Edgar Filing: SemGroup Energy Partners, L.P.

form10k.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

Mark One [ X ]	Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 2008
	OR
[ ]	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

SEMGROUP ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware		20-8536826
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Two Warren Place 6120 South Yale Avenue, Suite 500 Tulsa, Oklahoma		74136
(Address of principal executive offices)		(Zip Code)

(918) 237-4000

(Registrant’s telephone number, including area code)

_______________________

Securities Registered Pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered
Common Units representing limited partner interests		OTC

Securities Registered Pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes o No x

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 the past 90 days.

Yes o No x

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes o No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer x Non-accelerated filer o Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

As of June 30, 2008, the aggregate market value of the registrant’s common units held by non-affiliates of the registrant was approximately $457.8 million, based on $25.34 per common unit, the closing price of the common units as reported on the Nasdaq Global Market on such date.

At June 26, 2009, there were 21,557,309 common units and 12,570,504 subordinated units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

None

TABLE OF CONTENTS

		Page
PART I		1
Item 1.	Business.	1
Item 1A.	Risk Factors.	24
Item 1B.	Unresolved Staff Comments.	51
Item 2.	Properties.	51
Item 3.	Legal Proceedings.	52
Item 4.	Submission of Matters to a Vote of Security Holders.	53
PART II		54
Item 5.	Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.	54
Item 6.	Selected Financial Data.	56
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operation.	58
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk.	76
Item 8.	Financial Statements and Supplementary Data .	77
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.	77
Item 9A.	Controls and Procedures.	78
Item 9B.	Other Information.	79
PART III		80
Item 10.	Directors, Executive Officers and Corporate Governance.	80
Item 11.	Executive Compensation.	85
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	95
Item 13.	Certain Relationships and Related Transactions, and Director Independence.	97
Item 14.	Principal Accountant Fees and Services.	104
PART IV		105
Item 15.	Exhibits, Financial Statement Schedules.	105

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DEFINITIONS

We use the following oil and gas measurements and industry terms in this report:

Barrel: One barrel of petroleum products equals 42 United States gallons.

Bpd: Barrels per day.

Common carrier pipeline: A pipeline engaged in the transportation of petroleum products as a public utility and common carrier for hire.

Condensate: A natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.

Feedstock: A raw material required for an industrial process such as in petrochemical manufacturing.

Finished asphalt products: As used herein, the term refers to liquid asphalt cement sold directly to end users and to asphalt emulsions, asphalt cutbacks, polymer modified asphalt cement and related asphalt products processed using liquid asphalt cement. The term is also used to refer to various residual fuel oil products directly sold to end users.

Liquid asphalt cement: Liquid asphalt cement is a dark brown to black cementitious material that is primarily produced by petroleum distillation. When crude oil is separated in distillation towers at a refinery, the heaviest hydrocarbons with the highest boiling points settle at the bottom. These tar-like fractions, called residuum, require relatively little additional processing to become products such as asphalt cement or residual fuel oil. Liquid asphalt cement is primarily used in the road construction and maintenance industry. Residual fuel oil is primarily used as a burner fuel in numerous industrial and commercial business applications. As used herein, the term refers to both liquid asphalt cement and residual fuel oils.

Midstream: The industry term for the components of the energy industry in between the production of oil and gas (upstream) and the distribution of refined and finished products (downstream).

Terminalling: The receipt of crude oil and petroleum products for storage into storage tanks and other appurtenant equipment, including pipelines, where the crude oil and petroleum products will be commingled with other products of similar quality; the storage of the crude oil and petroleum products; and the delivery of the crude oil and petroleum products as directed by a distributor into a truck, vessel or pipeline.

Throughput: The volume of product transported or passing through a pipeline, plant, terminal or other facility.

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PART I

As used in this annual report, unless we indicate otherwise: (1) ”SemGroup Energy Partners,” “our,” “we,” “us” and similar terms refer to SemGroup Energy Partners, L.P., together with its subsidiaries and (2) the “Private Company” refers to SemGroup, L.P. and its subsidiaries and affiliates (other than our general partner and us). The historical financial statements for periods prior to the contribution of the assets, liabilities and operations to us by the Private Company on July 20, 2007 reflect the assets, liabilities and operations of our predecessor.

Forward Looking Statements

This report contains “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Statements included in this annual report that are not historical facts (including any statements concerning the benefits of the Settlement (as defined below) or the Credit Agreement Amendment (as defined below), the impact of the Bankruptcy Filings (as defined below) and any statements regarding plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto) 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 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 “Item 1A—Risk Factors,” included in this annual report, and those set forth from time to time in our filings with the Securities and Exchange Commission (“SEC”), which are available through the Investor Relations link at www.SGLP.com and through the SEC’s Electronic Data Gathering and Retrieval System (“EDGAR”) at http://www.sec.gov.

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.

Item 1. Business.

Overview

We are a publicly traded master limited partnership with operations in twenty-three states. We provide integrated terminalling, storage, processing, 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 three operating segments: (i) crude oil terminalling and storage services, (ii) crude oil gathering and transportation services and (iii) asphalt services. We were formed in February 2007 as a Delaware master limited partnership initially to own, operate and develop a diversified portfolio of complementary midstream energy assets.

In July 2007, we issued 12,500,000 common units, representing limited partner interests, and 12,570,504 subordinated units, representing additional limited partner interests, to SemGroup Holdings, L.P., or SemGroup Holdings, and 549,908 general partner units representing a 2% general partner interest to SemGroup Energy Partners G.P., L.L.C., our general partner. SemGroup Holdings then completed a public offering of 12,500,000 common units at a price of $22 per unit. In addition, we issued an additional 1,875,000 common units to the public pursuant to the underwriters’ exercise of their over-allotment option. We did not receive any proceeds from the common units sold by SemGroup Holdings. We received net proceeds of approximately $38.7 million after deducting underwriting discounts from the sale of common units in connection with the exercise of the underwriters’ over-allotment option. We used these net proceeds to reduce outstanding borrowings under our credit facility. In connection with our initial public offering, we entered into a Throughput Agreement (the “Throughput Agreement”) with the Private Company under which we provided crude oil gathering and transportation and terminalling and storage services to the Private Company. The Throughput Agreement was subsequently rejected by the Private Company in connection with the Bankruptcy Cases (as defined below).

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On February 20, 2008, we purchased land, receiving infrastructure, storage tanks, machinery, pumps and piping at 46 liquid asphalt cement and residual fuel oil terminalling and storage facilities (the “Acquired Asphalt Assets”) from the Private Company for aggregate consideration of $379.5 million, including $0.7 million of acquisition-related costs. For accounting purposes, the acquisition has been reflected as a purchase of assets, with the Acquired Asphalt Assets recorded at the historical cost of the Private Company, which was approximately $145.5 million, with the additional purchase price of $234.0 million reflected in the statement of changes in partners’ capital as a distribution to the Private Company. In conjunction with the purchase of the Acquired Asphalt Assets, we amended our existing credit facility, increasing our borrowing capacity to $600 million. Concurrently, we issued 6,000,000 common units in an underwritten public offering, receiving proceeds, net of underwriting discounts and offering-related costs, of $137.2 million. Our general partner also made a capital contribution of $2.9 million to maintain its 2.0% general partner interest in us. On March 5, 2008, we issued an additional 900,000 common units in an underwritten public offering, receiving proceeds, net of underwriting discounts, of $20.6 million, in connection with the underwriters’ exercise of their over-allotment option in full. Our general partner made a corresponding capital contribution of $0.4 million to maintain its 2.0% general partner interest in us. In connection with the acquisition of the Acquired Asphalt Assets, we entered into a Terminalling and Storage Agreement (the “Terminalling Agreement”) with the Private Company and certain of its subsidiaries under which we provided liquid asphalt cement terminalling and storage and throughput services to the Private Company and the Private Company has agreed to use the our services at certain minimum levels. The Terminalling Agreement was subsequently rejected by the Private Company in connection with the Bankruptcy Cases. Our general partner’s Board of Directors (the “Board”) approved the acquisition of the Acquired Asphalt Assets as well as the terms of the related agreements based on a recommendation from its conflicts committee, which consisted entirely of independent directors. The conflicts committee retained independent legal and financial advisors to assist it in evaluating the transaction and considered a number of factors in approving the acquisition, including an opinion from the committee’s independent financial advisor that the consideration paid for the Acquired Asphalt Assets was fair, from a financial point of view, to us.

On May 12, 2008, we purchased the Eagle North Pipeline System, a 130-mile, 8-inch pipeline that originates in Ardmore, Oklahoma and terminates in Drumright, Oklahoma as well as other real and personal property related to the pipeline (the “Acquired Pipeline Assets”) from the Private Company for aggregate consideration of $45.1 million, including $0.1 million of acquisition-related costs. The acquisition was funded with borrowings under our revolving credit facility. We have suspended capital expenditures on this pipeline due to the continuing impact of the Bankruptcy Filings (as defined below). Management currently intends to put the asset into service in early 2010 and is exploring various alternatives to complete the project. The Board approved the acquisition of the Acquired Pipeline Assets based on a recommendation from its conflicts committee, which consisted entirely of independent directors. The conflicts committee retained independent legal and financial advisors to assist it in evaluating the transaction and considered a number of factors in approving the acquisition, including an opinion from the committee’s independent financial advisor that the consideration paid for the Acquired Pipeline Assets was fair, from a financial point of view, to us.

On May 30, 2008, we purchased certain land, crude oil storage and terminalling facilities with an aggregate of approximately 2.0 million barrels of storage capacity and related assets located at the Cushing Interchange from the Private Company and we assumed a take-or-pay, fee-based, third party contract with a term through August 2010 relating to the 2.0 million barrels of storage capacity (the “Acquired Storage Assets”) for aggregate consideration of $90.3 million, including $0.3 million of acquisition-related costs. The acquisition was funded with borrowings under our revolving credit facility. The Board approved the acquisition of the Acquired Storage Assets based on a recommendation from its conflicts committee, which consisted entirely of independent directors. The conflicts committee retained independent legal and financial advisors to assist it in evaluating the transaction and considered a number of factors in approving the acquisition, including an opinion from the committee’s independent financial advisor that the consideration paid for the Acquired Storage Assets was fair, from a financial point of view, to us.

Impact of the Bankruptcy of the Private Company and Certain of its Subsidiaries and Related Events

Due to the events related to the Bankruptcy Filings (as defined below) described herein, including the uncertainty relating to future cash flows, we face substantial doubt as to our ability to continue as a going concern. While it is not feasible to predict the ultimate outcome of the events surrounding the Bankruptcy Cases (as defined below), we have been and could continue to be materially and adversely affected by such events and we may be forced to make a bankruptcy filing or take other action that could have a material adverse effect on our business, the price of our common units and our results of operations.

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Bankruptcy Filings

On July 22, 2008 and thereafter, the Private Company and certain of its subsidiaries filed voluntary petitions (the “Bankruptcy Filings”) for reorganization under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”), Case No. 08-11547-BLS. The Private Company and its subsidiaries continue to operate their businesses and own and manage their properties as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code (the “Bankruptcy Cases”). None of us, our general partner, our subsidiaries nor the subsidiaries of our general partner are debtors in the Bankruptcy Cases. However, because of the contractual relationships with the Private Company and certain of its subsidiaries, the Bankruptcy Filings have adversely impacted us and may in the future impact us in various ways, including the items discussed herein.

Bankruptcy Court Order

On September 9, 2008, the Bankruptcy Court entered an order relating to the settlement of certain matters between us and the Private Company (the “Order”) in the Bankruptcy Cases. Among other things, the Order provided that (i) the Private Company was to directly pay any utility costs attributable to the operations of the Private Company at certain shared facilities, and the Private Company was to pay us for past utility cost reimbursements that were due from the Private Company; (ii) commencing on September 15, 2008, payments under the Terminalling Agreement were netted against amounts due under the Amended Omnibus Agreement (as defined below); (iii) the Private Company was to make payments under the Throughput Agreement for the month of August 2008 based upon the monthly contract minimums in the Throughput Agreement and netted against amounts due under the Amended Omnibus Agreement; (iv) the Private Company was to make payments under the Throughput Agreement for the months of September and October 2008 based upon actual volumes for each such month and at a rate equal to the average rate charged by us to third-party shippers in the same geographical area, with any such amounts netted against amounts due under the Amended Omnibus Agreement; (v) representatives of us and the Private Company were to meet to discuss the transition to us of certain of the Private Company’s employees necessary to maintain our business, and pending agreement between the parties, the Private Company was to continue to provide services in accordance with the Amended Omnibus Agreement through at least November 30, 2008; (vi) the Private Company was to consent to an order relating to a third-party storage contract which provided that we were the rightful owner of the rights in and to a certain third-party storage agreement and the corresponding amounts due thereunder; and (vii) we were to enter into a specified lease with the Private Company to permit the Private Company to construct a pipeline.

Settlement with the Private Company

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The Settlement provided for the following:

•

we transferred certain crude oil storage assets located in Kansas and northern Oklahoma to the Private Company;

•

the Private Company transferred ownership of 355,000 barrels of crude oil tank bottoms and line fill to us;

•

the Private Company rejected the Throughput Agreement;

•

we and one of our subsidiaries have a $20 million unsecured claim against the Private Company and certain of its subsidiaries relating to rejection of the Throughput Agreement;

•

we and the Private Company entered into a Throughput Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009 (the “New Throughput Agreement”), pursuant to which we provide certain crude oil gathering, transportation, terminalling and storage services to the Private Company;

•

we offered employment to certain crude oil employees;

•

the Private Company transferred its asphalt assets that are connected to the Acquired Asphalt Assets to us;

•

the Private Company rejected the Terminalling Agreement;

•

one of our subsidiaries has a $35 million unsecured claim against the Private Company and certain of its subsidiaries relating to rejection of the Terminalling Agreement;

•

we and the Private Company entered into a Terminalling and Storage Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009 (the “New Terminalling Agreement”), pursuant to which we provide liquid asphalt cement terminalling and storage services for the Private Company’s remaining asphalt inventory;

•

we and the Private Company entered into an Access and Use Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009 (the “New Access and Use Agreement”), pursuant to which we will allow the Private Company access rights to our asphalt facilities relating to its existing asphalt inventory;

•

the Private Company agreed to remove all of its remaining asphalt inventory from our asphalt storage facilities no later than October 31, 2009;

•

the Private Company will be entitled to receive 20% of the proceeds of any sale by us of any of the asphalt assets transferred to us in connection with the Settlement that occurs prior to December 31, 2009;

•

the Private Company rejected the Amended Omnibus Agreement;

•

we and the Private Company entered into a Shared Services Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009 (the “Shared Services Agreement”), pursuant to which the Private Company provides certain operational services for us;

•

we and the Private Company entered into a Transition Services Agreement, dated April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009 (the “Transition Services Agreement”), pursuant to which the Private Company will provide certain corporate, crude oil and asphalt transition services, in each case for a limited amount of time, to us;

•

other than as provided above, we and the Private Company entered into mutual releases of claims relating to the rejection of the Terminalling Agreement, the Throughput Agreement and the Amended Omnibus Agreement;

•

certain pre-petition claims by the Private Company and us were netted and waived;

•

we and the Private Company resolved certain remaining issues related to the contribution of crude oil assets to us in connection with our initial public offering, our acquisition of the Acquired Asphalt Assets, our acquisition of the Acquired Pipeline Assets and our acquisition of the Acquired Storage Assets, including the release of claims relating to such acquisitions; and

•

we and the Private Company entered into a Trademark License Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009 (the “Trademark Agreement”), which provides us with a non-exclusive, worldwide license to use certain trade names, including the name “SemGroup”, and the corresponding mark until December 31, 2009, and the Private Company waived claims for infringement relating to such trade names and mark prior to the date of such license agreement.

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Management is obtaining independent valuations of the assets transferred. Please see “Item 13—Certain Relationships and Related Party Transactions, and Director Independence—Agreements Related to the Settlement with the Private Company” for more detailed descriptions of the agreements that were entered into in connection with the Settlement.

Claims Against and By The Private Company’s Bankruptcy Estate

In connection with the Settlement, we and the Private Company entered into mutual releases regarding certain claims. In addition, the Settlement provided that we have a $35 million unsecured claim against the Private Company relating to rejection of the Terminalling Agreement and a $20 million unsecured claim against the Private Company relating to rejection of the Throughput Agreement. On May 15, 2009, the Private Company filed a joint plan of reorganization with the Bankruptcy Court (the “Reorganization Plan”). If such plan is confirmed without material amendment, our claims will be impaired, and we will recover substantially less than the nominal value of such claims. We may also have additional claims against the Private Company that were not released in connection with the Settlement, and the Private Company may also have additional claims against us that were not released in connection with the Settlement. Any claims asserted by us against the Private Company in the Bankruptcy Cases will be subject to the claim allowance procedure provided in the Bankruptcy Code and bankruptcy rules. If an objection is filed, the Bankruptcy Court will determine the extent to which any such claim that has been objected to is allowed and the priority of such claim.

Examiner

On August 12, 2008, a motion was filed by the United States Trustee asking the Bankruptcy Court to appoint an examiner to investigate the Private Company’s trading strategies as well as certain “insider transactions,” including the contribution of the crude oil assets to us in connection with our initial public offering, the sale of the Acquired Asphalt Assets to us in February 2008, the sale of the Acquired Pipeline Assets to us in May 2008, the sale of the Acquired Storage Assets to us in May 2008, and the entering into the Holdings Credit Agreements by SemGroup Holdings. On September 10, 2008, the Bankruptcy Court approved the appointment of an examiner, and on October 14, 2008, the United States Trustee appointed Louis J. Freeh, former director of the Federal Bureau of Investigation, as the examiner (the “Examiner”). On April 15, 2009, the Examiner filed a report summarizing the findings of his investigation with the Bankruptcy Court (the “Examiner’s Report”).

The Examiner was directed by the Bankruptcy Court to (i) investigate the circumstances surrounding the Private Company’s trading strategy, the transfer of the New York Mercantile Exchange account, certain insider transactions, the formation of us, the potential improper use of borrowed funds and funds generated from the Private Company’s operations and the liquidation of its assets to satisfy margin calls related to the trading strategy for the Private Company and certain entities owned or controlled by the Private Company’s officers and directors and (ii) determine whether any directors, officers or employees of the Private Company participated in fraud, dishonesty, incompetence, misconduct, mismanagement, or irregularity in the management of the affairs of the Private Company and whether the Private Company’s estates have causes of action against such persons arising from any such participation.

The Examiner’s Report identified potential claims or causes of action against current officers of our general partner who were former officers and/or directors of the Private Company, including (i) against Kevin L. Foxx for his failure to develop a suitable risk management policy or integrate a suitable risk management policy into the Private Company’s business controls, and for his failure to comply with the risk management policy that did exist, thereby subjecting the Private Company to increased risk and (ii) against Alex G. Stallings for his failure to stop Thomas L. Kivisto from engaging in trading activity on his own behalf through Westback Purchasing Company, L.L.C. (“Westback”), a limited liability trading partnership that Mr. Kivisto owned and controlled, thereby subjecting the Private Company to increased risk and losses. In addition, the Examiner’s Report criticized Mr. Foxx for certain conflicts of interest with entities that he or his family invested in and that had a business relationship with the Private Company. Additionally, the Examiner’s Report identified a number of potential claims or causes of action against Mr. Kivisto and Gregory C. Wallace, who are former directors of our general partner and former officers of the Private Company, including, without limitation, for negligence and mismanagement, fraud and false statements, conversion and corporate waste, unjust enrichment, breach of fiduciary duties and breach of contract.

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The Examiner did not perform a detailed analysis applying the elements of any of the causes of action identified in the Examiner’s Report to the facts of the Private Company’s Bankruptcy Cases or otherwise evaluate the strength of any particular claims the Private Company’s bankruptcy estate may have. In addition, the Examiner did not analyze potential defenses that may be available with respect to these causes of action.

The Examiner’s Report and related exhibits are publicly available at www.kccllc.net/SemGroup.

Bankruptcy Adversary Proceeding

The Official Committee of Unsecured Creditors of SemCrude, L.P. (“Unsecured Creditors Committee”) filed an adversary proceeding in connection with the Bankruptcy Cases against Thomas L. Kivisto, Gregory C. Wallace, and Westback. In that proceeding, filed February 18, 2009, the Unsecured Creditors Committee asserted various claims against the defendants on behalf of the Private Company’s bankruptcy estate, including claims based upon theories of fraudulent transfer, breach of fiduciary duties, waste, breach of contract, and unjust enrichment. On June 8, 2009, the Unsecured Creditors Committee filed a Second Amended Complaint asserting additional claims against Kevin L. Foxx and Alex G. Stallings, among others, based upon certain findings and recommendations in the Examiner’s Report described above (see “—Examiner”). The claims against Mr. Foxx are based upon theories of fraudulent transfer, unjust enrichment, and breach of fiduciary duty with respect to certain bonus payments received from the Private Company, and other claims of breach of fiduciary duty and breach of contract are also alleged against Messrs. Foxx and Stallings in the amended complaint. Messrs. Foxx and Stallings have informed us that they intend to vigorously defend these claims.

Board and Management Composition

On July 18, 2008, Manchester Securities Corp. (“Manchester”) and Alerian Finance Partners, LP (“Alerian”), as lenders to SemGroup Holdings, the sole member of our general partner, exercised certain rights described below under a Loan Agreement and a Pledge Agreement, each dated June 25, 2008 (the “Holdings Credit Agreements”), that were triggered by certain events of default under the Holdings Credit Agreements. On July 18, 2008, Manchester and Alerian exercised their right under the Holdings Credit Agreements in connection with certain events of default thereunder to vote the membership interests of our general partner in order to reconstitute the Board (the “Change of Control”). Messrs. Thomas L. Kivisto, Gregory C. Wallace, Kevin L. Foxx, Michael J. Brochetti and W. Anderson Bishop were removed from the Board. Mr. Bishop had served as the chairman of the audit committee and as a member of the conflicts committee and compensation committee of the Board. Messrs. Sundar S. Srinivasan, David N. Bernfeld and Gabriel Hammond (each of whom is affiliated with Manchester or Alerian) were appointed to the Board. Mr. Srinivasan was elected as Chairman of the Board. Messrs. Brian F. Billings and Edward F. Kosnik remain as independent directors of the Board and continue to serve as members of the conflicts committee, audit committee and compensation committee of the Board. On October 1, 2008, Dave Miller (who is an affiliate of Manchester) and Duke R. Ligon were appointed members of the Board.

On March 20, 2009, Alerian transferred its interest in the Holdings Credit Agreements to Manchester (Alerian is still potentially entitled to receive a portion of certain potential recoverable value from such interest). The Holdings Credit Agreements are secured by our subordinated units and incentive distribution rights and the membership interests in our general partner owned by SemGroup Holdings. Manchester has not foreclosed on our subordinated units owned by SemGroup Holdings or the membership interests in our general partner. Manchester may in the future exercise other remedies available to them under the Holdings Credit Agreements and related loan documents, including taking action to foreclose on the collateral securing the loan. Neither we nor our general partner is a party to the Holdings Credit Agreements or the related loan documents.

SemGroup Holdings is party to the Bankruptcy Cases. On May 15, 2009, the Private Company filed the Reorganization Plan. The Reorganization Plan does not address the reorganization of SemGroup Holdings, including the satisfaction of any obligations it has to Manchester under the Holdings Credit Agreements or the disposition of the ownership interests in our general partner or our subordinated units and incentive distribution rights. The membership units in our general partner, as well as our subordinated units and our incentive distribution rights, may be transferred, without the consent of our unitholders, to a third party as part of the Bankruptcy Cases or subsequent to the resolution of the Bankruptcy Cases. Furthermore, Manchester may transfer all or a portion of its interests in the Holdings Credit Agreements (including its rights to vote the membership interest in our general partner) to a third party. Any new owner of our general partner or holder of such voting rights would be in a position to replace the board of directors and officers of our general partner with its own choices and thereby influence the decisions made by the board of directors and officers. In addition, any such change of control of us or our general partner will result in an event of default under our credit agreement, may result in additional uncertainty in our operations and business and could have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business.

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Operation and General Administration of the Partnership

As is the case with many publicly traded partnerships, we have not historically directly employed any persons responsible for managing or operating us or for providing services relating to day-to-day business affairs. Pursuant to the Amended Omnibus Agreement, the Private Company operated our assets and performed other administrative services for us such as accounting, legal, regulatory, development, finance, land and engineering. The events related to the Bankruptcy Filings terminated the Private Company’s obligations to provide services to us under the Amended Omnibus Agreement. The Private Company continued to provide such services to us until the effective date of the Settlement at which time the Private Company rejected the Amended Omnibus Agreement and we and the Private Company entered into the Shared Services Agreement and the Transition Services Agreement relating to the provision of such services. In addition, in connection with the Settlement, we made offers of employment to, and now employ, certain individuals associated with our crude oil operations and subsequently made additional offers of employment to, and now employ, certain individuals associated with our asphalt operations. The costs to directly employ these individuals as well as the costs under the Shared Services Agreement and the Transition Services Agreement may be higher than those previously paid by us under the Amended Omnibus Agreement, which could have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business.

In addition, in connection with the Settlement, we agreed to not solicit the Private Company’s employees for a year from the time of the Settlement. In connection with the Bankruptcy Cases, the Private Company may reduce a substantial number of its employees or some of the Private Company’s employees may choose to terminate their employment with the Private Company, some of whom may currently be providing general and administrative and operating services to us under the Shared Services Agreement or the Transition Services Agreement. Any reductions in critical personnel who provide services to us and any increased costs to replace such personnel could have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business.

Credit Facility

As described below under “Item 7. Management’s Discussion and Analysis of Financial Condition—Liquidity and Capital Resources”, in connection with the events related to the Bankruptcy Filings, certain events of default occurred under our credit agreement. On September 18, 2008, we and the requisite lenders under our credit facility entered into the Forbearance Agreement (as defined below) relating to such events of default. On April 7, 2009, we and the requisite lenders entered into the Credit Agreement Amendment (as defined below), under which the lenders consented to the Settlement and waived all existing defaults and events of default described in the Forbearance Agreement and amendments thereto. See “Item 7. Management’s Discussion and Analysis of Financial Condition—Liquidity and Capital Resources” for more information regarding our credit facility, the Forbearance Agreement and the Credit Agreement Amendment.

Distributions to Our Unitholders

We did not make a distribution to our common unitholders, subordinated unitholders or general partner attributable to the results of operations for the quarters ended June 30, 2008, September 30, 2008, December 31, 2008 or March 31, 2009 due to the events of default under our credit agreement and the uncertainty of our future cash flows relating to the Bankruptcy Filings. In addition, we do not currently expect to make a distribution relating to the second quarter of 2009. Our unitholders will be required to pay taxes on their share of our taxable income even though they did not receive a cash distribution for the applicable periods. We distributed approximately $14.3 million to our unitholders for the three months ended March 31, 2008. Pursuant to the Credit Agreement Amendment, we are prohibited from making distributions to our unitholders if our leverage ratio (as defined in the credit agreement) exceeds 3.50 to 1.00. As of December 31, 2008 and March 31, 2009, our leverage ratio was 4.86 to 1.00 and 5.28 to 1.00, respectively. If our leverage ratio does not improve, we may not make quarterly distributions to our unitholders in the future.

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Our partnership agreement provides that, during the subordination period, which we are currently in, our common units have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.3125 per common unit per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. After giving effect to the nonpayment of distributions for the quarters ended June 30, 2008, September 30, 2008, December 31, 2008 and March 31, 2009, each common unit was entitled to an arrearage of $1.25, or total arrearages for all common units of $26.9 million based upon 21,557,309 common units outstanding as of June 26, 2009. Please see “Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities—Distributions of Available Cash” for further discussion regarding distributions to our unitholders.

Nasdaq Delisting

Effective at the opening of business on February 20, 2009, trading in our common units was suspended on the Nasdaq Global Market (“Nasdaq”) due to our failure to timely file our periodic reports with the SEC, and our common units were subsequently delisted from Nasdaq. Our common units are currently traded on the Pink Sheets, which is an over-the-counter securities market, under the symbol SGLP.PK. The fact that our common units are not listed on a national securities exchange is likely to make trading such common units more difficult for broker-dealers, unitholders and investors, potentially leading to further declines in the price of our common units. In addition, it may limit the number of institutional and other investors that will consider investing in our common units, which may have an adverse effect on the price of our common units. It may also make it more difficult for us to raise capital in the future.

We continue to work to become compliant with our SEC reporting obligations and intend to promptly seek the relisting of our common units on Nasdaq as soon as practicable after we have become compliant with such reporting obligations. However, we may not be able to relist our common units on Nasdaq or any other national securities exchange, and we may face a lengthy process to relist our common units if we are able to relist them at all.

Other Effects

The Bankruptcy Filings have had and may in the future continue to have a number of other impacts on our business and management. In the Amended Omnibus Agreement and other agreements with the Private Company, the Private Company agreed to indemnify us for certain environmental and other claims relating to the crude oil and asphalt assets that have been contributed to us. In connection with the Settlement, we waived these claims, and the Amended Omnibus Agreement and other relevant agreements, including the indemnification provisions therein, were rejected as part of the Bankruptcy Cases. If we experience an environmental or other loss, we would experience increased losses that may have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business.

We are currently pursuing various strategic alternatives for our business and assets including the possibility of entering into strategic partnerships (potentially involving the issuance of additional interests in our company), additional storage contracts with third party customers, and/or the sale of all or a portion of our assets. The uncertainty relating to the Bankruptcy Filings and the recent global market and economic conditions may make it more difficult to pursue strategic opportunities or enter into storage contracts with third party customers.

See “Item 7. Management’s Discussion and Analysis of Financial Condition—Impact of the Bankruptcy of the Private Company and Certain of its Subsidiaries and Related Events” for further discussion of the impact of the Bankruptcy Filings and events related thereto upon our results of operations.

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Our Assets and Services

Our network of assets provides our customers the flexibility to access multiple points for the receipt and delivery of crude oil and the terminalling, storage and processing of crude oil and asphalt cement. We do not take title to, or marketing responsibility for, the crude oil or asphalt cement that we gather, transport, terminal and store. As a result, our operations have minimal direct exposure to changes in crude oil and asphalt cement prices, but the volumes of crude oil and asphalt cement we gather, transport, terminal or store are indirectly affected by commodity prices. We generate revenues by charging a fee for services provided at each transportation stage as crude oil is shipped from its origin at the wellhead to destination points such as the Cushing Interchange, to refineries in Oklahoma, Kansas and Texas or to pipelines and by charging a fee for services provided for the terminalling and storage of crude oil and asphalt cement.

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Asphalt services. Our 46 asphalt cement terminals are located in 23 states and as such are well positioned to provide asphalt services in the market areas they serve throughout the continental United States. With our approximately 7.4 million barrels of total asphalt product and residual fuel oil storage capacity, we are able to provide our customers the ability to effectively manage their asphalt product storage and processing and marketing activities. As of June 26, 2009, we have entered into storage contracts or leases with third party customers relating to 45 of our 46 asphalt facilities.

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Crude oil terminalling and storage assets and services. We provide crude oil terminalling and storage services at our terminalling and storage facilities located in Oklahoma and Texas. We currently own and operate an aggregate of approximately 8.7 million barrels of storage capacity. Of this storage capacity, approximately 6.7 million barrels are located at our terminal in Cushing, Oklahoma. Our Cushing terminal is strategically located within the Cushing Interchange, one of the largest crude oil marketing hubs in the United States and the designated point of delivery specified in all New York Mercantile Exchange, or NYMEX, crude oil futures contracts. Our terminals have a combined capacity to receive or deliver approximately 10.0 million barrels of crude oil per month. We also own approximately 26 acres of additional land within the Cushing Interchange where we can develop additional storage capacity.

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Crude oil gathering and transportation assets and services. We own and operate two pipeline systems, the Mid-Continent system and the Longview system, collectively consisting of approximately 1,150 miles of pipelines that gather crude oil for our customers and transport it to refiners, to common carrier pipelines for ultimate delivery to refiners or to terminalling and storage facilities owned by us and others. Our pipeline gathering and transportation system located in Oklahoma and the Texas Panhandle, which we refer to as the Mid-Continent system, has a combined length of approximately 820 miles. Our second pipeline gathering and transportation system located in East Texas, which we refer to as the Longview system, consists of approximately 330 miles of tariff-regulated crude oil gathering pipeline. In addition to our pipelines, we use our approximately 200 owned or leased tanker trucks to gather crude oil in Kansas, Oklahoma, Texas, New Mexico and Colorado for our customers at remote wellhead locations generally not connected to pipeline and gathering systems and transport the crude oil to aggregation points and storage facilities located along pipeline gathering and transportation systems. In connection with our gathering services, we also provide a number of producer field services, ranging from gathering condensates from natural gas producers to hauling production waste water to disposal wells.

Prior to the Settlement, we derived substantially all of our revenues from services provided to the crude oil purchasing, marketing and distribution operations of the Private Company pursuant to the Throughput Agreement, and the services provided to the finished asphalt product processing and marketing operations of the Private Company pursuant to the Terminalling Agreement. For the year ended December 31, 2008, we derived approximately 73%, of our revenues, excluding fuel surcharge revenues related to fuel and power consumed to operate our asphalt cement storage tanks, from services we provided to the Private Company. Prior to the Order and the Settlement, the Private Company was obligated to pay us minimum monthly fees totaling $76.1 million annually and $58.9 million annually in respect of the minimum commitments under the Throughput Agreement and Terminalling Agreement, respectively, regardless of whether such services were actually utilized by the Private Company. As described herein, the Order required the Private Company to make certain payments under the Throughput Agreement and Terminalling Agreement during a portion of the third and fourth quarters of 2008, including the contractual minimum payments under the Terminalling Agreement. In connection with the Settlement, we waived the fees due under the Terminalling Agreement during March 2009. In addition, the Private Company rejected the Throughput Agreement and the Terminalling Agreement and we and the Private Company entered into the New Throughput Agreement and the New Terminalling Agreement. We expect revenues from services provided to the Private Company under the New Throughput Agreement and New Terminalling Agreement to be substantially less than prior revenues from services provided to the Private Company as the new agreements are based upon actual volumes gathered, transported, terminalled and stored instead of certain minimum volumes and are at reduced rates when compared to the Throughput Agreement and Terminalling Agreement.

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We have been pursuing opportunities to provide crude oil terminalling and storage services and crude oil gathering and transportation services to third parties. As a result of new crude oil third-party storage contracts, we increased our crude oil third-party terminalling and storage revenue from approximately $1.0 million, or approximately 10% of total terminalling and storage revenue during the second quarter of 2008, to approximately $4.6 million, $8.4 million and $10.2 million, or approximately 41%, 83% and 88% of total terminalling and storage revenue for the third quarter of 2008, the fourth quarter of 2008 and the first quarter of 2009, respectively.

In addition, as a result of new third-party crude oil transportation contracts and reduced commitments of usage by the Private Company under the Throughput Agreement, we increased our third-party gathering and transportation revenue from approximately $5.0 million, or approximately 21% of total gathering and transportation revenue during the second quarter of 2008, to approximately $10.9 million, $13.6 million and $13.7 million, or approximately 51%, 85% and 93% of total gathering and transportation revenue for the third quarter of 2008, the fourth quarter of 2008 and the first quarter of 2009, respectively.

The significant majority of the increase in third party revenues results from an increase in third-party crude oil services provided and a corresponding decrease in the Private Company’s crude oil services provided due to the termination of the monthly contract minimum revenues under the Throughput Agreement in September 2008. Average rates for the new third-party crude oil terminalling and storage and gathering and transportation contracts are comparable with those previously received from the Private Company. However, the volumes being terminalled, stored, gathered and transported have decreased as compared to periods prior to the Bankruptcy Filings, which has negatively impacted total revenues. As an example, fourth quarter 2008 total revenues are approximately $9.5 million (or approximately 19%) less than second quarter 2008 total revenues, in each case excluding fuel surcharge revenues related to fuel and power consumed to operate our liquid asphalt cement storage tanks.

In addition, we have recently entered into leases and storage agreements with third party customers relating to 45 of our 46 asphalt facilities. The majority of these leases and storage agreements with third parties were effective during May 2009 and extend through December 31, 2011. We operate the asphalt facilities pursuant to the storage agreements while our contract counterparties operate the asphalt facilities that are subject to the lease agreements. The revenues we receive pursuant to these leases and storage agreements are less than the revenues received under the Terminalling Agreement with the Private Company. We expect annual revenues from these leases and storage agreements to be approximately $40 million.

Industry Overview

Crude Oil Industry

We provide crude oil gathering, transportation, storage and terminalling services to independent producers, marketers and refiners of crude oil products. The market we serve, which begins at the source of production and extends to the point of distribution to the end user customer, is commonly referred to as the “midstream” market. Our crude oil operations are located primarily in Oklahoma, Kansas and Texas where there are extensive crude oil production operations in place and our assets extend from gathering systems and trucking networks in and around these producing fields to transportation pipelines carrying crude oil to logistics hubs, such as the Cushing Interchange, where we have substantial terminalling and storage facilities that aid our customers in managing the delivery of their crude oil.

Gathering and transportation. Pipeline transportation is generally considered the lowest cost method for shipping crude oil and refined petroleum products to other locations. Crude oil and refined products pipelines transport about two-thirds of the petroleum shipped in the United States. Crude oil pipelines transport oil from the wellhead to logistics hubs and/or refineries. Logistics hubs like the Cushing Interchange provide storage and connections to other pipeline systems and modes of transportation, such as tankers, railroads, and trucks. Barges and railroads provide additional transportation capabilities shipping crude oil between gathering storage systems, pipelines, terminals and storage centers and end-users. Barge transportation is typically a cost-efficient mode of transportation that allows for the ability to transport large volumes of crude oil over long distances.

Trucking complements pipeline gathering systems by gathering crude oil from operators at remote wellhead locations not served by pipeline gathering systems. These trucks can also be used to transport crude oil to aggregation points and storage facilities, which are generally located along pipeline gathering and transportation systems. Trucking is generally limited to low volume, short haul movements where other alternatives to pipeline transportation are often unavailable. Trucking costs escalate sharply with distance, making trucking the most expensive mode of crude oil transportation. Despite being small in terms of both volume per shipment and distance, trucking is an essential component to the completeness of the oil distribution system.

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Terminalling and storage. Terminalling and storage facilities complement the crude oil pipeline gathering and transportation systems. Terminals are facilities where crude oil is transferred to or from a storage facility or transportation system, such as a gathering pipeline, to another transportation system, such as trucks or another pipeline. Terminals play a key role in moving crude oil to end-users such as refineries by providing the following services:

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storage and inventory management;

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distribution; and

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blending to achieve specified grades of crude oil.

Storage and terminalling assets generate revenues through a combination of storage and throughput charges to third parties. Storage fees are generated when tank capacity is provided to third parties. Terminalling fees, also referred to as throughput fees, are generated when a terminal receives crude oil from a shipper and redelivers it to another shipper. Both storage and terminalling fees are earned from refiners and gatherers that need segregated storage or custom blended crude oils for refining feedstocks, pipeline operators, refiners or traders that need segregated storage for foreign cargoes, traders who make or take delivery under NYMEX contracts and producers and marketers that seek to increase their marketing alternatives.

Overview of the Cushing Interchange. The Cushing Interchange is one of the largest crude oil marketing hubs in the United States and the designated point of delivery specified in all NYMEX crude oil futures contracts. As the NYMEX delivery point and a cash market hub, the Cushing Interchange serves as the primary source of refinery feedstock for Midwest refiners and plays an integral role in establishing and maintaining markets for many varieties of foreign and domestic crude oil. The following table lists substantially all of the incoming pipelines connected to the Cushing Interchange, the proprietary terminals within the complex and all outgoing pipelines from the Cushing Interchange for delivery throughout the United States:

Incoming Pipelines to Cushing Interchange		Cushing Interchange Proprietary Terminals		Outgoing Pipelines from Cushing Interchange
SemGroup Energy Partners, L.P. SemGroup, L.P. (the Private Company) BP p.l.c. TEPPCO Partners, L.P. Basin Pipeline Sunoco Logistics Partners, L.P. Plains All American Pipeline, L.P. Seaway Crude Pipeline Company ConocoPhillips Enbridge Energy Partners, L.P.		SemGroup Energy Partners, L.P. BP p.l.c. TEPPCO Partners, L.P. Basin Pipeline Enbridge Energy Partners, L.P. Plains All American Pipeline, L.P. ConocoPhillips Seaway Crude Pipeline Company		BP p.l.c. Cush-Po, Inc. ConocoPhillips Sunoco Logistics Partners, L.P. Enbridge Energy Partners, L.P. Osage Pipeline Company, LLC Ozark Pipeline Plains All American Pipeline, L.P.

Due to our pipeline and terminalling infrastructure, we have the ability to receive and/or deliver, directly or indirectly, to all pipelines and terminals within the Cushing Interchange.

Asphalt Industry

Liquid asphalt cement is one of the oldest engineering materials. Liquid asphalt cement’s adhesive and waterproofing properties have been used for building structures, waterproofing ships, mummification and numerous other applications. In the United States, approximately 90% of liquid asphalt cement consumed is used for road paving and approximately 10% is used for roofing products, with other specialty applications accounting for only a very small fraction of consumption.

Production of liquid asphalt cement begins with the production of crude oil. Liquid asphalt cement is a dark brown to black cementitious material that is primarily produced by petroleum distillation. When crude oil is separated in distillation towers at a refinery, the heaviest hydrocarbons with the highest boiling points settle at the bottom. These tar-like fractions, called residuum, require relatively little additional processing to become products such as asphalt base or residual fuel oil. Liquid asphalt cement production represents only a small portion of the total product production in the crude oil refining process. The liquid asphalt cement produced by petroleum distillation can be sold by the refinery either directly into the wholesale and retail liquid asphalt cement markets or to a liquid asphalt cement marketer.

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In its normal state, asphalt cement is too viscous a liquid to be used at ambient temperatures. For paving applications, asphalt cement can be heated (as for hot mix asphalt), diluted or cut back with petroleum solvents (cutback asphalts), or emulsified in a water base with emulsifying chemicals by a colloid mill (asphalt emulsions). Approximately 90% of the road paving liquid asphalt cement in the United States is used for hot mix asphalt. Hot mix asphalt is produced by mixing hot asphalt cement and heated aggregate (stone, sand and/or gravel). The hot mix asphalt is loaded into trucks for transport to the paving site, where it is placed on the road surface by paving machines and compacted by rollers. Hot mix asphalt is used for new construction, reconstruction and for thin maintenance overlays on existing roads.

Asphalt emulsions and cutback asphalts are used for a variety of applications including spraying as a tack coat between an old pavement and a new hot mix asphalt overlay, cold mix pothole patching material, and preventive maintenance surface applications such as chip seals. Asphalt emulsions are also used for fog seal, slurry seal, scrub seal, sand seal and microsurfacing maintenance treatments, for warm mix emulsion/aggregate mixtures, base stabilization and both central plant and in-place recycling. Asphalt emulsions and cutback asphalts are generally sold directly to government agencies but are also sold to contractors for use in applications such as chip seals.

The asphalt industry in the United States is characterized by a high degree of seasonality. Much of this seasonality is due to the impact that weather conditions have on road construction schedules, particularly in cold weather states. Refineries produce liquid asphalt cement year round, but the peak asphalt demand season is during the warm weather months when most of the road construction activity in the United States takes place. As a result, liquid asphalt cement prices can vary dramatically from the winter to summer months. Liquid asphalt cement marketers and finished asphalt product producers with access to extensive storage capacity possess the inherent advantage of being able to purchase supply from refineries at low prices in the low demand winter months and then sell finished asphalt products at higher prices in the peak summer demand season.

Residual Fuel Oil Industry

Like asphalt cement, residual fuel oil is another by-product of the crude oil distillation process. Residual fuel oil is primarily used as a burner fuel in numerous industrial and commercial business applications including the utility industry, the shipping and paper industry, steel mills, tire manufacturing, schools and food processors.

The residual fuel oil industry in the United States is characterized by a high degree of seasonality with much of the seasonality driven by the impact of weather on the need to produce power for heating and cooling applications. The residual fuel oil market is largely a commodity market with price functioning as the primary decision-making criterion. However, many customers have unique product specifications driven by their particular business applications that require the blending of various components to meet those specifications.

Residual fuel oil is purchased from a variety of refiners by our customers and transported to our terminalling and storage facilities via numerous transportation methods including rail tank car, barge, ship and truck. Some of our customers use our asphalt assets to service their residual fuel oil business.

Crude Oil Terminalling and Storage Services

With approximately 8.7 million barrels of above-ground crude oil terminalling facilities and storage tanks, we are able to provide our customers the ability to effectively manage their crude oil inventories and significant flexibility in their marketing and operating activities. Our crude oil terminalling and storage assets are located throughout our core operating areas with the majority of our crude oil terminalling and storage strategically located at the Cushing Interchange.

Our crude oil terminals and storage assets receive crude oil products from pipelines, including those owned by us, and distribute these products to interstate common carrier pipelines and regional independent refiners, among other third parties.

Our crude oil terminals derive most of their revenues from terminalling fees charged to customers. The Private Company was our primary customer prior to the Order and the Settlement.

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The table below sets forth the total average barrels stored at and delivered out of our Cushing terminal in each of the periods presented and the total storage capacity at our Cushing terminal and at our other terminals at the end of such periods:

	Year Ended December 31,
	2007(1)		2008
Average crude oil barrels stored per month at our Cushing terminal		2,194,070		1,451,732
Average crude oil delivered (Bpd) to our Cushing terminal		63,448		26,395
Total storage capacity at our Cushing terminal (barrels at end of period)		4,765,000		6,710,000
Total other storage capacity (barrels at end of period)		1,952,150		1,962,764

(1)	Includes results of operations of our predecessor for the period from January 1, 2007 through July 20, 2007.

The following table outlines the location of our crude oil terminals and their storage capacities and number of tanks as of December 31, 2008:

Location	Storage Capacity (barrels)		Number of Tanks
Cushing, Oklahoma		6,710,000		36
Longview, Texas		430,000		7
Other(1)(2)		1,532,764		275
Total		8,672,764		318

(1)	Consists of miscellaneous storage tanks located at various points along our pipeline and gathering system.

(2)	In connection with the Settlement, we transferred certain crude oil assets to the Private Company and acquired certain truck tanks in Kansas and Oklahoma. As of June 26, 2009, we have approximately 1,062,000 barrels of other storage capacity and approximately 320 other tanks.

Cushing Terminal. One of our principal assets is our Cushing terminal, which is located within the Cushing Interchange in Cushing, Oklahoma. Currently, we own and operate 36 crude oil storage tanks with approximately 6.7 million barrels of storage capacity at this location.

Our predecessor completed construction of three new storage tanks with approximately 450,000 barrels of additional capacity at our Cushing terminal in March 2007. We also own 26 additional acres of land within the Cushing Interchange that is available for future expansion. This acreage is capable of housing an additional 1.5 million barrels of storage in four to six above ground tanks. In May 2008, we acquired the Acquired Storage Assets from the Private Company which consisted of 2.0 million barrels of storage capacity.

Our predecessor purchased the Cushing terminal in 2000 at which time the facility had approximately 790,000 barrels of storage capacity. The storage capacity of our Cushing terminal was substantially expanded in a series of phases beginning in 2002. Prior to the Bankruptcy Filings, the Private Company used the Cushing terminal and our other storage assets to conduct its crude oil business and has been the primary driver of the increased volumes terminalled and stored each year since our predecessor purchased the assets.

Our Cushing terminal was constructed over the last 50 years and it has an expected remaining life of at least 20 years. Over 85% of our total storage capacity in our Cushing terminal has been built since 2002. We estimate that all of our tanks have a weighted average age of seven years. The relatively young age of our tanks helps reduce required maintenance capital at our Cushing terminal.

The design and construction specifications of our storage tanks meet or exceed the minimums established by the American Petroleum Institute, or API. Our storage tanks also undergo regular maintenance inspection programs that are more stringent than established governmental guidelines. We believe that these design specifications and inspection programs will result in lower future maintenance capital costs to us.

A key attribute of our Cushing terminal is that through our pipeline and gathering system interface, we have access and connectivity to all the terminals located within the Cushing Interchange. This connectivity is a key attribute of our Cushing terminal because it provides us the ability to deliver to virtually any customer within the Cushing Interchange.

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Our Cushing terminal can receive crude oil from our Mid-Continent system as well as from pipelines owned by the Private Company, BP Amoco, TEPPCO, Basin, Sunoco Logistics Partners, Plains All American, Seaway, ConocoPhillips, Enbridge Energy Partners and two truck racks. Our Cushing terminal’s pipeline connections to major markets in the Mid-Continent region provide our customers with marketing flexibility. Our Cushing terminal can deliver crude oil via pipeline and, in the aggregate, is capable of receiving and/or delivering 282,000 Bpd of crude oil.

Longview Terminal. We own and operate the Longview terminal, located in Longview, Texas, consisting of seven tanks with a total storage capacity of 430,000 barrels. We use our Longview terminal in connection with our Longview system. The Longview terminal can receive and ship crude oil in both directions at the same time. A number of other potential customers have access to the Longview terminal. Our predecessor acquired the Longview terminal in 2000. Since 2000, our predecessor has conducted several expansion projects to increase the capacity and connectivity of our Longview terminal. The Longview terminal was constructed beginning in the 1940s and we believe it has a remaining life of at least 20 years.

Crude Oil Gathering and Transportation Services

Pipeline Gathering and Transportation Services

We own and operate a crude oil gathering and transportation system in the Mid-Continent region of the United States with a combined length of approximately 820 miles and a 330 mile tariff regulated crude oil gathering and transportation pipeline in the Longview, Texas area. In addition, we acquired the Eagle North Pipeline System in May 2008. We have suspended capital expenditures on this pipeline due to the continuing impact of the Bankruptcy Filings. Management currently intends to put the asset into service in early 2010 and is exploring various alternatives to complete the project.

System

Asset Type

Length

(miles)

Average

Throughput for

Year Ended

December 31, 2007

(Bpd)(1)

Average

Throughput for

Year Ended

December 31, 2008

(Bpd)

Pipe Diameter

Range

Mid-Continent

Gathering and transportation pipelines

820

31,661

25,442

4” to 20”

Longview

Gathering and transportation pipelines

330

27,404

26,218

6” to 8”

Eagle North

Gathering and transportation pipelines

130

n/a

8”

(1)	Includes results of operations of our predecessor for the period from January 1, 2007 through July 20, 2007.

Mid-Continent System. Our Mid-Continent gathering and transportation system consists of approximately 820 miles of gathering pipelines that, in aggregate, gather wellhead crude oil from approximately 11,000 wells for transport to our primary transportation systems that provide access to our Cushing terminal and other storage facilities. The Oklahoma portion of our Mid-Continent system consists of approximately 790 miles of various sized pipeline. Crude oil gathered into the Oklahoma portion of our Mid-Continent system is transported to our Cushing terminal or delivered to local area refiners. The Mid-Continent system also includes a small, 34-mile gathering and transportation system in the Texas Panhandle near Dumas, Texas. Crude oil collected through the Texas Panhandle portion of our Mid-Continent system is transported by pipeline and delivered to a ConocoPhillips refinery near Borger, Texas. For the years ended December 31, 2007 and 2008, this system gathered an average of approximately 31,661 Bpd and 25,442 Bpd of crude oil, respectively. Since the Bankruptcy Filings, we have experienced and continue to experience decreased volumes in the Bpd gathered by our Mid-Continent gathering and transportation system. For the fourth quarter of 2008 and the first quarter of 2009, the system gathered an average of 19,978 and 20,519 Bpd, respectively. The Private Company historically has been the sole shipper on our Mid-Continent system. The Mid-Continent system was constructed in various stages beginning in the 1940s and we believe it has a remaining life of at least 20 years.

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Longview System. Our Longview system consists of approximately 330 miles of tariff regulated crude oil gathering pipeline. The East Texas portion of this system delivers to crude oil terminalling, refinery and storage facilities at various delivery points in the East Texas region. Our Longview system also includes a small pipeline gathering system (Thompson-to-Webster) located near Houston, Texas. The Thompson-to-Webster gathering system, located south of Houston, consists of 42 miles of 6” and 8” pipeline. Deliveries made from this gathering system are transported to refineries in the Baytown/Texas City area. Shippers on the Longview system include the Private Company, ExxonMobil, Plains All American L.P., Delek, Eastex, Sunoco Logistics Partners L.P. and Wapiti. The Longview system was constructed in various stages beginning in the 1940s and we believe it has a remaining life of at least 20 years.

Eagle North Pipeline System. On May 12, 2008, we purchased the Acquired Pipeline Assets, including the Eagle North Pipeline System, a 130-mile, 8-inch pipeline that originates in Ardmore, Oklahoma and terminates in Drumright, Oklahoma, from the Private Company for aggregate consideration of $45.1 million, including $0.1 million of acquisition-related costs. The acquisition was funded with borrowings under our revolving credit facility. We have suspended capital expenditures on this pipeline due to the continuing impact of the Bankruptcy Filings. Management currently intends to put the asset into service in early 2010 and is exploring various alternatives to complete the project.

Trucking Services

We provide two types of trucking services: crude oil transportation services and producer field services.

Crude Oil Transportation Services. To complement our pipeline gathering and transportation business, we use our approximately 200 owned or leased tanker trucks, which have an average tank size of approximately 200 barrels. Our tanker trucks moved an average of 67,515 Bpd and 59,439 Bpd, respectively, for the years ended December 31, 2007 and 2008 from wellhead locations not served by pipeline gathering systems to aggregation points and storage facilities. Since the Bankruptcy Filings, we have experienced and continue to experience decreased volumes in the Bpd moved by our tanker trucks. For the fourth quarter of 2008 and the first quarter of 2009, our tanker trucks moved an average of 51,726 and 49,837 Bpd, respectively. Several of our trucking services operating areas, such as West Texas, are not currently served by our gathering and transportation pipeline systems. In these areas, our trucking operations extend our ability to gather and aggregate crude oil on our systems. This ability allows the crude oil marketing customers we serve to increase the level of service they are able to provide to their customers and facilitates the transportation of incremental volumes on our system. The following table outlines the distribution of our trucking assets among our operating areas as of December 31, 2008:


State	Number of Trucks
Oklahoma		54
Kansas		34
Dumas, Texas		40
West Texas/New Mexico		74
Colorado		10
Total		212

Normally we assign trucks to a specific area but, when needed, we can temporarily relocate them to meet demand. We dispatch our drivers with advanced computer technology out of central locations in Oklahoma City, Oklahoma, Abilene, Texas and Dumas, Texas. The drivers are provided with hand-held computers and after loading, the drivers provide the customers with a printed computer generated ticket with the information needed for payment. The hand-held computer can transmit as well as receive needed information to accomplish daily workloads. The drivers are also provided mobile communications to enhance safety and security.

Producer Field Services. We provide a number of producer field services for companies such as Eagle Rock Energy, DCP Midstream and ConocoPhillips. These services include gathering condensates by way of bobtail trucks for natural gas companies to hauling produced water to disposal wells, providing hot and cold fresh water, chemical and down hole well treating, wet oil clean up and building and maintaining separation facilities. We provide these services at contractual hourly rates. Our producer service fleet consists of approximately 100 trucks in a number of different sizes. Currently, we operate 17 different producer service facilities and have the ability to tailor our services to fit the needs of our customers.

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Asphalt Services

With approximately 7.4 million barrels of total asphalt product and residual fuel oil storage capacity, we are able to provide our customers the ability to effectively manage their asphalt product storage and processing and marketing activities. Our 46 terminals are located in 23 states and as such are well positioned to provide asphalt services in the market areas they serve throughout the continental United States.

We now serve the asphalt industry by providing our customers access to their market areas through a combination of the leasing of certain of our asphalt facilities and through the provision of storage and processing services at other of our asphalt and residual fuel oil facilities. In our asphalt services segment, we generate revenues by charging a fee for the lease of a facility or for services provided as asphalt products are terminalled, stored and/or processed in our facilities.

We have recently entered into leases and storage agreements with third party customers relating to 45 of our 46 asphalt facilities. The majority of these leases and storage agreements with third parties were effective during May 2009 and extend through December 31, 2011. We operate the asphalt facilities pursuant to the storage agreements while our contract counterparties operate the asphalt facilities that are subject to the lease agreements. During 2008 and the first quarter of 2009, we generated revenues from our asphalt assets pursuant to the Terminalling Agreement with the Private Company. The revenues we receive pursuant to these leases and storage agreements are less than the revenues received under the Terminalling Agreement with the Private Company.

