Volume Commitment, and the other provisions contained herein are essential to support the respective commitments of the Parties as described in this Agreement. Except as expressly provided herein, nothing in this Agreement shall be deemed to in any way restrict, waive, or otherwise limit Shipper’s right to initiate or participate in any governmental, regulatory, administrative or judicial proceedings. The Parties further agree that nothing in this Agreement, and none of the rates associated with this Agreement, shall be used by either Party in any other proceeding to attempt to demonstrate any rate not subject to the specific terms of this Agreement is or is not just and reasonable or otherwise in compliance with applicable law, rules, or regulations.

4.3 Shipper History. Shipper, an affiliate of the Shipper or a party whom the Shipper has given the right to transport the Shippers’ Crude Oil, shall, at all times during the Term, earn and hold one hundred percent (100%) of the Shipper History in its own name as the “shipper of record” of Shipper’s Crude Oil for purposes of any

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apportionment or allocation of capacity on the Knight Warrior Pipeline as provided in the Rules and Regulations.

4.4 Modification to Rules and Regulations. Carrier retains the right to modify the Rules and Regulations applicable to the Knight Warrior Pipeline without the permission of Shipper so long as such modifications will not unreasonably interfere with Shipper’s rights under this Agreement or adversely affect Shipper. Carrier will not support any modification to the applicable Rules and Regulations that would change Shipper’s rights as a Committed Shipper to transport up to the Daily Volume Commitment without proration if nominations by non-Committed Shippers exceed available capacity, except to the extent required by Applicable Law. Carrier will provide written notice to Shipper thirty (30) Days in advance of the proposed effective date for any changes to the Rules and Regulations.

4.5 Escalation. Carrier may adjust the Throughput Fee annually each July 1 after the Commencement Date, to reflect inflation adjustments; provided however that in no event shall Carrier be required to reduce its Throughput Fee to reflect a negative inflation adjustment The inflation adjustment will be in accordance with the lower of (a) the inflation adjustment promulgated by the Federal Energy Regulatory Commission (the “FERC Index”) or (b) one hundred and four percent (104%). In the event the FERC Index is greater than four percent (4.0%) in any given year, then the difference between the FERC Index and (b) above will be accrued and carried forward and added to future years FERC Index in subsequent years where the FERC Index is less than four percent (4.0%). For example, if the FERC Index is five percent (5.0%) in a year three post the Commencement Date, and three percent (3.0%) in year four post the Commencement Date, then the FERC Index adjustment shall be capped at four percent (4.0%) in year three when the FERC Index is five percent (5.0%) and the FERC Index adjustment shall be increased to four percent (4.0%) in year four when the calculated FERC Index is three percent (3.0%). If, during the term of this Agreement, the FERC’s indexing methodology is discontinued, the Throughput Fee shall continue pursuant to be escalated annually as of July 1 using the Producer Price index (“PPI”). Shipper agrees to not oppose changes to the Throughput Fee that Carrier makes during the Term pursuant to this Section 4.5. The Throughput Fees are based upon the Annual Volume Commitment, which shall be maintained throughout the Term until this Agreement is terminated or cancelled.

4.6 Compliance Costs.

(a) Carrier shall deliver written notice to Shipper and every other shipper on the Knight Warrior Pipeline of any Change in Law Event promptly upon learning of such event. If during the Term, Carrier becomes obligated solely as a result of a Change in Law Event to bear Compliance Costs, Carrier shall be entitled to seek recovery of the Compliance Costs in accordance with the terms hereof. Such Compliance Costs shall be recovered through a surcharge (“Compliance Costs Surcharge”) that is applicable equally to each Barrel

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shipped on the Knight Warrior Pipeline. Carrier shall reasonably determine the Compliance Costs Surcharge by taking into account the nature and estimated useful life of such costs, the segment(s) associated with such costs and dividing such cost by the total number of Barrels transported on the Knight Warrior Pipeline with respect to the immediately prior twelve (12) Month period, or such shorter period of time if the Knight Warrior Pipeline has been operating for less than twelve (12) Months at such time. Carrier shall assume for purposes of calculating the Compliance Costs Surcharge that Shipper has transported at least the Quarterly Volume Commitment in all prior periods and that every other shipper that has entered into a transportation services agreement with Carrier (if any) has transported at least its required volume on the Knight Warrior Pipeline, as set forth in that transportation services agreement. Carrier hereby represents to Shipper that as of the Effective Date, Carrier has no knowledge of any proposed or anticipated Change in Law that would result in a Compliance Costs Surcharge.

(b) Carrier shall notify Shipper, not less than ninety (90) Days prior to the implementation of any increase pursuant to this Section of the amount of such proposed increase, the reason for such increase, and the method of calculating such increase. Shipper shall have the right to notify Carrier within thirty (30) Days after Shipper receives Carrier’s notice, of Shipper’s decision not to pay such increase, but only to the extent such increase is greater than twenty percent (20%) (“Increase Threshold”) of the unadjusted rate that is affected. Shipper shall have no right to object to or refuse any increase in the rate up to the Increase Threshold, other than to object to Carrier’s calculations, and shall be bound by any increase up to the Increase Threshold. If Shipper fails to timely notify Carrier of its decision, then it shall be deemed for purposes of this Agreement that Shipper accepts and approves such increase. Carrier may, in its sole discretion, elect whether or not to request any such increase allowed under this Section. If the cost is over the Increase Threshold and Shipper decides not to pay such increase, Carrier may stop operating the Knight Warrior Pipeline with no liability to Shipper.

(c) Any Compliance Costs Surcharge implemented, amended or modified by Carrier shall be supported with detailed work papers and reasonable support for the Compliance Costs expended or to be expended and shall be provided to Shipper and all other shippers, if any, on the Knight Warrior Pipeline. Carrier shall have the right, in its sole good faith discretion, but subject to the other provisions of this Section 4.6, to amend or modify the Compliance Costs Surcharge with respect to the amount or duration of the Compliance Costs Surcharge. Any such modification or amendment shall be included in the Rules and Regulations. If Carrier proposes any increase pursuant to this section, Shipper shall be entitled to audit Carrier’s applicable books and

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records for the limited purpose of determining if the amount of the increase is justified by the actually-incurred amount of costs of the improvements and/or expenses relating to the Knight Warrior Pipeline. If such audit shall reflect that such increase was not justifiable in accordance with the foregoing, Carrier shall promptly credit the amount of such discrepancy to Shipper, unless Carrier disagrees with the results of such audit, in which case the matter shall be resolved in accordance with Article 10 of this Agreement. Any price per Barrel increase in rates to Shipper hereunder shall not be greater than the lowest price per Barrel increase imposed for the same reason on any other shippers on the Knight Warrior Pipeline imposed at the same time.

(d) Effective as of the date of Carrier’s recovery of the Compliance Costs through the Compliance Costs Surcharge, Carrier shall remove the Compliance Costs Surcharge from the Rules and Regulations and shall immediately stop collecting the Compliance Costs Surcharge from Shipper and all other shippers, if any, on the Knight Warrior Pipeline. In such event, Carrier shall promptly provide written notice to Shipper and all other shippers, if any, on the Knight Warrior Pipeline, that such recovery of the Compliance Costs has been completed, which notice shall include a statement of the total Compliance Costs recovered and the volumes against which the Compliance Costs Surcharge were assessed in recovering such Compliance Costs.

Article 5

VOLUME COMMITMENT AND DEFICIENCY PAYMENTS

5.1 Volume Commitment.

(a) During the Term, Shipper agrees to (i) ship Crude Oil on the Knight Warrior Pipeline (A) in accordance with the terms of this Agreement, (B) at the then effective Throughput Fee, and (C) in quantities equal to the Quarterly Volume Commitment for each Quarter, or (ii) pay any Deficiency Payment.

(b) Volume Increases. On the Effective Date, the Daily Volume Commitment is 40,000 barrels. Shipper shall have the right to increase the Daily Volume Commitment by any amount up to 30,000 barrels (in increments of 5,000), prior to the Commencement Date, subject to Carrier’s availability on the Knight Warrior Pipeline, by providing written notice to Carrier. After the Commencement Date, Shipper shall have the right to increase the Daily Volume Commitment (in increments of 5,000) by any amount up to 30,000 barrels (in increments of 5,000), less any increases in the Daily Volume Commitment by Shipper pre-Commencement Date, and will notify the Carrier in writing of such volumes within a commercially reasonable timeframe. In the event that Carrier does not have sufficient availability to accommodate the Shipper’s requested increase in the Daily Volume Commitment (after setting aside Available Capacity reserved for committed shippers plus a reserve of ten (10) percent of the Available Capacity of Knight

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Warrior Pipeline for walk-up shippers), then the Carrier shall use commercially reasonable efforts to increase the Available Capacity sufficient to satisfy the Shipper’s requested Daily Volume Commitment increase within twelve (12) months of Shipper providing written notice.

(c) Committed Shipper Volume Commitment Credit. During the initial Term and any Additional Term (if any), the Shipper shall receive a *** reduction in Shipper’s Daily Volume Commitment, up to a maximum Daily Volume Commitment reduction of *** barrels (“Committed Shipper Credit”), for the time during which ***. At no time shall the Shipper’s Daily Volume Commitment, taking into account the Committed Shipper Credit, be lower than *** barrels, during the Term or any Additional Term. The Carrier will be required to provide quarterly notifications to Shipper of the aggregate *** on the Knight Warrior Pipeline within ten (10) days of each calendar quarter end. Prior to the Commencement Date, ***. The Committed Shipper Credit shall not be retro-active. Any Quarterly Deficiency Volume calculated per Section 5.2 shall not be reduced on a retro-active basis by any Committed Shipper Credit.

5.2    Deficiency Payments.

(a) Definition. For purposes of this Agreement, a “Quarterly Deficiency Volume” for a particular Quarter means the amount (in Barrels), determined as of the end of such Quarter, by which the Quarterly Volume Commitment exceeds the total volume (in Barrels) of Shipper’s Crude Oil received by Carrier at an Origin Point during such Quarter under this Agreement.

Notwithstanding the foregoing, if an Extraordinary Operating Condition exists which does not constitute a Force Majeure event per Section 9.2 (b), and as a result of such Extraordinary Operating Condition, Carrier is unable in any Quarter to permit Shipper to ship and/or Shipper is unable in any Quarter to deliver or receive, sufficient volumes to meet its Quarterly Volume Commitment, then the Quarterly Deficiency Volume means the Shipper’s Adjusted Nomination (as defined in the proration policy in the Rules and Regulations) less the total volume (in Barrels) of Shipper’s Crude Oil received by the Carrier at an Origin Point during such Quarter under this Agreement; provided that the resulting number may not be less than zero.

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Should the Commencement Date not fall on the first Day of a Quarter or should the Term end on a Day other than the last Day of a Quarter, the Quarterly Deficiency Volume, if any, shall be proportionately adjusted. For example, should the Commencement Date be on the twenty fifth (25^th) date of a Quarter that has ninety one (91) days in the Quarter, then the Quarterly Deficiency Volume for the partial Quarter post Commencement Date would be proportionately adjusted by multiplying the Quarterly Deficiency Volume by 72.5% (i.e. 1 minus .275 = 72.5%, whereby .275 is derived by dividing 25by 91 days in the Quarter).

(b) Deficiency Payments. Except as provided in Section 5.2(d), if a Quarterly Deficiency Volume exists as of the end of any Quarter, then Shipper shall pay to Carrier an amount equal to the product of (i) the Quarterly Deficiency Volume for such Quarter and (ii) the Throughput Fee in effect for such Quarter (such product being the “Deficiency Payment”). Any Deficiency Payment due by Shipper hereunder shall be paid by Shipper as provided in Article 6.

(c) Prepaid Transportation Credits.

(i) If Daily Volume Commitment is 20,000 bpd or more, then any Deficiency Payments made by Shipper to Carrier under the provisions of this Section 5.2shall constitute prepayment for services hereunder (a “Prepaid Transportation Credit”) that may be carried forward for twelve (12) months; provided, however, such twelve (12) month period shall be extended on a month for month basis for every month that Shipper nominates volume in excess of its Monthly Volume Commitment but is unable to ship such excess volume as a result of the proration policy set forth in the Rules and Regulations.

(ii) If this Agreement has Terminated other than for termination pursuant to the provisions of Section 2.2(a), Section 2.2(c), or a Shipper default pursuant to Article 15 hereof, then any available Prepaid Transportation Credit shall carry forward in accordance with the periods set forth above.

(iii) Prepaid Transportation Credits may be utilized solely against shipments of Crude Oil in excess of the Quarterly Volume Commitment, which are accepted for transportation by Carrier subject to available space and in accordance with the then-effective proration policy under the Rules and Regulations, and shall be applied against the transportation charges for such volumes at the rates set forth in this Agreement.

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Article 6

Billing and Payment

6.1 Billing. No later than the 15th day of each Month after the Commencement Date, Carrier shall deliver to Shipper a statement for transportation services provided in the preceding Month setting forth (i) the volumes of Shipper’s Crude Oil (in Barrels) received at the Origin Point in that preceding Month, (ii) the Throughput Fees for that preceding Month, (iii) any adjustments for prior periods, and (iv) all other amounts due by Shipper hereunder, including any Deficiency Payments. Carrier’s invoices shall include information reasonably sufficient to explain and support any estimates and charges reflected therein, the reconciliation of any estimates made in a prior Month to any actual measurements, and any adjustments to prior period volumes and quantities.

6.2 Payment.

(a) Subject to Section 6.2(b), Shipper shall remit to Carrier amounts due under Section 6.1 by wire transfer by the later of (i) ten (10) Days after Shipper’s receipt of the statement referenced above and (ii) the twentieth (20^th) Day of each Month, to the bank account specified by Carrier on the face of the statement. If such due date is not a Business Day, payment is due on the next Business Day following such date.

(b) If Shipper disputes any portion of any invoice (the “Disputed Amount”), Shipper shall promptly Notify Carrier of the Disputed Amount and pay the undisputed portion according to the terms of this Article 6. After receipt of such Notice, Carrier shall promptly work with Shipper to resolve the dispute. If the Parties are unable to resolve such dispute within thirty (30) Days after receipt of such Notice, the Parties will submit to dispute resolution in accordance with Article 10.

6.3 Late Payments. If Shipper fails to pay any amount hereunder when due (including disputed amounts that are not paid by the due date, but are later determined to be owed), interest thereon shall accrue on the unpaid amounts in the manner provided in the Rules and Regulations.

6.4 Financial Assurances.

At all times during the Term, Shipper shall maintain at least one (1) credit rating for either its long-term issuer credit rating or its senior unsecured long term debt (either or both hereinafter “Long Term Debt”) from one of the Rating Agencies and shall have no credit rating for Long Term Debt from a Rating Agency that is lower than Investment Grade.

Credit Enhancement. If as of the Commencement Date Shipper does not satisfy Section 6.4, Shipper shall, within twenty-one (21) Days after demand by

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Carrier, provide to Carrier credit enhancement reasonably acceptable to Carrier (the “Credit Enhancement”), as follows:

(a)The Credit Enhancement shall be a Letter of Credit in an amount equal tothe product of (A) 365, multiplied by (B) the Daily Volume Commitment, and (C) the then applicable Throughput Fee. For the avoidance of doubt, Carrier shall be entitled to draw on any Letter of Credit if, at least forty-five (45) days prior to the expiration of such Letter of Credit, Shipper does not deliver to Carrier a new Letter of Credit or extension that is in the amount required by this subsection 6.4(a) and that satisfies the requirements of the definition of “Letter of Credit” set forth in Section 1; provided that, if the Letter of Credit permits partial draws, the amount drawn shall be the lesser of (1) the then remaining balance of the Letter of Credit, and (2) the amount of the Letter of Credit then required under this subsection 6.4(a). For purposes of this subsection 6.4(a), the term “then applicable Throughput Fee” shall mean the applicable Throughput Fee set forth in Schedule C attached hereto.

(b)If agreed in writing between Carrier and Shipper, but not otherwise, in lieu of the Letter of Credit, Carrier may accept as Credit Enhancement (A) a guaranty, in form and substance acceptable to Carrier, of all of Shipper’s payment obligations from a guarantor that (1) maintains at least one (1) credit rating for its Long Term Debt from one of the Rating Agencies, (2) has no credit rating for Long Term Debt that is lower than Investment Grade, and (3) is either a direct or indirect parent of Shipper, or (B) other financial assurances acceptable to Carrier and Shipper, which are from Shipper or a third party issuer and in an amount and on terms and conditions acceptable to Carrier and Shipper.

In the event Customer provides Credit Enhancement pursuant to this Section 6.4(a), but thereafter satisfies Section 6.4, Carrier shall release the Credit Enhancement (and any cash proceeds thereof then held by Carrier), less any portion thereof that has been applied in accordance with Section 6.6, within ten (10) Days after written demand; provided that the provisions of this Section 6.4 shall again apply if the Long Term Debt rating requirement per Section 6.4 above thereafter again applies.

6.5 Failure to Provide Credit Enhancement. In the event Shipper fails to comply with any obligation in Section 6.4 on or before the due date therefore, Carrier shall not be obligated to provide Shipper with access to the Knight Warrior Pipeline or to provide Services pursuant to this Agreement until such requirement is fully met.

6.6 Use of Credit Enhancement. Credit Enhancement may be applied by Carrier, in its sole discretion, against any losses suffered by Carrier in connection with this Agreement or damages to which Carrier is entitled in connection with this Agreement

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or breach thereof by Shipper (including a breach arising out of the termination or rejection of this Agreement under the U.S. Bankruptcy Code or other applicable insolvency legal requirements). The use, application or retention of the Credit Enhancement, or any portion thereof, by Carrier shall not prevent Carrier from exercising any other right or remedy provided by this Agreement, the Rules Tariff or which Carrier may otherwise have at law, in equity or by statute or regulation and shall not operate as a limita-tion on any recovery to which Carrier may otherwise be entitled.

6.7 Ongoing Payment Obligations. Notwithstanding that any Credit Enhancement shall have been provided under Section 6.4, Shipper shall continue to make ongoing payments under this Agreement, as and when such payments are due and payable under the terms hereof and thereof.

Article 7

Title

7.1 Title Warranty. Shipper represents and warrants to Carrier that Shipper has title to, or the right to transport, all of Shipper’s Crude Oil delivered hereunder.

7.2 Title to the Product. Title to the Crude Oil transported, stored and/or handled hereunder shall always remain with Shipper, an affiliate of the Shipper or with a party whom the Shipper has the right to transport that party’s Crude Oil.

7.3 Title Indemnity. SHIPPER AGREES TO INDEMNIFY AND HOLD CARRIER HARMLESS FROM ANY AND ALL CLAIMS AND LOSSES INCURRED BY CARRIER IN CONNECTION WITH, OR IN ANY MANNER WHATSOEVER RELATING TO, THE BREACH OF THE REPRESENTATION MADE BY SHIPPER IN SECTION 7.1.

Article 8

Waiver of Certain Damages/Limitation of Liability

NOTWITHSTANDING ANYTHING TO THE CONTRARY IN THIS AGREEMENT, IN NO EVENT SHALL EITHER PARTY BE LIABLE TO THE OTHER PARTY, ANY SUCCESSORS IN INTEREST OR ANY BENEFICIARY OR ASSIGNEE OF THIS AGREEMENT FOR ANY CONSEQUENTIAL, INCIDENTAL, INDIRECT, SPECIAL, OR PUNITIVE DAMAGES ARISING OUT OF THIS AGREEMENT OR ANY BREACH HEREOF. THIS ARTICLE 8 SHALL APPLY NOTWITHSTANDING THE SOLE, JOINT OR CONCURRENT NEGLIGENCE, FAULT OR RESPONSIBILITY OF THE PARTY WHOSE LIABILITY IS WAIVED BY THIS PROVISION, OR ANY OTHER EVENT OR CONDITION, WHETHER ANTICIPATED OR UNANTICIPATED, AND REGARDLESS OF WHETHER PRE-EXISTING PRIOR TO THE DATE OF THIS AGREEMENT; PROVIDED, HOWEVER, THE FOREGOING LIMITATION OF LIABILITY SHALL NOT

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BE CONSTRUED AS LIMITING THE OBLIGATION OF EITHER PARTY HEREUNDER TO INDEMNIFY THE OTHER PARTY AGAINST TORT CLAIMS ASSERTED BY UNAFFILIATED THIRD PARTIES, INCLUDING, BUT NOT LIMITED TO, THIRD PARTY CLAIMS FOR PUNITIVE, INDIRECT, INCIDENTAL OR CONSEQUENTIAL DAMAGES.

