Blueknight Energy Parnters, L.P.
Annual Report 2017

Plain-text annual report

BLUEKNIGHT ENERGY PARTNERS, L.P. FORM 10-K (Annual Report) Filed 03/08/18 for the Period Ending 12/31/17 Address Telephone CIK Symbol SIC Code 201 NW 10TH, SUITE 200 OKLAHOMA CITY, OK, 73103 (405) 278-6400 0001392091 BKEP 4610 - Pipe Lines (No Natural Gas) Industry Oil & Gas Transportation Services Sector Fiscal Year Energy 09/14 http://www.edgar-online.com © Copyright 2018, EDGAR Online, a division of Donnelley Financial Solutions. All Rights Reserved. Distribution and use of this document restricted under EDGAR Online, a division of Donnelley Financial Solutions, Terms of Use.  UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM 10-Kx ANNUAL REPORT PURSUANT TO SECTION 13 or 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2017 OR oTRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from __________ to _________ Commission File Number 001-33503 BLUEKNIGHT ENERGY PARTNERS, L.P.(Exact name of registrant as specified in its charter)Delaware(State or other jurisdiction of incorporation or organization) 20-8536826(IRS EmployerIdentification No.) 201 NW 10th, Suite 200Oklahoma City, Oklahoma 73103(Address of principal executive offices, zip code) Registrant’s telephone number, including area code: (405) 278-6400 (Former name, former address and former fiscal year, if changed since last report)Securities Registered Pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registeredCommon Units representing limitedpartner interests Nasdaq Global MarketSeries A Preferred Units representing limitedpartner interests Nasdaq Global MarketSecurities Registered Pursuant to Section 12(g) of the Act: NoneIndicate 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 xIndicate 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 duringthe preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for thepast 90 days. Yes ý No o Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required tobe submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that theregistrant was required to submit and post such files). Yes ý No o Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and willnot 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 anyamendment to this Form 10-K. oIndicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or anemerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” inRule 12b-2 of the Exchange Act. (Check one):Large accelerated filer o Accelerated filer x Non-accelerated filer o (Do not check if a smaller reporting company) Smaller reporting company o Emerging growth company o If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new orrevised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. oIndicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ýAs of June 30, 2017 , the aggregate market value of the registrant’s common units held by non-affiliates of the registrant was approximately $191.6 million ,based on $6.25 per common unit, the closing price of the common units as reported on the Nasdaq Global Market on such date. As of March 1, 2018 , there were 35,125,202 Series A Preferred Units and 40,310,272 common units outstanding. Table of ContentsTable of Contents PagePART I . 1Item 1.Business.1Item 1A.Risk Factors.15Item 1B.Unresolved Staff Comments.37Item 2.Properties.37Item 3.Legal Proceedings.38Item 4.Mine Safety Disclosures.38 PART II . 38Item 5.Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.38Item 6.Selected Financial Data.40Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations.42Item 7A.Quantitative and Qualitative Disclosures about Market Risk.60Item 8.Financial Statements and Supplementary Data.61Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.61Item 9A.Controls and Procedures.61 PART III . 62Item 10.Directors, Executive Officers and Corporate Governance.62Item 11.Executive Compensation.66Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.76Item 13.Certain Relationships and Related Transactions, and Director Independence.78Item 14.Principal Accountant Fees and Services.79 PART IV . 81Item 15.Exhibits, Financial Statement Schedules.81Item 16.Form 10-K Summary.86iTable of ContentsDEFINITIONSWe use the following 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 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 oilproducts directly sold to end users. Liquid asphalt: A dark brown to black cementitious material that is primarily produced by petroleum distillation. When crude oil is separated in distillationtowers at a refinery, the heaviest hydrocarbons with the highest boiling points settle at the bottom. These tar-like fractions, called residuum, require relatively littleadditional processing to become products such as liquid asphalt cement or residual fuel oil. Liquid asphalt cement is primarily used in the road construction andmaintenance industry. Residual fuel oil is primarily used as a burner fuel in numerous industrial and commercial business applications. As used herein, the termrefers 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 refinedand finished products (downstream). PMAC: Polymer modified asphalt cement. Preferred Units: Series A Preferred Units representing limited partnership interests in our partnership. SemCorp: SemCorp refers to SemGroup Corporation and its predecessors (including SemGroup, L.P.), subsidiaries and affiliates (other than our GeneralPartner and us during periods in which we were affiliated with SemGroup, L.P.). Terminalling: The receipt of crude oil and petroleum products for storage into storage tanks and other appurtenant equipment, including pipelines, where thecrude oil and petroleum products will be commingled with other products of similar quality; the storage of the crude oil and petroleum products; and the deliveryof 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.iiTable of ContentsPART I.As used in this annual report, unless we indicate otherwise: (1) “Blueknight Energy Partners,” “our,” “we,” “us” and similar terms refer to BlueknightEnergy Partners, L.P. , together with its subsidiaries, (2) our “General Partner” refers to Blueknight Energy Partners G.P., L.L.C., (3) “Ergon” refers to Ergon, Inc.,its affiliates and subsidiaries (other than our General Partner and us), (4) “Vitol” refers to Vitol Holding B.V., its affiliates and subsidiaries and (5) “Charlesbank”refers to Charlesbank Capital Partners, LLC, its affiliates and subsidiaries.Forward-Looking StatementsThis report contains “forward-looking statements” within the meaning of the federal securities laws. Statements included in this annual report that are nothistorical facts (including any statements regarding plans and objectives of management for future operations or economic performance, or assumptions orforecasts 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, containprojections of results of operations or of financial condition, or state other “forward-looking” information. We and our representatives may from time to time makeother 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 asof the date of this report. Although we believe that the expectations or assumptions reflected in these forward-looking statements are based on reasonableassumptions, no assurance can be given that these expectations will prove to be correct. Important factors that could cause our actual results to differ materiallyfrom the expectations reflected in these forward-looking statements include, among other things, those set forth in “Item 1A-Risk Factors,” included in this annualreport, and those set forth from time to time in our filings with the Securities and Exchange Commission (“SEC”), which are available through the Investors - SECFilings page at www.bkep.com and through the SEC’s Electronic Data Gathering and Retrieval System (“EDGAR”) at 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 topublicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. All subsequent written and oralforward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements containedthroughout this report.Item 1. Business.Overview We are a publicly traded master limited partnership with operations in 27 states. We provide integrated terminalling, gathering and transportation services forcompanies engaged in the production, distribution and marketing of liquid asphalt and crude oil. We manage our operations through four operating segments: (i)asphalt terminalling services, (ii) crude oil terminalling services, (iii) crude oil pipeline services and (iv) crude oil trucking and producer field services. Our OperationsWe were formed as a Delaware limited partnership in 2007 to own, operate and develop a diversified portfolio of complementary midstream energyassets. Our operating assets are owned by, and our operations are conducted through, our subsidiaries. Our General Partner has sole responsibility for conductingour business and for managing our operations. Our General Partner is owned by Blueknight Energy Holding GP, LLC. On October 5, 2016, Ergon purchased100% of the outstanding voting stock of Blueknight GP Holding, L.L.C., which owns 100% of the capital stock of our General Partner, pursuant to a MembershipInterest Purchase Agreement dated July 19, 2016, among CB-Blueknight, LLC (“CBB”), an indirect wholly-owned subsidiary of Charlesbank, Blueknight EnergyHolding, Inc. (“BEHI”), an indirect wholly-owned subsidiary of Vitol, and Ergon Asphalt Holdings, LLC, a wholly-owned subsidiary of Ergon (the “ErgonChange of Control”). In conjunction with the Ergon Change of Control, Ergon contributed nine asphalt terminals plus $22.1 million in cash in return for totalconsideration of approximately $144.7 million, which consisted of the issuance of 18,312,968 Preferred Units in a private placement. We also repurchased6,667,695 Preferred Units from each Vitol and Charlesbank in a private placement for an aggregate purchase price of approximately $95.3 million. Vitol andCharlesbank each retained 2,488,789 Preferred Units upon completion of these transactions. In addition, Ergon acquired an aggregate of $5.0 million of commonunits for cash in a private placement, pursuant to a Contribution Agreement between us, Blueknight Terminal Holding, L.L.C. and three indirect wholly-ownedsubsidiaries of Ergon.1Table of Contents Our General Partner has no business or operations other than managing our business. In addition, outside of its investment in us, our General Partner owns noassets or property other than a minimal amount of cash, which has been distributed by us to our General Partner in respect of its interest in us. Our partnershipagreement imposes no additional material liabilities upon our General Partner or obligations to contribute to us other than those liabilities and obligations imposedon general partners under the Delaware Revised Uniform Limited Partnership Act. The following diagram depicts our organizational structure, including our relationship with our affiliates and subsidiaries, as of March 1, 2018 :Our Strengths and StrategiesStrategically placed assets . We own and operate a diversified portfolio of complementary midstream energy assets that includes approximately 10.3 millionbarrels of liquid asphalt storage located at 56 terminals in 26 states which we believe are well positioned to provide services in the market areas they servethroughout the continental United States. Our primary crude oil terminalling facilities are located within the Cushing Interchange in Cushing, Oklahoma, one of thelargest crude oil2Table of Contentsmarketing hubs in the United States and the designated point of delivery specified in all New York Mercantile Exchange (“NYMEX”) crude oil futures contracts.We believe that the Cushing Interchange will continue to serve as one of the largest crude oil marketing hubs in the United States. In addition, we haveapproximately 655 miles of strategically positioned gathering and transportation pipelines in Oklahoma and Texas.Growth opportunities. Ergon has indicated that it intends to use us as a growth vehicle to pursue the acquisition and expansion of midstream energybusinesses and assets. We cannot say with any certainty whether or not Ergon will develop any projects or, if they do, which, if any, future acquisitionopportunities may be made available to us, or if we will choose to pursue any such opportunity. Experienced management team . Our General Partner has an experienced and knowledgeable management team with extensive experience in the energyindustry. We expect to directly benefit from this management team’s strengths, including significant relationships throughout the energy industry with customersof our asphalt terminalling services and with producers, marketers and refiners of crude oil.Our relationship with Ergon . Ergon owns our General Partner and therefore controls our operations. Ergon is a privately held company formed in 1954 andis based in Jackson, Mississippi, with over 2,500 employees globally. Ergon and its subsidiaries are engaged in a wide range of operations that are categorized intosix primary business segments: Refining & Marketing, Asphalt & Emulsions, Transportation & Terminalling, Oil & Gas, Real Estate and Corporate & Other. Thisrelationship may provide us with additional capital sources for future growth as well as increased opportunities to provide terminalling, gathering andtransportation services. While this relationship may benefit us, it may also be a source of potential conflicts. Ergon is not restricted from competing with us andmay acquire, construct or dispose of additional assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.Industry Overview Asphalt Industry We provide asphalt terminalling services to marketers and distributors of liquid asphalt and asphalt-related products. We do not take title to the product; welease certain facilities for operation by our customers and at some facilities we process, blend and manufacture products to meet our customers’ specifications. Ourterminal network consists of 56 facilities located coast-to-coast throughout the United States.Liquid asphalt, which includes liquid asphalt cement and residual fuel oils, is one of the oldest engineering materials. Liquid asphalt’s adhesive andwaterproofing properties have been used for building structures, waterproofing ships, mummification and numerous other applications. Production of liquid asphalt begins with the refining of crude oil. When crude oil is separated in distillation towers at a refinery, the heaviest hydrocarbonswith the highest boiling points settle at the bottom. These tar-like fractions, called residuum, require relatively little additional processing to become products suchas liquid asphalt cement or residual fuel oil. Liquid asphalt production typically represents only a small portion of the total product production in the crude oilrefining process. The liquid asphalt produced by petroleum distillation can be sold by the refinery either directly into the wholesale and retail liquid asphalt marketsor to a liquid asphalt marketer. In its normal state, liquid asphalt is too viscous to be used at ambient temperatures. For paving applications, asphalt can be heated (hot mix asphalt), diluted orcut back with petroleum solvents (cutback asphalts), or emulsified in a water base with emulsifying chemicals by a colloid mill (asphalt emulsions). Hot mixasphalt 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 thepaving 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 andfor thin maintenance overlay 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 mixasphalt overlay, cold mix pothole patching material and preventive maintenance surface applications such as chip seals. Asphalt emulsions are also used for fogseal, slurry seal, scrub seal, sand seal and microsurfacing maintenance treatments, warm mix emulsion/aggregate mixtures, base stabilization and both central plantand in-place recycling. Asphalt emulsions and cutback asphalts are generally sold directly to government agencies but are also sold to contractors. 