At facilities where we have storage contracts, we receive, terminal, store and/or process our customer’s asphalt products until we deliver these products to our customers or other third parties. Our asphalt assets include the logistics assets, such as docks and rail spurs and the piping and pumping equipment necessary, to facilitate the unloading of liquid asphalt cement into our terminalling and storage facilities as well as the processing and manufacturing equipment required for the processing of asphalt emulsions, asphalt cutbacks, polymer modified asphalt cement and other related finished asphalt products. After initial unloading, the liquid asphalt cement is moved via heat traced pipelines into large storage tanks. These tanks are insulated and contain heating elements that allow the asphalt cement to be stored in a heated state. The asphalt cement can then be directly sold by our customers to end users or used as a raw material for the processing of asphalt emulsions, asphalt cutbacks, polymer modified asphalt cement and related finished asphalt products that we process in accordance with the formulations and specifications provided by our customers. Dependent on the product, the processing of asphalt entails combining asphalt cement and various other products such as emulsifying chemicals and polymers to achieve the desired specification and application requirements.

At leased facilities, our customers conduct the operations at the asphalt facility, including the storage and processing of asphalt products, and we collect a monthly rental fee relating to the lease of such facility.

We do not take title to, or marketing responsibility for, the liquid asphalt product that we terminal, store and/or process. As a result, our asphalt operations have minimal direct exposure to changes in commodity prices, but the volumes of liquid asphalt cement we terminal or store are indirectly affected by commodity prices.

During 2008 and the first quarter of 2009, the Private Company was our primary customer pursuant to the Terminalling Agreement under which the Private Company paid us a fee based on the number of barrels of liquid asphalt cement we terminalled or stored based upon certain minimum levels.

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The following table outlines the location of each asphalt facility and their respective storage capacity as of December 31, 2008:


Location	Number of Tanks		Shell Capacity (Barrels)
St. Louis, MO		13		499,550
Newport News, VA		15		497,000
Saginaw, TX		26		494,668
Gloucester City, NJ		8		455,524
Halstead, KS		11		341,394
Memphis, TN*		17		327,929
Catoosa, OK*		8		291,116
Spokane, WA*		19		273,644
Las Vegas, NV		13		272,005
Port of Catoosa, OK*		9		269,500
Boise, ID		16		261,398
Muskogee, OK		15		229,520
Lubbock, TX		15		228,340
Bay City, MI		6		181,571
Denver, CO*		6		173,905
Salt Lake City, UT		17		165,538
New Madrid, MO		10		150,468
Warsaw, IN		10		134,032
Morehead City, NC		9		128,552
Chicago, IL		4		127,195
Parsons, TN		7		114,214
Grand Island, NE		6		111,600
Pasco, WA		8		103,223
Pekin, IL		2		102,090
Billings, MT		8		100,000
Woods Cross, UT		12		98,592
Dodge City, KS		9		84,699
Pueblo, CO		11		75,146
Grand Junction, CO		11		68,161
Ennis, TX		11		63,895
Fontana, CA		10		52,913
Spokane, WA*		4		43,277
Columbus, OH		4		26,524
Northumberland, PA		8		23,333
Reading, PA		7		11,810
Catoosa, OK*		4		9,063
Austin, TX		4		8,568
Garden City, GA		5		8,214
Denver, CO*		5		8,167
Little Rock, AR		4		6,722
Sedalia, MO		3		6,271
El Dorado, KS		4		5,619
Salina, KS		5		5,590
Lawton, OK		5		4,935
Memphis, TN*		4		3,095
Ardmore, OK		3		2,090
Total(1)		411		6,650,660

*	Denotes locations that have more than one facility.

(1)

In connection with the Settlement, the Private Company transferred certain asphalt processing assets that were connected to, adjacent to, or otherwise contiguous with our existing asphalt facilities and associated real property interests to us. The transfer increased our shell capacity to approximately 7.4 million barrels of total asphalt product and residual fuel oil storage capacity. The transfer of the Private Company’s asphalt assets in connection with the Settlement provides us with outbound logistics and processing assets for our existing asphalt assets and, therefore, allows us to provide asphalt terminalling, storage and processing services to third parties.

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The asphalt assets range in age from two years to over fifty years and we expect that the storage tanks and related assets will have an average remaining life of in excess of 20 years. Our asphalt assets have been well maintained.

The Private Company acquired the majority of our asphalt assets from Koch Materials Company in April 2005. Since that time until our acquisition in February 2008 and pursuant to the Settlement Agreement, the asphalt assets were operated by SemMaterials, L.P., a wholly owned subsidiary of the Private Company.

Competition

We are subject to competition from other crude oil gathering, transportation, terminalling and storage operations that may be able to supply our customers with the same or comparable services on a more competitive basis. We compete with national, regional and local gathering, storage and pipeline companies and liquid asphalt cement storage and processing companies, including the major integrated oil companies, of widely varying sizes, financial resources and experience. In addition, the Private Company has indicated in its Reorganization Plan that it intends to emerge from bankruptcy later this year. If it is successful in its reorganization, we will compete with the Private Company in the provision of various services, including the provision of crude oil terminalling and storage services at the Cushing Interchange. We rely upon the Private Company to provide us certain services, including services related to our crude oil operations at the Cushing Interchange, pursuant to the Shared Services Agreement.

With respect to our crude oil gathering and transportation services, these competitors include TEPPCO Partners, L.P., Plains All American Pipeline, L.P., ConocoPhillips, Sunoco Logistics Partners L.P. and National Cooperative Refinery Association, among others. With respect to our crude oil storage and terminalling services, these competitors include BP plc, Enbridge Energy Partners, L.P. and Plains All American Pipeline, L.P. Several of our competitors conduct portions of their operations through publicly traded partnerships with structures similar to ours, including Plains All American Pipeline, L.P., TEPPCO Partners, L.P. and Sunoco Logistics Partners L.P. Our ability to compete could be harmed by factors we cannot control, including:

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price competition from gathering, transportation, terminalling and storage companies, some of which are substantially larger than us and have greater financial resources, and control substantially greater storage capacity, than we do;

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the perception that another company can provide better service;

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our prior association with the Private Company and any negative goodwill created by the Bankruptcy Filings;

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the availability of crude oil alternative supply points, or crude oil supply points located closer to the operations of our customers; and

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a decision by our competitors to acquire or construct crude oil midstream assets and provide gathering, transportation, terminalling or storage services in geographic areas, or to customers, served by our assets and services.

The asphalt industry is highly fragmented and regional in nature. Participants range in size from major oil companies to small family-owned proprietorships. Our competitors in the asphalt business include: refiners such as BP p.l.c., Flint Hills Resources, L.P., CHS, Inc., Exxon Mobil Corporation, ConocoPhillips Company, NuStar Energy L.P., Ergon, Inc., Marathon Petroleum Company LLC, Alon USA LP, Suncor Energy Inc. and Valero Energy Corporation; resellers such as NuStar Energy L.P., Idaho Asphalt Supply, Inc. and Asphalt Materials, Inc.; and large road construction firms such as OldCastle Materials, Inc., APAC, Inc. and Colas SA. We also compete with national, regional and local liquid asphalt cement terminalling and storage companies including the major integrated oil companies and a variety of others including KinderMorgan Energy Partners, International-Matex Tank Terminals and Houston Fuel Oil Terminal Company.

If we are unable to compete with services offered by other midstream enterprises, our ability to make distributions to our unitholders may be adversely affected. Additionally, we also compete with national, regional and local companies, including potentially the Private Company, for asset acquisitions and expansion opportunities. Some of these competitors are substantially larger than us and have greater financial resources and lower costs of capital than we do.

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Regulation

Longview System. The Federal Energy Regulatory Commission, or FERC, pursuant to the Interstate Commerce Act of 1887, or ICA, as amended, the Energy Policy Act of 1992 (“Energy Policy Act”), and rules and orders promulgated thereunder, regulates the tariff rates for our Longview system. The FERC requires that interstate oil pipelines file tariffs that contain rules and regulations governing the rates and charges for services performed. These tariffs apply to the interstate movement of crude and liquid petroleum products. Pursuant to the ICA, the rates, terms and conditions for providing service on ICA-regulated pipelines must be just and reasonable, and the service must be provided on a non-discriminatory basis. The ICA permits interested persons to challenge proposed new or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff during the term of the investigation. The FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.

All of our FERC regulated rates are deemed just and reasonable, or grandfathered, under the Energy Policy Act. The Energy Policy Act limits the circumstances under which a complaint can be made against such grandfathered rates. In order to challenge grandfathered rates, a party would have to show that it was previously contractually barred from challenging the rates, or that the economic circumstances of the liquids pipeline that were a basis for the rate or the nature of the service underlying the rate had substantially changed or that the rate was unduly discriminatory or preferential.

We cannot predict what rates we will be allowed to charge in the future for service on our Longview system. Currently, we have one tariff rate on the Longview System that is regulated by FERC with the other tariff rates being regulated by the Texas Railroad Commission. Because rates charged for transportation services must be competitive with those charged by other transporters, the rates set forth in our tariffs will be determined based on competitive factors in addition to regulatory considerations.

Gathering and Intrastate Pipeline Regulation. In the states in which we operate, regulation of crude gathering facilities and intrastate crude pipeline facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. For example, our intrastate crude pipeline facilities in Texas must have a tariff on file and charge just and reasonable rates for service, which much be provided on a non-discriminatory basis. Although state regulation is typically less onerous than at FERC, proposed and existing rates subject to state regulation and the provision of non-discriminatory service are subject to challenge by complaint.

Pipeline Safety. The laws and regulations in the states in which we operate are subject to change, resulting in potentially more stringent requirements and increased costs. For instance, in Texas, the Texas Railroad Commission, or RRC, incorporates into its own rules those federal safety standards for hazardous liquids pipelines contained in Title 40, Part 195 of the Federal Code of Regulations. In September 2006, the United States Department of Transportation, or DOT, proposed an amendment of Part 195 by broadening the scope of coverage to include certain rural onshore hazardous liquid gathering and low-stress pipeline systems found near “unusually sensitive areas,” including non-populated areas requiring extra protection because of the presence of sole source drinking water resources, endangered species, or other ecological resources. Also, on December 6, 2006, the Congress passed, and on December 29, 2006, President Bush signed into law the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, or PIPES, which reauthorizes and amends the DOT’s pipeline safety programs. Included in PIPES is a provision eliminating the regulatory exemption contained in Part 195 for hazardous liquid pipelines operated at low stress. Final rules promulgated under PIPES were promulgated in July 2008 and extend all existing safety regulations, including integrity management requirements, to large-diameter low-stress pipelines within a defined “buffer” area around an “unusually sensitive area,” which include areas that contain sole-source drinking water, endangered species, or other ecological resources. Operators of these, and all other low-stress pipelines, are required by the rules to comply with annual reporting requirements. Owing to the RRC’s incorporation by reference of the safety standards contained in Part 195, the issuance of any new gathering and low-stress pipeline safety regulations, including requirements for integrity management of those pipelines, are likely to increase the operating costs of our pipelines subject to such new requirements, and such future costs may be material.

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Trucking Regulation. We operate a fleet of trucks to transport crude oil and oilfield materials as a private, contract and common carrier. We are licensed to perform both intrastate and interstate motor carrier services. As a motor carrier, we are subject to certain safety regulations issued by the DOT. The trucking regulations cover, among other things, driver operations, maintaining log books, truck manifest preparations, the placement of safety placards on the trucks and trailer vehicles, drug and alcohol testing, safety of operation and equipment, and many other aspects of truck operations. We are also subject to requirements of the federal Occupational Safety and Health Act, as amended, or OSHA, with respect to our trucking operations.

Environmental, Health and Safety Risks

General. Our midstream crude oil gathering, transportation, terminalling and storage operations, together with the asphalt assets that we acquired from the Private Company, are subject to stringent federal, state, and local laws and regulations relating to the discharge of materials into the environment or otherwise relating to protection of the environment. As with the midstream and liquid asphalt cement industries generally, compliance with current and anticipated environmental laws and regulations increases our overall cost of business, including our capital costs to construct, maintain and upgrade equipment and facilities. Failure to comply with these laws and regulations may result in the assessment of significant administrative, civil and criminal penalties, the imposition of investigatory and remedial liabilities, and even the issuance of injunctions that may restrict or prohibit some or all of our operations. We believe that our operations are in substantial compliance with applicable laws and regulations. However, environmental laws and regulations are subject to change, resulting in potentially more stringent requirements, and we cannot provide any assurance that the cost of compliance with current and future laws and regulations will not have a material affect on our results of operations or earnings.

There are also risks of accidental releases into the environment inherent in the nature of both our midstream and liquid asphalt cement operations, such as leaks or spills of petroleum products or hazardous materials from our pipelines, trucks, terminals and storage facilities. A discharge of petroleum products or hazardous materials into the environment could, to the extent such event is not covered by insurance, subject us to substantial expense, including costs related to environmental clean-up or restoration, compliance with applicable laws and regulations, and any personal injury, natural resource or property damage claims made by neighboring landowners and other third parties.

The following is a summary of the more significant current environmental, health and safety laws and regulations to which our business operations are subject and for which compliance may require material capital expenditures or have a material adverse impact on our results of operations or financial position.

Water. The federal Clean Water Act and analogous state and local laws impose restrictions and strict controls regarding the discharge of pollutants into waters of the United States and state waters. Permits must be obtained to discharge pollutants into these waters. The Clean Water Act and analogous laws provide significant penalties for unauthorized discharges and impose substantial potential liabilities for cleaning up spills and leaks into water. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. We believe that we are in substantial compliance with any such applicable state requirements.

The federal Oil Pollution Act, as amended, or OPA, was enacted in 1990 and amends provisions of the Federal Water Pollution Control Act of 1972, the Clean Water Act, and other statutes as they pertain to prevention and response to oil spills. The OPA, and analogous state and local laws, subject owners of facilities used for storing, handling or transporting oil, including trucks and pipelines, to strict, joint and potentially unlimited liability for containment and removal costs, natural resource damages and certain other consequences of an oil spill, where such spill is into navigable waters, along shorelines or in the exclusive economic zone of the United States. The OPA, the Clean Water Act and other analogous laws also impose certain spill prevention, control and countermeasure requirements, such as the preparation of detailed oil spill emergency response plans and the construction of dikes and other containment structures to prevent contamination of navigable or other waters in the event of an oil overflow, rupture or leak. We believe that we are in substantial compliance with applicable OPA and analogous state and local requirements.

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Air Emissions. Our operations are subject to the federal Clean Air Act, as amended, as well as to comparable state and local laws. We believe that our operations are in substantial compliance with these laws in those areas in which we operate. Amendments to the federal Clean Air Act enacted in 1990 imposed a federal operating permit requirement for major sources of air emissions. Some of our midstream and liquid asphalt cement terminals hold such a permit, which is referred to as a “Title V permit.” We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with obtaining or maintaining permits and approvals addressing air emission related issues. Although we can provide no assurance, we believe future compliance with the federal Clean Air Act, as amended, will not have a material adverse effect on our financial condition or results of operations.

Climate. Legislative and regulatory measures to address concerns that emissions of certain gases, commonly referred to as “greenhouse gases” (“GHGs”), may be contributing to warming of the Earth’s atmosphere are in various phases of discussions or implementation at the international, national, regional, and state levels. The oil and gas industry is a direct source of certain GHG emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. In the United States, federal legislation requiring GHG controls may be enacted by the end of 2009. In addition, EPA is considering initiating a rulemaking to regulate GHGs as a pollutant under the CAA. Furthermore, EPA recently issued proposed regulations that would require the economy-wide monitoring and reporting of GHG emissions on an annual basis, including extensive GHG monitoring and reporting requirements. The rule as proposed would apply to natural gas transmission compression and could apply to emissions from other activities we conduct. Although this proposed rule would not control GHG emission levels from any facilities, if it applied to us, it would still cause us to incur monitoring and reporting costs. The EPA has also recently proposed findings that GHGs in the atmosphere endanger public health and welfare, and that emissions from mobile sources cause or contribute to GHGs in the atmosphere. These proposed findings, if finalized as proposed, would not immediately affect our operations, but standards eventually promulgated pursuant to these findings could affect our operations and ability to obtain air permits for new or modified facilities. Legislation and regulations are also in various stages of discussions or implementation in many of the states in which we operate. Lawsuits have been filed seeking to force the federal government to regulate GHG emissions under the CAA and to require individual companies to reduce GHG emissions from their operations. These and other lawsuits may result in decisions by state and federal courts and agencies that could impact our operations and ability to obtain certifications and authorizations to construct future projects.

Passage of climate change legislation or other federal or state legislative or regulatory initiatives that regulate or restrict GHG emissions in areas in which we conduct business could adversely affect the demand for our products and services, and depending on the particular program adopted could increase the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions (e.g., at compressor stations), pay any taxes related to our GHG emissions and/or administer and manage a GHG emissions program. At this time, it is not possible to accurately estimate how laws or regulations addressing GHG emissions would impact our business. Although we would not be impacted to a greater degree than other similarly situated midstream transporters of petroleum products, a stringent greenhouse gas control program could have an adverse effect on our cost of doing business and could reduce demand for the products we transport.

Solid Waste Disposal and Environmental Remediation.

The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, or CERCLA, also known as Superfund, as well as comparable state and local laws, impose liability without regard to fault or the legality of the original act, on certain classes of persons associated with the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site or sites where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Under CERCLA, such persons may be subject to strict joint and several liability for cleanup costs, for damages to natural resources, and for the costs of certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by releases of hazardous substances or other pollutants. We generate materials in the course of our operations that are regulated as hazardous substances. Beyond the federal statute, many states have enacted environmental response statutes that are analogous to CERCLA.

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We generate wastes, including “hazardous wastes,” that are subject to the requirements of the federal Resource Conservation and Recovery Act, as amended, or RCRA, as well as to comparable state and local laws. While normal costs of complying with RCRA would not be expected to have a material adverse effect on our financial conditions, we could incur substantial expense in the future if the RCRA exclusion for oil and gas waste were eliminated. Should our oil and gas wastes become subject to RCRA, we would become subject to more rigorous and costly disposal requirements, resulting in additional capital expenditures or operating expenses for us.

We currently own or lease properties where hazardous substances are being handled or have been handled for many years. Although we believe that operating and disposal practices that were standard in the midstream and liquid asphalt cement industries at the time were utilized at properties leased or owned by us, historical releases of hazardous substances or associated generated wastes have occurred on or under the properties owned or leased by us, or on or under other locations where these wastes were taken for disposal. In addition, many of these properties have been operated in the past by third parties whose treatment and disposal or release of hazardous substances or associated generated wastes were not under our control. These properties and the materials disposed on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously spilled hazardous materials or associated generated wastes (including wastes disposed of or released by other site occupants or by prior owners or operators), or to clean up contaminated property (including contaminated groundwater).

Contamination resulting from the release of hazardous substances or associated generated wastes is not unusual within the midstream and liquid asphalt cement industries. Other assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified. In the future, we likely will experience releases of hazardous materials, including petroleum products, into the environment from our pipeline terminalling and storage operations, or discover releases that were previously unidentified. Although we maintain a program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to environmental releases from our assets may substantially affect our business.

OSHA. We are subject to the requirements of OSHA, as well as to comparable state and local laws that regulate the protection of worker health and safety. In addition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements, including general midstream and liquid asphalt cement industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.

Anti-Terrorism Measures. The federal Department of Homeland Security Appropriations Act of 2007 requires the Department of Homeland Security, or DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to the act and, on November 20, 2007, further issued an Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. We have not yet determined the extent to which our facilities are subject to the interim rules or the associated costs to comply, but it is possible that such costs could be substantial.

Operational Hazards and Insurance

Pipelines, terminals, storage tanks, and similar facilities may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We have maintained insurance of various types and varying levels of coverage that we consider adequate under the circumstances to cover our operations and properties, including coverage for pollution related events. However, such insurance does not cover every potential risk associated with operating pipelines, terminals and other facilities. Notwithstanding what we believe is a favorable claims history, the overall cost of the insurance program as well as the deductibles and overall retention levels that we maintain have increased. Through the utilization of deductibles and retentions we self insure the “working layer” of loss activity to create a more efficient and cost effective program. The working layer consists of high frequency/low severity losses that are best retained and managed in-house. As we continue to grow, we will continue to monitor our retentions as they relate to the overall cost and scope of our insurance program.

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Employees

During 2008 we did not directly employ any persons responsible for managing or operating us or for providing services relating to day-to-day business affairs. Pursuant to the Amended Omnibus Agreement, the Private Company operated our assets and performed other administrative services for us such as accounting, legal, regulatory, development, finance, land and engineering. In addition, in connection with the Settlement, we made offers of employment to, and now employ, certain individuals associated with our crude oil operations and subsequently made additional offers of employment to, and now employ, certain individuals associated with our asphalt operations. The costs to directly employ these individuals as well as the costs under the Shared Services Agreement and the Transition Services Agreement may be higher than those previously paid by us under the Amended Omnibus Agreement. As of June 26, 2009, we employed approximately 400 persons. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that relations with these employees are satisfactory.

In addition, in connection with the Settlement, we agreed to not solicit the Private Company’s employees for a year from the time of the Settlement. In connection with the Bankruptcy Cases, the Private Company may reduce a substantial number of its employees or some of the Private Company’s employees may choose to terminate their employment with the Private Company, some of whom may currently be providing general and administrative and operating services to us under the Shared Services Agreement or the Transition Services Agreement. Any reductions in critical personnel who provide services to us and any increased costs to replace such personnel could have a material adverse effect on our ability to conduct our business and our results of operations.

Prior to the events surrounding the Bankruptcy Filings, the officers of our general partner were also employees and officers or directors of the Private Company. Messrs. Kevin Foxx and Alex Stallings resigned the positions each officer held with SemGroup, L.P. in July 2008. Mr. Michael Brochetti had previously resigned from his position with SemGroup, L.P. in March 2008. Mr. Jerry Parsons left the employment of SemGroup, L.P. in March 2009. Messrs. Foxx, Brochetti, Stallings, and Parsons remain as officers of our general partner. Mr. Peter Schwiering continues to serve as an officer of the Private Company and as an officer of our general partner.

Financial Information about Segments

Information regarding our operating revenues and identifiable assets attributable to each of our segments is presented in Note 17 to our consolidated financial statements included in this annual report on Form 10-K.

Available Information

We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to these reports filed with the SEC under the Securities and Exchange Act of 1934. These documents may be accessed free of charge on our website, www.sglp.com, as soon as is reasonably practicable after their filing with the SEC. Information contained on our website is not incorporated by reference in this report or any of our other filings. The filings are also available through the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Information on the operation of the Public Reference Room is available by calling 1-800-SEC-0330. The SEC also maintains a website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The SEC’s website is www.sec.gov.

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Item 1A. Risk Factors.

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this report. If any of the following risks were actually to occur, our business, financial condition, or results of operations could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline and our unitholders could lose all or part of their investment.

Risks Related to the Bankruptcy Filings

We may not be able to continue as a going concern.

The financial statements included in this annual report on Form 10-K have been prepared assuming we will continue as a going concern, though such an assumption may not be true. We earned 73% of our revenues, excluding fuel surcharge revenues related to fuel and power consumed to operate our liquid asphalt cement storage tanks, for the year ended December 31, 2008 from the Private Company, which commenced the Bankruptcy Cases in July 2008, the effects of which are more fully described herein. Events and uncertainties related to the Bankruptcy Filings, including uncertainties relating to our ability to comply with covenants under our credit facility, our exposure and sensitivity to interest rate risks given the materiality of our borrowings under our credit facility, and uncertainties related to securities and other litigation, raise substantial doubt about our ability to continue as a going concern. While it is not feasible to predict the ultimate outcome of the events surrounding the Bankruptcy Cases, we have been and could continue to be materially and adversely affected by such events and we may be forced to make a bankruptcy filing or take other action that could have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business. See “Item 1. Business—Impact of the Bankruptcy of the Private Company and Certain of its Subsidiaries and Related Events,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Impact of the Bankruptcy of the Private Company and Certain of its Subsidiaries and Related Events” and Note 19 to the consolidated financial statements.

The Bankruptcy Filings may continue to have a material adverse effect on our results of operations and our ability to make distributions to our unitholders.

As of the date of the Bankruptcy Filings, we were party to various agreements with the Private Company and its subsidiaries, including subsidiaries that are debtors in the Bankruptcy Cases. Under the Throughput Agreement, we provided certain crude oil gathering, transportation, terminalling and storage services to a subsidiary of the Private Company that is a debtor in the Bankruptcy Cases. Under the Terminalling Agreement, we provided certain liquid asphalt cement terminalling and storage services to a subsidiary of the Private Company that is a debtor in the Bankruptcy Cases. For the year ended December 31, 2008, we derived approximately 73% of our revenues, excluding fuel surcharge revenues related to fuel and power consumed to operate our liquid asphalt cement storage tanks, from services we provided to the Private Company and its subsidiaries. Prior to the Order and the Settlement, the Private Company was obligated to pay us minimum monthly fees totaling $76.1 million annually and $58.9 million annually in respect of the minimum commitments under the Throughput Agreement and the Terminalling Agreement, respectively, regardless of whether such services were actually used by the Private Company. In connection with the Settlement, the Private Company rejected the Throughput Agreement and the Terminalling Agreement and we and the Private Company entered into the New Throughput Agreement and the New Terminalling Agreement. We expect revenues from services provided to the Private Company under the New Throughput Agreement and New Terminalling Agreement to be substantially less than prior revenues from services provided to the Private Company as the new agreements are based upon actual volumes gathered, transported, terminalled and stored instead of certain minimum volumes and are at reduced rates when compared to the Throughput Agreement and Terminalling Agreement. See “─The Private Company has rejected certain contracts it has with us as part of the Bankruptcy Cases, which could have a material adverse effect on our results of operations, cash flows and ability to make distributions to our unitholders.”

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We have been pursuing opportunities to provide crude oil terminalling and storage services and crude oil gathering and transportation services to third parties. Although average rates for the new third-party crude oil terminalling and storage and transportation and gathering contracts are comparable with those previously received from the Private Company, the volumes being terminalled, stored, transported and gathered have decreased as compared to periods prior to the Bankruptcy Filings, which has negatively impacted total revenues. As an example, fourth quarter 2008 total revenues are approximately $9.5 million (or approximately 19%) less than second quarter 2008 total revenues, in each case excluding fuel surcharge revenues related to fuel and power consumed to operate our liquid asphalt cement storage tanks. In addition, we have recently entered into leases and storage agreements with third parties relating to certain of our asphalt facilities. The revenues that we will receive pursuant to these leases and storage agreements will be less than the revenues received under the Terminalling Agreement with the Private Company.

Our efforts to increase the third party revenue may not be successful. In addition, certain third parties may be less likely to enter into business transactions with us due to the Bankruptcy Filings and our financial condition. The Private Company may also choose to curtail its operations or liquidate its assets as part of the Bankruptcy Cases. As a result, unless we are able to generate additional third party revenues, we will continue to experience lower volumes in our system which could have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business.

The Private Company has rejected certain contracts it has with us as part of the Bankruptcy Cases, which could have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business.

In connection with the Settlement, among other things, the Private Company rejected certain agreements, including the Terminalling Agreement, the Throughput Agreement and the Amended Omnibus Agreement (see “Item 1. Business—Impact of the Bankruptcy of the Private Company and Certain of its Subsidiaries and Related Events—Settlement with the Private Company”). We may not be able to replace the volumes provided by the Private Company under the Terminalling Agreement and the Throughput Agreement and any contracts we make with third parties may be for prices that are less than those charged the Private Company under the Throughput Agreement and the Terminalling Agreement, which could have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business.

We have recently entered into leases and storage agreements with third party customers relating to 45 of our 46 asphalt facilities. The revenues that we will receive pursuant to these leases and storage agreements will be less than the revenues received under the Terminalling Agreement with the Private Company. Without sufficient revenues from our asphalt assets, we may be unable to meet the covenants, including the minimum liquidity, minimum EBITDA and minimum receipt requirements, under our credit agreement. Any significant decrease in the amount of revenues that we receive from our asphalt operations could have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business.

We did not make a distribution for the second quarter, third quarter or fourth quarter of 2008 or the first quarter of 2009, do not expect to make a distribution for the second quarter of 2009 and may not make distributions in the future.

We did not make a distribution to our common unitholders, subordinated unitholders or general partner attributable to the results of operations for the quarters ended June 30, 2008, September 30, 2008, December 31, 2008 or March 31, 2009 due to the events of default under our credit agreement and the uncertainty of our future cash flows relating to the Bankruptcy Filings. In addition, we do not currently expect to make a distribution relating to the second quarter of 2009. Our unitholders will be required to pay taxes on their share of our taxable income even though they did not receive a cash distribution for the applicable periods. See “—Tax Risks to Common Unitholders—Our unitholders have been and will be required to pay taxes on their share of our taxable income even if they have not or do not receive any cash distributions from us.” Pursuant to the Credit Agreement Amendment, we are prohibited from making distributions to our unitholders if our leverage ratio (as defined in the credit agreement) exceeds 3.50 to 1.00. As of December 31, 2008 and March 31, 2009, our leverage ratio was 4.86 to 1.00 and 5.28 to 1.00, respectively. We are uncertain as to when, if ever, our leverage ratio will be below 3.50 to 1.00 and therefore we are uncertain as to when or if we may again make distributions to our unitholders.

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We are exposed to the credit risk of the Private Company and the material nonperformance by the Private Company could reduce our ability to make distributions to our unitholders.

In connection with the Settlement we entered into the Shared Services Agreement and the Transition Services Agreement. Pursuant to such agreements we continue to rely upon the Private Company for certain operational and administrative services relating to our operations. If the Private Company fails to reorganize successfully, it may no longer be able to provide such operational and administrative services to us. Any material nonperformance under the Shared Services Agreement or the Transition Services Agreement by the Private Company could materially and adversely impact our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business. See “─The Private Company has rejected certain contracts it has with us as part of the Bankruptcy Cases, which could have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business.”

In addition, the Private Company has defaulted under its credit facilities and its indenture relating to its senior notes. Moody’s and Fitch Ratings have withdrawn their ratings of the Private Company due to the Bankruptcy Filings. Though we have no indebtedness rated by any credit rating agency, we may have rated debt in the future. Credit rating agencies such as Moody’s and Fitch Ratings may consider the Private Company’s debt ratings when assigning ours, because of our historical relationship with the Private Company. Due to the Private Company’s default of its indebtedness and the uncertainty related to the Bankruptcy Filings, we could experience an increase in our borrowing costs or difficulty accessing capital markets if we are able to access them at all. Such a development could adversely affect our ability to grow our business and to make distributions to unitholders.

Prior to the Settlement, we did not have employees and relied solely on the employees of the Private Company. We continue to rely upon the Private Company for certain operational and administrative services and may experience increased costs as we begin employing individuals directly associated with our operations.

In addition, in connection with the Bankruptcy Cases, the Private Company may reduce a substantial number of its employees or some of the Private Company’s employees may choose to terminate their employment with the Private Company, some of whom may currently be providing general and administrative and operating services to us under the Shared Services Agreement or the Transition Services Agreement. Any reductions in critical personnel who provide services to us and any increased costs to replace such personnel could have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business.

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Certain of our officers and personnel who perform services for us also provide services to the Private Company.

We rely upon the Private Company to provide us certain services, including services related to our crude oil operations at the Cushing Interchange, pursuant to the Shared Services Agreement. In addition, Peter L. Schwiering, our Executive Vice President — Crude Operations, is an officer of the Private Company. If Mr. Schwiering or other employees of the Private Company performing services on our behalf favor the Private Company’s interests over our interests when conducting our operations, it may have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business.

Our interests may be adverse to the Private Company’s interests due to the Bankruptcy Filings.

The Settlement provided that we have a $35 million unsecured claim against the Private Company relating to rejection of the Terminalling Agreement and a $20 million unsecured claim against the Private Company relating to rejection of the Throughput Agreement. On May 15, 2009, the Private Company filed the Reorganization Plan. If such plan is confirmed without material amendment, our claims will be impaired, and we will recover substantially less than the nominal value of such claims if we recover anything. We may also have additional claims against the Private Company that were not released in connection with the Settlement. In addition, if the Private Company fails to make its payments under the New Throughput Agreement or the New Terminalling Agreement or otherwise fails to perform under the contracts we have with the Private Company, we may have potential claims against the Private Company’s bankruptcy estate. Any claims asserted by us against the Private Company in the Bankruptcy Cases will be subject to the claim allowance procedure provided in the Bankruptcy Code and bankruptcy rules. If an objection is filed, the Bankruptcy Court will determine the extent to which any such claim that has been objected to is allowed and the priority of such claim, which may reduce the value of any such claim.

As a result of these items, our interests may be adverse to the Private Company’s interests. The Private Company provides various administrative and operational services for us pursuant to the Shared Services Agreement and the Transition Services Agreement. In addition, we rely upon the Private Company’s personnel for the implementation of certain of our internal controls. The progress of the Bankruptcy Cases may influence the Private Company’s decision to continue providing any of these services, which could have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business.

The Private Company may assert claims against us in the Bankruptcy Cases, which could have a material adverse effect on our cash flows and ability to make distributions to our unitholders.

Pursuant to the Settlement, the Private Company released certain of its claims against us. However, there may be other claims against us that have not been released in connection with the Settlement. If claims are identified, such claims may prompt the filing of lawsuits in the Bankruptcy Cases to seek monetary damages or to challenge or to seek to unwind transactions with us under the bankruptcy laws. Such litigation may be expensive and, if successful, would have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business.

We may experience significant costs in changing our name and trademark.

In connection with the Settlement, we and the Private Company entered into the Trademark Agreement, pursuant to which the Private Company granted us a non-exclusive, worldwide license to use certain trade names, including the name “SemGroup” and the corresponding mark, until December 31, 2009, and the Private Company waived claims for infringement relating to such trade names and mark prior to the effective date of such Trademark Agreement (see “Item 1. Business—Impact of the Bankruptcy of the Private Company and Certain of its Subsidiaries and Related Events—Settlement with the Private Company”). As such, we will be required to change our name and trademark upon or prior to the expiration of the Trademark Agreement. The expenses associated with such a change may be significant, which could have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business.

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Our future operations and cash flows are uncertain and may cause events of default under our credit agreement.

Our future operations and cash flows are uncertain. The covenants and other requirements under our credit facility were designed using certain projections and assumptions relating to revenues, EBITDA and cash flows. In addition, our interest expense has increased due to our entering into the Forbearance Agreement, as amended, and the Credit Agreement Amendment. For example, the weighted average interest rate incurred by us during the three months ended June 30, 2008 was 4.62% resulting in interest expense of approximately $4.3 million as compared to a weighted average interest rate incurred by us of 9.00% during the three months ended March 31, 2009 resulting in interest expense of approximately $10.0 million. This increased interest expense may have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business.

An event of default will occur under our credit agreement if we fail to become current in our periodic filings.

It is an event of default under the credit agreement if we do not file our delinquent quarterly and annual reports with the SEC by September 30, 2009, unless we retain new auditors, in which case such deadline is extended to December 31, 2009. If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies, including taking the available cash in our bank accounts. If an event of default exists and we are unable to obtain forbearance from our lenders or a waiver of the events of default under our credit agreement, we may be forced to sell assets, make a bankruptcy filing or take other action that could have a material adverse effect on our business, the price of our common units and our results of operations. We are also prohibited from making cash distributions to our unitholders while the events of default exist.

An event of default will occur under our credit agreement if there is a change of control of us or our general partner.

It is an event of default under the credit agreement if there is a change of control of us or our general partner. We cannot assure our unitholders that a change of control will not occur. The membership units in our general partner, as well as our subordinated units and our incentive distribution rights, may be transferred, without the consent of our unitholders, to a third party as part of the Bankruptcy Cases or subsequent to the resolution of the Bankruptcy Cases. Furthermore, Manchester may transfer all or a portion of its interests in the Holdings Credit Agreements (including its rights to vote the membership interest in our general partner) to a third party. If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies, including taking the available cash in our bank accounts. If an event of default exists and we are unable to obtain forbearance from our lenders or a waiver of the events of default under our credit agreement, we may be forced to sell assets, make a bankruptcy filing or take other action that could have a material adverse effect on our business, the price of our common units and our results of operations. We are also prohibited from making cash distributions to our unitholders while the events of default exist.

We are subject to an SEC inquiry and a Federal Grand Jury subpoena.

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

On July 23, 2008, we and our general partner each received a Grand Jury subpoena from the United States Attorney’s Office in Oklahoma City, Oklahoma, requiring, among other things, that we and our general partner produce financial and other records related to our July 17, 2008 press release. We have been informed that the U.S. Attorneys’ Offices for the Western District of Oklahoma and the Northern District of Oklahoma are in discussions regarding the subpoenas, and no date has been set for a response to the subpoenas. We and our general partner intend to cooperate fully with this investigation if and when it proceeds.

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In the event that either the SEC inquiry or the Grand Jury investigation leads to action against any of our current or former directors or officers, or the Partnership itself, the trading price of our common units may be adversely impacted. In addition, the SEC inquiry and the Grand Jury investigation may result in the incurrence of significant legal expense, both directly and as the result of our indemnification obligations. These matters may also divert management’s attention from our operations which may cause our business to suffer. If we are subject to adverse findings in either of these matters, we could be required to pay damages or penalties or have other remedies imposed upon us which could have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business. All or a portion of the defense costs and any amount we may be required to pay in connection with the resolution of these matters may not be covered by insurance.

We have been named as a party in lawsuits and may be named in additional litigation in the future, all of which could result in an unfavorable outcome and have a material adverse effect on our business, financial condition, results of operations, cash flows, ability to make distributions to our unitholders, the trading price of our common units and our ability to conduct our business.

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

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

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

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

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

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

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

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

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

The lead plaintiff obtained an extension to file its consolidated amended complaint until May 4, 2009; defendants have 60 days from that date to answer or otherwise respond to the complaint.

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

We intend to vigorously defend these actions. There can be no assurance regarding the outcome of the litigation.

In March and April 2009, nine current or former executives of the Private Company and certain of its affiliates filed wage claims with the Oklahoma Department of Labor against our general partner. Their claims arise from our general partner’s Long-Term Incentive Plan, Employee Phantom Unit Agreement (“Phantom Unit Agreement”). Most claimants allege that phantom units previously awarded to them vested upon the Change of Control that occurred in July 2008. One claimant alleges that his phantom units vested upon his termination. The claimants contend our general partner’s failure to deliver certificates for the phantom units within 60 days after vesting has caused them to be damaged, and they seek recovery of approximately $2 million in damages and penalties. On April 30, 2009, all of the wage claims were dismissed on jurisdictional grounds by the Department of Labor. Our general partner intends to vigorously defend these claims.

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

We may experience increased losses as a result of waivers relating to the Private Company’s indemnification obligations.

In the Amended Omnibus Agreement and other agreements with the Private Company, the Private Company agreed to indemnify us for certain environmental and other claims relating to the crude oil and liquid asphalt cement assets that have been contributed to us. In connection with the Settlement, we waived these claims, and the Amended Omnibus Agreement and other relevant agreements, including the indemnification provisions therein, were rejected as part of the Bankruptcy Cases. If we experience an environmental or other loss, we would experience increased losses that may have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business.

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Our common units were delisted from the Nasdaq and are currently quoted on the Pink Sheets, which may make buying or selling our common units more difficult.

Effective at the opening of business on February 20, 2009, trading in our common units was suspended on Nasdaq due to our failure to timely file our periodic reports with the SEC, and our common units were subsequently delisted from Nasdaq. Our common units are currently traded on the Pink Sheets, which is an over-the-counter securities market, under the symbol SGLP.PK. The fact that our common units are not listed on a national securities exchange is likely to make trading such common units more difficult for broker-dealers, unitholders and investors, potentially leading to further declines in the price of our common units. In addition, it may limit the number of institutional and other investors that will consider investing in our common units, which may have an adverse effect on the price of our common units. It may also make it more difficult for us to raise capital in the future.

If our general partner fails to develop or maintain an effective system of internal controls, then we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common units.

SemGroup Energy Partners G.P., L.L.C., our general partner, has sole responsibility for conducting our business and for managing our operations. Effective internal controls are necessary for our general partner, on our behalf, to provide reliable financial reports, prevent fraud and operate us successfully as a public company. If our general partner’s efforts to develop and maintain its internal controls are not successful, it is unable to maintain adequate controls over our financial processes and reporting in the future or it is unable to assist us in complying with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, our operating results could be harmed or we may fail to meet our reporting obligations.

We and our general partner rely upon the Private Company for certain personnel related to our internal controls and disclosure controls and procedures for certain of our crude oil and asphalt operations. In connection with the Settlement, we migrated to our own accounting system and no longer rely upon the Private Company’s accounting system, which may change the design or implementation of certain of our controls. Ineffective internal controls could cause us to report inaccurate financial information or cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.

The equity interests in our general partner may be transferred to a third party in the Bankruptcy Cases.

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We may continue to incur substantial costs as a result of events related to the Bankruptcy Filings.

Events related to the Bankruptcy Filings, the securities litigation and governmental investigations, and our efforts to enter into storage contracts with third party customers and pursue other strategic opportunities has resulted in increased expense and we expect it to continue to result in increased expense due to the costs related to legal and financial advisors as well as other related costs. General and administrative expenses (exclusive of non-cash compensation expense related to the vesting of the units under our general partner’s long-term incentive plan (the “Plan”)) increased by approximately $6.9 million, $7.5 million and $5.7 million, or approximately 300%, 326% and 248%, to approximately $9.2 million for the third quarter of 2008, $9.8 million for the fourth quarter of 2008 and $8.0 million for the first quarter of 2009, respectively, compared to $2.3 million in the second quarter of 2008. We expect this increased level of general and administrative expenses to continue throughout 2009. These increased costs may be substantial and could have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business.

We may not be able to raise sufficient capital to operate or grow our business.

As of June 26, 2009, we had an aggregate unused credit availability under our revolving credit facility of approximately $28.1 million and cash on hand of approximately $3.0 million. Pursuant to the Credit Agreement Amendment, our revolving credit facility is limited to $50.0 million. In addition, if any of the financial institutions that support our revolving credit facility were to fail, we may not be able to find a replacement lender, which could negatively impact our ability to borrow under our revolving credit facility. For instance, Lehman Brothers Commercial Bank is one of the lenders under our $50.0 million revolving credit facility, and Lehman Brothers Commercial Bank has agreed to fund approximately $2.5 million (approximately 5%) of the revolving credit facility. On several occasions Lehman Brothers Commercial Bank has failed to fund revolving loan requests under our revolving credit facility, effectively limiting the aggregate amount of our revolving credit facility to $47.5 million. Our ability to access capital markets may also be limited due to the Bankruptcy Filings and the related uncertainty of our future cash flows. In addition, we may have difficulty obtaining a credit rating or any credit rating that we do obtain may be lower that it otherwise would be due to our relationships with the Private Company. The lack of a credit rating or a low credit rating may also adversely impact our ability to access capital markets. If we fail to raise additional capital or an event of default exists under our credit agreement, we may be forced to sell assets, make a bankruptcy filing or take other action that could have a material adverse effect on our business, the price of our common units and our results of operations. In addition, if we are unable to access the capital markets for acquisitions or expansion projects, it will have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business.

We are not fully insured against all risks incident to our business, and could incur substantial liabilities as a result.

We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of changing market conditions, premiums and deductibles for certain of our insurance policies may increase substantially in the future. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business.

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Risks Related to Our Business

We depend upon the Private Company for a portion of our revenues and are therefore indirectly subject to the business risks of the Private Company.

Because we depend upon the Private Company for a portion of our revenues, we are indirectly subject to the business risks of the Private Company, many of which are similar to the business risks we face. In particular, these business risks include the following:

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the inability of the Private Company to generate adequate gross margins from the purchase, transportation, storage and marketing of petroleum products;

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material reductions in the supply of crude oil, liquid asphalt cement and petroleum products;

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a material decrease in the demand for crude oil, finished asphalt and petroleum products in the markets served by the Private Company;

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the inability of the Private Company to manage its commodity price risk resulting from its ownership of crude oil, liquid asphalt cement and petroleum products;

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contract non-performance by the Private Company’s customers; and

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various operational risks to which the Private Company’s business is subject.

In addition, as a result of the Bankruptcy Filings, we are also currently subject to the risks described above under “—Risks Related to the Bankruptcy Filings.”

We may not be able to obtain funding or obtain funding on acceptable terms because of the deterioration of the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.

Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it difficult to obtain funding.

In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers. These factors may have a material adverse effect on our ability to refinance our outstanding debt or, in the event we fail to comply with the covenants of the credit facility, to obtain a waiver of events of default under our credit agreement or to negotiate forbearance with our lenders.

Due to these factors, we cannot be certain that funding will be available if needed and to the extent required, on acceptable terms or at all. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to operate or grow our existing business, make future acquisitions, or otherwise take advantage of business opportunities or respond to competitive pressures any of which could have a material adverse effect on our financial condition and results of operations. In addition, such financing, if available, may be at higher interest rates or result in substantial equity dilution.

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We require a significant amount of cash to service our indebtedness. Our ability to generate cash depends on many factors beyond our control.

Our ability to make payments on and to refinance our indebtedness and to fund any future capital expenditures depends on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure our unitholders that we will generate sufficient cash flow from operations or that future borrowings will be available to us under our credit agreement or otherwise at all or in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs.

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units and subordinated units.

Pursuant to the Credit Agreement Amendment, we are prohibited from making distributions to our unitholders if our leverage ratio (as defined in the credit agreement) exceeds 3.50 to 1.00. As of December 31, 2008 and March 31, 2009, our leverage ratio was 4.86 to 1.00 and 5.28 to 1.00, respectively. If our leverage ratio does not improve, we may not make quarterly distributions to our unitholders in the future. Even if we are permitted to make distributions under our credit agreement, we may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things, the risks described in this section, including the Bankruptcy Filings.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:

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the level of capital expenditures we make;

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the cost of acquisitions;

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our debt service requirements and other liabilities;

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fluctuations in our working capital needs;

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our ability to borrow funds and access capital markets;

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restrictions contained in our credit facility or other debt agreements, including the ability to make distributions while events of default exist under our credit facility; and

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the amount of cash reserves established by our general partner.

The amount of cash we have available for distribution to holders of our common units and subordinated units depends primarily on our cash flow and not solely on earnings reflected in our financial statements. Consequently, even if we are profitable and are otherwise able to pay distributions, we may not be able to make cash distributions to holders of our common units and subordinated units.

Our unitholders should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow and not solely on earnings reflected in our financial statements, which will be affected by non-cash items. As a result, we may make cash distributions, if permitted by our credit agreement, during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

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A significant decrease in demand for crude oil and/or finished asphalt products in the areas served by our storage facilities and pipelines could reduce our ability to make distributions to our unitholders if we are otherwise permitted to make distributions under our credit agreement.

A sustained decrease in demand for crude oil and/or finished asphalt products in the areas served by our storage facilities and pipelines could significantly reduce our revenues and, therefore, reduce our ability to make or increase distributions to our unitholders if we are otherwise permitted to make distributions under our credit agreement. Factors that could lead to a decrease in market demand for crude oil and finished asphalt products include:

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lower demand by consumers for refined products, including finished asphalt products, as a result of recession or other adverse economic conditions or due to high prices caused by an increase in the market price of crude oil or higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasolines or other refined products;

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a shift by consumers to more fuel-efficient or alternative fuel vehicles or an increase in fuel economy of vehicles, whether as a result of technological advances by manufacturers, governmental or regulatory actions or otherwise; and

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fluctuations in demand for crude oil, such as those caused by refinery downtime or shutdowns, could also significantly reduce our revenues and, therefore, reduce our ability to make distributions to our unitholders.

Certain of our field and pipeline operating costs and expenses are fixed and do not vary with the volumes we gather and transport. These costs and expenses may not decrease ratably or at all should we experience a reduction in our volumes gathered or transmitted by our gathering and transportation operations. As a result, we may experience declines in our margin and profitability if our volumes decrease. Due to events related to the Bankruptcy Filings, the volumes being terminalled, stored, transported and gathered have decreased as compared to periods prior to the Bankruptcy Filings, which has negatively impacted total revenues. As an example, fourth quarter 2008 total revenues are approximately $9.5 million (or approximately 19%) less than second quarter 2008 total revenues, in each case excluding fuel surcharge revenues related to fuel and power consumed to operate our liquid asphalt cement storage tanks. Our future total revenues may be further impacted because, in connection with the Settlement, the Private Company rejected the Terminalling Agreement and the Throughput Agreement and we and the Private Company entered into the New Throughput Agreement and the New Terminalling Agreement. We expect revenues from services provided to the Private Company under the New Throughput Agreement and New Terminalling Agreement to be substantially less than prior revenues from services provided to the Private Company as the new agreements are based upon actual volumes gathered, transported, terminalled and stored instead of certain minimum volumes and are at reduced rates when compared to the Throughput Agreement and Terminalling Agreement (see “Item 1. Business—Impact of the Bankruptcy of the Private Company and Certain of its Subsidiaries and Related Events—Settlement with the Private Company”).

A material decrease in the production of crude oil from the oil fields served by our pipelines could materially reduce our ability to make distributions to our unitholders if we are otherwise permitted to make distributions under our credit agreement.

The throughput on our crude oil pipelines depends on the availability of attractively priced crude oil produced from the oil fields served by such pipelines, or through connections with pipelines owned by third parties. Crude oil production may decline for a number of reasons, including natural declines due to depleting wells, a material decrease in the price of crude oil, or the inability of producers to obtain necessary drilling or other permits from applicable governmental authorities. If we are unable to replace volumes lost due to a temporary or permanent material decrease in production from the oil fields served by our crude oil pipelines, our throughput could decline, reducing our revenue and cash flow and adversely affecting our ability to make distributions to our unitholders if we are otherwise permitted to make distributions under our credit agreement. The Private Company may also have difficulty attracting producers while it is in bankruptcy. In addition, it is difficult to attract producers to a new gathering system if the producer is already connected to an existing system. As a result, the Private Company or third-party shippers on our pipeline systems may experience difficulty acquiring crude oil at the wellhead in areas where there are existing relationships between producers and other gatherers and purchasers of crude oil.

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A material decrease in the production of liquid asphalt cement could materially reduce our ability to make distributions to our unitholders if we are otherwise permitted to make distributions under our credit agreement.

The throughput at our asphalt facilities depends on the availability of attractively priced liquid asphalt cement produced from the various liquid asphalt cement producing refineries. Liquid asphalt cement production may decline for a number of reasons, including refiners processing more light, sweet crude oil or refiners installing coker units that further refine heavy residual fuel oil bottoms such as liquid asphalt cement. If we are unable to replace volumes lost due to a temporary or permanent material decrease in production from the suppliers of liquid asphalt cement, our throughput could decline, reducing our revenue and cash flow and adversely affecting our ability to make distributions to our unitholders if we are otherwise permitted to make distributions under our credit agreement.

Our debt levels under the credit agreement may limit our ability to make distributions and our flexibility in obtaining additional financing and in pursuing other business opportunities.

Our level of debt under the credit facility could have important consequences for us, including the following:

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our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

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we will need a substantial portion of our cash flow to make principal and interest payments on our debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders;

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our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

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our debt level may limit our flexibility in responding to changing business and economic conditions.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors. Our ability to service debt under our credit facility also will depend on market interest rates, since the interest rates applicable to our borrowings will fluctuate with the London Interbank Offered Rate, or LIBOR, or the prime rate, and are higher due to the Forbearance Agreement, as amended, and the Credit Agreement Amendment. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms, or at all.

We expect that for the foreseeable future, substantially all of our cash generated from operations will be used to service our debt and restrictions in our credit facility may prevent us from making capital expenditures, growing our business or otherwise engaging in beneficial transactions.

We expect that for the foreseeable future, substantially all of our cash generated from operations will be used to service our debt. Among other things, our credit facility, as amended by the Credit Agreement Amendment, requires us to make (i) minimum quarterly amortization payments on March 31, 2010 in the amount of $2.0 million, June 30, 2010 in the amount of $2.0 million, September 30, 2010 in the amount of $2.5 million, December 31, 2010 in the amount of $2.5 million and March 31, 2011 in the amount of $2.5 million, (ii) mandatory prepayments of amounts outstanding under the revolving credit facility (with no commitment reduction) whenever cash on hand exceeds $15.0 million, (iii) mandatory prepayments with 100% of asset sale proceeds, (iv) mandatory prepayment with 50% of the proceeds raised through equity sales and (v) annual prepayments with 50% of excess cash flow (as defined in the Credit Agreement Amendment). Our credit facility, as amended by the Credit Agreement Amendment, prohibits us from making draws under the revolving credit facility if we would have more than $15.0 million of cash on hand after making the draw and applying the proceeds thereof. In addition, pursuant to the Credit Agreement Amendment, our revolving credit facility is limited to $50.0 million Capital expenditures are also limited under our credit agreement to $12.5 million in 2009, $8.0 million in 2010 and $4.0 million in 2011. These restrictions may prevent us making capital expenditures, growing our business or otherwise engaging in beneficial transactions. Furthermore, our credit facility, as amended by the Credit Agreement Amendment, requires us to comply with certain restrictive financial covenants, including minimum interest coverage ratios and maximum leverage ratios (see “Management’s Discussion and Analysis of Financial Condition —Liquidity and Capital Resources” and Note 8 to our Consolidated Financial Statements). Failure to comply with these covenants may result in an event of default under our credit facility and may have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, our results of operations and ability to conduct our business.

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If we borrow funds to make any permitted quarterly distributions, our ability to pursue acquisitions and other business opportunities may be limited and our operations may be materially and adversely affected.

Available cash for the purpose of making distributions to unitholders includes working capital borrowings. If we borrow funds to pay one or more quarterly distributions, such amounts will incur interest and must be repaid in accordance with the terms of our credit facility. Currently we are prohibited from paying distributions to our unitholders due to our failure to maintain a leverage ratio that is less than 3.50 to 1.00, as required by our credit agreement. In addition, any amounts borrowed for permitted distributions to our unitholders will reduce the funds available to us for other purposes under our credit facility, including amounts available for use in connection with acquisitions and other business opportunities. If we are unable to pursue our growth strategy due to our limited ability to borrow funds, our operations may be materially and adversely affected.

We face intense competition in our gathering, transportation, terminalling and storage activities. Competition from other providers of crude oil gathering, transportation, terminalling and storage services that are able to supply our customers with those services at a lower price could reduce our ability to make distributions to our unitholders if we are otherwise permitted to make distributions under our credit agreement.

We are subject to competition from other crude oil gathering, transportation, terminalling and storage operations that may be able to supply the Private Company and our other customers with the same or comparable services on a more competitive basis. We compete with national, regional and local gathering, storage, terminalling and pipeline companies, including the major integrated oil companies, of widely varying sizes, financial resources and experience. Some of these competitors are substantially larger than us, have greater financial resources, and control substantially greater storage capacity than we do. With respect to our gathering and transportation services, these competitors include TEPPCO Partners, L.P., Plains All American Pipeline, L.P., ConocoPhillips, Sunoco Logistics Partners L.P. and National Cooperative Refinery Association, among others. With respect to our storage and terminalling services, these competitors include BP plc, Enbridge Energy Partners, L.P. and Plains All American Pipeline, L.P. Several of our competitors conduct portions of their operations through publicly traded partnerships with structures similar to ours, including Plains All American Pipeline, L.P., TEPPCO Partners, L.P., Sunoco Logistics Partners L.P. and Enbridge Energy Partners, L.P. Our ability to compete could be harmed by numerous factors, including:

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price competition;

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the perception that another company can provide better service;

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the uncertainty relating to the Private Company having filed bankruptcy; and

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the availability of alternative supply points, or supply points located closer to the operations of the Private Company’s customers.

In addition, the Private Company owns midstream assets and may engage in competition with us. If we are unable to compete with services offered by other midstream enterprises, including the Private Company, our ability to make distributions to our unitholders may be adversely affected if we are otherwise permitted to make distributions under our credit agreement.

Some of our pipeline systems are dependent upon their interconnections with other crude oil pipelines to reach end markets.

Some of our pipeline systems are dependent upon their interconnections with other crude oil pipelines to reach end markets. Reduced throughput on these interconnecting pipelines as a result of testing, line repair, reduced operating pressures or other causes could result in reduced throughput on our pipeline systems that would adversely affect our revenue and cash flow and our ability to make distributions to our unitholders.

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Prior to the Bankruptcy Filings, a principal focus of our business strategy was to grow and expand our business through acquisitions. If we are able to pursue this strategy in the future but are unable to make acquisitions on economically acceptable terms, our future growth may be limited.

Prior to the Bankruptcy Filings, a principal focus of our business strategy was to grow and expand our business through acquisitions. If we are able to stabilize our business, we may be able to again pursue this strategy. Our ability to grow depends, in part, on our ability to make acquisitions that result in an increase in the cash generated per unit from operations. If we are unable to make these accretive acquisitions, either because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms or (3) outbid by competitors, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations per unit.