Article 9

Force Majeure

9.1 Definition. For purposes of this Agreement, “Force Majeure” means acts of God, acts of federal, state, or local government or any agencies thereof, compliance with rules, regulations, or orders of any Governmental Authority or any office, department, agency, or instrumentality thereof, strikes, lockouts, or other industrial disturbances, acts of the public enemy, acts of terrorism, wars, blockades, insurrections, riots, epidemics, landslides, lightning, earthquakes, fires, hurricanes, floods, or other adverse and severe weather conditions, washouts, civil disturbances, explosions or breakage of machinery, equipment, or lines or pipes of a Party (provided that such breakage is not caused by a Party’s failure to maintain its machinery, equipment and lines of pipes in accordance with standard industry practices), freezing of wells or lines of pipes, embargoes, or expropriations of Governmental Authorities, inability to secure or obtain or delays in securing or obtaining necessary and properly sought rights‑of‑way, easements, or similar property rights or material permits or other authorizations in connection with the Knight Warrior Pipeline, and any other cause or event, not reasonably within the control of the Party claiming suspension, and the inability to deliver Crude Oil to the Delivery Point or receive and take away Crude Oil at the Delivery Point as a result of the foregoing events. Force Majeure shall not include (i) increases in costs of materials, (ii) a Party’s financial difficulties that impair its ability to perform, (iii) conditions resulting from changes in the price of, or the market for, Crude Oil or other hydrocarbons, (iv) the depletion of Shipper’s wells or other failure by Shipper to secure a source of Crude Oil (including by purchase) for a reason not specifically enumerated above; or (v) the inability of a third party to perform a service or supply a product or material, excepting services or supply of product or materials during the construction of facilities prior to the Commencement Date.

9.2 Effect of Force Majeure.

(a) Effect. Subject to the provisions of this Article 9, if a Party is prevented from performing its obligations under this Agreement due to an event of Force Majeure then, to the extent that it is so prevented, that Party’s failure to perform shall not be considered a breach of its obligations under this Agreement, and the affected obligations of that Party shall be relieved during the continuance of that Party’s inability to perform caused by the event of Force Majeure, but for no longer period.

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(b) Remedy. The Party affected by an event of Force Majeure shall use commercially reasonable efforts to promptly remedy and mitigate the effects of the event of Force Majeure. No Party shall be compelled to resolve any strikes, lockouts, or other industrial disputes other than as it shall determine to be in its best interests.

(c) Termination by Carrier. If an event of Force Majeure that prevents Shipper from delivering any volumes of Shipper’s Crude Oil under this Agreement continues for a period of one hundred eighty (180) consecutive Days or longer or more than one hundred eighty (180) Days at any time during the Term, then Carrier shall have the right to terminate this Agreement upon Notice to Shipper.

(d) Termination by Shipper. If, except during the period preceding the Commencement Date, an event of Force Majeure that prevents Carrier from receiving and transporting any volumes of Shipper’s Crude Oil, or providing adequate means for alternate transportation, under this Agreement continues for a period of one hundred eighty (180) consecutive Days or longer or more than one hundred eighty (180) Days at any time during the Term, then Shipper shall have the right to terminate this Agreement upon Notice to Carrier with no liability of Shipper to Carrier for Throughput Fees, Deficiency Payments or Compliance Costs except as the foregoing was incurred prior to the termination by Shipper pursuant to this provision.

(e) Notice. If a Force Majeure event renders a Party unable, in whole or in part, to carry out its obligations under this Agreement, that Party shall use commercially reasonable efforts to give a timely notice to the other Party Notice and full particulars and a reasonable, good-faith estimate of the number of days of Force Majeure delay that will be caused thereby. The Party providing the Notice shall use commercially reasonable efforts to ameliorate the Force Majeure conditions

9.3 Volume Commitment Adjustments. If a Force Majeure event affects a Party’s ability to deliver or receive and transport hereunder the Daily Volume Commitment of Shipper’s Crude Oil on any Day in a Contract Year, then the following shall occur:

(a) the Term shall be extended for a period corresponding to the duration of such event of Force Majeure (the “Extended Period”);

(b) the Quarterly Volume Commitment corresponding to the period during which such Force Majeure event occurs will be reduced by an amount equal to the volume of Shipper’s Crude Oil not transported by Carrier due to such Force Majeure event (such volume reduction is referred to herein as the “Force Majeure Volume”); and

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(c) a new Annual Volume Commitment shall be established for the Extended Period in an amount equal to the Force Majeure Volume and Shipper shall be obligated to deliver the Force Majeure Volume as the Annual Volume Commitment under this Agreement during the Extended Period.

Article 10

Governing Law; Venue; Dispute Resolution

10.1 Governing Law. This Agreement is entered into in the State of Texas and shall be governed, interpreted and construed in accordance with the laws of the State of Texas without regard to the conflicts of laws provisions thereof.

10.2 Venue. The Parties agree exclusive venue for any suit, action, or proceeding brought by either Party in connection with this Agreement or arising out of the terms or conditions hereof shall be in Harris County, Texas. The Parties hereby irrevocably and unconditionally waive, to the fullest extent they may legally and effectively do so, any objection they may now or hereafter have to the laying of venue of any suit, action, or proceeding arising out of or relating to this Agreement or the transactions contemplated hereby in the state and federal courts situated in the City of Houston, Harris County, Texas.

10.3 Negotiation. Prior to submitting any dispute for resolution by a court, a Party shall provide Notice to the other Party of the occurrence of such dispute. If the Parties have failed to resolve the dispute within fifteen (15) Business Days after such Notice was given, the Parties shall seek to resolve the dispute by negotiation between senior management personnel of each Party. Such personnel shall endeavor to meet and attempt to amicably resolve the dispute. If the Parties are unable to resolve the dispute for any reason within thirty (30) Business Days after the original Notice of dispute was given, then either Party shall be entitled to pursue any remedies available at law or in equity; provided, however, this Section 10.3shall not limit a Party’s right to initiate litigation prior to the expiration of the time periods set forth in this Section 10.3 if application of statutes of limitations (or other principle of law or equity) would prevent a Party from filing a lawsuit or claim within the applicable period for filing lawsuits.

Article 11

Taxes

11.1 Taxes. Shipper shall pay any and all Taxes levied on Shipper’s Crude Oil including property Taxes on Shipper’s Crude Oil in the Knight Warrior Pipeline. Carrier shall pay any and all Taxes levied on the Knight Warrior Pipeline. Shipper shall not be liable for any Taxes assessed against Carrier based on Carrier’s income, revenues, gross receipts, or ownership of the Knight Warrior Pipeline, and all state franchise, license, and similar taxes required for the maintenance of Carrier’s corporate existence.

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11.2 Reimbursement. If Carrier is required to pay any Tax or Taxes for Shipper, Shipper shall reimburse Carrier for such taxes within thirty (30) days after receipt of an invoice and supporting documentation provided by Carrier.

Article 12

Assignment

12.1 Assignment. This Agreement, and the rights and obligations created hereby, may not be assigned, in whole or in part, by either Party without the prior written consent of the other Party, which consent shall not be unreasonably withheld, conditioned, or delayed, except either Party may assign its rights under this Agreement to an Affiliate without such prior written consent, provided such Affiliate has a financial strength at least equal to that of the assignor, and (ii) Carrier may, subject to prior notification to Shipper, assign this Agreement to a third party purchasing substantially all of Carrier’s interest in the Knight Warrior Pipeline. Any such permitted assignment shall require that the assignee assume and agree to discharge the duties and obligations of its assignor under this Agreement. No such permitted assignment by Shipper shall effect or operate to discharge any obligations (including responsibility for and payment of any Deficiency Payment) of Shipper under this Agreement. Notwithstanding the foregoing, either Party may, without the consent of the other Party, pledge, encumber, mortgage, grant a lien or security interest in or assign all or any portion of its interest in this Agreement to one or more third parties in connection with a financing transaction; provided, however, that none of the foregoing shall be deemed to relieve such Party from its obligations hereunder. If the Person which owns or controls a majority of the voting shares/rights in Carrier at any time sells or disposes of such majority of voting shares/rights, or changes its identity for any reason (including a merger, consolidation or reorganization), such change of ownership or control shall constitute an assignment for purposes of this Section 12.1.

12.2 Notice of Assignment. No such assignment, nor any succession to the interest of either Party, shall be effective and binding until the other Party is furnished with proper and satisfactory evidence of such assignment or succession.

Article 13

Notice and Statements

13.1 Notice. Any notice, statement, payment (for which Carrier has not specified an account for wire transfer), claim or other communication required or permitted hereunder (each a “Notice”) shall be in writing and shall be sent by: (i) facsimile transmission (as to all Notices other than payments); (ii) delivered by hand; (iii) sent by United States mail with all postage fully prepaid; or (iv) by courier with charges paid in accordance with the customary arrangements established by such courier, in each of the foregoing cases addressed to the other Party at the following addresses:

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If to Carrier:

Address: 201 NW 10th, Suite 200

Oklahoma City, Oklahoma 73103

Contact: General Counsel

Fax: 918-237-4138

If to Shipper:

Vitol Inc.

Attn: Contracts

1100 Louisiana Street, Suite 5100

Houston, TX 77002

Fax: (713) 230-1185

E-Mail: xcontractshou@vitol.com

SEI Energy, LLC

2120 Northgate Park Lane, Suite 402

Chattanooga, TN 37415

Fax: 423.875.6040

E-Mail: brad.sawyer@seienergy.com

Such Notices shall be deemed received as follows: (i) if delivered personally, upon delivery; (ii) if sent by United States mail, whether by express mail, registered mail, certified mail or regular mail, the notice shall be deemed to have been received on the day receipt is refused or is confirmed orally or in writing by the receiving Party; (iii) if sent by a courier service, upon delivery; or (iv) if sent by facsimile, on the Business Day following the day on which it was transmitted and confirmed by transmission report or such earlier time as confirmed orally or in writing by the receiving Party.

13.2 Change of Address. Notices of change of address of either of the Parties shall be given in writing to the other Party in the manner aforesaid and shall be observed in the giving of all future Notices required or permitted to be given hereunder.

Article 14

Indemnity

14.1 Indemnification by Shipper. SUBJECT TO ARTICLE 8, SHIPPER AGREES TO DEFEND AND INDEMNIFY CARRIER, ITS AFFILIATES, AND ITS AND THEIR RESPECTIVE DIRECTORS, OFFICERS, AND EMPLOYEES, CUSTOMERS, CONTRACTORS AND OTHER REPRESENTATIVES FROM AND AGAINST ALL LOSSES RESULTING FROM, ASSOCIATED WITH, OR ARISING OUT OF ITS PERFORMANCE OR NON-

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PERFORMANCE OF THIS AGREEMENT, OR ITS NEGLIGENCE, WILLFUL MISCONDUCT OR GROSS NEGLIGENCE.

14.2 Indemnification by Carrier.SUBJECT TO ARTICLE 8, CARRIER AGREES TO DEFEND AND INDEMNIFY SHIPPER, ITS AFFILIATES AND THEIR RESPECTIVE DIRECTORS, OFFICERS, AND EMPLOYEES, CUSTOMERS, CONTRACTORS AND OTHER REPRESENTATIVES FROM AND AGAINST ANY LOSSES RESULTING FROM, ASSOCIATED WITH, OR ARISING OUT OF CARRIER’S PERFORMANCE OR NON-PERFORMANCE OF THIS AGREEMENT, OR ITS NEGLIGENCE, WILLFUL MISCONDUCT, OR GROSS NEGLIGENCE.

14.3 Joint Liability. UNDER THE FOREGOING INDEMNITIES, WHERE THE PERSONAL INJURY TO OR DEATH OF ANY PERSON OR LOSS OF OR DAMAGE TO PROPERTY IS THE RESULT OF THE JOINT OR CONCURRENT NEGLIGENCE, GROSS NEGLIGENCE, OR WILLFUL ACTS OR OMISSIONS OF SHIPPER AND CARRIER, EACH PARTY’S DUTY OF INDEMNIFICATION WILL BE IN PROPORTION TO ITS SHARE OF SUCH JOINT OR CONCURRENT NEGLIGENCE, GROSS NEGLIGENCE, OR WILLFUL MISCONDUCT.

14.4 Procedures Relating to Indemnification. To receive the foregoing indemnities, the Party seeking indemnification must notify the other in writing of a claim or suit promptly (provided that any failure to provide such notice shall not limit a Party’s right to indemnification except to the extent that the indemnifying Party shall have been materially prejudiced thereby) and provide reasonable cooperation (at the indemnifying Party’s expense) and full authority to defend the claim or suit. Notwithstanding the foregoing, no indemnifying Party shall be entitled to settle any claim or suit without the consent of the indemnified Party unless such settlement contains a full release of the indemnified Party without any liability for any monetary damages or any type of equitable relief. Neither Party shall have any obligation to indemnify the other under any settlement made without its written consent.

Article 15

Other Provisions

15.1 Events of Default. Notwithstanding any other provision of this Agreement, an event of default (“Event of Default”) shall be deemed to occur with respect to a Party when:

(a) Such Party fails to make any undisputed payment when due under this Agreement, within thirty (30) Business Days of a written demand therefor;

(b) Other than an Event of Default described in Paragraph (a) above, such Party fails to perform any obligation or covenant to the other Party under this Agreement and such matter is not in dispute, which failure is not cured to

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the reasonable and commercially acceptable satisfaction of the other Party within thirty (30) Days from the date that such Party receives written notice that corrective action is needed;

(c) Such Party becomes Bankrupt; or

(d) An assignment or purported assignment of this Agreement in violation of the provisions of Article 12.

15.2Remedies.

(a) Notwithstanding any other provision of this Agreement, upon the occurrence of an Event of Default with respect to either Party (the “Defaulting Party”), the other Party (the “Performing Party”) shall in its reasonable discretion, in addition to all other remedies available to it and without incurring any liabilities to the Defaulting Party or to third parties, be entitled as long as such Event of Default is continuing, to do one or more of the following: (a) suspend its performance under this Agreement with prior notice of five (5) Business Days to the Defaulting Party, (b) proceed against the Defaulting Party for damages occasioned by the Defaulting Party’s failure to perform, and (c) upon five (5) Business Days’ notice to the Defaulting Party, terminate this Agreement. Notwithstanding the foregoing, in the case of an Event of Default described in Section 15.1(c)above, no prior notice shall be required. The Defaulting Party shall reimburse the Performing Party for all costs and expenses related to the Performing Party’s claim with respect to such breach, including but not limited to reasonable attorneys’ fees. The remedies provided in this provision are in addition to any and all other remedies available to the Performing Party under this Agreement and Applicable Law.

(b) If Carrier exercises its termination right under Section 15.2, then, (i) Carrier shall have the right, but absolutely no obligation, to hold an open season with respect to, or otherwise market or offer to third parties, a volume equal to Shipper’s Quarterly Volume Commitment (the “Shipper’s Capacity”) and (ii) if, as a result of any such open season, or otherwise, Carrier enters into one or more new transportation services agreements with respect to some or all of the Shipper’s Capacity, Carrier will credit to Shipper’s Quarterly Volume Commitment any revenues received by Carrier from such new shipper(s) as transportation charges or deficiency payments for committed volumes, as and when actually received by Carrier, less Carrier’s costs in marketing such Shipper’s Capacity to secure a new commitment; provided that Shipper shall not be entitled to any such credit for revenues that may accrue to the extent the tariff rate payable under such new transportation services agreement exceeds the applicable tariff rate for services to Shipper hereunder. Shipper expressly acknowledges that it shall have no right to challenge or dispute the terms and conditions of any new transportation services agreements entered into by Carrier as a result of any such open

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season, or otherwise, and that, without limitation, such new transportation services agreement(s) may expire before the last day of this Agreement and the tariff rate payable under such new transportation services agreement(s) may be less than the applicable tariff rate. In the event that Carrier holds an open season with respect to a volume equal to the committed volumes of more than one defaulting customer, Carrier shall allocate among such defaulting customers, on an equitable basis, any revenues actually received by Carrier under any new transportation services agreements executed as a result of such open season.

15.3 Carrier Representations. Carrier hereby represents to Shipper as follows:

(a) This Agreement and all documents executed by Carrier required hereby are duly authorized, executed, and delivered by Carrier, are legal, valid, and binding obligations of Carrier, and do not violate any provisions of any agreement to which Carrier is a party or to which it is subject and do not violate any duties to which Carrier is subject.

(b) There are no pending, or to Carrier’s knowledge, threatened actions, suits, arbitrations, claims or proceedings, at law or in equity, that could materially and adversely affect the development, ownership or operation of the Knight Warrior Pipeline.

Article 16

Other Provisions

16.1 Amendments. All modifications, amendments, or changes to this Agreement, whether made simultaneously with or after the execution of this Agreement, shall be in writing, and executed by both Carrier and Shipper.

16.2 Confidentiality.

(a) Confidentiality. Each Party agrees that it shall maintain all terms and conditions of this Agreement in strictest confidence, and that it shall not cause or permit disclosure of this Agreement or any provisions contained herein without the written consent of the other Party.

(b) Permitted Disclosures. Notwithstanding Section 16.2(a) of this Agreement, disclosures of any terms and provisions of this Agreement otherwise prohibited may be made by either Party: (i) to the extent necessary for such Party to enforce its rights hereunder against the other Party; (ii) to the extent to which a Party is required to disclose all or part of this Agreement by a statute or by the order or rule of a court, agency, or other Governmental Authority, by order, by regulations, or by other compulsory process (including deposition, subpoena, interrogatory, or request for production of documents); (iii) to the extent required by the applicable regulations of a

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securities or commodities exchange; (iv) to a third Person in connection with a proposed sale or other transfer of a Party’s interest in this Agreement, provided such third Person agrees in writing to be bound by the terms of this Section 16.2; (v) to its own directors, officers, employees, agents and representatives; (vi) to an Affiliate (and its employees, officers, and members); (vii) to a co-working interest owner or royalty owner of Shipper’s Crude Oil delivered hereunder, or (viii) if and to the extent such information is or becomes public other than by a violation of the terms of this Section 16.

(c) Notification. If either Party (the disclosing Party) is or becomes aware of a fact, obligation, or circumstance that has resulted or may result in a disclosure of any of the terms and conditions of this Agreement in connection with (i) litigation between private parties or (ii) a request or requirement by any legislative, regulatory, or administrative body, and such request or requirement identifies the non-disclosing Party by name, then to the extent permitted by the court or legislative, regulatory, or administrative body, the disclosing Party will provide the non-disclosing Party with prompt notice of such request or requirement in order to afford the non-disclosing Party an opportunity to seek an appropriate protective order or motion to quash.

(d) Public Announcements. If Carrier chooses to make a press release with respect to this Agreement or the transaction represented herein using Shipper’s name, Carrier shall provide Shipper with a copy of the proposed announcement or statement. Carrier shall obtain Shipper’s prior written approval of the public announcement or statement. If approval is not granted, Carrier shall remove Shipper’s name before making the press release. Nothing contained in this section shall be construed to require either Party to obtain approval of the other Party to disclose information with respect to this Agreement or the transaction represented herein to any Governmental Authority to the extent required by Applicable Law or necessary to comply with disclosure requirements of the Securities and Exchange Commission, New York Stock Exchange, or any other regulated stock exchange.

(e) Survival. The provisions of this Section 16.2 shall survive any expiration or termination of this Agreement for a period of one (1) year.

16.3 Waiver. No waiver of any term, provision or condition of this Agreement shall be effective unless in writing signed by the Parties, and no such waiver shall be deemed to be or construed as a further or continuing waiver of any such term, provision or condition or as a waiver of any other term, provision or condition of the Agreement, unless specifically so stated in such written waiver.

16.4 No Third Party Beneficiaries. This Agreement does not confer any right, remedy, obligation, or liability upon any Person not a Party hereto.