3Table of ContentsThe 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 conditionshave on road construction schedules, particularly in cold weather states. Refineries produce liquid asphalt year-round, but the peak asphalt demand season is duringthe warm weather months when most of the road construction activity in the United States takes place. Liquid asphalt marketers and finished asphalt productproducers with access to storage capacity possess the inherent advantage of being able to purchase supply from refineries on a year-round basis and then sellfinished asphalt products in the peak summer demand season. Crude Oil Industry We provide crude oil gathering, marketing, transportation and terminalling services to producers, marketers and refiners of crude oil products. The market weserve, 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 ourassets extend from gathering systems and trucking networks in and around producing fields to transportation pipelines carrying crude oil to logistics hubs, such asthe Cushing Interchange, where we have terminalling facilities that aid our customers in managing their crude oil. Gathering, marketing and transportation . Pipeline transportation is generally considered the lowest cost and safest method for shipping crude oil and refinedpetroleum products to other locations. Crude oil pipelines transport oil from the wellhead to logistics hubs and/or refineries. Logistics hubs like the CushingInterchange provide storage and connections to other pipeline systems and other modes of transportation, such as truck, railroad, barge and tanker ship. Vessels andrailroads provide additional transportation capabilities for shipping crude oil between gathering storage systems, pipelines, terminals and end users. Vesseltransportation 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 gatheringsystems. Trucks can also be used to transport crude oil to aggregation points and storage facilities, which are generally located along pipeline gathering andtransportation systems. Trucking is generally limited to low-volume, short-haul movements where other alternatives to pipeline transportation are unavailable.Trucking costs escalate sharply with distance, making trucking the most expensive mode of crude oil transportation. Despite being small in terms of both volumeper shipment and distance, trucking is an essential component of the oil distribution system. Terminalling . Terminalling facilities complement the crude oil pipeline gathering and transportation systems. Terminals are facilities where crude oil istransferred 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 storage and inventory management and distribution. Terminalling assets generate revenues through a combination of storage and throughput charges to third parties. Storage fees are generated when tank capacityis 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 itto another shipper. Both storage fees and terminalling fees are earned from pipeline operators, refiners, gatherers and traders that need segregated storage, traderswho make or take delivery under NYMEX contracts, and producers and marketers who seek to increase their marketing alternatives. Overview of the Cushing Interchange . The Cushing Interchange, located in Cushing, Oklahoma, is one of the largest crude oil marketing hubs in the UnitedStates and the designated point of delivery specified in NYMEX crude oil futures contracts. As the NYMEX delivery point and a cash market hub, the CushingInterchange serves as the primary source of refinery feedstock for Midwest refiners and plays an integral role in establishing and maintaining markets for manyvarieties of foreign and domestic crude oil. The following table lists certain of the entities with incoming pipelines connected to the Cushing Interchange, theproprietary terminals within the complex and outgoing pipelines from the Cushing Interchange for delivery throughout the United States: 4Table of ContentsIncoming Pipelinesto Cushing InterchangeCushing InterchangeTerminalsOutgoing Pipelines from CushingInterchangeBlueknight Energy Partners, L.P. Basin PipelineSystemBP p.l.c. Centurion Pipeline, L.P. Enbridge Inc.Enterprise Products Partners L.P. Magellan MidstreamPartners, L.P. NGL Energy Partners, L.P.Plains All American Pipeline, L.P.SemGroup CorporationSunoco Logistics Partners, L.P. Tallgrass PonyExpress Pipeline, LLCTransCanada Corp.White Cliffs Pipeline, LLCBlueknight Energy Partners, L.P. ConocoPhillipsDeeprock Energy Resources LLC Enbridge EnergyPartners, L.P.Enterprise Products Partners L.P.Kinder Morgan, Inc.Magellan Midstream Partners, L.P.NGL Energy Partners, L.P.Plains All American Pipeline, L.P. SemGroup CorporationSunoco Logistics Partners, L.P.TransCanada Corp.Blueknight Energy Partners, L.P. BP p.l.c. Centurion Pipeline, L.P. ConocoPhillips DiamondPipeline, LLC Marathon Pipe Line, LLC MagellanMidstream Partners, L.P. NGL Energy Partners, L.P. Osage Pipeline Company, LLC Plains All American Pipeline, L.P. SemGroup CorporationSeaway Crude Pipeline Company LLCSunoco Logistics Partners, L.P. TransCanada Corp. With our pipeline and terminalling infrastructure, we have the ability to receive and/or deliver, directly or indirectly, to all pipelines and terminals within theCushing Interchange.Residual Fuel Oil Industry Like liquid asphalt, residual fuel oil is another by-product of the crude oil distillation process. Residual fuel oil is primarily used as a burner fuel in numerousindustrial and commercial applications, including the utility industry, the shipping and paper industry, steel mills, tire manufacturing 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 ofweather on the need to produce power for heating and cooling applications. The residual fuel oil market is largely a commodity market with price functioning asthe primary decision-making criterion. However, many customers have unique product specifications driven by their particular business applications that requirethe 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 facilities via numerous transportation methods,including truck, railroad, barge, and tanker ship. Some of our customers use our asphalt assets to service their residual fuel oil business.Asphalt Terminalling ServicesWith approximately 10.3 million barrels of asphalt cement storage capacity, we are able to provide our customers the ability to effectively manage their liquidasphalt inventories while allowing significant flexibility in their processing and marketing activities. As of March 7, 2018 , we have 56 terminals located in 26states and, as such, are well-positioned to provide asphalt terminalling services in the market areas we serve throughout the continental United States. We serve the asphalt industry by providing our customers access to their market areas through a combination of leasing our liquid asphalt facilities andproviding terminalling services at certain facilities. We generate revenues by charging a fee for the lease of a facility or for services provided as asphalt productsare terminalled in our facilities. As of March 7, 2018 , we have leases and storage agreements relating to all of our asphalt facilities. Lease and storage agreements related to 16 of thesefacilities have terms that expire by the end of 2018 , while the agreements relating to our additional 40 facilities have on average approximately five yearsremaining under their terms. Fifteen of the contracts that expire in 2018 are with Ergon. We may not be able to extend, renegotiate or replace these contracts whenthey expire and the terms of any renegotiated contracts may not be as favorable as the contracts they replace. We operate the asphalt facilities that are contracted bystorage, throughput and handling agreements, while our contract counterparties operate the asphalt facilities that are subject to the lease agreements. At facilities where we have storage contracts, we receive, store and/or process our customer’s asphalt products until we deliver those products to ourcustomers or other third parties. Our asphalt assets include the logistics assets, such as docks and rail spurs and the piping and pumping equipment necessary tofacilitate the unloading of liquid asphalt into our terminalling5Table of Contentsand storage facilities, as well as the processing and manufacturing equipment required for the processing of asphalt emulsions, asphalt cutbacks, polymer modifiedasphalt cement and other related finished asphalt products. After initial unloading, the liquid asphalt is moved via heat-traced pipe into storage tanks. Those tanksare insulated and contain heating elements that allow the liquid asphalt to be stored in a heated state. The liquid asphalt can then be directly sold by our customersto end users or used as a raw material for the processing of asphalt emulsions, asphalt cutbacks, polymer modified asphalt cement and related finished asphaltproducts that we process in accordance with the formulations and specifications provided by our customers. Depending on the product, the processing of asphaltentails combining asphalt cement and various other products such as emulsifying chemicals and polymers to achieve the desired specification and applicationrequirements. At leased facilities, our customers conduct the operations at the asphalt facility, including the storage and processing of asphalt products, and we collect amonthly rental fee relating to the lease of such facility. Generally, under the terms of those leases, (i) title to the asphalt, raw materials or finished asphalt productsreceived, unloaded, stored or otherwise handled at such asphalt facility is in the name of the lessee; (ii) the lessee is responsible for complying with environmental,health, safety, transportation and security laws; (iii) the lessee is required to obtain and maintain necessary permits, licenses, plans, approvals or other suchauthorizations and is responsible for insuring such asphalt facility; and (iv) most routine maintenance and repairs of such asphalt facility are the responsibility ofthe lessee. We do not take title to, or have marketing responsibility for, the liquid asphalt product that we terminal. As a result, our asphalt operations have minimal directexposure to changes in commodity prices, but the volumes of liquid asphalt we terminal are indirectly affected by commodity prices. The following table provides an overview of our asphalt facilities as of March 7, 2018 :LocationNumber of FacilitiesTotal Tankage (in thousands of bbls) (1)Alabama1212Arizona166Arkansas121California166Colorado4401Georgia2192Idaho1285Illinois2232Indiana1156Kansas5662Missouri3643Mississippi1202Montana1123Nebraska1292New Jersey1459Nevada1280North Carolina1259Ohio138Oklahoma71,409Pennsylvania159Tennessee51,596Texas61,001Utah2300Virginia2635Washington3470Wyoming1220Total5610,279_______________(1) Total tankage refers to the approximate total capacity of all tanks.6Table of ContentsOur asphalt assets range in age from one year to over 50 years, and we expect that our storage tanks and related assets will have an average remaining life inexcess of 20 years.Significant Customers. For the year ended December 31, 2017 , Ergon accounted for at least 45% but not more than 50% of our total asphalt terminallingservices revenue. Asphalt & Fuel Supply, LLC accounted for at least 10% but not more than 15% of asphalt terminalling services revenue in 2017 . The loss ofeither of those customers could have a material adverse effect on our business, cash flows and results of operations. No other customer accounted for more than10% of our asphalt terminalling services revenue during 2017 . As of March 7, 2018 , we have storage, throughput and handling agreements or operating leaseswith Ergon for 26 of our asphalt terminals. For more information regarding the Ergon agreements, please see “Item 13-Certain Relationships and Related-PartyTransactions, and Director Independence-Agreements with Related Parties and Affiliates.”Crude Oil Terminalling Services With approximately 6.9 million barrels of above-ground crude oil terminalling facilities, we are able to provide our customers with the ability to effectivelymanage their crude oil inventories and enhance flexibility in their marketing and operating activities. Our crude oil terminalling assets are located throughout ourcore operating areas, with the majority of our crude oil terminalling strategically located at the Cushing Interchange. Our crude oil terminalling assets receive crude oil products from pipelines or trucks, including those owned by us, and distribute those products to interstatecommon carrier pipelines and regional independent refiners, among other third parties. Our crude oil terminals derive most of their revenues from terminallingfees charged to customers.As of March 1, 2018 , we have approximately 5.4 million barrels of crude oil storage under service contracts, including 4.7 million barrels of crude oil storagecontracts that are either month-to-month contracts or expire in 2018. The weighted average remaining term on the service contracts is approximately 11 months ,with one contract having a remaining term of 47 months . Storage contracts with Vitol represent 2.2 million barrels of crude oil storage capacity under contract. Wemay 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 thecontracts they replace. 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 storagecapacity at our Cushing terminal and at our other terminals at the end of such periods: Year ended December 31, 2016 2017 (in thousands)Average crude oil barrels stored per month at our Cushing terminal5,536 5,413Average crude oil delivered (Bpd) to our Cushing terminal78 41Total storage capacity at our Cushing terminal (barrels at end of period)6,600 6,600Total other storage capacity (barrels at end of period)834 337 The following table outlines the location of our crude oil terminals and their storage capacities and number of tanks as of December 31, 2017 :LocationStorage Capacity(thousands of barrels)Number ofTanksCushing, Oklahoma6,60034Other (1)337177Total6,937211_______________(1) Consists of miscellaneous storage tanks located at various points along our pipeline and gathering systems. 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 34 crude oil storage tanks with approximately 6.6 million barrels of storage capacity at this location. We own approximately 50 additionalacres of land within the Cushing Interchange that is available for future expansion. 7Table of ContentsOur Cushing terminal was constructed over the last 50 years and has an expected remaining life of at least 20 years. Over 90% of our total storage capacity inour Cushing terminal has been built since 2002. We estimate that our storage tanks have a weighted average age of 14 years. The design and construction specifications of our storage tanks meet or exceed the minimums established by the American Petroleum Institute (“API”). Ourstorage tanks also undergo regular maintenance inspection programs that are more stringent than established governmental guidelines. We believe that these designspecifications and inspection programs will result in lower future maintenance capital costs. A key attribute of our Cushing terminal is that through our pipeline interface, we have access and connectivity to almost all of the terminals located within theCushing Interchange. This connectivity is important because it provides us the ability to deliver to virtually any customer within the Cushing Interchange. Our Cushing terminal can receive crude oil from our Mid-Continent pipeline system as well as other terminals owned by Magellan Midstream Partners,Enterprise Products Partners, Sunoco Logistics Partners, Plains All American Pipeline, L.P., Seaway Crude Pipeline Company, LLC, Enbridge Energy Partners,L.P., SemGroup Corporation, Deeprock Energy Resources, LLC and two truck stations. 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 ofreceiving and/or delivering approximately 350,000 Bpd of crude oil. Significant Customers . For the year ended December 31, 2017 , Vitol accounted for at least 40% but not more than 45% of our total crude oil terminallingrevenue, and Citigroup Energy, Inc. and MVP Logistics, LLC each accounted for at least 10% but not more than 25% of our total crude oil terminallingrevenue. The loss of any of these customers could have a material adverse effect on our business, cash flows and results of operations. No other customeraccounted for more than 10% of our crude oil terminalling revenue during 2017 .Crude Oil Pipeline Services We own and operate a crude oil transportation system in the Mid-Continent region of the United States with a total length of approximately 655 miles. Inaddition, we purchase crude oil at production leases in Oklahoma, and we market those barrels primarily at the Cushing Interchange.SystemAsset TypeApproximateLength(miles)AverageThroughput forYear EndedDecember 31, 2016(Bpd)AverageThroughput forYear EndedDecember 31, 2017(Bpd)Pipe DiameterRangeMid-ContinentGathering and transportation pipelines65526,50521,9314” to 20” Mid-Continent Pipeline System . Our Mid-Continent pipeline system provides access to our Cushing terminal and other storage facilities. Our Mid-Continentpipeline system consists of approximately 655 miles of various sized pipeline, of which approximately 150 miles are currently idle, and has a capacity ofapproximately 25,000 Bpd. Crude oil delivered into the Oklahoma portion of our Mid-Continent pipeline system is transported to our Cushing terminal ordelivered to local area refiners. The Mid-Continent pipeline system includes:•an approximately 110-mile gathering and transportation system in southern Oklahoma acquired in November 2015 which has a capacity of 5,000 Bpd.Barrels transported on this pipeline are delivered to a single customer in southern Oklahoma;•an approximately 35-mile gathering and transportation system in the Texas Panhandle near Dumas, Texas. Crude oil collected through the TexasPanhandle portion of our Mid-Continent system is transported by pipeline to a station where it is then delivered to market via tanker truck; and•an approximately 145-mile, 8-inch pipeline previously referred to as the Eagle North pipeline system. The throughput and deficiency agreement on ourEagle North pipeline system expired June 30, 2016. In July of 2016, because of the suspension of service of a portion of the Mid-Continent pipelinesystem, we completed a connection between our Mid-Continent and Eagle North pipeline systems and concurrently reversed the Eagle North pipelinesystem to deliver barrels from southern Oklahoma to Cushing, Oklahoma. As a result, we are currently operating one Oklahoma mainline system,which is a combination of both the Mid-Continent and Eagle North pipeline systems, instead of two separate systems.8Table of ContentsThe Mid-Continent pipeline system was constructed in various stages beginning in the 1940s, and we believe it has a remaining life of at least 20 years. In lateApril 2016, as a precautionary measure we suspended service on a segment of our Mid-Continent pipeline system due to discovery of a pipeline exposure causedby heavy rains and the erosion of a riverbed in southern Oklahoma. There was no damage to the pipe and no loss of product. In the second quarter of 2016, we tookaction to mitigate the service suspension and worked with customers to divert volumes and, in certain circumstances, transported volumes to a third-party pipelinesystem via truck. We are working to restore service on the second Oklahoma pipeline system and expect to put the line back in condensate service by the end of thesecond quarter of 2018, increasing the transportation capacity of our pipeline systems by approximately 20,000 Bpd. The ability to fully utilize the capacity ofthese systems may be impacted by the market price of crude oil and producers’ decisions to increase or decrease production in the areas we serve. East Texas Pipeline System . We previously owned and operated the East Texas pipeline system, which is located in Texas. On April 18, 2017, we sold theEast Texas pipeline system. We received cash proceeds at closing of approximately $4.8 million and recorded a gain of less than $0.1 million. For the years endedDecember 31, 2016 and 2017 , our East Texas pipeline system gathered an average of approximately 9,146 Bpd and 2,937 Bpd, respectively, for the periods inwhich we owned the system. Significant Customers . For the year ended December 31, 2017 , CP Energy, LLC, CVR Energy, Inc. and Vitol each accounted for at least 20% but not morethan 35% of crude oil pipeline services revenue. The loss of any of these customers could have a material adverse effect on our business, cash flows and results ofoperations. No other customer accounted for more than 10% of our crude oil pipeline services revenue during 2017 .Crude Oil Trucking and Producer Field Services We provide two types of trucking services: crude oil trucking transportation and producer field services. Crude Oil Trucking Services. To complement our pipeline gathering, marketing and transportation business, we use our approximately 65 owned or leasedtanker trucks, which have an average tank size of approximately 200 barrels, to move crude oil to aggregation points, pipeline injection stations and storagefacilities. Our tanker trucks moved an average of 27,000 Bpd and 21,000 Bpd for the years ended December 31, 2016 and 2017 , respectively, from wellheadlocations not served by