Any acquisition involves potential risks, including, among other things:

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mistaken assumptions about volumes, revenues and costs, including synergies;

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an inability to integrate successfully the businesses we acquire;

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an inability to hire, train or retain qualified personnel to manage and operate our business and assets;

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the assumption of unknown liabilities;

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limitations on rights to indemnity from the seller;

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mistaken assumptions about the overall costs of equity or debt;

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the diversion of management’s and employees’ attention from other business concerns;

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unforeseen difficulties operating in new product areas or new geographic areas; and

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customer or key employee losses at the acquired businesses.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

Our acquisition strategy is based, in part, on our expectation of ongoing divestitures of energy assets by industry participants. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our operations and cash flows available for distribution to our unitholders.

Prior to the Bankruptcy Filings, our growth strategy included acquiring midstream entities or assets that are distinct and separate from our existing terminalling, storage, gathering and transportation operations. If we are able to pursue this strategy in the future, it could subject us to additional business and operating risks.

We may acquire midstream assets that have operations in new and distinct lines of business from our crude oil or our liquid asphalt cement operations. Integration of a new business is a complex, costly and time-consuming process. Failure to timely and successfully integrate acquired entities’ new lines of business with our existing operations may have a material adverse effect on our business, financial condition or results of operations. The difficulties of integrating a new business with our existing operations include, among other things:

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operating distinct businesses that require different operating strategies and different managerial expertise;

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the necessity of coordinating organizations, systems and facilities in different locations;

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integrating personnel with diverse business backgrounds and organizational cultures; and

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consolidating corporate and administrative functions.

In addition, the diversion of our attention and any delays or difficulties encountered in connection with the integration of a new business, such as unanticipated liabilities or costs, could harm our existing business, results of operations, financial conditions and prospects. Furthermore, new lines of business will subject us to additional business and operating risks. For example, we may in the future determine to acquire businesses that are subject to significant risks due to fluctuations in commodity prices. These new business and operating risks could have a material adverse effect on our financial condition or results of operations.

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Expanding our business by constructing new assets subjects us to risks that projects may not be completed on schedule, and that the costs associated with projects may exceed our expectations, which could cause our cash available for distribution to our unitholders to be less than anticipated.

The construction of additions or modifications to our existing assets, and the construction of new assets, involves numerous regulatory, environmental, political, legal and operational uncertainties and requires the expenditure of significant amounts of capital. If we undertake these types of projects, they may not be completed on schedule or at all or at the budgeted cost. In addition, our revenues may not increase immediately upon the expenditure of funds on a particular project. Moreover, we may construct facilities to capture anticipated future growth in demand in a market in which such growth does not materialize. We acquired the Acquired Pipeline Assets from the Private Company in May 2008. We have suspended capital expenditures on this pipeline due to the continuing impact of the Bankruptcy Filings. Management currently intends to put the asset into service in early 2010 and is exploring various alternatives to complete the project.

We are exposed to the credit risks of our third-party customers in the ordinary course of our gathering activities. Any material nonpayment or nonperformance by our third-party customers could reduce our ability to make distributions to our unitholders.

We are subject to risks of loss resulting from nonpayment or nonperformance by our third-party customers. Some of our customers may be highly leveraged and subject to their own operating and regulatory risks. In addition, any material nonpayment or nonperformance by our customers could require us to pursue substitute customers for our affected assets or provide alternative services. Any such efforts may not be successful or may not provide similar fees. These events could reduce our ability to make distributions to our unitholders.

Our revenues from third-party customers are generated under contracts that must be renegotiated periodically and that allow the customer to reduce or suspend performance in some circumstances, which could cause our revenues from those contracts to decline and reduce our ability to make distributions to our unitholders.

Some of our contract-based revenues from customers are generated under contracts with terms which allow the customer to reduce or suspend performance under the contract in specified circumstances, such as the occurrence of a catastrophic event to our or the customer’s operations. The occurrence of an event which results in a material reduction or suspension of our customer’s performance could reduce our ability to make distributions to our unitholders if we are otherwise permitted to make distributions under our credit agreement.

Many of our contracts with customers for producer field services have terms of one year or less. As these contracts expire, they must be extended and renegotiated or replaced. We may not be able to extend, renegotiate or replace these contracts when they expire, and the terms of any renegotiated contracts may not be as favorable as the contracts they replace. In particular, our ability to extend or replace contracts could be harmed by numerous competitive factors, such as those described above under “—We face intense competition in our gathering, transportation, terminalling and storage activities. Competition from other providers of crude oil gathering, transportation, terminalling and storage services that are able to supply our customers with those services at a lower price could reduce our ability to make distributions to our unitholders.” Additionally, we may incur substantial costs if modifications to our terminals are required in order to attract substitute customers or provide alternative services. If we cannot successfully renew significant contracts or must renew them on less favorable terms, or if we incur substantial costs in modifying our terminals, our revenues from these arrangements could decline and our ability to make distributions to our unitholders could suffer if we are otherwise permitted to make distributions under our credit agreement.

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We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any necessary pipeline repair, or preventative or remedial measures, which could have a material adverse effect on our results of operations.

The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in “high consequence areas”, including high population areas, areas that are sources of drinking water, ecological resource areas that are unusually sensitive to environmental damage from a pipeline release and commercially navigable waterways, unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area. The regulations require operators of covered pipelines to:

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perform ongoing assessments of pipeline integrity;

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identify and characterize threats to pipeline segments that could impact a high consequence area;

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improve data collection, integration and analysis;

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repair and remediate the pipeline as necessary; and

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implement preventive and mitigating actions.

Effective July 2008, the DOT broadened the scope of coverage of its existing pipeline safety standards, including its integrity management programs, to include certain rural onshore hazardous liquid and low-stress pipeline systems found near “unusually sensitive areas,” including non-populated areas requiring extra protection because of the presence of sole source drinking water resources, endangered species, or other ecological resources. Also, in December 2006, the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 was enacted. This act reauthorizes and amends the DOT’s pipeline safety programs and includes a provision eliminating the regulatory exemption for hazardous liquid pipelines operated at low stress. Adoption of new or more stringent pipeline safety regulations affecting our gathering or low-stress pipelines could result in more rigorous and costly integrity management planning requirements being imposed on those lines, which could have a material adverse effect on our results of operations. Please read “Item 1. Business—Regulation—Pipeline Safety” for more information.

Our operations are subject to environmental and worker safety laws and regulations that may expose us to significant costs and liabilities. Failure to comply with these laws and regulations could adversely affect our ability to make distributions to our unitholders if we are otherwise permitted to make distributions under our credit agreement.

Our midstream crude oil gathering, transportation, terminalling and storage operations, together with the liquid asphalt cement terminalling and storage assets that we acquired from the Private Company, are subject to stringent federal, state and local laws and regulations relating to the protection of the environment. Various governmental authorities, including the EPA, have the power to enforce compliance with these laws and regulations and the permits issued under them, and violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Joint and several strict liability may be incurred without regard to fault or the legality of the original conduct under CERCLA, RCRA and analogous state laws for the remediation of contaminated areas. Private parties, including the owners of properties located near our terminalling and storage facilities or through which our pipeline systems pass, also may have the right to pursue legal actions to enforce compliance, as well as seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. Moreover, new stricter laws, regulations or enforcement policies could be implemented that significantly increase our compliance costs and the cost of any remediation that may become necessary, some of which may be material.

In performing midstream operations and asphalt services, we incur environmental costs and liabilities in connection with the handling of hydrocarbons and solid wastes. We currently own, operate or lease properties that for many years have been used for midstream activities, including properties in and around the Cushing Interchange, and with respect to our asphalt assets, for asphalt activities. Activities by us or prior owners, lessees or users of these properties over whom we had no control may have resulted in the spill or release of hydrocarbons or solid wastes on or under them. Additionally, some sites we own or operate are located near current or former storage, terminal and pipeline operations, and there is a risk that contamination has migrated from those sites to ours. Increasingly strict environmental laws, regulations and enforcement policies as well as claims for damages and other similar developments could result in significant costs and liabilities, and our ability to make distributions to our unitholders could suffer as a result. Please see “Item 1—Business—Regulation” for more information.

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In addition, the workplaces associated with the storage facilities and pipelines we operate are subject to OSHA requirements and comparable state statutes that regulate the protection of the health and safety of workers. The OSHA hazard communication standard requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees, state and local government authorities, and local residents. Failure to comply with OSHA requirements, including general industry standards, recordkeeping requirements and monitoring of occupational exposure to regulated substances, could subject us to fines or significant compliance costs and adversely affect our ability to make distributions to our unitholders if we are otherwise permitted to make distributions under our credit agreement.

Adoption of legislation and regulatory measures targeting greenhouse gas (GHG) emissions could affect our operations, expose us to significant costs and liabilities, and reduce demand for the products we transport.

The oil and gas industry is a direct source of certain GHG emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. Federal legislation requiring GHG controls may be enacted by the end of 2009. In addition, EPA is considering initiating a rulemaking to regulate GHGs as a pollutant under the CAA. EPA recently proposed findings under the CAA that GHGs in the atmosphere endanger public health and welfare, and that emissions from mobile sources cause or contribute to GHGs in the atmosphere. If the findings are finalized as proposed, EPA standards eventually promulgated pursuant to these findings could affect our operations and ability to obtain air permits for new or modified facilities. Furthermore, EPA recently issued proposed regulations that would require the economy-wide monitoring and reporting of GHG emissions on an annual basis. The rule as proposed would apply to natural gas transmission compression and could apply to emissions from other activities we conduct. Although this proposed rule would not control GHG emission levels from any facilities, if it applied to us, it would still cause us to incur monitoring and reporting costs. Legislation and regulations are also in various stages of discussions or implementation in many of the states in which we operate.

Passage of climate change legislation or other federal or state legislative or regulatory initiatives that regulate or restrict GHG emissions in areas in which we conduct business could potentially:

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adversely affect the demand for our products and services;

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affect our operations and ability to obtain air permits for new or modified facilities;

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increase the costs to operate and maintain our facilities;

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increase the costs to install new emission controls on our facilities;

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increase the costs of our business by requiring us to acquire allowances to authorize our GHG emissions (e.g., at compressor stations); and

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increase the costs of our business by requiring us to pay any taxes related to our GHG emissions and/or administer and manage a GHG emissions program.

Please read “Item 1. Business—Environmental, Health and Safety Risks—Climate” for more information.

Our business involves many hazards and operational risks, including adverse weather conditions, which could cause us to incur substantial liabilities.

Our operations are subject to the many hazards inherent in the transportation and storage of crude oil and the storage and processing of liquid asphalt cement, including:

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explosions, fires, accidents, including road and highway accidents involving our tanker trucks;

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extreme weather conditions, such as hurricanes which are common in the Gulf Coast and tornadoes and flooding which are common in the Midwest;

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damage to our pipelines, storage tanks, terminals and related equipment;

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leaks or releases of crude oil into the environment; and

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acts of terrorism or vandalism.

If any of these events were to occur, we could suffer substantial losses because of personal injury or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage resulting in curtailment or suspension of our related operations. In addition, mechanical malfunctions, faulty measurement or other errors may result in significant costs or lost revenues.

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We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.

We do not own all of the land on which our pipelines and crude oil and asphalt facilities have been constructed, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way or any material real property leases lapse or terminate. We obtain the rights to construct and operate our pipelines and some of our crude oil and asphalt facilities on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew leases, right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions to our unitholders. In addition, we are in the process of obtaining consents from the lessors for certain leased property that was transferred to us as part of the acquisition of our asphalt assets. If any consent is denied, it could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions to our unitholders.

Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.

The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks on our industry in general, and on us in particular, is not known at this time. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for our services, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror.

Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

Risks Inherent in an Investment in Us

Some of our general partner’s directors are affiliates of certain creditors of SemGroup Holdings; therefore, such creditors may have different business interests than the common unitholders.

Manchester is a creditor under a loan agreement with SemGroup Holdings, which is a subsidiary of the Private Company. This loan is secured by our subordinated units and incentive distribution rights and the membership interests in our general partner, owned by SemGroup Holdings. On July 18, 2008, Manchester and Alerian declared an event of default under the loan agreement and exercised their right under a pledge agreement with SemGroup Holdings to direct the vote of the membership interests of our general partner. Manchester and Alerian exercised these voting rights to reconstitute our general partner’s board of directors. On March 20, 2009, Alerian transferred its interest in the Holdings Credit Agreements to Manchester (Alerian is still potentially entitled to receive a portion of certain potential recoverable value from such interest). Manchester may have business interests that are different from the business interests of our common unitholders.

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Our general partner has sole responsibility for conducting our business and managing our operations. Our general partner has conflicts of interest with us and limited fiduciary duties, which may permit it to favor its own interests to the detriment of our unitholders.

Conflicts of interest may arise between our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving those conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. Although the conflicts committee of our general partner’s board of directors may review such conflicts of interest, our general partner’s board of directors is not required to submit such matters to the conflicts committee. These conflicts include, among others, the following situations:

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neither our partnership agreement nor any other agreement requires the general partner or any person who controls the general partner to pursue a business strategy that favors us. Such persons may make these decisions in their best interest, which may be contrary to our interests;

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our general partner is allowed to take into account the interests of parties other than us, such as creditors and the Private Company and their affiliates, in resolving conflicts of interest;

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if we do not have sufficient available cash from operating surplus, our general partner could cause us to use cash from non-operating sources, such as asset sales, issuances of securities and borrowings, to pay distributions, which means that we could make distributions that deteriorate our capital base and that our general partner could receive distributions on its subordinated units and incentive distribution rights to which it would not otherwise be entitled if we did not have sufficient available cash from operating surplus to make such distributions;

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our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;

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our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to unitholders;

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our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units;

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our general partner may make a determination to receive a quantity of our Class B units in exchange for resetting the target distribution levels related to its incentive distribution rights without the approval of the conflicts committee of our general partner or our unitholders;

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our general partner determines which costs incurred by it and its affiliates are reimbursable by us and the Private Company determines the allocation of shared overhead expenses;

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our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

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our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

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our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units;

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our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and

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our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

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Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and subordinated units and restricts the remedies available to holders of our common units and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:

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permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its right to receive a quantity of our Class B units in exchange for resetting the target distribution levels related to its incentive distribution rights, the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;

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provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;

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generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith. In determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

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provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

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provides that in resolving conflicts of interest, it will be presumed that in making its decision the general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

By purchasing a common unit, a common unitholder will become bound by the provisions in the partnership agreement, including the provisions discussed above.

The Private Company may compete with us, which could adversely affect our existing business and limit our ability to acquire additional assets or businesses.

Neither our partnership agreement nor any other agreement with the Private Company prohibits the Private Company or any successor to the Private Company or acquirer of its assets from owning assets or engaging in businesses that compete directly or indirectly with us. The Private Company has indicated in its Reorganization Plan that it intends to emerge from bankruptcy later this year. If it is successful in its reorganization, we will compete with the Private Company in the provision of various services, including the provision of crude oil terminalling and storage services at the Cushing Interchange. In addition, the Private Company or any successor to the Private Company or acquirer of its assets may acquire, construct or dispose of additional midstream or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. As a result, competition from the Private Company or any successor to the Private Company or acquirer of its assets could adversely impact our results of operations and cash available for distribution.

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Cost reimbursements due to our general partner and its affiliates for services provided, which are determined by our general partner, may be substantial and will reduce our cash available for distribution to our unitholders.

Pursuant to our partnership agreement, the Private Company receives reimbursement for the payment of operating expenses related to our operations and for the provision of various general and administrative services for our benefit. Payments for these services may be substantial and reduce the amount of cash available for distribution to unitholders. In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated under our partnership agreement to reimburse or indemnify our general partner. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments would reduce the amount of cash otherwise available for distribution to our unitholders. Please see “Item 13—Certain Relationships and Related Party Transactions, and Director Independence—Agreements Related to Our Acquisition of the Asphalt Assets—Amended Omnibus Agreement.”

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our general partner or our general partner’s board of directors, and have no right to elect our general partner or our general partner’s board of directors on an annual or other continuing basis. The present board of directors of our general partner was chosen by Manchester pursuant to its rights under the Holdings Credit Agreements to direct the vote of the membership interests of our general partner. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Removal of our general partner without its consent will dilute and adversely affect our common unitholders.

If our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of the general partner because of the unitholders’ dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

Control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of SemGroup Holdings, the owner of our general partner, from transferring all or a portion of its ownership interest in our general partner to a third party, or Manchester from transferring all or a portion of its loan interest voting rights in the general partner, to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and thereby influence the decisions made by the board of directors and officers.

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We may issue additional units without approval of our unitholders, which would dilute our unitholders’ ownership interests.

Our partnership agreement does not limit the number or price of additional limited partner interests (including any securities of equal or senior rank to our common units, and options, rights, warrants and appreciation rights relating to any such securities) that we may issue at any time without the approval of our unitholders. In addition, because we are a limited partnership, we will not be subject to the shareholder approval requirements relating to the issuance of securities (other than in connection with the establishment or material amendment of a stock option or purchase plan or the making or material amendment of any other equity compensation arrangement) contained in Nasdaq Marketplace Rule 5635 if we are again listed on Nasdaq. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

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our unitholders’ proportionate ownership interest in us will decrease;

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the amount of cash available for distribution on each unit may decrease;

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because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

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the ratio of taxable income to distributions may increase;

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the relative voting strength of each previously outstanding unit may be diminished; and

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the market price of the common units may decline.

Our partnership agreement restricts the voting rights of unitholders, other than our general partner and its affiliates, including the Private Company, owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions.

Affiliates of our general partner may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.

Executive officers and directors of our general partner beneficially own an aggregate of 578,087 common units and SemGroup Holdings owns 12,570,504 subordinated units, although such units are collateral to a loan between SemGroup Holdings and Manchester. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier. The sale of these units in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders also may incur a tax liability upon a sale of their units. At the end of the subordination period, assuming no additional issuances of common units and no sales of subordinated units, our general partner and its affiliates (excluding executive officers and directors) will own 36.8% of the common units.

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Common units held by persons who are not Eligible Holders will be subject to the possibility of redemption.

The Longview system is, and any additional interstate pipelines that we acquire or construct may be, subject to the rate regulation of the FERC. Our general partner has the right under our partnership agreement to institute procedures, by giving notice to each of our unitholders, that would require transferees of common units and, upon the request of our general partner, existing holders of our common units to certify that they are Eligible Holders. The purpose of these certification procedures would be to enable us to utilize a federal income tax expense as a component of the pipeline’s cost of service upon which tariffs may be established under FERC rate-making policies applicable to entities that pass through their taxable income to their owners. Eligible Holders are individuals or entities subject to United States federal income taxation on the income generated by us or entities not subject to United States federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation. If these tax certification procedures are implemented, we will have the right to redeem the common units held by persons who are not Eligible Holders at the lesser of the holder’s purchase price and the then-current market price of the units. The redemption price would be paid in cash or by delivery of a promissory note, as determined by our general partner.

Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business.

Our unitholders could be liable for our obligations as if they were a general partner if:

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a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

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a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 and 17-804 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

Tax Risks to Common Unitholders

Our unitholders have been and will be required to pay taxes on their share of our taxable income even if they have not or do not receive any cash distributions from us.

Because our unitholders are treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, they will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, even if our unitholders receive no cash distributions from us. In this regard, we did not pay a distribution to our unitholders for the quarters ended June 30, 2008, September 30, 2008, December 31, 2008 or March 31, 2009. In addition, we do not expect to make a distribution relating to the second quarter of 2009 and may not be able to make distributions in the future. Thus, our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

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The storage contracts and leases we recently entered into with third party customers with respect to certain of our asphalt facilities could generate levels of non-qualifying income that require us to transfer certain of these contracts and the related asphalt assets and rental or fee income to one or more subsidiaries taxed as corporations. Any such subsidiary taxed as a corporation would be subject to entity level federal and state income taxes on its net taxable income and, if a material amount of entity-level taxes were incurred, then our cash available for distribution to our unitholders could be substantially reduced.

We recently entered into new storage contracts and leases with third party customers with respect to substantially all of our asphalt facilities. It is unclear under current tax law as to whether the rental income from the leases, and whether the fees attributable to certain of the processing services we provide under certain of the storage contracts, constitute “qualifying income.” In the second quarter of 2009, we submitted a request for a ruling from the IRS that rental income from the leases constitutes “qualifying income.” We may not be successful in obtaining this ruling. If we are not successful in obtaining this ruling, we will likely have to transfer the leases and the related asphalt assets and rental income, and/or certain of the processing assets and related fee income, to one or more subsidiaries taxed as corporations. Even if successful in obtaining this ruling, we will likely transfer certain of the processing assets and related fee income, to one or more subsidiaries taxed as corporations Any such subsidiary that is taxed as a corporation 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 (and possibly local) income tax at varying rates. Distributions would generally be taxed again to unitholders as corporate distributions and none of the income, gains, losses, deductions or credits of any such subsidiary would flow through to our unitholders. If a material amount of entity-level taxes were incurred by any such subsidiaries, then our cash available for distribution to our unitholders could be substantially reduced.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on us 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 us, 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 we were treated as a corporation for federal income tax purposes, then we would pay federal income tax on our 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 our income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as an entity, cash available for distribution to our unitholders would be substantially reduced. Treatment of us 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 our common units.

Current law may change, so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay annually a Texas franchise tax at a maximum effective rate of 0.7% of our gross income apportioned to Texas with respect to the prior year. As of June 26, 2009, we paid $0.1 million and $0.3 million representing our estimated tax liability related to our 2007 and 2008 gross income apportioned to Texas, respectively. Imposition of such a tax on us by Texas and, if applicable, by any other state will reduce the cash available for distribution to our unitholders. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

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The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of Congress are considering substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Although the currently proposed legislation would not appear to affect our tax treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

If the IRS contests any of the federal income tax positions we take, the market for our common units may be adversely affected, and the costs of any contest will reduce our cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to our unitholders in excess of the total net taxable income our unitholders were allocated for a common unit, which decreased their tax basis in that common unit, will, in effect, become taxable income to our unitholders if the common unit is sold at a price greater than their tax basis in that common unit, even if the price our unitholders receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if our unitholders sell their units, they may incur a tax liability in excess of the amount of cash our unitholders receive from the sale.

Tax-exempt entities, regulated investment companies and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), regulated investment companies (known as mutual funds), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income. If a potential unitholder is a tax-exempt entity or a foreign person, it should consult its tax advisor before investing in our common units.

We will treat each purchaser of units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and/or amortization positions that may not conform with all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from their sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns.

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The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated for federal income tax purposes if there are one or more transfers of interests in our partnership that together represent a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For these purposes,

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multiple transfers of the same interest within a twelve month period will be counted only once;

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if the Private Company sells or exchanges its interests in SemGroup Holdings or our general partner, the interests held by SemGroup Holdings or our general partner, as the case may be, in us will be deemed to have been sold or exchanged; and

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if 50% or more of the total interests in the Private Company’s capital and profits are sold or exchanged within a twelve month period, the Private Company, SemGroup Holdings and the general partner will be deemed to have sold or exchanged all of their interests in us.

Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

Our unitholders likely will be subject to state and local taxes and return filing or withholding requirements as a result of investing in our common units.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. Our unitholders likely will be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We own property and conduct business in Texas, Oklahoma, Kansas, Colorado, New Mexico, Arkansas, California, Georgia, Idaho, Illinois, Indiana, Missouri, Michigan, Montana, Nebraska, Nevada, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Utah, Virginia and Washington. Of these states, Texas does not currently impose a state income tax on individuals. We may own property or conduct business in other states or foreign countries in the future. It is each unitholder’s responsibility to file all federal, state and local tax returns. Under the tax laws of some states where we will conduct business, we may be required to withhold a percentage from amounts to be distributed to a unitholder who is not a resident of that state. For example, in the case of Oklahoma, we are required to either report detailed tax information about our non-Oklahoma resident unitholders with an income in Oklahoma in excess of $500 to the taxing authority, or withhold an amount equal to 5% of the portion of our distributions to unitholders which is deemed to be the Oklahoma share of our income. Similarly, we are required to withhold Kansas income tax at a rate of 6.45% on each non-Kansas resident unitholder’s share of our taxable income that is attributable to Kansas (regardless of whether such income is distributed), unless the non-Kansas resident unitholder files a tax reporting affidavit with us which we, in turn, are required to file with the Kansas Department of Revenue. Our counsel has not rendered an opinion on the state and local tax consequences of an investment in our common units.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We will adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. Because the determination of value and the allocation of value are factual matters, rather than legal matters, our counsel is unable to opine as to these matters. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

A description of our properties is contained in “Item 1—Business.”

Title to Properties

Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, property on which our pipelines were built was purchased in fee. Our crude oil terminals are on real property owned or leased by us.

Our asphalt assets are on real property owned or leased by us. Some of the real property leases that were transferred to us as part of the acquisition of our asphalt assets require the consent of the grantor of such rights, which in certain instances is a governmental entity. Our general partner is continuing to obtain these consents.

We believe that we have satisfactory title to all of our assets. Although title to such properties is subject to encumbrances in certain cases, such as customary interests generally retained in connection with acquisition of real property, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens and minor easements, restrictions and other encumbrances to which the underlying properties were subject at the time of acquisition by our predecessor or us, we believe that none of these burdens will materially interfere with their use in the operation of our business.

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Item 3. Legal Proceedings.

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

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

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

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

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

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The lead plaintiff obtained an extension to file its consolidated amended complaint until May 4, 2009; defendants have 60 days from that date to answer or otherwise respond to the complaint.

We intend to vigorously defend these actions. There can be no assurance regarding the outcome of the litigation. An estimate of possible loss, if any, or the range of loss cannot be made and therefore we have not accrued a loss contingency related to these actions. However, the ultimate resolution of these actions could have a material adverse effect on our business, financial condition, results of operations, cash flows, ability to make distributions to our unitholders, the trading price of the our common units and our ability to conduct our business.

The Unsecured Creditors Committee filed an adversary proceeding in connection with the Bankruptcy Cases against Thomas L. Kivisto, Gregory C. Wallace, and Westback. In that proceeding, filed February 18, 2009, the Unsecured Creditors Committee asserted various claims against the defendants on behalf of the Private Company’s bankruptcy estate, including claims based upon theories of fraudulent transfer, breach of fiduciary duties, waste, breach of contract, and unjust enrichment. On June 8, 2009, the Unsecured Creditors Committee filed a Second Amended Complaint asserting additional claims against Kevin L. Foxx and Alex G. Stallings, among others, based upon certain findings and recommendations in the Examiner’s Report (see “Item 1. Business—Impact of the Bankruptcy of the Private Company and Certain of its Subsidiaries and Related Events—Examiner”). The claims against Mr. Foxx are based upon theories of fraudulent transfer, unjust enrichment, and breach of fiduciary duty with respect to certain bonus payments received from the Private Company, and other claims of breach of fiduciary duty and breach of contract are also alleged against Messrs. Foxx and Stallings in the amended complaint. Messrs. Foxx and Stallings have informed us that they intend to vigorously defend these claims.

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

Item 4. Submission of Matters to a Vote of Security Holders.

None.

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PART II

Item 5.

Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.

Our common units began trading on Nasdaq under the symbol “SGLP” on July 18, 2007 at an initial public offering price of $22.00 per common unit. Effective at the opening of business on February 20, 2009, trading in our common units was suspended on Nasdaq due to our failure to timely file our periodic reports with the SEC, and our common units were subsequently delisted from Nasdaq. Our common units are currently traded on the Pink Sheets, which is an over-the-counter securities market, under the symbol SGLP.PK.

On June 26, 2009, there were 21,557,309 common units outstanding, held by approximately 21 unitholders of record of our common units. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record. We have also issued 12,570,504 subordinated units, for which there is no established public trading market. The subordinated units are held by one record holder, SemGroup Holdings.

The following table shows the high and low sales prices per common unit, as reported by Nasdaq and distributions declared by quarter since the initial public offering of our common units in July 2007.


	Low		High		Cash Distribution per Unit
2007:
Third Quarter(1)	$	24.16	$	31.00	$	0.24(2)
Fourth Quarter		24.02		30.50		0.3375

2008:
First Quarter		22.20		29.09		0.40
Second Quarter		24.50		28.00	No Distribution(3)
Third Quarter		3.17		29.50	No Distribution(3)
Fourth Quarter		0.87		6.99	No Distribution(3)

(1)	For the period from July 18, 2007, the day our common units began trading on Nasdaq, through September 30, 2007.

(2)	Reflects the pro rata portion of the $0.3125 minimum quarterly distribution per unit for the period from the July 23, 2007 closing of our initial public offering through September 30, 2007.

(3)

Distributions of Available Cash

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date.

Available cash, for any quarter, consists of all cash on hand at the end of that quarter:

•

less the amount of cash reserves established by our general partner to:

•

provide for the proper conduct of our business;

•

comply with applicable law, any of our debt instruments or other agreements; or

•

provide funds for distributions to our unitholders for any one or more of the next four quarters;

•

plus all additional cash and cash equivalents on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within 12 months.

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Our partnership agreement provides that, during the subordination period, which we are currently in, our common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.3125 per common unit per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. We did not make a distribution to our common unitholders, subordinated unitholders or general partner attributable to the results of operations for the quarters ended June 30, 2008, September 30, 2008, December 31, 2008 or March 31, 2009 due to the events of default under our credit agreement and the uncertainty of our future cash flows relating to the Bankruptcy Filings. After giving effect to the nonpayment of distributions for the quarters ended June 30, 2008, September 30, 2008, December 31, 2008 and March 31, 2009, each common unit was entitled to an arrearage of $1.25, or total arrearages for all common units of $26.9 million based upon 21,557,309 common units outstanding as of June 26, 2009. In addition, we do not currently expect to make a distribution relating to the second quarter of 2009. Pursuant to the Credit Agreement Amendment, we are prohibited from making distributions to our unitholders if our leverage ratio (as defined in the credit agreement) exceeds 3.50 to 1.00. As of December 31, 2008 and March 31, 2009, our leverage ratio was 4.86 to 1.00 and 5.28 to 1.00, respectively. If our leverage ratio does not improve, we may not make quarterly distributions to our unitholders in the future.

In addition, in the event we are not prohibited under our credit facility from paying distributions, the amount of distributions paid under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. The board of directors of our general partner will have broad discretion to establish cash reserves for the proper conduct of our business and for future distributions to our unitholders, and the establishment of those reserves could result in a reduction in cash distributions to our unitholders.

General Partner Interest and Incentive Distribution Rights.

Upon the closing of our initial public offering, SemGroup Holdings received 12,570,504 subordinated units. During the subordination period, the common units have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.3125 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” units because for a period of time, referred to as the subordination period, the subordinated units are not entitled to receive any distributions until the common units have received the minimum quarterly distribution and any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units.

The subordination period will extend until the first day of any quarter beginning after June 30, 2010 that each of the following tests are met:

distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

the “adjusted operating surplus” (as defined in our partnership agreement) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the general partner units during those periods; and

·	there are no arrearages in payment of the minimum quarterly distribution on the common units. If the unitholders remove the general partner without cause, the subordination period may end before June 30, 2010.

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The subordination period will automatically terminate and all of the subordinated units will convert into common units on a one-for-one basis if each of the following occurs:

·	distributions of available cash from operating surplus on each outstanding common unit and subordinated unit equaled or exceeded $1.88 (150% of the annualized minimum quarterly distribution) for any four-quarter period immediately preceding that date;

the “adjusted operating surplus” (as defined in our partnership agreement) generated during any four-quarter period immediately preceding that date equaled or exceeded the sum of $1.88 (150% of the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units and general partner units on a fully diluted basis; and

·	there are no arrearages in payment of the minimum quarterly distribution on the common units.

We will make distributions of available cash (as defined in its partnership agreement) from operating surplus for any quarter during any subordination period in the following manner:

·	first, 98% to the holders of common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.3125 plus any arrearages from prior quarters;

·	second, 98% to the holders of subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.3125;

·	third, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder has received a distribution of $0.3594;

·	fourth, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder has received a distribution of $0.3906;

·	fifth, 75% to all unitholders, pro rata, and 25% to the general partner, until each unitholder has received a distribution of $0.4688; and

·	thereafter, 50% to all unitholders, pro rata, and 50% to the general partner.

The maximum distribution of 50% to our general partner includes distributions paid to our general partner in respect of its 2% general partner interest and assumes that our general partner maintains its general partner interest at 2%. The maximum distribution of 50% does not include any distributions that our general partner may receive on common or subordinated units that it owns.

For equity compensation plan information, see “Item 12—Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.”

Item 6. Selected Financial Data.

The following table shows selected historical financial and operating data of SemGroup Energy Partners, L.P. Predecessor, our predecessor, and historical financial and operating data of SemGroup Energy Partners, L.P. for the periods and as of the dates presented. In connection with the closing of our initial public offering, the Private Company contributed certain crude oil gathering, transportation, terminalling and storage assets to us in connection with our initial public offering, which we refer to as the Crude Oil Business. The Crude Oil Business had historically been a part of the integrated operations of the Private Company, and neither the Private Company nor our predecessor recorded revenue associated with the gathering, transportation, terminalling and storage services provided on an intercompany basis. The Private Company and our predecessor recognized only the costs associated with providing such services. Accordingly, revenues reflected in the historical financial statements of our predecessor represent services provided to third parties and do not include any revenues for services provided to the Private Company. In addition, our results of operations for the year ended December 31, 2008 were affected by the Bankruptcy Filings and related events, which resulted in decreased revenues and increased expenses (see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation —Impact of the Bankruptcy of the Private Company and Certain of its Subsidiaries and Related Events—Our Revenues,” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Impact of the Bankruptcy of the Private Company and Certain of its Subsidiaries and Related Events—Our Expenses,” respectively).

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Due to the events related to the Bankruptcy Filings, including uncertainties related to future revenues and cash flows, we do not expect our financial results for the year ended December 31, 2008 to be indicative of our future financial results. Since the Bankruptcy Filings, the volumes being terminalled, stored, transported and gathered have decreased as compared to periods prior to the Bankruptcy Filings, which has negatively impacted total revenues. As an example, fourth quarter 2008 total revenues are approximately $9.5 million (or approximately 19%) less than second quarter 2008 total revenues, in each case excluding fuel surcharge revenues related to fuel and power consumed to operate our liquid asphalt cement storage tanks. Our future total revenues will be further impacted because, pursuant to the Settlement, the Private Company rejected the Terminalling Agreement and the Throughput Agreement (see “Item 1. Business—Impact of the Bankruptcy of the Private Company and Certain of its Subsidiaries and Related Events—Settlement with the Private Company”). We have entered into crude oil storage and transportation agreements and asphalt leases and storage agreements with third parties, but the revenues received from such agreements are less than the revenues received from the Private Company pursuant to the Terminalling Agreement and the Throughput Agreement. In addition, we have experienced increased expenses since the Bankruptcy Filings, including increased general and administrative expenses related to the costs of legal and financial advisors and increased interest expense related to the events of default under our credit facility, the associated Forbearance Agreement and amendments thereto and the Credit Agreement Amendment. For these reasons and due to the other factors described in “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operation—Overview—Items Impacting the Comparability of Our Financial Results,” our results of operations are not comparable to our predecessor’s historical results and our historical results may not be indicative of our future results.

We derived the information in the following table from, and that information should be read together with and is qualified in its entirety by reference to, the historical financial statements and the accompanying notes included elsewhere in this annual report. The table should be read together with “Item 1— Business” and “Item 7— Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	Year Ended December 31,
	2004			2005			2006			2007(1)			2008
	(in thousands, except per unit data)
Statement of Operations Data:
Service revenues:
Third party revenue	$	15,857		$	20,361		$	28,839		$	28,303		$	48,295
Related party revenue		—			—			—			46,262			143,885
Total revenue		15,857			20,361			28,839			74,565			192,180
Expenses:
Operating		30,996			38,467			51,608			67,182			103,510
Allowance for doubtful accounts		—			—			—			—			568
General and administrative		7,570			6,280			11,097			13,595			43,085
Total expenses		38,566			44,747			62,705			80,777			147,163
Operating income (loss)		(22,709	)		(24,386	)		(33,866	)		(6,212	)		45,017
Interest expense(2)		1,973			2,597			1,989			6,560			26,951
Income (loss) before income taxes		(24,682	)		(26,983	)		(35,855	)		(12,772	)		18,066
Provision for income taxes		—			—			—			141			291
Net income (loss)	$	(24,682	)	$	(26,983	)	$	(35,855	)	$	(12,913	)	$	17,775
General partner interest in net income										$	264		$	3,334
Limited partner interest in net income										$	12,941		$	14,441
Basic and diluted net income per limited partner unit:
Common units										$	0.55		$	0.46
Subordinated units										$	0.40		$	0.46
Cash distributions per unit to limited partners:(3)
Paid										$	0.24		$	0.74
Declared										$	0.58		$	0.40

Balance Sheet Data (at period end):
Property, plant and equipment, net	$	49,601		$	64,688		$	92,245		$	102,239		$	284,489
Total assets		57,739			72,912			104,847			125,482			354,641
Long-term debt and capital lease obligations		35,337			38,849			36,757			91,959			449,221
Total division equity/partners’ capital (deficit)		20,198			28,799			62,146			17,229			(126,643	)

(1)	Net income and net income per unit is presented for the period from July 20, 2007 through December 31, 2007.
(2)	Interest expense before July 20, 2007 reflects interest on capital lease obligations and debt payable to the Private Company. Interest expense after July 20, 2007 includes interest expense incurred under our credit facility.
(3)	Cash distributions paid per unit to limited partners represent payments made per unit during the period stated. Cash distributions declared per unit to limited partners represent distributions declared per unit for the quarters within the period stated. Declared distributions were paid within 45 days following the close of each quarter.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.

On July 23, 2007, we completed our initial public offering of common units. In our initial public offering, an aggregate of 14,375,000 common units (including 1,875,000 common units sold pursuant to the full exercise by the underwriters of their over-allotment option) were sold to the public at a price of $22.00 per unit. Upon completion of our initial public offering, we had 14,375,000 common units, 12,570,504 subordinated units and 549,908 general partner units outstanding. The subordinated units and membership interests in our general partner units are owned by SemGroup Holdings. Our general partner units are owned by our general partner.

The historical financial statements for periods prior to the contribution of the assets, liabilities and operations to us by the Private Company on July 20, 2007 reflect the assets, liabilities and operations of our predecessor. The following discussion analyzes the historical financial condition and results of operations of us and our predecessor and should be read in conjunction with our financial statements and notes thereto. In certain circumstances and for ease of reading we discuss the financial results of our predecessor as being “our” financial results during historical periods when this business was owned by the Private Company.

Overview

We are a publicly traded master limited partnership with operations in twenty-three states. We provide integrated terminalling, storage, gathering and transportation services for companies engaged in the production, distribution and marketing of crude oil and liquid asphalt cement. We manage our operations through three operating segments: (i) crude oil terminalling and storage services, (ii) crude oil gathering and transportation services and (iii) asphalt services. We were formed in February 2007 as a Delaware master limited partnership initially to own, operate and develop a diversified portfolio of complementary midstream energy assets.

In July 2007, we issued 12,500,000 common units, representing limited partner interests, and 12,570,504 subordinated units, representing additional limited partner interests, to SemGroup Holdings, and 549,908 general partner units representing a 2% general partner interest to SemGroup Energy Partners G.P., L.L.C., our general partner. SemGroup Holdings then completed a public offering of 12,500,000 common units at a price of $22 per unit. In addition, we issued an additional 1,875,000 common units to the public pursuant to the underwriters’ exercise of their over-allotment option. We did not receive any proceeds from the common units sold by SemGroup Holdings. We received net proceeds of approximately $38.7 million after deducting underwriting discounts from the sale of common units in connection with the exercise of the underwriters’ over-allotment option. We used these net proceeds to reduce outstanding borrowings under our credit facility. In connection with our initial public offering, we entered into the Throughput Agreement with the Private Company under which we provided crude oil gathering and transportation and terminalling and storage services to the Private Company.

On February 20, 2008, we purchased the Acquired Asphalt Assets, consisting of land, receiving infrastructure, storage tanks, machinery, pumps and piping at 46 liquid asphalt cement and residual fuel oil terminalling and storage facilities (from the Private Company for aggregate consideration of $379.5 million, including $0.7 million of acquisition-related costs. For accounting purposes, the acquisition has been reflected as a purchase of assets, with the Acquired Asphalt Assets recorded at the historical cost of the Private Company, which was approximately $145.5 million, with the additional purchase price of $234.0 million reflected in the statement of changes in partners’ capital as a distribution to the Private Company. In conjunction with the purchase of the Acquired Asphalt Assets, we amended our existing credit facility, increasing our borrowing capacity to $600 million. Concurrently, we issued 6,000,000 common units in an underwritten public offering, receiving proceeds, net of underwriting discounts and offering-related costs, of $137.2 million. Our general partner also made a capital contribution of $2.9 million to maintain its 2.0% general partner interest in us. On March 5, 2008, we issued an additional 900,000 common units in an underwritten public offering, receiving proceeds, net of underwriting discounts, of $20.6 million, in connection with the underwriters’ exercise of their over-allotment option in full. Our general partner made a corresponding capital contribution of $0.4 million to maintain its 2.0% general partner interest in us. In connection with the acquisition of the Acquired Asphalt Assets, we entered into the Terminalling Agreement with the Private Company and certain of its subsidiaries under which we provided liquid asphalt cement terminalling and storage and throughput services to the Private Company and the Private Company agreed to use our services at certain minimum levels. Our general partner’s Board approved the acquisition of the Acquired Asphalt Assets as well as the terms of the related agreements based on a recommendation from its conflicts committee, which consisted entirely of independent directors. The conflicts committee retained independent legal and financial advisors to assist it in evaluating the transaction and considered a number of factors in approving the acquisition, including an opinion from the committee’s independent financial advisor that the consideration paid for the Acquired Asphalt Assets was fair, from a financial point of view, to us.

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On May 12, 2008, we purchased the Acquired Pipeline Assets consisting of the Eagle North Pipeline System, a 130-mile, 8-inch pipeline that originates in Ardmore, Oklahoma and terminates in Drumright, Oklahoma as well as other real and personal property related to the pipeline from the Private Company for aggregate consideration of $45.1 million, including $0.1 million of acquisition-related costs. The acquisition was funded with borrowings under our revolving credit facility. We have suspended capital expenditures on this pipeline due to the continuing impact of the Bankruptcy Filings. Management currently intends to put the asset into service in early 2010 and is exploring various alternatives to complete the project. The Board approved the acquisition of the Acquired Pipeline Assets based on a recommendation from its conflicts committee, which consisted entirely of independent directors. The conflicts committee retained independent legal and financial advisors to assist it in evaluating the transaction and considered a number of factors in approving the acquisition, including an opinion from the committee’s independent financial advisor that the consideration paid for the Acquired Pipeline Assets was fair, from a financial point of view, to us.

On May 30, 2008, we purchased the Acquired Storage Assets consisting of certain land, crude oil storage and terminalling facilities with an aggregate of approximately 2.0 million barrels of storage capacity and related assets located at the Cushing Interchange from the Private Company and we assumed a take-or-pay, fee-based, third party contract with a term through August 2010 relating to the 2.0 million barrels of storage capacity for aggregate consideration of $90.3 million, including $0.3 million of acquisition-related costs. The acquisition was funded with borrowings under our revolving credit facility. The Board approved the acquisition of the Acquired Storage Assets based on a recommendation from its conflicts committee, which consisted entirely of independent directors. The conflicts committee retained independent legal and financial advisors to assist it in evaluating the transaction and considered a number of factors in approving the acquisition, including an opinion from the committee’s independent financial advisor that the consideration paid for the Acquired Storage Assets was fair, from a financial point of view, to us.

Impact of the Bankruptcy of the Private Company and Certain of its Subsidiaries and Related Events

The Private Company made the Bankruptcy Filings on July 22, 2008. The Bankruptcy Filings and the events related thereto have had a significant impact upon our business and results of operations. These items include, among others: (i) the reconstitution of our Board and management in connection with the Change of Control, (ii) the events of default that were triggered under our credit facility, the corresponding Forbearance Agreement amendments thereto and the Credit Agreement Amendment that we entered into in order to waive such events of default, (iii) the uncertainty relating to and the rebuilding of our business to provide services to and derive revenues from third parties instead of relying upon the Private Company for substantially all of our revenues, (iv) the hiring of certain operational employees in connection with the Settlement and the rejection of the Amended Omnibus Agreement, (v) becoming a party to securities and other litigation as well as governmental investigations, (vi) being delisted from Nasdaq, (vii) failing to make distributions for the second, third and fourth quarters of 2008 and the first quarter of 2009, (viii) experiencing increased general and administrative expenses due to the costs related to legal and financial advisors as well as other related costs, (ix) experiencing increased interest expense as a result of the forbearance agreements and amendments to our credit facility and (x) the entering into the Settlement with the Private Company. Certain of these items are discussed in more detail below. In addition, please see “Item 1. Business—Impact of the Bankruptcy of the Private Company and Certain of its Subsidiaries and Related Events” for a further discussion of the impact of the Bankruptcy Filings upon our business.

Our Revenues

For the year ended December 31, 2008, we derived approximately 73% of our revenues, excluding fuel surcharge revenues related to fuel and power consumed to operate our liquid asphalt cement storage tanks, from services we provided to the Private Company and its subsidiaries. Prior to the Order and the Settlement, the Private Company was obligated to pay us minimum monthly fees totaling $76.1 million annually and $58.9 million annually in respect of the minimum commitments under the Throughput Agreement and the Terminalling Agreement, respectively, regardless of whether such services were actually utilized by the Private Company. As described above, the Order required the Private Company to make certain payments under the Throughput Agreement and Terminalling Agreement during a portion of the third and fourth quarters of 2008, including the contractual minimum payments under the Terminalling Agreement. In connection with the Settlement, we waived the fees due under the Terminalling Agreement during March 2009. In addition, the Private Company rejected the Throughput Agreement and the Terminalling Agreement and we and the Private Company entered into the New Throughput Agreement and the New Terminalling Agreement. We expect revenues from services provided to the Private Company under the New Throughput Agreement and New Terminalling Agreement to be substantially less than prior revenues from services provided to the Private Company as the new agreements are based upon actual volumes gathered, transported, terminalled and stored instead of certain minimum volumes and are at reduced rates when compared to the Throughput Agreement and Terminalling Agreement. Also in connection with the Settlement, the Private Company transferred certain asphalt assets to us that were connected to our existing asphalt assets. The transfer of the Private Company’s asphalt assets in connection with the Settlement provides us with outbound logistics for our existing asphalt assets and, therefore, allows us to provide asphalt services for third parties.

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We have been pursuing opportunities to provide crude oil terminalling and storage services, crude oil gathering and transportation services and asphalt services to third parties.

As a result of new crude oil third-party storage contracts, we increased our third-party crude oil terminalling and storage revenue from approximately $1.0 million, or approximately 10% of total terminalling and storage revenue during the second quarter of 2008, to approximately $4.6 million, $8.4 million and $10.2 million, or approximately 41%, 83% and 88% of total terminalling and storage revenue for the third quarter of 2008, the fourth quarter of 2008 and the first quarter of 2009, respectively.

The significant majority of the increase in third party revenues results from an increase in third-party crude oil services provided and a corresponding decrease in the Private Company’s crude oil services provided due to the termination of the monthly contract minimum revenues under the Throughput Agreement in September 2008. Average rates for the new third-party crude oil terminalling and storage and transportation and gathering contracts are comparable with those previously received from the Private Company. However, the volumes being terminalled, stored, transported and gathered have decreased as compared to periods prior to the Bankruptcy Filings, which has negatively impacted total revenues. As an example, fourth quarter 2008 total revenues are approximately $9.5 million (or approximately 19%) less than second quarter 2008 total revenues, in each case excluding fuel surcharge revenues related to fuel and power consumed to operate our liquid asphalt cement storage tanks.

We are continuing to pursue additional contracts with third parties; however, these additional efforts may not be successful. In addition, certain third parties may be less likely to enter into business transactions with us due to the Bankruptcy Filings. The Private Company may also choose to curtail its operations or liquidate its assets as part of the Bankruptcy Cases. As a result, unless we are able to generate additional third party revenues, we will continue to experience lower volumes in our system which could have a material adverse effect on our results of operations and cash flows.

Our Expenses

Events related to the Bankruptcy Filings, the securities litigation and governmental investigations, and our efforts to enter into storage contracts with third party customers and pursue strategic opportunities has resulted in increased expenses beginning in the third quarter of 2008 due to the costs related to legal and financial advisors as well as other related costs. General and administrative expenses (exclusive of non-cash compensation expense related to the vesting of the units under the Plan as described in Note 14 to our Consolidated Financial Statements) increased by approximately $6.9 million, $7.5 million and $5.7 million, or approximately 300%, 326% and 248%, to approximately $9.2 million for the third quarter of 2008, $9.8 million for the fourth quarter of 2008 and $8.0 million for the first quarter of 2009, respectively, compared to $2.3 million in the second quarter of 2008. We expect this increased level of general and administrative expenses to continue throughout 2009.

Our financial results as of December 31, 2008 reflect a $0.6 million allowance for doubtful accounts related to amounts due from third parties as of December 31, 2008. The allowance is related primarily to amounts due from third parties and was established as a result of certain third party customers netting amounts due them from the Private Company with amounts due to us. Also, due to the change of control of our general partner related to the Private Company’s liquidity issues, all outstanding awards under the Plan vested on July 18, 2008, resulting in an incremental $18.0 million in non-cash compensation expense for the twelve months ended December 31, 2008.

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In addition, we have experienced increased interest expenses and other costs due to the events of default that existed under our credit agreement and the entering into the Forbearance Agreement, the amendments thereto and the Credit Agreement Amendment. Please see “—Liquidity and Capital Resources” for a discussion of these agreements and the associated expenses.

We also may experience increased operational expenses as a result of directly employing individuals associated with our operations. Historically, we did not directly employ any persons responsible for managing or operating us or for providing services relating to day-to-day business affairs as these services were provided to us by the Private Company pursuant to the Amended Omnibus Agreement. In connection with the Settlement, the Private Company rejected the Amended Omnibus Agreement and we and the Private Company entered into the Shared Services Agreement and the Transition Services Agreement relating to the provision of such services. In addition, we now directly employ approximately 400 individuals associated with our crude oil and asphalt operations. The costs to directly employ these individuals as well as the costs under the Shared Services Agreement and the Transition Services Agreement may be higher than those previously paid by us under the Amended Omnibus Agreement, which could have a material adverse effect on our business, financial condition, results of operations, cash flows, ability to make distributions to our unitholders, the trading price of our common units and our ability to conduct our business.

Taxation as a Corporation

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Global Economic Conditions

Additional Items Impacting the Comparability of Our Financial Results

In addition to the impacts on our future results of operations described above, our future results of operations and cash flows may not be comparable to the historical results of operations for the periods presented below for our predecessor, for the reasons described below. The historical financial statements for periods prior to the contribution of the assets, liabilities and operations to us by the Private Company on July 20, 2007 reflect the assets, liabilities and operations of our predecessor.

·	There are differences in the way our predecessor recorded revenues and the way we record revenues.

Historically, a substantial portion of our revenues were derived from services provided to the crude oil purchasing, marketing and distribution operations of the Private Company pursuant to the Throughput Agreement. Under the Throughput Agreement, the Private Company paid us a fee for gathering, transportation, terminalling and storage services based on volume and throughput. In rendering these services, we did not take title to, or marketing responsibility for, the crude oil that we gathered, transported, terminalled or stored and, therefore, we had minimal direct exposure to changes in crude oil prices.

The Crude Oil Business had historically been a part of the integrated operations of the Private Company, and neither the Private Company nor our predecessor recorded revenue associated with the gathering, transportation, terminalling and storage services provided on an intercompany basis. The Private Company and our predecessor recognized only the costs associated with providing such services. As such, the revenues we received under the Throughput Agreement are not reflected in the historical financial statements of our predecessor.

Our predecessor recognized revenues from third parties for (1) crude oil storage services, (2) crude oil transportation services and (3) crude oil producer field services. Although a substantial majority of our revenues are derived from services provided to the Private Company, we also recognize revenue for gathering, transportation, terminalling and storage services provided to third parties.

·	There are differences in the way general and administrative expenses were allocated to our predecessor and the way we recognize general and administrative expenses.

General and administrative expenses include office personnel and benefit expenses, costs related to our administration facilities, and insurance, accounting and legal expenses, including costs allocated by the Private Company for centralized general and administrative services performed by the Private Company. Such costs were allocated to our predecessor based on the nature of the respective expenses and its proportionate share of the Private Company’s head count, compensation expense, net revenues or square footage as appropriate.

We were party to an Omnibus Agreement with the Private Company. The Omnibus Agreement was amended (the “Amended Omnibus Agreement”) in connection with the purchase of the Acquired Asphalt Assets to, among other things, increase the fixed administrative fee payable under such agreement from $5.0 million per year to $7.0 million per year. Pursuant to the Amended Omnibus Agreement, we were required to pay our general partner and the Private Company this fixed administrative fee for the provision by our general partner and the Private Company of various general and administrative services to us for three years following the acquisition of our asphalt assets. The events related to the Bankruptcy Filings terminated the Private Company’s obligations to provide services to us under the Amended Omnibus Agreement. The Private Company continued to provide such services to us until the effective date of the Settlement at which time the Private Company rejected the Amended Omnibus Agreement and we and the Private Company entered into the Shared Services Agreement and the Transition Services Agreement relating to the provision of such services (see “Item 1. Business—Impact of the Bankruptcy of the Private Company and Certain of its Subsidiaries and Related Events—Settlement with the Private Company”). For a more complete description of the Amended Omnibus Agreement, see “Item 13—Certain Relationships and Related Party Transactions, and Director Independence—Agreements Related to Our Acquisition of the Asphalt Assets —Amended Omnibus Agreement.”

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We incur incremental general and administrative expenses as a result of being a publicly traded limited partnership, including costs associated with annual and quarterly reports to unitholders, financial statement audit, tax return and Schedule K-1 preparation and distribution, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. These incremental general and administrative expenditures are not reflected in the historical financial statements of our predecessor.

·	With the exception of capital lease obligations and prepaid insurance, no working capital was contributed to us in connection with our initial public offering.

Our predecessor had $31.2 million in debt payable to the Private Company which was not assumed by us in our initial public offering. We entered into a $250.0 million five-year credit facility and borrowed $137.5 million under that facility and used net proceeds of approximately $38.7 million from the issuance of 1,875,000 common units pursuant to the underwriters’ exercise of their over-allotment option in our initial public offering to reduce outstanding borrowings under our credit facility. In connection with the purchase of our Acquired Asphalt Assets, we amended our credit facility to increase our borrowing capacity to $600.0 million. This borrowing capacity has subsequently been reduced as described in “—Liquidity and Capital Resources.”

Factors That Will Significantly Affect Our Results

Commodity Prices. Although our current operations have minimal direct exposure to commodity prices, the volumes of crude oil and liquid asphalt cement we gather, transport, terminal or store are indirectly affected by commodity prices. Petroleum product prices may be contango (future prices higher than current prices) or backwardated (future prices lower than current prices) depending on market expectations for future supply and demand. Our terminalling and storage services benefit most from an increasing price environment, when a premium is placed on storage, and our gathering and transportation services benefit most from a declining price environment when a premium is placed on prompt delivery.

Volumes. Our results of operations are dependent upon the volumes of crude oil we gather, transport, terminal and store and asphalt we terminal, store and/or process. Our results of operations are impacted by our ability to utilize our pipeline and storage capacity to transport and store supplies of crude oil for our customers. An increase or decrease in the production of crude oil from the oil fields served by our pipelines or an increase or decrease in the demand for crude oil in the areas served by our pipelines and storage facilities will have a corresponding effect on the volumes we gather, transport, terminal and store. The production and demand for crude oil and liquid asphalt cement are driven by many factors, including the price for crude oil.

Acquisition Activities. Prior to the Bankruptcy Filings, our strategy was to pursue both strategic and accretive acquisitions within the midstream industry. If we are able to stabilize our business, we may be able to again pursue this strategy. These acquisition efforts may involve assets that, if acquired, would have a material effect on our financial condition and results of operations. We can give no assurance that any such acquisition efforts will be successful or that any such acquisition will be completed on terms considered favorable to us.

Organic Expansion Activities. Prior to the Bankruptcy Filings, our strategy was to pursue opportunities to expand our existing asset base and consider constructing additional assets in strategic locations. If we are able to stabilize our business, we may be able to again pursue this strategy. The construction of additions or modifications to our existing assets, and the construction of new assets, involve numerous regulatory, environmental, political, legal and operational uncertainties beyond our control and may require the expenditure of significant amounts of capital.