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16.5 No Partnership. It is not the intention of the Parties to create, nor is there created hereby, a partnership, trust, joint venture or association. The status of each Party hereunder is solely that of an independent contractor.

16.6 Headings. The headings and captions in this Agreement have been inserted for convenience of reference only and shall not define or limit any of the terms and provisions hereof.

16.7 Rules of Construction. In construing this Agreement, the following principles shall be followed:

(a) examples shall not be construed to limit, expressly or by implication, the matter they illustrate;

(b) the word “includes” and its syntactical variants mean “includes, but is not limited to” and corresponding syntactical variant expressions;

(c) the plural shall be deemed to include the singular and vice versa, as applicable;

(d) all references in this Agreement to an “Article,” “Section,” “subsection,” or “Exhibit” shall be to an Article, Section, subsection, or Exhibit of this Agreement, unless the context requires otherwise;

(e) unless the context otherwise requires, the words “this Agreement,” “hereof,” “hereunder,” “herein,” “hereby,” or words of similar import shall refer to this Agreement as a whole and not to a particular Article, Section, subsection, clause, Exhibit or other subdivision hereof; and

(f) each Exhibit to this Agreement is attached hereto and incorporated herein as a part of this Agreement, but if there is any conflict or inconsistency between the main body of this Agreement and any Exhibit, the provisions of the main body of this Agreement shall prevail.

16.8 Entire Agreement. This Agreement contains the entire agreement between the Parties relating to the subject matter hereof and there are no oral promises, agreements, or warranties affecting same.

16.9 Applicable Laws. This Agreement, and the performance hereunder, shall be subject to valid and applicable Federal, State and local laws and rules, orders or regulations, of any Federal, State or local agencies having appropriate jurisdiction; provided however, nothing contained herein shall be construed as a waiver of any right to question or contest any such law, order, rule, or regulation in any forum having appropriate jurisdiction.

16.10 Severability. If any provision of this Agreement shall be held to be invalid, illegal or unenforceable, (i) the validity, legality and/or enforceability of the remaining provisions shall not, in any way, be affected or impaired thereby and (ii) in lieu of

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such invalid, illegal or unenforceable provision, there shall be automatically added to this Agreement a provision as similar to such invalid, illegal or unenforceable provision as may be possible and be legal, valid and enforceable.

16.11 Joint Preparation. Shipper and Carrier acknowledge and mutually agree that this Agreement and all contents herein were jointly prepared by the Parties.

16.12 Further Assurances. Each Party shall take such acts and execute and deliver such documents as may be reasonably required to effectuate the purposes of this Agreement.

16.13 No Inducements. No director, employee, or agent of any Party shall give or receive any commission, fee, rebate, gift, or entertainment of significant cost or value in connection with this Agreement.

16.14 Counterpart Execution. This Agreement may be executed in any number of counterparts, each of which shall be considered an original, and all of which shall be considered one and the same instrument.

16.15 “Most Favored Nation” Treatment. Carrier agrees that if Carrier extends committed rates for services to any party regarding matters set forth in this Agreement (the “Third Party Rates”), and the Third Party Rates are more favorable than the Throughput Fees under this Agreement, the Throughput Fees under this Agreement shall be adjusted to reflect the Third Party Rates. Shipper and Carrier shall facilitate review by a third party of the Third Party Rates of agreements with other parties or amendments thereto to monitor Carrier’s compliance with this Section. Such agreements may be redacted to conceal the identity of the contracting party and the third party conducting such review shall be subject to appropriate confidentiality obligations.

16.16 Area of Mutual Interest (“AMI”). During the Initial Term or any Additional Terms of this Agreement, the Shipper and Shipper’s equity owners, SEI Energy, LLC (“SEI Energy”) and Vitol, Inc, (“Vitol”), collectively the AMI Parties (“AMI Parties”), hereby agree that any crude oil originated or marketed by the AMI Parties from any of the following counties located in the state of Texas: Grimes County, Houston County, Leon County, Madison County and Walker County and being transported via a crude oil pipeline to destinations in either Harris County, TX or Jefferson County, TX shall be transported on the Carrier’s pipeline.

28

IN WITNESS WHEREOF, the Parties have executed this Agreement to be effective as of the Effective Date.

Carrier
By:	/s/ Mark A. Hurley
Name:	Mark A. Hurley
Title:	CEO
Shipper
By:	/s/ Thomas Ramsey
Name:	Thomas Ramsey
Title:	Manager

IN WITNESS WHEREOF, the following Parties are hereby agreeing to be legally bound as it relates solely to the provisions outlined per Section 16.16 contained herein.

Vitol, Inc.
By:	/s/ M. A. Loya
Name:	M. A. Loya
Title:	President
SEI Energy, LLC
By:	/s/ John B. Sawyer
Name:	John B. Sawyer
Title:	President

29

EXHIBIT A

CARRIER PIPELINE

See Attached Exhibit A Map for Approximate Routing of Carrier Pipeline

Exhibit A

Exhibit A

EXHIBIT B

RULES AND REGULATIONS

See Attached Exhibit B

Exhibit B

EXHIBIT B

Texas R.R.C. No. 1

Knight Warrior LLC

LOCAL TARIFF

CONTAINING

RULES AND REGULATIONS

GOVERNING

THE GATHERING AND TRANSPORTATION

OF CRUDE PETROLEUM

BY PIPELINE

GENERAL APPLICATION

The rules and regulations published herein apply only under tariffs making specific reference by number to this tariff; supplements hereto and successive issues hereof. Specific rules and regulations published in individual tariffs will take precedence over rules and regulations published herein.

The Provisions published herein will, if effective, not result in an effect on the quality of the human environment.

ISSUED: __________, 201_ EFFECTIVE: __________, 201_

Issued by:	Compiled by:
Mark Hurley, President	Diane Stephens
Knight Warrior LLC	Knight Warrior LLC
201 NW 10th, Suite 200	201 NW 10th, Suite 200
Oklahoma City, Oklahoma 73103	Oklahoma City, Oklahoma 73103
	405.278.6448

SECTION I

RULES AND REGULATIONS OF RAILROAD COMMISSION OF TEXAS

RULE 71. PIPELINE TARIFFS.

1. ALL MARKETABLE OIL TO BE RECEIVED FOR TRANSPORTATION: By the term "marketable oil" is meant any crude petroleum adapted for refining or fuel purposes, properly settled and containing not more than two percent (2%) of basic sediment, water, or other impurities above a point six (6) inches below the pipeline connection with the tank. Pipelines shall receive for transportation all such "marketable oil" tendered; but no pipeline shall be required to receive for shipment from any one person an amount exceeding three thousand (3,000) barrels of petroleum in any one (1) day; and, if the oil tendered for transportation differs materially in character from that usually produced in the field and being transported therefrom by the pipeline, then it shall be transported under such terms as the shipper and the owner of the pipeline may agree or the Commission may require.

2. BASIC SEDIMENT, HOW DETERMINED -- TEMPERATURE: In determining the amount of sediment, water or other impurities, a pipeline is authorized to make a test of the oil offered for transportation from an average sample from each such tank, by the use of centrifugal machine, or by the use of any other appliance agreed upon by the pipeline and the Shipper. The same method of ascertaining the amount of the sediment, water or other impurities shall be used in the delivery as in the receipt of oil. A pipeline shall not be required to receive for transportation, nor shall consignee be required to accept as a delivery, any oil of a higher temperature than ninety degrees Fahrenheit (90° F), except that during the summer oil shall be received at any atmospheric temperature, and may be delivered at like temperature. Consignee shall have the same right to test the oil upon delivery at destination that the pipeline has to test before receiving from the Shipper.

3. "BARREL" DEFINED: For the purpose of these rules, a "barrel" of crude petroleum is declared to be forty-two (42) gallons of 231 cubic inches per gallon at sixty degrees Fahrenheit (60° F).

4. OIL INVOLVED IN LITIGATION, ETC. -- INDEMNITY AGAINST LOSS: When any oil offered for transportation is involved in litigation, or the ownership is in dispute, or when the oil appears to be encumbered by lien or charge of any kind, the pipeline may require of Shippers an indemnity bond to protect it against all loss.

5. STORAGE: Each pipeline shall provide, without additional charge, sufficient operational storage, such as is incidental and necessary to the transportation of oil, including storage at destination or so near thereto as to be available for prompt delivery to destination point, for five (5) days from the date of order of delivery at destination.

6. IDENTITY OF OIL, MAINTENANCE OF: A pipeline may deliver to Consignee, either the identical oil received for transportation, subject to such consequence of mixing with other oil as are incident to the usual pipeline transportation, or it may make delivery from its common stock at destination; provided, if this last be done, the delivery shall be of substantially like kind and market value.

7. MINIMUM QUANTITY TO BE RECEIVED: A pipeline shall not be required to receive less than one (1) tank carload of oil when oil is offered for loading into tank cars at destination of the pipeline. When oil is offered for transportation for other than tank car delivery, a pipeline shall not be required to receive less than five hundred (500) barrels.

8. GATHERING CHARGES: Tariffs to be filed by a pipeline shall specify separately the charges for gathering of the oil, for transportation, and for delivery. (See amendment to this rule in Item No. 50, Section hereof.)

9. GAUGING, TESTING, AND DEDUCTIONS: All crude oil tendered to a pipeline for transportation shall be measured and tested by a representative of the pipeline prior to its receipt by the pipeline. The Shipper may be present or represented at the gauging and testing. Quantities shall be determined in accordance with applicable A.P.I. Manual of Petroleum Measurement Standards. A pipeline may deduct sediment, water, and other impurities as shown by the centrifugal method, Karl Fischer method or other test agreed upon and two tenths of one percent (.2 %) for evaporation and loss during transportation.* The net balance shall be the quantity deliverable by the pipeline. In allowing the deductions, it is not the intention of the Commission to affect any tax or royalty obligations imposed by the laws of Texas on any producer or shipper of crude oil.

The gauging and testing of oil by the pipeline representative is directed toward and intended to require tank gauge measurement, or other type measuring device when authorized by the Commission, of produced crude prior to the transfer of custody to the initial transporter from a producing property. A transfer of custody of crude between transporters is subject to measurement as agreed upon by the transporters. (See exceptions to this rule in Item No. 45, Section hereof.)

__________________

* This deviates from Rule 71.9 of the General Conservation Rules in that a deduction of less than one percent (1%) will be made for evaporation and loss during transportation.

10. DELIVERY AND DEMURRAGE: Each pipeline shall transport oil with reasonable diligence, considering the quality of the oil, the distance of transportation, and other material elements, but at any time after receipt of a consignment of oil, upon twenty-four (24) hours' notice to the Consignee, may offer oil for delivery from its common stock at the point of destination, conformable to Section 6 of this rule, at a rate not exceeding ten thousand (10,000) barrels per day of twenty-four (24) hours. Computation of time of storage (as provided for in Section 5 of this rule) shall begin at the expiration of such notice. At the expiration of the time allowed in Section 5 of this rule for storage at destination, a pipeline may assess a demurrage charge on oil offered for delivery and remaining undelivered, at a rate for the first ten (10) days of one-tenth of one cent per barrel; and thereafter at a rate of three-fourths of one cent per barrel, for each day of twenty-four (24) hours or fractional part thereof.

11. PAYMENT OF TRANSPORTATION AND OTHER CHARGES*: The Shipper or Consignee shall pay all applicable gathering, transportation, and all other lawful charges accruing on petroleum delivered to and accepted by Carrier for shipment, and, if required, shall prepay or guarantee the same before acceptance by the Carrier, or pay the same before delivery. Carrier shall have a lien on all petroleum in its possession belonging to Shipper or Consignee to secure the payment of any and all unpaid gathering, transportation, or any lawful charges that are due Carrier that are unpaid by Shipper or Consignee, and may withhold such petroleum from delivery until all unpaid charged have been paid.

If any charge remains unpaid after the due date specified in Carrier's invoice, then such amount shall bear interest from the day after the date of the invoice until paid, calculated at an annual rate equivalent to 125% of the prime rate of interest, as of the date of Carrier's invoice, charged by the Citibank N.A. of New York, New York, for ninety (90) day loans made to substantial and responsible commercial borrowers or the maximum rate allowed by law, whichever is the lesser. If the invoice is not paid within thirty (30) days from the date due, Carrier shall have the right, either directly or through an agent, at any time after such publication of notice of such sale in a daily newspaper of general circulation published in the town, city, or general area where the sale is to be held, stating the time and place of sale and the quantity and location of the petroleum to be sold. At said sale, Carrier shall have the right to bid, and, if it is the highest bidder, to become the purchaser. The proceeds of disposition shall be applied in the following order: (A) To the reasonable expenses of holding, preparing for sale, selling, and to the extent allowed by law, reasonable attorney's fees and legal expense incurred by Carrier; and (B) To the satisfaction of the indebtedness secured hereby including interest herein provided from due date of invoice to date of sale. The balance of the proceeds of the sale remaining, if any, shall be held for whomsoever may be lawfully entitled thereto. (This item 11, Section I is amended by item 100, Section II below)

12. NOTICE OF CLAIMS: Notice of claims for loss, damage or delay in connection with the shipment of oil must be made in writing to the pipeline within ninety-one (91) days after the damage, loss, or delay occurred. If the claim is for failure to make delivery, the claim must be made within ninety-one (91) days after a reasonable time for delivery has elapsed.

13. TELEPHONE-TELEGRAPH LINE -- SHIPPER TO USE: If a pipeline maintains a private telegraph or telephone line, a Shipper may use it without extra charge, for message incident to shipments. However, a pipeline shall not be held liable for failure to delivery any messages away form its office or for delay in transmission or for interruption of service.

14. CONTRACTS OF TRANSPORTATION: When a consignment of oil is accepted, the pipeline shall give the Shipper a run ticket, and shall give the Shipper a statement that shows the amount of oil received for transportation, the points of origin and destination, corrections made for temperature, deductions made for impurities, and the rate for such transportation.

15. SHIPPER'S TANKS, ETC. --INSPECTION: When a shipment of oil has been offered for transportation, the pipeline shall have the right to go upon the premises where the oil is produced or stored, and have access to any and all tanks or storage receptacles for the purpose of making any examination, inspection, or test authorized by this Rule.

16. OFFERS IN EXCESS OF FACILITIES: If oil is offered to any pipeline for transportation in excess of the amount that can be immediately transported, the transportation furnished by the pipeline shall be apportioned among all Shippers in proportion to the amounts offered by each; but no offer for transportation shall be considered beyond the amount which the person requesting the shipment then has ready for shipment by the pipeline. The pipeline shall be considered as a Shipper of oil produced or purchased by itself and held for shipment through its line, and its oil shall be entitled to participate in such apportionment. (This item 16, Section I is amended by item 125, Section II below)

17. INTERCHANGE OF TONNAGE: Pipelines shall provide the necessary connections and facilities for the exchange of tonnage at every locality reached by two or more pipelines, when the Commission finds that a necessity exists for connection, and under such regulations as said Commission may determine in each case.

18. RECEIPT AND DELIVERY -- NECESSARY FACILITIES FOR: Each pipeline shall install and maintain facilities for the receipt and delivery of marketable crude petroleum of Shippers at any point on its line if the Commission finds that a necessity exists therefor, and under regulations by the Commission.

__________________

*This deviates from Rule 71.11 of the General Conservation Rules.

19. FIRES, LIGHTNING AND LEAKAGE, REPORTS OF LOSS FROM:

A. Each pipeline shall immediately notify the Commission, by telegraph, telephone, or letter of each fire that occurs at any oil tank owned or controlled by the pipeline, or of any tank struck by lightning. Each pipeline shall in like manner report each break or leak in any of its tanks or pipelines from which more than five (5) barrels escapes. Each pipeline shall report in writing to the Commission, by the fifteenth (15th) day of each Calendar Month, the estimated amount of loss of oil by fire or leakage from its tanks and pipelines for the preceding month; but not including leakage or evaporation ordinarily incident to transportation.

B. No risk of fire, storm, flood or act of God, and no risk resulting from riots, insurrection, rebellion, war, or act of the public enemy, or from quarantine or authority of law or any order, requisition or necessity of the government of the United States in time of war, shall be borne by a pipeline, nor shall any liability accrue to it from any damage thereby occasioned. If loss of any crude oil from any such causes occurs after the oil has been received for transportation, and before it has been delivered to the Consignee, the Shipper shall bear a loss in such proportion as the amount of his shipment is to all of the oil held in transportation by the pipeline at the time of such loss, and the Shipper shall be entitled to have delivered only such portion of his shipment as may remain after a deduction of his due proportion of such loss, but in such event the Shipper shall be required to pay charges only on the quantity of oil delivered. This rule shall not apply if the loss occurs because of negligence of the pipeline.

20. PRINTING AND POSTING: Each pipeline shall have Sections 1 through 19 of this rule printed on its tariff sheets, and shall post the printed sections in a prominent place in its various offices for the inspection of the shipping public. Each pipeline shall post and publish only such Rules and Regulations as may be adopted by the Commission as general rules or such special rules as may be adopted for any particular field.

SECTION II

RULES AND REGULATIONS

5. DEFINITIONS:

"A.P.I. Gravity," as used herein, means gravity determined in accordance with American Society for Testing Materials Designation D-287.

"Carrier" means the pipeline company, Knight Warrior LLC, which accepts Nominations for transportation of, and transports, Crude Oil on its Pipeline system.

“Committed Shipper” means a Shipper that has committed to ship, or pay a deficiency payment for failure to ship, certain minimum volumes of Crude Oil pursuant to a Throughput Agreement entered into with Carrier.

“Consignee” means the party owning and/or operating the destination facility for the crude petroleum transported hereunder.

"Crude Petroleum," as used herein and sometimes referred to as crude oil, oil, or petroleum (each of which may or may not be a capitalized term), means the direct product of oil wells.

“Delivery Point” means the storage or other connection where delivery is made as set forth in the rate tariff or an applicable Throughput Agreement.

“Origin Point” means the point at which Carrier takes custody of the Crude Petroleum as set forth in the rate tariff or an applicable Throughput Agreement.

“Pipeline” or “System” means the Knight Warrior Pipeline.

“Uncommitted Shipper” means a Shipper other than a Committed Shipper.

10. APPLICATION OF RATES FROM AND TO INTERMEDIATE POINTS: For shipments accepted for transportation from any point not named in tariffs making reference hereto which is intermediate to a point from which rates are published in said tariffs, through such unnamed point, the rate published therein from the next more distant point specified in the tariff will apply from such unnamed point, and the gathering charge at the next more distant point shall apply when gathering service is performed. For shipments accepted for transportation to any point not named in tariffs making reference hereto which is intermediate to a point to which rates are published in said tariffs, through such unnamed point, the rate published therein to the next more distant point specified in the tariff will apply.

25. SPECIFICATIONS AS TO QUALITY AND LEGALITY OF SHIPMENTS: Carrier reserves the right to reject any and all of the following shipments:

A. Crude Oil having a vapor pressure in excess of ten (10) pounds absolute at a temperature of 100 degrees Fahrenheit and/or an A.P.I. gravity in excess of 65 degrees.

B. Crude Oil where the Shipper or Consignee has failed to comply with all applicable laws, rule, and regulations made by any governmental authorities regulating shipments of Crude Oil.

C. Crude Oil received from tanks containing basic sediment, water, or other impurities in excess of one percent (1%) average in suspension above the pipeline connection. Where crude oil is delivered to pipeline through automatic custody transfer measurement facilities, Carrier may require use of a monitor which rejects oil containing in excess of one percent (1%) basic sediment and water. (This limitation by Carrier is supplementary to the two percent (2%) basic sediment and water limit above a point 6 inches below pipeline connection provided for in Item 1 of Railroad Commission of Texas Rule 71.)

D. If Carrier determines that a Shipper has delivered to Carrier’s facilities Crude Petroleum that has been contaminated by the existence of and or excess amounts of impure substances, including but not limited to chlorinated and/or oxygenated hydrocarbons, arsenic, lead and/or other metals which results in harm to other shippers, carriers, users of the contaminated Crude Petroleum or Carrier, such Shipper will be excluded from further entry into applicable segments of the pipeline system until such time as the quality of the Crude Petroleum is to the satisfaction of the Carrier. Carrier is not responsible for monitoring receipts or deliveries for contaminants. Further, Carrier reserves the right to dispose of any contaminated Crude Petroleum blocking its pipeline system. Disposal thereof may be made in any reasonable manner including but not limited to commercial sales, and any liability associated with the contamination or disposal of any Crude Petroleum shall be borne by the Shipper introducing the contaminated Crude Petroleum into Carrier’s system. Shipper liability includes claims of cross contamination from other shippers, carriers, or users of the contaminated Crude Petroleum and the costs of any regulatory or judicial proceeding.