pipeline gathering systems. The following table outlines the distribution of our trucking assets among our operating areas as of March 1,2018 :LocationNumber of TrucksOklahoma45Kansas15Texas5Total65 During the second half of 2015, our West Texas operating margins and transported volumes were negatively impacted by increased competition fromtransporters moving equipment from crude oil shale areas to West Texas, where crude oil volumes have remained fairly steady and producers and marketersquickly pipe-connected barrels for transport, reducing the demand for trucking transportation. As a result, we decided to cease trucking barrels in West Texas andrefocus our efforts on transporting barrels around our owned crude oil pipelines and storage assets in Oklahoma and Kansas. Due to this change, we recognized a$1.6 million restructuring expense in December 2015 comprised of employee severance costs and the recognition of future lease expense on idled equipment as ofDecember 31, 2015. The severance costs were paid in the first quarter of 2016, and the lease payments will be made over the remaining lease terms, which extendthrough July 2019. See Note 6 to our consolidated financial statements for additional detail regarding this restructuring expense. Additionally, in December 2015we recorded a $0.5 million impairment expense to write down the assets related to our West Texas trucking stations to their estimated fair value.Producer Field Services . We provide various producer field services for companies such as DCP Operating Company, LP, Scout Energy Management, LLCand Regency Energy Partners, LP. These services include gas gathering pipeline maintenance, hot and cold fresh water delivery, chemical and downhole welltreatment, wet oil cleanup, and separation facilities building and maintenance. In December 2017 we recorded a $2.4 million impairment expense to write down thecarrying value of our assets related to our producer field services business to their estimated fair value.9Table of ContentsWe provide these services at contracted hourly rates. Our producer service fleet consists of approximately 85 trucks in a number of different sizes. Significant Customers. For the year ended December 31, 2017 , MV Purchasing, LLC, Vitol and DCP Operating Company, LP each accounted for at least10% but not more than 30% of crude oil trucking and producer field services revenue. The loss of any of these customers could have a material adverse effect onour business, cash flows and results of operations. No other customer accounted for more than 10% of our crude oil trucking and producer field services revenueduring 2017 .Competition We compete with national, regional and local liquid asphalt terminalling companies and gathering, storage and pipeline companies, including the majorintegrated oil companies, of widely varying sizes, financial resources and experience. We are subject to competition from other crude oil gathering, pipelinetransportation, terminalling operations and trucking operations that may be able to supply our customers with the same or comparable services on a morecompetitive basis. The asphalt industry is highly fragmented and regional in nature. Participants range in size from major oil companies to small family-ownedbusinesses. Participants in the asphalt business include refiners such as BP p.l.c., Flint Hills Resources, L.P., CHS, Inc., Exxon Mobil Corporation, ConocoPhillipsCo., NuStar Energy L.P., Ergon, Inc., Marathon Petroleum Company LLC, Alon USA LP, Suncor Energy Inc. and Valero Energy Corporation; resellers such asAssociated Asphalt Partners, LLC, Idaho Asphalt Supply, Inc. and Asphalt Materials, Inc.; and large road construction firms such as Old Castle Materials, Inc. andColas SA. We compete for asphalt terminalling services with the national, regional and local industry participants as well as with liquid asphalt terminallingcompanies, including the major integrated oil companies and a variety of others, such as KinderMorgan Inc., International-Matex Tank Terminals and HoustonFuel Oil Terminal Company. With respect to our crude oil gathering and transportation services, our competitors include Enterprise Products Partners L.P., Plains All American Pipeline,L.P., Magellan Midstream Partners, L.P., Sunoco Logistics Partners L.P. and Rose Rock Midstream Partners, L.P., among others. With respect to our crude oilterminalling services, our competitors include Magellan Midstream Partners, L.P., Enbridge Energy Partners, L.P., Enterprise Products Partners L.P., Plains AllAmerican Pipeline, L.P. and Rose Rock Midstream Partners, L.P., among others. Several of our competitors conduct portions of their operations through publiclytraded partnerships with structures similar to ours, including Plains All American Pipeline, L.P., Enterprise Products Partners L.P., Sunoco Logistics Partners L.P.,Magellan Midstream Partners, L.P. and Rose Rock Midstream Partners, L.P. Our ability to compete could be harmed by factors we cannot control, including:•the perception that another company can provide better service;•the availability of crude oil alternative supply points, or crude oil supply points located closer to the operations of our customers; and/or•a decision by our competitors to acquire or construct crude oil midstream assets and provide gathering, transportation or terminalling services ingeographic areas, or to customers, served by our assets and services. If we are unable to compete effectively with services offered by other midstream enterprises, our financial results and ability to make distributions to ourunitholders may be adversely affected. Additionally, we also compete with national, regional and local companies for asset acquisitions and expansionopportunities. Some of these competitors are substantially larger than us and have greater financial resources and lower costs of capital than we do.Pipeline RegulationWe currently do not offer interstate transportation service regulated by the Federal Energy Regulatory Commission (“FERC”) with the exception of two shortinterstate segments where the sole shipper is our affiliate. Our interstate pipeline segments are subject to regulatory enforcement by the U.S. Department ofTransportation’s (“DOT”) Pipeline Hazardous Materials Safety Administration (“PHMSA”). Gathering and Intrastate Pipeline Regulation . All intrastate pipelines in the state of Oklahoma are regulated by the Oklahoma Corporation Commission. Inthe 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. Pipeline Safety . Our pipelines are subject to state and federal laws and regulations governing design, construction, operation and maintenance of the lines;qualifications of pipeline personnel; public awareness; emergency response and other10Table of Contentsaspects of pipeline safety. These laws and regulations are subject to change, resulting in potentially more stringent requirements and increased costs. Applicablepipeline safety regulations establish minimum safety requirements and, for pipelines that pose a greater risk to populated areas or environmentally sensitive areas,impose a more rigorous requirement for the implementation of pipeline integrity management programs for our pipelines. The Pipeline Safety, RegulatoryCertainty, and Job Creation Act of 2011 (“Pipeline Safety Act”) was enacted in January 2012. That legislation increased the maximum civil penalties for pipelinesafety administrative enforcement actions; required the DOT to study and report on the expansion of integrity management requirements, the sufficiency ofexisting gathering line regulations to ensure safety and the feasibility of leak detection systems for hazardous liquid pipelines; required pipeline operators to verifytheir records on maximum allowable operating pressure; and imposed new emergency response and incident notification requirements. In 2016, the Pipeline SafetyAct was reauthorized and amended to add additional construction inspection requirements, clarify integrity management rules and update federally incorporatedstandards. On January 23, 2017, PHMSA published a final rule that became effective on March 24, 2017. This rule amended the Pipeline Safety Act to include,among other provisions, a specific time frame for notifying PHMSA of accidents and incidents, allowance for PHMSA to recover costs associated with designreviews of new projects, renewal of expiring special permits, processes for requesting protection of confidential commercial information, changes to the drug andalcohol testing requirements and incorporating consensus standards by reference for in-line inspection and stress corrosion cracking direct assessment. The states inwhich we operate pipelines incorporate into their state rules those federal safety standards for hazardous liquids pipelines contained in Title 49, Part 195 of theFederal Code of Regulations. As a result, the issuance of any new pipeline safety regulations, including additional requirements for integrity management, is likelyto increase the operating costs of our pipelines subject to such new requirements, and such future costs may be material. 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 toperform both intrastate and interstate motor carrier services. As a motor carrier, we are subject to certain safety regulations issued by the DOT. The truckingregulations cover, among other things, driver operations, maintaining log books, truck manifest preparations, the placement of safety placards on the trucks andtrailer vehicles, drug and alcohol testing, safety of operation and equipment and many other aspects of truck operations. We are also subject to requirements of thefederal Occupational Safety and Health Act, as amended (“OSHA”), with respect to our trucking operations.Environmental, Health and Safety RisksGeneral . Our midstream crude oil gathering, transportation and terminalling operations, as well as our asphalt assets, are subject to stringent federal, stateand local laws and regulations relating to the discharge of materials into the environment or otherwise relating to protection of the environment, health and safety.Various permits or other authorizations are required under these laws for the operation of our terminals, pipelines and related operations, and may be subject torevocation, modification and renewal. These laws and regulations may also require notice to stakeholders of proposed and ongoing operations; require theinstallation of expensive pollution control equipment; restrict the types, quantities and concentrations of various substances that can be released into theenvironment in connection with transporting through pipelines; or establish specific safety and health criteria addressing worker protection. As with liquid asphaltand midstream industries generally, compliance with current and anticipated environmental laws and regulations increases our overall cost of business, includingour capital costs to construct, maintain and upgrade equipment and facilities. Failure to comply with these laws and regulations may result in the assessment ofsignificant administrative, civil and/or criminal penalties, the imposition of investigatory and remedial liabilities and issuance of injunctions that may restrict orprohibit some or all of our operations. We believe that our operations are in substantial compliance with applicable laws, regulations and permits. However,environmental laws and regulations are subject to change, along with varying degrees of interpretation and departmental policies, resulting in potentially morestringent requirements. The recent legislative and regulatory trend has been to place increasingly stringent restrictions and limitations on activities that may affectthe environment. Federal, state or local administrative decisions, developments in the federal or state court systems or other governmental or judicial actions mayinfluence the interpretation and/or enforcement of environmental laws and regulations and may thereby increase compliance costs. We cannot provide anyassurance that the cost of compliance with current and future laws and regulations will not have a material effect on our results of operations, financial position orcash flows. Risks of accidental releases into the environment, such as leaks or spills of petroleum products or hazardous materials from our terminals, pipelines and trucks,are inherent in the nature of both our liquid asphalt and midstream operations. A discharge of petroleum products or hazardous materials into the environmentcould, to the extent such event is not covered by insurance, subject us to substantial expense, including costs related to environmental cleanup or restoration,compliance with applicable laws and regulations and any personal injury, natural resource or property damage claims made by neighboring landowners and otherthird parties. 11Table of ContentsThe following is a summary of the more significant current environmental, health and safety laws and regulations to which our business operations are subjectand for which compliance may require material capital expenditures or have a material adverse impact on our results of operations, financial position and cashflows. Water . The federal Clean Water Act (“CWA”) and analogous state and local laws impose restrictions, strict controls and permitting requirements on thedischarge of pollutants into waters of the United States and state waters. We note that the term “waters of the United States” is already broadly construed and, in2015, the United States Environmental Protection Agency (“EPA”) and U.S. Army Corps of Engineers adopted a rule to clarify the meaning of the term “waters ofthe United States.” Many interested parties believe that the rule expands federal jurisdiction under the CWA. In January 2018, the Supreme Court ruled that districtcourts have jurisdiction over challenges to the rule. Litigation surrounding this rule is ongoing, and the EPA has instituted rulemakings to both delay the effectivedate of the rule and to repeal the rule. Although the outcome of these legal challenges remains uncertain, with the change in administration, the “waters of theUnited States” rule is not currently expected to survive those challenges. The CWA and analogous laws provide significant penalties for unauthorized dischargesand impose substantial potential liabilities for cleaning up releases into water. In addition, the CWA and analogous state laws require individual permits orcoverage under general permits for discharges of storm water runoff from certain types of facilities. Some states also maintain groundwater protection programsthat require permits for discharges or operations that may impact groundwater conditions. We believe that we are in substantial compliance with any suchapplicable state requirements. The federal Oil Pollution Act, as amended (“OPA”), was enacted in 1990 and amended provisions of the Federal Water Pollution Control Act of 1972, theCWA 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 forstoring, handling or transporting oil, including trucks and pipelines, to strict, joint and potentially unlimited liability for containment and removal costs, naturalresource damages and certain other consequences of an oil spill, where such spill is into navigable waters, along shorelines or in the exclusive economic zone ofthe United States. The OPA and other analogous laws also impose certain spill prevention, control and countermeasure requirements, such as the preparation ofdetailed oil spill emergency response plans and the construction of dikes and other containment structures to prevent contamination of navigable or other waters inthe 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. Air Emissions . Our operations are subject to the federal Clean Air Act (“CAA”), as amended, as well as to comparable state and local laws. We believe thatour operations are in substantial compliance with applicable laws in those areas in which we operate. Amendments to the CAA enacted in 1990 imposed a federaloperating permit requirement for major sources of air emissions. Our crude oil terminal located in Cushing, Oklahoma holds such a permit, which is referred to as a“Title V permit.” The EPA approved final rules under the CAA that established new air emission controls for oil and natural gas production, pipelines andprocessing operations that took effect on October 15, 2012. To respond to challenges, the EPA revised certain aspects of the rules and has indicated it mayreconsider other aspects. The EPA finalized a rule, which took effect August 2, 2016, to set standards for methane and volatile organic compound emissions fromnew and modified sources in the oil and gas sector, including transmission. The EPA is currently engaged in rulemaking to stay the effective date of these rules.The costs of compliance with any modified or newly issued rules cannot be predicted. The Obama administration also announced in January 2015 that other federalagencies, including the Bureau of Land Management (“BLM”), PHMSA and the Department of Energy, will impose new or more stringent regulations on the oiland gas sector that are said to have the effect of reducing methane emissions. For example, the BLM adopted rules that took effect on January 17, 2017, to reduceventing, flaring and leaks during oil and natural gas production activities on onshore federal and Indian leases. In December 2017, implementation of this rule wasdelayed until January 2019. Compliance with these rules could result in additional compliance costs for us and for others in our industry. In response to these andother regulatory developments, we may be required to incur certain capital expenditures in the next several years for air pollution control equipment andoperational changes in connection with obtaining or maintaining permits and approvals and complying with applicable regulations addressing air emission relatedissues. However, the status of recent and future rules and rulemaking initiatives under the new administration is uncertain. Although we can provide no assurance,we believe future compliance with the CAA, as currently amended, will not have a material adverse effect on our financial condition, results of operations or cashflows. Climate Change . 