Credit Facility Restrictions. We expect that for the foreseeable future, substantially all of our cash generated from operations will be used to reduce our debt. Among other things, our credit facility, as amended by the Credit Agreement Amendment, requires us to make (i) minimum quarterly amortization payments on March 31, 2010 in the amount of $2.0 million, June 30, 2010 in the amount of $2.0 million, September 30, 2010 in the amount of $2.5 million, December 31, 2010 in the amount of $2.5 million and March 31, 2011 in the amount of $2.5 million, (ii) mandatory prepayments of amounts outstanding under the revolving credit facility (with no commitment reduction) whenever cash on hand exceeds $15.0 million, (iii) mandatory prepayments with 100% of asset sale proceeds, (iv) mandatory prepayment with 50% of the proceeds raised through equity sales and (v) annual prepayments with 50% of excess cash flow (as defined in the Credit Agreement Amendment). Our credit facility, as amended by the Credit Agreement Amendment, prohibits us from making draws under the revolving credit facility if we would have more than $15.0 million of cash on hand after making the draw and applying the proceeds thereof. In addition, pursuant to the Credit Agreement Amendment, our revolving credit facility is limited to $50.0 million. These restrictions may prevent us making capital expenditures or growing our business. Furthermore, our credit facility, as amended by the Credit Agreement Amendment, requires us to comply with certain restrictive financial covenants, including minimum interest coverage ratios and maximum leverage ratios (see “—Liquidity and Capital Resources” and Note 8 to our Consolidated Financial Statements). Failure to comply with these covenants may result in an event of default under our credit facility and may have a material adverse impact on our ability to meet our capital requirements.

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Distributions to our Unitholders. Pursuant to the Credit Agreement Amendment, we are prohibited from making distributions to our unitholders if our leverage ratio (as defined in the credit agreement) exceeds 3.50 to 1.00. As of December 31, 2008 and March 31, 2009, our leverage ratio was 4.86 to 1.00 and 5.28 to 1.00, respectively. If our leverage ratio does not improve, we may not make quarterly distributions to our unitholders in the future. If we are permitted to make distributions to our unitholders under our credit facility, we expect that we will distribute to our unitholders most of the cash generated by our operations. In such a case, we expect that we will rely upon external financing sources, including commercial bank borrowings and other debt and equity issuances, to fund our acquisition and expansion capital expenditures, as well as our working capital needs.

Results of Operations

The following table and discussion is a summary of our results of operating for each of the years ended December 31, 2006, 2007 and 2008:

	Year Ended December 31,
	2006			2007			2008
	(in thousands)
Service revenues:
Crude oil terminalling and storage revenues:
Third party	$	8,345		$	7,857		$	13,877
Related party		730			16,894			28,089
Total crude oil terminalling and storage		9,075			24,751			41,966
Crude oil gathering and transportation revenues:
Third party		19,764			20,446			34,416
Related party		-			29,368			49,953
Total crude oil gathering and transportation		19,764			49,814			84,369
Asphalt services revenues:
Third party		-			-			2
Related party		-			-			65,843
Total asphalt services		-			-			65,845
Total revenues		28,839			74,565			192,180

Operating expenses:
Crude oil terminalling and storage		4,494			4,863			6,314
Crude oil gathering and transportation		47,114			62,319			65,438
Asphalt services		-			-			31,758
Allowance for doubtful accounts		-			-			568
Total operating expenses		51,608			67,182			104,078

General and administrative expenses		11,097			13,595			43,085

Operating income (loss)		(33,866	)		(6,212	)		45,017
Interest expense		1,989			6,560			26,951
Income tax expense		-			141			291
Net income (loss)	$	(35,855	)	$	(12,913	)	$	17,775

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Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Service revenues. Service revenues, including fuel surcharge revenues of $12.9 million in 2008 related to fuel and power consumed to operate our liquid asphalt cement storage tanks, were $192.2 million for the twelve months ended December 31, 2008 compared to $74.6 million for the twelve months ended December 31, 2007, an increase of $117.6 million, or 158%. Crude oil terminalling and storage revenues increased by $17.2 million to $42.0 million for the twelve months ended December 31, 2008 compared to $24.8 million for the twelve months ended December 31, 2007, primarily due to the fact that prior to our initial public offering in July of 2007 our predecessor accounted for only the costs of operating our assets and not the revenue associated with the services it provided to the Private Company on an intercompany basis. In connection with the Bankruptcy Filings, the Private Company rejected the Throughput Agreement, and we concurrently began to replace this business with services provided to third party customers. This resulted in a 77% increase in our third party crude oil terminalling and service revenues during the year ended December 31, 2008 as compared to the year ended December 31, 2007. In the first quarter of 2009, third parties accounted for 88% of our total crude oil terminalling and storage revenue of $11.6 million. We expect this increased amount of third party revenue to continue in the foreseeable future.

Our crude oil gathering and transportation services revenue increased by $34.6 million to $84.4 million for twelve months ended December 31, 2008 compared to $49.8 million for the twelve months ended December 31, 2007, primarily due to the fact that, prior to our initial public offering, our predecessor historically did not account for these services it provided on an intercompany basis. In connection with the Bankruptcy Filings, the Private Company rejected the Throughput Agreement, and we concurrently began to replace this business with services provided to third party customers. This resulted in a 68% increase in our third party crude oil gathering and transportation revenues during the year ended December 31, 2008 as compared to the year ended December 31, 2007. In the first quarter of 2009, third parties accounted for 93% of our total crude oil gathering and transportation revenue of $14.8 million. We expect this increased amount of third party revenue to continue in the foreseeable future.

We acquired our asphalt assets from the Private Company in February 2008 and in March 2009 in connection with the Settlement. Our asphalt services revenue was $65.8 million for twelve months ended December 31, 2008. All of this revenue was generated under the Terminalling Agreement.

Operating expenses. Operating expenses include salary and wage expenses and related taxes and depreciation and amortization expenses. Operating expenses increased by $36.9 million, or 55%, to $104.1 million for the twelve months ended December 31, 2008, including $12.9 million of fuel and power expense to operate our liquid asphalt cement storage tanks, compared to $67.2 million for the twelve months ended December 31, 2007. This increase was primarily due to our acquisition of our asphalt assets from the Private Company in February 2008, which accounted for $31.8 million of the $36.9 million increase. Crude oil terminalling and storage operating expenses increased by $1.4 million to $6.3 million for the twelve months ended December 31, 2008 compared to $4.9 million for the twelve months ended December 31, 2007 primarily as a result of depreciation expense related to the Acquired Storage Assets as well as depreciation related to crude oil storage assets placed in service in 2007 prior to our initial public offering. Our crude oil gathering and transportation operating expenses increased by $3.1 million to $65.4 million for the twelve months ended December 31, 2008 compared to $62.3 million for the twelve months ended December 31, 2007 due to both higher diesel fuel prices and growth in our operations.

As a result of our acquisition of the Acquired Asphalt Assets and the Acquired Storage Assets in 2008, our depreciation expense increased by $11.9 million to $21.0 million in 2008. Also, approximately $5.7 million of the increase in operating expenses related to increased compensation expense, with $3.5 million of the increased compensation expense resulting from the acquisition of our asphalt assets in 2008. The remaining increase in compensation expense is primarily attributed to growth in our crude oil gathering and transportation segment in 2008.

In addition, our fuel expenses related to our crude oil gathering and transportation segment increased by $2.1 million to $11.7 million as a result of increased utilization of our assets and rising diesel prices. We also experienced a $2.3 million increase in property tax expenses in 2008 due primarily to our acquisition of the Acquired Asphalt Assets.

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General and administrative expenses. General and administrative expenses increased by $29.5 million, or 217%, to $43.1 million for the twelve months ended December 31, 2008 compared to $13.6 million for the twelve months ended December 31, 2007. The increase was primarily the result of the impact of the Private Company’s Bankruptcy Filings. As a result of the change of control of our general partner that occurred in July of 2008, we recognized an incremental $18.0 million in non-cash compensation expense due to the vesting of all outstanding awards under the Plan. Furthermore, events related to the Bankruptcy Filings, the securities litigation and governmental investigations, and our efforts to enter into storage contracts with third party customers and pursue strategic opportunities has resulted in increased expense beginning in the third quarter of 2008 due to the costs related to legal and financial advisors as well as other related costs. These incremental costs accounted for $10.8 million of our increased general and administrative expenses in 2008. We expect this increased level of general and administrative expenses to continue throughout 2009.

Interest expense. Interest expense represents interest on capital lease obligations and long-term borrowings under our credit facility and the impact of our interest rate swap agreements. Interest expense increased by $20.4 million to $27.0 million for the twelve months ended December 31, 2008 compared to $6.6 million for the twelve months ended December 31, 2007. The increase was primarily due to an increase in the average long-term borrowings outstanding during the twelve months ended December 31, 2008 compared to the twelve months ended December 31, 2007, which accounted for approximately $23.7 million of the increase in interest expense, net of capitalized interest. The decrease in the average interest rate we incurred on our borrowings from 2007 to 2008 resulted in a $4.2 million decrease in interest expense for the twelve months ended December 31, 2008 compared to the twelve months ended December 31, 2007. Furthermore, interest expense associated with the events of default that existed under our credit agreement and the entering into the Forbearance Agreement and the amendments thereto accounted for approximately $3.5 million of an increase in interest expense for the twelve months ended December 31, 2008. In addition, the two interest rate swap agreements entered into during the third quarter of 2007 and the three additional interest rate swap agreements entered into in February 2008 resulted in $0.9 million in interest income for the twelve months ended December 31, 2008 compared to $2.2 million of interest expense for the twelve months ended December 31, 2007. Due to events related to the Bankruptcy Filings, all of these interest rate swap positions were terminated in the third quarter of 2008, and we have recorded a $1.5 million liability as of December 31, 2008 with respect to these positions.

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Service revenues. Service revenues were $74.6 million for the twelve months ended December 31, 2007 compared to $28.8 million for the twelve months ended December 31, 2006, an increase of $45.8 million, or 159%. Crude oil terminalling and storage revenues increased by $15.7 million to $24.8 million for the twelve months ended December 31, 2007 compared to $9.1 million for the twelve months ended December 31, 2006, primarily due to revenues generated under the Throughput Agreement subsequent to the closing of our initial public offering. Our predecessor historically did not account for these services which were provided on an intercompany basis.

Our crude oil gathering and transportation services revenue increased by $30.0 million to $49.8 million for twelve months ended December 31, 2007 compared to $19.8 million for the twelve months ended December 31, 2006, primarily due to revenues generated under the Throughput Agreement subsequent to the closing of our initial public offering. Our predecessor historically did not account for these services which were provided on an intercompany basis.

Operating expenses. Operating expenses include salary and wage expenses and related taxes and depreciation and amortization expenses. Operating expenses increased by $15.6 million, or 30%, to $67.2 million for the twelve months ended December 31, 2007 compared to $51.6 million for the twelve months ended December 31, 2006. Crude oil terminalling and storage operating expenses increased by $0.4 million to $4.9 million for the twelve months ended December 31, 2007 compared to $4.5 million for the twelve months ended December 31, 2006. Our crude oil gathering and transportation operating expenses increased by $15.2 million to $62.3 million for the twelve months ended December 31, 2007 compared to $47.1 million for the twelve months ended December 31, 2006.

Approximately $5.3 million of this increase in operating expenses was due to our acquisition of Big Tex Crude Oil Company (“Big Tex”) on June 30, 2006. Included in operating expenses for the twelve months ended December 31, 2007 is $1.6 million in costs associated with the clean up of a crude oil leak that occurred in the twelve months ended December 31, 2007 in relation to a thirty-five mile pipeline located in Conroe, Texas. This gathering line was sold by the Private Company on April 30, 2007, and we have no future obligations associated with the aforementioned leak because this gathering line was not part of the crude oil assets that were contributed to us in connection with our initial public offering. Our repair and maintenance expenses increased by $2.3 million to $8.2 million for the twelve months ended December 31, 2007 compared to $5.9 million for the twelve months ended December 31, 2006, of which $0.9 million related to the Big Tex acquisition. The additional increase in repair and maintenance expenses was due primarily to the timing of routine maintenance in our crude oil gathering and transportation segment.

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In addition, our fuel expenses increased by $2.0 million to $9.6 million for the twelve months ended December 31, 2007 compared to $7.6 million for the twelve months ended December 31, 2006, of which $0.6 million related to the Big Tex acquisition. The additional increase in our fuel costs is attributable to the increase in number of transport trucks we operated for the respective periods, the rising price of diesel fuel during the comparative periods and a fire at a refinery located in western Texas that resulted in our transporting 0.7 million barrels of crude oil to alternative locations which were a greater distance from the barrels’ respective points of origination than the refinery that normally receives those barrels. The Throughput Agreement provided for a fuel surcharge, recorded in revenue, which offsets increases in fuel expenses related to either rising diesel prices or force majeure events such as the refinery fire that impacted our operations during the twelve months ended December 31, 2007.

Compensation expense increased by $3.7 million to $22.9 million for the twelve months ended December 31, 2007 compared to $19.2 million for the twelve months ended December 31, 2006, of which $2.8 million related to the Big Tex acquisition. The remaining increase is attributable to the growth in our crude oil gathering and transportation segment. As a result of the growth in our property and equipment during this period, our insurance premiums increased by $0.5 million to $1.7 million for the twelve months ended December 31, 2007 compared to $1.2 million for the twelve months ended December 31, 2006. Furthermore, as a result of our increase in operating leases during this period, including the acquisition of Big Tex, our vehicle rent expense increased by $1.1 million to $1.5 million for the twelve months ended December 31, 2007 compared to $0.4 million for the twelve months ended December 31, 2006. Lastly, our third party transportation costs increased by $0.5 million to $0.7 million for the twelve months ended December 31, 2007 compared to $0.2 million for the twelve months ended December 31, 2006 primarily as a result of our utilization of third party transportation services to meet customer demand.

General and administrative expenses. General and administrative expenses increased by $2.5 million, or 23%, to $13.6 million for the twelve months ended December 31, 2007 compared to $11.1 million for the twelve months ended December 31, 2006. The increase was primarily the result of growth in our business, and was comprised of a $1.5 million increase in compensation expenses (including $1.2 million recognized during 2007 under our long-term incentive plan, which did not exist in 2006) and a $1.4 million increase in outside professional service costs attributed to our operating as a public company. This was partially offset by a $0.3 million decrease in travel and meeting expenses.

Interest expense. Interest expense represents interest on capital lease obligations and long-term borrowings under our revolving credit facility. Interest expense increased by $4.6 million to $6.6 million for the twelve months ended December 31, 2007 compared to $2.0 million for the twelve months ended December 31, 2006. The increase was primarily due to an increase in the average long-term borrowings during the twelve months ended December 31, 2007 compared to the twelve months ended December 31, 2006, which accounted for approximately $2.4 million of the total increase in interest expense, and is a reflection of borrowings under our new revolving credit facility. In addition, during the third quarter of 2007, we entered into two interest rate swap agreements, the fair value accounting for which resulted in $2.2 million in interest expense for the twelve months ended December 31, 2007.

Effects of Inflation

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

Off Balance Sheet Arrangements

We do not have any off-balance sheet financing arrangements.

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Liquidity and Capital Resources

Cash Flows and Capital Expenditures

Cash generated from operations and borrowings under our credit facility have historically been the primary sources of our liquidity. Due to the events related to the Bankruptcy Filings, including uncertainties related to future revenues and cash flows, we do not expect our historical cash flows to be indicative of our future financial cash flows. As of June 26, 2009, we had $421.9 million in outstanding borrowings under our credit facility (consisting of $21.9 million under our revolving credit facility and $400.0 million under our term loan facility) with an aggregate unused credit availability under our revolving credit facility of approximately $28.1 million and cash on hand of approximately $3.0 million. Pursuant to the Credit Agreement Amendment, our revolving credit facility is limited to $50.0 million. If we are unable to sustain our sources of revenue generation and reestablish our relationships within the credit markets, this cash position and availability under our credit facility may not be sufficient to operate our business over the long-term.

Historically, our predecessor’s sources of liquidity included cash generated from operations and funding from the Private Company. The following table summarizes our sources and uses of cash for the twelve months ended December 31, 2006, 2007 and 2008:

	Year Ended December 31,
	2006			2007			2008
	(in millions)
Net cash provided by (used in) operating activities	$	(25.8	)	$	(0.6	)	$	56.0
Net cash used in investing activities		(41.3	)		(20.0	)		(520.3	)
Net cash provided by financing activities		67.1			21.0			492.7

Operating Activities Net cash provided by operating activities increased $56.6 million for the twelve months ended December 31, 2008 as compared to the twelve months ended December 31, 2007. The increase in net cash provided by operating activities is primarily due to a $30.7 million increase in our net income for the year ended December 31, 2008 compared to the year ended December 31, 2007 primarily as a result of revenues generated by services provided under the Throughput Agreement and the Terminalling Agreement, which have been rejected by the Private Company in connection with the Bankruptcy Cases. Prior to the Private Company’s contribution of Crude Oil Business to us, our predecessor did not record revenue associated with the gathering, transportation, terminalling and storage services provided on an intercompany basis. In addition, net cash provided by our operating activities was impacted by certain non-cash items, including a $11.9 million increase in depreciation and amortization and a $16.8 million increase in equity-based compensation. The increase was offset by a decrease in our interest rate swap liability of $2.2 million. Net cash used in operating activities was $0.6 million for the twelve months ended December 31, 2007 as compared to $25.8 million for the twelve months ended December 31, 2006. This decrease in net cash used in operating activities is primarily due to a $22.9 million decrease in our net loss for the twelve months ended December 31, 2007 compared to the twelve months ended December 31, 2006. In addition, our cash used in operating activities decreased in 2007 due to a $0.9 million increase in depreciation and amortization, an increase in our unrealized loss related to derivative instruments of $2.2 million, and an increase in equity-based incentive compensation expense of $1.2 million. The impact of the above increases was partially offset by an increase of $1.8 million in cash used related to changes in working capital.

Investing Activities. Net cash used in investing activities was $520.3 million for the twelve months ended December 31, 2008 compared to $20.0 million for the twelve months ended December 31, 2007. This increase is primarily attributable to the purchase of our Acquired Asphalt Assets in February 2008 for approximately $380 million, our purchase of our Acquired Storage Assets in May 2008 for approximately $90 million, and our purchase of our Acquired Pipeline Assets in May 2008 for approximately $45 million. Expansion capital expenditures for organic growth projects totaled $2.3 million in 2008 compared to $17.5 million in 2007. The 2007 expansion capital expenditures are primarily comprised of expenditures made by our predecessor for the construction of crude oil storage assets that are a part of our crude oil assets. We expect 2009 expansion capital expenditures for organic growth projects to be approximately $2 million to $5 million in 2009. Maintenance capital expenditures totaled $3.7 million in 2008 as compared to $2.7 million in 2007. The increase is primarily due to the maintenance of our Acquired Asphalt Assets, which we purchased in February 2008. We expect maintenance capital expenditures to be approximately $7 million in 2009. Net cash used in investing activities was $20.0 million for the twelve months ended December 31, 2007 as compared to $41.3 million for the twelve months ended December 31, 2006. This decrease was attributable to a reduction in capital expenditures primarily resulting from the timing of construction projects in our crude oil terminalling and storage segment. Capital expenditures for the years ended December 31, 2007 and 2006 were $20.4 million and $41.5 million, respectively, consisting of both our acquisition of Big Tex on June 30, 2006 and expenditures for the construction of additional crude oil storage capacity during these periods.

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Financing Activities. Net cash provided by financing activities was $492.7 million for the twelve months ended December 31, 2008 as compared to $21.0 million for the twelve months ended December 31, 2007. Net cash provided by financing activities for the twelve months ended December 31, 2008 is primarily comprised of the change in our net borrowings under our credit facility of $358.5 million and proceeds from the February 2008 public offering, net of offering fees, of $161.2 million, and is offset by distributions paid of $23.7 million for the twelve months ended December 31, 2008. Prior to our initial public offering our net cash provided by financing activities primarily comprised of capital contributions received from the Private Company. The capital contributions served to fund our working capital needs and both maintenance and expansion capital expenditure projects that are reflected in net cash used in investing activities for the twelve months ended December 31, 2007. Net cash provided by financing activities was $21.0 million for the twelve months ended December 31, 2007 as compared to $67.1 million for the twelve months ended December 31, 2006. This decrease was attributable to a reduction in capital expenditures primarily resulting from the timing of construction projects in our crude oil terminalling and storage segment. Net cash provided by financing activities is primarily comprised of capital contributions of $39.3 million and $69.2 million received by us from the Private Company for the years ended December 31, 2007 and 2006, respectively. The capital contributions served to fund our working capital needs and both maintenance and expansion capital expenditure projects that are reflected in net cash used in investing activities prior to our initial public offering in July 2007.

Our Liquidity and Capital Resources

Cash flow from operations and our credit facility are our primary sources of liquidity. At December 31, 2008, we had approximately $21.9 million of availability under our revolving credit facility. As of June 26, 2009, we had an aggregate unused credit availability under our revolving credit facility of approximately $28.1 million and cash on hand of approximately $3.0 million. Usage of our revolving credit facility is subject to ongoing compliance with covenants. If we are unable to sustain our sources of revenue generation and reestablish our relationships within the credit markets, this cash position and availability under our credit facility may not be sufficient to operate our business over the long-term. Historically, we have derived a substantial majority of our revenues from services provided to the Private Company, and as such, our liquidity was affected by the liquidity and credit risk of the Private Company. Due to the events related to the Bankruptcy Filings described herein, including the uncertainty relating to future cash flows, we face substantial doubt as to our ability to continue as a going concern.

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.

No assurance can be given that we will not be required to restrict our operations because of possible limitations on our ability to obtain financing for our maintenance capital expenditures and our expansion capital expenditures due to restrictions under our credit agreement and the uncertainty related to the Bankruptcy Filings.

Our Ability to Grow Depends on Our Ability to Access External Expansion Capital. Our partnership agreement provides that we distribute all of our available cash to our unitholders. Available cash is reduced by cash reserves established by our general partner to provide for the proper conduct of our business (including for future capital expenditures) and to comply with the provisions of our credit facility. Pursuant to the Credit Agreement Amendment, we are prohibited from making distributions to our unitholders if our leverage ratio (as defined in the credit agreement) exceeds 3.50 to 1.00. As of December 31, 2008 and March 31, 2009, our leverage ratio was 4.86 to 1.00 and 5.28 to 1.00, respectively. As discussed under “—Factors That Will Significantly Affect our Results—Credit Facility Restrictions,” we expect that for the foreseeable future, substantially all of our cash generated from operations will be used to reduce our debt. In the event that we are again able to pay distributions, 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.

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We do not expect to make significant acquisitions or expansion capital expenditures in the near term. We currently intend to put the Acquired Pipeline Assets into service in early 2010, and we expect to make capital expenditures related to this project during 2009. Capital expenditures are limited under our credit agreement to $12.5 million in 2009, $8.0 million in 2010 and $4.0 million in 2011. To the extent we are unable to finance growth externally and we are unwilling to establish cash reserves to fund future acquisitions, our cash distribution policy will significantly impair our ability to grow.

Description of Credit Facility. In July 2007 we entered into a $250.0 million five-year credit facility with a syndicate of financial institutions. In connection with our acquisition of our asphalt assets, we amended this credit facility to increase the total amount we may borrow to $600.0 million.

The credit facility is available for general partnership purposes, including working capital, capital expenditures, distributions and repayment of indebtedness that is assumed in connection with acquisitions. Due to events related to the Bankruptcy Filings, events of default occurred under our credit agreement. Effective on September 18, 2008, we and the requisite lenders under our credit facility entered into a Forbearance Agreement and Amendment to Credit Agreement (the “Forbearance Agreement”) under which the lenders agreed, subject to specified limitations and conditions, to forbear from exercising their rights and remedies arising from the defaults and events of default described therein for the period commencing on September 18, 2008 and ending on the earliest of (i) December 11, 2008, (ii) the occurrence of any default or event of default under the credit agreement other than certain defaults and events of default indicated in the Forbearance Agreement, or (iii) the failure of us to comply with any of the terms of the Forbearance Agreement (the “Forbearance Period”). On December 11, 2008, the lenders agreed to extend the Forbearance Period until December 18, 2008 pursuant to a First Amendment to Forbearance Agreement and Amendment to Credit Agreement (the “First Forbearance Amendment”), on December 18, 2008, the lenders agreed to extend the Forbearance Period until March 18, 2009 pursuant to a Second Amendment to Forbearance Agreement and Amendment to Credit Agreement (the “Second Forbearance Amendment”), and on March 18, 2009, the lenders agreed to further extend the Forbearance Period until April 8, 2009 pursuant to a Third Amendment to Forbearance Agreement and Amendment to Credit Agreement (the “Third Forbearance Amendment”).

In connection with the Settlement, we, our subsidiaries that are guarantors of the obligations under the credit facility, Wachovia Bank, National Association, as Administrative Agent, and the requisite lenders under our credit agreement entered into the Consent, Waiver and Amendment to Credit Agreement (the “Credit Agreement Amendment”), dated as of April 7, 2009, under which, among other things, the lenders consented to the Settlement and waived all existing defaults and events of default described in the Forbearance Agreement and amendments thereto.

Prior to the execution of the Forbearance Agreement, the credit agreement was comprised of a $350 million revolving credit facility and a $250 million term loan facility. The Forbearance Agreement permanently reduced our revolving credit facility under the credit agreement from $350 million to $300 million and prohibited us from borrowing additional funds under our revolving credit facility during the Forbearance Period. Under the Forbearance Agreement, we agreed to pay the lenders executing the Forbearance Agreement a fee equal to 0.25% of the aggregate commitments under the credit agreement after giving effect to the above described commitment reduction. The Second Forbearance Amendment further permanently reduced our revolving credit facility under the credit agreement from $300 million to $220 million. In addition, under the Second Forbearance Amendment, we agreed to pay the lenders executing the Second Forbearance Amendment a fee equal to 0.375% of the aggregate commitments under the credit agreement after the above described commitment reduction. Under the Third Forbearance Amendment, we agreed to pay a fee equal to 0.25% of the aggregate commitments under the credit agreement after the above described commitment reduction. The amendments to the Forbearance Agreement prohibited us from borrowing additional funds under our revolving credit facility during the extended Forbearance Period.

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The Credit Agreement Amendment subsequently further permanently reduced our revolving credit facility under the credit agreement from $220 million to $50 million, and increased the term loan facility from $250 million to $400 million. Upon the execution of the Credit Agreement Amendment, $150 million of our outstanding revolving loans were converted to term loans and we became able to borrow additional funds under our revolving credit facility. Pursuant to the Credit Agreement Amendment, the credit facility and all obligations thereunder will mature on June 30, 2011. Under the Credit Agreement Amendment, we agreed to pay the lenders executing the Credit Agreement Amendment a fee equal to 2.00% of the aggregate commitments under the credit agreement after the above described commitment reduction, or $9.0 million, offset by the $1.2 million fee paid pursuant to the Third Forbearance Amendment. As of June 26, 2009, we had $421.9 million in outstanding borrowings under our credit facility (consisting of $21.9 million under our revolving credit facility and $400.0 million under our term loan facility) with an aggregate unused credit availability under our revolving credit facility of approximately $28.1 million and cash on hand of approximately $3.0 million. Pursuant to the Credit Agreement Amendment, our revolving credit facility is limited to $50.0 million. If any of the financial institutions that support our revolving credit facility were to fail, we may not be able to find a replacement lender, which could negatively impact our ability to borrow under our revolving credit facility. For instance, Lehman Brothers Commercial Bank is one of the lenders under our $50.0 million revolving credit facility, and Lehman Brothers Commercial Bank has agreed to fund approximately $2.5 million (approximately 5%) of the revolving credit facility. On several occasions Lehman Brothers Commercial Bank has failed to fund revolving loan requests under our revolving credit facility, effectively limiting the aggregate amount of our revolving credit facility to $47.5 million.

Prior to the events of default, indebtedness under the credit agreement bore interest at our option, at either (i) the higher of the administrative agent’s prime rate or the federal funds rate plus 0.5% (the “Base rate”), plus an applicable margin that ranges from 0.50% to 1.75%, depending on our total leverage ratio and senior secured leverage ratio, or (ii) LIBOR plus an applicable margin that ranges from 1.50% to 2.75%, depending upon our total leverage ratio and senior secured leverage ratio. During the Forbearance Period indebtedness under the credit agreement bore interest at our option, at either (i) the Base rate, plus an applicable margin that ranges from 2.75% to 3.75%, depending upon our total leverage ratio, or (ii) LIBOR plus an applicable margin that ranges from 4.25% to 5.25%, depending upon our total leverage ratio. Pursuant to the Second Forbearance Amendment, commencing on December 12, 2008, indebtedness under the credit agreement bore interest at our option, at either (i) the Base rate plus 5.0% per annum, with a Base rate floor of 4.0% per annum, or (ii) LIBOR plus 6.0% per annum, with a LIBOR floor of 3.0% per annum.

After giving effect to the Credit Agreement Amendment, amounts outstanding under our credit facility bear interest at either the LIBOR rate plus 6.50% per annum, with a LIBOR floor of 3.00%, or the Base rate plus 5.50% per annum, with a Base rate floor of 4.00% per annum. We now pay a fee of 1.50% per annum on unused commitments under our revolving credit facility. After giving effect to the Credit Agreement Amendment, interest on amounts outstanding under our credit facility must be paid monthly. Our credit facility, as amended by the Credit Agreement Amendment, now requires us to pay additional interest on October 6, 2009, April 6, 2010, October 6, 2010 and April 6, 2011, equal to the product of (i) the sum of the total amount of term loans then outstanding plus the aggregate commitments under the revolving credit facility and (ii) 0.50%, 0.50%, 1.00% and 1.00%, respectively.

During the twelve months ended December 31, 2008, the weighted average interest rate incurred by us was 6.45% resulting in interest expense of approximately $24.2 million. During the three months ended March 31, 2009, the weighted average interest rate incurred by us was 9.0% resulting in interest expense of approximately $10.0 million. We expect the interest expense we incur in 2009 to be substantially greater than the interest expense we incurred in 2008.

Among other things, our credit facility, as amended by the Credit Agreement Amendment, now requires us to make (i) minimum quarterly amortization payments on March 31, 2010 in the amount of $2.0 million, June 30, 2010 in the amount of $2.0 million, September 30, 2010 in the amount of $2.5 million, December 31, 2010 in the amount of $2.5 million and March 31, 2011 in the amount of $2.5 million, (ii) mandatory prepayments of amounts outstanding under the revolving credit facility (with no commitment reduction) whenever cash on hand exceeds $15.0 million, (iii) mandatory prepayments with 100% of asset sale proceeds, (iv) mandatory prepayment with 50% of the proceeds raised through equity sales and (v) annual prepayments with 50% of excess cash flow (as defined in the Credit Agreement Amendment). Our credit facility, as amended by the Credit Agreement Amendment, prohibits us from making draws under the revolving credit facility if we would have more than $15.0 million of cash on hand after making the draw and applying the proceeds thereof.

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Under the credit agreement, we are subject to certain limitations, including limitations on our ability to grant liens, incur additional indebtedness, engage in a merger, consolidation or dissolution, enter into transactions with affiliates, sell or otherwise dispose of our assets (other than the sale or other disposition of the assets of the asphalt business, provided that such disposition is at arm’s length to a non-affiliate for fair market value in exchange for cash and the proceeds of the disposition are used to pay down outstanding loans), businesses and operations, materially alter the character of our business, and make acquisitions, investments and capital expenditures. The credit agreement prohibits us from making distributions of available cash to our unitholders if any default or event of default (as defined in the credit agreement) exists. The credit agreement, as amended by the Credit Agreement Amendment, requires us to maintain a leverage ratio (the ratio of our consolidated funded indebtedness to our consolidated adjusted EBITDA, in each case as defined in the credit agreement), determined as of the last day of each month for the twelve month period ending on the date of determination, that ranges on a monthly basis from not more than 5.50 to 1.00 to not more than 9.75 to 1.00. In addition, pursuant to the Credit Agreement Amendment, our ability to make acquisitions and investments in unrestricted subsidiaries is limited and we may only make distributions if our leverage ratio is less than 3.50 to 1.00 and certain other conditions are met. As of December 31, 2008 and March 31, 2009, our leverage ratio was 4.86 to 1.00 and 5.28 to 1.00, respectively. If our leverage ratio does not improve, we may not make quarterly distributions to our unitholders in the future.

The credit agreement, as amended by the Credit Agreement Amendment, also requires us to maintain an interest coverage ratio (the ratio of our consolidated EBITDA to our consolidated interest expense, in each case as defined in the credit agreement) that ranges on a monthly basis from not less than 2.50 to 1.00 to not less than 1.00 to 1.00. As of December 31, 2008 and March 31, 2009, our interest coverage ratio was 3.58 to 1.00 and 2.64 to 1.00, respectively.

Further, under the Credit Agreement Amendment we are required to maintain a minimum monthly consolidated adjusted EBITDA for the prior twelve months ranging from $45.4 million to $82.9 million as determined at the end of each month. As of March 31, 2009, our consolidated adjusted EBITDA for the prior twelve months is approximately $84.9 million. Under the Credit Agreement Amendment, consolidated adjusted EBITDA generally means our consolidated net income for the prior twelve months, plus, to the extent deducted in determining net income, our interest expense, income taxes, depreciation, amortization, non-cash charges and restructuring charges for such period, minus, to the extent added in determining net income, our non-cash items of income for such period, all adjusted to take into account any material acquisitions or dispositions. In addition, our capital expenditures are limited under the Credit Agreement Amendment to $12.5 million in 2009, $8.0 million in 2010 and $4.0 million in the six months ending June 30, 2011. In the three months ended March 31, 2009, our capital expenditures were approximately $1.4 million.

The credit agreement specifies a number of events of default (many of which are subject to applicable cure periods), including, among others, failure to pay any principal when due or any interest or fees within three business days of the due date, failure to perform or otherwise comply with the covenants in the credit agreement, failure of any representation or warranty to be true and correct in any material respect, failure to pay debt, and other customary defaults. In addition, it is an event of default under our credit agreement if there is a change of control of us or our general partner. It is also an event of default under the credit agreement if we do not file our delinquent quarterly and annual reports with the SEC by September 30, 2009, unless we retain new auditors, in which case such deadline is extended to December 31, 2009. If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies, including taking available cash in our bank accounts. If an event of default exists and we are unable to obtain forbearance from our lenders or a waiver of the events of default under our credit agreement, we may be forced to sell assets, make a bankruptcy filing or take other action that could have a material adverse effect on our business, the price of our common units and our results of operations. We are also prohibited from making cash distributions to our unitholders while the events of default exist.

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Contractual Obligations. A summary of our contractual cash obligations over the next several fiscal years, as of December 31, 2008, is as follows:

	Payments Due by Period
Contractual Obligations	Total		Less than 1 year		1-3 years		4-5 years		More than 5 years
	(in millions)
Omnibus Agreement obligations(1)	$	-	$	-	$	-	$	-	$	-
Debt obligations(2)		548.9		40.3		508.6		-		-
Capital lease obligations		1.2		0.9		0.3		-		-
Operating lease obligations		12.3		3.8		7.9		0.5		0.1
Financial advisory obligations(3)		1.5		1.5		-		-		-
Employee contract obligations(4)		0.6		0.6		-		-		-

(1)

As of December 31, 2008, the Private Company still provided services to us under the Amended Omnibus Agreement and we still paid our general partner and the Private Company a fixed administrative fee, in the amount of $7.0 million per year, for the provision by our general partner and the Private Company of various general and administrative services pursuant to the Amended Omnibus Agreement. The events related to the Bankruptcy Filings terminated the Private Company’s obligations to provide services to us under the Amended Omnibus Agreement. The Private Company continued to provide such services to us until the effective date of the Settlement at which time the Private Company rejected the Amended Omnibus Agreement and we and the Private Company entered into the Shared Services Agreement and the Transition Services Agreement relating to the provision of such services (see “Item 1. Business—Impact of the Bankruptcy of the Private Company and Certain of its Subsidiaries and Related Events—Settlement with the Private Company”).

(2)

Represents required future principal repayments of borrowings and interest payments under our credit facility, all of which is variable rate debt. For purposes of calculating interest payments on our variable rate debt, the interest rate on our borrowing of 9.0% as of December 31, 2008 was used. All amounts outstanding under the credit facility mature in June 2011. The amounts included in this table do not reflect the effect of the Third Forbearance Amendment or the Credit Agreement Amendment, which were entered into after December 31, 2008. See Note 8 of the Notes to the Consolidated Financial Statements included in this annual report on Form 10-K.

(3)	Represents required future payments under a financial advisory services contract.

(4)	Represents required future payments to certain of our employees under retention agreements.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements. We prepared these financial statements in conformity with generally accepted accounting principles in the United States. As such, we are required to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented. We based our estimates on historical experience, available information and various other assumptions we believe to be reasonable under the circumstances. On an on-going basis, we evaluate our estimates; however, actual results may differ from these estimates under different assumptions or conditions. The accounting policies that we believe require our most difficult, subjective or complex judgments and are the most critical to our reporting of results of operations and financial position are as follows:

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires management to make estimates and assumptions that affect the reported amounts and disclosure of contingencies. We make significant estimates including: (1) allowance for doubtful accounts receivable; (2) estimated useful lives of assets, which impacts depreciation; (3) estimated cash flows and fair values inherent in impairment tests under SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”) and SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”); (4) estimated fair value of assets and liabilities acquired and identification of associated intangible assets; (5) accruals related to revenues and expenses; and (6) liability and contingency accruals. Although we believe these estimates are reasonable, actual results could differ from these estimates.

Property, Plant and Equipment. Property, plant and equipment are recorded at cost. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred. The carrying value of the assets is based on estimates, assumptions and judgments relative to useful lives and salvage values. As assets are disposed of or sold, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is included in other income in the statements of operations.

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We calculate depreciation using the straight-line method, based on estimated useful lives of our assets. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives and salvage values that we believe to be reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. The estimated useful lives of our asset groups are as follows:


Asset Group	Estimated Useful Lives (Years)
Land improvements		10-20
Pipelines and facilities		5-31
Storage and terminal facilities		10-35
Transportation equipment, injection stations		3-10
Office property and equipment and other		3-31

We capitalize certain costs directly related to the construction of assets, including interest and engineering costs. Upon disposition or retirement of property, plant and equipment, any gain or loss is included in other income in the statements of operations.

We have contractual obligations to perform dismantlement and removal activities in the event that some of our asphalt assets are abandoned. These obligations include varying levels of activity including completely removing the assets and returning the land to its original state. We have 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. In addition, it is not possible to predict when demands for our asphalt services will cease, and we do not believe that such demand will cease for the foreseeable future. Accordingly, we believe the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, we cannot reasonably estimate the fair value of the associated asset retirement obligations. We believe that if our 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. We will record asset retirement obligations for these assets in the period in which sufficient information becomes available for us to reasonably determine the settlement dates, and we will apply the provisions of SFAS No. 143, “Accounting for Asset Retirement Obligations.”

Impairment of Long-lived Assets. Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value in accordance with SFAS 144 as amended. Under SFAS 144, assets are tested for impairment when events or circumstances indicate that their carrying values may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows.

Fair Value of Assets and Liabilities Acquired and Identification of Associated Goodwill and Intangible Assets. In conjunction with each acquisition, we must allocate the cost of the acquired entity to the assets and liabilities assumed based on their estimated fair values at the date of acquisition. As additional information becomes available, we may adjust the original estimates within a short time subsequent to the acquisition. We are also required to recognize intangible assets separately from goodwill. Goodwill and intangible assets with indefinite lives are not amortized but instead are periodically assessed for impairment. The impairment testing entails estimating future net cash flows relating to the asset based on our estimate of market conditions including pricing, demand, competition, operating costs and other factors. Intangible assets with finite lives are amortized over the estimated useful life determined by management. Determining the fair value of assets and liabilities acquired, as well as intangible assets that relate to such items as customer relationships and contracts with suppliers, involves professional judgment and is ultimately based on acquisition models and our assessment of the value of the assets acquired and, to the extent available, third-party assessments. Uncertainties associated with these estimates include changes in production by producers and refiners, economic obsolescence factors in the area and potential future sources of cash flow. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.

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Allocation Methodologies Used to Derive Our Predecessor Financial Statements on a Carve-out Basis. Our predecessor employed various allocation methodologies to separate certain general and administrative expenses incurred by the Private Company and recorded in its financial statements presented herein. The Private Company provided to our predecessor centralized corporate functions such as legal, accounting, treasury, insurance administration, risk management, health, safety and environmental, information technology, human resources, credit, payroll, taxes and other corporate services and the use of facilities that support these functions. The allocation methodologies vary based on the nature of the charge and include, among other things, employee headcount, compensation expense, net revenues and square footage of facilities. Our predecessor’s management believes that the allocation methodologies used to allocate indirect costs to it are reasonable. If certain general and administrative expenses were allocated using different methodologies, our predecessor’s results of operations could have significantly differed from those presented herein.

Recent Accounting Pronouncements

In April 2009, the Financial and Accounting Standards Board (FASB) issued FASB Staff Position (FSP) Statement No. 107-1 and Accounting Principles Board (APB) 28-1 (collectively, FSP FAS 107-1), “Interim Disclosures about Fair Value of Financial Instruments.” FSP FAS 107-1 amends FAS 107, “Disclosures about Fair Value of Financial Instruments,” to require an entity to provide disclosures about fair value of financial instruments in interim financial information. The FSP FAS 107-1 also amends APB Opinion 28, “Interim Financial Reporting,” to require those disclosures in summarized financial information at interim reporting periods. Under FSP FAS 107-1, we will be required to include disclosures about the fair value of our financial instruments whenever we issue financial information for interim reporting periods. In addition, we will be required to disclose in the body or in the accompanying notes of our summarized financial information for interim reporting periods and in our financial statements for annual reporting periods the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position. FSP FAS 107-1 is effective for periods ending after June 15, 2009. We are currently evaluating the impact FSP FAS 107-1 may have on our consolidated financial statements.

In June 2008, the Emerging Issues Task Force (“EITF”) issued Issue No. 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities “ (“EITF 03-6-1”). EITF 03-6-1 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share (“EPS”) under the two-class method. EITF 03-6-1 will be effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. All prior-period EPS data presented will be adjusted retrospectively to conform with the provisions of EITF 03-6-1. We are evaluating the expected impact of adoption of EITF 03-6-1.

In April 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) No. FAS 142-3 “Determination of the Useful Life of Intangible Assets “ (“FSP No. FAS 142-3”). FSP No. FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets “ (“SFAS 142”). The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141 (revised 2007), “Business Combinations,” and other GAAP. This FSP will be effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. We are evaluating the expected impact; however, we believe adoption will not impact our financial position, results of operations or cash flows.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 133” (“SFAS No. 161”). This Statement requires enhanced disclosures about our derivative and hedging activities. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We will adopt SFAS No. 161 beginning January 1, 2009. With the adoption of this statement, we do not expect any significant impact on our financial position, results of operations or cash flows.

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In March 2008, the Emerging Issues Task Force (“EITF”) of the FASB reached a final consensus on Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“Issue No. 07-4”). This conclusion reached by the EITF affects how a master limited partnership (“MLP”) allocates income between its general partner, which typically holds incentive distribution rights (“IDRs”) along with the general partner interest, and the limited partners. It is not uncommon for MLPs to experience timing differences between the recognition of income and partnership distributions. The amount of incentive distribution is typically calculated based on the amount of distributions paid to the MLP’s partners. The issue is whether current period earnings of an MLP should be allocated to the holders of IDRs as well as the holders of the general and limited partnership interests when applying the two-class method under SFAS No. 128, “Earnings Per Share.”

The conclusion reached by the EITF in Issue No. 07-4 is that when current period earnings are in excess of cash distributions, the undistributed earnings should be allocated to the holders of the general partner interest, the holders of the limited partner interest and incentive distribution rights holders based upon the terms of the partnership agreement. Under this model, contractual limitations on distributions to incentive distribution rights holders would be considered when determining the amount of earnings to allocate to them. That is, undistributed earnings would not be considered available cash for purposes of allocating earnings to incentive distribution rights holders. Conversely, when cash distributions are in excess of earnings, net income (or loss) should be reduced (increased) by the distributions made to the holders of the general partner interest, the holders of the limited partner interest and incentive distribution rights holders. The resulting net loss would then be allocated to the holders of the general partner interest and the holders of the limited partner interest based on their respective sharing of the losses based upon the terms of the partnership agreement.

Issue No. 07-4 is effective for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. The accounting treatment is effective for all financial statements presented. We do not expect the impact of the adoption of Issue 07-4 on our presentation of earnings per unit to be significant.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” This statement requires assets acquired and liabilities assumed to be measured at fair value as of the acquisition date, acquisition related costs incurred prior to the acquisition to be expensed and contractual contingencies to be recognized at fair value as of the acquisition date. This statement is effective for financial statements issued for fiscal years beginning after December 15, 2008. We are currently assessing the impact, if any, the adoption of this statement will have on our financial position, results of operations or cash flows.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

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

As of June 26, 2009 we had $421.9 million outstanding under our credit facility that was subject to a variable interest rate. Interest rate swap agreements were used to manage a portion of the exposure related to changing interest rates by converting floating-rate debt to fixed-rate debt. In August 2007 we entered into interest rate swap agreements with an aggregate notional value of $80.0 million that mature on August 20, 2010. Under the terms of the interest rate swap agreements, we were to pay fixed rates of 4.9% and receive three-month LIBOR with quarterly settlement. In March 2008 we entered into interest rate swap agreements with an aggregate notional value of $100.0 million that mature on March 31, 2011. Under the terms of the interest rate swap agreements, we were to pay fixed rates of 2.6% to 2.7% and receive three-month LIBOR with quarterly settlement. The interest rate swaps do not receive hedge accounting treatment under Statement of Financial Accounting Standard (“SFAS”) SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”). Changes in the fair value of the interest rate swaps are recorded in interest expense in the statements of operations. In addition, the interest rate swap agreements contain cross-default provisions to events of default under the credit agreement. Due to events related to the Bankruptcy Filings, all of these interest rate swap positions were terminated in the third quarter of 2008, and we have recorded a $1.5 million liability as of December 31, 2008 with respect to these positions.

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Prior to the events of default, indebtedness under the credit agreement bore interest at our option, at either (i) the Base rate, plus an applicable margin that ranges from 0.50% to 1.75%, depending on our total leverage ratio and senior secured leverage ratio, or (ii) LIBOR plus an applicable margin that ranges from 1.50% to 2.75%, depending upon our total leverage ratio and senior secured leverage ratio. During the Forbearance Period indebtedness under the credit agreement bore interest at our option, at either (i) the Base rate, plus an applicable margin that ranges from 2.75% to 3.75%, depending upon our total leverage ratio, or (ii) LIBOR plus an applicable margin that ranges from 4.25% to 5.25%, depending upon our total leverage ratio. Pursuant to the Second Forbearance Amendment, commencing on December 12, 2008, indebtedness under the credit agreement bore interest at our option, at either (i) the Base rate plus 5.0% per annum, with a Base rate floor of 4.0% per annum, or (ii) LIBOR plus 6.0% per annum, with a LIBOR floor of 3.0% per annum.

After giving effect to the Credit Agreement Amendment, amounts outstanding under our credit facility bear interest at either the LIBOR rate plus 6.50% per annum, with a LIBOR floor of 3.00%, or the Base rate plus 5.50% per annum, with a Base rate floor of 4.00% per annum. We now pay a fee of 1.50% on unused commitments under our revolving credit facility. After giving effect to the Credit Agreement Amendment, interest on amounts outstanding under our credit facility must be paid monthly. Our credit facility, as amended by the Credit Agreement Amendment, now requires us to pay additional interest on October 6, 2009, April 6, 2010, October 6, 2010 and April 6, 2011, equal to the product of (i) the sum of the total amount of term loans then outstanding plus the aggregate commitments under the revolving credit facility and (ii) 0.50%, 0.50%, 1.00% and 1.00%, respectively.

Due to the Forbearance Agreement, the Second Forbearance Amendment and the Credit Agreement Amendment, we expect our interest expense to continue to increase as compared to our interest expense prior to the Bankruptcy Filings. Changes in economic conditions could result in higher interest rates, thereby increasing our interest expense and reducing our funds available for capital investment, operations or distributions to our unitholders. Additionally, if domestic interest rates continue to increase, the interest rates on any of our future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Based on borrowings as of December 31, 2008, an increase or decrease of 100 basis points in the interest rate will result in increased or decreased, respectively, annual interest expenses of $4.5 million.

Item 8. Financial Statements and Supplementary Data.

Our consolidated financial statements, together with the report of our independent registered public accounting firm PricewaterhouseCoopers LLP, are set forth on pages F-1 through F-41 of this report and are incorporated herein by reference.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

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Item 9A. 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 December 31, 2008, were effective.

Management’s Report on Internal Control Over Financial Reporting. Our general partner’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Our general partner’s management, including the Chief Executive Officer and Chief Financial Officer of our general partner, conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal Control — Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2008. Our internal control over financial reporting as of December 31, 2008 has been audited by PricewaterhouseCoopers LLP, our independent registered public accounting firm, as stated in their report appearing on page F-2.

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 December 31, 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

However, since the beginning of the third quarter of 2008, the Private Company has made the Bankruptcy Filings, and, as previously announced, in July 2008 the Board created an internal review subcommittee of the Board comprised of directors who are independent of management and the Private Company to determine whether we participate in businesses other than as described in our filings with the SEC and to conduct investigations into other such specific items as are deemed to be appropriate by the subcommittee. The subcommittee retained independent legal counsel to assist it in its investigations.

The subcommittee has investigated a short-term financing transaction involving two subsidiaries of the Private Company. This transaction was identified as a potential source of concern in a whistleblower report made after the Private Company filed for bankruptcy. Although the transaction did not involve us or our subsidiaries, it was investigated because it did involve certain senior executive officers of our general partner who were also senior executive officers of the Private Company at the time of the transaction. Based upon its investigation, counsel for the subcommittee found that, subject to the subcommittee’s lack of access to Private Company documents and electronic records and witnesses, although certain irregularities occurred in the transactions, the transaction did not appear to cause the relevant officers to understand or believe that the Private Company had a lack of liquidity that imperiled the Private Company’s ability to meet its obligations to us and that certain aspects of the documentation of the transaction that were out of the ordinary did not call into question the integrity of any of the relevant officers.

The subcommittee also investigated whether certain senior executive officers of our general partner who were also senior executive officers of the Private Company knew and understood, beginning as early as July 2007 and at various times thereafter, about a lack of liquidity at the Private Company that imperiled the Private Company’s ability to meet its obligations to us. Based upon this investigation, and subject to the subcommittee’s lack of access to Private Company documents and electronic records and witnesses, counsel for the subcommittee found that each of the officers had access to and reviewed Private Company financial information, including information regarding the Private Company’s commodity trading activities, from which they could have developed an understanding of the nature and significance of the trading activities that led to liquidity problems at the Private Company well before they say they did. While the officers each stated sincerely that they did not understand the nature or extent of the Private Company’s trading-related problems until the first week of July 2008 or later, objective evidence suggests that they showed at least some indifference to known or easily discoverable facts and that they failed to adhere to procedures under the Private Company’s Risk Management Policy created expressly to ensure that the Private Company’s trading activities were properly monitored. Nonetheless, counsel for the subcommittee was not persuaded by the documents and other evidence it was able to access that the officers in fact knew and understood that the Private Company’s liquidity or capital needs were a significant cause for alarm until, at the earliest, the second quarter of 2008. Moreover, while it appeared to counsel that the officers developed a growing awareness of the nature and severity of the Private Company’s liquidity issues over the second quarter of 2008, counsel was unable to identify with any more precision the specific level of concern or understanding these individuals had prior to July 2008. While not within the scope of such counsel’s investigation, counsel was requested by the subcommittee to note any information that came to counsel’s attention during its investigation that suggested that the officers intended to deceive or mislead any third party. Subject to limitations described in its report, no information came to counsel’s attention during its investigation that suggested to counsel that the officers intended to deceive or to mislead any third parties. In addition, in connection with the investigation, counsel for the subcommittee did not express any findings of intentional misconduct or fraud on the part of any officer or employee of us.

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After completion of the internal review, a plan was developed with the advice of the audit committee of the Board to further strengthen our processes and procedures. This plan includes, among other things, reevaluating executive officers and accounting and finance personnel (including a realignment of officers as described elsewhere in this report) and hiring, as deemed necessary, additional accounting and finance personnel or consultants; reevaluating our internal audit function and determining whether to expand the duties and responsibilities of such group; evaluating the comprehensive training programs for all management personnel covering, among other things, compliance with controls and procedures, revising the reporting structure so that the Chief Financial Officer reports directly to the audit committee, and increasing the business and operational oversight role of the audit committee.

Item 9B. Other Information.

On July 1, 2009, the compensation committee of the Board adopted the SemGroup Energy Partners G.P., L.L.C. 2009 Executive Cash Bonus Plan (the “2009 Cash Bonus Plan”). Under the 2009 Cash Bonus Plan, participating senior executives, including the named executive officers, will be eligible to receive a cash award based on our level of achievement of specified performance objectives established by the compensation committee for fiscal 2009. Awards under the 2009 Cash Bonus Plan will equal a percentage of the participant’s base salary (ranging from 52.5% to 125% of base salary) depending on the individual and the level of our achievement of the applicable company performance objectives (ranging from 85% to greater than 110% of the target performance level). In general, a participant must be an active employee as of the applicable payment date to receive an award under the 2009 Cash Bonus Plan.

The compensation committee has adopted the following performance measures under the 2009 Cash Bonus Plan:

(1) For the Chief Executive Officer, the Chief Financial Officer, any Executive Vice President other than the Operations Participants (as defined below) and the Chief Accounting Officer (the “Corporate Executive Participants”), earnings before interest, taxes, depreciation and amortization, and restructuring and certain other non-cash charges (“EBITDA”) of the Partnership.

(2) For the Executive Vice President - Crude Operations and the Executive Vice President - Asphalt Operations (the “Operations Participants”), a combined performance measure including EBITDA of the crude business or the asphalt business, respectively, and EBITDA of the Partnership.

Participants who meet the highest level of attainment will be eligible to participate in awards from a bonus pool equal to 5% of EBITDA of the Partnership in excess of 110% of targeted EBITDA of the Partnership, to be awarded at the discretion of the compensation committee.

Awards under the 2009 Cash Bonus Plan for the year ending December 31, 2009 will be paid in two installments. The first installment will be paid in July 2009 and will equal 40% of the participant’s base salary (24% in the case of the Chief Accounting Officer to reflect that he was not an executive officer for the full six month period). Corporate Executive Participants will be eligible for the July 2009 payment if the actual EBITDA of the Partnership for the first six months of 2009 exceeds 95% of the target EBITDA for the first six months of 2009. Operational Participants will be eligible for the July 2009 payment if the actual EBITDA of the Partnership for the first six months of 2009 exceeds 95% of the target EBITDA for the first six months of 2009 and the EBITDA of the crude business or asphalt business, respectively, exceeds 95% of the target EBITDA for the first six months of 2009. The second payment will be determined and paid within 15 days after the filing of the Partnership’s annual report on Form 10-K for the year ended December 31, 2009.

In addition, upon a Change of Control of the Partnership, awards will be determined on a pro-rata basis as of the date of such Change of Control with the actual EBITDA of the Partnership, the crude business and the asphalt business, respectively, being calculated as of the most recently completed month prior to the Change of Control (the “Change of Control Period”) for which financial statements are available and the target performance measures being adjusted for the Change of Control Period. For purposes of the 2009 Cash Bonus Plan, a “Change of Control” means any of the following events: (i) any person or group other than the Private Company, Manchester Securities Corp., Alerian Finance Partners, LP, or their respective affiliates, shall become the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the combined voting power of the equity interests in us or our general partner; (ii) our limited partners approve, in one or a series of transactions, a plan of complete liquidation of us; (iii) the sale or other disposition by either our general partner or us of all or substantially all of the assets of our general partner or us in one or more transactions to any person other than our general partner and its affiliates; or (iv) a transaction resulting in a person other than our general partner or an affiliate of our general partner being our general partner.

The description of the 2009 Cash Bonus Plan above does not purport to be complete and is qualified in its entirety by reference to the complete text of the 2009 Cash Bonus Plan, a copy of which filed as an exhibit to this annual report on Form 10-K.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance.

SemGroup Energy Partners G.P., L.L.C., our general partner, manages our operations and activities. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. The directors of our general partner oversee our operations. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Our general partner owes a limited fiduciary duty to our unitholders. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Our general partner, therefore, may cause us to incur indebtedness or other obligations that are nonrecourse to it.

Directors and Executive Officers

Prior to the Bankruptcy Filings and the event related thereto, all of the executive officers of our general partner were employed by both our general partner and the Private Company and allocated their time between managing our business and affairs and the business and affairs of the Private Company. Messrs. Foxx and Stallings resigned the positions each officer held with SemGroup, L.P. in July 2008. Mr. Brochetti had previously resigned from his position with SemGroup, L.P. in March 2008. Mr. Parsons left the employment of SemGroup, L.P. in March 2009. Mr. Schwiering continues to serve as an officer of the Private Company and may have conflicts of interest and may favor the Private Company’s interests over our interests when conducting our operations.