E. Carrier will not accept Crude Oil containing any of the following: Waste oils, Lube oils, Crankcase oils, PCB’s or Dioxins.

30. APPLICATION OF RATES: Crude Oil accepted for gathering and/or transportation shall be subject to the rates in effect on the date of receipt by Carrier, irrespective of the date of the tendered.

31. TENDERS REQUIRED:

A. Crude Oil for shipment through lines of Carrier will be received only on properly executed tenders from the Shipper showing the point at which the Crude Oil is to be received, point of delivery, consignee, and amount of Crude Oil transported. Carrier may refuse to accept Crude Oil for transportation unless satisfactory evidence be furnished that the Shipper or Consignee has made provision for prompt receipt thereof at destination.

B. Any Shipper desiring to tender Crude Oil for transportation shall make such tender to the initial Carrier in writing on or before the twenty-fifth day of the month preceding the month during which the transportation under the tender is to begin; except that, if space is available for current movement, a Shipper may tender Crude Oil for transportation after the twenty-fifth day of the month preceding the month during which the transportation under the tender is to begin.

36. LINE FILL AND TANK BOTTOM INVENTORY: Except as may be provided for in a Throughput Agreement with a Committed Shipper, either prior to or after the acceptance of Crude Oil for transportation through the System, Carrier may, upon reasonable notice, require each Shipper to provide a pro rata part of the volume of Crude Oil necessary for pipeline fill, unavailable stocks below tank connections, and reasonable additional minimum quantities required for the efficient operation of the System. Upon the termination of shipments by Shipper, Carrier will deliver to Shipper at the Delivery Point all of Shipper’s Crude Oil in the pipeline or otherwise available for shipment. Redelivery shall be completed as batches transit the pipeline with expected transit time based on batch size. As shipments are nominated an estimated window of delivery dates will be provided by Carrier. Expected transit time is not guaranteed. Tank bottoms belonging to Shipper will be made available for removal by Shipper from the tank within 90 days after Shipper ceases making shipments, provided that the Carrier may, if possible, make physical delivery of the tank bottoms, arrange for a trade of like barrels to Shipper, or otherwise financially settle the inventory. Shipper will at all times retain title to its Crude Oil in transit and tank bottoms and Carrier will, at the discretion of Carrier, provide to or have available for Shipper, a monthly statement of Shipper’s inventory.

40. UNLOADING OR TRANSFER CHARGES:

A. All common stream shipments and all shipments that are to be moved in batches of less than [10000] bbls that are received from tank truck unloading facilities or gathering pipeline facilities provided by others, either of which delivers into Carrier's trunkline facilities, will be subject to an unloading or transfer charge of nine cents (9¢) per barrel, except that no charge in either case shall be made if the initial trunkline pumping is provided by others. This provision is not applicable to Committed Shippers unless otherwise agreed to in the applicable Throughput Agreement.

B. All shipments received from tank truck unloading facilities into Carrier's gathering facilities will be subject to the applicable gathering charge for the particular gathering facility but will not be subject to a truck unloading or transfer charge.

45. DEDUCTIONS AND QUANTITIES DELIVERABLE: (Exception to Rule 9, Section hereof and not applicable to Committed Shippers unless otherwise agreed to in the applicable Throughput Agreement).

A. All common stream shipments and all shipments that are to be moved in batches of less than 10,000 bbls that are of 45 degrees or above shall be subject to a deduction to cover the shrinkage resulting from the mixture thereof, in the facilities of Knight Warrior LLC, with Crude Oil of A.P.I. Gravity of 44.9 degrees or less according to the following table:

A.P.I. Gravity	% Deduction
45.0° through 49.9°	0.5
50.0° through 59.9°	1.0
60.0° through 65.0°	1.5

Carrier will not accept any Crude Oil for shipment above sixty-five degrees (65°) A.P.I. Gravity at sixty degrees Fahrenheit (60°F) and any Crude Oil with a Reid vapor pressure in excess of 10.0.

B. The quantity deliverable shall be reduced by deduction for sediment, water, other impurities, loss for evaporation and loss during transportation as provided for in Rule 9, Section hereof, less the applicable deduction for shrinkage.

50. GATHERING CHARGES: (Amendment to Rule 8 Section hereof.) When gathering service is performed by Carrier, gathering charges will be assessed on the net volume remaining after adjustment for temperature and deduction for basic sediment, water, other impurities, and losses, provided for in Rule 9, Section hereof, with no deduction being made for shrinkage.

55. COMMON STREAM PETROLEUM-CONNECTING CARRIERS: When both receipts from and deliveries to a connecting Carrier of substantially the same grade of Crude Oil are scheduled at the same interconnection, Carrier reserves the right, with cooperation of the connecting Carrier, to offset like volumes of such common stream Crude Oil in order to avoid the unnecessary use of energy which would be required to physically pump the offsetting volumes. When this right is exercised, Carrier will make the further deliveries for the Shipper involved from its common stream Crude Oil.

60. CHARGE FOR FUND COMPENSATION: In addition to all other charges accruing on Crude Petroleum accepted for gathering and/or transportation, a per barrel charge will be assessed and collected in the amount of any tax, fee, or other charge levied against Carrier by any Federal, State or local act, regulation or agency for the purpose of providing a fund for the reimbursement of parties who sustain costs or losses resulting from oil pipeline industry operations. Such charge will be included in the appropriate tariff filed with the Commission.

65. WARRANTIES: Shipper warrants that the Crude Oil tendered to Carrier will conform with the Specifications stated in Item 25, it will be merchantable and will not be contaminated. Shipper will be liable to Carrier, other Shippers and/or Consignees for any damage including special, incidental, and consequential, as well as attorney fees, arising from a breach of contract. Transportation of the Crude Oil may be refused or canceled if Carrier determines or is advised the the Crude Oil does not meet the requirements of these Rules and Regulations. In addition, if Carrier samples the Crude Oil prior to or after tendered by Shipper and if test results determine that the Crude Oil is non-merchantable, Shipper will be liable to Carrier for all costs and expenses incurred for such tests for non-merchantable or contaminated Crude Oil.

100. GENERAL APPLICATION: Carrier will provide working tankage that is incident and necessary to the transportation of Crude Oil, but does not provide or offer storage service. Shipper or Consignee may, by request on the original tender or shipper order, or by order for diversion or reconsignment enroute, have Crude Oil tendered for shipment stored in tanks furnished by the Shipper or Consignee at points on the lines of Carrier, when intermediate to the destination shown on the tender of shipments, subject to the conditions provided in this Section.

105. RATES APPLICABLE AND PAYMENT TERMS:

A. The following modifies and supercedes Item 11 of Section I:

Transportation charges will be computed and collected as set forth in the Rate Tariff or the agreed upon contract rate for Commited Shippers.

(i) Billing. No later than the 15th business day of each month, Carrier shall deliver to Shipper a statement for transportation services in the preceding month setting forth (i) the volumes of Shipper’s Crude Oil (in Barrels) received at the origin point, (ii) the throughput fees for that month, (iii) any adjustments for prior periods, and (iv) all other amounts due by Shipper, including any deficiency payments. Carrier’s invoices shall include information reasonably sufficient to explain and support any estimates and charges reflected therein, the reconciliation of any estimates made in a prior month to any actual measurements, and any adjustments to prior period volumes and quantities.

(ii) Payment terms for Committed Shippers.

(a) Subject to Item 100(b)(ii) of Section II, Shipper shall remit to Carrier amounts due under Item 100(a) of Section II by wire transfer by the later of (X) 10 days after Shipper’s receipt of the statement referenced above and (Y) the 20th day of each month, to the bank account specified by Carrier. If such due date is not a business day, payment is due on the next business day following such date.

(b) If Shipper disputes any portion of any invoice (the “Disputed Amount”), Shipper shall promptly notify Carrier of the disputed amount and pay the undisputed portion according to the terms of this Item 100 of Section II. After receipt of such notice, Carrier shall promptly work with Shipper to resolve the dispute.

(iii) Payment terms for other than Committed Shippers. All transportation charges shall be paid upon delivery of the Crude Petroleum at the Destination Point or may be required in advance of transportation at the option of Carrier.

(iv) Late Payments. Carrier shall have a lien on all petroleum in its possession belonging to Shipper or Consignee to secure the payment of any and all unpaid gathering, transportation, or any lawful charges that are due Carrier that are unpaid by Shipper or Consignee, and may withhold such petroleum from delivery until all unpaid charged have been paid. If Shipper fails to pay any amount hereunder when due (including disputed amounts that are not paid by the due date, but are later determined to be owed), interest thereon shall accrue on the unpaid amounts at an annual rate equivalent to 125% of the prime rate of interest, as of the date of Carrier's invoice, charged by the Citibank N.A. of New York, New York, for ninety (90) day loans made to substantial and responsible commercial borrowers or the maximum rate allowed by law, whichever is the lesser. If the invoice is not paid within thirty (30) days from the date due, Carrier shall have the right, either directly or through an agent, at any time after such publication of notice of such sale in a daily newspaper of general circulation published in the town, city, or general area where the sale is to be held, stating the time and place of sale and the quantity and location of the petroleum to be sold. At said sale, Carrier shall have the right to bid, and, if it is the highest bidder, to become the purchaser. The proceeds of disposition shall be applied in the following order: (i) To the reasonable expenses of holding, preparing for sale, selling, and to the extent allowed by law, reasonable attorney's fees and legal expense incurred by Carrier; and (ii) To the satisfaction of the indebtedness secured hereby including interest herein provided from due date of invoice to date of sale. The balance of the proceeds of the sale remaining, if any, shall be held for whomsoever may be lawfully entitled thereto.

B. Except as may be provided for in a Throughput Agreement with a Committed Shipper,in the absence of a through rate from point of origin to the storage point, the rate to the next point beyond shall be applied.

C. Crude Oil will be subject to the local rate for movement into the storage point and Crude Oil not forwarded from storage points within the specified time will be subject to the local rate into, and out of the storage point published in Carrier's tariffs lawfully on file with the Railroad Commission of Texas.

D. After a shipment has had time to arrive at destination, and on 24 hours notice to Shipper or Consignee, Carrier may begin delivery of such shipment from its common stock to Consignee at Carriers current rate of pumping. If Shipper or Consignee is unable or refuses to receive said shipment, a demurrage charge of six cents(6.0 cents) per barrel per 24 hours shall accrue from the time said notice expires, on that part of such shipment which is not received by Consignee. Carrier reserves the right, if deemed necessary to clear its pipeline system to make whatever arrangements for disposition of the shipment that are appropriate which includes selling the shipment to the first available purchaser at the best price attainable. Any expenses incurred by the Carrier in making such arrangements shall be borne by the Shipper or Consignee, in addition to any demurrage charges.

110. DELIVERY INTO STORAGE TANKS: Upon delivery of Crude Oil into storage tanks furnished by the Shipper or Consignee, its custody and possession shall be that of the Shipper or Consignee and not that of Carrier, and Carrier shall not be liable for loss of or damage to such Crude Oil while in storage.

120. NOMINATION PROCEDURE: Crude Oil for shipment through lines of the Carrier will be received only on proper notice showing the point at which the Crude Oil is to be received, point or points of delivery, Consignee, and amount of Crude Oil to be transported. The notice shall be received by the Carrier on or before the twentieth (20^th) day of the calendar month preceding the desired shipment date. If the twentieth (20^th) day of the month falls on a weekend or holiday, nominations are due on the last workday before the twentieth (20^th). The nomination may be e-mailed or faxed. A nomination must specify, for each shipment, the quantity, product, grade, origin, destination, supply sources, and Shipper, and must meet any requirements of the Delivery Point.

125. PRORATION POLICY: The Proration Policy attached hereto supercedes Item 16 of Section I.

126.SHIPPER HISTORY - ASSIGNMENT PERMITTED. Except as may be prohibited by a regulatory agency Shipper may assign its Shipper History to another Shipper (“Assignee Shipper”) (“Assigned Shipper History”). Carrier shall be given notice of such assignment in writing by the twenty-fifth (25^th) day of the month prior to the month in which an apportionment decision by the Carrier is expected to include the Assigned Shipper History in apportionment. For any purpose under these Rules and Regulations for which Shipper History is relevant, Assigned Shipper History shall apply to the Assignee Shipper as though it had been performed by the Assignee Shipper itself.

Section 130.   SURCHARGES.  Carrier shall list as a separate line item on monthly billing invoices and accounting statements to Shippers any Carrier surcharges (if any) imposed by Carrier on Shippers.

2. Will there be a provision for pipeline loss allowance? See #9]

EXPLANATION OF REFERENCE MARKS AND ABBREVIATIONS

A.P.I.	American Petroleum Institute
A.S.T.M	American Society for Testing Materials
[U]	Unchanged
[W]	Wording Change
[N]	New Wording
[C]	Cancelled

KNIGHT WARRIOR PIPELINE

PRORATION POLICY

The intention of this Proration Policy is twofold:

• To allocate the capacity of a specific Pipeline segment among the Regular Shippers and New Shippers on an equitable basis in the Nomination process.

• To maximize the actual utilization of the capacity of a specific Pipeline segment.

Carrier shall implement this Proration Policy anytime the Nominations on a specific Pipeline segment exceed the Available Capacity on that Pipeline segment.

Definitions:

Actual Shipments means the volume of Crude Oil transported over a specific Pipeline segment.

Affiliate means any Person that directly or indirectly, through one or more intermediaries, controls or is controlled by or is under common control with another Person. The term “control” (including its derivatives and similar terms) means possessing the power to direct or cause the direction of the management and policies of a Person, whether through ownership, by contract, or otherwise. Without limiting the foregoing, any Person shall be deemed to be an Affiliate of any specified Person if such Person owns more than fifty percent (50%) of the voting securities of the specified Person, or if the specified Person owns more than fifty percent (50%) of the voting securities of such Person, or if more than fifty percent (50%) of the voting securities of the specified Person and such Person are under common control.

Allocation Month means any month in which the Nominations of all Shippers on a specific Pipeline segment exceed the Available Capacity, thereby causing Carrier to implement this Proration Policy.

Available Capacity means the capacity of the Pipeline not subject to prior commitment to other shippers to transport Crude Oil.

Base Period means the twelve (12) consecutive month period ending with the second month prior to the Allocation Month for which Nominations are being apportioned, during which current Shippers establish their Shipper History.

BPM means barrels per month.

Carrier means the pipeline company, Knight Warrior LLC, which accepts Nominations for transportation of, and transports, Crude Oil on its Pipeline system.

Committed Shipper means a Shipper that has committed to ship, or pay a deficiency payment for failure to ship, certain minimum volumes of Crude Oil pursuant to a Throughput Agreement entered into with Carrier.

Committed Volume means, with respect to a Committed Shipper, the minimum daily volume of Crude Oil that such Committed Shipper committed to ship, or pay a deficiency payment for failure to ship set out in the Commited Shipper’s Throughput Agreement with Carrier.

Extraordinary Operating Conditions means (i) operating conditions that result in the capacity of the Pipeline available for shipments of Crude Oil, or a segment thereof, being reduced below the then committed volumes on the applicable segment(s), for any reason, including events of force majeure, other weather conditions, repairs or maintenance or (ii) a force majeure event at the destination point resulting in Carrier being unable to deliver Crude Oil into the applicable receipt facilities at the destination point.

Minimum Volume means the volume set forth in the Rules and Regulations.

New Shipper means any Shipper who is not a Regular Shipper.

Nomination means a notice from a Shipper to Carrier requesting that Carrier transport for Shipper in a given month a stated volume of Shipper’s Crude Oil on the Pipeline, at the times and in the manner provided in the Rules and Regulations.

Person means any individual, firm, corporation, trust, partnership, limited partnership, master limited partnership, limited liability company, association, joint venture, other business enterprise or governmental authority.

Pipeline means the Knight Warrior Pipeline.

Prepaid Transportation Credits means credits generated by deficiency payments made by a Committed Shipper under its Throughput Agreement that may be applied as prepayment for transportation by such Committed Shipper.

Proration Policy means this document, which is the official written description of the process by which Carrier will allocate Available Capacity when Nominations on any segment of the Pipeline exceed the Available Capacity.

Regular Shipper means (i) a Committed Shipper (excluding any Committed Shipper whose rights with respect in the event of prorationing have been terminated by the Carrier in accordance with its Throughput Agreement), and (ii) a Shipper that has Actual Shipments during at least 9 months of the Base Period.

Shipper means the transporter of Crude Oil on the Pipeline segment and the entity that submitted Nominations to the Carrier.

Shipper History means (a) for a Regular Shipper other than a Committed Shipper, the monthly average of such Regular Shipper’s volumes of Crude Oil actually shipped over the Base Period, and (b) for a Committed Shipper, the greater of (i) the monthly average of such Committed Shipper’s volumes of Crude Oil actually shipped over the Base Period (or such portion of such monthly average that shall not result in an allocation to any other Committed Shipper under step 2 below that reduces such other Committed Shipper below its Committed Volume) and (ii) the Committed Shipper’s Committed Volume.

Throughput Agreement means a transportation services agreement executed by the Carrier and a Committed Shipper.

Allocation Methodology:

During an Allocation Month, Available Capacity on an affected Pipeline segment will be allocated as follows:

1. In the aggregate, New Shippers will be allocated 10% of the Available Capacity of the prorated Pipeline segment in any Allocation Month, on a pro rata basis but not to exceed the lesser of a New Shipper’s Nomination or 2.5% of Available Capacity in any Allocation Month. If the pro rata allocation in an Allocation Month, based on the number of New Shippers making Nominations, results in no New Shipper being allocated the Minimum Volume, then Carrier will administer a lottery process for the total number of Minimum Volume allocations available to New Shippers in the Allocation Month. A New Shipper will not be allocated capacity through the lottery process if it is: (a) an Affiliate of a Regular Shipper, or (b) an Affiliate of another Shipper who received an allocation through the lottery process. The lottery process will be conducted as follows:

A. Carrier will use a random number generating software to randomly assign each New Shipper a number from one to the number representing the total number of New Shippers participating in the lottery (i.e. if there are fifty New Shippers, numbers one through fifty will be assigned).

B. The New Shipper assigned number one will receive the first Minimum Volume allocation. Thereafter, Minimum Volume allocations will be assigned to New Shippers sequentially, from lowest assigned number to highest assigned number, until 10% of Available Capacity is fully allocated.

2. For each prorated Pipeline segment, 90% of Available Capacity will be allocated to Regular Shippers proportionately based on the lesser of each Regular Shipper’s Shipper History or its Nomination in the Allocation Month.

3. Any Remaining Capacity after implementing steps #1 and #2 will be allocated on a pro rata basis to Committed Shippers nominating volumes to be shipped with the application of Prepaid Transportation Credits, based on the excess of such Committed Shippers’ Nomination over the capacity allocated to such Committed Shipper pursuant to Step #2.

4. Any Remaining Capacity after implementing steps #1, #2 and #3 will be allocated on a pro rata basis among all Shippers which were allocated Available Capacity pursuant to steps #1, #2 or #3 based on the excess of such Shipper’s Nomination over the capacity allocated to such Shipper pursuant to Steps #1, #2 and #3.

5. No Nominations will be considered above the amount that the Shipper has been allocated for shipment, nor will Carrier accept a Nomination which exceeds the Available Capacity. Shippers shall not make Nominations which are inflated beyond the volume such Shipper reasonably expects to be able to ship. Carrier may require written assurances from responsible officials of a Shipper, stating that this requirement has not been violated. Furthermore, during any Allocation Month no New Shipper Nomination shall be considered beyond 10% of Available Capacity. Nominations in excess of these limits will be reduced accordingly.