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, regionaland state levels. The oil and gas industry is a direct source of certain GHG emissions, namely carbon dioxide and methane, and future restrictions on suchemissions could impact our future operations. In the United States, the U.S. Congress, in the past, has considered but not enacted federal legislation requiring GHGcontrols. The EPA has adopted regulations under existing provisions of the CAA that require Prevention of Significant Deterioration (“PSD”) pre-constructionpermits, and Title V operating permits for GHG emissions from certain large stationary sources. Furthermore, in 2009, the EPA adopted rules requiring themonitoring and reporting of GHG emissions12Table of Contentsfrom specified sources in the United States., including, among others, certain onshore oil and natural gas processing and fractionating facilities. Monitoringobligations began in 2010 and the emissions reporting requirements took effect in 2011. These EPA rulemakings could affect our operations and ability to obtainair permits for new or modified facilities. In addition, efforts have been and continue to be made in the international community toward the adoption ofinternational treaties or protocols. In 2015, the United States participated in the United Nations Conference on Climate Change, which led to the adoption of theParis Agreement that will require countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emissionreduction goals, every five years beginning in 2020. However, in June 2017, President Trump announced that the United States plans to withdraw from the ParisAgreement and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. The Paris Agreementprovides for a four-year exit process beginning in November 2016, which would result in an effective exit date of November 2020. The United States’s adherenceto the exit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. Dueto the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developmentson our operations. Legislation and regulations relating to control or reporting of GHG emissions are also in various stages of discussions or implementation in many of the statesin which we operate. Passage of climate change legislation or other federal or state legislative or regulatory initiatives that regulate or restrict GHG emissions inareas in which we conduct business could adversely affect the demand for our products and services, and depending on the particular program adopted couldincrease the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances toauthorize our GHG emissions (e.g., from natural gas fired combustion units), pay any taxes related to our GHG emissions and/or administer and manage a GHGemissions program. At this time, it is not possible to accurately estimate how laws or regulations addressing GHG emissions would impact our business. Althoughwe do not expect we would be impacted to a greater degree than other similarly situated midstream transporters of petroleum products, the greenhouse gas controlprograms could have an adverse effect on our cost of doing business and could reduce demand for the products we transport. In addition to potential impacts on our business directly or indirectly resulting from climate change legislation or regulations, our business also could benegatively affected by climate-related physical changes or changes in weather patterns. Severe weather could result in damages to or loss of our physical assets,impact our ability to conduct operations and/or result in a disruption of our customers’ operations. These types of physical changes could also affect entities thatprovide goods and services to us, and indirectly have an adverse effect on our business as a result of increases in costs or availability of goods andservices. Changes of this nature could have a material adverse impact on our business. Solid Waste Disposal and Environmental Remediation. The Comprehensive Environmental Response, Compensation, and Liability Act, as amended(“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, oncertain classes of persons associated with the release of a “hazardous substance” into the environment. These persons include the owner or operator and certainformer owners and operators of the site or sites where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardoussubstances found at the site. Under CERCLA, such persons may be subject to strict and, under certain circumstances, 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 forpersonal injury and property damage allegedly caused by releases of hazardous substances or other pollutants. We generate materials in the course of ouroperations that fall within CERCLA’s hazardous substance definition. Beyond the federal statute, many states have enacted environmental response statutes thatare analogous to CERCLA. We generate wastes, including “hazardous wastes,” that are subject to the requirements of the federal Resource Conservation and Recovery Act, as amended(“RCRA”), as well as to comparable state and local laws. While normal costs of complying with these laws would not be expected to have a material adverse effecton our financial conditions, we could incur substantial expense in the future if the RCRA exemption for certain oil and gas “exploration and production” wastewere eliminated. For example, in 2016, the EPA and certain environmental organizations entered into a consent decree which requires the EPA to propose arulemaking no later than March 15, 2019, for the revision of criteria regulations pertaining to exempted oil and gas wastes or to sign a determination that revisionof the regulations is not necessary. Should any oil and gas exploration and production wastes become subject to RCRA, we would also become subject to morerigorous 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, transported or stored or have been handled, transported or stored formany years. Although we believe that operating and disposal practices that were standard in the liquid asphalt, midstream and field services industries at the timewere utilized at properties leased or owned by us, historical releases of hazardous substances or associated generated wastes may have occurred on or under theproperties owned13Table of Contentsor 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 bythird parties whose treatment and disposal or release of hazardous substances or associated generated wastes were not under our control. These properties and thematerials disposed on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediatepreviously released hazardous materials or associated generated wastes (including wastes disposed of or released by other site occupants or by prior owners oroperators), or to clean up contaminated property (including contaminated groundwater). Contamination resulting from the release of hazardous substances or associated generated wastes is not unusual in the liquid asphalt and midstreamindustries. Other assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified. In thefuture, we may experience releases of hazardous materials, including petroleum products, into the environment from our pipeline terminalling operations, ordiscover releases that were previously unidentified. Although we maintain a program designed to prevent and, as applicable, to detect and address such releasespromptly, damages and liabilities incurred due to environmental releases from our assets may substantially affect our business.Regulation of Hydraulic Fracturing. A portion of our customers’ production is developed from unconventional sources, such as shales, that require hydraulicfracturing as part of the production process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into shale formations tostimulate crude oil and/or natural gas production. The practice of hydraulic fracturing has been subject to public scrutiny in recent years and various efforts toregulate, or in some cases prohibit, hydraulic fracturing have been pursued at the local, state and federal levels of government, and may be pursued in the future.For example, several states, including states in which we operate, have imposed disclosure requirements on hydraulic fracturing, and several local governmentshave prohibited or severely restricted hydraulic fracturing within their jurisdictions. Restrictions on hydraulic fracturing could adversely affect our operations byreducing the volumes of crude oil that we transport.Seismicity Related to Wastewater Disposal Wells. Wastewater injection into disposal wells has been tied to increased seismic activity in Oklahoma and otherproducing states. In some seismically active areas, regulators have responded with permanent and temporary restrictions on the volume and rate of wastewaterinjection into disposal wells. Such restrictions on wastewater disposal wells or taxation imposed on injected fluids could have a negative impact on us and others inthe industry.Endangered Species and Migratory Birds. The Endangered Species Act (“ESA”), restricts activities that may affect endangered or threatened species or theirhabitats. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are insubstantial compliance with the ESA. However, the designation of previously unlisted endangered or threatened species could cause us to incur additional costs orbecome subject to operating restrictions or bans or limit future development in the affected areas. The Migratory Bird Treaty Act (“MBTA”), implements varioustreaties and conventions between the United States and certain other nations for the protection of migratory birds. Pursuant to the MBTA, the taking, killing orpossessing of migratory birds is unlawful without a permit, thereby potentially requiring the implementation of operating restrictions or a temporary, seasonal, orpermanent ban in affected areas. We believe that we are in substantial compliance with the MBTA. 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. Inaddition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in operations andthat this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliancewith OSHA requirements and industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. National Environmental Policy Act . The National Environmental Policy Act (“NEPA”) requires federal agencies, including the EPA and Department ofInterior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare anenvironmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailedenvironmental impact statement that may be made available for public review and comment. This process has the potential to delay or even halt the developmentoil and natural gas projects.Anti-Terrorism Measures . The federal Department of Homeland Security Appropriations Act of 2007 (“Appropriations Act”) requires the Department ofHomeland Security (“DHS”) to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oiland gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 known as the Chemical Facility Anti-Terrorism Standards (“CFATS”) regarding risk-based performance standards to be attained pursuant to the Appropriations Act and, on14Table of ContentsNovember 20, 2007, issued an Appendix A to CFATS that established chemicals of interest and their respective threshold quantities that trigger compliance withthe interim rules. In December 2014, the Protecting and Securing Chemical Facilities from Terrorist Attacks Act of 2014 (“CFATS Act”) was enacted. The CFATSAct reauthorized the CFATS program for four years. The CFATS program utilizes a Chemical Security Assessment Tool (“CSAT”) to identify chemical facilitiespotentially deemed “high risk.” The first step of CSAT is user registration, followed by the completion of a top-screen evaluation. The top-screen evaluationanalyzes whether a facility stores regulated chemicals above specified thresholds. If it does, the facility must complete a Security Vulnerability Assessment, whichidentifies a facility’s security vulnerabilities, and develop and implement a Site Security Plan, which must include measures that satisfy the identified risk-basedperformance standards. DHS must review and approve or deny all security vulnerability assessments and site security plans. CFATS also requires regulatedfacilities to keep detailed security records and allow DHS the right to enter, inspect, and audit the property, equipment, operations and records of such facilities.We believe we are in substantial compliance with the CFATS program at our facilities that handle, store, use or process COI above the applicable threshold.Operational Hazards and Insurance Terminals, pipelines and similar facilities may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury andloss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insuranceof various types and varying levels of coverage which we consider adequate under the circumstances to cover our operations and properties, including coverage forpollution-related events. However, such insurance does not cover every potential risk associated with operating terminals, pipelines and other facilities. The overallcost of the insurance program has decreased over the last five years due to favorable claims history, improved risk management practices, collaborativerelationships with our underwriters and competitive insurance markets. Through the utilization of deductibles and retentions, we self-insure the “working layer” ofloss activity to create a more efficient and cost-effective program. The working layer consists of high-frequency/low-severity losses that are best retained andmanaged in-house. We continue to monitor our retentions as they relate to the overall cost and scope of our insurance program.Employees As of December 31, 2017 , we employed approximately 370 persons. None of these employees are represented by labor unions or covered by any collectivebargaining agreement. We believe that relations with these employees are satisfactory.Financial Information about Segments Information regarding our operating revenues, profit and loss and identifiable assets attributable to each of our segments is presented in Note 20 to ourconsolidated 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 reportsfiled with the SEC under the Securities and Exchange Act of 1934. These documents may be accessed free of charge on our website, www.bkep.com, as soon as isreasonably practicable after their filing with the SEC. Information contained on our website is not incorporated by reference in this report or any of our otherfilings. 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 theoperation of the Public Reference Room is available by calling 1-800-SEC-0330. The SEC also maintains a website which contains reports, proxy and informationstatements and other information regarding issuers that file electronically with the SEC. The SEC’s website is www.sec.gov .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 aresimilar 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 theother information included in this report. If any of the following risks were actually to occur, our business, financial condition, results of operations and cash flowscould be materially adversely affected. In that case, we might not be able to pay distributions on our units, the trading price of our units could decline and ourunitholders could lose all or part of their investment.15Table of ContentsRisks Related to our BusinessWe may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including costreimbursements to our General Partner, to enable us to make cash distributions to holders of our units at our current distribution rate. In order to make cash distributions on our Preferred Units at the preference distribution rate of $0.17875 per unit per quarter, or $0.715 per unit per year, and onour common units at the minimum quarterly distribution of $0.11 per unit per quarter, or $0.44 per unit per year, we will require available cash of approximately$10.9 million per quarter, or $43.7 million per year. We may not have sufficient available cash from operating surplus each quarter to enable us to make cashdistributions on our Preferred Units at the preference rate or on our common units at the minimum quarterly distribution rate. The amount of cash we can distributeon our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among otherthings, the risks described herein. In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:•the level of capital expenditures we make;•the cost of acquisitions;•our debt service requirements and other liabilities;•fluctuations in our working capital needs;•our ability to borrow funds and access capital markets;•restrictions contained in our credit facility or other debt agreements; and•the amount of cash reserves established by our General Partner.Our cash available for distributions to our unitholders could be negatively impacted if we are unable to extend existing storage contracts or enter into newstorage contracts at our Cushing terminal. We have a total of 6.6 million barrels of storage capacity at the Cushing terminal. Customer storage contracts for 4.7 million barrels of storage at this locationare month-to-month or expire in 2018. We may not be able to extend, renegotiate or replace these contracts when they expire and the terms of any renegotiatedcontracts may not be as favorable as the contracts they replace. In addition, to the degree that we operate outside of long-term contracts, our revenues can besignificantly more volatile than would be the case with a pricing structure negotiated through a long-term storage contract. If we cannot successfully renewsignificant contracts or must renew them on less favorable terms, our revenues from these arrangements could decline, which could have a material adverse effecton our financial condition, results of operations and cash flows. We depend on certain key customers for a portion of our revenues and are exposed to credit risks of these customers. The loss of or material nonpayment ornonperformance by any of these key customers could adversely affect our financial condition, results of operations and cash flows. We rely on certain key customers for a portion of revenues. For example, Ergon Asphalt & Emulsions, Inc. , a wholly-owned subsidiary of Ergon, Inc.,represented approximately $56.4 million , or 50% , of our total asphalt terminalling services revenue in 2017 . Vitol represented approximately $8.9 million , or40% , of our total crude oil terminalling revenue, $6.4 million , or 30% , of our crude oil pipeline services revenue and $5.9 million , or 24% , of our total crude oiltrucking and producer field services revenue in 2017 . Vitol and Ergon are private companies and we have limited information regarding their financial condition. Vitol and Ergon Asphalt & Emulsions, Inc. comprised 9% and 29% , respectively, of total accounts receivable at December 31, 2017 . In addition to Vitol and Ergon Asphalt & Emulsions, Inc. , we have other key customers. Asphalt & Fuel Supply, LLC accounted for at least 10% but notmore than 15% of total asphalt terminalling services revenue in 2017 . Citigroup Energy, Inc. and MVP Logistics, LLC each accounted for at least 10% but nomore than 25% of total crude oil terminalling revenue in 2017 . MV Purchasing, LLC and DCP Operating