On July 18, 2008, Manchester and Alerian exercised their right under the Holdings Credit Agreements in connection with certain events of default thereunder to vote the membership interests of our general partner in order to reconstitute the Board and effect the Change of Control. Messrs. Thomas L. Kivisto, Gregory C. Wallace, Kevin L. Foxx, Michael J. Brochetti and W. Anderson Bishop were removed from the Board. Mr. Bishop had served as the chairman of the audit committee and as a member of the conflicts committee and compensation committee of the Board. Messrs. Sundar S. Srinivasan, David N. Bernfeld and Gabriel Hammond (each of whom is affiliated with Manchester or Alerian) were appointed to the Board. Mr. Srinivasan was elected as Chairman of the Board. Messrs. Brian F. Billings and Edward F. Kosnik remained as independent directors of the Board and continue to serve as members of the conflicts committee, audit committee and compensation committee of the Board.

On October 1, 2008, Dave Miller (who is an affiliate of Manchester) and Duke R. Ligon were appointed members of the Board. Mr. Ligon is an independent member of the Board and is the chairman of the audit committee and also serves on the compensation committee and the conflicts committee of the Board. In connection with his appointment to the Board, Mr. Ligon was granted an award of 5,000 restricted common units. The restricted common units granted to Mr. Ligon vest in one-third increments over a three-year period.

On January 9, 2009, Mr. Srinivasan resigned his positions as Chairman of the Board and as a director. Mr. Ligon was subsequently elected as Chairman of the Board.

On March 18, 2009, the Board realigned the officers of our general partner appointing Michael J. Brochetti as Executive Vice President—Corporate Development and Treasurer, Alex G. Stallings as Chief Financial Officer and Secretary, and James R. Griffin as Chief Accounting Officer. Mr. Brochetti had previously served as Chief Financial Officer, Mr. Stallings had previously served as Chief Accounting Officer and Secretary and Mr. Griffin had previously served as controller.

Prior to the events surrounding the Bankruptcy Filings, the officers of our general partner were also employees and officers or directors of the Private Company. Messrs. Foxx and Stallings resigned the positions each officer held with SemGroup, L.P. in July 2008. Mr. Brochetti had previously resigned from his position with SemGroup, L.P. in March 2008. Mr. Parsons left the employment of SemGroup, L.P. in March 2009. Messrs. Foxx, Brochetti, Stallings, and Parsons remain as officers of our general partner. Mr. Schwiering continues to serve as an officer of the Private Company and as an officer of our general partner.

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The following table shows information regarding the current directors and executive officers of SemGroup Energy Partners G.P., L.L.C.

Name	Age	Position with SemGroup Energy Partners G.P., L.L.C.
Kevin L. Foxx	53		President and Chief Executive Officer
Michael J. Brochetti	43		Executive Vice President—Corporate Development and Treasurer
Alex G. Stallings	42		Chief Financial Officer and Secretary
James R. Griffin	32		Chief Accounting Officer
Peter L. Schwiering	65		Executive Vice President—Crude Operations
Jerry A. Parsons	56		Executive Vice President—Asphalt Operations
Duke R. Ligon	68		Director, Chairman of the Board and Audit Committee
Brian F. Billings	70		Director, Chairman of the Conflicts Committee
Edward F. Kosnik	64		Director, Chairman of the Compensation Committee
Gabriel Hammond	30		Director
Dave Miller	30		Director
David N. Bernfeld	29		Director

Our directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers.

Kevin L. Foxx has more than 24 years of experience in the crude oil gathering, transportation, terminalling and storage industry. Mr. Foxx has served as President and Chief Executive Officer of our general partner since February 2007. Mr. Foxx served as a director of our general partner from February 2007 to July 2008. Mr. Foxx served as the Private Company’s Chief Operating Officer and Executive Vice President and as a member of the Private Company’s Management Committee from 2000 to July 2008. Mr. Foxx founded and served as President of Foxx Transports, L.L.C., a domestic oil gathering and trading company based in Houston, Texas. Foxx Transports, L.L.C. was founded in 1995 and became part of the Private Company in 2000. Prior to founding Foxx Transports, L.L.C., Mr. Foxx formed the transportation division of Elleron Oil Company in 1987 and later sold that division to Plains Marketing in 1992, where he served as Vice President.

Michael J. Brochetti has served as Executive Vice-President—Corporate Development and Treasurer of our general partner since March 2009. Mr. Brochetti served as Chief Financial Officer of our general partner from February 2007 to March 2009. Mr. Brochetti also served as a director of our general partner from February 2007 to July 2008. Mr. Brochetti served as the Private Company’s Senior Vice President—Finance from October 2005 to March 2008. Prior to joining the Private Company, Mr. Brochetti was employed by Bank of America, N.A. in Boston, Massachusetts, since 1992, serving in various capacities, most recently as Director—Specialized Industries where he helped lead the financial institution’s relationships with key clients in the energy industry. Prior to joining Bank of America, Mr. Brochetti was employed with Barclays Bank, PLC, in the lending group’s corporate banking division.

Alex G. Stallings has served as Chief Financial Officer and Secretary of our general partner since March 2009. Mr. Stallings served as Chief Accounting Officer and Secretary of our general partner from February 2007 to March 2009. Additionally, Mr. Stallings served as the Private Company’s Chief Accounting Officer from September 2002 to July 2008. Prior to joining the Private Company, Mr. Stallings served as Chief Accounting Officer for Staffmark, Inc., a temporary staffing company where he was responsible for the public reporting and integration of numerous acquisitions during his tenure. Mr. Stallings also previously was an audit manager for the public accounting firm of Coopers & Lybrand, working in its Tulsa, Oklahoma office.

James R. Griffin has served as the Chief Accounting Officer of our general partner since March 2009. Mr. Griffin served as our general partner’s controller from May of 2007 to March 2009 and the Private Company’s transactional services controller from September 2006 to May 2007. Prior to joining the Private Company, Mr. Griffin served in various capacities, most recently as an audit manager, for the public accounting firm of PricewaterhouseCoopers LLP, working in its Tulsa, Oklahoma office since January 2000.

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Peter L. Schwiering has served as Executive Vice President—Crude Operations of our general partner since February 2007 and Vice President of Operations of SemCrude, L.P. since 2000. Prior to joining the Private Company, Mr. Schwiering worked for Dynegy Pipeline as manager of pipeline and commercial business. He also served with Sun Company for 25 years in various positions. He began with Sun in its New Jersey operations as a marketing representative for petroleum products. When he left Sun in 1995, Mr. Schwiering was the company’s manager of business development—Western Region, and he was based in Oklahoma.

Jerry A. Parsons has served as Executive Vice-President—Asphalt Operations of our general partner since February 20, 2008. Mr. Parsons served as Vice President, Corporate Development—North America of the Private Company from June 2005 to March 2009. Before joining the Private Company in June 2005, Mr. Parsons served as Vice President, Business Development for Koch Materials, Inc. (a subsidiary of Koch Industries, Inc.), where he oversaw the development of business operations supplying asphalt cement and related products to the road construction and roofing industries. Mr. Parsons joined Koch Industries, Inc. in 1974 and has over 30 years of experience in a variety of energy related businesses, including asphalt, refining, trading, crude oil and transportation.

Duke R. Ligon has served as a director of our general partner since October 2008. He is an attorney and served as senior vice president and general counsel of Devon Energy Corporation from January 1997 until he retired in February 2007. Since February 2007, Mr. Ligon has served in the capacity of Strategic Advisor to Love’s Travel Stops & Country Stores, Inc., based in Oklahoma City, and has acted as Executive Director of the Love’s Entrepreneurship Center at Oklahoma City University. He is also a member of the Board of Directors of Quest Midstream Partners, L.P., Heritage Trust Company, Security State Bank, Panhandle Oil and Gas Inc. (NYSE: PHX), Pre-Paid Legal Services, Inc. (NYSE: PPD), TransMontaigne Partners L.P. (NYSE: TLP) and TEPPCO Partners, L.P. (NYSE: TPP). Mr. Ligon received an undergraduate degree in chemistry from Westminster College and a law degree from the University of Texas School of Law.

Brian F. Billings has served as a director of our general partner since October 2007. Mr. Billings served as a director of Buckeye GP LLC, the general partner of Buckeye Partners, L.P. (NYSE: BPL), from its 1986 inception and as the chairman of its audit committee since 1999 until his resignation in September 2007. In addition, he was president of Buckeye GP LLC from 1986 to 1990. During Mr. Billings’ career, he also served as executive vice president of Williams Exploration Company and as president of Williams Energy Company, both of which are subsidiaries of The Williams Companies, Inc. Mr. Billings later was president of The Penn Central Corporation’s energy group which, through Buckeye Pipe Line Company and other subsidiaries, engaged in natural gas and refined products transportation, natural gas liquids processing and marketing, oil and gas exploration, and refining operations. Mr. Billings has been a private investor since 2001.

Edward F. Kosnik has served as a director of our general partner since July 2008. Mr. Kosnik has been a private investor since 2001. Most recently, Kosnik served as a director and member of the audit committee of Buckeye GP LLC, the general partner of Buckeye Partners, L.P. (NYSE: BPL), from its 1986 inception until his resignation in September 2007. He previously served on the board of directors of Premcor, Inc. from November 2004 to September 2005 and was a member of Premcor, Inc.’s audit committee. In addition, Mr. Kosnik has served as a member of the Board of Trustees and a member of the audit committee of Marquette University since September 2006. Prior to 2001, Mr. Kosnik served in various capacities, including as President and Chief Executive Officer and Chief Operating Officer, at Berwind Group, a private diversified operating and investment company from 1997-2001, and as Executive Vice President and Chief Financial Officer of Alexander & Alexander, a global insurance brokerage company from 1994-1997. In addition, he served in various capacities, including as Chairman, Chief Executive Officer and Chief Financial Officer, at JWP Inc, a global facility management and contracting company, from 1992-1997, President and Chief Executive Officer of Sprague Technologies Inc., an electronics component manufacturer, from 1987-1992 and as Executive Vice President and Chief Financial Officer of The Penn Central Corporation from 1983-1987.

Gabriel Hammond has served as a director of our general partner since July 2008 and was initially appointed to the Board in connection with his affiliation with Alerian. On March 20, 2009, Alerian transferred its interest in the Holdings Credit Agreements to Manchester (Alerian is still potentially entitled to receive a portion of certain potential recoverable value from such interest). Currently, Mr. Hammond serves as a director, but not pursuant to any agreement or understanding. Mr. Hammond is the Managing Partner of Alerian. Prior to founding the company in 2004, Mr. Hammond covered the broader Energy and Power sector at Goldman, Sachs & Co. in the firm’s Equity Research Division. Specializing in the Master Limited Partnership midstream energy space, Mr. Hammond advised Goldman Sachs Asset Management, which holds an estimated $2 billion of MLP securities (both as principal and on behalf of its clients), with portfolio allocation, short-term trading, and tax-advantaged specialty applications. Mr. Hammond sits on the Board of Directors of the National Association of Publicly Traded Partnerships.

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Dave Miller has served as a director of our general partner since October 2008 and was appointed to the Board in connection with his affiliation with Elliott Associates, L.P., which is the parent of Manchester. Mr. Miller is a Portfolio Manager at Elliott Associates, L.P. Mr. Miller joined Elliott Associates, L.P. in March 2003 after having worked in mergers and acquisitions and financing advisory roles at Peter J. Solomon Company. Mr. Miller received an A.B. degree, magna cum laude, from Harvard University. He is currently a manager of JCIM, LLC, an automotive component supply joint-venture affiliated with Johnson Controls, Inc.

David N. Bernfeld has served as a director of our general partner since July 2008 and was appointed to the Board in connection with his affiliation with Elliott Associates, L.P., which is the parent of Manchester. Mr. Bernfeld has served as an analyst at Elliott Associates, L.P. since April 2008. Prior to joining Elliott Associates, L.P., Mr. Bernfeld was an analyst with DKR Capital, Inc. since 2007, a Private Equity Associate at Ardshiel, Inc. from 2003 until 2005, and an Analyst in the Mergers and Acquisition Group of Bear, Stearns & Co. Inc. from 2001 through 2003. Mr. Bernfeld received an M.B.A. from Columbia Business School in 2007, and a B.A. in Economics and Mathematics from Haverford College in 2001.

Independence of Directors

During 2008, we were listed on Nasdaq, and we intend to apply for relisting of our securities after becoming timely in our periodic filings with the SEC. Our general partner currently has six directors, three of whom (Messrs. Billings, Kosnik and Ligon) are “independent” as defined under the independence standards established by Nasdaq. In addition, Mr. Bishop was an independent director of our general partner prior to his removal from the Board in connection with the Change of Control. Nasdaq’s independence definition includes a series of objective tests, such as that the director is not an employee of the company and has not engaged in various types of business dealings with the company. In addition, the board of directors has made a subjective determination as to each independent director that no relationships exist which, in the opinion of the board, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director. In making these determinations, the directors reviewed and discussed information provided by the directors and us with regard to each director’s business and personal activities as they may relate to us and our management. Nasdaq does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a nominating committee.

In addition, the members of the audit committee also each qualify as “independent” under special standards established by the SEC for members of audit committees, and the audit committee includes at least one member who is determined by the board of directors to meet the qualifications of an “audit committee financial expert” in accordance with SEC rules, including that the person meets the relevant definition of an “independent” director. Mssrs. Billings and Kosnik are the independent directors who have been determined to be audit committee financial experts. Unitholders should understand that this designation is a disclosure requirement of the SEC related to experience and understanding with respect to certain accounting and auditing matters. The designation does not impose any duties, obligations or liability that are greater than are generally imposed on a member of the audit committee and board of directors, and the designation of a director as an audit committee financial expert pursuant to this SEC requirement does not affect the duties, obligations or liability of any other member of the audit committee or board of directors.

Board Committees

We have standing conflicts, audit and compensation committees of the board of directors of our general partner. In addition, in July 2008 the Board created an internal review subcommittee of the Board. Each member of the audit, compensation and conflicts committees is an independent director in accordance with Nasdaq and applicable securities laws. Each of the audit, compensation and conflicts committees has a written charter approved by the board of directors of our general partner. The written charter for each of these committees is available on our web site at www.sglp.com under the “Investors—Corporate Governance” section. We will also provide a copy of any of our committee charters to any of our unitholders without charge upon written request to the attention of Investor Relations at 6120 South Yale, Suite 500, Tulsa, Oklahoma 74136. The current members of the audit, compensation and conflicts committees and the internal review subcommittee of the Board and a brief description of the functions performed by each committee are set forth below:

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Conflicts Committee. The members of the conflicts committee are Messrs. Billings (chairman), Kosnik and Ligon. Mr. Bishop also served as a member of the conflicts committee prior to the Change of Control in July 2008. The primary responsibility of the conflicts committee is to review matters that the directors believe may involve conflicts of interest. The conflicts committee determines if the resolution of the conflict of interest is fair and reasonable to us. The conflicts committee may retain independent legal and financial advisors to assist it in its evaluation of a transaction. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates and must meet the independence standards to serve on an audit committee of a board of directors established by Nasdaq (or any national securities exchange upon which the common units are traded) and the SEC. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders.

Audit Committee. The members of the audit committee are Messrs. Billings, Kosnik and Ligon (chairman). Mr. Bishop also served as a member of the audit committee prior to the Change of Control in July 2008. The primary responsibilities of the audit committee are to assist the Board in its general oversight of our financial reporting, internal controls and audit functions, and it is directly responsible for the appointment, retention, compensation and oversight of the work of our independent auditors. In connection with the internal review, the audit committee increased its business and oversight role.

Compensation Committee. The members of the compensation committee are Messrs. Billings, Kosnik (chairman after his appointment to the Board in July 2008) and Ligon. Mr. Bishop also served as a member of the compensation committee prior to the Change of Control in July 2008 and as the chairman of the compensation committee prior to Mr. Kosnik’s appointment to the Board. The primary responsibility of the compensation committee is to oversee compensation decisions for the outside directors of our general partner and executive officers of our general partner as well as our long-term incentive plan.

Internal Review Subcommittee. The members of the internal review subcommittee are Messrs. Bernfeld, Billings and Hammond. The internal review subcommittee is comprised of directors who are independent of management and the Private Company to determine whether we participate in businesses other than as described in our filings with the SEC and to conduct investigations into other such specific items as are deemed to be appropriate by the subcommittee.

Code of Ethics and Business Conduct

Our general partner has adopted a Code of Business Conduct and Ethics applicable to all of our general partner’s employees, including all officers, and including our general partner’s independent directors, who are not employees of our general partner, with regard to their activities relating to us. The Code of Business Conduct and Ethics incorporate guidelines designed to deter wrongdoing and to promote honest and ethical conduct and compliance with applicable laws and regulations. They also incorporate our expectations of our general partner’s employees that enable us to provide accurate and timely disclosure in our filings with the Securities and Exchange Commission and other public communications. The Code of Business Conduct and Ethics is publicly available under the “Investors - Corporate Governance” section of our web site at www.sglp.com. The information contained on, or connected to, the our web site is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this or any other report that we file with, or furnish to, the Securities and Exchange Commission. We will also provide a copy of the Code of Business Conduct and Ethics to any of our unitholders without charge upon written request to the attention of Investor Relations at 6120 South Yale, Suite 500, Tulsa, Oklahoma 74136. If any substantive amendments are made to the Code of Business Conduct and Ethics or if we or our general partner grant any waiver, including any implicit waiver, from a provision of the code to any of our general partner’s executive officers and directors, we will disclose the nature of such amendment or waiver on that web site or in a current report on Form 8-K.

Section 16(a) Beneficial Ownership Reporting Compliance

Based solely upon a review of Forms 3, 4 and 5 (and any amendments thereto) furnished to us, we believe that no directors, officers, beneficial owners of more than 10% of any class of the Partnership’s securities or any other person subject to Section 16 of the Exchange Act failed to file reports required by Section 16(a) of the Exchange Act during the year ended December 31, 2008 except as follows: one report on Form 4 filed by each of Messrs. Schwiering, Kivisto, Parsons, Brochetti, Stallings, Wallace and Foxx, with respect to the award of phantom units; one report with respect to the award of restricted units upon Mr. Ligon’s appointment to the Board later filed on a Form 5, and one report with respect to purchase of common units on the open market later filed on a Form 5 by Cushing MLP Opportunity Fund I, LP.

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Reimbursement of Expenses of our General Partner

We were party to the Amended Omnibus Agreement with the Private Company. Pursuant to the Amended Omnibus Agreement, we were required to pay our general partner and the Private Company an annual fixed administrative fee of $7.0 million for the provision by our general partner and the Private Company of various general and administrative services to us. The events related to the Bankruptcy Filings terminated the Private Company’s obligations to provide services to us under the Amended Omnibus Agreement. The Private Company continued to provide such services to us until the effective date of the Settlement at which time the Private Company rejected the Amended Omnibus Agreement and we and the Private Company entered into the Shared Services Agreement and the Transition Services Agreement relating to the provision of such services (see “Item 1. Business—Impact of the Bankruptcy of the Private Company and Certain of its Subsidiaries and Related Events—Settlement with the Private Company”). In addition, in connection with the Settlement, we made offers of employment to, and now employ, certain individuals associated with our crude oil operations and subsequently made additional offers of employment to, and now employ, certain individuals associated with our asphalt operations. The costs to directly employ these individuals as well as the costs under the Shared Services Agreement and the Transition Services Agreement may be higher than those previously paid by us under the Amended Omnibus Agreement, which could have a material adverse effect on our business, financial condition, results of operations, cash flows, ability to make distributions to our unitholders, the trading price of our common units and our ability to conduct our business. For a more complete description of the Amended Omnibus Agreement and the Shared Services Agreement, see “Item 13—Certain Relationships and Related Party Transactions, and Director Independence.”

Item 11. Executive Compensation.

Compensation Discussion and Analysis

As is the case with many publicly traded partnerships, we have not historically directly employed any persons responsible for managing or operating us or for providing services relating to day-to-day business affairs. SemGroup Energy Partners G.P., L.L.C., our general partner, manages our operations and activities, and its board of directors and officers make decisions on our behalf. Each of the executive officers of our general partner, including Kevin L. Foxx, Michael J. Brochetti, Alex G. Stallings, Peter L. Schwiering and Jerry A. Parsons (collectively, the “named executive officers”), have entered into an employment agreement with a subsidiary of our general partner. During portions of 2008, each of the named executive officers was also employed by and provided services to the Private Company. The compensation for the named executive officers for services rendered to us is determined by the compensation committee of our general partner. The events related to the Bankruptcy Filings terminated the Private Company’s obligations to provide services to us under the Amended Omnibus Agreement. The Private Company continued to provide such services to us until the effective date of the Settlement at which time the Private Company rejected the Amended Omnibus Agreement. In connection with the Settlement, we made offers of employment to, and now employ, certain individuals associated with our crude oil operations and subsequently made additional offers of employment to, and now employ, certain individuals associated with our asphalt operations.

Compensation Methodology. Prior to the Bankruptcy Filings and the events related thereto, our general partner sought to improve our operating performance to provide a return to unitholders in the form of distributions and to maintain a capital structure to support future growth. Since the time of the Bankruptcy Filings, our general partner has had to devote considerable time and effort to stabilizing our business, replacing the substantial amount of revenues previously derived from services provided to the Private Company with revenues to third parties, curing bank credit defaults and negotiating a new credit agreement amendment, negotiating a settlement with the Private Company, managing litigation, and bringing current our various regulatory and financial filings. These additional challenges have played an important role in the compensation committee's deliberations concerning discretionary bonus awards in 2008 and in formulating the 2009 Cash Bonus Plan.

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The compensation committee of our general partner seeks to provide a total compensation package designed to drive performance and reward contributions in support of these business strategies and to attract, motivate and retain high quality talent with the skills and competencies required by us. Prior to the Bankruptcy Filings, the compensation committee examined the compensation practices of our peer companies, which consisted of other publicly traded master limited partnerships having a business mix comparable to ours. Previously, these peer companies included Enbridge Energy Partners, L.P., Magellan Midstream Partners, L.P., Plains All American Pipeline, L.P., Sunoco Logistics Partners L.P. and TEPPCO Partners, L.P. The compensation committee also reviewed compensation data from the general midstream energy industry to obtain a general understanding of current compensation practices, as it believed that the competition for executive talent was broader than just the peer companies. The compensation committee is currently reevaluating these peer companies, compensation in the general midstream industry and other items it deems relevant and has recently adopted an incentive cash bonus plan for the year ended December 31, 2009 taking into account the changes to our business and priorities discussed earlier as a result of the Bankruptcy Filings and related events. Please see “—2009 Cash Bonus Plan.” The compensation committee may review and, in certain cases, participate in, various relevant compensation surveys and consult with compensation consultants with respect to determining compensation for the named executive officers. The compensation committee did not participate in any such surveys during the year ended December 31, 2008.

Elements of Compensation. The primary elements of our general partner’s compensation program are a combination of annual cash and long-term equity-based compensation. For 2008, the principal elements of compensation for the named executive officers were the following:

•

base salary;

•

discretionary bonus awards;

•

long-term incentive plan awards; and

•

other benefits.

Base Salary. During 2008, our general partner’s compensation committee established base salaries for the named executive officers based on various factors including the amounts it considered necessary to attract and retain the highest quality executives, the responsibilities of the named executive officers and market data including publicly available market data for the peer companies listed above as reported in their filings with the SEC. The compensation committee is currently reviewing the compensation of the named executive officers, including the base salaries payable to such officers. As part of its review, the compensation committee may review the compensation of executives in similar positions with similar responsibility in the peer companies listed above and in companies in the midstream energy industry with which we believe we generally compete for executives. As discussed above, during 2008, the base salaries of the named executive officers were allocated to us by our general partner as general and administrative expenses and were included in the annual administrative fee that we paid to our general partner and the Private Company pursuant to the Amended Omnibus Agreement for the provision of certain general and administrative functions. There were no changes to base salaries during 2008.

Each of the named executive officers have entered into employment agreements with a subsidiary of our general partner. The employment agreements provided for an initial annual base salary of $450,000, $300,000, $275,000, $250,000 and $250,000, for Mr. Foxx, Mr. Brochetti, Mr. Stallings, Mr. Schwiering and Mr. Parsons, respectively. These initial base salary amounts were determined based upon the scope of each executive’s responsibilities that are commensurate with such executive’s position as well as the added responsibilities the executives have that are typical of executives in publicly traded partnerships, taking into account competitive market compensation paid by similar companies for comparable positions. In March 2009, Mr. Stallings’ annual base salary was increased to $300,000 in connection with his appointment as the Chief Financial Officer and Secretary of our general partner.

Discretionary Bonus Awards. Our general partner’s compensation committee may also award discretionary bonus awards to the named executive officers. Our general partner may use discretionary bonus awards for achieving financial and operational goals and for achieving individual performance objectives. On December 18, 2008, the compensation committee awarded the following cash bonus awards to the named executive officers: Kevin Foxx - $365,000; Michael Brochetti - $245,000; Alex Stallings - $225,000; Peter Schwiering - $120,000; and Jerry Parsons - $215,000. In awarding these cash bonuses, the compensation committee considered, among other factors, the role and responsibility of each officer with our general partner, the change in each named executive officer’s responsibility after the Bankruptcy Filings, the difficult operational, financial, legal and working environment caused by the Bankruptcy Filings, each named executive officer’s past compensation, perceived contribution of each named executive officer to our general partner and to us generally, target EBITDA during the third and fourth quarters of 2008, actual and projected financial results for the third and fourth quarters of 2008, obtaining forbearances under our credit agreement and satisfying the covenants in such agreements and each named executive officer’s efforts in rebuilding our business after July 2008 as a substantial majority of our business was derived from services provided to the Private Company prior to the Bankruptcy Filings in July 2008.

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Long-Term Incentive Plan Awards. Our general partner has adopted a Long-Term Incentive Plan, or the Plan, for employees, consultants and directors of our general partner and its affiliates (including the Private Company prior to the Change of Control) who perform services for us. Each of the named executive officers are eligible to participate in this plan. The long-term incentive plan provides for the grant of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights and substitute awards. For a more detailed description of this plan, please see “—Long-Term Incentive Plan.”

On June 20, 2008, our general partner’s compensation committee made grants of phantom units under the Plan to eligible individuals who performed services for us, including the named executive officers. In connection therewith, the compensation committee approved two forms of Phantom Unit Grant Agreements to be used for grants of phantom units under the Plan.

Phantom Units granted under the form of Phantom Unit Grant Agreement filed as Exhibit 10.15 hereto (“Type A Awards”) were to vest in one-third increments over a three year period, subject to earlier vesting on a change of control or upon a termination without cause or due to death or disability. The Type A Awards had distribution equivalent rights for each fiscal quarter in which our quarterly cash distribution to our subordinated and common unitholders for such quarter equals or exceeds $0.39 per unit (or $1.56 per unit on an annualized basis). Pursuant to the distribution equivalent right, the grantee was entitled to receive a cash payment with respect to each Phantom Unit then outstanding equal to the product of (i) the per unit cash distributions paid to the Partnership’s unitholders during such fiscal quarter, if any, multiplied by (ii) the number of phantom units included in the grant.

Phantom Units granted under the form of Phantom Unit Grant Agreement filed as Exhibit 10.16 hereto (“Type B Awards”) have substantially similar terms as Type A Awards, except that the phantom units have distribution equivalent rights for each fiscal quarter in which our quarterly cash distribution to our subordinated and common unitholders for such quarter equals or exceeds $0.47 per unit (or $1.88 per unit on an annualized basis).

The named executive officers were granted Type A Awards and Type B Awards as indicated below:

Officer	Type A Awards	Type B Awards
Kevin L. Foxx	35,000	30,000
Michael J. Brochetti	27,000	23,000
Alex G. Stallings	24,000	21,000
Jerry A. Parsons	11,000	9,000
Peter L. Schwiering	8,000	7,000

The Change of Control constituted a change of control under the Plan, which resulted in the early vesting of all awards under the Plan, including the Type A Awards and the Type B Awards. See “—Change of Control” below.

Other Benefits. The employment agreements entered into by each of the named executive officers with our general partner provide that the named executive officer is eligible to participate in any employee benefit plans maintained by our general partner. During 2008, our general partner did not maintain any benefit plans other than the long-term incentive plan described above. In addition, the employment agreements provide that each named executive officer is entitled to reimbursement for out-of-pocket expenses incurred while performing his duties under the employment agreement.

Prior to the Bankruptcy Filings, the Private Company provided certain perquisites to our named executive officers. After the Bankruptcy Filings, we provided these perquisites, including country club memberships, car allowances and reimbursement of certain deductibles and co-payments for medical expenses, to our named executive officers.

Compensation Mix. Our general partner’s compensation committee determines the mix of compensation, both among short and long-term compensation and cash and non-cash compensation, to establish structures that it believes are appropriate for each of the named executive officers. The compensation committee is currently evaluating the mix of base salary, bonus awards, awards under the long-term incentive plan and the other benefits that are available to the named executive officers to ensure that such mix fits the overall compensation objectives of our general partner and us taking into account the changes to and rebuilding of our business as a result of the Bankruptcy Filings and related events. The compensation committee recently adopted the 2009 Cash Bonus Plan for the year ended December 31, 2009 taking into account the changes to our business and priorities discussed earlier as a result of the Bankruptcy Filings and related events. Please see “—2009 Cash Bonus Plan.”

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Role of Executive Officers in Executive Compensation. Our general partner’s compensation committee determines the compensation of the named executive officers. Our chief executive officer, Mr. Foxx, provides periodic recommendations to the compensation committee regarding the compensation of other named executive officers. In addition, the employment agreements entered into by the named executive officers were originally approved by the management committee of the Private Company’s general partner pursuant to its limited liability company agreement. Mr. Foxx served on this management committee at the time of the approval of such agreements, but did not participate in the approval of his employment agreement.

Employment Agreements. As indicated above, each of the named executive officers has entered into an employment agreement with our general partner. All of these agreements are substantially similar except for the amounts of compensation paid to the respective named executive officer. Each of the employment agreements has a term of two years that will automatically be extended for one year periods unless either party gives 90 days advance notice.

The employment agreements provide for the initial annual base salaries described above. As described above, Mr. Stallings’ base salary was increased in March 2009 in connection with the realignment of our executive officers. In addition, each of the named executive officers is eligible for discretionary bonus awards and long-term incentives which may be made from time to time in the sole discretion of the board of directors of our general partner. The employment agreements also provide that the named executive officers are eligible to participate in any employee benefit plans maintained by our general partner and are entitled to reimbursement for certain out-of-pocket expenses.

Pursuant to the employment agreements, each of the named executive officers has agreed not to disclose any confidential information obtained by him while employed under the agreement. In addition, each employment agreement contains payment obligations that may be triggered by a termination after a change of control as defined therein. The Change of Control resulted in a change of control under the employment agreements of the named executive officers. See “—Change of Control” below.

Potential Payments Upon Change of Control or Termination.

Employment Agreements. Under the employment agreements entered into with our named executive officers, our general partner may be required to pay certain amounts upon a change of control of us or our general partner or upon the termination of the executive officer in certain circumstances. These termination payments were set by comparing similar payments made by the peer companies listed above and other companies in the midstream energy industry with which we believed we generally competed for executives. Except in the event of termination for Cause, termination by the named executive officer other than for Good Reason, or termination after the expiration of the term of the employment agreement, the employment agreements provide for payment of any unpaid base salary and vested benefits under any incentive plans, a lump sum payment equal to twelve months of base salary and continued participation in our general partner’s welfare benefit programs for the longer of the remainder of the term of the employment agreement or one year after termination.

If within one year after a change of control occurs the named executive officer is terminated by our general partner without Cause or the named executive officer terminates the agreement for Good Reason, he will be entitled to payment of any unpaid base salary and vested benefits under any incentive plans, a lump sum payment equal to 24 months of base salary and continued participation in our general partner’s welfare benefit programs for the longer of the remainder of the term of the employment agreement or one year after termination. If such termination occurred effective as of December 31, 2008, Messrs Foxx, Brochetti, Stallings, Schwiering and Parsons would have been entitled to lump sum payments of $900,000, $600,000, $550,000, $500,000 and $500,000, respectively, in addition to continued participation in our general partner’s welfare benefit programs and the amounts of unpaid base salary and benefits under any incentive plans. As discussed below, the Change of Control constituted a change of control under the employment agreements.

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For purposes of the employment agreements:

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

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

“Change of Control” means any of the following events: (i) any person or group other than the Private Company and its affiliates, shall become the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the combined voting power of the equity interests in us or our general partner; (ii) our limited partners approve, in one or a series of transactions, a plan of complete liquidation of us; (iii) the sale or other disposition by either our general partner or us of all or substantially all of the assets of our general partner or us in one or more transactions to any person other than our general partner and its affiliates; or (iv) a transaction resulting in a person other than our general partner or an affiliate of our general partner being the general partner of the partnership.

LTIP Awards. The restricted and phantom units granted under the Plan will vest automatically upon a change of control (as defined in the Plan) of us or our general partner, subject to any contrary provisions in the award agreement. As of December 31, 2008, Mr. Ligon was on the only individual holding unvested awards under the Plan.

Change of Control

The Change of Control constituted a change of control under the Plan, which resulted in the early vesting of all awards under the Plan. As such, the phantom units awarded to Messrs. Foxx, Brochetti, Stallings, Schwiering and Parsons in the amounts of 150,000 units, 90,000 units, 75,000 units, 45,000 units and 20,000 units, respectively, were fully vested upon the Change of Control. The common units underlying such awards were issued to such individuals in August 2008. In addition, the 5,000 restricted units awarded to each of Messrs. Billings, Kosnik and Bishop for their service as independent members of the Board were fully vested upon the Change of Control.

The Change of Control also resulted in a change of control under the employment agreements of Messrs. Foxx, Brochetti, Stallings, Schwiering and Parsons. If within one year after the Change of Control any such officer is terminated by our general partner without Cause (as defined above under “—Potential Payments Upon Change of Control or Termination”) or such officer terminates the agreement for Good Reason (as defined above under “—Potential Payments Upon Change of Control or Termination”), he will be entitled to payment of any unpaid base salary and vested benefits under any incentive plans, a lump sum payment equal to 24 months of base salary and continued participation in the our general partner’s welfare benefit programs for one year after termination. Upon such an event, Messrs Foxx, Brochetti, Stallings, Schwiering and Parsons would be entitled to lump sum payments of $900,000, $600,000, $550,000, $500,000 and $500,000, respectively, in addition to continued participation in our general partner’s welfare benefit programs and the amounts of unpaid base salary and benefits under any incentive plans. As of the date of the filing of this report, none of these officers is entitled to these benefits as none of them has been terminated by our general partner without Cause or has terminated his agreement for Good Reason.

Long-Term Incentive Plan

General. Our general partner has adopted the Plan for employees, consultants and directors of our general partner and its affiliates (including the Private Company prior to the Change of Control) who perform services for us. The summary of the Plan contained herein does not purport to be complete and is qualified in its entirety by reference to the Plan. The Plan provides for the grant of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights and substitute awards. Subject to adjustment for certain events, an aggregate of 1,250,000 common units may be delivered pursuant to awards under the Plan. Units that are cancelled, forfeited or are withheld to satisfy our general partner’s tax withholding obligations are available for delivery pursuant to other awards. The Plan is administered by the compensation committee of our general partner’s board of directors. The Plan has been designed to furnish additional compensation to employees, consultants and directors and to align their economic interests with those of common unitholders. In addition, in December 2008 the Plan was amended to provide for the delivery of subordinated units in addition to common units.

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Unit Awards. The compensation committee may grant unit awards to eligible individuals under the Plan. A unit award is an award of common units or subordinated units that are fully vested upon grant and not subject to forfeiture.

Restricted Units and Phantom Units. A restricted unit is a common unit or subordinated unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit or a subordinated unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit or subordinated unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equal to the fair market value of a common unit or subordinated unit. The compensation committee may make grants of restricted units and phantom units under the Plan to eligible individuals containing such terms, consistent with the Plan, as the compensation committee may determine, including the period over which restricted units and phantom units granted will vest. The compensation committee may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria. In addition, the restricted and phantom units will vest automatically upon a change of control (as defined in the Plan) of us or our general partner, subject to any contrary provisions in the award agreement. The Change of Control constituted a change of control under the Plan. See “—Change of Control” above.

If a grantee’s employment, consulting or membership on the board of directors terminates for any reason, the grantee’s restricted units and phantom units will be automatically forfeited unless, and to the extent, the award agreement or the compensation committee provides otherwise.

Distributions made by us with respect to awards of restricted units may, in the compensation committee’s discretion, be subject to the same vesting requirements as the restricted units. The compensation committee, in its discretion, may also grant tandem distribution equivalent rights with respect to phantom units.

We intend for restricted units and phantom units granted under the Plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, participants will not pay any consideration for the common units they receive with respect to these types of awards, and neither we nor our general partner will receive remuneration for the units delivered with respect to these awards.

Unit Options and Unit Appreciation Rights. The Plan also permits the grant of options covering common units, subordinated units and unit appreciation rights. Unit options represent the right to purchase a number of common units or subordinated units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units or subordinated units over a specified exercise price, either in cash or in common units or subordinated units as determined by the compensation committee. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the compensation committee may determine, consistent with the Plan; however, a unit option or unit appreciation right must have an exercise price equal to the fair market value of a common unit or subordinated unit on the date of grant.

Distribution Equivalent Rights. Distribution equivalent rights are rights to receive all or a portion of the distributions otherwise payable on units during a specified time. Distribution equivalent rights may be granted alone or in combination with another award.

By giving participants the benefit of distributions paid to unitholders generally, grants of distribution equivalent rights provide an incentive for participants to operate our business in a manner that allows our partnership to provide increasing partnership distributions. Typically, distribution equivalent rights will be granted in tandem with a phantom unit, so that the amount of the participant’s compensation is tied to both the market value of our units and the distributions that unitholders receive while the award is outstanding. We believe this aligns the participant’s incentives directly to the measures that drive returns for our unitholders.

Substitute Awards. The compensation committee, in its discretion, may grant substitute or replacement awards to eligible individuals who, in connection with an acquisition made by us, our general partner or an affiliate, have forfeited an equity-based award in their former employer. A substitute award that is an option may have an exercise price less than the value of a common unit or subordinated unit on the date of grant of the award.

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Source of Common Units; Cost. Common units to be delivered with respect to awards may be common or subordinated units acquired by our general partner on the open market, common or subordinated units already owned by our general partner, common or subordinated units acquired by our general partner directly from us or any other person or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common and subordinated units. With respect to unit options, our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring these units and the proceeds received from an optionee at the time of exercise. Thus, we will bear the cost of the unit options. If we issue new units with respect to these awards, the total number of units outstanding will increase, and our general partner will remit the proceeds it receives from a participant, if any, upon exercise of an award to us. With respect to any awards settled in cash, our general partner will be entitled to reimbursement by us for the amount of the cash settlement.

Amendment or Termination of Long-Term Incentive Plan. Our general partner’s board of directors, in its discretion, may terminate the Plan at any time with respect to the units for which a grant has not theretofore been made. The Plan will automatically terminate on the earlier of the 10th anniversary of the date it was initially approved by our unitholders or when units are no longer available for delivery pursuant to awards under the Plan. Our general partner’s board of directors will also have the right to alter or amend the Plan or any part of it from time to time and the compensation committee may amend any award; provided, however, that no change in any outstanding award may be made that would materially impair the rights of the participant without the consent of the affected participant.

2009 Cash Bonus Plan

On July 1, 2009, the compensation committee adopted the 2009 Cash Bonus Plan. This plan provides for incentive payments to our named executive officers based upon the overall financial performance measured by EBITDA of our asphalt and/or crude oil operations. In addition, the compensation committee may make discretionary incentive payments based upon the performance of such named executive officer. Please see “Item 9B—Other Information” for a description of the 2009 Cash Bonus Plan.

Compensation Committee Report

The compensation committee of the general partner of SemGroup Energy Partners, L.P. has reviewed and discussed the Compensation Discussion and Analysis section of this report required by Item 402(b) of Regulation S-K with management of the general partner of SemGroup Energy Partners, L.P. and, based on that review and discussion, has recommended that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.

The Compensation Committee

Edward F. Kosnik, Committee Chair

Brian F. Billings

Duke R. Ligon

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Summary Compensation Table

The following table summarizes the compensation of our named executive officers for the fiscal years ended 2008 and 2007.

Name and Position (1)	Year		Salary ($)(2)		Bonus ($)(2)		Stock Awards ($) (4)		Option Awards ($)		Non-Equity Incentive Plan Compensation ($)		All Other Compensation ($) (5)		Total ($)

Kevin L. Foxx President and Chief Executive Officer		2008 2007		450,000 202,050		365,000 —		3,361,493 210,715		— —		— —		4,715 —		4,181,208 412,765
Michael J. Brochetti Executive Vice President - Corporate Development and Treasurer		2008 2007		300,000 134,700		245,000 —		2,090,467 99,160		— —		— —		16,491 —		2,651,958 233,860
Alex G. Stallings Chief Financial Officer and Secretary		2008 2007		275,000 123,475		225,000 —		1,764,351 74,370		— —		— —		420 —		2,264,771 197,845
Peter L. Schwiering Executive Vice President - Crude Operations		2008 2007		250,000 112,250		120,000 —		978,351 74,370		— —		— —		159 —		1,348,510 186,620
Jerry A. Parsons Executive Vice President - Asphalt Operations(5)		2008 2007		215,750 N/A		215,000 N/A		524,000 N/A		— N/A		— N/A		— N/A		954,750 N/A

(1)		During 2008, Mr. Brochetti served as our general partner’s Chief Financial Officer and Mr. Stallings served as our Chief Accounting Officer and Secretary. The officers of our general partner were realigned in March 2009.
(2)		We did not pay any bonuses during the year ended December 31, 2007. Any bonus amounts received by the named executive officers during 2007 were paid by the Private Company.
(3)		Mr. Stallings’ annual base salary was increased to $300,000 in March 2009.
(4)		Dollar amounts represent the compensation expense recognized in 2008 with respect to phantom unit grants under our the Plan. See Note 14 to our Consolidated Financial Statements for assumptions used in calculating these amounts.
(5)		Prior to the Bankruptcy Filings, the Private Company provided certain perquisites to our named executive officers. After the Bankruptcy Filings, we provided these perquisites, including country club memberships and reimbursement of certain deductibles and co-payments for medical expenses, to our named executive officers.
(6)		Mr. Parsons became an executive officer of our general partner in connection with our acquisition of the Asphalt Acquired Assets in February 2008. Mr. Parsons’ annual base salary is $250,000.

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Grants of Plan-Based Awards Table for Fiscal 2008

The following tables provide information concerning each grant of an award made to a named executive officer during 2008, including, but not limited to, awards made under our general partner’s Long-Term Incentive Plan.

		Estimated Future Payouts Under Non-Equity Incentive Plan Awards				Estimated Future Payouts Under Equity Incentive Plan Awards
Name	Grant Date	Threshold ($)	Target ($)	Maximum ($)	Threshold ($)		Target ($)	Maximum ($)	All Other Unit Awards: Number of Units (#)(1)	All Other Unit Awards: Number of Securities Underlying Options (#)	Exercise or Base Price of Option Awards ($/Sh)	Grant Date Fair Value of Unit and Option Awards ($)(2)
Kevin L. Foxx	June 20, 2008	—	—	—	—		—	—	65,000	—	—	1,703,000
Michael J. Brochetti	June 20, 2008	—	—	—	—		—	—	50,000	—	—	1,310,000
Alex G. Stallings	June 20, 2008	—	—	—	—		—	—	45,000	—	—	1,179,000
Peter L. Schwiering	June 20, 2008	—	—	—	—		—	—	15,000	—	—	393,000
Jerry A. Parsons	June 20, 2008	—	—	—	—		—	—	20,000	—	—	524,000

(1)		These amounts represent grants of phantom units under our general partner’s Long-Term Incentive Plan. See Note 14 to our Consolidated Financial Statements. These phantom units vested in connection with the Change of Control. See “Compensation Discussion and Analysis—Change of Control.”
(2)		The grant date fair value of these awards is computed in accordance with SFAS 123(R).

Outstanding Equity Awards at Fiscal Year-End 2008

There was no outstanding equity award made to a named executive officer as of December 31, 2008. The Change of Control constituted a change of control under the Plan, which resulted in the early vesting of all awards under the Plan. As such, the phantom units awarded to Messrs. Foxx, Brochetti, Stallings, Schwiering and Parsons are fully vested. The common units underlying such awards were issued to such individuals in August 2008.

Option Exercises and Stock Vested Table for Fiscal 2008

The following table provides information regarding each vesting of phantom units held by our named executive officers in 2008.

	Stock Awards
Name	Number of Shares Acquired on Vesting (#)		Value Realized on Vesting ($) (1)
Kevin L. Foxx		150,000	$	1,580,850
Michael J. Brochetti		90,000		948,510
Alex G. Stallings		75,000		790,425
Peter L. Schwiering		45,000		474,255
Jerry A. Parsons		20,000		210,780

(1) The amounts shown for phantom units are based on the average of the high and low trading prices of our common unit on August 13, 2008, the date of issuance of such common units.

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Director Compensation for Fiscal 2008

Name	Fees Earned or Paid in Cash ($)		Stock Awards ($)			Option Awards ($)		Non-Equity Incentive Plan Compensation ($)		Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)		All Other Compensation ($)		Total ($)
Thomas L. Kivisto(1)....		—		3,361,493	(3)		—		—		—		—		3,361,493
Gregory C. Wallace(1)..		—		3,361,493	(3)		—		—		—		—		3,361,493
W. Anderson Bishop(1)		31,500		97,558	(4)		—		—		—		—		129,058
Brian F. Billings		156,000		126,061	(4)		—		—		—		—		282,061
Edward F. Kosnik		132,000		120,000	(4)		—		—		—		—		252,000
Duke R. Ligon		110,000		205	(5)		—		—		—		—		110,205
Sundar Srinivasan(2)		—		—			—		—		—		—		—
Dave Miller(2)		—		—			—		—		—		—		—
David Bernfeld(2)		—		—			—		—		—		—		—
Gabriel Hammond(2)		—		—			—		—		—		—		—

(1)		Messrs. Kivisto, Wallace and Bishop were removed from the Board in connection with the Change of Control in July 2008.
(2)		Affiliated with Manchester or Alerian.
(3)		These amounts represent the grant date fair value of phantom units awarded under the Plan. The grant date fair value of these awards is computed in accordance with SFAS 123(R). See Note 14 to our Consolidated Financial Statements for assumptions used in calculating these amounts.
(4)		These amounts represent the grant date fair value of restricted units awarded under the Plan. The grant date fair value of these awards is computed in accordance with SFAS 123(R). See Note 14 to our Consolidated Financial Statements for assumptions used in calculating these amounts. These restricted units vested in connection with the Change of Control. These phantom units vested in connection with the Change of Control. The value of these awards for each of Messrs. Bishop, Billings and Kosnik was $41,500 and $12,600 on July 18, 2008, the date that such restricted common units vested, and December 31, 2008, respectively, based upon the closing prices of our common units of $8.30 and $2.52 as reported by Nasdaq on July 18, 2008 and December 31, 2008, respectively.
(5)		These amounts represent the grant date fair value of restricted units awarded under the Plan. The grant date fair value of these awards is computed in accordance with SFAS 123(R). See Note 14 to our Consolidated Financial Statements for assumptions used in calculating these amounts.

Directors who are not officers or employees of the Private Company prior to the Change of Control or any other controlling entity after the Change of Control or their affiliates receive compensation for attending meetings of the board of directors and committees thereof. Prior to the Bankruptcy Filings, such directors received (a) $50,000 per year as an annual retainer fee; (b) $5,000 per year for each committee of the board of directors on which such director served, except that the chairperson of the audit committee received $10,000 per year; (c) $1,500 for each meeting of the board of directors that such director attended; (d) 5,000 restricted common units upon becoming a director, vesting in one-third increments over a three-year period; (e) 1,000 restricted common units on each anniversary of becoming a director, vesting in one-third increments over a three-year period; (f) reimbursement for out-of-pocket expenses associated with attending meetings of the board of directors or committees; and (g) director and officer liability insurance coverage. Each director is fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law. Subsequent to the Bankruptcy Filings, the annual retainer fee was increased to $75,000 and the grants of 1,000 restricted common units upon each anniversary of becoming a director were eliminated. In addition, beginning in 2009, the Chairman of the Board received an additional annual fee of $20,000. As of December 31, 2008, there were 5,000 restricted units outstanding.

Compensation Committee Interlocks and Insider Participation

During the fiscal year ended 2008, the compensation committee of our general partner was comprised of Brian F. Billings, Edward F. Kosnik (chairman since his appointment to the Board in July 2008), Duke R. Ligon and W. Anderson Bishop (prior to his removal from the Board in July 2008 and who served as chairman prior to Mr. Kosnik’s appointment to the Board). No member of the compensation committee was an officer or employee of our general partner. As described above, each of the named executive officers has entered into an employment agreement with our general partner. The base salary amounts payable to such individuals under these agreements were initially determined by the board of directors of our general partner prior to the organization of the conflicts committee. The compensation committee, consisting of independent directors, subsequently ratified these employment agreements including the base salary amounts. Messrs. Foxx and Brochetti served on the board of directors of our general partner when these employment agreements were initially approved, but they did not participate in the approval of their respective employment agreements. In addition, these employment agreements were required to be approved by the management committee of the Private Company’s general partner pursuant to its limited liability company agreement. Mr. Foxx served on this management committee at the time of the approval of such agreements, but did not participate in the approval of his employment agreement.

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Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Security Ownership of Certain Beneficial Owners and Management

The following table sets forth the beneficial ownership of our units as of June 26, 2009 held by:

•

each person who beneficially owns 5% or more of our outstanding units;

•

all of the directors of our general partner;

•

each named executive officer of our general partner; and

•

all directors and officers of our general partner as a group.

Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable. Percentage of total common and subordinated units beneficially owned is based on 21,557,309 common units and 12,570,504 subordinated units outstanding as of June 26, 2009.


Name of Beneficial Owner(1)	Common Units Beneficially Owned		Percentage of Common Units Beneficially Owned			Subordinated Units Beneficially Owned		Percentage of Subordinated Units Beneficially Owned			Percentage of Total Common and Subordinated Units Beneficially Owned
SemGroup Holdings, L.P.(2)		—		*			12,570,504		100	%		36.8	%
Kevin L. Foxx(3)		230,325		1.1	%		—		*			*
Michael J. Brochetti(4)		111,245		*			—		*			*
Alex G. Stallings(5)		91,037		*			—		*			*
Peter L. Schwiering(6)		70,622		*			—		*			*
Jerry A. Parsons(7)		14,910		*			—		*			*
Duke R. Ligon(8)		—		*			—		*			*
Brian F. Billings		10,000		*			—		*			*
Edward F. Kosnik(9)		5,000		*			—		*			*
Gabriel Hammond		—		*			—		*			*
Dave Miller(2) (10)		—		*			—		*			*
David N. Bernfeld(2) (10)		—		*			—		*			*
Swank Capital, LLC(11)		4,990,415		23.2	%		—		*			14.6	%
MSD Capital, L.P.(12)		3,481,994		16.2	%		—		*			10.2	%
Neuberger Berman Inc.(13)		1,503,864		7.0	%		—		*			4.4	%
Costa Brava Partnership III L.P.(14)		1,178,507		5.5	%		—		*			3.5	%
All named executive officers and directors as a group (12 persons)		543,087		2.5	%		—		*			1.6	%

*	Less than 1%

(1)	Unless otherwise indicated, the address for all beneficial owners in this table is Two Warren Place, 6120 South Yale Avenue, Suite 500, Tulsa, Oklahoma 74136.

(2)

The Holdings Credit Agreements are secured by our subordinated units and incentive distribution rights and the membership interests in our general partner owned by SemGroup Holdings. Manchester has not foreclosed on our subordinated units or incentive distribution rights owned by SemGroup Holdings or the membership interests in our general partner but has exercised the voting rights of the membership interests in our general partner and may in the future exercise the voting rights in our subordinated units. In addition, Manchester may in the future exercise other remedies available to them under the Holdings Credit Agreement and related loan documents, including taking action to foreclose on the collateral securing the loan. Neither we nor our general partner is a party to the Holdings Credit Agreements or the related loan documents. The address for SemGroup Holdings is Two Warren Place, 6120 South Yale Avenue, Suite 700, Tulsa, Oklahoma 74136. Because Manchester has the right to direct the voting of our 12,570,504 subordinated units, it may be deemed to be the beneficial owner of such units. The address for Manchester is 712 Fifth Avenue, New York, NY 10019.

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(3)	Mr. Foxx may be deemed to be the beneficial owner of 20,000 common units held by his wife and 10,000 common units held by his daughter. Substantially all the common units owned by Mr. Foxx are held in a margin account.

(4)	Substantially all the common units owned by Mr. Brochetti are held in a margin account.

(5)	Substantially all the common units owned by Mr. Stallings are held in a margin account.

(6)	Substantially all the common units owned by Mr. Schwiering are held in a margin account.

(7)	Mr. Parsons has shared investment power with respect to the 14,910 common units that are jointly held with his spouse.

(8)	Does not include unvested restricted units granted under the Plan, none of which will vest within 60 days of the date hereof.

(9)	Mr. Kosnik has shared investment power with respect to the 5,000 common units that are jointly held with his spouse.

(10)	Messrs. Miller and Bernfeld are affiliated with Elliott Associates, L.P. Manchester, a wholly-owned subsidiary of Elliott Associates, L.P., entered into the Holdings Credit Agreements with SemGroup Holdings.

(11)

Based on a Schedule 13G/A, dated February 17, 2009, filed by Swank Capital, LLC with the SEC. The filing is made jointly with Swank Energy Income Advisors, LP and Jerry V. Swank. The filers report that Swank Capital, LLC and Jerry V. Swank have sole voting power and Swank Energy Income Advisors, LP has shared voting power with respect to the 4,990,415 common units and that their address is 3300 Oak Lawn Avenue, Suite 650, Dallas, TX 75219.

(12)

Based on a Schedule 13G/A, dated June 16, 2009, filed by MSD Capital, L.P. with the SEC as updated by Forms 4 filed with the SEC through June 19, 2009. The filing is made jointly with MSD Torchlight, L.P. The filers report that they have shared voting power with respect to the common units and that their address is 645 Fifth Avenue, 21st Floor, New York, New York 10022.

(13)

Based on a Schedule 13G, dated June 11, 2009, filed by Neuberger Berman Inc. with the SEC. The filing is made jointly with Neuberger Berman, LLC. The filers report that they own 1,503,864 common units and that both filers have sole voting power with respect to 1,340,004 common units and shared dispositive power with respect to 1,503,864 common units. Their address as reported in such Schedule 13G is 605 Third Avenue, New York, New York 10158.

(14)

Based on a Schedule 13G, dated December 22, 2008, filed by Costa Brava Partnership III L.P. with the SEC. The filing is made jointly with Roark, Rearden & Hamot, LLC and Seth W. Hamot. The filers report that they each have sole voting power with respect to the 1,178,507 common units and that their address is 420 Boylston Street, Boston, MA 02116.

Securities Authorized for Issuance under Equity Compensation Plans

Equity Compensation Plan Information (1)

	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights		(b) Weighted-average exercise price of outstanding options, warrants and rights		(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders		—		N/A		N/A
Equity compensation plans not approved by security holders		5,000	$	0		380,000
Total		5,000	$	0		380,000

(1) Our general partner has adopted and maintains the Plan for employees, consultants and directors of our general partner and its affiliates (including the Private Company prior to the Change of Control) who perform services for us. All outstanding awards under the Plan on the date of the Change of Control vested due to such Change of Control. In connection with Mr. Duke R. Ligon’s appointment to the Board, the compensation committee awarded him a restricted unit grant 5,000 units under the Plan. No value is shown in column (b) of the table because the restricted units do not have an exercise price. For more information about the Plan, which did not require approval by our unitholders, please see “Item 11—Executive Compensation—Compensation Discussion and Analysis—Long-Term Incentive Plan.”

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Item 13. Certain Relationships and Related Transactions, and Director Independence.

Distributions and Payments to Our General Partner and Its Affiliates

Our general partner is a subsidiary of SemGroup Holdings, which owns 12,570,504 subordinated units representing an aggregate 36.8% limited partner interest in us as of June 26, 2009. In addition, our general partner owns a 2% general partner interest in us and the incentive distribution rights.