6. Once Carrier has determined each Shipper’s adjusted nominationfor any prorated Pipeline segment in accordance with the foregoing Allocation Methodology (the “Adjusted Nomination”), Carrier will notify each Shipper of its Adjusted Nominations for the Allocation Month, if any, which shall be binding on the Shipper absent manifest error by Carrier.

7. In the event that a Regular Shipper or New Shipper releases all or any part of its allocated capacity in sufficient time prior to the Allocation Month to permit Carrier to reallocate and revise the schedule, and as a result the Carrier is then able to solicit other Shippers to fully utilize that capacity, that Shipper's allocation will be reduced without penalty (other than any deficiency payments payable by Committed Shippers for their allocated capacity).

8. If the allocated capacity awarded to a Regular Shipper or New Shipper on a prorated Pipeline segment goes unused by that Shipper ("Unused Allocation"), then that Shipper is accountable for payment of the tariff fees for the Actual Shipments, or 100% of the Adjusted Nomination, whichever is greater. These charges will be waived when there exists Unused Allocation as a result of deliveries having been reduced at the request of the Carrier, or where Extraordinary Operating Conditions prevented full receipt or delivery of barrels nominated by the Shipper.

9. In the event that a Shipper, who in spite of having a binding Adjusted Nomination on the prorated Pipeline segment, then attempts to withdraw that binding Adjusted Nomination, and as a result the Available Capacity is not fully allocated following application of items #1 through #3 above, the newly available portion of the Available Capacity shall be allocated in the following manner:

A. Each Regular Shipper with Nominations exceeding its Adjusted Nomination for such Pipeline segment will be allocated a portion of the newly available portion of the Available Capacity in the same proportion as that which it has been assigned on the allocated Pipeline segment.

B. Each New Shipper who was allocated Available Capacity pursuant to Step #1 above whose Nominations exceeded its Adjusted Nomination will be allocated a portion of the newly available portion of the Available Capacity in the same proportion as that which it has been assigned on the allocated Pipeline segment.

C. If there are no Shippers who have Nominations exceeding their Adjusted Nominations all Shippers who have Nominations on the allocated Pipeline segment will be notified that there is additional Available Capacity on the Pipeline segment. All Nominations from these Shippers will be honored in the same proportion that their Adjusted Nomination bears to the aggregated Adjusted Nominations from all Nominations from Shippers.

EXHIBIT C

THROUGHPUT FEES

(in $’s per barrel, except bpd amounts)

Subject to Shipper Daily Volume Commitment(s) per Section 5.1, the following are the throughput rate fee tiers available to Shipper on volumes committed by Shipper and either shipped or subject to deficiency payment:

Volume Commitment, bpd	Throughput Fee (in $/Bbl) from Midway or North Zulch Stations to Houston	Rate Application	Batch Segregation
***	***	Rate applies to all barrels shipped	Segregation available
***	***	Rate applies to all barrels shipped	Segregation available
***	***	Rate applies to all barrels shipped	Segregation available
***	***	Rate applies to all barrels shipped	Segregation available
***	***	Rate applies to all barrels shipped	Segregation available
***	***	Rate applies to all barrels shipped	Segregation available

Provided the Shipper has provided written notice per Section 5.1 to increase the Shipper’s Daily Volume Commitment, the Shipper shall be entitled to the tiered rates specified above for Shipper’s indicated Daily Volume Commitment tier. Volumes shipped by Shipper above the Shipper’s Daily Volume Commitment shall be made on an as available basis by Carrier and shall incur a Throughput Fee equal to the Shipper’s Daily Volume Commitment tier indicated above

Exhibit C

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, 2014
/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, 2014
/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, 2014 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, 2014

/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, 2014

* 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.

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RELATED PARTY TRANSACTIONS (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Related Party Transaction [Line Items]
Related party revenue	$ 9,857,000	$ 15,399,000	$ 32,663,000	$ 39,381,000
Receivables from related parties	3,118,000		3,118,000		3,149,000
Vitol [Member]
Related Party Transaction [Line Items]
Related party revenue	9,600,000	15,100,000	31,900,000	39,000,000
Receivables from related parties	3,000,000		3,000,000		3,000,000
Due to Related Parties	300,000		300,000		200,000
Advantage Pipeline, L.L.C. [Member]
Related Party Transaction [Line Items]
Related party revenue	300,000	300,000	700,000	300,000
Receivables from related parties	100,000		100,000		200,000
Due to Related Parties	$ 100,000		$ 100,000

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INCOME TAXES (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
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	$ 950
Deferred tax asset	950
Less: valuation allowance	(950)
Net deferred tax asset	$ 0

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Discontinued Operations Thomson-to-Webster system (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended			3 Months Ended	9 Months Ended		3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Sep. 30, 2013 Northumberland, PA Asphalt Facility [Member] Asphalt Services [Member]	Sep. 30, 2013 Northumberland, PA Asphalt Facility [Member] Asphalt Services [Member]	Nov. 21, 2013 Northumberland, PA Asphalt Facility [Member] Asphalt Services [Member]	Sep. 30, 2013 Thompson To Webster System [Member] Crude Oil Pipeline Services [Member]	Sep. 30, 2013 Thompson To Webster System [Member] Crude Oil Pipeline Services [Member]	Dec. 31, 2013 Thompson To Webster System [Member] Crude Oil Pipeline Services [Member]	Dec. 30, 2013 Thompson To Webster System [Member] Crude Oil Pipeline Services [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenue						$ 164	$ 493		$ 410	$ 1,750
Operating						49	105		418	958
Asset impairment expense		5,900	0	5,855					5,732	5,732	5,700
Gain on sale of assets			1,780	1,732					136	1,010
Loss from discontinued operations	0	(5,489)	0	(3,542)		115	388		(5,604)	(3,930)
Diluted net loss from discontinued operations per common unit	$ 0.00	$ (0.10)	$ 0.00	$ (0.15)		$ 0.00	$ 0.02		$ (0.10)	$ (0.17)
Accounts Receivable	12,803		12,803		12,244			4				400
Plant, property and equipment, net	305,567		305,567		297,400							1,000
Assets of discontinued operations								4				1,400
Accounts Payable	8,089		8,089		6,537			13				1
Deferred Revenue								28				148
Other liabilities								84				339
Liabilities of discontinued operations								$ 125				$ 488
Basic net loss from discontinued operations per common unit	$ 0.00	$ (0.23)	$ 0.00	$ (0.15)		$ 0.01	$ 0.02		$ (0.24)	$ (0.17)

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PROPERTY, PLANT AND EQUIPMENT (Tables)

9 Months Ended

Sep. 30, 2014

Property, Plant and Equipment [Abstract]

Schedule of Property, Plant and Equipment

	Estimated Useful Lives (Years)	December 31, 2013			September 30, 2014
		(dollars in thousands)
Land	N/A	$	16,374		$	17,680
Land improvements	10-20	6,306			6,351
Pipelines and facilities	5-30	144,261			159,176
Storage and terminal facilities	10-35	234,208			238,592
Transportation equipment	3-10	16,735			14,241
Office property and equipment and other	3-20	26,371			28,182
Pipeline linefill and tank bottoms	N/A	10,193			10,186
Construction-in-progress	N/A	14,008			17,808
Property, plant and equipment, gross		468,456			492,216
Accumulated depreciation		(171,056		)	(186,649		)
Property, plant and equipment, net		$	297,400		$	305,567

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FAIR VALUE MEASUREMENTS Fair Value Measurements (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate swaps liability	$ 930	$ 0
Total	930	0
Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate swaps liability	0
Total	0
Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate swaps liability	930
Total	930
Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate swaps liability	0
Total	$ 0

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PARTNERS' CAPITAL AND DISTRIBUTIONS (Narrative) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Sep. 30, 2014
Distribution Made to Member or Limited Partner, Cash Distributions Declared	$ 4.7
Phantom Share Units and Restricted Units [Member]
Distribution Made to Member or Limited Partner, Cash Distributions Declared	0.1
Series A Preferred Unitholders [Member]
Distribution Made to Member or Limited Partner, Distributions Declared (in dollars per unit)	$ 0.17875
Distribution Made to Member or Limited Partner, Cash Distributions Declared	5.4
Limited Partner [Member]
Distribution Made to Member or Limited Partner, Distributions Declared (in dollars per unit)	$ 0.1345
Distribution Made to Member or Limited Partner, Distributions Declared, Percentage Increase Over Previous Quarter Distribution	1.50%
Distribution Made to Member or Limited Partner, Cash Distributions Declared	4.4
General Partner Interest [Member]
Distribution Made to Member or Limited Partner, Cash Distributions Declared	$ 0.2

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ORGANIZATION AND NATURE OF BUSINESS

9 Months Ended

Sep. 30, 2014

ORGANIZATION AND NATURE OF BUSINESS [Abstract]

ORGANIZATION AND NATURE OF BUSINESS

ORGANIZATION AND NATURE OF BUSINESS

Blueknight Energy Partners, L.P. and subsidiaries (collectively, the “Partnership”) is a publicly traded master limited partnership with operations in twenty-two 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 February2007 as a Delaware master limited partnership initially to own, operate and develop a diversified portfolio of complementary midstream energy assets.

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FAIR VALUE MEASUREMENTS Fair Value Measurement Reconciliation (Details) (Fair Value, Inputs, Level 3 [Member], USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014		Sep. 30, 2014
Fair Value, Inputs, Level 3 [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 2,002		$ 0
Included in Earnings	1,072	[1]	(930)	[1]
Included in other comprehensive income	0		0
Purchases, issuances, and settlements	0		0
Transfers in and/or out of Level 3	930		930
Ending Balance	0		0
The amount of total income (expense) for the period included in earnings attributable to the change in unrealized gains (losses) for liabilities still held at the reporting date	$ 1,072		$ (930)

[1] Amounts reported as included in earnings are reported as interest expense on the statements of operations.

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OPERATING SEGMENTS (Tables)

9 Months Ended

Sep. 30, 2014

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):  

	Three Months ended September 30,				Nine Months ended September 30,
	2013		2014		2013		2014
Crude Oil Terminalling and Storage Services
Service revenue
Third party revenue	$	3,216	$	1,875	$	9,149	$	7,020
Related party revenue	4,477		3,080		14,495		10,726
Total revenue for reportable segments	7,693		4,955		23,644		17,746
Operating expenses (excluding depreciation and amortization)	1,068		1,006		2,872		2,980
Operating margin (excluding depreciation and amortization)	6,625		3,949		20,772		14,766
Total assets (end of period)	$	65,314	$	67,451	$	65,314	$	67,451
Crude Oil Pipeline Services
Service revenue
Third party revenue	$	6,499	$	5,906	$	12,681	$	13,439
Related party revenue	4,807		2,098		7,179		5,934
Total revenue for reportable segments	11,306		8,004		19,860		19,373
Operating expenses (excluding depreciation and amortization)	3,968		2,484		11,056		11,600
Operating margin (excluding depreciation and amortization)	7,338		5,520		8,804		7,773
Total assets (end of period)	$	175,476	$	170,700	$	175,476	$	170,700
Crude Oil Trucking and Producer Field Services
Service revenue
Third party revenue	$	11,712	$	12,264	$	36,085	$	38,280
Related party revenue	5,805		4,433		16,370		15,057
Total revenue for reportable segments	17,517		16,697		52,455		53,337
Operating expenses (excluding depreciation and amortization)	15,226		15,607		45,469		48,235
Operating margin (excluding depreciation and amortization)	2,291		1,090		6,986		5,102
Total assets (end of period)	$	20,446	$	28,208	$	20,446	$	28,208
Asphalt  Services
Service revenue
Third party revenue	$	17,843	$	18,456	$	47,586	$	49,196
Related party revenue	310		246		1,337		946
Total revenue for reportable segments	18,153		18,702		48,923		50,142
Operating expenses (excluding depreciation and amortization)	5,895		6,627		18,510		20,115
Operating margin (excluding depreciation and amortization)	12,258		12,075		30,413		30,027
Total assets (end of period)	$	101,215	$	95,110	$	101,215	$	95,110
Total operating margin (excluding depreciation and amortization)(1)	$	28,512	$	22,634	$	66,975	$	57,668

____________________

(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,
	2013			2014			2013			2014
Operating margin (excluding depreciation and amortization) from continuing operations	$	28,512		$	22,634		$	66,975		$	57,668
Depreciation and amortization on continuing operations	(5,975		)	(6,571		)	(17,533		)	(19,342		)
General and administrative expenses	(4,649		)	(4,267		)	(13,806		)	(13,124		)
Asset impairment expense	(123		)	—			(123		)	—
Gain on sale of assets	598			808			722			1,780
Interest expense	(1,897		)	(1,640		)	(9,188		)	(8,325		)
Equity gain (loss) in unconsolidated entity	(151		)	423			(325		)	477
Income from continuing operations before income taxes	$	16,315		$	11,387		$	26,722		$	19,134

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FAIR VALUE MEASUREMENTS Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2014

Fair Value Measurements [Abstract]

Fair Value, by Balance Sheet Grouping [Table Text Block]

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

	Fair Value Measurements as of September 30, 2014
Description	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs   (Level 3)
Liabilities:
Interest rate swap liabilities	$	930	$	—	$	930	$	—
Total	$	930	$	—	$	930	$	—

The Partnership had no recurring financial assets or liabilities subject to fair value measurements as of December 31, 2013.

Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

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)
	Three Months ended September 30, 2014		Nine Months ended September 30, 2014
Beginning Balance	$	2,002	$	—
Total gains or losses (realized/unrealized):
Included in earnings(1)	1,072		(930		)
Included in other comprehensive income	—		—
Purchases, issuances, and settlements	—		—
Transfers in and/or out of Level 3	930		930
Ending Balance	$	—	$	—
The amount of  total income (expense) for the period included in earnings attributable to the change in unrealized gains (losses) for liabilities still held at the reporting date	$	1,072	$	(930	)

____________________

(1) Amounts reported as included in earnings are reported as interest expense on the statements of operations.

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OPERATING SEGMENTS (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014 Operating-segments		Sep. 30, 2013		Dec. 31, 2013
Segment Reporting Information [Line Items]
Number of operating segments (in operating segments)					4
Service revenue
Third party revenue	$ 38,501		$ 39,270		$ 107,935		$ 105,501
Related party revenue	9,857		15,399		32,663		39,381
Total revenue for reportable segments	48,358		54,669		140,598		144,882
Operating margin (excluding depreciation and amortization) from continuing operations	22,634	[1]	28,512	[1]	57,668	[1]	66,975	[1]
Total assets (end of period)	361,469				361,469				354,748
Reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes
Operating margin (excluding depreciation and amortization) from continuing operations	22,634	[1]	28,512	[1]	57,668	[1]	66,975	[1]
Depreciation and amortization on continuing operations	(6,571)		(5,975)		(19,342)		(17,533)
General and administrative expenses	(4,267)		(4,649)		(13,124)		(13,806)
Assets Impairment Charges on Continuing Operations	0		(123)		0		(123)
Gain on sale of assets	808		598		1,780		722
Interest expense	(1,640)		(1,897)		(8,325)		(9,188)
Equity (earnings) loss in unconsolidated affiliate	423		(151)		477		(325)
Income from continuing operations before income taxes	11,387		16,315		19,134		26,722
Crude Oil Terminalling and Storage Services [Member]
Service revenue
Third party revenue	1,875		3,216		7,020		9,149
Related party revenue	3,080		4,477		10,726		14,495
Total revenue for reportable segments	4,955		7,693		17,746		23,644
Operating expenses (excluding depreciation and amortization)	1,006		1,068		2,980		2,872
Operating margin (excluding depreciation and amortization) from continuing operations	3,949		6,625		14,766		20,772
Total assets (end of period)	67,451		65,314		67,451		65,314
Reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes
Operating margin (excluding depreciation and amortization) from continuing operations	3,949		6,625		14,766		20,772
Crude Oil Pipeline Services [Member]
Segment Reporting Information [Line Items]
Number of pipelines systems owned and operated (in pipeline systems)					3
Service revenue
Third party revenue	5,906		6,499		13,439		12,681
Related party revenue	2,098		4,807		5,934		7,179
Total revenue for reportable segments	8,004		11,306		19,373		19,860
Operating expenses (excluding depreciation and amortization)	2,484		3,968		11,600		11,056
Operating margin (excluding depreciation and amortization) from continuing operations	5,520		7,338		7,773		8,804
Total assets (end of period)	170,700		175,476		170,700		175,476
Reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes
Operating margin (excluding depreciation and amortization) from continuing operations	5,520		7,338		7,773		8,804
Crude Oil Trucking and Producer Field Services [Member]
Service revenue
Third party revenue	12,264		11,712		38,280		36,085
Related party revenue	4,433		5,805		15,057		16,370
Total revenue for reportable segments	16,697		17,517		53,337		52,455
Operating expenses (excluding depreciation and amortization)	15,607		15,226		48,235		45,469
Operating margin (excluding depreciation and amortization) from continuing operations	1,090		2,291		5,102		6,986
Total assets (end of period)	28,208		20,446		28,208		20,446
Reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes
Operating margin (excluding depreciation and amortization) from continuing operations	1,090		2,291		5,102		6,986
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)	42				42
Number of states that Asphalt product and residual fuel terminalling, storage and blending services at its terminalling and storage facilities are provided (in states)	21				21
Service revenue
Third party revenue	18,456		17,843		49,196		47,586
Related party revenue	246		310		946		1,337
Total revenue for reportable segments	18,702		18,153		50,142		48,923
Operating expenses (excluding depreciation and amortization)	6,627		5,895		20,115		18,510
Operating margin (excluding depreciation and amortization) from continuing operations	12,075		12,258		30,027		30,413
Total assets (end of period)	95,110		101,215		95,110		101,215
Reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes
Operating margin (excluding depreciation and amortization) from continuing operations	$ 12,075		$ 12,258		$ 30,027		$ 30,413

[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, 2013 2014 2013 2014Operating margin (excluding depreciation and amortization) from continuing operations$28,512 $22,634 $66,975 $57,668Depreciation and amortization on continuing operations(5,975) (6,571) (17,533) (19,342)General and administrative expenses(4,649) (4,267) (13,806) (13,124)Asset impairment expense(123) — (123) —Gain on sale of assets598 808 722 1,780Interest expense(1,897) (1,640) (9,188) (8,325)Equity gain (loss) in unconsolidated entity(151) 423 (325) 477Income from continuing operations before income taxes$16,315 $11,387 $26,722 $19,134

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INCOME TAXES (Tables)

9 Months Ended

Sep. 30, 2014

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, 2014 are presented below (dollars in thousands):

Deferred tax assets
Difference in bases of property, plant and equipment	$	950
Deferred tax asset	950
Less: valuation allowance	(950		)
Net deferred tax asset	$	—

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ORGANIZATION AND NATURE OF BUSINESS (Narrative) (Details)	9 Months Ended
	Sep. 30, 2014 Operating-segments States
ORGANIZATION AND NATURE OF BUSINESS [Abstract]
Number of states in which entity operates (in states)	22
Number of operating segments (in operating segments)	4

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Cash flows from operating activities:
Net income	$ 18,783	$ 22,729
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for uncollectible receivables from third parties	153	400
Provision for uncollectible receivables from related parties	171	0
Depreciation and amortization	19,342	17,812
Amortization and write-off of debt issuance costs	603	3,117
Unrealized loss related to interest rate swaps	930	0
Asset impairment charge	0	(5,855)
Gain on sale of assets	1,780	1,732
Equity-based incentive compensation	848	1,547
Equity (earnings) loss in unconsolidated affiliate	477	(325)
Changes in assets and liabilities
Increase in accounts receivable	(712)	(5,844)
Increase in receivables from related parties	(140)	(2,304)
Decrease in prepaid insurance	1,969	2,022
Decrease in other current assets	467	348
Decrease in other assets	128	11
Decrease in accounts payable	(503)	(1,490)
Decrease in accrued interest payable	(307)	(8)
Decrease in accrued interest payable to related parties	0	(304)
Increase in accrued property taxes	1,054	793
Increase (decrease) in unearned revenue	1,346	(388)
Increase (decrease) in unearned revenue from related parties	122	(97)
Increase (decrease) in accrued payroll	(913)	74
Decrease in other accrued liabilities	(1,765)	(605)
Net cash provided by operating activities	39,319	42,261
Cash flows from investing activities:
Capital expenditures	(25,372)	(56,438)
Proceeds from sale of assets	1,982	1,980
Investment in unconsolidated affiliate	0	(20,000)
Net cash used in investing activities	(23,390)	(74,458)
Cash flows from financing activities:
Payment on insurance premium financing agreement	(1,875)	(1,669)
Debt issuance costs	(326)	(3,639)
Payments on long-term payable to related party	0	(2,681)
Borrowings under credit facility	42,733	331,411
Payments under credit facility	(103,733)	(268,000)
Proceeds from Issuance of Common Limited Partners Units	71,193	0
Capital contribution related to profits interest	112	112
Distributions	(25,853)	(24,872)
Net cash provided by (used in) financing activities	(17,749)	30,662
Net decrease in cash and cash equivalents	(1,820)	(1,535)
Cash and cash equivalents at beginning of period	3,182	3,177
Cash and cash equivalents at end of period	1,362	1,642
Supplemental disclosure of cash flow information:
Increase in accounts payable related to purchase of property, plant and equipment	2,055	3,465
Increase in accounts receivable related to accrued proceeds on sale of assets	0	194
Decrease in accounts receivable related to purchase of property, plant and equipment	2,494	2,609
Decrease in accounts receivable related to purchase of property, plant and equipment	$ 0	$ 1,274