Company, LP each accounted for at least 10% but nomore than 30% of total crude oil trucking and producer field services revenue in 2017 . CP Energy, LLC and CVR Energy, Inc. each accounted for at least 20% butno more than 35% of total crude oil pipeline services revenue in 2017 . We may be unable to negotiate extensions or replacements of contracts with key customers on favorable terms. In addition, some of these key customers mayexperience financial problems which could have a significant effect on their creditworthiness. Severe financial problems encountered by our customers could limitour ability to collect amounts owed to us16Table of Contentsor to enforce performance of obligations under contractual arrangements. Additionally, many of our customers finance their activities through cash flows fromoperations, the incurrence of debt or the issuance of equity. The reduction of cash flows resulting from declines in commodity prices, a reduction in borrowingbases under credit facilities, the lack of availability of debt or equity financing or any combination of such factors may result in a significant reduction of ourcustomers’ liquidity and limit their ability to make payments or perform on their obligations to us. Furthermore, some of our customers may be highly leveragedand subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. The loss of all or even a portion ofthe contracted volumes of these key customers, as a result of competition, creditworthiness or otherwise, could have a material adverse effect on our business, cashflows, ability to make distributions to our unitholders, unit price, results of operations and ability to conduct our business.We are exposed to the credit risks of our third-party customers in the ordinary course of our gathering activities. Any material nonpayment or nonperformanceby 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 leveragedand subject to their own operating and regulatory risks, including risks relating to commodity price deterioration or other conditions in the energy industry. Inaddition, any material nonpayment or nonperformance by our customers could require us to pursue substitute customers for our affected assets or to providealternative services. Any such efforts may not be successful, may be expensive to undertake and may not provide similar fees. These events could have a materialadverse effect on our financial condition, results of operations and cash flows.The amount of cash we have available for distribution to holders of our units depends primarily on our cash flows and not solely on earnings reflected in ourfinancial statements. Consequently, even if we are profitable and are otherwise able to pay distributions, we may not be able to make cash distributions toholders of our units. Our unitholders should be aware that the amount of cash we have available for distribution depends primarily upon our cash flows and not solely on earningsreflected 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 forfinancial accounting purposes.Our debt levels under our credit agreement may limit our ability to make distributions and our flexibility in obtaining additional financing and in pursuingother business opportunities. As of December 31, 2017 , we had approximately $309.1 million in outstanding indebtedness, including approximately $1.5 million in outstanding letters ofcredit, under our $450.0 million credit agreement. Our level of debt under the credit agreement could have important consequences for us, including the following:•our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or suchfinancing may not be available on favorable terms;•we will need a substantial portion of our cash flows to make principal and interest payments on our debt, reducing the funds that would otherwise beavailable for operations, future business opportunities and distributions to unitholders;•our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and•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 prevailingeconomic conditions and financial, business, regulatory and other factors. Our ability to service debt under our credit agreement also will depend on market interestrates, since the interest rates applicable to our borrowings will fluctuate with the eurodollar rate or the prime rate. If our operating results are not sufficient toservice 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 toeffect any of these actions on satisfactory terms, or at all.17Table of ContentsRestrictions in our credit agreement could materially adversely affect our business, financial condition, results of operations, ability to make cash distributionsto unitholders and value of our units .We are dependent upon the earnings and cash flows generated by our operations to meet our debt service obligations and to make cash distributions to ourunitholders. The operating and financial restrictions and covenants in our credit agreement and any future financing agreements could restrict our ability to financefuture operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make cash distributions to our unitholders.For example, our credit agreement restricts our ability to, among other things:•incur or guarantee certain additional debt;•make certain cash distributions on or redeem or repurchase certain units;•make certain investments and acquisitions;•make certain capital expenditures;•incur certain liens or permit them to exist;•enter into certain types of transactions with affiliates;•merge or consolidate with another company or otherwise engage in a change of control transaction; and•transfer, sell or otherwise dispose of certain assets.Our credit agreement also contains covenants requiring us to maintain certain financial ratios and meet certain financial tests. Our ability to meet thosefinancial ratios and financial tests can be affected by events beyond our control, and we cannot guarantee that we will meet those ratios and tests.The provisions of our credit agreement may affect our ability to obtain future financing and pursue attractive business opportunities as well as affect ourflexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our credit agreement could resultin a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to beimmediately due and payable. If we were unable to repay the accelerated amounts, the lenders under our credit agreement could proceed against the collateralgranted to them to secure such debt. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders couldexperience a partial or total loss of their investment. The credit agreement also has cross default provisions that apply to any other indebtedness we may have, andthe indentures have cross default provisions that apply to certain other indebtedness.We may not be able to raise sufficient capital to grow our business. As of March 1, 2018 , we have aggregate unused credit availability under our credit agreement of approximately $139.9 million , although our ability toborrow such funds may be limited by the financial covenants in our credit agreement, and cash on hand of approximately $1.3 million . Our ability to access thepublic capital markets on terms acceptable to us or at all may be limited due to, among other things, commodity price volatility and deterioration, general economicconditions, rising interest rates, capital market volatility, the uncertainty of our future cash flows, adverse business developments and other contingencies. Inaddition, we may have difficulty obtaining a credit rating or any credit rating that we do obtain may be lower than it otherwise would be due to theseuncertainties. The lack of a credit rating or a low credit rating may also adversely impact our ability to access capital markets on terms acceptable to us or at all,and may increase significantly the costs of financing our growth potential.If we fail to raise additional capital or an event of default occurs under our credit agreement, we may be forced to sell assets or take other action that couldhave a material adverse effect on our business, unit price and results of operations. In addition, if we are unable to access the capital markets for acquisitions orexpansion projects on terms acceptable to us or at all, or if the financing cost related to any such acquisitions or expansion projects increases, it may have amaterial adverse effect on our business, cash flows, ability to make distributions to our unitholders, unit price, results of operations and ability to conduct ourbusiness. If we borrow funds to make any permitted quarterly distributions, our ability to pursue acquisitions and other business opportunities may be limited and ouroperations 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 quarterlydistributions, such amounts will incur interest and must be repaid in accordance with the terms of our credit agreement. In addition, any amounts borrowed forpermitted distributions to our unitholders will reduce the18Table of Contentsfunds available to us for other purposes under our credit agreement, including amounts available for use in connection with acquisitions and other businessopportunities. 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 are indirectly exposed to commodity price volatility. Our operations have minimal direct exposure to changes in liquid asphalt and crude oil prices. However, the volumes of liquid asphalt and crude oil weterminal, gather, market or transport are affected by commodity prices because many of our customers have direct commodity price exposure. Many of ourcustomers have been, and continue to be, adversely affected by significant changes in commodity prices. If our customers continue to be negatively impacted bycommodity price volatility, a sustained period of depressed commodity prices or other adverse conditions of the energy industry, they may, among other things,decrease the amount of services that we provide to them. The prices of liquid asphalt and crude oil are inherently volatile, and we expect this volatility tocontinue. Any significant reduction in the amount of services we provide to our customers would have a material adverse effect on our results of operations andcash flows. Our revenues from third-party customers are generated under contracts that must be renegotiated periodically and that allow the customer to reduce orsuspend performance in some circumstances, which could cause our revenues from those contracts to decline and reduce our ability to make distributions toour unitholders. Some of our contract-based revenues from customers are generated under contracts with terms which allow the customer to reduce or suspend performanceunder 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 whichresults in a material reduction or suspension of our customer’s performance could have a material adverse effect on our financial condition, results of operationsand cash flows. Our contracts with some of our customers have terms of one year or less. As these contracts expire, they must be extended and renegotiated or replaced. Wemay not be able to extend and renegotiate or replace these contracts when they expire, and the terms of any renegotiated contracts may not be as favorable as thecontracts they replace. In particular, our ability to extend or replace contracts could be harmed by numerous competitive factors, such as those described aboveunder “ Item 1. Business - Competition. ” We face intense competition in our terminalling, gathering, pipeline transportation and trucking activities. Competitionfrom other providers of crude oil gathering, pipeline transportation, terminalling and trucking services that are able to supply our customers with those services at alower price could reduce our ability to make distributions to our unitholders. Additionally, we may incur substantial costs if modifications to our terminals arerequired in order to attract substitute customers or provide alternative services. If we cannot successfully renew significant contracts or must renew them on lessfavorable terms, or if we incur substantial costs in modifying our terminals, our revenues from these arrangements could decline, which could have a materialadverse effect on our financial condition, results of operations and cash flows. Certain of our asphalt terminalling services contracts have short terms, and certain leases relating to our asphalt operations may be terminated upon shortnotice. As of March 7, 2018 , we had leases or storage agreements with third-party customers relating to each of our 56 asphalt facilities. Lease or storage agreementsrelated to 16 of these facilities have terms that expire by the end of 2018 . We may not be able to renew or extend our existing contracts or enter into new leases orstorage agreements when such contracts expire on terms acceptable to us or at all. In addition, certain key customers account for a significant portion of ourasphalt terminalling services revenues, the loss of which could result in a significant decrease in revenues from our asphalt operations. A significant decrease inthe revenues we receive from our asphalt operations could result in violations of covenants under our credit agreement and could have a material adverse effect onour business, cash flows, ability to make distributions to our unitholders, the price of our units, our results of operations and ability to conduct our business. In addition, certain of our asphalt facilities are located on land that we lease from third parties. Some of these leases may be terminated by the lessor with asshort as thirty days’ notice. We also have not yet received consent from certain of the lessors to sublease such facilities, which may result in a default under suchlease or invalidate the subleases. If such leases were terminated, it could have a material adverse effect on our ability to provide asphalt terminalling services,which could have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, unit price, results of operations and abilityto conduct our business. In addition, in certain instances we have not entered into new leases with a lessor, although we continue to operate under expired leasesand make payments to the lessor and are in the process of negotiating new leases. If it were determined that we did not have rights under these expired leases, itcould have a material adverse effect on our ability to conduct our asphalt operations and on our financial condition, results of operations and cash flows. 19Table of ContentsWe 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, premiumsand deductibles for certain of our insurance policies may increase substantially in the future. In some instances, certain insurance could become unavailable oravailable 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 adverseeffect on our business, cash flows, ability to make distributions to our unitholders, unit price, results of operations and ability to conduct our business. A significant decrease in demand for liquid asphalt and/or crude oil products in the areas served by our operations could reduce our ability to makedistributions to our unitholders. A sustained decrease in demand for liquid asphalt and/or crude oil products in the areas served by our terminalling facilities and pipelines could significantlyreduce our revenues and, therefore, reduce our ability to make or increase distributions to our unitholders. Factors that could lead to a decrease in market demandfor liquid asphalt and crude oil products include:•lower demand by consumers for refined products, including asphalt products, as a result of (i) recession or other adverse economic conditions; (ii)higher prices caused by an increase in the market price of crude oil; or (iii) higher taxes or other governmental or regulatory actions that increase,directly or indirectly, the cost of gasoline or other refined products; and•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 technologicaladvances by manufacturers, governmental or regulatory actions or otherwise. Certain of our pipeline and field operating costs and expenses are fixed and do not vary with the volumes we gather and transport. These costs and expensesmay not decrease ratably or at all should we experience a reduction in our volumes gathered or transported by our operations. As a result, we may experiencedeclines in our margin and profitability if our volumes decrease. A material decrease in the production of liquid asphalt could materially reduce our ability to make distributions to our unitholders.The throughput at our asphalt facilities depends on the availability of attractively priced liquid asphalt produced from the various liquid asphalt producingrefineries. Liquid asphalt production may decline for a number of reasons, including refiners processing more light, sweet crude oil or refiners installing cokerunits which further refine heavy residual fuel oil bottoms such as liquid asphalt. If our customers are unable to replace volumes lost due to a temporary orpermanent material decrease in production from the suppliers of liquid asphalt, our throughput could decline, reducing our revenue and cash flows and adverselyaffecting our financial condition and results of operations.