The following table summarizes the distributions and payments made by us to our general partner and its affiliates in connection with the formation of SemGroup Energy Partners, L.P. and to be made to us by our general partner and its affiliates in connection with the ongoing operation and liquidation of SemGroup Energy Partners, L.P. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Formation Stage

The consideration received by the Private Company and its subsidiaries for the contribution of the assets and liabilities to us

· 12,500,000 common units;

· 12,570,504 subordinated units;

· 549,908 general partner units;

· the incentive distribution rights; and

· $137.5 million cash payment from the proceeds of borrowings under our credit facility.

Operational Stage

Distributions of available cash to our general partner and its affiliates

Unless restricted by the terms of our credit agreement, we will generally make cash distributions 98% to our unitholders pro rata, including our general partner and its affiliates, as the holder of 12,570,504 subordinated units, and 2% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target distribution level.

Payments to our general partner and its affiliates

We will reimburse our general partner for the payment of certain operating expenses and for the provision of various general and administrative services for our benefit. Prior to the Settlement, we reimbursed the Private Company for such services. Please see “—Agreements Relating to Our Acquisition of the Asphalt Assets—Amended Omnibus Agreement—Reimbursement of General and Administrative Expenses.”

Withdrawal or removal of our general partner

If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.

Liquidation Stage

Liquidation

Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

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Agreements Relating to Our Initial Public Offering

In connection with our initial public offering, we and other parties entered into various documents and agreements relating to, among other things, the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries. These agreements were not the result of arm’s-length negotiations, and they, or any of the transactions that they provide for, may not have been effected on terms at least as favorable to the parties to these agreements as they could have been obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, were paid from the proceeds of our initial public offering.

Omnibus Agreement

In connection with our initial public offering, we entered into an Omnibus Agreement with the Private Company and our general partner that addresses the reimbursement of our general partner for costs incurred on our behalf and indemnification matters. Concurrently with the closing of the acquisition of our asphalt assets on February 20, 2008, we amended and restated this Omnibus Agreement. For a description of the Amended Omnibus Agreement, please see “—Agreements Relating to Our Acquisition of the Asphalt Assets—Amended Omnibus Agreement.”

Throughput Agreement

In connection with our initial public offering, we entered into the Throughput Agreement with the Private Company. Prior to the Order and the Settlement, a substantial portion of our revenues were derived from services provided to the crude oil purchasing, marketing and distribution operations of the Private Company pursuant to this agreement. None of these revenues are reflected in the historical financial statements of our predecessor. Under this agreement, we provided crude oil gathering and transportation services and terminalling and storage services to the Private Company. Under the Throughput Agreement, certain services were subject to minimum requirements each month, regardless of the amount of such services actually used by the Private Company in a given month. The Throughput Agreement did not apply to any services we provided to customers other than the Private Company. We generated revenues of approximately $78.0 million from the Private Company with respect to services provided pursuant to the Throughput Agreement during fiscal 2008. In connection with the Settlement, the Throughput Agreement was rejected as part of the Bankruptcy Cases.

Agreements Relating to Our Acquisition of the Asphalt Assets

Purchase and Sale Agreement for the Asphalt Assets

On January 14, 2008, we entered into a purchase and sale agreement with the Private Company pursuant to which we acquired the Acquired Asphalt Assets on February 20, 2008 from the Private Company for aggregate consideration of $379.5 million, including $0.7 million of acquisition-related costs. For accounting purposes, the acquisition has been reflected as a purchase of assets, with the Acquired Asphalt Assets recorded at the historical cost of the Private Company, which was approximately $145.5 million, with the additional purchase price of $234.0 million reflected in the statement of changes in partners’ capital as a distribution to the Private Company. In conjunction with the purchase of the Acquired Asphalt Assets, we amended our existing credit facility, increasing our borrowing capacity to $600 million. Concurrently, we issued 6,000,000 common units, receiving proceeds, net of underwriting discounts and offering-related costs, of $137.2 million. Our general partner also made a capital contribution of $2.9 million to maintain its 2.0% general partner interest in us. On March 5, 2008, we issued an additional 900,000 common units, receiving proceeds, net of underwriting discounts, of $20.6 million, in connection with the underwriters’ exercise of their over-allotment option in full. Our general partner made a corresponding capital contribution of $0.4 million to maintain its 2.0% general partner interest in us. In connection with the acquisition of the Acquired Asphalt Assets, we entered into the Terminalling Agreement with the Private Company and certain of its subsidiaries under which we provided liquid asphalt cement terminalling and storage and throughput services to the Private Company and the Private Company agreed to use our services at certain minimum levels (see “—Terminalling Agreement”). In connection with the Settlement, the Private Company rejected the Terminalling Agreement. Our general partner’s Board approved the acquisition of the Acquired Asphalt Assets as well as the terms of the related agreements based on a recommendation from its conflicts committee, which consisted entirely of independent directors. The conflicts committee retained independent legal and financial advisors to assist it in evaluating the transaction and considered a number of factors in approving the acquisition, including an opinion from the committee’s independent financial advisor that the consideration paid for the Acquired Asphalt Assets was fair, from a financial point of view, to us.

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Amended Omnibus Agreement

Concurrently with the closing of the acquisition of our asphalt assets on February 20, 2008, we amended and restated the Omnibus Agreement that we entered into with the Private Company, our general partner and others, as described herein. The events related to the Bankruptcy Filings terminated the Private Company’s obligations to provide services to us under the Amended Omnibus Agreement. The Private Company continued to provide such services to us until the effective date of the Settlement at which time the Private Company rejected the Amended Omnibus Agreement and we and the Private Company entered into the Shared Services Agreement and the Transition Services Agreement relating to the provision of such services (see “Item 1. Business—Impact of the Bankruptcy of the Private Company and Certain of its Subsidiaries and Related Events—Settlement with the Private Company”).

Under the Amended Omnibus Agreement, we reimbursed the Private Company for the payment of certain operating expenses and for the provision of various general and administrative services for our benefit with respect to the Crude Oil Business and our asphalt business. Under the Amended Omnibus Agreement, the fixed administrative fee that we paid to the Private Company for providing general and administrative services to us increased to $7.0 million per year from $5.0 million per year in the original Omnibus Agreement. We also were obligated to reimburse the Private Company for operating expenses, which were not included in the $7.0 million annual fixed administrative fee, to the extent incurred by the Private Company on our behalf. Such operating expenses primarily included compensation of operational personnel performing services for our benefit and the cost of their employee benefits and insurance coverage expenses the Private Company incurred with respect to our business and operations.

Under the Amended Omnibus Agreement, the Private Company indemnified us for certain potential environmental claims, losses and expenses. In addition, the Amended Omnibus Agreement contained non-competition and right of first refusal provisions. In connection with the Settlement, the Amended Omnibus Agreement, including the indemnification, non-competition and right of first refusal provisions therein, was rejected as part of the Bankruptcy Cases.

Terminalling Agreement

In connection with our acquisition of the asphalt assets, we entered into the Terminalling Agreement with the Private Company. Prior to the Settlement, a substantial portion of our revenues were derived from services provided to the finished asphalt product processing and marketing operations of the Private Company pursuant to this agreement. Under this agreement, we provided asphalt terminalling and storage services to the Private Company. Such services were subject to minimum throughput requirements each month, regardless of the amount of such services actually used by the Private Company in a given month. The Terminalling Agreement did not apply to any services we provided to customers other than the Private Company. We generated revenues of approximately $53.0 million, excluding fuel surcharge revenues related to fuel and power consumed to operate our asphalt storage tanks, from the Private Company with respect to services provided pursuant to the Terminalling Agreement during fiscal 2008. In connection with the Settlement, the Terminalling Agreement was rejected as part of the Bankruptcy Cases.

Access and Use Agreement

In connection with our acquisition of our asphalt assets, we entered into a terminal access and use agreement, which we refer to as the Access and Use Agreement, with the Private Company. Pursuant to the Access and Use Agreement, the Private Company reserved the right to access facilities used for both terminalling and storage of liquid asphalt cement and processing of finished asphalt products. In addition, pursuant to the Access and Use Agreement we were indemnified for any losses that occur from the Private Company’s operations at or relating to our asphalt assets. In connection with the Settlement, the Access and Use Agreement was rejected as part of the Bankruptcy Cases.

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Agreements Relating to Other Acquisitions from the Private Company

On May 12, 2008, we entered into a purchase and sale agreement with the Private Company, pursuant to which we acquired the Acquired Pipeline Assets from the Private Company for aggregate consideration of $45.1 million, including $0.1 million of acquisition-related costs. The acquisition was funded with borrowings under our revolving credit facility. We have suspended capital expenditures on this pipeline due to the continuing impact of the Bankruptcy Filings. Management currently intends to put the asset into service in early 2010 and is exploring various alternatives to complete the project. The Board approved the acquisition of the Acquired Pipeline Assets based on a recommendation from its conflicts committee, which consisted entirely of independent directors. The conflicts committee retained independent legal and financial advisors to assist it in evaluating the transaction and considered a number of factors in approving the acquisition, including an opinion from the committee’s independent financial advisor that the consideration paid for the Acquired Pipeline Assets was fair, from a financial point of view, to us.

On May 20, 2008, we entered into a purchase and sale agreement with the Private Company, pursuant to which we acquired the Acquired Storage Assets from the Private Company for aggregate consideration of $90.3 million, including $0.3 million of acquisition-related costs. The acquisition was funded with borrowings under our revolving credit facility. The Board approved the acquisition of the Acquired Storage Assets based on a recommendation from its conflicts committee, which consisted entirely of independent directors. The conflicts committee retained independent legal and financial advisors to assist it in evaluating the transaction and considered a number of factors in approving the acquisition, including an opinion from the committee’s independent financial advisor that the consideration paid for the Acquired Storage Assets was fair, from a financial point of view, to us.

Agreements Relating to the Settlement with the Private Company

In connection with the Settlement, we entered into various agreements with the Private Company. These agreements are discussed in more detail below.

Shared Services Agreement

In connection with the Settlement, we entered into the Shared Services Agreement with the Private Company. Pursuant to the Shared Services Agreement, the Private Company will provide certain general shared services, Cushing shared services (as described below), and SCADA services (as described below) to us. In addition, we pay a general administrative fee to the Private Company under the Shared Services Agreement. This general administrative fee was approximately $10,000 for the month of May 2009.

The general shared services include crude oil movement services, Department of Transportation services, right-of-way services, environmental services, pipeline and civil structural maintenance services, safety services, pipeline truck station maintenance services, project support services and truck dispatch services. The fees for such general shared services are fixed at $125,000 for the month of April 2009. Thereafter the fees will be calculated in accordance with the formulas contained therein. For example, in the month of May 2009, the fees for such general shared services were approximately $123,000. The Private Company has agreed to provide the general shared services for three years (subject to earlier termination as provided therein) and the term may be extended an additional year by mutual agreement of the parties.

The Cushing shared services include operational and maintenance services related to terminals at Cushing, Oklahoma. The fees for such Cushing shared services are fixed at $20,000 for the month of April 2009. Thereafter the fees will be calculated in accordance with the formulas contained therein. For example, in the month of May 2009, the fees for such Cushing shared services were approximately $25,000. The Private Company has agreed to provide the Cushing shared services for three years (subject to earlier termination as provided therein) and the term may be extended an additional year by mutual agreement of the parties.

The SCADA services include services related to the operation of the SCADA system which is used in connection with our crude oil operations. The fees for such SCADA services are fixed at $15,000 for the month of April 2009. Thereafter the fees will be calculated in accordance with the formulas contained therein. For example, in the month of May 2009, the fees for such SCADA services were approximately $10,000. The Private Company has agreed to provide the SCADA services for five years (subject to earlier termination as provided therein) and we may elect to extend the term for two subsequent five year periods.

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Transition Services Agreement

In connection with the Settlement, we entered into the Transition Services Agreement with the Private Company. Pursuant to the Transition Services Agreement, the Private Company will provide certain corporate, crude oil and asphalt transition services, in each case for a limited amount of time, to us. During the month of April and May 2009, we incurred fees of approximately $1.1 million and $0.2 million, respectively, under the Transition Services Agreement. We expect future fees under the Transition Services Agreement to decrease as services are transitioned from the Private Company to us and the agreement is eventually terminated.

Transfer of Crude Oil Assets

In connection with the Settlement, we transferred certain crude oil assets located in Kansas and northern Oklahoma to the Private Company. These transfers included real property and associated personal property at locations where the Private Company owned the pipeline. We retained certain access and connection rights to enable us to continue to operate our crude oil trucking business in such areas. In addition, we transferred our interests in the SCADA System, a crude oil inventory tracking system, to the Private Company.

In addition, the Private Company transferred to us (i) 355,000 barrels of crude oil line fill and tank bottoms, which are necessary for us to operate our crude oil tank storage operations and our Oklahoma and Texas crude oil pipeline systems, (ii) certain personal property located in Oklahoma, Texas and Kansas used in connection with our crude oil trucking business and (iii) certain real property located in Oklahoma, Kansas, Texas and New Mexico that was intended to be transferred in connection with our initial public offering.

Management is obtaining independent valuations of the assets transferred.

Transfer of Asphalt Assets

In connection with the Settlement, the Private Company transferred certain asphalt processing assets that were connected to, adjacent to, or otherwise contiguous with our existing asphalt facilities and associated real property interests to us. The transfer of the Private Company’s asphalt assets in connection with the Settlement provides us with outbound logistics for our existing asphalt assets and, therefore, allows us to provide asphalt terminalling, storage and processing services to third parties. Management is obtaining independent valuations of the assets transferred.

New Throughput Agreement

In connection with the Settlement, we and the Private Company entered into the New Throughput Agreement pursuant to which we provide certain crude oil gathering, transportation, terminalling and storage services to the Private Company.

Under the New Throughput Agreement, we charge the following fees: (i) barrels gathered via gathering lines will be charged a gathering rate of $0.75 per barrel, (ii) barrels transported within Oklahoma will be charged $1.00 per barrel while barrels transported on the Masterson Mainline will be charged $0.55 per barrel, (iii) barrels transported by truck will be charged in accordance with the schedule contained therein, including a fuel surcharge, (iv) storage fees shall equal $0.50 per barrel per month for product located in storage tanks located in Cushing, Oklahoma and $0.44 per barrel per month for product not located in dedicated Cushing storage tanks, and (v) a delivery charge of $0.08 per barrel will be charged for deliveries out of the Cushing Interchange Terminal. The New Throughput Agreement has an initial term of one year with additional automatic one-month renewals unless either party terminates the agreement upon thirty-days prior notice.

New Terminalling and Storage Agreement

In connection with the Settlement, we and the Private Company entered into the Terminalling and Storage Agreement pursuant to which we provide certain asphalt terminalling and storage services for the remaining asphalt inventory of the Private Company. Storage services under the New Terminalling Agreement are equal to $0.565 per barrel per month multiplied by the total shell capacity in barrels for each storage tank where the Private Company and its affiliates have product; provided that if the Private Company removes all product from a storage tank prior to the end of the month, then the storage service fees shall be pro-rated for such month based on the number of calendar days storage was actually used. Throughput fees under the New Terminalling Agreement are equal to $9.25 per ton; provided that no fees are payable for transfers of product between storage tanks located at the same or different terminals. The New Terminalling Agreement has an initial term that expires on October 31, 2009, which may be extended for one month by mutual agreement of the parties.

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New Access and Use Agreement

In connection with the Settlement, we and the Private Company entered into the New Access and Use Agreement pursuant to which we will allow the Private Company access rights to our asphalt facilities relating to its existing asphalt inventory. The term of the Access and Use Agreement will end separately for each terminal upon the earlier of October 31, 2009 or until all of the existing asphalt inventory of the Private Company is removed from such terminal.

Trademark Agreement

In connection with the Settlement, we and the Private Company entered into the Trademark License Agreement pursuant to which the Private Company granted us a non-exclusive, worldwide license to use certain trade names, including the name “SemGroup”, and the corresponding mark until December 31, 2009, and the Private Company waived claims for infringement relating to such trade names and mark prior to the effective date of the Trademark Agreement.

Building and Office Leases

In connection with the Settlement, we leased office space in Oklahoma City, Oklahoma and certain facilities in Cushing, Oklahoma to the Private Company. We collect rental fees of approximately $19,000 per month as a result of these leases. The term for the leases expires on March 31, 2014.

Easements

In connection with the Settlement, we and the Private Company granted mutual easements relating to access, facility improvements, existing and future pipeline rights and corresponding rights of ingress and egress for properties owned by the parties at Cushing, Oklahoma. In addition, we granted the Private Company certain pipeline easements at Cushing, Oklahoma, together with the corresponding rights of ingress and egress.

Indemnification of Directors and Officers

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

·	our general partner;

·	any departing general partner;

·	any person who is or was an affiliate of a general partner or any departing general partner;

·	any person who is or was a director, officer, member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points;

·	any person who is or was serving as director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and

·	any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

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We and our general partner have also entered into separate indemnification agreements with each of the directors and officers of our general partner. The terms of the indemnification agreements are consistent with the terms of the indemnification provided by our partnership agreement and our general partner’s limited liability company agreement. The indemnification agreements also provide that we and our general partner must advance payment of certain expenses to such indemnified directors and officers, including fees of counsel, subject to receipt of an undertaking from the indemnitee to return such advance if it is it is ultimately determined that the indemnitee is not entitled to indemnification.

Other Related Party Transactions

Mr. Ligon, a member of the Board, also serves as a member of the board of directors of the general partner of TEPPCO Partners, L.P. (“TEPPCO”). We provide crude oil gathering and transportation services to TEPPCO. During the year ended December 31, 2008, we earned revenue of approximately $1.3 million from services provided to TEPPCO, and as of December 31, 2008, we have a receivable in the amount of approximately $0.7 million as a result of services provided to TEPPCO.

During 2008, Mr. Wallace, a former member of the Board, served on the board of directors of the F&M Bank & Trust Company. We lease transport trucks and trailers in connection with our crude oil gathering and transportation services from Harvard Capital, Inc., a subsidiary of F&M Bank & Trust Company. During the year ended December 31, 2008, we made payments of $2.2 million to Harvard Capital Inc., and as of December 31, 2008, we have future commitments to Harvard Capital, Inc. totaling $7.7 million. In addition, during 2008, Mr. Kivisto, a former member of the Board, served on the board of directors of the BOK Financial Corporation. We have a banking relationship with Bank of Oklahoma, which is a subsidiary of BOK Financial Corporation.

Approval and Review of Related Party Transactions

If we contemplate entering into a transaction, other than a routine or in the ordinary course of business transaction, in which a related person will have a direct or indirect material interest, the proposed transaction is submitted for consideration to the Board of our general partner or to our management, as appropriate. If the Board is involved in the approval process, it determines whether to refer the matter to the conflicts committee of the Board, as constituted under our limited partnership agreement. If a matter is referred to the conflicts committee, it obtains information regarding the proposed transaction from management and determines whether to engage independent legal counsel or an independent financial advisor to advise the members of the committee regarding the transaction. If the conflicts committee retains such counsel or financial advisor, it considers such advice and, in the case of a financial advisor, such advisor’s opinion as to whether the transaction is fair and reasonable to us and to our unitholders.

Director Independence

Please see “Item 10—Directors, Executive Officers and Corporate Governance—Directors, Executive Officers and Corporate Governance” of this report for a discussion of director independence matters.

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Item 14. Principal Accountant Fees and Services.

We have engaged PricewaterhouseCoopers LLP as our principal accountant. The following table summarizes fees we have paid PricewaterhouseCoopers LLP for independent auditing, tax and related services for each of the last two fiscal years:

	Year Ended December 31,
	2007		2008
Audit fees (1)	$	586,500	$	887,600
Audit-related fees (2)		—		—
Tax fees (3)		303,856		290,213
All other fees (4)		—		—

(1)

Audit fees represent amounts billed for each of the years presented for professional services rendered in connection with (a) the audit of our annual financial statements and internal controls over financial reporting, (b) the review of our quarterly financial statements and (c) those services normally provided in connection with statutory and regulatory filings or engagements, including comfort letters, consents and other services related to SEC matters. In addition to the amounts presented above, we have incurred $1.0 million in audit fees in 2009 related to the fiscal year 2008 audit and investigation performed by the internal review subcommittee of the Board.

(2)

Audit-related fees represent amounts we were billed in each of the years presented for assurance and related services that are reasonably related to the performance of the annual audit or quarterly reviews, and include fees incurred in connection with our initial public offering.

(3)

Tax fees represent amounts we were billed in each of the years presented for professional services rendered in connection with tax compliance, tax advice and tax planning. This category primarily includes services relating to the preparation of unitholder annual K-1 statements.

(4)

All other fees represent amounts we were billed in each of the years presented for services not classifiable under the other categories listed in the table above.

All audit and non-audit services provided by PricewaterhouseCoopers LLP are subject to pre-approval by our audit committee to ensure that the provisions of such services do not impair the auditor’s independence. Under our pre-approval policy, the audit committee is informed of each engagement of the independent auditor to provide services under the policy. The audit committee of our general partner has approved the use of PricewaterhouseCoopers LLP as our independent principal accountant.

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PART IV

Item 15. Exhibits, Financial Statement Schedules.

(a) Financial Statements and Schedules

(1)

See the Index to Financial Statements on page F-1.

(2)

All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto

(3) Exhibits

Exhibit Number	Description
3.1	Certificate of Limited Partnership of SemGroup Energy Partners, L.P. (the “Partnership”), dated February 22, 2007 (filed as Exhibit 3.1 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-141196), filed March 9, 2007, and incorporated herein by reference).
3.2	First Amended and Restated Agreement of Limited Partnership of the Partnership, dated July 20, 2007 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed July 25, 2007, and incorporated herein by reference).
3.3	Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of the Partnership, effective as of July 20, 2007 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed on April 14, 2008, and incorporated herein by reference).
3.4	Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of the Partnership, dated June 25, 2008 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed on June 30, 2008, and incorporated herein by reference).
3.5	Certificate of Formation of SemGroup Energy Partners G.P., L.L.C. (the “General Partner”), dated February 22, 2007 (filed as Exhibit 3.3 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-141196), filed March 9, 2007, and incorporated herein by reference).
3.6	Amended and Restated Limited Liability Company Agreement of the General Partner, dated July 20, 2007 (filed as Exhibit 3.2 to the Partnership’s Current Report on Form 8-K, filed July 25, 2007, and incorporated herein by reference).
3.7	Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of the General Partner, dated June 25, 2008 (filed as Exhibit 3.2 to the Partnership’s Current Report on Form 8-K, filed on June 30, 2008, and incorporated herein by reference).
3.8	Amendment No. 2 to Amended and Restated Limited Liability Company Agreement of the General Partner, dated July 18, 2008 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed on July 22, 2008, and incorporated herein by reference).
4.1	Specimen Unit Certificate (included in Exhibit 3.2).
10.1	Credit Agreement, dated July 20, 2007, among the Partnership, Wachovia Bank, National Association, as Administrative Agent, L/C Issuer and Swing Line Lender, Bank of America, N.A., as Syndication Agent and the other lenders from time to time party thereto (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed July 25, 2007, and incorporated herein by reference).
10.2	Amended and Restated Credit Agreement, dated February 20, 2008, among the Partnership, Wachovia Bank, National Association, as Administrative Agent, L/C Issuer and Swing Line Lender, Bank of America, N.A., as Syndication Agent and the other lenders from time to time party thereto (filed as Exhibit 10.4 to the Partnership’s Current Report on Form 8-K, filed February 25, 2008, and incorporated herein by reference).
10.3	Forbearance Agreement and Amendment to Credit Agreement, dated September 12, 2008 but effective as of September 18, 2008, by and among SemGroup Energy Partners, L.P., Wachovia Bank, National Association, as Administrative Agent, L/C Issuer and Swing Line Lender, and the Lenders party thereto (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed on September 22, 2008, and incorporated herein by reference).
10.4	First Amendment to Forbearance Agreement and Amendment to Credit Agreement, dated as of December 11, 2008, by and among SemGroup Energy Partners, L.P., Wachovia Bank, National Association, as Administrative Agent, L/C Issuer and Swing Line Lender, and the Lenders party thereto (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed on December 12, 2008, and incorporated herein by reference).

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Exhibit Number	Description
10.5	Second Amendment to Forbearance Agreement and Amendment to Credit Agreement, dated as of December 18, 2008, by and among SemGroup Energy Partners, L.P., Wachovia Bank, National Association, as Administrative Agent, L/C Issuer and Swing Line Lender, and the Lenders party thereto (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed on December 19, 2008, and incorporated herein by reference).
10.6	Third Amendment to Forbearance Agreement and Amendment to Credit Agreement, dated as of March 17, 2009, by and among SemGroup Energy Partners, L.P., Wachovia Bank, National Association, as Administrative Agent, L/C Issuer and Swing Line Lender, and the Lenders party thereto (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed on March 19, 2009, and incorporated herein by reference).
10.7	Consent, Waiver and Amendment to Credit Agreement, dated as of April 7, 2009, by and among SemGroup Energy Partners, L.P., as Borrower, SemGroup Energy Partners G.P., L.L.C., SemGroup Energy Partners Operating, L.L.C., SemMaterials Energy Partners, L.L.C., SemGroup Energy Partners, L.L.C., SemGroup Crude Storage, L.L.C., SemPipe, L.P., SemPipe G.P., L.L.C. and SGLP Management, Inc., as Guarantors, Wachovia Bank, National Association, as Administrative Agent, L/C Issuer and Swing Line Lender, and the Lenders party thereto (filed as Exhibit 10.14 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.8*	Amendment to Credit Agreement, dated as of May 19, 2009, by and among SemGroup Energy Partners, L.P., the Guarantors, Wachovia Bank, National Association, as Administrative Agent, L/C Issuer and Swing Line Lender, and the Lenders party thereto.
10.9†	SemGroup Energy Partners G.P., L.L.C. Long-Term Incentive Plan (filed as Exhibit 10.5 to the Partnership’s Current Report on Form 8-K, filed July 25, 2007, and incorporated herein by reference).
10.10†	Amendment to the SemGroup Energy Partners G.P., L.L.C. Long Term Incentive Plan (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed on December 23, 2008, and incorporated herein by reference).
10.11†	Form of Employment Agreement (filed as Exhibit 10.6 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-141196), filed May 25, 2007, and incorporated herein by reference).
10.12†	Form of Employment Agreement (filed as Exhibit 10.14 to the Partnership’s Quarterly Report on Form 10-Q, filed on March 23, 2009, and incorporated herein by reference).
10.13†	Form of Indemnification Agreement (filed as Exhibit 10.7 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-141196), filed May 25, 2007, and incorporated herein by reference).
10.14†	Form of Phantom Unit Agreement (filed as Exhibit 10.8 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-141196), filed May 25, 2007, and incorporated herein by reference).
10.15†	Form of Phantom Unit Agreement (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed on June 24, 2008, and incorporated herein by reference).
10.16†	Form of Phantom Unit Agreement (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed on June 24, 2008, and incorporated herein by reference).
10.17†	Form of Phantom Unit Agreement (filed as Exhibit 10.15 to the Partnership’s Quarterly Report on Form 10-Q, filed on March 23, 2009, and incorporated herein by reference).
10.18†	Form of Retention Agreement (filed as Exhibit 10.16 to the Partnership’s Quarterly Report on Form 10-Q, filed on March 23, 2009, and incorporated herein by reference).
10.19†	Form of Restricted Unit Agreement (filed as Exhibit 10.9 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-141196), filed May 25, 2007, and incorporated herein by reference).
10.20†	Form of Director Restricted Common Unit Agreement (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed on December 23, 2008, and incorporated herein by reference).

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Exhibit Number	Description
10.21†	Form of Director Restricted Subordinated Unit Agreement (filed as Exhibit 10.3 to the Partnership’s Current Report on Form 8-K, filed on December 23, 2008, and incorporated herein by reference).
10.22†*	SemGroup Energy Partners G.P., L.L.C. 2009 Executive Cash Bonus Plan
10.23	Closing Contribution, Conveyance, Assignment and Assumption Agreement, dated July 20, 2007, among the Partnership, the General Partner, SemCrude, L.P., SemGroup, L.P. and SemGroup Energy Partners Operating, L.L.C. (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed July 25, 2007, and incorporated herein by reference).
10.24	Purchase and Sale Agreement, dated as of January 14, 2008, by and among SemMaterials, L.P. and SemGroup Energy Partners Operating, L.L.C. (filed as Exhibit 2.1 to the Partnership’s Current Report on Form 8-K, filed on January 15, 2008, and incorporated herein by reference).
10.25	Purchase and Sale Agreement, dated as of May 12, 2008, by and between SemCrude, L.P. and SemGroup Energy Partners, L.L.C. (filed as Exhibit 2.1 to the Partnership’s Current Report on Form 8-K, filed on May 15, 2008, and incorporated herein by reference).
10.26	Purchase and Sale Agreement, dated as of May 20, 2008, by and between SemGroup Energy Partners, L.L.C. and SemCrude, L.P. (filed as Exhibit 2.1 to the Partnership’s Current Report on Form 8-K, filed on May 23, 2008, and incorporated herein by reference).
10.27	Omnibus Agreement, dated July 20, 2007, among the Partnership, the General Partner, SemGroup, L.P. and SemManagement, L.L.C. (filed as Exhibit 10.3 to the Partnership’s Current Report on Form 8-K, filed July 25, 2007, and incorporated herein by reference).
10.28	Amended and Restated Omnibus Agreement, dated as of February 20, 2008, by and among SemGroup, L.P., SemManagement, L.L.C., SemMaterials, L.P., the Partnership, SemGroup Energy Partners G.P., L.L.C. and SemMaterials Energy Partners, L.L.C. (filed as Exhibit 10.3 to the Partnership’s Current Report on Form 8-K, filed February 25, 2008, and incorporated herein by reference).
10.29#	Throughput Agreement, dated July 20, 2007, among the Partnership, SemGroup Energy Partners, L.L.C., SemCrude, L.P., Eaglwing, L.P. and SemGroup, L.P. (filed as Exhibit 10.4 to the Partnership’s Current Report on Form 8-K, filed July 25, 2007, and incorporated herein by reference).
10.30#	Terminalling and Storage Agreement, dated as of February 20, 2008, by and between SemMaterials, L.P. and SemMaterials Energy Partners, L.L.C. (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed February 25, 2008, and incorporated herein by reference).
10.31	Terminal Access and Use Agreement, dated as of January 28, 2008, by and among SemMaterials Energy Partners, L.L.C., SemMaterials, L.P. and K.C. Asphalt, L.L.C. (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed February 25, 2008, and incorporated herein by reference).
10.32	Agreed Order of the United States Bankruptcy Court for the District of Delaware Regarding Motion by SemGroup Energy Partners, L.P. (i) to Compel Debtors to Provide Adequate Protection and (ii) to Modify the Automatic Stay (filed as Exhibit 99.1 to the Partnership’s Current Report on Form 8-K, filed on September 9, 2008, and incorporated herein by reference).
10.33	Master Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and among by and among SemGroup, L.P., SemManagement, L.L.C., SemOperating G.P., L.L.C., SemMaterials, L.P., K.C. Asphalt, L.L.C., SemCrude, L.P., Eaglwing, L.P., SemGroup Holdings, L.P., SemGroup Energy Partners, L.P., SemGroup Energy Partners G.P., L.L.C., SemGroup Energy Partners Operating, L.L.C., SemGroup Energy Partners, L.L.C., SemGroup Crude Storage, L.L.C., SemPipe, L.P., SemPipe G.P., L.L.C., SGLP Management, Inc. and SemMaterials Energy Partners, L.L.C. (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.34	Shared Services Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and among SemGroup Energy Partners, L.P., SemGroup Energy Partners, L.L.C., SemGroup Crude Storage, L.L.C., SemPipe G.P., L.L.C., SemPipe, L.P., SemCrude, L.P. and SemManagement, L.L.C. (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).

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Exhibit Number	Description
10.35	Transition Services Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and among SemGroup Energy Partners, L.P., SemGroup Energy Partners, L.L.C., SemGroup Crude Storage, L.L.C., SemPipe G.P., L.L.C., SemPipe, L.P., SemMaterials Energy Partners, L.L.C., SGLP Asphalt L.L.C., SemCrude, L.P., SemGroup, L.P., SemMaterials, L.P. and SemManagement, L.L.C. (filed as Exhibit 10.3 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.36	Contribution, Conveyance, Assignment and Assumption Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and among SemMaterials, L.P., K.C. Asphalt, L.L.C., SGLP Asphalt, L.L.C. and SemMaterials Energy Partners, L.L.C. (filed as Exhibit 10.4 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.37	Membership Interest Transfer Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and between SemMaterials, L.P. and SemMaterials Energy Partners, L.L.C. (filed as Exhibit 10.5 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.38	Throughput Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and among SemGroup Energy Partners, L.L.C. and SemCrude, L.P. (filed as Exhibit 10.6 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.39	Terminalling and Storage Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and between SemMaterials Energy Partners, L.L.C. and SemMaterials, L.P. (filed as Exhibit 10.7 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.40	Access and Use Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and between SemMaterials, L.P. and SemMaterials Energy Partners, L.L.C. (filed as Exhibit 10.8 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.41	Trademark License Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and among SemGroup, L.P., SemMaterials, L.P. and SemGroup Energy Partners, L.P. (filed as Exhibit 10.9 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.42	Office Lease, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and between SemGroup Energy Partners, L.L.C. and SemCrude, L.P. (filed as Exhibit 10.10 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.43	Building Lease, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and between SemGroup Energy Partners, L.L.C. and SemCrude, L.P. (filed as Exhibit 10.11 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.44	Mutual Easement Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, among SemCrude, L.P., SemGroup Energy Partners, L.L.C., and SemGroup Crude Storage, L.L.C. (filed as Exhibit 10.12 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.45	Pipeline Easement Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and among White Cliffs Pipeline, L.L.C., SemGroup Energy Partners, L.L.C., and SemGroup Crude Storage, L.L.C. (filed as Exhibit 10.13 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).

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Exhibit Number	Description
10.46	Term Sheet, dated as of March 6, 2009 (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed on March 10, 2009, and incorporated herein by reference).
21.1*	List of Subsidiaries of SemGroup Energy Partners, L.P.
23.1*	Consent of PricewaterhouseCoopers, L.L.P.
23.2*	Consent of PricewaterhouseCoopers, L.L.P. for Exhibit 99.1.
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.”
99.1*	SemGroup Energy Partners G.P., L.L.C. Financial Statements.

* Filed herewith.

# Certain portions of this exhibit have been granted confidential treatment by the Securities and Exchange Commission. The omitted portions have been separately filed with the Securities and Exchange Commission.

† As required by Item 15(a)(3) of Form 10-K, this exhibit is identified as a compensatory plan or arrangement.

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SIGNATURES

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

SEMGROUP ENERGY PARTNERS, L.P.

By: SemGroup Energy Partners G.P., L.L.C.

Its General Partner

Date: July 2, 2009 By: /s/ Alex G Stallings

Alex G. Stallings

Chief Financial Officer and Secretary

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on July 2, 2009.


Signature	Title

/s/ Kevin L. Foxx	President and Chief Executive Officer (Principal Executive Officer)
Kevin L. Foxx

/s/ Alex G. Stallings	Chief Financial Officer and Secretary (Principal Financial Officer)
Alex G. Stallings

/s/ James R. Griffin	Chief Accounting Officer (Principal Accounting Officer)
James R. Griffin	Chief Accounting Officer (Principal Accounting Officer)

/s/ Duke R. Ligon	Director
Duke R. Ligon	Director

/s/ Brian F. Billings	Director
Brian F. Billings	Director

/s/ Edward F. Kosnik	Director
Edward F. Kosnik	Director

/s/ Gabriel Hammond	Director
Gabriel Hammond	Director

/s/ Dave Miller	Director
Dave Miller	Director

/s/ David N. Bernfeld	Director
David N. Bernfeld	Director

Table of Contents

INDEX TO FINANCIAL STATEMENTS


SEMGROUP ENERGY PARTNERS, L.P. AUDITED FINANCIAL STATEMENTS:
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2007 and 2008	F-3
Consolidated Statements of Operations for the Years Ended December 31, 2006, 2007 and 2008	F-4
Consolidated Statements of Changes in Division Equity/Partners’ Capital for the Years Ended December 31, 2006, 2007 and 2008	F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2007 and 2008	F-6
Notes to the Consolidated Financial Statements	F-7

F-1

Table of Contents

Report of Independent Registered Public Accounting Firm

To the Board of Directors of SemGroup Energy Partners G.P., L.L.C. and Unitholders of SemGroup Energy Partners, L.P.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statement of operations, of changes in partners' capital (deficit) and cash flows present fairly, in all material respects, the financial position of SemGroup Energy Partners, L.P. and subsidiaries (the “Partnership”) at December 31, 2008 and 2007 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for these financial statements and for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, and on the Partnership's internal control over financial reporting based on our audits (which was an integrated audit in 2008). We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

The accompanying financial statements have been prepared assuming that the Partnership will continue as a going concern. As discussed in Note 19 to the consolidated financial statements, the Partnership has substantial long-term debt, a deficit in partners’ capital, significant litigation uncertainties, and other issues, which raise substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 19. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

A partnership’s internal control over financial reporting is a process designed 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. A partnership’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the partnership; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the partnership’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Tulsa, Oklahoma

July 2, 2009

F-2

Table of Contents

SEMGROUP ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands, except per unit data)

	As of December 31,
	2007			2008
ASSETS
Current assets:
Cash and cash equivalents	$	416		$	28,785
Accounts receivable, net of allowance for doubtful accounts of $0 and $554 at December 31, 2007 and December 31, 2008, respectively		2,666			8,342
Receivables from related parties, net of allowance for doubtful accounts of $0 for both dates		9,665			18,912
Prepaid insurance		797			2,256
Other current assets		442			1,811
Total current assets		13,986			60,106
Property, plant and equipment, net of accumulated depreciation of $40,222 and $80,277 at December 31, 2007 and December 31, 2008, respectively		102,239			284,489
Goodwill		6,340			6,340
Debt issuance costs		944			1,956
Intangibles and other assets, net		1,973			1,750
Total assets	$	125,482		$	354,641
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
Current liabilities:
Accounts payable	$	3,045		$	2,610
Payables to related parties		10,227			20,134
Accrued interest payable		449			175
Accrued property taxes payable		-			1,951
Interest rate swap settlements payable		-			1,505
Unearned revenue		-			2,765
Other accrued liabilities		340			2,923
Current portion of capital lease obligations		1,236			866
Total current liabilities		15,297			32,929
Long-term debt		89,600			448,100
Long-term capital lease obligations		1,123			255
Interest rate swaps liability		2,233			-
Commitments and contingencies (Notes 8, 15 and 19)
Partners’ capital (deficit):
Common unitholders (14,375,000 and 21,557,309 units issued and outstanding at December 31, 2007 and December 31, 2008, respectively)		317,004			481,007
Subordinated unitholders (12,570,504 units issued and outstanding for both dates)		(287,210	)		(284,332	)
General partner interest (2.0% interest with 549,908 and 690,725 general partner units outstanding at December 31, 2007 and December 31, 2008, respectively)		(12,565	)		(323,318	)
Total Partners’ capital (deficit)		17,229			(126,643	)
Total liabilities and Partners’ capital (deficit)	$	125,482		$	354,641

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

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SEMGROUP ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

	Year ended December 31,
	2006			2007			2008
Service revenue:
Third party revenue	$	28,109		$	28,303		$	48,295
Related party revenue		730			46,262			143,885
Total revenue		28,839			74,565			192,180
Expenses:
Operating		51,608			67,182			103,510
Allowance for doubtful accounts		-			-			568
General and administrative		11,097			13,595			43,085
Total expenses		62,705			80,777			147,163
Operating income (loss)		(33,866	)		(6,212	)		45,017
Other expenses:
Interest expense		1,989			6,560			26,951
Income (loss) before income taxes		(35,855	)		(12,772	)		18,066
Provisions for income taxes		-			141			291
Net income (loss)	$	(35,855	)	$	(12,913	)	$	17,775
Allocation of net income (loss) to limited and subordinated partners:
Net loss attributed to SemGroup Energy Partners Predecessor				$	(26,118	)	$	-
General partner interest in net income				$	264		$	3,334
Net income allocable to limited and subordinated partners				$	12,941		$	14,441

Basic and diluted net income per common unit				$	0.55		$	0.46
Basic and diluted net income per subordinated unit				$	0.40		$	0.46

Weighted average common units outstanding - basic and diluted					14,375			20,401
Weighted average subordinated partners’ units outstanding - basic and diluted					12,571			12,571

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

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SEMGROUP ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL (DEFICIT)

(in thousands)

	Predecessor Division Equity			Common Unitholders			Subordinated Unitholders			General Partner Interest			Total Partners’ Capital (Deficit)

Balance December 31, 2005	$	28,799		$	-		$	-		$	-		$	28,799
Contributions from the Private Company		69,202			-			-			-			69,202
Net loss		(35,855	)		-			-			-			(35,855	)
Balance December 31, 2006		62,146			-			-			-			62,146
Contributions from the Private Company		71,931			-			1			-			71,932
Net loss from January 1, 2007 through July 19, 2007		(26,118	)		-			-			-			(26,118	)
Allocation of SGLP Predecessor equity in exchange for 12,500,000 common units, 12,570,504 subordinated units and a 2% general partnership interest (represented by 549,908 units)		28,504			275,000			(290,783	)		(12,721	)		-
Distribution to SemGroup Holdings		(136,463	)		-			-			-			(136,463	)
Proceeds from sale of 1,875,000 common units, net of underwriters’ discount and offering expenses of $3.2 million		-			38,036			-			-			38,036
Net income from July 20, 2007 through December 31, 2007		-			6,903			6,038			264			13,205
Equity-based incentive compensation		-			631			551			24			1,206
Distributions paid		-			(3,566	)		(3,017	)		(132	)		(6,715	)
Balance, December 31, 2007		-			317,004			(287,210	)		(12,565	)		17,229
Net income		-			8,818			5,623			3,334			17,775
Equity-based incentive compensation		-			11,081			6,526			357			17,964
Distributions paid		-			(13,719	)		(9,271	)		(727	)		(23,717	)
Proceeds from sale of 6,900,000 common units, net of underwriters’ discount and offering expenses of $7.1 million		-			157,823			-			-			157,823
Proceeds from issuance of 140,817 general partner units		-			-			-			3,365			3,365
Consideration paid in excess of historical cost of assets acquired from Private Company		-			-			-			(317,082	)		(317,082	)
Balance, December 31, 2008	$	-		$	481,007		$	(284,332	)	$	(323,318	)	$	(126,643	)

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

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SEMGROUP ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31
	2006			2007			2008
Cash flows from operating activities:
Net income (loss)	$	(35,855	)	$	(12,913	)	$	17,775
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Provision for uncollectible receivables from third parties		-			-			554
Depreciation and amortization		8,597			9,478			21,328
Amortization and write off of debt issuance costs		-			93			1,082
Unrealized loss related to interest rate swaps		-			2,233			-
Loss on sale of assets		405			95			251
Equity-based incentive compensation		-			1,206			17,964

Changes in assets and liabilities
Increase in accounts receivable		(444	)		(122	)		(6,230	)
Increase in receivables from related parties		-			(9,665	)		(9,247	)
Increase in prepaid insurance		-			-			(1,459	)
Decrease (increase) in other current assets		(23	)		17			(1,674	)
Decrease (increase) in other assets		-			138			(74	)
Increase (decrease) in accounts payable		1,165			(947	)		(485	)
Increase in payables to related parties		-			10,227			9,907
Decrease in accrued interest payable		-			-			(274	)
Increase in accrued property taxes		-			-			1,951
Increase in interest rate swap settlements payable		-			-			1,505
Increase in unearned revenue		-			-			2,765
Increase (decrease) in other accrued liabilities		374			(394	)		2,583
Decrease in interest rate swap liability		-			-			(2,233	)
Net cash provided by (used in) operating activities		(25,781	)		(554	)		55,989
Cash flows from investing activities:
Acquisition of assets from Private Company		(9,835	)		-			(514,668	)
Capital expenditures		(31,640	)		(20,351	)		(6,016	)
Proceeds from sale of assets		146			366			375
Net cash used in investing activities		(41,329	)		(19,985	)		(520,309	)
Cash flows from financing activities:
Debt issuance costs		-			(1,037	)		(2,094	)
Payments on capital lease obligations		(2,092	)		(1,748	)		(1,238	)
Borrowings under credit facility		-			158,450			518,600
Payments under credit facility		-			(68,850	)		(160,100	)
Proceeds from equity issuance, net of offering costs		-			38,036			161,238
Distributions paid		-			(143,178	)		(23,717	)
Contributions from Private Company		69,202			39,282			-
Net cash provided by financing activities		67,110			20,955			492,689
Net increase in cash and cash equivalents		-			416			28,369
Cash and cash equivalents at beginning of period		-			-			416
Cash and cash equivalents at end of period	$	-		$	416		$	28,785
Supplemental disclosure of cash flow information:
Predecessor liabilities not contributed to Partnership	$	-		$	32,650		$	-
Increase (decrease) in accounts payable related to purchase of property, plant and equipment		(859	)		(769	)		50
Cash paid for interest, net of amount capitalized		1,989			3,639			27,655
Cash paid for income taxes		-			-			141

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

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SEMGROUP ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND NATURE OF BUSINESS

SemGroup Energy Partners, L.P. and subsidiaries (the “Partnership”) is a publicly traded master limited partnership with operations in twenty-three states. The Partnership provides integrated terminalling, storage, gathering and transportation services for companies engaged in the production, distribution and marketing of crude oil and liquid asphalt cement. The Partnership manages its operations through three operating segments: (i) crude oil terminalling and storage services, (ii) crude oil gathering and transportation services and (iii) asphalt services. The Partnership was formed in February 2007 as a Delaware master limited partnership initially to own, operate and develop a diversified portfolio of complementary midstream energy assets.

On July 20, 2007, the Partnership issued 12,500,000 common units, representing limited partner interests in the Partnership, and 12,570,504 subordinated units, representing additional limited partner interests in the Partnership, to SemGroup Holdings, L.P. (“SemGroup Holdings”) and 549,908 general partner units representing a 2.0% general partner interest in the Partnership to SemGroup Energy Partners G.P., L.L.C. SemGroup Holdings subsequently offered 12,500,000 common units pursuant to a public offering at a price of $22 per unit. In addition, the Partnership issued an additional 1,875,000 common units to the public pursuant to the underwriters’ exercise of their over-allotment option. The initial public offering closed on July 23, 2007. In connection with its initial public offering, the Partnership entered into a Throughput Agreement (the “Throughput Agreement”) with SemGroup, L.P. (collectively, with its subsidiaries other than the Partnership and the Partnership’s general partner, the “Private Company”) under which the Partnership provided crude oil gathering and transportation and terminalling and storage services to the Private Company.

On February 20, 2008, the Partnership purchased land, receiving infrastructure, storage tanks, machinery, pumps and piping at 46 liquid asphalt cement and residual fuel oil terminalling and storage facilities (the “Acquired Asphalt Assets”) from the Private Company for aggregate consideration of $379.5 million, including $0.7 million of acquisition-related costs. For accounting purposes, the acquisition has been reflected as a purchase of assets, with the Acquired Asphalt Assets recorded at the historical cost of the Private Company, which was approximately $145.5 million, with the additional purchase price of $234.0 million reflected in the statement of changes in partners’ capital as a distribution to the Private Company. In conjunction with the purchase of the Acquired Asphalt Assets, the Partnership amended its existing credit facility, increasing its borrowing capacity to $600 million. Concurrently, the Partnership issued 6,000,000 common units, receiving proceeds, net of underwriting discounts and offering-related costs, of $137.2 million. The Partnership’s general partner also made a capital contribution of $2.9 million to maintain its 2.0% general partner interest in the Partnership. On March 5, 2008, the Partnership issued an additional 900,000 common units, receiving proceeds, net of underwriting discounts, of $20.6 million, in connection with the underwriters’ exercise of their over-allotment option in full. The Partnership’s general partner made a corresponding capital contribution of $0.4 million to maintain its 2.0% general partner interest in the Partnership. In connection with the acquisition of the Acquired Asphalt Assets, the Partnership entered into a Terminalling and Storage Agreement (the “Terminalling Agreement”) with the Private Company and certain of its subsidiaries under which the Partnership provided liquid asphalt cement terminalling and storage and throughput services to the Private Company and the Private Company agreed to use the Partnership’s services at certain minimum levels. The board of directors of the Partnership’s general partner (the “Board”) approved the acquisition of the Acquired Asphalt Assets as well as the terms of the related agreements based on a recommendation from its conflicts committee, which consisted entirely of independent directors. The conflicts committee retained independent legal and financial advisors to assist it in evaluating the transaction and considered a number of factors in approving the acquisition, including an opinion from the committee’s independent financial advisor that the consideration paid for the Acquired Asphalt Assets was fair, from a financial point of view, to the Partnership.

On May 12, 2008, the Partnership purchased the Eagle North Pipeline System, a 130-mile, 8-inch pipeline that originates in Ardmore, Oklahoma and terminates in Drumright, Oklahoma (the “Acquired Pipeline Assets”) from the Private Company for aggregate consideration of $45.1 million, including $0.1 million of acquisition-related costs. For accounting purposes, the acquisition has been reflected as a purchase of assets, with the Acquired Pipeline Assets recorded at the historical cost of the Private Company, which was approximately $35.1 million, with the additional purchase price of $10.0 million reflected in the statement of changes in partners’ capital as a distribution to the Private Company. The acquisition was funded with borrowings under the Partnership’s existing revolving credit facility. The Board approved the acquisition of the Acquired Pipeline Assets based on a recommendation from its conflicts committee, which consisted entirely of independent directors. The conflicts committee retained independent legal and financial advisors to assist it in evaluating the transaction and considered a number of factors in approving the acquisition, including an opinion from the committee’s independent financial advisor that the consideration paid for the Acquired Pipeline Assets was fair, from a financial point of view, to the Partnership.

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On May 30, 2008, the Partnership purchased eight recently constructed crude oil storage tanks located at the Cushing Interchange from the Private Company and the Private Company assigned a take-or-pay, fee-based agreement to the Partnership that commits substantially all of the 2.0 million barrels of new storage to a third-party customer through August 2010 (the “Acquired Storage Assets”) for aggregate consideration of $90.3 million, including $0.3 million of acquisition-related costs. For accounting purposes, the acquisition has been reflected as a purchase of assets, with the Acquired Storage Assets recorded at the historical cost of the Private Company, which was approximately $17.2 million, inclusive of $0.6 million of completion costs subsequent to the close of the acquisition, with the additional purchase price of $73.1 million reflected in the statement of changes in partners’ capital as a distribution to the Private Company. The acquisition was funded with borrowings under the Partnership’s existing revolving credit facility. The Board approved the acquisition of the Acquired Storage Assets based on a recommendation from its conflicts committee, which consisted entirely of independent directors. The conflicts committee retained independent legal and financial advisors to assist it in evaluating the transaction and considered a number of factors in approving the acquisition, including an opinion from the committee’s independent financial advisor that the consideration paid for the Acquired Storage Assets was fair, from a financial point of view, to the Partnership.

On July 22, 2008, the Private Company and certain of its subsidiaries filed voluntary petitions (the “Bankruptcy Filings”) for reorganization under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”), Case No. 08-11547-BLS. The Private Company and its subsidiaries continue to operate their businesses and own and manage their properties as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. None of the Partnership, its general partner, the subsidiaries of the Partnership nor the subsidiaries of the Partnership’s general partner were party to the Bankruptcy Filings. See Notes 8 and 19 for a discussion of the impact of the Bankruptcy Filings and related events upon the Partnership.

2. BASIS OF PRESENTATION

The accompanying financial statements have been prepared assuming that the Partnership will continue as a going concern. Prior to consummating the Settlement (as defined below in Note 19), events of default existed under the Partnership’s credit facility, including during the year ended December 31, 2008. As discussed in Notes 8 and 19 to the financial statements, the Partnership entered into the Credit Agreement Amendment (as defined below) under which, among other things, the lenders under the Partnership’s credit facility consented to the Settlement and waived all existing defaults and events of default described in the Forbearance Agreement (as defined below) and amendments thereto. However, the Partnership continues to face uncertainty relating to its ability to comply with certain financial covenants specified in its credit facility, its exposure and sensitivity to interest rate risks given the materiality of its borrowings under its credit facility, and uncertainties related to securities and other litigation as discussed in Note 19. These factors raise substantial doubt about the Partnership’s ability to continue as a going concern. Management’s plans in regard to these matters are also discussed in Note 19. The accompanying financial statements do not include any adjustments that might result from the outcome of this uncertainty.

The accompanying consolidated financial statements and related notes include the accounts of the Partnership, and prior to July 20, 2007, the operations contributed to the Partnership by the Private Company in connection with the Partnership’s initial public offering. The financial statements have been prepared in accordance with accounting principles and practices generally accepted in the United States of America (“GAAP”).

The accompanying financial statements include the results of operations of crude oil terminalling and storage and gathering and transportation operations that were contributed to the Partnership prior to the closing of the Partnership’s initial public offering on a carve-out basis and are referred to herein as the “Predecessor.” Both the Partnership and the Predecessor had common ownership and, in accordance with Emerging Issues Task Force Issue No. 87-21, “Change of Accounting Basis in Master Limited Partnership Transactions,” the assets and liabilities transferred were carried forward to the Partnership at their historical amounts. Additionally, due to the previous common control of the Private Company and the Partnership, the subsequent acquisitions of fixed assets from the Private Company prior to the Change of Control (as defined below in Note 19) in July 2008 were recorded at the historical cost of the Private Company. All significant intercompany accounts and transactions have been eliminated in the preparation of the accompanying financial statements.

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Through the date of the initial public offering, the Private Company provided cash management services to the Predecessor through a centralized treasury system. As a result, all of the Predecessor’s charges and cost allocations covered by the centralized treasury system were deemed to have been paid to the Private Company in cash during the period in which the cost was recorded in the financial statements. In addition, cash advances by the Private Company in excess of cash earned by the Predecessor are reflected as contributions from the Private Company in the statements of cash flows.

Historically, the Predecessor was a part of the integrated operations of the Private Company, and neither the Private Company nor the Predecessor recorded revenue associated with the terminalling and storage and gathering and transportation services provided on an intercompany basis. The Private Company and the Predecessor recognized only the costs associated with providing such services. Accordingly, revenues reflected in these financial statements for all periods prior to the contribution of the assets, liabilities and operations to the Partnership by the Private Company on July 20, 2007 relate to services provided to third parties. Prior to the close of its initial public offering in July 2007, the Partnership entered into a Throughput Agreement with the Private Company under which the Partnership provided crude oil gathering and transportation and terminalling and storage services to the Private Company. In connection with its February 2008 purchase of the Acquired Asphalt Assets, the Partnership entered into a Terminalling Agreement with the Private Company under which the Partnership provided liquid asphalt cement terminalling and storage and throughput services to the Private Company (see Note 13). In connection with the Settlement, the Private Company rejected the Throughput Agreement and the Terminalling Agreement as part of its Bankruptcy Cases (as defined below in Note 19).

The accompanying financial statements include allocated general and administrative charges from the Private Company for indirect corporate overhead to cover costs of functions such as legal, accounting, treasury, environmental safety, information technology and other corporate services. General and administrative charges allocated by the Private Company prior to the contribution of the assets, liabilities and operations to the Partnership by the Private Company were $3.8 million and $3.2 million for the years ended December 31, 2006 and 2007, respectively. Management believes that the allocated general and administrative expense is representative of the costs and expenses incurred by the Private Company for the Predecessor. Prior to the close of its initial public offering in July 2007, the Partnership entered into an Omnibus Agreement with the Private Company under which the Partnership reimbursed the Private Company for the provision of various general and administrative services for the Partnership’s benefit. The Omnibus Agreement was amended and restated in conjunction with the purchase of the Acquired Asphalt Assets in February 2008 (the “Amended Omnibus Agreement”) (see Note 13). The events related to the Bankruptcy Filings terminated the Private Company’s obligations to provide services to the Partnership under the Amended Omnibus Agreement. The Private Company continued to provide such services to the Partnership until the effective date of the Settlement at which time the Private Company rejected the Amended Omnibus Agreement and the Private Company and the Partnership entered into the Shared Services Agreement (as defined below) and the Transition Services Agreement (as defined below in Note 19) relating to the provision of such services (see Note 19).

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

USE OF ESTIMATES —The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts and disclosure of contingencies. Management makes significant estimates including: (1) allowance for doubtful accounts receivable; (2) estimated useful lives of assets, which impacts depreciation; (3) estimated cash flows and fair values inherent in impairment tests under SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”) and SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”); (4) estimated fair value of assets and liabilities acquired and identification of associated intangible assets; (5) accruals related to revenues and expenses; and (6) liability and contingency accruals. Although management believes these estimates are reasonable, actual results could differ from these estimates.

RECLASSIFICATIONS — Certain amounts in the Partnership’s consolidated financial statements have been reclassified to conform to the 2008 presentation. These reclassifications did not impact previously reported net income or partners’ capital.