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Discontinued Operations Northumberland, PA Asphalt Facility (Details) (USD $)	3 Months Ended		9 Months Ended			3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Sep. 30, 2013 Northumberland, PA Asphalt Facility [Member] Asphalt Services [Member]	Sep. 30, 2013 Northumberland, PA Asphalt Facility [Member] Asphalt Services [Member]	Dec. 31, 2013 Northumberland, PA Asphalt Facility [Member] Asphalt Services [Member]	Nov. 21, 2013 Northumberland, PA Asphalt Facility [Member] Asphalt Services [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenue						$ 164,000	$ 493,000
Operating						49,000	105,000
Loss on disposal of facility								600,000
Loss from discontinued operations	0	(5,489,000)	0	(3,542,000)		115,000	388,000
Basic income (loss) from discontinued operations per common units	$ 0.00	$ (0.23)	$ 0.00	$ (0.15)		$ 0.01	$ 0.02
Diluted income (loss) from discontinued operations per common unit	$ 0.00	$ (0.10)	$ 0.00	$ (0.15)		$ 0.00	$ 0.02
Accounts Receivable	12,803,000		12,803,000		12,244,000				4,000
Assets of discontinued operations									4,000
Accounts Payable	8,089,000		8,089,000		6,537,000				13,000
Deferred Revenue									28,000
Other liabilities									84,000
Liabilities of discontinued operations									$ 125,000

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LONG-TERM INCENTIVE PLAN (Details) (USD $)	9 Months Ended		3 Months Ended	9 Months Ended		1 Months Ended			3 Months Ended		9 Months Ended		1 Months Ended		1 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Jun. 30, 2014 Plan [Member]	Sep. 30, 2014 Plan [Member]	Apr. 28, 2014 Plan [Member]	Mar. 31, 2014 Plan [Member] Phantom common units [Member]	Mar. 31, 2013 Plan [Member] Phantom common units [Member]	Mar. 31, 2012 Plan [Member] Phantom common units [Member]	Sep. 30, 2014 Plan [Member] Phantom common units [Member]	Sep. 30, 2013 Plan [Member] Phantom common units [Member]	Sep. 30, 2014 Plan [Member] Phantom common units [Member]	Sep. 30, 2013 Plan [Member] Phantom common units [Member]	Sep. 30, 2012 Plan [Member] Phantom common units [Member] Chief Executive Officer [Member]	Sep. 30, 2014 Plan [Member] Phantom common units [Member] Chief Executive Officer [Member]	Dec. 31, 2013 Plan [Member] Restricted common units [Member] Independent Directors [Member]	Dec. 31, 2012 Plan [Member] Restricted common units [Member] Independent Directors [Member]	Dec. 31, 2011 Plan [Member] Restricted common units [Member] Independent Directors [Member]	Mar. 31, 2012 January 2015 Vesting [Member] Plan [Member] Phantom common units [Member]	Mar. 31, 2013 January 2016 Vesting [Member] Plan [Member] Phantom common units [Member]	Mar. 31, 2014 January 2017 Vesting [Member] Plan [Member] Phantom common units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Additional Shares Authorized			1,500,000
Number of units authorized				4,100,000	2,600,000
Vesting period													5 years
Award vesting rights percentage															33.00%	33.00%	33.00%
Value of award grants (in dollars)						$ 2,500,000	$ 2,200,000	$ 2,400,000					$ 2,800,000		$ 100,000	$ 100,000	$ 42,750
Unrecognized estimated compensation cost (in dollars)									2,400,000		2,400,000			1,700,000
Equity-based incentive compensation expense (in dollars)	$ 848,000	$ 1,547,000							$ 600,000	$ 500,000	$ 1,600,000	$ 1,500,000
Number of Units [Roll Forward]
Number of Units, Nonvested, Beginning balance				1,058,162
Number of Units, Granted				276,773									500,000		7,500	7,500	7,500	353,300	251,106	276,773
Number of Units, Vested				298,936
Number of Units, Forfeited				11,304
Number of Units, Nonvested, Ending balance				1,024,695
Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, Nonvested, Beginning balance (in dollars per unit)				$ 7.03
Weighted Average Grant Date Fair Value, Granted (in dollars per unit)				$ 9.06		$ 9.06	$ 8.75	$ 6.76					$ 5.62
Weighted Average Grant Date Fair Value, Vested (in dollars per unit)				$ 7.36
Weighted Average Grant Date Fair Value, Forfeited (in dollars per unit)				$ 8.34
Weighted Average Grant Date Fair Value, Nonvested, Ending balance (in dollars per unit)				$ 7.47

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 1,362	$ 3,182
Accounts receivable, net of allowance for doubtful accounts of $69 and $222 at December 31, 2013 and September 30, 2014, respectively	12,803	12,244
Receivables from related parties, net of allowance for doubtful accounts of $0 and $171 at December 31, 2013 and September 30, 2014, respectively	3,118	3,149
Prepaid insurance	2,512	1,694
Assets held for sale, net of accumulated depreciation and impairments of $166 and $26 at December 31, 2013 and September 30, 2014, respectively	76	338
Other current assets	3,854	4,321
Total current assets	23,725	24,928
Property, plant and equipment, net of accumulated depreciation of $171,056 and $186,649 at December 31, 2013 and September 30, 2014, respectively	305,567	297,400
Investment in unconsolidated affiliate	19,975	19,498
Goodwill	7,216	7,216
Debt issuance costs, net	3,303	3,580
Intangibles and other assets, net	1,683	2,126
Total assets	361,469	354,748
Current liabilities:
Accounts payable	8,089	6,537
Accrued interest payable	175	482
Accrued property taxes payable	2,864	1,810
Unearned revenue	2,368	2,326
Unearned revenue with related parties	239	90
Accrued payroll	6,466	7,379
Other current liabilities	3,422	4,959
Total current liabilities	23,623	23,583
Unearned revenue with related parties, noncurrent	126	153
Other long-term liabilities	4,249	2,554
Interest rate swaps liability	930	0
Long-term debt	212,000	273,000
Commitments and contingencies (Note 13)
Partners’ capital:
Series A Preferred Units (30,158,619 units issued and outstanding for both dates)	204,599	204,599
Common unitholders (22,786,101 and 32,766,663 units issued and outstanding at December 31, 2013 and September 30, 2014, respectively)	526,302	461,149
General partner interest (2.1% and 1.8% interest at December 31, 2013 and September 30, 2014, respectively, with 1,127,755 general partner units outstanding at both dates)	(610,360)	(610,290)
Total Partners’ capital	120,541	55,458
Total liabilities and Partners’ capital	$ 361,469	$ 354,748

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COMMITMENTS AND CONTINGENCIES (Narrative) (Details) (USD $)	1 Months Ended	12 Months Ended
	Nov. 30, 2013 Insurance Claims [Member] bbl Pipeline_Systems	Dec. 31, 2013 Insurance Claims [Member]	Jun. 10, 2013 Pending Litigation [Member] Physical Management and Control of Crude Oil [Member] bbl	Feb. 06, 2012 Pending Litigation [Member] Physical Management and Control of Crude Oil [Member] bbl	Feb. 06, 2012 Minimum [Member] Pending Litigation [Member] Physical Management and Control of Crude Oil [Member]
Loss Contingencies [Line Items]
Judgement seeking immediate return of crude cil Linefill belonging to company (in BOE)				140,000
Gain contingency, unrecorded amount					$ 75,000
Gain Contingency, Partnership's Shortage Found by Special Master			148,000
Gain Contingency, Defendent's Overage Found By Special Master			130,000
Number of pipelines systems owned and operated (in pipeline systems)	1
Number of Barrels	500
Loss Contingency, Estimate of Possible Loss		2,100,000
Insurance Deductible Paid		$ 250,000

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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, 2013	$ 55,458	$ 461,149	$ 204,599	$ (610,290)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	18,783	2,237	16,173	373
Equity-based incentive compensation	848	831		17
Profits interest contribution	112			112
Proceeds from sale of 9,775,000 common units, net of underwriters’ discount and offering expenses of $3.2 million	71,193	71,193
Distributions	(25,853)	(9,108)	(16,173)	(572)
Balance at Sep. 30, 2014	$ 120,541	$ 526,302	$ 204,599	$ (610,360)

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DEBT (Credit Agreements) (Details) (USD $)	0 Months Ended	3 Months Ended		9 Months Ended			3 Months Ended		9 Months Ended	0 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended			3 Months Ended										9 Months Ended
	Jun. 28, 2013	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Sep. 30, 2014 Blueknight General Partners G. P., L.L.C. [Member]	Sep. 30, 2014 Vitol or Charlesbank [Member]	Sep. 30, 2013 Secured Debt and Revolving Credit Facility [Member]	Jun. 28, 2013 Secured Debt [Member]	Jun. 28, 2013 Revolving Credit Facility [Member]	Sep. 30, 2014 Revolving Credit Facility [Member]	Sep. 30, 2013 Revolving Credit Facility [Member]	Sep. 30, 2014 Revolving Credit Facility [Member]	Sep. 30, 2013 Revolving Credit Facility [Member]	Sep. 30, 2014 Revolving Credit Facility [Member] Minimum [Member]	Sep. 30, 2014 Revolving Credit Facility [Member] Maximum [Member]	Oct. 30, 2014 Revolving Credit Facility [Member] Subsequent Event [Member]	Sep. 30, 2014 Revolving Credit Facility [Member] Federal funds rate [Member]	Sep. 30, 2014 Revolving Credit Facility [Member] Eurodollar rate [Member]	Sep. 30, 2014 Revolving Credit Facility [Member] Applicable margin based on ABR [Member] Minimum [Member]	Sep. 30, 2014 Revolving Credit Facility [Member] Applicable margin based on ABR [Member] Maximum [Member]	Sep. 30, 2014 Revolving Credit Facility [Member] Applicable margin based on Eurodollar rate [Member] Minimum [Member]	Sep. 30, 2014 Revolving Credit Facility [Member] Applicable margin based on Eurodollar rate [Member] Maximum [Member]	Oct. 30, 2014 Letter of Credit [Member] Subsequent Event [Member]	Sep. 30, 2014 Interest Rate Swap [Member]	Sep. 30, 2014 Interest Rate Swap Two [Member]	Sep. 30, 2014 Aggregate Principal Above Threshold [Member] Revolving Credit Facility [Member]	Sep. 30, 2014 Aggregate Principal Below Threshold [Member] Revolving Credit Facility [Member]	Sep. 30, 2014 Provision Two, Applicable Period Two [Member] Aggregate Principal Above Threshold [Member] Revolving Credit Facility [Member]	Sep. 30, 2014 Provision Three, Applicable Period One [Member] Aggregate Principal Below Threshold [Member] Revolving Credit Facility [Member]	Sep. 30, 2014 Provision Two, Applicable Period One [Member] Aggregate Principal Above Threshold [Member] Revolving Credit Facility [Member]	Sep. 30, 2014 Provision Two, Applicable Period One [Member] Aggregate Principal Below Threshold [Member] Revolving Credit Facility [Member]	Sep. 30, 2014 Provision One, Applicable Period Three [Member] Aggregate Principal Below Threshold [Member] Revolving Credit Facility [Member]	Sep. 30, 2014 Provision One, Applicable Period Two [Member] Aggregate Principal Below Threshold [Member] Revolving Credit Facility [Member]	Sep. 30, 2014 Provision One, Applicable Period One [Member] Aggregate Principal Above Threshold [Member] Revolving Credit Facility [Member]	Sep. 30, 2014 Provision One, Applicable Period One [Member] Aggregate Principal Below Threshold [Member] Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Revolving credit facility amount											$ 400,000,000
Borrowings under credit facility				42,733,000	331,411,000
Repayments of Long-term Debt				103,733,000	268,000,000
Revolver borrowings																		212,000,000
Letters of credit outstanding, amount																									700,000
Unused borrowing capacity																		187,300,000
Maximum borrowing capacity including additional lenders												500,000,000		500,000,000
Basis spread on variable rate (as a percent)																			0.50%	1.00%			2.00%	3.00%
Applicable margin interest rate increase (as a percent)																					1.00%	2.00%
Unused capacity, commitment fee (as a percent)																0.375%	0.50%
Consolidated total leverage (as a ratio), Maximum permitted																													4.50	5.00	5.00	5.50	5.50	4.50	4.75	5.00	5.00
Minimum Acquisition Costs																													15,000,000.0
Minimum Percent of Projected Capital Expenditures																													50.00%
Minimum Capital Expenditure																													15,000,000.0
Debt Instrument Covenant, Issued Qualified Senior Notes																200,000,000												200,000,000	200,000,000
Debt Instrument Maximum Covenant Consolidated Senior Secured Leverage Ratio												3.50		3.50
Consolidated interest coverage (as a ratio), minimum permitted												2.50		2.50
Consolidated total leverage (as a ratio), actual												3.18		3.18
Consolidated interest coverage (as a ratio), actual												7.12		7.12
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)							100.00%
Credit agreement, Constitute a change of control if Vitol Holding BV and Charlesbank ceasing to collectively own and control 50% of the GP								50.00%
Write off of Deferred Debt Issuance Cost	2,000,000									1,800,000	200,000
Debt issuance costs, net		3,303,000		3,303,000		3,580,000					500,000
Debt Instrument, Interest Rate During Period		3.41%	3.18%	3.41%	4.39%
Debt issuance costs				326,000	3,639,000				200,000			300,000	300,000	300,000	3,400,000
Amortization and write-off of debt issuance costs		200,000	200,000	600,000	1,100,000
Interest expense for long-term debt		2,500,000	2,200,000	7,300,000	8,200,000
Weighted average interest rate (as a percent)												3.72%		3.72%
Interest expense related to credit agreement		1,640,000	1,897,000	8,325,000	9,188,000
Capitalized interest		84,000	272,000	244,000	969,000
Derivative, Notional Amount		200,000,000		200,000,000																						100,000,000	100,000,000
Derivative, Fixed Interest Rate																										1.45%	1.97%
Interest Expense, Other		300,000		300,000
Interest rate swaps liability		$ 930,000		$ 930,000		$ 0

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INCOME TAXES

9 Months Ended

Sep. 30, 2014

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

The anticipated after-tax economic benefit of an investment in the Partnership’s 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 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, 2014 are presented below (dollars in thousands):

Deferred tax assets
Difference in bases of property, plant and equipment	$	950
Deferred tax asset	950
Less: valuation allowance	(950		)
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.

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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, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Earnings Per Share [Abstract]
Income from continuing operations	$ 11,271	$ 16,030	$ 18,783	$ 26,271
Loss from discontinued operations	0	(5,489)	0	(3,542)
Net income	11,271	10,541	18,783	22,729
General partner interest in net income	247	220	437	537
Preferred interest in net income	5,391	5,391	16,173	16,173
Income available to limited partners	$ 5,633	$ 4,930	$ 2,173	$ 6,019
Basic and diluted weighted average number of units:
Common units	23,909	22,697	23,245	22,684
Common units	54,927	53,718	23,245	22,684
Basic net income from continuing operations per common unit	$ 0.23	$ 0.44	$ 0.09	$ 0.41
Basic net loss from discontinued operations per common unit	$ 0.00	$ (0.23)	$ 0.00	$ (0.15)
Restricted and phantom units	725	699	659	667
Basic net income per common unit	$ 0.23	$ 0.21	$ 0.09	$ 0.26
Diluted net income from continuing operations per common unit	$ 0.20	$ 0.29	$ 0.09	$ 0.41
Diluted net loss from discontinued operations per common unit	$ 0.00	$ (0.10)	$ 0.00	$ (0.15)
Diluted net income per common unit	$ 0.20	$ 0.19	$ 0.09	$ 0.26

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Discontinued Operations DISCONTINUED OPERATIONS (Tables)

9 Months Ended

Sep. 30, 2013

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]

The amounts of revenue and costs reported in discontinued operations are set forth in the table below for the period indicated:

	Three Months ended September 30			Nine Months ended September 30,
	2013			2013
	(in thousands, except per unit data)
Total revenue	$	410		$	1,750
Expenses:
Operating	418			958
Asset impairment expense	5,732			5,732
Gain on sale of assets	136			1,010
Loss from discontinued operations	$	(5,604	)	$	(3,930	)
Basic net loss from discontinued operations per common unit	$	(0.24	)	$	(0.17	)
Diluted net loss from discontinued operations per common unit	$	(0.10	)	$	(0.17	)

The following table discloses the major classes of discontinued assets and liabilities related to the Thompson to Webster Pipeline System at the disposal date:

	December 30, 2013
	(in thousands)
Assets
Accounts Receivable	$	400
Property, plant and equipment, net	1,000
Assets of discontinued operations	$	1,400
Liabilities
Accounts Payable	$	1
Deferred Revenue	148
Other liabilities	339
Liabilities of discontinued operations	$	488

The amounts of revenue and costs reported in discontinued operations are set forth in the table below for the period indicated:

	Three Months ended September 30,		Nine Months ended September 30,
	2013		2013
	(in thousands, except per unit data)
Total revenue	$	164	$	493
Expenses:
Operating	49		105
Income from discontinued operations	$	115	$	388
Basic net income from discontinued operations per common unit	$	0.01	$	0.02
Diluted net income from discontinued operations per common unit	$	—	$	0.02

The following table discloses the major classes of discontinued assets and liabilities related to the Northumberland asphalt facility at the disposal date:

	November 21, 2013
	(in thousands)
Assets
Accounts Receivable	$	4
Assets of discontinued operations	$	4
Liabilities
Accounts Payable	$	13
Deferred Revenue	28
Other liabilities	84
Liabilities of discontinued operations	$	125

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CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL (PARENTHETICAL) (USD $) In Millions, except Share data, unless otherwise specified	Sep. 30, 2014	Sep. 22, 2014
Statement of Partners' Capital [Abstract]
Limited Partners' Capital Account, Units Issued		9,775,000
Limited Partners' Offering Costs	$ 3.2

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Current assets:
Accounts receivable, allowance for doubtful accounts	$ 222	$ 69
Receivables from related parties, allowance for doubtful accounts	171	0
Accumulated Depreciation and Impairments, Assets held for sale	26	166
Accumulated Depreciation and Impairments, property plant and equipment	$ 186,649	$ 171,056
Partners’ capital:
Series A Preferred unitholders, units issued	30,158,619	30,158,619
Series A Preferred unitholders, units outstanding	30,158,619	30,158,619
Common unitholders, units issued	32,766,663	22,786,101
Common unitholders, units outstanding	32,766,663	22,786,101
General partner interest, units outstanding	1,127,755	1,127,755
General partner percentage interest	1.80%	2.10%

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LONG-TERM INCENTIVE PLAN

9 Months Ended

Sep. 30, 2014

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

LONG-TERM INCENTIVE PLAN

LONG-TERM INCENTIVE PLAN

In July 2007, the General Partner adopted the Long-Term Incentive Plan (the “LTIP”). The compensation committee of the Board administers the LTIP. Effective April 29, 2014, the Partnership's unitholders approved an amendment to the LTIP to increase the number of common units reserved for issuance under the incentive plan by 1,500,000 common units from 2,600,000 common units to 4,100,000 common units. The common units are deliverable upon vesting.  Although other types of awards are contemplated under the LTIP, 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 each of December 2011, 2012 and 2013, 7,500 restricted common units were granted which vest in one-third increments over three years.  These grants were made in connection with the anniversary of the independent directors joining the Board. The fair value of the restricted units for the 2011 and 2012 grants was less than $0.1 million while the fair value of the restricted units for the 2013 grant was $0.1 million.