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 ourunitholders. The throughput on our crude oil pipelines depends on the availability and demand for transportation and storage of crude oil produced from the oil fieldsserved by such pipelines or through connections with pipelines owned by third parties. Crude oil production may decline for a number of reasons, including naturaldeclines 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 fromapplicable governmental authorities. If commodity prices remain depressed for any sustained period of time, production may slow and our customers may decreasethe volumes we transport or store for them. If we are unable to replace volumes lost due to a temporary or permanent material decrease in production from the oilfields served by our crude oil pipelines, our throughput could decline, reducing our revenue and cash flows and adversely affecting our financial condition andresults of operations. In addition, it is difficult to attract producers to a new gathering system if the producer is already connected to an existing system. As aresult, third-party shippers on our pipeline systems may experience difficulty acquiring crude oil at the wellhead in areas where there are existing relationshipsbetween producers and other gatherers and purchasers of crude oil.20Table of ContentsWe face intense competition in our terminalling, gathering and transportation activities. Competition from other providers of crude oil terminalling, gatheringand transportation services that are able to supply our customers with those services at a lower price could reduce our ability to make distributions to ourunitholders. We are subject to competition from other crude oil terminalling, gathering, and transportation operations that may be able to supply our customers with thesame or comparable services on a more competitive basis. We compete with national, regional and local gathering, terminalling and pipeline companies, includingthe major integrated oil companies, of widely varying sizes, financial resources and experience. Some of these competitors are substantially larger than us, havegreater financial resources, and control substantially greater storage capacity than we do. Our ability to compete could be harmed by numerous factors, including:•price competition;•the perception that another company can provide better service; and•the availability of alternative supply points, or supply points located closer to the operations of our customers. If we are unable to compete with services offered by other midstream enterprises, it could have a material adverse effect on our financial condition, results ofoperations and cash flows. Some of our pipeline systems are dependent upon 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 theseinterconnecting pipelines as a result of testing, line repair, reduced operating pressures or other causes could result in reduced throughput on our pipeline systemswhich would adversely affect our revenue, cash flows and results of operations. If we are unable to make acquisitions on economically acceptable terms, our future growth may be limited. Our ability to grow in the future will depend, in part, on our ability to make acquisitions that result in an increase in the cash generated per unit fromoperations. Ergon has indicated that it intends to use us as a growth vehicle to pursue the acquisition and expansion of midstream energy businesses andassets. We cannot say with any certainty whether or not Ergon will develop any projects or, if they do, which, if any, of these future acquisition opportunities maybe made available to us, or if we will choose to pursue any such opportunity. We may also make acquisitions directly from third parties. If we are unable to make accretive acquisitions because we are (i) unable to acquire projects fromsuch a development company when they are available; (ii) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;(iii) unable to obtain financing for these acquisitions on economically acceptable terms; or (iv) outbid by competitors, then our future growth and ability to increasedistributions may be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in adecrease in the cash generated from operations per unit. Any acquisition involves potential risks, including, among other things:•mistaken assumptions about volumes, revenues and costs, including synergies;•an inability to integrate successfully the businesses we acquire;•an inability to hire, train or retain qualified personnel to manage and operate our business and assets;•the assumption of unknown liabilities;•limitations on rights to indemnity from the seller;•mistaken assumptions about the overall costs of equity or debt;•the diversion of management’s and employees’ attention from other business concerns;•unforeseen difficulties operating in new product areas or new geographic areas; and•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 likely will not have theopportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and otherresources. 21Table of ContentsIf we acquire assets that are distinct and separate from our existing terminalling, gathering and transportation operations, it could subject us to additionalbusiness and operating risks. We may acquire assets that have operations in new and distinct lines of business from our liquid asphalt or crude oil operations. Integration of a new businessis a complex, costly and time-consuming process. Failure to timely and successfully integrate acquired entities’ lines of business with our existing operations mayhave a material adverse effect on our business, financial condition, results of operations and cash flows. The difficulties of integrating a new business with ourexisting operations include, among other things:•operating distinct businesses which require different operating strategies and different managerial expertise;•the necessity of coordinating organizations, systems and facilities in different locations;•integrating personnel with diverse business backgrounds and organizational cultures; and•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 unanticipatedliabilities or costs, could harm our existing business, results of operations, financial condition and prospects. Furthermore, new lines of business may subject us toadditional business and operating risks. For example, we may in the future determine to acquire businesses that are subject to direct exposure to fluctuations incommodity prices. These new business and operating risks could have a material adverse effect on our financial condition, results of operations and cash flows. Expanding our business by constructing new assets subjects us to risks that projects may not be completed on schedule and that the costs associated withprojects may exceed our expectations and budgets, 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 becompleted on schedule or at all or within the budgeted cost. Moreover, we may construct facilities to capture anticipated future growth in demand in a market inwhich such growth does not materialize. Our expansion projects may not immediately produce operating cash flows.Expansion projects require us to make significant capital investments over time and we will incur financing costs during the planning and construction phasesof these projects; however, the operating cash flows we expect these projects to generate will not materialize, if at all, until sometime after the projects arecompleted and placed into service. As a result, to the extent we finance our projects with borrowings, our leverage may increase during the period prior to thegeneration of those operating cash flows and, to the extent we finance our projects with equity, our cash available for distribution on a common unit basis maydecrease during the period prior to the generation of those operating cash flows. If we experience unanticipated or extended delays in generating operating cashflows from construction projects, or if such operating cash flows do not materialize as expected, we may need to reduce or reprioritize our capital budget in orderto meet our capital requirements, and our liquidity and capital position could be adversely affected.We may incur significant costs and liabilities as a result of pipeline integrity management program requirements and any necessary pipeline repair orpreventative 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 pipelines that could affect “high consequenceareas” including populated areas, areas that are unusually sensitive to environmental damage and commercially navigable waterways. The regulations requireoperators of covered pipelines to: •perform ongoing assessments of pipeline integrity;•identify and characterize threats to pipeline segments that could impact a high consequence area;•improve data collection, integration and analysis;•repair and remediate the pipeline as necessary; and•implement preventive and mitigating actions. 22Table of ContentsEffective July 2008, the DOT broadened the scope of coverage of its existing pipeline safety standards, including its integrity management programs, toinclude certain rural onshore hazardous liquid and low-stress pipeline systems found near “unusually sensitive areas,” including non-populated areas requiringextra protection because of the presence of sole source drinking water resources, endangered species or other ecological resources. Also, in December 2006, thePipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (“PIPES”) was enacted. PIPES reauthorized and amended the DOT’s pipeline safetyprograms and included a provision eliminating the regulatory exemption for low-stress hazardous liquid pipelines. The Pipeline Safety Act established additionalsafety requirements for newly constructed pipelines and required the DOT to study safety issues that could result in the adoption of additional regulatoryrequirements for existing pipelines. On August 13, 2012, PHMSA published rules to update pipeline safety regulations, including increasing maximum civilpenalties from $0.1 million to $0.2 million per day of violation and from $1.0 million to $2.0 million total for a related series of violations, as well as changingPHMSA’s enforcement process. This maximum penalty authority established by statute has been and will continue to be adjusted periodically to account forinflation. PHMSA also issued an Advisory Bulletin in May 2012 which advised pipeline operators that they must have records to document the maximumoperating pressure for each section of their pipeline and that the records must be traceable, verifiable and complete. Locating such records and, in the absence ofany such records, verifying maximum pressures through physical testing (including hydrostatic testing) or modifying or replacing facilities to meet the demands ofverifiable pressures, could significantly increase an operator’s costs of compliance. On January 23, 2017, PHMSA published a final rule that became effective onMarch 24, 2017. This rule amended the Pipeline Safety Act to include, among other provisions, a specific time frame for notifying PHMSA of accidents andincidents, allowance for PHMSA to recover costs associated with design reviews of new projects, renewal of expiring special permits, processes for requestingprotection of confidential commercial information, changes to the drug and alcohol testing requirements and incorporating consensus standards by reference for in-line inspection and Stress Corrosion Cracking Direct Assessment. Please read “ Item 1. Business-Pipeline 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 complywith these laws and regulations could adversely affect our ability to make distributions to our unitholders. Our operations are subject to stringent federal, state and local laws and regulations relating to the protection of the environment. Various governmentalauthorities, including the EPA, have the power to enforce compliance with these laws and regulations and the permits issued under them. Violators ofenvironmental laws and regulations are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. We may experience delaysin obtaining, or be unable to obtain, required environmental permits, which may delay or interrupt our operations and limit our growth and revenue. Joint andseveral strict liability may be incurred without regard to the legality of the original conduct under CERCLA, RCRA and analogous state laws for the remediation ofcontaminated areas. Private parties also may have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, withenvironmental laws and regulations or for personal injury or property damage. Moreover, new laws, regulations or enforcement policies could be implemented thatsignificantly increase our compliance costs and the costs of any remediation that may become necessary, some of which may be material. We incur environmental costs and liabilities in connection with the handling of hydrocarbons and solid wastes. We currently own, operate or lease propertieswhich for many years have been used for asphalt activities and midstream activities, including properties in and around the Cushing Interchange. Activities by usor by 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 orunder them. Additionally, some sites we own or operate are located near current or former terminal and pipeline operations, and there is a risk that contaminationhas migrated from those sites to ours. Increasingly strict environmental laws, regulations and enforcement policies, as well as claims for damages and other similardevelopments, 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-Environmental, Health, and Safety Risks” for more information. In addition, the workplaces associated with the terminalling facilities and pipelines we operate are subject to OSHA requirements and comparable statestatutes that regulate the protection of the health and safety of workers. The OSHA hazard communication standard requires that we maintain information abouthazardous materials used or produced in our operations and that we provide this information to employees, state and local government authorities and localresidents. Failure to comply with OSHA requirements, including general industry standards, recordkeeping requirements and monitoring of occupational exposureto regulated substances, could subject us to fines or significant compliance costs and have a material adverse effect on our financial condition, results of operationsand cash flows.23Table of ContentsAdoption of legislation and regulatory measures targeting GHG emissions could affect our operations, expose us to significant costs and liabilities, and reducedemand for the products we transport. The crude oil and petroleum-based product business is a direct source of certain GHG emissions, namely carbon dioxide and methane, and future restrictionson such emissions could impact our future operations. Federal legislation requiring GHG controls has been considered in the past but has not been enacted. TheEPA has adopted regulations under existing provisions of the CAA which require PSD pre-construction permits and Title V operating permits for GHG emissionsfrom certain large stationary sources. These EPA rulemakings could affect our operations by effectively reducing demand for motor fuels from crude oil and couldaffect our ability to obtain air permits for new or modified facilities. Furthermore, in 2009, the EPA adopted rules requiring the monitoring and reporting of GHGemissions from specified sources in the United States, including, among others, certain onshore oil and natural gas processing and fractionating facilities.Monitoring obligations began in 2010 and the emissions reporting requirements took effect in 2011. Some of our facilities include natural gas-fired combustionunits which may become subject to this rule. These facilities are required to annually calculate their GHG emissions to determine whether they trigger reportingand monitoring requirements. To date, none of our facilities have exceeded the thresholds established for reporting or monitoring requirements. Although this ruledoes not control GHG emission levels from any of our facilities, it has caused us to incur monitoring and reporting costs relating to GHG emissions. We also note,as previously mentioned, that the EPA finalized rules that took effect in August 2016 to set standards for methane and volatile organic compound emissions fromnew and modified sources in the oil and gas sector, including transmission. However, the EPA is currently engaged in rulemaking to stay the effective date of theserules. We continue to monitor and review these regulations to determine future impacts, including potential reporting requirements. Legislation and regulationsrelating to control or reporting of GHG emissions 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 weconduct business or that have the effect of requiring or encouraging reduced consumption or production of crude oil and petroleum-based products couldpotentially:•adversely affect the demand for our products and services;•affect our operations and ability to obtain air permits for new or modified facilities;•increase the costs to operate and maintain our facilities;•increase the costs of our business by requiring us to acquire allowances to authorize our GHG emissions (e.g., for natural gas-fired combustion units);•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 emissionsprogram; and•increase the costs or availability of goods and services as a result of impacts on entities that provide goods and services to us. In addition to potential impacts on our business directly or indirectly resulting from climate change legislation or regulations, our business also could benegatively affected by climate-related physical changes or changes in weather patterns. A loss of coastline in the vicinity of our facilities or an increase in severeweather patterns could result in damages to or loss of our physical assets, impact our ability to conduct operations and/or result in a disruption of our customers’operations. These kinds of physical changes could also affect entities that provide goods and services to us and indirectly have an adverse effect on our business asa result of increases in costs or availability of goods and services. Changes of this nature could have a material adverse impact on our business. Finally, increasingattention to the risks of climate change has resulted in an increased possibility of lawsuits brought by public and private entities against oil and gas companies inconnection with their greenhouse gas emissions. Should we be targeted by any such litigation, we may incur liability which, to the extent that societal pressures orpolitical or other factors are involved, could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.A portion of our customers’ production is developed from unconventional sources, such as shales, which require hydraulic fracturing as part of the productionprocess. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into shale formations to stimulate crude oil and/or gas production.The practice of hydraulic fracturing has been subject to public scrutiny in recent years and various efforts to regulate, or in some cases prohibit, hydraulicfracturing have been pursued at the local, state and federal levels of government and may be pursued in the future. For example, several states, including states inwhich we operate, have imposed disclosure requirements on hydraulic fracturing, and several local governments have prohibited or severely restricted hydraulicfracturing within their jurisdictions. Restrictions on hydraulic fracturing could adversely affect our operations by reducing the volumes of crude oil that wetransport.24Table of ContentsAdditionally, the ESA restricts activities that may affect endangered or threatened species or their habitats. While some of our operations may be located inareas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designationof previously unlisted endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans or limit futuredevelopment in the affected areas. The MBTA implements various treaties and conventions between the United States and certain other nations for the protectionof migratory birds. Pursuant to the MBTA, the taking, killing or possessing of migratory birds is unlawful without a permit, thereby potentially requiring theimplementation of operating restrictions or a temporary, seasonal or permanent ban in affected areas. We believe that we are in substantial compliance with theMBTA, but noncompliance could result in fines or operational prohibitions which could adversely affect our financial condition, results of operations and cashflows. Please also see “Item 1. Business-Environmental, Health and Safety Risks-Climate.”