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CASH AND CASH EQUIVALENTS — The Partnership includes as cash and cash equivalents, cash and all investments with maturities at date of purchase of three months or less which are readily convertible into known amounts of cash.

ACCOUNTS RECEIVABLE — The majority of the Partnership’s accounts receivable relate to its gathering and transportation activities. Accounts receivable included in the balance sheets are reflected net of the allowance for doubtful accounts of $0.0 million and $0.6 million at December 31, 2007 and 2008, respectively.

The Partnership reviews all outstanding accounts receivable balances on a monthly basis and records a reserve for amounts that the Partnership expects will not be fully recovered. Although the Partnership considers its allowance for doubtful trade accounts receivable to be adequate, there is no assurance that actual amounts will not vary significantly from estimated amounts.

PROPERTY, PLANT AND EQUIPMENT — Property, plant and equipment are recorded at cost. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred. The carrying value of the assets is based on estimates, assumptions and judgments relative to useful lives and salvage values. As assets are disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is included in other income in the statements of operations.

Depreciation is calculated using the straight-line method, based on estimated useful lives of the assets. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand in the area. When assets are put into service, management makes estimates with respect to useful lives and salvage values that it believes are reasonable. However, subsequent events could cause management to change its estimates, thus impacting the future calculation of depreciation.

The Partnership has contractual obligations to perform dismantlement and removal activities in the event that some of its liquid asphalt cement and residual fuel oil terminalling and storage assets are abandoned (see Note 15). Such obligations are recognized in the period incurred if reasonably estimable under the provisions of SFAS No 143, “Accounting for Asset Retirement Obligations.”

IMPAIRMENT OF LONG-LIVED ASSETS — Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value in accordance with SFAS 144 as amended. Under SFAS 144, a long-lived asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows. There were no asset impairments in the three year period ended December 31, 2008.

DEBT ISSUANCE COSTS — Costs incurred in connection with the issuance of long-term debt related to the Partnership’s credit facilities are capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization.

GOODWILL AND OTHER INTANGIBLE ASSETS — Goodwill represents the excess of the cost of acquisitions over the amounts assigned to assets acquired and liabilities assumed. Goodwill is not amortized but is tested annually for impairment and when events and circumstances warrant an interim evaluation. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit. The Partnership has three reporting segments comprised of (i) its crude oil terminalling and storage operations, (ii) its crude oil gathering and transportation operations and (iii) its asphalt operations. All of the Partnership’s goodwill is attributed to its crude oil gathering and transportation reporting unit. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not impaired. Since adoption of SFAS 142, the Partnership has not recognized any impairment of goodwill.

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Acquired customer relationships and non-compete agreements are capitalized and amortized over useful lives ranging from 5 to 10 years using the straight-line method of amortization. An impairment loss is recognized for amortizable intangibles if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value. No impairment loss was recognized in the three year period ended December 31, 2008.

ENVIRONMENTAL MATTERS — Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines, and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. No material environmental liabilities exist as of December 31, 2008.

REVENUE RECOGNITION — The Partnership’s revenues consist of (i) terminalling and storage revenues and (ii) gathering and transportation revenues.

Terminalling and storage revenues consist of (i) storage fees from actual storage used on a month-to-month basis; (ii) storage fees resulting from short-term and long-term contracts for committed space that may or may not be utilized by the customer in a given month; and (iii) terminal throughput charges to pump crude oil to connecting carriers or to deliver liquid asphalt cement out of the Partnership’s terminals. Terminal throughput 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 liquid asphalt cement is delivered out of the Partnership’s terminal. Storage revenues are recognized as the services are provided and the amounts earned on a monthly basis. All terminalling and storage revenues are based on actual volumes and rates.

Gathering and transportation revenues consist of fees recognized for the gathering of crude oil for the Partnership’s customers and the transportation of the crude oil to refiners, to common carrier pipelines for ultimate delivery to refiners, or to terminalling and storage facilities owned by the Partnership 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.

INCOME AND OTHER TAXES — The Partnership is not subject to federal income taxes. For federal and most state income tax purposes, all income, gains, losses, expenses, deductions and tax credits generated by the Partnership flow through to the unitholders of the Partnership. Beginning in 2007, the state of Texas implemented a partnership-level tax based on a percentage of the revenue earned for services provided in the state of Texas. The Partnership has estimated its liability related to this tax to be $0.1 million and $0.3 million at December 31, 2007 and 2008, respectively, which is reported as a provision for income taxes on its consolidated statements of operations. See “Taxation as a Corporation” in Note 19 for a discussion of certain risks related to the Partnership’s ability to be treated as a partnership for federal income tax purposes.

STOCK BASED COMPENSATION — In July 2007 the Partnership’s general partner adopted the SemGroup Energy Partners G.P. L.L.C. Long Term Incentive Plan (the “Plan”). The compensation committee of the general partner’s board of directors administers the Plan. The Plan authorizes the grant of an aggregate of 1.25 million common units deliverable upon vesting. Although other types of awards are contemplated under the Plan, currently outstanding awards include “phantom” units, which convey the right to receive common units upon vesting, and “restricted” units, which are grants of common units restricted until the time of vesting. The phantom unit awards also include distribution equivalent rights (“DERs”). Subject to applicable earnings 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. Cash distributions paid on DERs are accounted for as partnership distributions. Recipients of restricted units are entitled to receive cash distributions paid on common units during the vesting period. The unit-based awards granted during 2007 and 2008 have been accounted for under the provisions of SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123(R)”).

Under SFAS 123(R), the Partnership classifies unit award grants as either equity or liability awards. All award grants made under the Plan from its inception through December 31, 2008 are classified as equity awards. Fair value for award grants classified as equity is determined on the grant date of the award and this value is recognized as compensation expense ratably over the requisite service period of unit award grants, which generally is the vesting period. Fair value for equity awards is calculated as the closing price of the Partnership’s common units representing limited partner interests in the Partnership (“limited partner units”) on the grant date. Compensation expense related to unit-based payments is included in general and administrative expenses on the Partnership’s consolidated statements of operations.

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DERIVATIVE INSTRUMENTS — The Partnership utilizes derivative instruments to manage its exposure to interest rate risk. The Partnership records all derivative instruments on the balance sheet as either assets or liabilities measured at their fair value under the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”) . SFAS 133 requires that changes in derivative instruments’ fair value be recognized currently in earnings unless specific hedge accounting criteria are met, in which case, changes in fair value are deferred to accumulated other comprehensive income and reclassified into earnings when the underlying transaction affects earnings. Changes in the fair value of the Partnership’s interest rate swaps are recognized currently in earnings. See Note 8 for further discussion.

4. OTHER CURRENT ASSETS

Other current assets consist of the following (in thousands):

	December 31,
	2007		2008
Prepaid deposits	$	-	$	1,560
Acquisitions in progress		306		-
Other prepayments		136		251
Total other current assets	$	442	$	1,811

5. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, net is stated at cost and consisted of the following (in thousands):

	Estimated
	Useful		December 31,		December 31,
	Lives (Years)		2007		2008
Land			$	309	$	15,065
Land improvements		10-20		-		5,366
Pipelines and facilities		5-31		34,626		95,010
Storage and terminal facilities		10-35		71,873		166,950
Transportation equipment		3-10		25,133		24,744
Office property and equipment and other		3-31		8,505		19,972
Construction-in-progress				2,015		37,659
Property, plant and equipment, gross				142,461		364,766
Accumulated depreciation				(40,222)		(80,277)
Property, plant and equipment, net			$	102,239	$	284,489

Property, plant and equipment includes assets under capital leases of $2.4 million and $1.2 million, net of accumulated depreciation of $4.2 million and $5.3 million at December 31, 2007 and 2008, respectively. All capital leases relate to the transportation equipment asset category. At December 31, 2008, $37.1 million of construction-in-progress consists of the Eagle North Pipeline System, a 130-mile, 8-inch pipeline that was acquired by the Partnership from the Private Company on May 12, 2008. The Partnership has suspended capital expenditures on this pipeline due to the continuing impact of the Bankruptcy Filings (see Note 19). Management currently intends to put the asset into service in early 2010 and is exploring various alternatives to complete the project.

Depreciation expense for the years ended December 31, 2006, 2007 and 2008 was $8.5 million, $9.1 million and $21.0 million, respectively.

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6. INTANGIBLES AND OTHER ASSETS, NET

Other assets, net of accumulated amortization, consist of the following (in thousands):

	December 31,
	2007			2008
Customer relationships	$	1,858		$	1,858
Non-compete agreements		557			557
Deposits		4			19
Other		-			59

Other assets, gross		2,419			2,493
Accumulated amortization		(446	)		(743	)

Other assets, net	$	1,973		$	1,750

Amortization of intangibles for the years ended December 31, 2006, 2007 and 2008 were $0.1 million, $0.3 million and $0.3 million, respectively. The estimated aggregate amortization expense on amortizable intangible assets currently owned by the Partnership is as follows (in thousands):

For twelve months ending:
December 31, 2009	$	297
December 31, 2010		297
December 31, 2011		241
December 31, 2012		186
December 31, 2013		186
Thereafter		465
Total estimated aggregate amortization expense	$	1,672

7. ACQUISITIONS

On June 30, 2006, the Private Company completed the acquisition of the assets of Big Tex Crude Oil Company (“Big Tex”), a crude oil gathering, transportation and marketing company located in Abilene and Midland, Texas, and in Hobbs, New Mexico, for total consideration of approximately $15.5 million. Assets from this acquisition assigned to the Partnership totaled $9.8 million, consisting primarily of equipment, vehicles and intangibles related to customer relationships and non-compete agreements, including goodwill of $1.6 million and intangibles of $2.4 million.

The Partnership has acquired various assets, including the Acquired Asphalt Assets, the Acquired Pipeline Assets and the Acquired Storage Assets, from the Private Company. See Notes 1, 11 and 13 for a description of these acquisitions. In addition, the Partnership acquired certain liquid asphalt cement assets and crude oil assets from the Private Company in connection with the Settlement (see Note 19).

8. LONG TERM DEBT

On July 20, 2007, the Partnership entered into a $250.0 million five-year credit facility with a syndicate of financial institutions. The Partnership borrowed approximately $137.5 million prior to the closing of the initial public offering. The Partnership distributed $136.5 million, net of debt issuance costs of $1.0 million, advanced under the credit agreement to SemGroup Holdings. On July 23, 2007, the Partnership repaid approximately $38.7 million under the credit facility with the proceeds it received in connection with the exercise of the underwriters’ over-allotment option in the Partnership’s initial public offering.

In connection with its purchase of the Acquired Asphalt Assets, the Partnership amended this credit facility to increase the total borrowing capacity to $600.0 million.

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Due to events related to the Bankruptcy Filings, events of default occurred under the Partnership’s credit agreement (see Note 19). Effective on September 18, 2008, the Partnership and the requisite lenders under its credit facility entered into a Forbearance Agreement and Amendment to Credit Agreement (the “Forbearance Agreement”) under which the lenders agreed, subject to specified limitations and conditions, to forbear from exercising their rights and remedies arising from the Partnership’s defaults and events of default described therein for the period commencing on September 18, 2008 and ending on the earliest of (i) December 11, 2008, (ii) the occurrence of any default or event of default under the credit agreement other than certain defaults and events of default indicated in the Forbearance Agreement, or (iii) the failure of the Partnership to comply with any of the terms of the Forbearance Agreement (the “Forbearance Period”). On December 11, 2008, the lenders agreed to extend the Forbearance Period until December 18, 2008 pursuant to a First Amendment to Forbearance Agreement and Amendment to Credit Agreement (the “First Forbearance Amendment”), on December 18, 2008, the lenders agreed to extend the Forbearance Period until March 18, 2009 pursuant to a Second Amendment to Forbearance Agreement and Amendment to Credit Agreement (the “Second Forbearance Amendment”), and on March 18, 2009, the lenders agreed to further extend the Forbearance Period until April 8, 2009 pursuant to a Third Amendment to Forbearance Agreement and Amendment to Credit Agreement (the “Third Forbearance Amendment”).

The Partnership, its subsidiaries that are guarantors of the obligations under the credit facility, Wachovia Bank, National Association, as Administrative Agent, and the requisite lenders under the Partnership’s credit agreement entered into the Consent, Waiver and Amendment to Credit Agreement (the “Credit Agreement Amendment”), dated as of April 7, 2009, under which, among other things, the lenders consented to the Settlement (see Note 19) and waived all existing defaults and events of default described in the Forbearance Agreement and amendments thereto.

Prior to the execution of the Forbearance Agreement, the credit agreement was comprised of a $350 million revolving credit facility and a $250 million term loan facility. The Forbearance Agreement permanently reduced the Partnership’s revolving credit facility under the credit agreement from $350 million to $300 million and prohibited the Partnership from borrowing additional funds under its revolving credit facility during the Forbearance Period. Under the Forbearance Agreement, the Partnership agreed to pay the lenders executing the Forbearance Agreement a fee equal to 0.25% of the aggregate commitments under the credit agreement after giving effect to the above described commitment reduction. The Second Forbearance Amendment further permanently reduced the Partnership’s revolving credit facility under the credit agreement from $300 million to $220 million. In addition, under the Second Forbearance Amendment, the Partnership agreed to pay the lenders executing the Second Forbearance Amendment a fee equal to 0.375% of the aggregate commitments under the credit agreement after the above described commitment reduction. Under the Third Forbearance Amendment, the Partnership agreed to pay a fee equal to 0.25% of the aggregate commitments under the credit agreement after the above described commitment reduction. The amendments to the Forbearance Agreement prohibited the Partnership from borrowing additional funds under its revolving credit facility during the extended Forbearance Period.

The Credit Agreement Amendment subsequently further permanently reduced the Partnership’s revolving credit facility under the credit agreement from $220 million to $50 million, and increased the term loan facility from $250 million to $400 million. Upon the execution of the Credit Agreement Amendment, $150 million of the Partnership’s outstanding revolving loans were converted to term loans and the Partnership became able to borrow additional funds under its revolving credit facility. Substantially all of the Partnership’s assets are pledged as collateral under the Credit Agreement. Pursuant to the Credit Agreement Amendment, the credit facility and all obligations thereunder will mature on June 30, 2011. As of June 26, 2009, the Partnership had an aggregate unused credit availability under its revolving credit facility of approximately $28.1 million. Pursuant to the Credit Agreement Amendment, the Partnership’s revolving credit facility is limited to $ 50.0 million. If any of the financial institutions that support the Partnership’s revolving credit facility were to fail, it may not be able to find a replacement lender, which could negatively impact its ability to borrow under its revolving credit facility. For instance, Lehman Brothers Commercial Bank is one of the lenders under the Partnership’s $50.0 million revolving credit facility, and Lehman Brothers Commercial Bank has agreed to fund approximately $2.5 million (approximately 5%) of the revolving credit facility. On several occasions Lehman Brothers Commercial Bank has failed to fund revolving loan requests under the Partnership’s revolving credit facility, effectively limiting the aggregate amount of the Partnership’s revolving credit facility to $47.5 million.

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Prior to the events of default, indebtedness under the credit agreement bore interest at the Partnership’s option, at either (i) the higher of the administrative agent’s prime rate or the federal funds rate plus 0.5% (the “Base rate”), plus an applicable margin that ranges from 0.50% to 1.75%, depending on the Partnership’s total leverage ratio and senior secured leverage ratio, or (ii) LIBOR plus an applicable margin that ranges from 1.50% to 2.75%, depending upon the Partnership’s total leverage ratio and senior secured leverage ratio. During the Forbearance Period indebtedness under the credit agreement bore interest at the Partnership’s option, at either (i) the Base rate, plus an applicable margin that ranges from 2.75% to 3.75%, depending upon the Partnership’s total leverage ratio, or (ii) LIBOR plus an applicable margin that ranges from 4.25% to 5.25%, depending upon the Partnership’s total leverage ratio. Pursuant to the Second Forbearance Amendment, commencing on December 12, 2008, indebtedness under the credit agreement bore interest at the Partnership’s option, at either (i) the Base rate plus 5.0% per annum, with a Base rate floor of 4.0% per annum, or (ii) LIBOR plus 6.0% per annum, with a LIBOR floor of 3.0% per annum.

After giving effect to the Credit Agreement Amendment, amounts outstanding under the Partnership’s credit facility bear interest at either the LIBOR rate plus 6.50% per annum, with a LIBOR floor of 3.00%, or the Base rate plus 5.50% per annum, with a Base rate floor of 4.00% per annum. The Partnership now pays a fee of 1.50% per annum on unused commitments under its revolving credit facility. After giving effect to the Credit Agreement Amendment, interest on amounts outstanding under the Partnership’s credit facility must be paid monthly. The Partnership’s credit facility, as amended by the Credit Agreement Amendment, now requires the Partnership to pay additional interest on October 6, 2009, April 6, 2010, October 6, 2010 and April 6, 2011, equal to the product of (i) the sum of the total amount of term loans then outstanding plus the aggregate commitments under the revolving credit facility and (ii) 0.50%, 0.50%, 1.00% and 1.00%, respectively.

During the three months ended December 31, 2008, the weighted average interest rate incurred by the Partnership was 7.72% resulting in interest expense of approximately $8.9 million. During the twelve months ended December 31, 2006, 2007, and 2008, the Partnership capitalized interest of $1.1 million, $0.7 million, and $0.9 million, respectively.

Among other things, the Partnership’s credit facility, as amended by the Credit Agreement Amendment, now requires the Partnership to make (i) minimum quarterly amortization payments on March 31, 2010 in the amount of $2.0 million, June 30, 2010 in the amount of $2.0 million, September 30, 2010 in the amount of $2.5 million, December 31, 2010 in the amount of $2.5 million and March 31, 2011 in the amount of $2.5 million, (ii) mandatory prepayments of amounts outstanding under the revolving credit facility (with no commitment reduction) whenever cash on hand exceeds $15.0 million, (iii) mandatory prepayments with 100% of asset sale proceeds, (iv) mandatory prepayment with 50% of the proceeds raised through equity sales and (v) annual prepayments with 50% of excess cash flow (as defined in the Credit Agreement Amendment). The Partnership’s credit facility, as amended by the Credit Agreement Amendment, prohibits the Partnership from making draws under the revolving credit facility if it would have more than $15.0 million of cash on hand after making the draw and applying the proceeds thereof. Based on borrowings under the credit facility as of December 31, 2008, the Partnership estimates an additional principal repayment of $436.6 million in 2011 in connection with the June 30, 2011 maturity of all obligations under the credit facility. Based on the borrowing rates currently available to the Partnership for debt with similar terms and maturities and consideration of the Partnership’s non-performance risk, long-term debt at December 31, 2008 approximates its fair value.

Under the credit agreement, the Partnership is subject to certain limitations, including limitations on its ability to grant liens, incur additional indebtedness, engage in a merger, consolidation or dissolution, enter into transactions with affiliates, sell or otherwise dispose of its assets (other than the sale or other disposition of the assets of the asphalt business, provided that such disposition is at arm’s length to a non-affiliate for fair market value in exchange for cash and the proceeds of the disposition are used to pay down outstanding loans), businesses and operations, materially alter the character of its business, and make acquisitions, investments and capital expenditures. The credit agreement prohibits the Partnership from making distributions of available cash to its unitholders if any default or event of default (as defined in the credit agreement) exists. The credit agreement, as amended by the Credit Agreement Amendment, requires the Partnership to maintain a leverage ratio (the ratio of its consolidated funded indebtedness to its consolidated adjusted EBITDA, in each case as defined in the credit agreement), determined as of the last day of each month for the twelve month period ending on the date of determination, that ranges on a monthly basis from not more than 5.50 to 1.00 to not more than 9.75 to 1.00. In addition, pursuant to the Credit Agreement Amendment, the Partnership’s ability to make acquisitions and investments in unrestricted subsidiaries is limited and the Partnership may only make distributions if its leverage ratio is less than 3.50 to 1.00 and certain other conditions are met. As of December 31, 2008, the Partnership’s leverage ratio was 4.86 to 1.00. If the Partnership’s leverage ratio does not improve, it may not make quarterly distributions to its unitholders in the future.

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The credit agreement, as amended by the Credit Agreement Amendment, also requires the Partnership to maintain an interest coverage ratio (the ratio of its consolidated EBITDA to its consolidated interest expense, in each case as defined in the credit agreement) that ranges on a monthly basis from not less than 2.50 to 1.00 to not less than 1.00 to 1.00. As of December 31, 2008, the Partnership’s interest coverage ratio was 3.58 to 1.00.

Further, the Partnership is required to maintain a monthly consolidated adjusted EBITDA for the prior twelve months ranging from $45.4 million to $82.9 million as determined at the end of each month. In addition, capital expenditures are limited to $12.5 million in 2009, $8.0 million in 2010 and $4.0 million in the six months ending June 30, 2011.

The credit agreement specifies a number of events of default (many of which are subject to applicable cure periods), including, among others, failure to pay any principal when due or any interest or fees within three business days of the due date, failure to perform or otherwise comply with the covenants in the credit agreement, failure of any representation or warranty to be true and correct in any material respect, failure to pay debt, and other customary defaults. In addition, a change of control of the Partnership or the Partnership’s general partner will be an event of default under the credit agreement. It is also an event of default under the credit agreement if the Partnership does not file its delinquent quarterly and annual reports with the SEC by September 30, 2009, unless the Partnership retains new auditors, in which case such deadline is extended to December 31, 2009. If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies, including taking available cash in the Partnership’s bank accounts. If an event of default exists and the Partnership is unable to obtain forbearance from its lenders or a waiver of the events of default under its credit agreement, it may be forced to sell assets, make a bankruptcy filing or take other action that could have a material adverse effect on its business, the price of its common units and its results of operations. The Partnership is also prohibited from making cash distributions to its unitholders while the events of default exist.

The Partnership capitalized debt issuance costs of approximately $1.0 million and $2.1 million in 2007 and 2008, respectively, which are being amortized straight-line through June 2011. Amortization expense related to debt issuance costs for the years ended December 31, 2007 and 2008 was $0.1 million and $0.6 million, respectively. In connection with the forbearance agreements entered into in 2008, $0.5 million in debt issuance costs associated with the Partnership’s credit facility were written off and recorded as additional interest expense in 2008.

The Partnership is exposed to market risk for changes in interest rates related to its credit facility. Interest rate swap agreements were used to manage a portion of the exposure related to changing interest rates by converting floating-rate debt to fixed-rate debt. In August 2007 the Partnership entered into interest rate swap agreements with an aggregate notional value of $80.0 million that mature on August 20, 2010. Under the terms of the interest rate swap agreements, the Partnership was to pay fixed rates of 4.9% and receive three-month LIBOR with quarterly settlement. In March 2008 the Partnership entered into interest rate swap agreements with an aggregate notional value of $100.0 million that mature on March 31, 2011. Under the terms of the interest rate swap agreements, the Partnership was to pay fixed rates of 2.6% to 2.7% and receive three-month LIBOR with quarterly settlement. The interest rate swaps do not receive hedge accounting treatment under SFAS 133. Changes in the fair value of the interest rate swaps are recorded in interest expense in the statements of operations. In addition, the interest rate swap agreements contain cross-default provisions to events of default under the credit agreement. Due to events related to the Bankruptcy Filings, all of these interest rate swap positions were terminated in the third quarter of 2008, and the Partnership has recorded a $1.5 million liability as of December 31, 2008 with respect to these positions.

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9. FAIR VALUE MEASUREMENTS

The Partnership adopted SFAS No. 157, “ Fair Value Measurements ,” effective January 1, 2008 for financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets and financial liabilities that are being measured and reported on a fair value basis. In February 2008, the FASB issued FSP No. 157-2, which delayed the effective date of SFAS No. 157 by one year for nonfinancial assets and liabilities except those that are recognized and recorded in the financial statements at fair value on a recurring basis. As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). SFAS No. 157 requires disclosure that establishes a framework for measuring fair value and expands disclosure about fair value measurements. The statement requires fair value measurements be classified and disclosed in one of the following categories:

Level 1:		Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Partnership considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2:		Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3:		Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). The Partnership’s Level 3 instruments are comprised of interest rate swaps. Although the Partnership utilizes third party broker quotes to assess the reasonableness of its prices and valuation, the Partnership does not have sufficient corroborating market evidence to support classifying these assets and liabilities as Level 2.

As required by SFAS No. 157, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

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

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3) For the Year Ended December 31, 2008


Beginning balance	$	(2,233)
Total gains or losses (realized/unrealized)
Included in earnings (1)		2,785
Included in other comprehensive income
Purchases, issuances, and settlements		(552)
Transfers in and/or out of Level 3		-
Ending balance, December 31, 2008	$	-

The amount of total losses for the period included
in earnings attributable to the change in the unrealized
gains or losses relating to liabilities still held at
the reporting date	$	-

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

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10. NET INCOME PER LIMITED PARTNER UNIT

Subject to applicability of Emerging Issues Task Force Issue No. 03-06 (“EITF 03-06”), “Participating Securities and the Two-Class Method under Financial Accounting Standards Board (“FASB”) Statement No. 128,” as discussed below, Partnership income is allocated to the limited partners, including the holders of subordinated units, and to the general partner after consideration of its incentive distribution rights. Income allocable to the limited partners is first allocated to the common unitholders up to the quarterly minimum distribution of $0.3125 per unit, with remaining income allocated to the subordinated unitholders up to the minimum distribution amount. Basic and diluted net income per common and subordinated partner unit is determined by dividing net income attributable to common and subordinated partners by the weighted average number of outstanding common and subordinated partner units during the period.

EITF 03-06 addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock (or partnership distributions to unitholders). Under EITF 03-06, in accounting periods where the Partnership’s aggregate net income exceeds aggregate dividends declared in the period, the Partnership is required to present earnings per unit as if all of the earnings for the periods were distributed. The twelve months ended December 31, 2008 earnings per share calculation reflects the summation of the quarterly calculations, as earnings per share for master limited partnerships is calculated based on the distribution provisions set forth in the partnership agreement. The following sets forth the computation of basic and diluted net income per common and subordinated unit (in thousands, except per unit data):

	January 1, 2007 to			July 20, 2007 to		Twelve Months Ended
	July 19,			December 31,		December 31,
	2007			2007		2008
Net income (loss)	$	(26,118	)	$	13,205	$	17,775
Less: General partner interest in net income (loss)		(26,118	)		264		3,334
Net income available to limited and subordinated partners	$	-		$	12,941	$	14,441

Basic weighted average number of units:
Common units					14,375		20,401
Subordinated units					12,571		12,571
Restricted and phantom units					-		525

Diluted weighted average number of units:
Common units					14,375		20,401
Subordinated units					12,571		12,571
Restricted and phantom units					-		525

Basic and diluted net income per common unit				$	0.55	$	0.46
Basic and diluted net income per subordinated unit				$	0.40	$	0.46

11. PARTNERS’ CAPITAL AND DISTRIBUTIONS

In accordance with the terms of its partnership agreement, each quarter the Partnership distributes all of its available cash (as defined) to its unitholders. Generally, distributions are allocated first, 98% to the common unitholders and 2% to its general partner until the Partnership distributes for each common unit an amount equal to the minimum quarterly distribution $0.3125 per unit. Subject to any arrearages in the minimum quarterly distribution to the common unitholders, amounts then are distributed 98% to the subordinated unitholders and 2% to the general partner up to the minimum quarterly distribution for the quarter. Amounts distributable above the minimum quarterly amount are generally distributed 98% to all unitholders and 2% to its general partner, subject to the incentive distribution rights of the general partner. The incentive distribution rights entitle the general partner to receive increasing percentages, up to a maximum of 50%, of cash the Partnership distributes in excess of $0.3594 per unit each quarter. Distributions are also paid to the holders of restricted units and phantom units as disclosed in Note 14.

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On October 25, 2007, the Partnership declared a pro-rated cash distribution of $0.24 per unit on its outstanding units. The distribution was paid on November 14, 2007 to unitholders of record on November 1, 2007. The distribution was pro-rated for the partial quarter following the closing of the Partnership’s initial public offering and therefore corresponded to the period July 23, 2007 through September 30, 2007. The total distribution paid was approximately $6.7 million, with approximately $3.5 million, $3.0 million, and $0.1 million paid to the Partnership’s common unitholders, subordinated unitholders and general partner, respectively, and $0.1 million paid to phantom and restricted unitholders pursuant to awards granted under the Partnership’s long-term incentive plan.

On January 24, 2008, the Partnership declared a cash distribution of $0.3375 per unit on its outstanding units. The distribution was paid on February 14, 2008 to unitholders of record on February 1, 2008. The distribution is for the period October 1, 2007 through December 31, 2007. The total distribution paid was approximately $9.5 million, with approximately $4.9 million, $4.2 million, and $0.2 million paid to the Partnership’s common unitholders, subordinated unitholders and general partner, respectively, and $0.2 million paid to phantom and restricted unitholders pursuant to awards granted under the Partnership’s long-term incentive plan.

On February 20, 2008, the Partnership purchased the Acquired Asphalt Assets from the Private Company for aggregate consideration of $379.5 million, including $0.7 million of acquisition-related costs. For accounting purposes, the acquisition has been reflected as a purchase of assets, with the Acquired Asphalt Assets recorded at the historical cost of the Private Company, which was approximately $145.5 million, and with the additional purchase price of $234.0 million reflected in the statement of changes in partners’ capital as a distribution to the Private Company. The Board approved the acquisition of the Acquired Asphalt Assets as well as the terms of the related agreements based on a recommendation from its conflicts committee, which consisted entirely of independent directors. The conflicts committee retained independent legal and financial advisors to assist it in evaluating the transaction and considered a number of factors in approving the acquisition, including an opinion from the committee’s independent financial advisor that the consideration paid for the Acquired Asphalt Assets was fair, from a financial point of view, to the Partnership.

On April 24, 2008, the Partnership declared a cash distribution of $0.40 per unit on its outstanding units for the three month period ended March 31, 2008. The distribution was paid on May 15, 2008 to unitholders of record on May 5, 2008. The total distribution paid was approximately $14.3 million, with approximately $8.5 million, $5.0 million, and $0.6 million paid to the Partnership’s common unitholders, subordinated unitholders and general partner, respectively, and $0.2 million paid to phantom and restricted unitholders pursuant to awards granted under the Partnership’s long-term incentive plan.

On May 12, 2008, the Partnership purchased the Acquired Pipeline Assets from the Private Company for aggregate consideration of $45.1 million, including $0.1 million of acquisition-related costs. For accounting purposes, the acquisition has been reflected as a purchase of assets, with the Acquired Pipeline Assets recorded at the historical cost of the Private Company, which was approximately $35.1 million, and with the additional purchase price of $10.0 million reflected in the statement of changes in partners’ capital as a distribution to the Private Company. The Board approved the acquisition of the Acquired Pipeline Assets based on a recommendation from its conflicts committee, which consisted entirely of independent directors. The conflicts committee retained independent legal and financial advisors to assist it in evaluating the transaction and considered a number of factors in approving the acquisition, including an opinion from the committee’s independent financial advisor that the consideration paid for the Acquired Pipeline Assets was fair, from a financial point of view, to the Partnership.

On May 30, 2008, the Partnership purchased the Acquired Storage Assets from the Private Company for aggregate consideration of $90.3 million, including $0.3 million of acquisition-related costs. For accounting purposes, the acquisition has been reflected as a purchase of assets, with the Acquired Storage Assets recorded at the historical cost of the Private Company, which was approximately $17.2 million, inclusive of $0.6 million of completion costs subsequent to the close of the acquisition, and with the additional purchase price of $73.1 million reflected in the statement of changes in partners’ capital as a distribution to the Private Company. The Board approved the acquisition of the Acquired Storage Assets based on a recommendation from its conflicts committee, which consisted entirely of independent directors. The conflicts committee retained independent legal and financial advisors to assist it in evaluating the transaction and considered a number of factors in approving the acquisition, including an opinion from the committee’s independent financial advisor that the consideration paid for the Acquired Storage Assets was fair, from a financial point of view, to the Partnership.

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As a result of the Private Company’s control of the Partnership’s general partner, consideration paid in excess of the historical cost of the Acquired Asphalt Assets, Acquired Pipeline Assets, and Acquired Storage Assets were treated as distributions to the Private Company. This resulted in an aggregate reduction in Partners’ Capital of $317.1 million and negative Partners’ Capital of $126.6 million as of December 31, 2008. As a result of the Private Company’s control of the Partnership’s general partner, the Partnership was subject to the risk that the Private Company may favor its own interest in proposing the terms of any acquisition (or drop downs) the Partnership makes from the Private Company and such terms may not be as favorable as those received from an unrelated third party. The Board approved the acquisition of the Acquired Asphalt Assets, the Acquired Pipeline Assets, and Acquired Storage Assets, as well as the terms of the related agreements based on a recommendation from its conflicts committee, which consisted entirely of independent directors. The conflicts committee retained independent legal and financial advisors to assist it in evaluating these transactions and considered a number of factors in approving the acquisitions, including opinions from the committee’s independent financial advisor that the consideration paid for the Acquired Asphalt Assets, the Acquired Pipeline Assets, and the Acquired Storage Assets was fair, from a financial point of view, to the Partnership.

12. MAJOR CUSTOMERS AND CONCENTRATION OF CREDIT RISK

Nexen Marketing USA, Inc. accounted for 14% of the Predecessor’s revenues for the year ended December 31, 2006. No other customers accounted for 10% or more of the Predecessor’s revenues during the year ended December 31, 2006. As a result of entering into the Throughput Agreement with the Private Company in conjunction with the Partnership’s initial public offering, the revenues generated by this customer was replaced by fees charged for services provided to the Private Company.

For the years ended December 31, 2007 and 2008, the Private Company accounted for approximately 62% and 73%, respectively, of the Partnership’s revenues, excluding fuel surcharge revenues related to fuel and power consumed to operate its liquid asphalt cement storage tanks. As a result of the Bankruptcy Filings, the Partnership has made efforts to replace revenues generated by services provided to the Private Company with revenues generated from services provided to other third party customers (see Note 19).

No other customers accounted for 10% or more of the Partnership’s revenues during the years ended December 31, 2007 and 2008.

Financial instruments that potentially subject the Partnership to concentrations of credit risk consist principally of trade receivables. The Partnership’s accounts receivable are primarily from producers, purchasers and shippers of crude oil and liquid asphalt cement and at times will include the Private Company. This industry concentration has the potential to impact the Partnership’s overall exposure to credit risk in that the customers may be similarly affected by changes in economic, industry or other conditions. The Partnership reviews credit exposure and financial information of its counterparties and generally require letters of credit for receivables from customers that are not considered creditworthy, unless the credit risk can otherwise be reduced.

13. RELATED PARTY TRANSACTIONS

Prior to the close of its initial public offering in July 2007, the Partnership entered into the Throughput Agreement with the Private Company. For the years ended December 31, 2007 and 2008, the Partnership recognized revenue of $45.6 million and $77.7 million, respectively, under the Throughput Agreement.

In conjunction with the purchase of the Acquired Asphalt Assets in February 2008, the Partnership entered into the Terminalling Agreement with the Private Company. For the year ended December 31, 2008, the Partnership recognized revenue of $65.8 million under the Terminalling Agreement, including fuel surcharge revenues related to fuel and power consumed to operate its liquid asphalt cement storage tanks.

Based on the minimum requirements under the Throughput Agreement and the Terminalling Agreement, the Private Company was obligated to pay the Partnership an aggregate minimum monthly fee totaling $135.0 million annually for the Partnership’s gathering and transportation services and the Partnership’s terminalling and storage services. Pursuant to an order of the Bankruptcy Court entered on September 9, 2008, the Private Company began making payments under the Throughput Agreement at a market rate based upon the Private Company’s actual usage rather than the contractual minimums. In connection with the Settlement, the Private Company rejected the Throughput Agreement and the Terminalling Agreement as part of its Bankruptcy Cases (see Note 19).

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In connection with the Settlement, the Partnership and the Private Company entered into various agreements including the New Throughput Agreement pursuant to which the Partnership provides certain crude oil gathering, transportation, terminalling and storage services to the Private Company and the New Terminalling Agreement pursuant to which the Partnership provides certain liquid asphalt cement terminalling and storage services for the Private Company’s remaining asphalt inventory. For a further discussion of these agreements, and the other agreements entered into in connection with the Settlement, please see Note 19.

As of December 31, 2007 and 2008, the Partnership had $9.7 million and $18.9 million, respectively, in receivables from the Private Company and its subsidiaries, including the pre-petition receivables that will be netted and waived due to the Settlement of $0 and $10.5 million, respectively. The $10.5 million relates to amounts that were due from the Private Company as of December 31, 2008 and are considered prepetition debt in the Bankruptcy Cases. In connection with the Settlement, these pre-petition related party receivables will be netted against pre-petition related party payables and waived (see Note 19).

Prior to the Bankruptcy Filings, the Partnership paid the Private Company a fixed administrative fee for providing general and administrative services to the Partnership. This fixed administrative fee was initially fixed at $5.0 million per year through July 2010. Concurrently with the closing of the purchase of the Acquired Asphalt Assets, the Partnership amended and restated the Omnibus Agreement, increasing the fixed administrative fee the Partnership paid the Private Company for providing general and administrative services to the Partnership from $5.0 million per year to $7.0 million per year. For the years ended December 31, 2007 and 2008, the Partnership paid the Private Company $2.2 million and $6.9 million, respectively, for the services provided under the Omnibus Agreement. The obligation for the Private Company to provide services under the Amended Omnibus Agreement and the corresponding administrative fee payable by the Partnership were terminated in connection with the events related to the change of control of the Partnership’s general partner. The Private Company continued to provide such services to the Partnership until the effective date of the Settlement at which time the Private Company rejected the Amended Omnibus Agreement and the Private Company and the Partnership entered into the Shared Services Agreement and the Transition Services Agreement relating to the provision of such services (see Note 19). In addition, in connection with the Settlement, the Private Company waived the fixed administrative fee payable by the Partnership under the Amended Omnibus Agreement for the month of March 2009 (see Note 19).

The Partnership also reimburses the Private Company for direct operating payroll and payroll-related costs and other operating costs associated with services the Private Company’s employees provide to the Partnership. For the years ended December 31, 2007 and 2008, the Partnership recorded $10.5 million and $30.5 million, respectively, in compensation costs and $1.3 and $3.2 million, respectively, in other operating costs related to services provided by the Private Company’s employees which are reflected as operating expenses in the accompanying statement of operations. As of December 31, 2007 and 2008, the Partnership had $10.2 million and $20.1 million in payables to the Private Company and its subsidiaries, including the pre-petition payables that will be netted and waived due to the Settlement of $0 and $10.6 million, respectively. Pursuant to the Settlement, these pre-petition related party payables will be netted against pre-petition claims related party receivables and waived (see Note 19). After the effective date of the Settlement, these costs will be reimbursed pursuant to the Shared Services Agreement and the Transition Services Agreement (see Note 19). In addition, in connection with the Settlement, the Private Company waived the direct operational costs attributable to the Partnership’s asphalt operations and payable by the Partnership under the Amended Omnibus Agreement for the month of March 2009 (see Note 19).

The Partnership has acquired various assets, including the Acquired Asphalt Assets, the Acquired Pipeline Assets and the Acquired Storage Assets, from the Private Company. See Notes 1 and 11 for a description of these acquisitions. In addition, the Partnership acquired certain liquid asphalt cement assets and crude oil assets from the Private Company in connection with the Settlement (see Note 19).

During the year ended December 31, 2008 the Partnership provided crude oil gathering and transportation services to an entity on whose board of directors a member of the Board serves. The Partnership earned revenue of $1.3 million for services it provided to this entity in 2008, and as of December 31, 2008 the Partnership has a $0.7 million receivable from this entity.

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During the years ended December 31, 2007 and 2008, the Partnership made payments of $1.2 million and $2.2 million, respectively, to a third party entity on whose board of directors a former member of the Board served in connection with leased transport trucks and trailers utilized in the Partnership’s crude oil gathering and transportation services segment. At December 31, 2008 the Partnership had future commitments to this entity totaling $7.7 million.

During 2008, the Partnership had a banking relationship with a third party banking entity on whose board of directors a former member of the Board served.

14. LONG-TERM INCENTIVE PLAN

In July 2007, the Partnership’s general partner adopted the SemGroup Energy Partners G.P., L.L.C. Long-Term Incentive Plan (the “Plan”). The compensation committee of the Board administers the Plan. The Plan authorizes the grant of an aggregate of 1.25 million common units deliverable upon vesting. Although other types of awards are contemplated under the Plan, currently outstanding awards include “phantom” units, which convey the right to receive common units upon vesting, and “restricted” units, which are grants of common units restricted until the time of vesting. The phantom unit awards also include distribution equivalent rights (“DERs”).

Subject to applicable earning criteria, a DER entitles the grantee to a cash payment equal to the cash distribution paid on an outstanding common unit prior to the vesting date of the underlying award. Recipients of restricted units are entitled to receive cash distributions paid on common units during the vesting period which distributions are reflected initially as a reduction of partners’ capital. Distributions paid on units which ultimately do not vest are reclassified as compensation expense.

In July 2007, 475,000 phantom common units and 5,000 restricted common units were granted which vest ratably over periods of four and three years, respectively. In October 2007, 5,000 restricted common units were granted which vest ratably over three years. In June 2008, 375,000 phantom common units were granted which vest ratably over three years. In July 2008, 5,000 restricted common units were granted which vest ratably over three years. These grants are equity awards under SFAS 123(R), 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 granted in 2007 and 2008 is $22.06 per unit and $25.86 per unit, respectively. The value of these award grants was approximately $10.5 million, $0.1 million, $0.1 million, $9.8 million and $0.1 million on their grant dates, respectively. Due to the change of control of the Partnership’s general partner related to the Private Company’s liquidity issues, all outstanding awards as of July 18, 2008 vested. The Partnership’s equity-based incentive compensation expense for the years ended December 31, 2007 and 2008 was $1.2 million and $19.4 million, respectively. Equity-based compensation allocated from the Private Company to the Partnership for the year ended December 31, 2006 was not significant. On August 14, 2008, 282,309 common units were issued in connection with the vesting of certain of the outstanding awards. In addition, in December 2008 the Plan was amended to provide for the delivery of subordinated units in addition to common units upon vesting and 3,333 restricted common units and 1,667 restricted subordinated units were awarded under the Plan, and as of December 31, 2008, these were the only awards outstanding under the Plan. In April 2009, the 1,667 restricted subordinated units were cancelled and were replaced by a grant of 1,667 restricted common units. In the year ended December 31, 2008, there were no forfeitures of awards.

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15. COMMITMENTS AND CONTINGENCIES

The Partnership leases certain real property, equipment and operating facilities under various operating and capital leases. It also incurs costs associated with leased land, rights-of-way, permits and regulatory fees, the contracts for which generally extend beyond one year but can be cancelled at any time should they not be required for operations. Future non-cancellable commitments related to these items at December 31, 2008, are summarized below (in thousands):

	Capital Leases			Operating Leases
For twelve months ending:
December 31, 2009	$	933		$	3,752
December 31, 2010		261			3,282
December 31, 2011		1			2,890
December 31, 2012		-			1,672
December 31, 2013		-			417
Thereafter		-			239
Total future minimum lease payments		1,195		$	12,252
Less amount representing interest		(74	)
Net future minimum lease payments		1,121
Less current portion		(866	)
	$	255

Rental expense related to leases was $1.3 million, $2.4 million and $3.8 million for each of the years ended December 31, 2006, 2007 and 2008, respectively.

The Partnership is subject to various legal actions and claims, including a securities class action and other lawsuits, an SEC investigation and a Grand Jury investigation due to events related to the Bankruptcy Filings (see Note 19). The Partnership intends to vigorously defend these actions. There can be no assurance regarding the outcome of the litigation. An estimate of possible loss, if any, or the range of loss cannot be made and therefore the Partnership has not accrued a loss contingency related to these actions. However, the ultimate resolution of these actions could have a material adverse effect on the Partnership’s business, financial condition, results of operations, cash flows, ability to make distributions to its unitholders, the trading price of the its common units and the Partnership’s ability to conduct its business.

The Partnership is from time to time subject to various legal actions and claims incidental to its business, including those arising out of environmental-related matters. Management believes that these legal proceedings will not have a material adverse effect on the financial position, results of operations or cash flows of the Partnership. Once management determines that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred and the amount of such liability can be reasonably estimated, an accrual is established equal to its estimate of the likely exposure. The Partnership did not have an accrual for legal settlements as of December 31, 2007 or 2008.

The Partnership has contractual obligations to perform dismantlement and removal activities in the event that some of its liquid asphalt cement 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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In the Amended Omnibus Agreement and other agreements with the Private Company, the Private Company agreed to indemnify the Partnership for certain environmental and other claims relating to the crude oil and liquid asphalt cement assets that have been contributed to the Partnership. In connection with the Settlement, the Partnership waived these claims and the Amended Omnibus Agreement and other relevant agreements, including the indemnification provisions therein, were rejected as part of the Bankruptcy Cases. If the Partnership experiences an environmental or other loss, it would experience losses that may have a material adverse effect on its business, financial condition, results of operations, cash flows, ability to make distributions to its unitholders, the trading price of its common units and the ability to conduct its business.

16. ENVIRONMENTAL REMEDIATION

The Partnership maintains insurance of various types with varying levels of coverage that it considers adequate under the circumstances to cover its operations and properties. The insurance policies are subject to deductibles and retention levels that the Partnership considers reasonable and not excessive. Consistent with insurance coverage generally available in the industry, in certain circumstances the Partnership’s insurance policies provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences. Although the Partnership maintains a program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to environmental releases from its assets may substantially affect its business.

At December 31, 2007 and 2008, the Partnership was not aware of any existing conditions that may cause it to incur significant expenditures in the future for the remediation of existing contamination. As such, the Partnership has not reflected in the accompanying financial statements any liabilities for environmental obligations to be incurred in the future based on existing contamination. Changes in the Partnership’s estimates and assumptions may occur as a result of the passage of time and the occurrence of future events.

17. OPERATING SEGMENTS

The Partnership’s operations consist of three operating segments: (i) crude oil terminalling and storage services, (ii) crude oil gathering and transportation services and (iii) asphalt services. Historically, management evaluated the performance of the Partnership’s operations by aggregating both the crude oil terminalling and storage reporting unit and the asphalt services reporting unit due to both units having the same primary customer (the Private Company) and similar service contracts. As a result of the Bankruptcy Filings, the services provided by these reporting units are no longer for the same customer base nor are they based on contracts with similar provisions. As a result, the Partnership now has three reporting segments as follows:

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

CRUDE OIL GATHERING AND TRANSPORTATION SERVICES —The Partnership owns and operates two pipeline systems, the Mid-Continent system and the Longview system, that gather crude oil purchased by the Private Company and its other customers and transports it to refiners, to common carrier pipelines for ultimate delivery to refiners or to terminalling and storage facilities owned by the Partnership and others. The Partnership refers to its gathering and transportation system located in Oklahoma and the Texas Panhandle as the Mid-Continent system. It refers to its second gathering and transportation system, which is located in Texas, as the Longview system. In addition to its pipelines, the Partnership uses its owned and leased tanker trucks to gather crude oil for the Private Company and its other 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. In connection with its gathering services, the Partnership also provides a number of producer field services, ranging from gathering condensates from natural gas companies to hauling produced water to disposal wells.

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

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

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

	Crude Oil Terminalling and Storage		Crude Oil Gathering and Transportation			Asphalt Services		Total
	(in thousands)
Year ended December 31, 2006
Service revenue
Third party revenue	$	8,345	$	19,764		$	-	$	28,109
Related party revenue		730		-			-		730
Total revenue for reportable segments		9,075		19,764			-		28,839	(1)
Operating expense (excluding depreciation and amortization)		2,334		40,677			-		43,011
Operating margin (excluding depreciation and amortization)		6,741		(20,913	)		-		(14,172	)(2)
Additions to long-lived assets		22,586		13,969			-		36,555
Total assets (end of period)		54,221		50,626			-		104,847

Year ended December 31, 2007
Service revenue
Third party revenue	$	7,857	$	20,446		$	-	$	28,303
Related party revenue		16,894		29,368			-		46,262
Total revenue for reportable segments		24,751		49,814			-		74,565	(1)
Operating expense (excluding depreciation and amortization)		2,024		55,680			-		57,704
Operating margin (excluding depreciation and amortization)		22,727		(5,866	)		-		16,861	(2)
Additions to long-lived assets		12,566		7,016			-		19,582
Total assets (end of period)		65,508		59,974			-		125,482

Year ended December 31, 2008
Service revenue
Third party revenue	$	13,877	$	34,416		$	2	$	48,295
Related party revenue		28,089		49,953			65,843		143,885
Total revenue for reportable segments		41,966		84,369			65,845		192,180
Operating expense (excluding depreciation and amortization)		2,353		58,269			21,560		82,182
Allowance for doubtful accounts		-		568			-		568
Operating margin (excluding depreciation and amortization)		39,613		25,532			44,285		109,430	(2)
Additions to long-lived assets		17,299		38,834			147,766		203,899
Total assets (end of period)		89,450		103,238			161,953		354,641

(1) Historically, the Predecessor was a part of the integrated operations of the Private Company, and neither the Private Company nor the Predecessor recorded revenue associated with the terminalling and storage and gathering and transportation services provided on an intercompany basis. Accordingly, revenues reflected for all periods prior to the contribution of the assets, liabilities and operations to the Partnership by the Private Company on July 20, 2007 are substantially services provided to third parties.

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

	Year Ended December 31,
	2006			2007			2008
	(in thousands)
Operating margin (excluding depreciation and amortization)	$	(14,172	)	$	16,861		$	109,430
Depreciation and amortization		8,597			9,478			21,328
General and administrative expenses		11,097			13,595			43,085
Interest expense		1,989			6,560			26,951
Income (loss) before income taxes	$	(35,855	)	$	(12,772	)	$	18,066

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18. RECENTLY ISSUED ACCOUNTING STANDARDS

In April 2009, the Financial and Accounting Standards Board (FASB) issued FASB Staff Position (FSP) Statement No. 107-1 and Accounting Principles Board (APB) 28-1 (collectively, FSP FAS 107-1), “Interim Disclosures about Fair Value of Financial Instruments.” FSP FAS 107-1 amends FAS 107, “Disclosures about Fair Value of Financial Instruments,” to require an entity to provide disclosures about fair value of financial instruments in interim financial information. The FSP FAS 107-1 also amends APB Opinion 28, “Interim Financial Reporting,” to require those disclosures in summarized financial information at interim reporting periods. Under FSP FAS 107-1, the Partnership will be required to include disclosures about the fair value of its financial instruments whenever it issues financial information for interim reporting periods. In addition, the Partnership will be required to disclose in the body or in the accompanying notes of its summarized financial information for interim reporting periods and in its financial statements for annual reporting periods the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position. FSP FAS 107-1 is effective for periods ending after June 15, 2009. The Partnership is currently evaluating the impact FSP FAS 107-1 may have on our consolidated financial statements.

In June 2008, the Emerging Issues Task Force (“EITF”) issued Issue No. 03-6-1, “ Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities “ (“EITF 03-6-1”). EITF 03-6-1 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share (“EPS”) under the two-class method. EITF 03-6-1 will be effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. All prior-period EPS data presented will be adjusted retrospectively to conform with the provisions of EITF 03-6-1. The Partnership is evaluating the expected impact of adoption of EITF 03-6-1.

In April 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) No. FAS 142-3 “ Determination of the Useful Life of Intangible Assets “ (“FSP No. FAS 142-3”). FSP No. FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “ Goodwill and Other Intangible Assets “ (“SFAS 142”). The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141 (revised 2007), “ Business Combinations ,” and other GAAP. This FSP will be effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. The Partnership is evaluating the expected impact; however, it believes adoption will not impact the Partnership’s financial position, results of operations or cash flows.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 133” (“SFAS No. 161”). This Statement requires enhanced disclosures about the Partnership’s derivative and hedging activities. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The Partnership will adopt SFAS No. 161 beginning January 1, 2009. With the adoption of this statement, the Partnership does not expect any significant impact on its financial position, results of operations or cash flows.

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Issue No. 07-4 is effective for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. The accounting treatment is effective for all financial statements presented. The Partnership does not expect the impact of the adoption of Issue 07-4 on its presentation of earnings per unit to be significant.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” This statement requires assets acquired and liabilities assumed to be measured at fair value as of the acquisition date, acquisition related costs incurred prior to the acquisition to be expensed and contractual contingencies to be recognized at fair value as of the acquisition date. This statement is effective for financial statements issued for fiscal years beginning after December 15, 2008. The Partnership is currently assessing the impact, if any, the adoption of this statement will have on its financial position, results of operations or cash flows.

19. EVENTS RELATED TO THE BANKRUPTCY FILINGS AND SUBSEQUENT EVENTS

Due to the events related to the Bankruptcy Filings described herein, including the uncertainty relating to the Partnership’s ability to comply with certain restrictive financial covenants specified in its credit facility, its exposure and sensitivity to interest rate risks given the materiality of its borrowings under its credit facility, and uncertainties related to securities and other litigation, the Partnership faces substantial doubt as to its ability to continue as a going concern. While it is not feasible to predict the ultimate outcome of the events surrounding the Bankruptcy Cases (as defined below), the Partnership has been and could continue to be materially and adversely affected by such events and it may be forced to make a bankruptcy filing or take other action that could have a material adverse effect on its business, the price of its common units and its results of operations.

Bankruptcy Filings

On July 17, 2008, the Partnership issued a press release announcing that the Private Company was experiencing liquidity issues and was exploring various alternatives, including raising additional equity, debt capital or the filing of a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code to address these issues. The Partnership filed this press release in a Current Report on Form 8-K filed with the SEC on July 18, 2008.

On July 22, 2008 and thereafter, the Private Company and certain of its subsidiaries made the Bankruptcy Filings. The Private Company and its subsidiaries continue to operate their businesses and own and manage their properties as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code (the “Bankruptcy Cases”). None of the Partnership, its general partner, the subsidiaries of the Partnership nor the subsidiaries of the general partner are debtors in the Bankruptcy Cases. However, because of the contractual relationships with the Private Company and certain of its subsidiaries, the Bankruptcy Filings have adversely impacted the Partnership and may in the future impact the Partnership in various ways, including the items discussed below. The Partnership’s financial results as of December 31, 2008 also reflect a $0.6 million allowance for doubtful accounts related to amounts due from third parties as of December 31, 2008. The allowance related primarily to amounts due from third parties was established as a result of certain third party customers netting amounts due them from the Private Company with amounts due to the Partnership. Also, due to the change of control of the Partnership’s general partner related to the Private Company’s liquidity issues, all outstanding awards under the Plan vested on July 18, 2008, resulting in an incremental $18.0 million in non-cash compensation expense for the year ended December 31, 2008 (see Note 14). In addition to the allowance for doubtful accounts and non-cash compensation expense described above, the results of operations for the year ended December 31, 2008 included in this annual report were affected by the Bankruptcy Filings and related events, which resulted in decreased revenues and increased general and administrative expenses as described below under “—Partnership Revenues,” and “—Other Effects,” respectively.

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Board and Management Composition

On July 9, 2008, Edward F. Kosnik was appointed as an independent member of the Board. Mr. Kosnik is the chairman of the compensation committee and also serves on the audit committee and the conflicts committee of the Board. Under the provisions of the Plan, Mr. Kosnik was granted an award of 5,000 restricted common units on July 9, 2008. These restricted common units vested on July 18, 2008 in connection with the change of control of the Partnership’s general partner described below.

On July 18, 2008, Manchester Securities Corp. (“Manchester”) and Alerian Finance Partners, LP (“Alerian”), as lenders to SemGroup Holdings, the sole member of the Partnership’s general partner, exercised certain rights described below under a Loan Agreement and a Pledge Agreement, each dated June 25, 2008 (the “Holdings Credit Agreements”), that were triggered by certain events of default under the Holdings Credit Agreements. On March 20, 2009, Alerian transferred its interest in the Holdings Credit Agreements to Manchester (Alerian is still potentially entitled to receive a portion of certain potential recoverable value from such interest). The Holdings Credit Agreements are secured by the subordinated units and incentive distribution rights of the Partnership and the membership interests in the Partnership’s general partner owned by SemGroup Holdings. Manchester has not foreclosed on the subordinated units of the Partnership owned by SemGroup Holdings or the membership interests in the Partnership’s general partner. Manchester may in the future exercise other remedies available to them under the Holdings Credit Agreement and related loan documents, including taking action to foreclose on the collateral securing the loan. Neither the Partnership nor the Partnership’s general partner is a party to the Holdings Credit Agreements or the related loan documents.