In March 2012, 2013 and 2014, grants for 353,300, 251,106 and 276,773 phantom units, respectively, were made, which vest on January 1, 2015, January 1, 2016 and January 1, 2017, 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 $6.76, $8.75 and $9.06 per unit, respectively, which is the closing market price on the grant date of the awards. The value of these award grants was approximately $2.4 million, $2.2 million and $2.5 million, respectively, on their grant date. The unrecognized estimated compensation cost of outstanding phantom units at September 30, 2014 was $2.4 million, which will be recognized over the remaining vesting period.

In September 2012, Mark Hurley was granted 500,000 phantom units under the LTIP 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 estimated 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, and the unrecognized estimated compensation cost at September 30, 2014 was $1.7 million and will be expensed over the remaining vesting period.

The Partnership’s equity-based incentive compensation expense for the three months ended September 30,2013 and 2014 was $0.5 million and $0.6 million, respectively. The Partnership’s equity-based incentive compensation expense for the nine months ended September 30,2013 and 2014 was $1.5 million and $1.6 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, 2013	1,058,162	$	7.03
Granted	276,773	9.06
Vested	298,936	7.36
Forfeited	11,304	8.34
Nonvested at September 30, 2014	1,024,695	$	7.47

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Document And Entity Information	9 Months Ended
	Sep. 30, 2014	Oct. 30, 2014
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		32,766,663
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2014

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EMPLOYEE BENEFIT PLAN

9 Months Ended

Sep. 30, 2014

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 $0.3 million and $0.4 million for the three months ended September 30,2013 and 2014 for discretionary contributions under the 401(k) Plan. The Partnership recognized expense of $1.0 million and $1.1 million for the nine months ended September 30,2013 and 2014 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 both the three months ended September 30,2013 and 2014, for discretionary profit sharing contributions under the 401(k) Plan. The Partnership recognized expense of $0.8 million and $0.5 million for the nine months ended September 30,2013 and 2014, respectively, for discretionary profit sharing contributions under the 401(k) Plan.

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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, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Income Statement [Abstract]
Capitalized interest	$ 84	$ 272	$ 244	$ 969
Service revenue:
Third party revenue	38,501	39,270	107,935	105,501
Related party revenue	9,857	15,399	32,663	39,381
Total revenue	48,358	54,669	140,598	144,882
Expenses:
Operating	32,295	32,132	102,272	95,440
General and administrative	4,267	4,649	13,124	13,806
Total expenses	36,562	36,781	115,396	109,246
Assets Impairment Charges on Continuing Operations	0	(123)	0	(123)
Gain on sale of assets	808	598	1,780	722
Operating income	12,604	18,363	26,982	36,235
Other income (expense):
Equity earnings (loss) in unconsolidated affiliate	423	(151)	477	(325)
Interest expense (net of capitalized interest of $272, $84, $969, and $244, respectively)	(1,640)	(1,897)	(8,325)	(9,188)
Income from continuing operations before income taxes	11,387	16,315	19,134	26,722
Provision for income taxes	116	285	351	451
Income from continuing operations	11,271	16,030	18,783	26,271
Loss from discontinued operations	0	(5,489)	0	(3,542)
Net income	11,271	10,541	18,783	22,729
Allocation of net income for calculation of earnings per unit:
General partner interest in net income	247	220	437	537
Preferred interest in net income	5,391	5,391	16,173	16,173
Income available to limited partners	$ 5,633	$ 4,930	$ 2,173	$ 6,019
Basic net income from continuing operations per common unit	$ 0.23	$ 0.44	$ 0.09	$ 0.41
Basic net loss from discontinued operations per common unit	$ 0.00	$ (0.23)	$ 0.00	$ (0.15)
Basic net income per common unit	$ 0.23	$ 0.21	$ 0.09	$ 0.26
Diluted net income from continuing operations per common unit	$ 0.20	$ 0.29	$ 0.09	$ 0.41
Diluted net loss from discontinued operations per common unit	$ 0.00	$ (0.10)	$ 0.00	$ (0.15)
Diluted net income per common unit	$ 0.20	$ 0.19	$ 0.09	$ 0.26
Common units	23,909	22,697	23,245	22,684
Common units	54,927	53,718	23,245	22,684

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PROPERTY, PLANT AND EQUIPMENT

9 Months Ended

Sep. 30, 2014

Property, Plant and Equipment [Abstract]

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT

	Estimated Useful Lives (Years)	December 31, 2013			September 30, 2014
		(dollars in thousands)
Land	N/A	$	16,374		$	17,680
Land improvements	10-20	6,306			6,351
Pipelines and facilities	5-30	144,261			159,176
Storage and terminal facilities	10-35	234,208			238,592
Transportation equipment	3-10	16,735			14,241
Office property and equipment and other	3-20	26,371			28,182
Pipeline linefill and tank bottoms	N/A	10,193			10,186
Construction-in-progress	N/A	14,008			17,808
Property, plant and equipment, gross		468,456			492,216
Accumulated depreciation		(171,056		)	(186,649		)
Property, plant and equipment, net		$	297,400		$	305,567

Depreciation expense for the three months ended September 30,2013 and 2014 was $6.1 million and $6.6 million, respectively, and depreciation expense for the nine months ended September 30,2013 and 2014 was $17.8 million and $19.3 million, respectively. In the three and nine months ended September 30, 2013 , the Partnership recorded asset impairment expense of $5.9 million related to its pipelines and facilities, 5.7 million of which relates to the Thompson to Webster Pipeline System located in southern Texas. The Thompson to Webster Pipeline System was sold in December 2013 and is reflected as discontinued operations (see Note 3).

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Discontinued Operations (Notes)

9 Months Ended

Sep. 30, 2013

Discontinued Operations and Disposal Groups [Abstract]

Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]

DISCONTINUED OPERATIONS

Northumberland, PA Asphalt Facility

On November 1, 2013, the Partnership entered into a litigation settlement in which title to its Northumberland, Pennsylvania asphalt facility was conveyed on November 21, 2013 to the counterparty to the settlement agreement in return for complete indemnification from any and all environmental liabilities or lawsuits related to the facility. The Partnership recognized a loss on the disposal of the facility of $0.6 million in 2013. The financial results of the Partnership’s operations related to the Northumberland asphalt facility are reflected as discontinued operations in the consolidated statements of operations. All prior periods presented have been recast to reflect the discontinued operations.

The amounts of revenue and costs reported in discontinued operations are set forth in the table below for the period indicated:

	Three Months ended September 30,		Nine Months ended September 30,
	2013		2013
	(in thousands, except per unit data)
Total revenue	$	164	$	493
Expenses:
Operating	49		105
Income from discontinued operations	$	115	$	388
Basic net income from discontinued operations per common unit	$	0.01	$	0.02
Diluted net income from discontinued operations per common unit	$	—	$	0.02

The following table discloses the major classes of discontinued assets and liabilities related to the Northumberland asphalt facility at the disposal date:

	November 21, 2013
	(in thousands)
Assets
Accounts Receivable	$	4
Assets of discontinued operations	$	4
Liabilities
Accounts Payable	$	13
Deferred Revenue	28
Other liabilities	84
Liabilities of discontinued operations	$	125

Thompson to Webster Pipeline System

In September 2013, the Partnership experienced an oil spill on its Thompson to Webster Pipeline System. As the costs associated with future maintenance of the pipeline and the potential future realizable cash flows from this pipeline were assessed, the Partnership determined that it was not economically feasible for it to continue to operate the pipeline. The Partnership assessed the recoverability of the carrying value of this asset and determined it was impaired. This resulted in $5.7 million of impairment expense being recorded in 2013, which reduced the carrying value of this pipeline to the discounted future net cash flows the Partnership expected to realize from this asset. During the discussions with the current shipper on necessary future maintenance and the possibility of idling the system, the shipper expressed interest in purchasing the system. On December 30, 2013, the sale to the shipper was finalized. The financial information of the Thompson to Webster Pipeline System is reflected as discontinued operations in the consolidated statements of operations. All prior periods presented have been recast to reflect the discontinued operations.

The amounts of revenue and costs reported in discontinued operations are set forth in the table below for the period indicated:

	Three Months ended September 30			Nine Months ended September 30,
	2013			2013
	(in thousands, except per unit data)
Total revenue	$	410		$	1,750
Expenses:
Operating	418			958
Asset impairment expense	5,732			5,732
Gain on sale of assets	136			1,010
Loss from discontinued operations	$	(5,604	)	$	(3,930	)
Basic net loss from discontinued operations per common unit	$	(0.24	)	$	(0.17	)
Diluted net loss from discontinued operations per common unit	$	(0.10	)	$	(0.17	)

The following table discloses the major classes of discontinued assets and liabilities related to the Thompson to Webster Pipeline System at the disposal date:

	December 30, 2013
	(in thousands)
Assets
Accounts Receivable	$	400
Property, plant and equipment, net	1,000
Assets of discontinued operations	$	1,400
Liabilities
Accounts Payable	$	1
Deferred Revenue	148
Other liabilities	339
Liabilities of discontinued operations	$	488

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RECENTLY ISSUED ACCOUNTING STANDARDS	9 Months Ended
	Sep. 30, 2014
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
RECENTLY ISSUED ACCOUNTING STANDARDS	RECENTLY ISSUED ACCOUNTING STANDARDSIn July 2013, the FASB issued ASU 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists.” The amendment provides explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The amendments in this update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The Partnership adopted this update in January 2014, and the impact was not material.In April 2014, the FASB issued ASU 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” The amendments in this update change the criteria for reporting discontinued operations for all public and nonpublic entities. The amendments also require new disclosures about discontinued operations and disposals of components of an entity that do not qualify for discontinued operations reporting. The amendments in this update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2014. The Partnership is evaluating the impact of this guidance, which will be adopted beginning with the Partnership’s quarterly report for the period ending March 31, 2015.In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers.” The amendments in this Update create Topic 606, Revenue from Contracts with Customers, and supersede the revenue recognition requirements in Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the Industry Topics of the Codification. In addition, the amendments supersede the cost guidance in Subtopic 605-35, Revenue Recognition-Construction-Type and Production-Type Contracts, and create new Subtopic 340-40, Other Assets and Deferred Costs-Contracts with Customers. In summary, the core principle of Topic 606 is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The amendments in this update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. The Partnership is evaluating the impact of this guidance, which will be adopted beginning with the Partnership’s quarterly report for the period ending March 31, 2017.In August 2014, the FASB issued ASU 2014-15, “Presentation of Financial Statements - Going Concern.” The Update provides U.S. GAAP guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, management will be required to evaluate whether there are conditions or events that raise substantial doubt about a company’s ability to continue as a going concern within one year from the date the financial statements are issued. The amendments in this update are effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. The Partnership is evaluating the impact of this guidance, which will be adopted beginning with the Partnership's annual report for the period ending December 31, 2016.

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FAIR VALUE MEASUREMENTS

9 Months Ended

Sep. 30, 2014

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, to minimize the use of unobservable inputs when determining fair value.  In periods in which they occur, the Partnership recognizes transfers into and out of Level 3 as of the end of the reporting period. Transfers out of Level 3 represent existing assets and liabilities that were classified previously as Level 3 for which the observable inputs became a more significant portion of the fair value estimates. Determining the appropriate classification of the Partnership’s fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data.

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

	Fair Value Measurements as of September 30, 2014
Description	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs   (Level 3)
Liabilities:
Interest rate swap liabilities	$	930	$	—	$	930	$	—
Total	$	930	$	—	$	930	$	—

The Partnership had no recurring financial assets or liabilities subject to fair value measurements as of December 31, 2013.

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)
	Three Months ended September 30, 2014		Nine Months ended September 30, 2014
Beginning Balance	$	2,002	$	—
Total gains or losses (realized/unrealized):
Included in earnings(1)	1,072		(930		)
Included in other comprehensive income	—		—
Purchases, issuances, and settlements	—		—
Transfers in and/or out of Level 3	930		930
Ending Balance	$	—	$	—
The amount of  total income (expense) for the period included in earnings attributable to the change in unrealized gains (losses) for liabilities still held at the reporting date	$	1,072	$	(930	)

____________________

(1) Amounts reported as included in earnings are reported as interest expense on the statements of operations.

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, 2014, the carrying values on the 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, 2014 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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PARTNERS' CAPITAL AND DISTRIBUTIONS

9 Months Ended

Sep. 30, 2014

Partners' Capital Account, Distributions [Abstract]

PARTNERS' CAPITAL AND DISTRIBUTIONS

DISTRIBUTIONS

On September 22, 2014, the Partnership issued and sold 9,775,000 common units for a public offering price of $7.61, resulting in proceeds of approximately $71.2 million, net of underwriters' discount and offering expenses of $3.2 million.

On October 23, 2014, the Board approved a distribution of $0.17875 per Preferred Unit, or a total distribution of $5.4 million, for the quarter ending September 30, 2014.  The Partnership will pay this distribution on the preferred units on November 14, 2014 to unitholders of record as of November 4, 2014.

In addition, on October 23, 2014, the Board declared a cash distribution of $0.1345 per unit on its outstanding common units, a 1.5% increase over the previous quarter’s distribution. The distribution will be paid on November 14, 2014 to unitholders of record on November 4, 2014. The distribution is for the three months ended September 30,2014. The total distribution will be approximately $4.7 million, with approximately $4.4 million and $0.2 million to be paid to the Partnership’s common unitholders and general partner, respectively, and $0.1 million to be paid to holders of phantom and restricted units pursuant to awards granted under the Partnership’s long-term incentive plan.

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DEBT

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

DEBT

    DEBT

On June 28, 2013, the Partnership entered into an amended and restated credit agreement which consists of a $400.0 million revolving loan facility. On September 15, 2014, the Partnership amended its credit facility to, among other things, amend the maximum permitted consolidated total leverage ratio as discussed below and to increase the limit on material project adjustments to EBITDA (as defined in the credit agreement).

As of October 30, 2014, approximately $212.0 million of revolver borrowings and $0.7 million of letters of credit were outstanding under the credit facility, leaving the Partnership with approximately $187.3 million available capacity for additional revolver borrowings and letters of credit under the credit facility, although the Partnership’s ability to borrow such funds may be limited by the financial covenants in the credit facility. In connection with entering into the amended and restated credit agreement and the amendment thereto, the Partnership paid certain fees to the lenders thereunder, and the Partnership paid certain arrangement and other fees to the arranger and administrative agent of the credit agreement.  The proceeds of loans made under the amended and restated credit agreement may be used for working capital and other general corporate purposes of the Partnership. All references herein to the credit agreement on or after June 28, 2013 refer to the amended and restated credit agreement, as amended on September 15, 2014.

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 $500.0 million for all revolving loan commitments under the credit agreement.

The credit agreement will mature on June 28, 2018, 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, property or casualty insurance claims, and condemnation proceedings, unless the Partnership reinvests such proceeds in accordance with the credit agreement, but these mandatory prepayments will not require any reduction of the lenders’ commitments under the credit agreement.

Borrowings under the credit agreement bear interest, at the Partnership’s option, at either the reserve-adjusted eurodollar rate (as defined in the credit agreement) plus an applicable margin that ranges from 2.0% to 3.0% or the alternate base rate (the highest of the agent bank’s prime rate, the federal funds effective rate plus 0.5%, and the 30-day eurodollar rate plus 1%) plus an applicable margin that ranges from 1.0% to 2.0%.  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 ranging from 0.375% to 0.5% on the unused commitments under the credit agreement.  The credit agreement does not have a floor for the alternate base rate or the eurodollar rate.  The applicable margins for the Partnership’s interest rate, the letter of credit fee and the commitment fee vary quarterly based on the Partnership’s consolidated total leverage ratio (as defined in the credit agreement, being generally computed as the ratio of consolidated total debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges).

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.

Prior to the date on which the Partnership issues qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notes previously or concurrently issued) that equals or exceeds $200.0 million, the maximum permitted consolidated total leverage ratio is 4.50 to 1.00; provided that:

• after the Partnership delivers the Knight Warrior Pipeline Initiation Certificate (as defined in the credit agreement, but generally meaning that the Partnership has spent at least $15.0 million of the projected capital expenditures for its Knight Warrior pipeline project), the maximum permitted consolidated total leverage ratio is 5.00 to 1.00 for the fiscal quarters ending March 31, 2015 through September 30, 2016, 4.75 to 1.00 for the fiscal quarter ending December 31, 2016, and 4.50 to 1.00 for each fiscal quarter thereafter;

• after the Partnership delivers the Knight Warrior Pipeline Leverage Election Certificate (as defined in the credit agreement, but generally meaning that the Partnership has spent at least 50% of the projected capital expenditures for the Knight Warrior pipeline project), the Partnership may elect to increase the maximum permitted consolidated total leverage ratio to 5.50 to 1.00 for two consecutive fiscal quarters ending on or before September 30, 2016; and

• if the Partnership makes a specified acquisition (as defined in the credit agreement, but generally being an acquisition with consideration in excess of $15.0 million), the Partnership may elect to increase the maximum permitted consolidated total leverage ratio to 5.00 to 1.00 from and after the last day of the fiscal quarter immediately preceding the fiscal quarter in which such acquisition occurs to and including the last day of the second full fiscal quarter following the fiscal quarter in which such acquisition occurred.

From and after the date on which the Partnership issues qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notes previously or concurrently issued) that equals or exceeds $200.0 million, the maximum permitted consolidated total leverage ratio is 5.00 to 1.00; provided that after the Partnership delivers the Knight Warrior Pipeline Initiation Certificate, the maximum permitted consolidated total leverage ratio is 5.50 to 1.00 for the fiscal quarters ending March 31, 2015 through September 30, 2016, and 5.00 to 1.00 for each fiscal quarter thereafter.

The maximum permitted consolidated senior secured leverage ratio (as defined in the credit agreement, but generally computed as the ratio of consolidated total secured debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) is 3.50 to 1.00, but this covenant is only tested from and after the date on which the Partnership issues qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notes previously or concurrently issued) that equals or exceeds $200.0 million.

The minimum permitted consolidated interest coverage ratio (as defined in the credit agreement, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest expense) is 2.50 to 1.00.

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

• create, issue, incur or assume indebtedness;

• create, incur or assume liens;

• engage in mergers or acquisitions;

• sell, transfer, assign or convey assets;

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

• make investments;

• modify the terms of certain indebtedness, or prepay certain indebtedness;

• engage in transactions with affiliates;

• enter into certain hedging contracts;

• enter into certain burdensome agreements;

• change the nature of the Partnership’s business;

• enter into operating leases; and

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

At September 30, 2014, the Partnership’s consolidated total leverage ratio was 3.18 to 1.00 and the consolidated interest coverage ratio was 7.12 to 1.00.  The Partnership was in compliance with all covenants of its credit agreement as of September 30, 2014.

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 no default or event of default exists under the credit agreement on a pro forma basis after giving effect to such distribution. The Partnership is currently allowed to make distributions to its unitholders in accordance with this covenant; 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 Board of Directors (the “Board”) of Blueknight Energy Partners G.P., L.L.C. (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 7 for additional information regarding distributions.

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

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

• failure to meet the quarterly financial covenants;

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

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

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

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

• certain ERISA events involving the Partnership or its restricted subsidiaries resulting in a material adverse effect on the Partnership;

• bankruptcy or other insolvency events involving the General Partner, the Partnership or any of its restricted subsidiaries; and

• a change of control (as defined in the credit agreement, but generally being (i) the General Partner ceasing to own 100% of the Partnership’s general partner interest or ceasing to control the Partnership or (ii) Vitol Holding B.V. (together with its affiliates, “Vitol”) and Charlesbank Capital Partners, LLC ceasing to collectively own and control 50.0% or more of the membership interests of the General Partner).