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 terminalling of crude oil and the terminalling of liquid asphalt cement,including:•explosions, earthquakes, fires and accidents, including road and highway accidents involving our tanker trucks;•extreme weather conditions, such as hurricanes, which are common in the Gulf Coast, and tornadoes and flooding, which are common in the Midwestand other areas of the United States in which we operate;•damage to our terminals, pipelines and equipment;•leaks or releases of crude oil into the environment; and•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 propertyand 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. We do not own all of the land on which our facilities and pipelines are located, which could disrupt our operations. We do not own all of the land on which our asphalt and crude oil facilities and pipelines have been constructed, and we are therefore subject to the possibilityof more onerous terms and/or increased costs to retain necessary land use if rights-of-way or any material real property leases are invalid, lapse or terminate. Weobtain the rights to construct and operate some of our asphalt and crude oil facilities and pipelines on land owned by third parties and governmental agencies for aspecific 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 onour business, results of operations, financial condition, cash flows and ability to make cash distributions to our unitholders. In addition, we are in the process ofobtaining 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, itcould have a material adverse effect on our business, results of operations, financial condition, cash flows and our ability to make cash distributions to ourunitholders.We could experience increased severity or frequency of accidents and other claims.Potential liability associated with accidents in the trucking industry is severe and occurrences are unpredictable. A material increase in the frequency orseverity of accidents or workers’ compensation claims or the unfavorable development of existing claims could materially adversely affect our results ofoperations. In the event that accidents occur, we may be unable to obtain desired contractual indemnities, and our insurance may prove inadequate in certain cases.The occurrence of an event not fully insured or indemnified against or the failure or inability of a customer or insurer to meet its indemnification or insuranceobligations could result in substantial losses.25Table of ContentsChanges in trucking regulations may increase our costs and negatively impact our results of operations.Our trucking services are subject to regulation as a motor carrier by the DOT and by various state agencies, whose regulations include certain permitrequirements of state highway, and safety authorities. These regulatory authorities exercise broad powers over our trucking operations, generally governing suchmatters as the authorization to engage in motor carrier operations, safety, equipment testing and specifications and insurance requirements. There are additionalregulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industryis subject to possible regulatory and legislative changes that may impact our operations and affect the economics of the industry by requiring changes in operatingpractices or by changing the demand for or the costs of providing truckload services. Some of these possible changes include increasingly stringent fuel emissionlimits, changes in the regulations that govern the amount of time a driver may drive or work in any specific period, limits on vehicle weight and size and othermatters, including safety requirements.Terrorist or cyber-attacks and threats, escalation of military activity in response to these attacks or acts of war could have a material adverse effect on ourbusiness, financial condition or results of operations.Terrorist attacks and threats, cyber-attacks, escalation of military activity or acts of war may have significant effects on general economic conditions,fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Terrorist or cyber-attacks, rumors or threats of war, actual conflicts involving the United States or its allies or military or trade disruptions may significantly affect our operations andthose of our customers. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. We do notmaintain specialized insurance for possible exposures resulting from a cyber-attack on our assets that may shut down all or part of our business. Disruption orsignificant increases in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them,could have a material adverse effect on our business, financial condition and results of operations.Risks Inherent in an Investment in UsErgon controls our General Partner, which has sole responsibility for conducting our business and managing our operations. Our General Partner hasconflicts of interest with us and limited fiduciary duties, which may permit it to favor its own interests to the detriment of our unitholders. Ergon owns and controls our General Partner. Some of our General Partner’s directors are directors and officers of Ergon. Therefore, conflicts of interestmay 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 Partnermay favor its own interests and the interests of its affiliates over the interests of our unitholders. Although the conflicts committee of the board of directors of ourGeneral Partner (the “Board”) may review such conflicts of interest, the Board is not required to submit such matters to the conflicts committee. These conflictsinclude, among others, the following situations:•Neither our partnership agreement nor any other agreement requires our General Partner or Ergon to pursue a business strategy that favors us. Suchpersons may make decisions in their best interest, which may be contrary to our interests.•Our General Partner is allowed to take into account the interests of parties other than us and our unitholders, such as Ergon and its affiliates, inresolving conflicts of interest.•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 asasset sales, issuances of securities and borrowings, to pay distributions, which means that we could make distributions that deteriorate our capital baseand that our General Partner could receive distributions on its incentive distribution rights to which it would not otherwise be entitled if we did not havesufficient available cash from operating surplus to make such distributions.•Ergon is a holder of our Preferred Units and may favor its own interests in actions relating to such units, including causing us to make distributions onsuch units even if no distributions are made on the common units.•Ergon may compete with us, including with respect to future acquisition opportunities.•Ergon may favor its own interests in proposing the terms of any acquisitions we make directly from them, and such terms may not be as favorable asthose we could receive from an unrelated third party.•Our General Partner has limited liability and reduced fiduciary duties and our unitholders have restricted remedies available for actions that, without thelimitations, might constitute breaches of fiduciary duty.26Table of Contents•Our General Partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities andreserves, each of which can affect the amount of cash that is distributed to unitholders.•Our General Partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capitalexpenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination canaffect the amount of cash that is distributed to our unitholders.•Our General Partner may make a determination to receive a quantity of our Class B units in exchange for resetting the target distribution levels relatedto its incentive distribution rights without the approval of the conflicts committee of our General Partner or our unitholders.•Our General Partner determines which costs incurred by it and its affiliates are reimbursable by us.•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 intoadditional contractual arrangements with any of these entities on our behalf.•Our General Partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to beindemnified by us.•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.•Our General Partner controls the enforcement of obligations owed to us by our General Partner and its affiliates.•Our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.Our partnership agreement limits the fiduciary duties our General Partner owes to holders of our units and restricts the remedies available to holders of ourunits 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 fiduciaryduty laws. For example, our partnership agreement:•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 entitlesour 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 inexchange for resetting the target distribution levels related to its incentive distribution rights, the exercise of its limited call right, the exercise of itsrights 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 orconsolidation of the partnership or amendment to the partnership agreement;•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 itacted in good faith, meaning it believed the decision was in the best interests of our partnership;•generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the Board acting ingood 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 fromunrelated third parties or must be “fair and reasonable” to us, as determined by our General Partner in good faith. In determining whether a transactionor resolution is “fair and reasonable,” our General Partner may consider the totality of the relationships between the parties involved, including othertransactions that may be particularly advantageous or beneficial to us;•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 anyacts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our GeneralPartner 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 withknowledge that the conduct was criminal; and•provides that in resolving conflicts of interest, it will be presumed that in making its decision, our General Partner acted in good faith, and in anyproceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcomingsuch presumption. By purchasing a common unit, a common unitholder will become bound by the provisions in the partnership agreement, including the provisions discussedabove.27Table of ContentsErgon 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 Ergon prohibits Ergon from owning assets or engaging in businesses that compete directly orindirectly with us. In addition, Ergon may acquire, construct or dispose of assets in the future, without any obligation to offer us the opportunity to purchase orconstruct any of those assets. Ergon is a privately held company engaged in a wide range of operations. Ergon has significantly greater resources and experiencethan we have, which may make it more difficult for us to compete with Ergon with respect to commercial activities as well as for acquisition candidates. As aresult, competition from Ergon could adversely impact our results of operations and cash available for distribution. Cost reimbursements due to our General Partner and its affiliates for services provided, which are determined by our General Partner, may be substantial andwill reduce our cash available for distribution to our unitholders. Pursuant to our partnership agreement, our General Partner is entitled to receive reimbursement for the payment of expenses related to our operations and forthe provision of various general and administrative services for our benefit. Payments for these services may be substantial and reduce the amount of cash availablefor distribution to unitholders. In addition, under Delaware partnership law, our General Partner has unlimited liability for our obligations, such as our debts andenvironmental liabilities, except for our contractual obligations that are expressly made without recourse to our General Partner. To the extent our General Partnerincurs obligations on our behalf, we are obligated under our partnership agreement to reimburse or indemnify our General Partner. If we are unable or unwilling toreimburse or indemnify our General Partner, our General Partner may take actions to cause us to make payments of these obligations and liabilities. Any suchpayments would reduce the amount of cash otherwise available for distribution to our unitholders.Holders of our Preferred Units and 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, limitedability to influence management’s decisions regarding our business. Unitholders did not elect our General Partner or the Board and have no right to elect ourGeneral Partner or the Board on an annual or other continuing basis. The Board is chosen by Ergon. Furthermore, if the unitholders are dissatisfied with theperformance of our General Partner, they have little ability to remove our General Partner. Amendments to our partnership agreement may be proposed only by orwith 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 absenceor reduction of a takeover premium in the trading price.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 ofthe unitholders. Furthermore, our partnership agreement does not restrict the ability of Ergon, the owner of our General Partner, from transferring all or a portion ofits ownership interest in our General Partner to a third party. The new owner of our General Partner would then be in a position to replace the Board and officers ofour General Partner with its own choices and thereby influence the decisions made by the Board and officers. We may issue additional units without approval of our unitholders, which would dilute our unitholders’ ownership interests. Except in the case of the issuance of units that rank equal to or senior to the Preferred Units, our partnership agreement does not limit the number or price ofadditional limited partner interests we may issue at any time without the approval of our unitholders. In addition, because we are a limited partnership, we will notbe subject to the shareholder approval requirements relating to the issuance of securities (other than in connection with the establishment or material amendment ofa stock option or purchase plan or the making or material amendment of any other equity compensation arrangement) contained in Nasdaq Marketplace Rule5635. The issuance by us of additional common units or other equity securities of equal or senior rank may have any or all of the following effects, among others:•Our unitholders’ proportionate ownership interest in us will decrease.•The amount of cash available for distribution on each unit may decrease.•The ratio of taxable income to distributions may increase.•The relative voting strength of each previously outstanding unit may be diminished.•The market price of the common units may decline.28Table of Contents Our partnership agreement restricts the voting rights of unitholders, other than our General Partner and its affiliates, including Ergon, owning 20% or moreof any class of our partnership securities. Unitholders’ voting rights are further restricted by the partnership agreement, which provides that any units held by a person that owns 20% or more of anyclass of units then outstanding, other than our General Partner, its affiliates, their transferees and persons who acquired such units with the prior approval of theBoard, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire informationabout our operations, as well as other provisions.Even if our public unitholders are dissatisfied with our General Partner, it will be difficult for them to remove our General Partner without its consent. It will be difficult for our public unitholders to remove our General Partner without its consent because our General Partner and its affiliates own a substantialnumber of our units. The vote of the holders of at least 66 2 / 3 % of all outstanding units voting together as a single class is required to remove the General Partner.As of March 1, 2018 , Ergon owned approximately 28.3% of our aggregate outstanding Preferred Units and common units.Affiliates of our General Partner may sell units in the public markets, which sales could have an adverse impact on the trading price of the units. As of March 1, 2018 , the executive officers and directors of our General Partner beneficially own an aggregate of 1,037,212 common units and 20,400Preferred Units and Ergon owns 3,049,187 common units and 18,312,968 Preferred Units. The sale of these units in the public markets could have an adverseimpact on the public trading price of the 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 units at an undesirable time or price.If at any time our General Partner and its affiliates own more than 80% of any class of units then outstanding, our General Partner will have the right, but notthe obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of such class of units held by unaffiliated persons at a pricenot less than the then-current market price. As a result, our unitholders may be required to sell their units at an undesirable time or price and may not receive anyreturn on their investment. Our unitholders also may incur a tax liability upon a sale of their units. As of March 1, 2018 , Ergon owned 52.1% of our outstandingPreferred Units. Holders of our Preferred Units have a distribution preference and a liquidation preference, which may adversely impact the value of our common units. The Preferred Units rank prior to our common units as to both distributions of available cash and distributions upon liquidation. Holders of our PreferredUnits are entitled to preferred quarterly distributions of $0.17875 per unit per quarter (or $0.7150 per unit on an annual basis). If we fail to pay in full anydistribution on our Preferred Units, the amount of such unpaid distribution will accrue and accumulate from the last day of the quarter for which such distributionis due until paid in full. If we are liquidated, we may not have sufficient funds remaining after payment of amounts to our creditors and to holders of our PreferredUnits to make any distribution to holders of our common units.The conversion rate applicable to the Preferred Units will not be adjusted for all events that may