On July 18, 2008, Manchester and Alerian exercised their right under the Holdings Credit Agreements in connection with certain events of default thereunder to vote the membership interests of the Partnership’s general partner in order to reconstitute the Board (the “Change of Control”). Messrs. Thomas L. Kivisto, Gregory C. Wallace, Kevin L. Foxx, Michael J. Brochetti and W. Anderson Bishop were removed from the Board. Mr. Bishop had served as the chairman of the audit committee and as a member of the conflicts committee and compensation committee of the Board. Messrs. Sundar S. Srinivasan, David N. Bernfeld and Gabriel Hammond (each of whom is affiliated with Manchester or Alerian) were appointed to the Board. Mr. Srinivasan was elected as Chairman of the Board. Messrs. Brian F. Billings and Edward F. Kosnik remain as independent directors of the Board and continue to serve as members of the conflicts committee, audit committee and compensation committee of the Board. In addition, Messrs. Foxx and Alex Stallings resigned the positions each officer held with SemGroup, L.P. in July 2008. Mr. Brochetti had previously resigned from his position with SemGroup, L.P. in March 2008. Messrs. Foxx, Brochetti and Stallings remain as officers of the Partnership’s general partner.

On October 1, 2008, Dave Miller (who is an affiliate of Manchester) and Duke R. Ligon were appointed members of the Board. Mr. Ligon is an independent member of the Board and is the chairman of the audit committee and also serves on the compensation committee and the conflicts committee of the Board. Under the provisions of the Plan, Mr. Ligon was granted an award of 3,333 restricted common units and 1,667 restricted subordinated units on December 23, 2008 (see Note 14). In April 2009, the 1,667 restricted subordinated units granted to Mr. Ligon were cancelled and replaced with 1,667 restricted common units (see Note 14). The restricted common units granted to Mr. Ligon vest in one-third increments over a three-year period.

On January 9, 2009, Mr. Srinivasan resigned his positions as Chairman of the Board and as a director. Mr. Ligon was subsequently elected as Chairman of the Board.

On March 18, 2009, the Board realigned the officers of the Partnership’s general partner appointing Michael J. Brochetti as Executive Vice President—Corporate Development and Treasurer, Alex G. Stallings as Chief Financial Officer and Secretary, and James R. Griffin as Chief Accounting Officer. Mr. Brochetti had previously served as Chief Financial Officer, Mr. Stallings had previously served as Chief Accounting Officer and Secretary and Mr. Griffin had previously served as controller.

SemGroup Holdings is party to the Bankruptcy Cases. On May 15, 2009, the Private Company filed the Reorganization Plan. The Reorganization Plan does not address the reorganization of SemGroup Holdings, including the satisfaction of any obligations it has to Manchester under the Holdings Credit Agreements or the disposition of the ownership interests in the Partnership’s general partner or the Partnership’s subordinated units and incentive distribution rights. The membership units in the Partnership’s general partner, as well as the Partnership’s subordinated units and its incentive distribution rights, may be transferred, without the consent of the Partnership’s unitholders, to a third party as part of the Bankruptcy Cases or subsequent to the resolution of the Bankruptcy Cases. Furthermore, Manchester may transfer all or a portion of its interests in the Holdings Credit Agreements (including its rights to vote the membership interest in the Partnership’s general partner) to a third party. Any new owner of the Partnership’s general partner or holder of such voting rights would be in a position to replace the board of directors and officers of the Partnership’s general partner with its own choices and thereby influence the decisions made by the board of directors and officers. In addition, any such change of control of the Partnership or its general partner will result in an event of default under the Partnership’s credit agreement, may result in additional uncertainty in the Partnership’s operations and business and could have a material adverse effect on the Partnership’s business, cash flows, ability to make distributions to its unitholders, the price of its common units, its results of operations and ability to conduct its business.

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Bankruptcy Court Order

On September 9, 2008, the Bankruptcy Court entered an order relating to the settlement of certain matters between the Partnership and the Private Company (the “Order”) in the Bankruptcy Cases. Among other things, the Order provided that (i) the Private Company was to directly pay any utility costs attributable to the operations of the Private Company at certain shared facilities, and the Private Company was to pay the Partnership for past utility cost reimbursements that were due from the Private Company; (ii) commencing on September 15, 2008, payments under the Terminalling Agreement were netted against amounts due under the Amended Omnibus Agreement and were made on the 15th day of each month for the prior month (with a three business-day grace period); (iii) the Private Company provided the Partnership with a letter of credit in the amount of approximately $4.9 million to secure the Private Company’s postpetition obligations under the Terminalling Agreement; (iv) the Private Company was to make payments under the Throughput Agreement for the month of August on September 15, 2008 (with a three business-day grace period) based upon the monthly contract minimums in the Throughput Agreement and netted against amounts due under the Amended Omnibus Agreement; (v) the Private Company was to make payments under the Throughput Agreement for the months of September and October on October 15, 2008 (with a three business-day grace period) and November 15, 2008 (with a three business-day grace period), respectively, or three business days after amounts due are determined and documentation therefore was provided and exchanged based upon actual volumes for each such month and at a rate equal to the average rate charged by the Partnership to third-party shippers in the same geographical area, with any such amounts netted against amounts due under the Amended Omnibus Agreement; (vi) the parties were to reevaluate the Throughput Agreement and the payment terms with respect to services provided after October 2008; (vii) representatives of the Private Company and the Partnership were to meet to discuss the transition to the Partnership of certain of the Private Company’s employees necessary to maintain the Partnership’s business, and pending agreement between the parties, the Private Company was to continue to provide services in accordance with the Amended Omnibus Agreement through at least November 30, 2008; (viii) the Private Company was to consent to an order relating a third-party storage contract which provided that the Partnership was the rightful owner of the rights in and to a certain third-party storage agreement and the corresponding amounts due thereunder; and (ix) the Partnership was to enter into a specified lease with the Private Company to permit the Private Company to construct a pipeline.

Settlement with the Private Company

On March 12, 2009, the Bankruptcy Court held a hearing and approved the transactions contemplated by a term sheet (the “Settlement Term Sheet”) relating to the settlement of certain matters between the Private Company and the Partnership (the “Settlement”). The Bankruptcy Court entered an order approving the Settlement upon the terms contained in the Settlement Term Sheet on March 20, 2009. The Partnership and the Private Company executed definitive documentation, in the form of a master agreement (the “Master Agreement”), dated April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, and certain other transaction documents to effectuate the Settlement and that superseded the Settlement Term Sheet. The Bankruptcy Court entered an order approving the Master Agreement and the Settlement on April 7, 2009. In addition, in connection with the Settlement, the Partnership and the requisite lenders under the Partnership’s secured credit facility entered into the Credit Agreement Amendment under which, among other things, the lenders consented to the Settlement and waived all existing defaults and events of default described in the Forbearance Agreement and amendments thereto.

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The Settlement provided for the following:

·	the Partnership transferred certain crude oil storage assets located in Kansas and northern Oklahoma to the Private Company;

·	the Private Company transferred ownership of 355,000 barrels of crude oil tank bottoms and line fill to the Partnership;

·	the Private Company rejected the Throughput Agreement;

·	the Partnership and one of its subsidiaries have a $20 million unsecured claim against the Private Company and certain of its subsidiaries relating to rejection of the Throughput Agreement;

·	the Partnership and the Private Company entered into the New Throughput Agreement (as defined below) pursuant to which the Partnership provides certain crude oil gathering, transportation, terminalling and storage services to the Private Company;

·	the Partnership offered employment to certain crude oil employees;

·	the Private Company transferred its asphalt assets that are connected to the Acquired Asphalt Assets to the Partnership;

·	the Private Company rejected the Terminalling Agreement;

·	a subsidiary of the Partnership has a $35 million unsecured claim against the Private Company and certain of its subsidiaries relating to rejection of the Terminalling Agreement;

·	the Partnership and the Private Company entered into the New Terminalling Agreement (as defined below) pursuant to which the Partnership provides liquid asphalt cement terminalling and storage services for the Private Company’s remaining asphalt inventory;

·	the Private Company agreed to remove all of its remaining asphalt inventory from the Partnership’s asphalt storage facilities no later than October 31, 2009;

·	the Private Company will be entitled to receive 20% of the proceeds of any sale by the Partnership of any of the asphalt assets transferred to the Partnership in connection with the Settlement that occurs prior to December 31, 2009;

·	the Private Company rejected the Amended Omnibus Agreement;

·	the Partnership and the Private Company entered into the Shared Services Agreement (as defined below) pursuant to which the Private Company provides certain operational services for the Partnership;

·	other than as provided above, the Partnership and the Private Company entered into mutual releases of claims relating to the rejection of the Terminalling Agreement, the Throughput Agreement and the Amended Omnibus Agreement;

·	certain pre-petition claims by the Private Company and the Partnership were netted and waived;

the Private Company and the Partnership resolved certain remaining issues related to the contribution of crude oil assets to the Partnership in connection with the Partnership’s initial public offering, the Partnership’s acquisition of the Acquired Asphalt Assets, the Partnership’s acquisition of the Acquired Pipeline Assets and the Partnership’s acquisition of the Acquired Storage Assets, including the release of claims relating to such acquisitions; and

the Partnership and the Private Company entered into the Trademark Agreement (as defined below) which provides the Partnership with a non-exclusive, worldwide license to use certain trade names, including the name “SemGroup”, and the corresponding mark until December 31, 2009, and the Private Company waived claims for infringement relating to such trade names and mark prior to the date of such license agreement.

Management is obtaining independent valuations of the assets transferred. Certain terms of transaction documents relating to the Settlement are discussed in more detail below.

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Shared Services Agreement

In connection with the Settlement, the Partnership entered into a Shared Services Agreement, dated April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009 (the “Shared Services Agreement”), with the Private Company. Pursuant to the Shared Services Agreement, the Private Company will provide certain general shared services, Cushing shared services (as described below), and SCADA services (as described below) to the Partnership.

The general shared services include crude oil movement services, Department of Transportation services, right-of-way services, environmental services, pipeline and civil structural maintenance services, safety services, pipeline truck station maintenance services, project support services and truck dispatch services. The fees for such general shared services are fixed at $125,000 for the month of April 2009. Thereafter the fees will be calculated in accordance with the formulas contained therein. The Private Company has agreed to provide the general shared services for three years (subject to earlier termination as provided therein) and the term may be extended an additional year by mutual agreement of the parties.

The Cushing shared services include operational and maintenance services related to terminals at Cushing, Oklahoma. The fees for such Cushing shared services are fixed at $20,000 for the month of April 2009. Thereafter the fees will be calculated in accordance with the formulas contained therein. The Private Company has agreed to provide the Cushing shared services for three years (subject to earlier termination as provided therein) and the term may be extended an additional year by mutual agreement of the parties.

The SCADA services include services related to the operation of the SCADA system which is used in connection with the Partnership’s crude oil operations. The fees for such SCADA services are fixed at $15,000 for the month of April 2009. Thereafter the fees will be calculated in accordance with the formulas contained therein. The Private Company has agreed to provide the SCADA services for five years (subject to earlier termination as provided therein) and the Partnership may elect to extend the term for two subsequent five year periods.

Transition Services Agreement

In connection with the Settlement, the Partnership entered into a Transition Services Agreement, dated April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009 (the “Transition Services Agreement”), with the Private Company. Pursuant to the Transition Services Agreement, the Private Company will provide certain corporate, crude oil and asphalt transition services, in each case for a limited amount of time, to the Partnership.

Transfer of Crude Oil Assets

In connection with the Settlement, the Partnership transferred certain crude oil assets located in Kansas and northern Oklahoma to the Private Company. These transfers included real property and associated personal property at locations where the Private Company owned the pipeline. The Partnership retained certain access and connection rights to enable it to continue to operate its crude oil trucking business in such areas. In addition, the Partnership transferred its interests in the SCADA System, a crude oil inventory tracking system, to the Private Company.

In addition, the Private Company transferred to the Partnership (i) 355,000 barrels of crude oil line fill and tank bottoms, which are necessary for the Partnership to operate its crude oil tank storage operations and its Oklahoma and Texas crude oil pipeline systems, (ii) certain personal property located in Oklahoma, Texas and Kansas used in connection with the Partnership’s crude oil trucking business and (iii) certain real property located in Oklahoma, Kansas, Texas and New Mexico that was intended to be transferred in connection with the Partnership’s initial public offering.

Transfer of Asphalt Assets

In connection with the Settlement, the Private Company transferred certain asphalt processing assets that were connected to, adjacent to, or otherwise contiguous with the Partnership’s existing asphalt facilities and associated real property interests to the Partnership. The transfer of the Private Company’s asphalt assets in connection with the Settlement provides the Partnership with outbound logistics for its existing asphalt assets and, therefore, allows it to provide asphalt terminalling, storage and processing services to third parties.

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New Throughput Agreement

In connection with the Settlement, the Partnership and the Private Company entered into a Throughput Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009 (the “New Throughput Agreement”), pursuant to which the Partnership provides certain crude oil gathering, transportation, terminalling and storage services to the Private Company.

Under the New Throughput Agreement, the Partnership charges the following fees: (i) barrels gathered via gathering lines will be charged a gathering rate of $0.75 per barrel, (ii) barrels transported within Oklahoma will be charged $1.00 per barrel while barrels transported on the Masterson Mainline will be charged $0.55 per barrel, (iii) barrels transported by truck will be charged in accordance with the schedule contained therein, including a fuel surcharge, (iv) storage fees shall equal $0.50 per barrel per month for product located in storage tanks located in Cushing, Oklahoma and $0.44 per barrel per month for product not located in dedicated Cushing storage tanks, and (v) a delivery charge of $0.08 per barrel will be charged for deliveries out of the Cushing Interchange Terminal. The New Throughput Agreement has an initial term of one year with additional automatic one-month renewals unless either party terminates the agreement upon thirty-days prior notice.

New Terminalling and Storage Agreement

In connection with the Settlement, the Partnership and the Private Company entered into a Terminalling and Storage Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009 (the “New Terminalling Agreement”), pursuant to which the Partnership provides certain asphalt terminalling and storage services for the remaining asphalt inventory of the Private Company. Storage services under the New Terminalling Agreement are equal to $0.565 per barrel per month multiplied by the total shell capacity in barrels for each storage tank where the Private Company and its affiliates have product; provided that if the Private Company removes all product from a storage tank prior to the end of the month, then the storage service fees shall be pro-rated for such month based on the number of calendar days storage was actually used. Throughput fees under the New Terminalling Agreement are equal to $9.25 per ton; provided that no fees are payable for transfers of product between storage tanks located at the same or different terminals. The New Terminalling Agreement has an initial term that expires on October 31, 2009, which may be extended for one month by mutual agreement of the parties.

New Access and Use Agreement

In connection with the Settlement, the Partnership and the Private Company entered into an Access and Use Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009 (the “New Access and Use Agreement”), pursuant to which the Partnership will allow the Private Company access rights to the Partnership’s asphalt facilities relating to its existing asphalt inventory. The term of the Access and Use Agreement will end separately for each terminal upon the earlier of October 31, 2009 or until all of the existing asphalt inventory of the Private Company is removed from such terminal.

Trademark Agreement

In connection with the Settlement, the Private Company and the Partnership entered into a Trademark License Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009 (the “Trademark Agreement”), pursuant to which the Private Company granted the Partnership a non-exclusive, worldwide license to use certain trade names, including the name “SemGroup”, and the corresponding mark until December 31, 2009, and the Private Company waived claims for infringement relating to such trade names and mark prior to the effective date of the Trademark Agreement.

Building and Office Leases

In connection with the Settlement, the Partnership leased office space in Oklahoma City, Oklahoma and certain facilities in Cushing, Oklahoma to the Private Company. The terms for the leases expire on March 31, 2014. The rents for such leases are as described in the exhibits thereto.

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Easements

In connection with the Settlement, the Partnership and the Private Company granted mutual easements relating to access, facility improvements, existing and future pipeline rights and corresponding rights of ingress and egress for properties owned by the parties at Cushing, Oklahoma. In addition, the Partnership granted the Private Company certain pipeline easements at Cushing, Oklahoma, together with the corresponding rights of ingress and egress.

Partnership Revenues

For the year ended December 31, 2008, the Partnership derived approximately 73% of its revenues, excluding fuel surcharge revenues related to fuel and power consumed to operate its liquid asphalt cement storage tanks, from services it provided to the Private Company and its subsidiaries. Prior to the Order and the Settlement, the Private Company was obligated to pay the Partnership minimum monthly fees totaling $76.1 million annually and $58.9 million annually in respect of the minimum commitments under the Throughput Agreement and the Terminalling Agreement, respectively, regardless of whether such services were actually utilized by the Private Company. As described above, the Order required the Private Company to make certain payments under the Throughput Agreement and Terminalling Agreement during a portion of the third and fourth quarters of 2008, including the contractual minimum payments under the Terminalling Agreement. In connection with the Settlement, the Partnership waived the fees due under the Terminalling Agreement during March 2009. In addition, the Private Company rejected the Throughput Agreement and the Terminalling Agreement and the Partnership and the Private Company entered into the New Throughput Agreement and the New Terminalling Agreement. The Partnership expects revenues from services provided to the Private Company under the New Throughput Agreement and New Terminalling Agreement to be substantially less than prior revenues from services provided to the Private Company as the new agreements are based upon actual volumes gathered, transported, terminalled and stored instead of certain minimum volumes and are at reduced rates when compared to the Throughput Agreement and Terminalling Agreement.

The Partnership has been pursuing opportunities to provide crude oil terminalling and storage services, crude oil gathering and transportation services and asphalt services to third parties. As a result of new crude oil third-party storage contracts, the Partnership increased its third-party terminalling and storage revenue from approximately $1.0 million, or approximately 10% of total terminalling and storage revenue during the second quarter of 2008, to approximately $4.6 million and $8.4 million, or approximately 41% and 83% of total terminalling and storage revenue for the third and fourth quarter of 2008, respectively.

In addition, as a result of new third-party crude oil transportation contracts and reduced commitments of usage by the Private Company under the Throughput Agreement, the Partnership increased its third-party crude oil gathering and transportation revenue from approximately $5.0 million, or approximately 21% of total gathering and transportation revenue during the second quarter of 2008, to approximately $10.9 million and $13.6 million, or approximately 51% and 85% of total crude oil gathering and transportation revenue for the third and fourth quarter of 2008, respectively.

The significant majority of the increase in third party revenues results from an increase in third-party crude oil services provided and a corresponding decrease in crude oil services provided to the Private Company due to the termination of the monthly contract minimum revenues under the Throughput Agreement in September 2008. Average rates for the new third-party crude oil terminalling and storage and gathering and transportation contracts are comparable with those previously received from the Private Company. However, the volumes being terminalled, stored, gathered and transported have decreased as compared to periods prior to the Bankruptcy Filings, which has negatively impacted total revenues. As an example, fourth quarter 2008 total revenues are approximately $9.5 million (or approximately 19%) less than second quarter 2008 total revenues, in each case excluding fuel surcharge revenues related to fuel and power consumed to operate its liquid asphalt cement storage tanks.

In addition, the Partnership has recently entered into leases and storage agreements with third parties relating to 45 of its 46 asphalt facilities.

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The Partnership has entered into various crude oil transportation and storage contracts with third parties and is continuing to pursue additional contracts with third parties; however, these additional efforts may not be successful. In addition, certain third parties may be less likely to enter into business transactions with the Partnership due to the Bankruptcy Filings. The Private Company may also choose to curtail its operations or liquidate its assets as part of the Bankruptcy Cases. As a result, unless the Partnership is able to generate additional third party revenues, the Partnership will continue to experience lower volumes in its system which could have a material adverse effect on its results of operations and cash flows.

Asphalt Operations

Historically, the Partnership provided liquid asphalt cement terminalling and storage services to the Private Company pursuant to the Terminalling Agreement. In connection with the Settlement, the Private Company rejected the Terminalling Agreement and the Partnership and the Private Company entered into the New Terminalling Agreement whereby the Partnership provides liquid asphalt cement terminalling and storage services to the Private Company in connection with its remaining asphalt inventory. The New Terminalling Agreement has an initial term that ends on October 31, 2009 and the Private Company has agreed to remove all of its existing asphalt inventory no later than such date, and the Partnership expects that the Private Company may remove it much earlier than such date. Also in connection with the Settlement, the Private Company transferred certain asphalt assets to the Partnership that were connected to the Partnership’s existing asphalt assets. The transfer of the Private Company’s asphalt assets in connection with the Settlement provides the Partnership with outbound logistics for its existing asphalt assets and, therefore, allows it to provide asphalt terminalling, storage and processing services to third parties.

The asphalt industry in the United States is characterized by a high degree of seasonality. Much of this seasonality is due to the impact that weather conditions have on road construction schedules, particularly in cold weather states. Refineries produce liquid asphalt cement year round, but the peak asphalt demand season is during the warm weather months when most of the road construction activity in the United States takes place. As a result, liquid asphalt cement is typically purchased from refineries at low prices in the low demand winter months and then processed and sold at higher prices in the peak summer demand season. Any significant decrease in the amount of revenues that the Partnership receives from its liquid asphalt cement terminalling, storage and processing operations could have a material adverse effect on the Partnership’s cash flows, financial condition and results of operations.

The Partnership has recently entered into leases and storage agreements with third parties relating to 45 of its 46 asphalt facilities.

The revenues that the Partnership will receive pursuant to these leases and storage agreements will be less than the revenues received under the Terminalling Agreement with the Private Company. Without sufficient revenues from its asphalt assets, the Partnership may be unable to meet the covenants, including the minimum liquidity, minimum EBITDA and minimum receipt requirements, under its credit agreement.

Operation and General Administration of the Partnership

As is the case with many publicly traded partnerships, the Partnership has not historically directly employed any persons responsible for managing or operating the Partnership or for providing services relating to day-to-day business affairs. Pursuant to the Amended Omnibus Agreement, the Private Company operated the Partnership’s assets and performed other administrative services for the Partnership such as accounting, legal, regulatory, development, finance, land and engineering. The events related to the Bankruptcy Filings terminated the Private Company’s obligations to provide services to the Partnership under the Amended Omnibus Agreement. The Private Company continued to provide such services to the Partnership until the effective date of the Settlement at which time the Private Company rejected the Amended Omnibus Agreement and the Private Company and the Partnership entered into the Shared Services Agreement and the Transition Services Agreement relating to the provision of such services. In addition, in connection with the Settlement, the Partnership made offers of employment to, and now employs, certain individuals associated with its crude oil operations and subsequently made additional offers of employment to, and now employs, certain individuals associated with its asphalt operations. The costs to directly employ these individuals as well as the costs under the Shared Services Agreement and the Transition Services Agreement may be higher than those previously paid by the Partnership under the Amended Omnibus Agreement, which could have a material adverse effect on the Partnership’s business, cash flows, ability to make distributions to its unitholders, the price of its common units, its results of operations and ability to conduct its business.

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In addition, in connection with the Settlement, the Partnership agreed to not solicit the Private Company’s employees for a year from the time of the Settlement. In connection with the Bankruptcy Cases, the Private Company may reduce a substantial number of its employees or some of the Private Company’s employees may choose to terminate their employment with the Private Company, some of whom may currently be providing general and administrative and operating services to the Partnership under the Shared Services Agreement or the Transition Services Agreement. Any reductions in critical personnel who provide services to the Partnership and any increased costs to replace such personnel could have a material adverse effect on the Partnership’s business, cash flows, ability to make distributions to its unitholders, the price of its common units, its results of operations and ability to conduct its business.

Intellectual Property Rights

Pursuant to the Amended Omnibus Agreement, the Partnership licensed the use of certain trade names and marks, including the name “SemGroup.” This license terminated automatically upon the Change of Control. In connection with the Settlement, the Private Company and the Partnership entered into the Trademark Agreement, pursuant to which the Private Company granted the Partnership a non-exclusive, worldwide license to use certain trade names, including the name “SemGroup” and the corresponding mark, until December 31, 2009, and the Private Company waived claims for infringement relating to such trade names and mark prior to the effective date of such Trademark Agreement (see “—Settlement with the Private Company”). As such, the Partnership will be required to change its name and trademark upon or prior to the expiration of the Trademark Agreement. The expenses associated with such a change may be significant, which could have a material adverse effect on the Partnership’s business, financial condition, results of operations, cash flows, ability to make distributions to its unitholders, the trading price of its common units and its ability to conduct its business.

Credit Facility

As described in Note 8, in connection with the events related to the Bankruptcy Filings, events of default occurred under the Partnership’s credit agreement. On September 18, 2008, the Partnership and the requisite lenders under its credit facility entered into the Forbearance Agreement relating to such events of default. On April 7, 2009, the Partnership and the requisite lenders entered into the Credit Agreement Amendment, under which the lenders consented to the Settlement and waived all existing defaults and events of default described in the Forbearance Agreement and amendments thereto. See Note 8 for more information regarding the Partnership’s credit facility, the Forbearance Agreement and the Credit Agreement Amendment.

Distributions to Unitholders

The Partnership did not make a distribution to its common unitholders, subordinated unitholders or general partner attributable to the results of operations for the quarters ended June 30, 2008, September 30, 2008, December 31, 2008 or March 31, 2009 due to the events of default under its credit agreement and the uncertainty of its future cash flows relating to the Bankruptcy Filings. In addition, the Partnership does not currently expect to make a distribution relating to the second quarter of 2009. The Partnership’s unitholders will be required to pay taxes on their share of the Partnership’s taxable income even though they did not receive a cash distribution for such periods. The Partnership distributed approximately $14.3 million to its unitholders for the three months ended March 31, 2008. Pursuant to the Credit Agreement Amendment, the Partnership is prohibited from making distributions to its unitholders if its leverage ratio (as defined in the credit agreement) exceeds 3.50 to 1.00. As of December 31, 2008, the Partnership’s leverage ratio was 4.86 to 1.00. If the Partnership’s leverage ratio does not improve, it may not make quarterly distributions to its unitholders in the future.

The Partnership’s partnership agreement provides that, during the subordination period, which the Partnership is currently in, the Partnership’s common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.3125 per common unit per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units.

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Nasdaq Delisting

Effective at the opening of business on February 20, 2009, trading in the Partnership’s common units was suspended on the Nasdaq Global Market (“Nasdaq”) due to its failure to timely file its periodic reports with the SEC, and the Partnership’s common units were subsequently delisted from Nasdaq. The Partnership’s common units are currently traded on the Pink Sheets, which is an over-the-counter securities market, under the symbol SGLP.PK. The fact that the Partnership’s common units are not listed on a national securities exchange is likely to make trading such common units more difficult for broker-dealers, unitholders and investors, potentially leading to further declines in the price of the common units. In addition, it may limit the number of institutional and other investors that will consider investing in the Partnership’s common units, which may have an adverse effect on the price of its common units. It may also make it more difficult for the Partnership to raise capital in the future.

The Partnership continues to work to become compliant with its SEC reporting obligations and intends to promptly seek the relisting of its common units on Nasdaq as soon as practicable after it has become compliant with such reporting obligations. However, the Partnership may not be able to relist its common units on Nasdaq or any other national securities exchange, and the Partnership may face a lengthy process to relist its common units if it is able to relist them at all.

Claims Against and By the Private Company’s Bankruptcy Estate

In connection with the Settlement, the Partnership and the Private Company entered into mutual releases regarding certain claims. In addition, the Settlement provided that the Partnership has a $35 million unsecured claim against the Private Company relating to the rejection of the Terminalling Agreement and a $20 million unsecured claim against the Private Company relating to rejection of the Throughput Agreement. On May 15, 2009, the Private Company filed the Reorganization Plan. If such plan is confirmed without material amendment, the Partnership’s claims will be impaired, and the Partnership will recover substantially less than the nominal value of such claims if it recovers anything. The Partnership may also have additional claims against the Private Company that were not released in connection with the Settlement, and the Private Company may also have additional claims against the Partnership that were not released in connection with the Settlement. Any claims asserted by the Partnership against the Private Company in the Bankruptcy Cases will be subject to the claim allowance procedure provided in the Bankruptcy Code and bankruptcy rules. If an objection is filed, the Bankruptcy Court will determine the extent to which any such claim that has been objected to is allowed and the priority of such claim.

Governmental Investigations

On July 21, 2008, the Partnership received a letter from the staff of the SEC giving notice that the SEC is conducting an inquiry relating to the Partnership and requesting, among other things, that the Partnership voluntarily preserve, retain and produce to the SEC certain documents and information relating primarily to the Partnership’s disclosures respecting the Private Company’s liquidity issues, which were the subject of the Partnership’s July 17, 2008 press release. On October 22, 2008, the Partnership received a subpoena from the SEC pursuant to a formal order of investigation requesting certain documents relating to, among other things, the Private Company’s liquidity issues. The Partnership has been cooperating, and intends to continue cooperating, with the SEC in its investigation.

On July 23, 2008, the Partnership and its general partner each received a Grand Jury subpoena from the United States Attorney’s Office in Oklahoma City, Oklahoma, requiring, among other things, that the Partnership and its general partner produce financial and other records related to the Partnership’s July 17, 2008 press release. The Partnership has been informed that the U.S. Attorneys’ Offices for the Western District of Oklahoma and the Northern District of Oklahoma are in discussions regarding the subpoenas, and no date has been set for a response to the subpoenas. The Partnership and its general partner intend to cooperate fully with this investigation if and when it proceeds.

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Securities and Other Litigation

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

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

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

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

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

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

Pursuant to a motion filed with the United States Judicial Panel on Multidistrict Litigation (“MDL Panel”), the Maurer case has been transferred to the Northern District of Oklahoma and consolidated with the Carson case. The Rubin, Jain, and Hickman cases have also been transferred to the Northern District of Oklahoma.

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

The lead plaintiff obtained an extension to file its consolidated amended complaint until May 4, 2009; defendants have 60 days from that date to answer or otherwise respond to the complaint.

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

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The Partnership intends to vigorously defend these actions. There can be no assurance regarding the outcome of the litigation. An estimate of possible loss, if any, or the range of loss cannot be made and therefore the Partnership has not accrued a loss contingency related to these actions. However, the ultimate resolution of these actions could have a material adverse effect on the Partnership’s business, financial condition, results of operations, cash flows, ability to make distributions to its unitholders, the trading price of the Partnership’s common units and its ability to conduct its business.

In March and April 2009, nine current or former executives of the Private Company and certain of its affiliates filed wage claims with the Oklahoma Department of Labor against the Partnership’s general partner. Their claims arise from the Partnership’s general partner’s Long-Term Incentive Plan, Employee Phantom Unit Agreement (“Phantom Unit Agreement”). Most claimants allege that phantom units previously awarded to them vested upon the Change of Control that occurred in July 2008. One claimant alleges that his phantom units vested upon his termination. The claimants contend the Partnership’s general partner’s failure to deliver certificates for the phantom units within 60 days after vesting has caused them to be damaged, and they seek recovery of approximately $2 million in damages and penalties. On April 30, 2009, all of the wage claims were dismissed on jurisdictional grounds by the Department of Labor. The Partnership’s general partner intends to continue to vigorously defend these claims.

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

Examiner

On August 12, 2008, a motion was filed by the United States Trustee asking the Bankruptcy Court to appoint an examiner to investigate the Private Company’s trading strategies as well as certain “insider transactions,” including the contribution of the crude oil assets to the Partnership in connection with its initial public offering, the sale of the Acquired Asphalt Assets to the Partnership, the sale of the Acquired Pipeline Assets to the Partnership, the sale of the Acquired Storage Assets to the Partnership, and the entering into the Holdings Credit Agreements by SemGroup Holdings. On September 10, 2008, the Bankruptcy Court approved the appointment of an examiner, and on October 14, 2008, the United States Trustee appointed Louis J. Freeh, former director of the Federal Bureau of Investigation, as the examiner (the “Examiner”). On April 15, 2009, the Examiner filed a report summarizing the findings of his investigation with the Bankruptcy Court (the “Examiner’s Report”).

The Examiner was directed by the Bankruptcy Court to (i) investigate the circumstances surrounding the Private Company’s trading strategy, the transfer of the New York Mercantile Exchange account, certain insider transactions, the formation of the Partnership, the potential improper use of borrowed funds and funds generated from the Private Company’s operations and the liquidation of its assets to satisfy margin calls related to the trading strategy for the Private Company and certain entities owned or controlled by the Private Company’s officers and directors and (ii) determine whether any directors, officers or employees of the Private Company participated in fraud, dishonesty, incompetence, misconduct, mismanagement, or irregularity in the management of the affairs of the Private Company and whether the Private Company’s estates have causes of action against such persons arising from any such participation.

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The Examiner’s Report identified potential claims or causes of action against current officers of the Partnership’s general partner who were former officers and/or directors of the Private Company, including (i) against Kevin L. Foxx for his failure to develop a suitable risk management policy or integrate a suitable risk management policy into the Private Company’s business controls, and for his failure to comply with the risk management policy that did exist, thereby subjecting the Private Company to increased risk and (ii) against Alex G. Stallings for his failure to stop Thomas L. Kivisto from engaging in trading activity on his own behalf through Westback Purchasing Company, L.L.C. (“Westback”), a limited liability trading partnership that Mr. Kivisto owned and controlled, thereby subjecting the Private Company to increased risk and losses. In addition, the Examiner’s Report criticized Mr. Foxx for certain conflicts of interest with entities that he or his family invested in and that had a business relationship with the Private Company. Additionally, the Examiner’s Report identified a number of potential claims or causes of action against Mr. Kivisto and Gregory C. Wallace, who are former directors of the Partnership’s general partner and former officers of the Private Company, including, without limitation, for negligence and mismanagement, fraud and false statements, conversion and corporate waste, unjust enrichment, breach of fiduciary duties and breach of contract.

The Examiner’s Report and related exhibits are publicly available at www.kccllc.net/SemGroup.

Bankruptcy Adversary Proceeding

The Official Committee of Unsecured Creditors of SemCrude, L.P. (“Unsecured Creditors Committee”) filed an adversary proceeding in connection with the Bankruptcy Cases against Thomas L. Kivisto, Gregory C. Wallace, and Westback. In that proceeding, filed February 18, 2009, the Unsecured Creditors Committee asserted various claims against the defendants on behalf of the Private Company’s bankruptcy estate, including claims based upon theories of fraudulent transfer, breach of fiduciary duties, waste, breach of contract, and unjust enrichment. On June 8, 2009, the Unsecured Creditors Committee filed a Second Amended Complaint asserting additional claims against Kevin L. Foxx and Alex G. Stallings, among others, based upon certain findings and recommendations in the Examiner’s Report described above (see “—Examiner”). The claims against Mr. Foxx are based upon theories of fraudulent transfer, unjust enrichment, and breach of fiduciary duty with respect to certain bonus payments received from the Private Company, and other claims of breach of fiduciary duty and breach of contract are also alleged against Messrs. Foxx and Stallings in the amended complaint. Messrs. Foxx and Stallings have informed the Partnership that they intend to vigorously defend these claims.

Internal Review

As previously announced, in July 2008 the Board created an internal review subcommittee of the Board comprised of directors who are independent of management and the Private Company to determine whether the Partnership participates in businesses other than as described in its filings with the SEC and to conduct investigations into other such specific items as are deemed to be appropriate by the subcommittee. The subcommittee retained independent legal counsel to assist it in its investigations.

The subcommittee has investigated a short-term financing transaction involving two subsidiaries of the Private Company. This transaction was identified as a potential source of concern in a whistleblower report made after the Private Company filed for bankruptcy. Although the transaction did not involve the Partnership or its subsidiaries, it was investigated because it did involve certain senior executive officers of the Partnership’s general partner who were also senior executive officers of the Private Company at the time of the transaction. Based upon its investigation, counsel for the subcommittee found that, subject to the subcommittee’s lack of access to Private Company documents and electronic records and witnesses, although certain irregularities occurred in the transactions, the transaction did not appear to cause the relevant officers to understand or believe that the Private Company had a lack of liquidity that imperiled the Private Company’s ability to meet its obligations to the Partnership and that certain aspects of the documentation of the transaction that were out of the ordinary did not call into question the integrity of any of the relevant officers.

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The subcommittee also investigated whether certain senior executive officers of the Partnership’s general partner who were also senior executive officers of the Private Company knew and understood, beginning as early as July 2007 and at various times thereafter, about a lack of liquidity at the Private Company that imperiled the Private Company’s ability to meet its obligations to the Partnership. Based upon this investigation, and subject to the subcommittee’s lack of access to Private Company documents and electronic records and witnesses, counsel for the subcommittee found that each of the officers had access to and reviewed Private Company financial information, including information regarding the Private Company’s commodity trading activities, from which they could have developed an understanding of the nature and significance of the trading activities that led to liquidity problems at the Private Company well before they say they did. While the officers each stated sincerely that they did not understand the nature or extent of the Private Company’s trading-related problems until the first week of July 2008 or later, objective evidence suggests that they showed at least some indifference to known or easily discoverable facts and that they failed to adhere to procedures under the Private Company’s Risk Management Policy created expressly to ensure that the Private Company’s trading activities were properly monitored. Nonetheless, counsel for the subcommittee was not persuaded by the documents and other evidence it was able to access that the officers in fact knew and understood that the Private Company’s liquidity or capital needs were a significant cause for alarm until, at the earliest, the second quarter of 2008. Moreover, while it appeared to counsel that the officers developed a growing awareness of the nature and severity of the Private Company’s liquidity issues over the second quarter of 2008, counsel was unable to identify with any more precision the specific level of concern or understanding these individuals had prior to July 2008. While not within the scope of such counsel’s investigation, counsel was requested by the subcommittee to note any information that came to counsel’s attention during its investigation that suggested that the officers intended to deceive or mislead any third party. Subject to limitations described in its report, no information came to counsel’s attention during its investigation that suggested to counsel that the officers intended to deceive or to mislead any third parties. In addition, in connection with the investigation, counsel for the subcommittee did not express any findings of intentional misconduct or fraud on the part of any officer or employee of the Partnership.

After completion of the internal review, a plan was developed with the advice of the audit committee of the Board to further strengthen the processes and procedures at the Partnership. This plan includes, among other things, reevaluating executive officers and accounting and finance personnel (including a realignment of officers as described elsewhere in this report) and hiring, as deemed necessary, additional accounting and finance personnel or consultants; reevaluating the Partnership’s internal audit function and determining whether to expand the duties and responsibilities of such group; evaluating the comprehensive training programs for all management personnel covering, among other things, compliance with controls and procedures, revising the reporting structure so that the Chief Financial Officer reports directly to the audit committee, and increasing the business and operational oversight role of the audit committee.

Equity Awards and Employment Agreements

The Change of Control constituted a change of control under the Plan, which resulted in the early vesting of all awards under the Plan. As such, the phantom units awarded to Messrs. Kevin L. Foxx, Michael J. Brochetti, Alex G. Stallings, Peter L. Schwiering and Jerry A. Parsons in the amounts of 150,000 units, 90,000 units, 75,000 units, 45,000 units and 20,000 units, respectively, are fully vested. The common units underlying such awards were issued to such individuals in August 2008. In addition, the 5,000 restricted units awarded to each of Messrs. Billings, Kosnik and Bishop for their service as independent members of the Board fully vested.

The Change of Control also resulted in a change of control under the employment agreements of Messrs. Foxx, Brochetti, Stallings, Schwiering and Parsons. If within one year after the Change of Control any such officer is terminated by the Partnership’s general partner without Cause (as defined below) or such officer terminates the agreement for Good Reason (as defined below), he will be entitled to payment of any unpaid base salary and vested benefits under any incentive plans, a lump sum payment equal to 24 months of base salary and continued participation in the Partnership’s general partner’s welfare benefit programs for one year after termination. Upon such an event, Messrs Foxx, Brochetti, Stallings, Schwiering and Parsons would be entitled to lump sum payments of $900,000, $600,000, $550,000, $500,000 and $500,000, respectively, in addition to continued participation in the Partnership’s general partner’s welfare benefit programs. As of the date of the filing of this report, none of these officers is entitled to these benefits as none of them has been terminated by the Partnership’s general partner without Cause or has terminated his agreement for Good Reason.

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For purposes of the employment agreements:

Taxation as a Corporation

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

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

The Partnership recently entered into new storage contracts and leases with third party customers with respect to substantially all of its asphalt facilities. It is unclear under current tax law as to whether the rental income from the leases, and whether the fees attributable to certain of the processing services 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.” The Partnership may not be successful in obtaining this ruling. If the Partnership is not successful in obtaining this ruling, it will likely have to transfer the leases and the related asphalt assets and rental income, and/or certain of the processing assets and related fee income, to one or more subsidiaries taxed as corporations. Even if successful in obtaining this ruling, the Partnership will likely transfer certain of the processing assets and related fee income, to one or more subsidiaries taxed as corporations Any such subsidiary that is taxed as a corporation 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 (and possibly local) income tax at varying rates. Distributions would generally be taxed again to unitholders as corporate distributions and none of the income, gains, losses, deductions or credits of any such subsidiary would flow through to the Partnership’s unitholders. If a material amount of entity-level taxes were incurred by any such subsidiaries, then the Partnership’s cash available for distribution to its unitholders could be substantially reduced.

Other Effects

The Bankruptcy Filings have had and may in the future continue to have a number of other impacts on the Partnership’s business and management. In the Amended Omnibus Agreement and other agreements with the Private Company, the Private Company agreed to indemnify the Partnership for certain environmental and other claims relating to the crude oil and liquid asphalt cement assets that have been contributed to the Partnership. In connection with the Settlement, the Partnership waived these claims and the Amended Omnibus Agreement and other relevant agreements, including the indemnification provisions therein, were rejected as part of the Bankruptcy Cases. If the Partnership experiences an environmental or other loss, it would experience increased losses that 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 its common units and its ability to conduct its business.

The Partnership is currently pursuing various strategic alternatives for its business and assets including the possibility of entering into strategic partnerships (potentially involving the issuance of additional interests in the Partnership), additional storage contracts with third party customers, and/or the sale of all or a portion of the Partnership’s assets. The uncertainty relating to the Bankruptcy Filings and the recent global market and economic conditions may make it more difficult to pursue strategic opportunities or enter into storage contracts with third party customers.

In addition, general and administrative expenses (exclusive of non-cash compensation expense related to the vesting of the units under the Plan - see Note 14) increased by approximately $6.9 million and $7.5 million, or approximately 300% and 326%, to approximately $9.2 million for the third quarter of 2008, $9.8 million for the fourth quarter of 2008, respectively, compared to $2.3 million in the second quarter of 2008. This increase is due to increased costs related to legal and financial advisors as well as other related costs in connection with events related to the Bankruptcy Filings, the securities litigation and governmental investigations, and the Partnership’s efforts to enter into storage contracts with third party customers and pursue strategic opportunities. The Partnership expects this increased level of general and administrative expenses to continue throughout 2009.

20. QUARTERLY FINANCIAL DATA (UNAUDITED):

Summarized quarterly financial data is as follows (in thousands, except per unit amounts):

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(in thousands, except per unit data)
2007:
Revenues	$	8,634		$	10,464		$	25,280		$	30,187		$	74,565
Operating income (loss)		(11,855	)		(11,695	)		6,803			10,535			(6,212	)
Net income (loss)		(12,284	)		(12,211	)		4,317			7,265			(12,913	)
Basic and diluted net income per common unit		—			—			0.24			0.31			0.55
Basic and diluted net income per subordinated unit		—			—			0.19			0.21			0.40

2008:
Revenues	$	40,214		$	55,276		$	53,794		$	42,896		$	192,180
Operating income (loss)		14,938			21,448			(751	)		9,382			45,017
Net income (loss)		9,758			21,596			(11,851	)		(1,728	)		17,775
Basic and diluted net income (loss) per common unit		0.31			0.53			(0.33	)		(0.05	)		0.46
Basic and diluted net income (loss) per subordinated unit		0.31			0.53			(0.33	)		(0.05	)		0.46

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INDEX TO EXHIBITS

Exhibit Number	Description
3.1	Certificate of Limited Partnership of SemGroup Energy Partners, L.P. (the “Partnership”), dated February 22, 2007 (filed as Exhibit 3.1 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-141196), filed March 9, 2007, and incorporated herein by reference).
3.2	First Amended and Restated Agreement of Limited Partnership of the Partnership, dated July 20, 2007 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed July 25, 2007, and incorporated herein by reference).
3.3	Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of the Partnership, effective as of July 20, 2007 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed on April 14, 2008, and incorporated herein by reference).
3.4	Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of the Partnership, dated June 25, 2008 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed on June 30, 2008, and incorporated herein by reference).
3.5	Certificate of Formation of SemGroup Energy Partners G.P., L.L.C. (the “General Partner”), dated February 22, 2007 (filed as Exhibit 3.3 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-141196), filed March 9, 2007, and incorporated herein by reference).
3.6	Amended and Restated Limited Liability Company Agreement of the General Partner, dated July 20, 2007 (filed as Exhibit 3.2 to the Partnership’s Current Report on Form 8-K, filed July 25, 2007, and incorporated herein by reference).
3.7	Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of the General Partner, dated June 25, 2008 (filed as Exhibit 3.2 to the Partnership’s Current Report on Form 8-K, filed on June 30, 2008, and incorporated herein by reference).
3.8	Amendment No. 2 to Amended and Restated Limited Liability Company Agreement of the General Partner, dated July 18, 2008 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed on July 22, 2008, and incorporated herein by reference).
4.1	Specimen Unit Certificate (included in Exhibit 3.2).
10.1	Credit Agreement, dated July 20, 2007, among the Partnership, Wachovia Bank, National Association, as Administrative Agent, L/C Issuer and Swing Line Lender, Bank of America, N.A., as Syndication Agent and the other lenders from time to time party thereto (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed July 25, 2007, and incorporated herein by reference).
10.2	Amended and Restated Credit Agreement, dated February 20, 2008, among the Partnership, Wachovia Bank, National Association, as Administrative Agent, L/C Issuer and Swing Line Lender, Bank of America, N.A., as Syndication Agent and the other lenders from time to time party thereto (filed as Exhibit 10.4 to the Partnership’s Current Report on Form 8-K, filed February 25, 2008, and incorporated herein by reference).
10.3	Forbearance Agreement and Amendment to Credit Agreement, dated September 12, 2008 but effective as of September 18, 2008, by and among SemGroup Energy Partners, L.P., Wachovia Bank, National Association, as Administrative Agent, L/C Issuer and Swing Line Lender, and the Lenders party thereto (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed on September 22, 2008, and incorporated herein by reference).
10.4	First Amendment to Forbearance Agreement and Amendment to Credit Agreement, dated as of December 11, 2008, by and among SemGroup Energy Partners, L.P., Wachovia Bank, National Association, as Administrative Agent, L/C Issuer and Swing Line Lender, and the Lenders party thereto (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed on December 12, 2008, and incorporated herein by reference).
10.5	Second Amendment to Forbearance Agreement and Amendment to Credit Agreement, dated as of December 18, 2008, by and among SemGroup Energy Partners, L.P., Wachovia Bank, National Association, as Administrative Agent, L/C Issuer and Swing Line Lender, and the Lenders party thereto (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed on December 19, 2008, and incorporated herein by reference).
10.6	Third Amendment to Forbearance Agreement and Amendment to Credit Agreement, dated as of March 17, 2009, by and among SemGroup Energy Partners, L.P., Wachovia Bank, National Association, as Administrative Agent, L/C Issuer and Swing Line Lender, and the Lenders party thereto (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed on March 19, 2009, and incorporated herein by reference).
10.7	Consent, Waiver and Amendment to Credit Agreement, dated as of April 7, 2009, by and among SemGroup Energy Partners, L.P., as Borrower, SemGroup Energy Partners G.P., L.L.C., SemGroup Energy Partners Operating, L.L.C., SemMaterials Energy Partners, L.L.C., SemGroup Energy Partners, L.L.C., SemGroup Crude Storage, L.L.C., SemPipe, L.P., SemPipe G.P., L.L.C. and SGLP Management, Inc., as Guarantors, Wachovia Bank, National Association, as Administrative Agent, L/C Issuer and Swing Line Lender, and the Lenders party thereto (filed as Exhibit 10.14 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.8*	Amendment to Credit Agreement, dated as of May 19, 2009, by and among SemGroup Energy Partners, L.P., the Guarantors, Wachovia Bank, National Association, as Administrative Agent, L/C Issuer and Swing Line Lender, and the Lenders party thereto.
10.9†	SemGroup Energy Partners G.P., L.L.C. Long-Term Incentive Plan (filed as Exhibit 10.5 to the Partnership’s Current Report on Form 8-K, filed July 25, 2007, and incorporated herein by reference).
10.10†	Amendment to the SemGroup Energy Partners G.P., L.L.C. Long Term Incentive Plan (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed on December 23, 2008, and incorporated herein by reference).
10.11†	Form of Employment Agreement (filed as Exhibit 10.6 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-141196), filed May 25, 2007, and incorporated herein by reference).
10.12†	Form of Employment Agreement (filed as Exhibit 10.14 to the Partnership’s Quarterly Report on Form 10-Q, filed on March 23, 2009, and incorporated herein by reference).
10.13†	Form of Indemnification Agreement (filed as Exhibit 10.7 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-141196), filed May 25, 2007, and incorporated herein by reference).
10.14†	Form of Phantom Unit Agreement (filed as Exhibit 10.8 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-141196), filed May 25, 2007, and incorporated herein by reference).
10.15†	Form of Phantom Unit Agreement (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed on June 24, 2008, and incorporated herein by reference).
10.16†	Form of Phantom Unit Agreement (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed on June 24, 2008, and incorporated herein by reference).
10.17†	Form of Phantom Unit Agreement (filed as Exhibit 10.15 to the Partnership’s Quarterly Report on Form 10-Q, filed on March 23, 2009, and incorporated herein by reference).
10.18†	Form of Retention Agreement (filed as Exhibit 10.16 to the Partnership’s Quarterly Report on Form 10-Q, filed on March 23, 2009, and incorporated herein by reference).
10.19†	Form of Restricted Unit Agreement (filed as Exhibit 10.9 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-141196), filed May 25, 2007, and incorporated herein by reference).
10.20†	Form of Director Restricted Common Unit Agreement (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed on December 23, 2008, and incorporated herein by reference).
10.21†	Form of Director Restricted Subordinated Unit Agreement (filed as Exhibit 10.3 to the Partnership’s Current Report on Form 8-K, filed on December 23, 2008, and incorporated herein by reference).
10.22†*	SemGroup Energy Partners G.P., L.L.C. 2009 Executive Cash Bonus Plan
10.23	Closing Contribution, Conveyance, Assignment and Assumption Agreement, dated July 20, 2007, among the Partnership, the General Partner, SemCrude, L.P., SemGroup, L.P. and SemGroup Energy Partners Operating, L.L.C. (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed July 25, 2007, and incorporated herein by reference).
10.24	Purchase and Sale Agreement, dated as of January 14, 2008, by and among SemMaterials, L.P. and SemGroup Energy Partners Operating, L.L.C. (filed as Exhibit 2.1 to the Partnership’s Current Report on Form 8-K, filed on January 15, 2008, and incorporated herein by reference).
10.25	Purchase and Sale Agreement, dated as of May 12, 2008, by and between SemCrude, L.P. and SemGroup Energy Partners, L.L.C. (filed as Exhibit 2.1 to the Partnership’s Current Report on Form 8-K, filed on May 15, 2008, and incorporated herein by reference).
10.26	Purchase and Sale Agreement, dated as of May 20, 2008, by and between SemGroup Energy Partners, L.L.C. and SemCrude, L.P. (filed as Exhibit 2.1 to the Partnership’s Current Report on Form 8-K, filed on May 23, 2008, and incorporated herein by reference).
10.27	Omnibus Agreement, dated July 20, 2007, among the Partnership, the General Partner, SemGroup, L.P. and SemManagement, L.L.C. (filed as Exhibit 10.3 to the Partnership’s Current Report on Form 8-K, filed July 25, 2007, and incorporated herein by reference).
10.28	Amended and Restated Omnibus Agreement, dated as of February 20, 2008, by and among SemGroup, L.P., SemManagement, L.L.C., SemMaterials, L.P., the Partnership, SemGroup Energy Partners G.P., L.L.C. and SemMaterials Energy Partners, L.L.C. (filed as Exhibit 10.3 to the Partnership’s Current Report on Form 8-K, filed February 25, 2008, and incorporated herein by reference).
10.29#	Throughput Agreement, dated July 20, 2007, among the Partnership, SemGroup Energy Partners, L.L.C., SemCrude, L.P., Eaglwing, L.P. and SemGroup, L.P. (filed as Exhibit 10.4 to the Partnership’s Current Report on Form 8-K, filed July 25, 2007, and incorporated herein by reference).
10.30#	Terminalling and Storage Agreement, dated as of February 20, 2008, by and between SemMaterials, L.P. and SemMaterials Energy Partners, L.L.C. (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed February 25, 2008, and incorporated herein by reference).
10.31	Terminal Access and Use Agreement, dated as of January 28, 2008, by and among SemMaterials Energy Partners, L.L.C., SemMaterials, L.P. and K.C. Asphalt, L.L.C. (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed February 25, 2008, and incorporated herein by reference).
10.32	Agreed Order of the United States Bankruptcy Court for the District of Delaware Regarding Motion by SemGroup Energy Partners, L.P. (i) to Compel Debtors to Provide Adequate Protection and (ii) to Modify the Automatic Stay (filed as Exhibit 99.1 to the Partnership’s Current Report on Form 8-K, filed on September 9, 2008, and incorporated herein by reference).
10.33	Master Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and among by and among SemGroup, L.P., SemManagement, L.L.C., SemOperating G.P., L.L.C., SemMaterials, L.P., K.C. Asphalt, L.L.C., SemCrude, L.P., Eaglwing, L.P., SemGroup Holdings, L.P., SemGroup Energy Partners, L.P., SemGroup Energy Partners G.P., L.L.C., SemGroup Energy Partners Operating, L.L.C., SemGroup Energy Partners, L.L.C., SemGroup Crude Storage, L.L.C., SemPipe, L.P., SemPipe G.P., L.L.C., SGLP Management, Inc. and SemMaterials Energy Partners, L.L.C. (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.34	Shared Services Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and among SemGroup Energy Partners, L.P., SemGroup Energy Partners, L.L.C., SemGroup Crude Storage, L.L.C., SemPipe G.P., L.L.C., SemPipe, L.P., SemCrude, L.P. and SemManagement, L.L.C. (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.35	Transition Services Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and among SemGroup Energy Partners, L.P., SemGroup Energy Partners, L.L.C., SemGroup Crude Storage, L.L.C., SemPipe G.P., L.L.C., SemPipe, L.P., SemMaterials Energy Partners, L.L.C., SGLP Asphalt L.L.C., SemCrude, L.P., SemGroup, L.P., SemMaterials, L.P. and SemManagement, L.L.C. (filed as Exhibit 10.3 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.36	Contribution, Conveyance, Assignment and Assumption Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and among SemMaterials, L.P., K.C. Asphalt, L.L.C., SGLP Asphalt, L.L.C. and SemMaterials Energy Partners, L.L.C. (filed as Exhibit 10.4 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.37	Membership Interest Transfer Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and between SemMaterials, L.P. and SemMaterials Energy Partners, L.L.C. (filed as Exhibit 10.5 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.38	Throughput Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and among SemGroup Energy Partners, L.L.C. and SemCrude, L.P. (filed as Exhibit 10.6 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.39	Terminalling and Storage Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and between SemMaterials Energy Partners, L.L.C. and SemMaterials, L.P. (filed as Exhibit 10.7 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.40	Access and Use Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and between SemMaterials, L.P. and SemMaterials Energy Partners, L.L.C. (filed as Exhibit 10.8 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.41	Trademark License Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and among SemGroup, L.P., SemMaterials, L.P. and SemGroup Energy Partners, L.P. (filed as Exhibit 10.9 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.42	Office Lease, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and between SemGroup Energy Partners, L.L.C. and SemCrude, L.P. (filed as Exhibit 10.10 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.43	Building Lease, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and between SemGroup Energy Partners, L.L.C. and SemCrude, L.P. (filed as Exhibit 10.11 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.44	Mutual Easement Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, among SemCrude, L.P., SemGroup Energy Partners, L.L.C., and SemGroup Crude Storage, L.L.C. (filed as Exhibit 10.12 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.45	Pipeline Easement Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, by and among White Cliffs Pipeline, L.L.C., SemGroup Energy Partners, L.L.C., and SemGroup Crude Storage, L.L.C. (filed as Exhibit 10.13 to the Partnership’s Current Report on Form 8-K, filed on April 10, 2009, and incorporated herein by reference).
10.46	Term Sheet, dated as of March 6, 2009 (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed on March 10, 2009, and incorporated herein by reference).
21.1*	List of Subsidiaries of SemGroup Energy Partners, L.P.
23.1*	Consent of PricewaterhouseCoopers, L.L.P.
23.2*	Consent of PricewaterhouseCoopers, L.L.P. for Exhibit 99.1.
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.”
99.1*	SemGroup Energy Partners G.P., L.L.C. Financial Statements.

______________________

* Filed herewith.

† As required by Item 15(a)(3) of Form 10-K, this exhibit is identified as a compensatory plan or arrangement.