If an event of default relating to bankruptcy or other insolvency events occurs with respect to the General Partner or the Partnership, 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. 

Upon the execution of the amended and restated credit agreement on June 28, 2013, the Partnership expensed $1.8 million of debt issuance costs related to the extinguished term loan and $0.2 million in debt issuance costs related to its revolving loan facility, leaving a remaining balance of $0.5 million ascribed to those lenders with commitments under both the prior and the amended and restated credit facility. During the nine months ended September 30, 2013, the Partnership capitalized debt issuance costs of $0.2 million related to the prior credit facility. During the three months ended September 30,2013 and 2014, the Partnership capitalized debt issuance costs of $0.3 million related to the current credit facility for both periods. During the nine months ended September 30,2013 and 2014, the Partnership capitalized debt issuance costs of $3.4 million and $0.3 million related to the current credit facility, respectively. The debt issuance costs are being amortized over the term of the amended and restated credit agreement. Interest expense related to debt issuance cost amortization for each of the three months ended September 30,2013 and 2014 was $0.2 million. Interest expense related to debt issuance cost amortization for the nine months ended September 30,2013 and 2014 was $1.1 million and $0.6 million, respectively, excluding the $1.8 million of debt issuance costs related to the extinguished term loan and $0.2 million in debt issuance costs related to the revolving loan facility that were expensed upon the execution of the amended and restated credit agreement in June of 2013.

During the three months ended September 30,2013 and 2014, the weighted average interest rate under the Partnership’s credit agreement was 3.18% and 3.41%, respectively, resulting in interest expense of approximately $2.2 million and $2.5 million, respectively. During the nine months ended September 30,2013 and 2014, the weighted average interest rate under the Partnership’s credit agreement, excluding the $2.0 million of debt issuance costs related to the prior credit facility that was expensed in the nine months ended September 30, 2013, was 4.39% and 3.41%, respectively, resulting in interest expense of approximately $8.2 million and $7.3 million, respectively. As of September 30, 2014, borrowings under the Partnership’s amended and restated credit agreement bore interest at a weighted average interest rate of 3.72%.

During the three months ended September 30,2013 and 2014, the Partnership capitalized interest of $0.3 million and $0.1 million, respectively.  During the nine months ended September 30,2013 and 2014, the Partnership capitalized interest of $1.0 million and $0.2 million, respectively. 

The Partnership is exposed to market risk for changes in interest rates related to its credit facility. Interest rate swap agreements are used to manage a portion of the exposure related to changing interest rates by converting floating-rate debt to fixed-rate debt. In March 2014 the Partnership entered into two interest rate swap agreements with an aggregate notional amount of $200.0 million. The first agreement has a notional amount of $100.0 million, became effective June 28, 2014, and matures on June 28, 2018. Under the terms of the first interest rate swap agreement, the Partnership pays a fixed rate of 1.45% and receives one-month LIBOR with monthly settlement. The second agreement has a notional amount of $100.0 million, becomes effective January 28, 2015, and matures on January 28, 2019. Under the terms of the second interest rate swap agreement, the Partnership will pay a fixed rate of 1.97% and will receive one-month LIBOR with monthly settlement. During each of the three and nine months ended September 30, 2014, the Partnership recorded swap interest expense of $0.3 million. The fair market value of the interest rate swaps at September 30, 2014 is a liability of $0.9 million and is recorded in long-term derivative liabilities on the consolidated balance sheet. The interest rate swaps do not receive hedge accounting treatment under ASC 815 - Derivatives and Hedging. Changes in the fair value of the interest rate swaps are recorded in interest expense in the statements of operations.

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NET INCOME PER LIMITED PARTNER UNIT

9 Months Ended

Sep. 30, 2014

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 per common unit (in thousands, except per unit data): 

	Three Months ended September 30,					Nine Months ended September 30,
	2013			2014		2013			2014
Net income from continuing operations	$	16,030		$	11,271	$	26,271		$	18,783
Loss from discontinued operations	(5,489		)	—		(3,542		)	—
Net income	10,541			11,271		22,729			18,783
General partner interest in net income	220			247		537			437
Preferred interest in net income	5,391			5,391		16,173			16,173
Income available to limited partners	$	4,930		$	5,633	$	6,019		$	2,173
Basic weighted average number of units:
Common units	22,697			23,909		22,684			23,245
Restricted and phantom units	699			725		667			659
Diluted weighted average number of units:
Common units	53,718			54,927		22,684			23,245
Basic net income from continuing operations per common unit	$	0.44		$	0.23	$	0.41		$	0.09
Basic net loss from discontinued operations per common unit	$	(0.23	)	$	—	$	(0.15	)	$	—
Basic net income per common unit	$	0.21		$	0.23	$	0.26		$	0.09
Diluted income from continuing operations per common unit	$	0.29		$	0.20	$	0.41		$	0.09
Diluted loss from discontinued operations per common unit	$	(0.10	)	$	—	$	(0.15	)	$	—
Diluted net income per common unit	$	0.19		$	0.20	$	0.26		$	0.09

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RELATED PARTY TRANSACTIONS

9 Months Ended

Sep. 30, 2014

Related Party Transactions [Abstract]

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

The Partnership provides crude oil gathering, transportation, terminalling and storage services to Vitol as well as certain operating, strategic assessment, economic evaluation and project design services.  For the three months ended September 30,2013 and 2014, the Partnership recognized revenues of $15.1 million and $9.6 million, respectively, for services provided to Vitol.  For the nine months ended September 30,2013 and 2014, the Partnership recognized revenues of $39.0 million and $31.9 million, respectively, for services provided to Vitol.  As of both December 31, 2013 and September 30, 2014, the Partnership had receivables from Vitol of $3.0 million, net of allowance for doubtful accounts. As of December 31, 2013 and September 30, 2014, the Partnership had unearned revenues from Vitol of $0.2 million and $0.3 million, respectively.

The Partnership also provides operating and administrative services to Advantage Pipeline. For the each of the three months ended September 30,2013 and 2014, the Partnership earned revenues of $0.3 million for services provided to Advantage Pipeline. For the nine months ended September 30,2013 and 2014, the Partnership earned revenues of $0.3 million and $0.7 million, respectively, for services provided to Advantage Pipeline. As of December 31, 2013 and September 30, 2014, the Partnership had receivables from Advantage Pipeline of $0.2 million and $0.1 million, respectively.

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PROPERTY, PLANT AND EQUIPMENT (Details) (USD $)	3 Months Ended		9 Months Ended							9 Months Ended				9 Months Ended				9 Months Ended				9 Months Ended				9 Months Ended						3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Sep. 30, 2014 Land [Member]	Dec. 31, 2013 Land [Member]	Sep. 30, 2014 Land improvements [Member]	Dec. 31, 2013 Land improvements [Member]	Sep. 30, 2014 Land improvements [Member] Minimum [Member]	Sep. 30, 2014 Land improvements [Member] Maximum [Member]	Sep. 30, 2014 Pipelines and facilities [Member]	Dec. 31, 2013 Pipelines and facilities [Member]	Sep. 30, 2014 Pipelines and facilities [Member] Minimum [Member]	Sep. 30, 2014 Pipelines and facilities [Member] Maximum [Member]	Sep. 30, 2014 Storage and terminal facilities [Member]	Dec. 31, 2013 Storage and terminal facilities [Member]	Sep. 30, 2014 Storage and terminal facilities [Member] Minimum [Member]	Sep. 30, 2014 Storage and terminal facilities [Member] Maximum [Member]	Sep. 30, 2014 Transportation equipment [Member]	Dec. 31, 2013 Transportation equipment [Member]	Sep. 30, 2014 Transportation equipment [Member] Minimum [Member]	Sep. 30, 2014 Transportation equipment [Member] Maximum [Member]	Sep. 30, 2014 Office property and equipment and other [Member]	Dec. 31, 2013 Office property and equipment and other [Member]	Sep. 30, 2014 Office property and equipment and other [Member] Minimum [Member]	Sep. 30, 2014 Office property and equipment and other [Member] Maximum [Member]	Sep. 30, 2014 Pipeline linefill and tank bottoms [Member]	Dec. 31, 2013 Pipeline linefill and tank bottoms [Member]	Sep. 30, 2014 Construction-in-progress [Member]	Dec. 31, 2013 Construction-in-progress [Member]	Sep. 30, 2013 Thompson To Webster System [Member] Crude Oil Pipeline Services [Member]	Sep. 30, 2013 Thompson To Webster System [Member] Crude Oil Pipeline Services [Member]	Dec. 31, 2013 Thompson To Webster System [Member] Crude Oil Pipeline Services [Member]	Dec. 30, 2013 Thompson To Webster System [Member] Crude Oil Pipeline Services [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 492,216,000		$ 492,216,000		$ 468,456,000	$ 17,680,000	$ 16,374,000	$ 6,351,000	$ 6,306,000			$ 159,176,000	$ 144,261,000			$ 238,592,000	$ 234,208,000			$ 14,241,000	$ 16,735,000			$ 28,182,000	$ 26,371,000			$ 10,186,000	$ 10,193,000	$ 17,808,000	$ 14,008,000
Accumulated Depreciation and Impairments, property plant and equipment	186,649,000		186,649,000		171,056,000
Property, plant and equipment, net	305,567,000		305,567,000		297,400,000																														1,000,000
Estimated Useful Lives										10 years	20 years			5 years	30 years			10 years	35 years			3 years	10 years			3 years	20 years
Depreciation	6,600,000	6,100,000	19,300,000	17,800,000
Asset Impairment Charges		$ 5,900,000	$ 0	$ 5,855,000																												$ 5,732,000	$ 5,732,000	$ 5,700,000

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COMMITMENTS AND CONTINGENCIES

9 Months Ended

Sep. 30, 2014

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. 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 SemGroup Corporation (together with its predecessors including SemGroup, L.P., subsidiaries and affiliates referred to herein as “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 related to the disputed 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 Partnership intends to vigorously defend these claims. No trial date has been set by the court. The parties are engaged in discovery and continuing settlement negotiations. The Partnership believes that any settlement will not have a material adverse effect on the Partnership’s financial condition or results of operations.

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 contested SemCorp’s motion for summary judgment, which was referred to a Special Master for report and recommendation.  On June 10, 2013, the Special Master filed a report with the District Court of Tulsa County, finding a shortage in the Partnership’s Cushing Terminal and Oklahoma pipeline system of approximately 148,000 barrels and an excess of approximately 130,000 in SemCorp’s physical inventory. The Special Master noted that she was unable to more precisely trace the shortage and length (excess held by SemCorp) due to the manner in which SemCorp operated the Cushing Terminal and maintained related records. On June 25, 2013, the Partnership filed a notice of non-objection and motion to adopt the Special Master’s report, which was granted on February 12, 2014. On September 17, 2013, the Partnership filed a motion for summary judgment as to the liability of SemCorp for the Partnership’s claims for breach of contract and negligence by a bailee.  On October 7, 2013, SemCorp renewed its motion for summary judgment, which the Partnership timely opposed.  On February 20, 2014, the Court denied summary judgment motions of both SemCorp and the Partnership. The Court allowed for additional discovery to take place and referred all discovery matters to the Special Master, as appropriate, and made other procedural rulings. The Partnership reasserted its fraud claims in accordance with the Court’s directives. Discovery proceedings continue and the Partnership has determined that SemCorp knew of its excess inventory and sold this inventory during the period prior to the Partnership's filing of the lawsuit while denying that the Partnership claims had any validity and failing to disclose the excess to the Partnership. The Partnership intends to seek additional damages from SemCorp related to various injuries to the Partnership as a result of SemCorp’s refusal to return the Partnership’s crude oil or to pay the Partnership for the fair market value of the missing oil. 

In late November 2013, one of the Partnership’s pipelines in East Texas leaked approximately 500 barrels of oil. The response and clean-up cost is expected to total approximately $2.1 million, all of which is reflected in the Partnership’s 2013 results of operations. The Partnership made a claim against its pollution liability insurance provider (Aspen) to cover the expenses related to the spill and has paid its deductible of $250,000.  In early February 2014, Aspen filed a lawsuit against the Partnership to rescind the policy.  In September 2014, this matter was settled on terms reasonable to both parties.

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 or 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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NET INCOME PER LIMITED PARTNER UNIT (Tables)

9 Months Ended

Sep. 30, 2014

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 per common unit (in thousands, except per unit data): 

	Three Months ended September 30,					Nine Months ended September 30,
	2013			2014		2013			2014
Net income from continuing operations	$	16,030		$	11,271	$	26,271		$	18,783
Loss from discontinued operations	(5,489		)	—		(3,542		)	—
Net income	10,541			11,271		22,729			18,783
General partner interest in net income	220			247		537			437
Preferred interest in net income	5,391			5,391		16,173			16,173
Income available to limited partners	$	4,930		$	5,633	$	6,019		$	2,173
Basic weighted average number of units:
Common units	22,697			23,909		22,684			23,245
Restricted and phantom units	699			725		667			659
Diluted weighted average number of units:
Common units	53,718			54,927		22,684			23,245
Basic net income from continuing operations per common unit	$	0.44		$	0.23	$	0.41		$	0.09
Basic net loss from discontinued operations per common unit	$	(0.23	)	$	—	$	(0.15	)	$	—
Basic net income per common unit	$	0.21		$	0.23	$	0.26		$	0.09
Diluted income from continuing operations per common unit	$	0.29		$	0.20	$	0.41		$	0.09
Diluted loss from discontinued operations per common unit	$	(0.10	)	$	—	$	(0.15	)	$	—
Diluted net income per common unit	$	0.19		$	0.20	$	0.26		$	0.09

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EMPLOYEE BENEFIT PLAN (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
401 (k) Plan [Member]
Defined Contribution Plans Disclosure [Line Items]
Employer discretionary contribution amount	$ 0.4	$ 0.3	$ 1.1	$ 1.0
Profit Sharing [Member]
Defined Contribution Plans Disclosure [Line Items]
Employer discretionary contribution amount	$ 0.2	$ 0.2	$ 0.5	$ 0.8

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CONSOLIDATED STATEMENTS OF OPERATIONS CONSOLIDATED STATEMENT OF OPERATIONS (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Income Statement [Abstract]
Capitalized interest	$ 84	$ 272	$ 244	$ 969

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BASIS OF CONSOLIDATION AND PRESENTATION

9 Months Ended

Sep. 30, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

BASIS OF CONSOLIDATION AND PRESENTATION

BASIS OF CONSOLIDATION AND 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 30,2013 and 2014, the consolidated statement of changes in partners’ capital for the nine months ended September 30,2014, the statement of cash flows for the nine months ended September 30,2013 and 2014, and the consolidated balance sheet as of September 30, 2014 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 2013 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, 2013 filed with the Securities and Exchange Commission (the “SEC”) on March 12, 2014 (the “2013 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 its 2013 Form 10-K. A reclassification has been made to the consolidated statements of operations for the three and nine months ended September 30, 2013 to reflect a recasting of amounts related to discontinued operations (see Note 3). The reclassification has no impact on net income.

The Partnership’s investment in Advantage Pipeline, L.L.C. (“Advantage Pipeline”), over which the Partnership has significant influence but not control, is accounted for by the equity method. The Partnership does not consolidate any part of the assets or liabilities of its equity investee. The Partnership’s share of net income or loss is reflected as one line item on the Partnership’s Consolidated Statements of Operations entitled “Equity earnings in unconsolidated affiliate” and will increase or decrease, as applicable, the carrying value of the Partnership’s investment in the unconsolidated affiliate on the balance sheet. Distributions to the Partnership will reduce the carrying value of its investment and will be reflected in the Partnership’s Consolidated Statements of Cash Flows in the line item “Distributions from unconsolidated affiliate.” In turn, contributions will increase the carrying value of the Partnership’s investment and will be reflected in the Partnership’s Consolidated Statements of Cash Flows in investing activities. The Partnership evaluates its equity investment for impairment in accordance with FASB guidance with respect to the equity method of accounting for investments in common stock. An impairment of an equity investment results when factors indicate that the investment’s fair value is less than its carrying value and the reduction in value is other than temporary in nature.

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LONG-TERM INCENTIVE PLAN (Tables)

9 Months Ended

Sep. 30, 2014

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, 2013	1,058,162	$	7.03
Granted	276,773	9.06
Vested	298,936	7.36
Forfeited	11,304	8.34
Nonvested at September 30, 2014	1,024,695	$	7.47

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PARTNERS' CAPITAL AND DISTRIBUTIONS Issuances Narrative (Details) (USD $)	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 22, 2014
Capital Unit [Line Items]
Limited Partners' Capital Account, Units Issued			9,775,000
Sale of Stock, Price Per Share			$ 7.61
Proceeds from Issuance of Common Limited Partners Units	$ 71,193,000	$ 0
Limited Partners' Offering Costs	3,200,000
Limited Partner [Member]
Capital Unit [Line Items]
Proceeds from Issuance of Common Limited Partners Units	$ 71,193,000

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OPERATING SEGMENTS

9 Months Ended

Sep. 30, 2014

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 the Eagle North System, that gather crude oil purchased by its customers and transports it to refiners, to common carrier pipelines for ultimate delivery to refiners or to terminalling and storage facilities owned by the Partnership and others. The Partnership refers to its 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 the Eagle North system.

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 42 terminalling and storage facilities located in twenty-one 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):  

	Three Months ended September 30,				Nine Months ended September 30,
	2013		2014		2013		2014
Crude Oil Terminalling and Storage Services
Service revenue
Third party revenue	$	3,216	$	1,875	$	9,149	$	7,020
Related party revenue	4,477		3,080		14,495		10,726
Total revenue for reportable segments	7,693		4,955		23,644		17,746
Operating expenses (excluding depreciation and amortization)	1,068		1,006		2,872		2,980
Operating margin (excluding depreciation and amortization)	6,625		3,949		20,772		14,766
Total assets (end of period)	$	65,314	$	67,451	$	65,314	$	67,451
Crude Oil Pipeline Services
Service revenue
Third party revenue	$	6,499	$	5,906	$	12,681	$	13,439
Related party revenue	4,807		2,098		7,179		5,934
Total revenue for reportable segments	11,306		8,004		19,860		19,373
Operating expenses (excluding depreciation and amortization)	3,968		2,484		11,056		11,600
Operating margin (excluding depreciation and amortization)	7,338		5,520		8,804		7,773
Total assets (end of period)	$	175,476	$	170,700	$	175,476	$	170,700
Crude Oil Trucking and Producer Field Services
Service revenue
Third party revenue	$	11,712	$	12,264	$	36,085	$	38,280
Related party revenue	5,805		4,433		16,370		15,057
Total revenue for reportable segments	17,517		16,697		52,455		53,337
Operating expenses (excluding depreciation and amortization)	15,226		15,607		45,469		48,235
Operating margin (excluding depreciation and amortization)	2,291		1,090		6,986		5,102
Total assets (end of period)	$	20,446	$	28,208	$	20,446	$	28,208
Asphalt  Services
Service revenue
Third party revenue	$	17,843	$	18,456	$	47,586	$	49,196
Related party revenue	310		246		1,337		946
Total revenue for reportable segments	18,153		18,702		48,923		50,142
Operating expenses (excluding depreciation and amortization)	5,895		6,627		18,510		20,115
Operating margin (excluding depreciation and amortization)	12,258		12,075		30,413		30,027
Total assets (end of period)	$	101,215	$	95,110	$	101,215	$	95,110
Total operating margin (excluding depreciation and amortization)(1)	$	28,512	$	22,634	$	66,975	$	57,668

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(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,
	2013			2014			2013			2014
Operating margin (excluding depreciation and amortization) from continuing operations	$	28,512		$	22,634		$	66,975		$	57,668
Depreciation and amortization on continuing operations	(5,975		)	(6,571		)	(17,533		)	(19,342		)
General and administrative expenses	(4,649		)	(4,267		)	(13,806		)	(13,124		)
Asset impairment expense	(123		)	—			(123		)	—
Gain on sale of assets	598			808			722			1,780
Interest expense	(1,897		)	(1,640		)	(9,188		)	(8,325		)
Equity gain (loss) in unconsolidated entity	(151		)	423			(325		)	477
Income from continuing operations before income taxes	$	16,315		$	11,387		$	26,722		$	19,134