be dilutive. The number of our common units issuable upon conversion of the Preferred Units is subject to adjustment only for subdivisions, splits or certain combinationsof our common units. The number of common units issuable upon conversion is not subject to adjustment for other events, such as employee option grants,offerings of our common units for cash or in connection with acquisitions or other transactions that may increase the number of outstanding common units anddilute the ownership of existing common unitholders. The terms of the Preferred Units do not restrict our ability to offer common units in the future or to engage inother transactions that could dilute our common units.29Table of ContentsWe have rights to require our preferred unitholders to convert their Preferred Units into common units, and we may exercise this mandatory conversion rightat an undesirable time.We have the right in certain circumstances to force the conversion of all outstanding Preferred Units to common units. These circumstances include asituation in which if the holders of a certain number of Preferred Units elect to convert the Preferred Units that they hold to common units, we could then force allremaining outstanding Preferred Units to convert to common units. Ergon, the owner of our General Partner, owns enough Preferred Units such that if they wereall converted to common units, we would be able to exercise this mandatory conversion right. In addition, we also have the right, effective October 25, 2015, toforce the conversion of the outstanding Preferred Units at any time if (i) the daily volume-weighted average trading price of our common units is greater than $8.45for 20 out of the trailing 30 trading days ending two trading days before we furnish notice of conversion and (ii) the average trading volume of our common unitshas exceeded 20,000 common units for 20 out of the trailing 30 trading days ending two trading days before we furnish notice of conversion. In addition, theconversion provisions may be modified with the consent of a majority of the outstanding Preferred Units. As of March 1, 2018, Ergon owned 52.1% of ouroutstanding Preferred Units and has the ability to consent to amendments to such conversion provisions. As a result, our preferred unitholders may be required toconvert their Preferred Units at an undesirable time and may not receive their expected return on investment.Ergon, as the holder of a majority of the outstanding Preferred Units, has the ability to consent to the amendments to the provisions of the Preferred Units.The Preferred Units have voting rights that are identical to the voting rights of common units and vote with the common units as a single class, so thateach Preferred Unit is entitled to one vote for each common unit into which such Preferred Unit is convertible on each matter with respect to which each commonunit is entitled to vote. In addition, the approval of a majority of the Preferred Units, voting separately as a class, is necessary on any matter that adversely affectsany of the rights of the Preferred Units or amends or modifies the terms of the Preferred Units in any material respect or affects the holders of the Preferred Unitsdisproportionately in relation to the holders of common units, including, without limitation, any action that would (i) reduce the distribution amount to thePreferred Units or change the time or form of payment of distributions, (ii) reduce the amount payable to the Preferred Units upon the liquidation of ourpartnership, (iii) modify the conditions relating to the conversion of the Preferred Units or (iv) issue any equity security that, with respect to distributions or rightsupon liquidation, ranks equal to or senior to the Preferred Units or issue any additional Preferred Units. As of March 1, 2018, Ergon owned 52.1% of ouroutstanding Preferred Units and has the ability to consent to amendments to the terms of the Preferred Units without the consent of other unitholders.Holders of the Preferred Units will not have rights to distributions as holders of common units until they acquire our common units. Until our preferred unitholders acquire common units upon conversion of the Preferred Units, such preferred unitholders will have no rights with respect todistributions on our common units. Upon conversion, our preferred unitholders will be entitled to exercise the rights of a holder of our common units only as tomatters for which the record date occurs after the date on which such Preferred Units were converted to our common units.The Preferred Units are limited partner interests in our partnership and therefore are subordinate to any indebtedness. The Preferred Units are limited partner interests in our partnership and do not constitute indebtedness. As such, the Preferred Units will rank junior to allindebtedness and other non-equity claims on our partnership with respect to assets available to satisfy claims on our partnership, including in a liquidation of ourpartnership. Units held by persons who are not Eligible Holders will be subject to the possibility of redemption. Our General Partner has the right under our partnership agreement to institute procedures, by giving notice to each of our unitholders, that would requiretransferees of units and, upon the request of our General Partner, existing holders of our units to certify that they are Eligible Holders. The purpose of thesecertification procedures would be to enable us to establish a federal income tax expense as a component of the pipeline’s cost of service for ratemaking purposesunder current FERC policy applicable to entities that pass through their taxable income to their owners. Eligible Holders are individuals or entities subject to U.S.federal income taxation on the income generated by us or entities not subject to U.S. federal income taxation on the income generated by us, so long as all of theentity’s owners are subject to such taxation. If these tax certification procedures are implemented, we will have the right to redeem the units held by persons whoare not Eligible Holders at the lesser of the30Table of Contentsholder’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, asdetermined by our General Partner.Market interest rates may affect the value of our units.One of the factors that will influence the price of our units will be the distribution yield on our units relative to market interest rates. An increase in marketinterest rates could cause the market price of the units to go down. The trading price of the units will also depend on many other factors, which may change fromtime to time, including:•the market for similar securities;•government action or regulation;•general economic conditions or conditions in the financial markets; and•our financial condition, performance and prospects. 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 thepartnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a numberof 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 insome 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:•a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnershipstatute; or•a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement orto 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 theDelaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed thefair 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 thedistribution 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 atthe time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners onaccount of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution ispermitted.I f we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. In addition,potential changes in accounting standards might cause us to revise our financial results and disclosure in the future.Effective internal controls are necessary for us to provide timely and reliable financial reports and effectively prevent fraud. If we cannot provide timely andreliable financial reports or prevent fraud, our reputation and operating results would be harmed. We continue to enhance our internal controls and financialreporting capabilities. These enhancements require a significant commitment of resources, personnel and the development and maintenance of formalized internalreporting procedures to ensure the reliability of our financial reporting. Our efforts to update and maintain our internal controls may not be successful, and we maybe unable to maintain adequate controls over our financial processes and reporting now or in the future, including future compliance with the obligations underSection 404 of the Sarbanes-Oxley Act of 2002. As further described below in “Internal Control Over Financial Reporting,” as of December 31, 2017, we haveidentified a material weakness in our internal control over financial reporting. Any failure to maintain effective controls or difficulties encountered in the effectiveimprovement of our internal controls could prevent us from timely and reliably reporting our financial results31Table of Contentsand may harm our operating results. Ineffective internal controls could also cause investors to lose confidence in our reported financial information. In addition, theFinancial Accounting Standards Board or the SEC could enact new accounting standards that might impact how we are required to record revenues, expenses,assets and liabilities. Any significant change in accounting standards or disclosure requirements could have a material effect on our business, results of operations,financial condition and ability to comply with our debt obligations. Tax Risks to UnitholdersRecently enacted tax legislation as well as future tax legislation may adversely affect our business, financial condition, results of operations and cash flows.On December 22, 2017, the President signed into law the 2017 budget reconciliation act commonly referred to as the Tax Cuts and Jobs Act (the “TCJA”),which makes significant changes to U.S. federal income tax laws. Among other changes, the TCJA (i) introduces a new deduction on certain pass-through income,(ii) repeals the partnership technical termination rule, (iii) imposes a new limitation on the deductibility of interest expense, (iv) reduces the corporate tax rate to21% and (v) limits the amount of net operating losses that are available to offset the taxable income of our corporate subsidiaries. The TCJA is complex and far-reaching and could have an adverse effect on our business, financial condition, results of operations and cash flows.Our common unitholders have been and will be required to pay taxes on their share of our taxable income even if they have not received or do not receive anycash distributions from us. Because our unitholders are treated as partners to whom we allocate taxable income which could be different in amount than the cash we distribute, ourcommon unitholders 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 ifour common unitholders receive no cash distributions from us. Our common unitholders may not receive cash distributions from us equal to their share of ourtaxable income or even equal to the actual tax liability that results from that income. Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as us not being subject to a material amount of entity-leveltaxation 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 statetax 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 taxpurposes. 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 thetransportation, marketing (other than to end users) or processing of crude oil, natural gas or products thereof, interest, dividends or similar sources, that partnershipwill be taxable as a corporation under Section 7704 of the Internal Revenue Code for federal income tax purposes for that taxable year and all subsequentyears. We have not requested and do not plan to request a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. If we were treated as a corporation for federal income tax purposes, then we would pay federal income tax on our taxable income at the corporate tax rate,which is currently a maximum of 21% , and would likely pay additional state income tax at varying rates. Distributions would generally be taxed again tounitholders as corporate distributions and none of our income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would beimposed upon us as a corporation, cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporationwould result in a material reduction in the anticipated cash flows and after-tax return to unitholders and thus would likely result in a substantial reduction in thevalue of our units. In addition, changes to the audit procedures for large partnerships and in certain circumstances for tax years beginning after 2017 would permit the IRS toassess and collect taxes (including any applicable penalties and interest) resulting from partnership-level federal income tax audits directly from us in the year inwhich the audit is completed. If we are required to make payments of taxes, penalties and interest resulting from audit adjustments, our cash available fordistribution to our unitholders might be substantially reduced. Moreover, changes in current state law may subject us to entity-level taxation by individual states.Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through theimposition of state income, franchise and other forms of taxation. For example, we are required to pay annually a Texas franchise tax on our total revenue, asadjusted and apportioned to the state under the applicable Texas rules and regulations, at a maximum effective tax rate of 0.525%. Imposition of such a tax on usby Texas and, if applicable, by any other state will reduce the cash available for distribution to our unitholders.32Table of ContentsOur partnership agreement provides that if a law is enacted or an existing law is modified or interpreted in a manner that subjects us to taxation as acorporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and thetarget distribution amounts will be adjusted to reflect the impact of that law on us. No such adjustments have been made to date, but there can be no assurance thatno such adjustments will be made in the future. The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrativechanges 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 byadministrative, legislative or judicial interpretation at any time. Any modification to the federal income tax laws and interpretations thereof may or may not beapplied retroactively. Moreover, any such modification could make it more difficult or impossible for us to meet the exception which allows publicly tradedpartnerships that generate qualifying income to be treated as partnerships (rather than corporations) for U.S. federal income tax purposes, affect or cause us tochange our business activities or affect the tax consequences of an investment in our common units. For example, members of Congress have consideredsubstantive changes to existing federal income tax laws that would affect the tax treatment of certain publicly traded partnerships. We are unable to predictwhether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our 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 suchcontest 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 or from the positions we take. It may be necessary to resort to administrative or courtproceedings 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 thepositions we take. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, the costs ofany 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. There are limits on the deductibility of losses that may adversely affect unitholders.In the case of taxpayers subject to the passive activity loss rules (generally individuals, closely-held corporations and regulated investment companies), anylosses generated by us will only be available to offset our future income and cannot be used to offset income from other activities, including other passive activitiesor investments. Unused losses may be deducted when the unitholder disposes of the unitholder’s entire investment in us in a fully taxable transaction with anunrelated party. A unitholder’s share of our net passive income may be offset by unused losses from us carried over from prior years, but not by losses from otherpassive activities, including losses from other publicly traded partnerships.Further, in addition to the other limitations described above, non-corporate taxpayers may only deduct business losses up to the gross income or gainattributable to such trade or business plus $250,000 ($500,000 for unitholders filing jointly). Amounts that may not be deducted in a taxable year may be carriedforward into the following taxable year. This limitation shall be applied after the passive loss limitations and, unless amended, applies only to taxable yearsbeginning prior to December 31, 2025.Our ability to deduct business interest is limited under the TCJA and is expected to increase our taxable income allocable to our unitholders.Our ability to deduct interest on indebtedness properly allocable to our trade or business (which excludes investment interest) will be limited to an amountequal to the sum of (i) our business interest income during the taxable year and (ii) 30% of our adjusted taxable income for such taxable year. Disallowed interestdeductions will be allocated to our unitholders and will be available to offset our future excess taxable income allocated to such unitholders. A unitholder’s taxbasis in our interests will be reduced by the amount of disallowed interest deductions allocated to such unitholder, even if such amounts do not give rise to adeduction to the unitholder in that taxable year. Such unitholder’s tax basis in its partnership interests will be subsequently increased immediately prior to anydisposition by such unitholder of its interest in us in an amount equal to the difference between the prior basis reduction and the amount of the disallowed interestthat has subsequently been used to offset excess taxable income of the unitholder.33Table of ContentsThe limitation on the deductibility of business interest expense described above also applies to our corporate subsidiaries; however, disallowed interestdeductions will be carried forward by our corporate subsidiaries and treated as business interest paid or accrued in the succeeding taxable year. The deductibility ofsuch business interest expense carried forward from a prior taxable year will be subject to the limitation described above. Tax gain or loss on the disposition of our common units could be more or less than expected. If our unitholders sell their units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those units.Because distributions to a unitholder that exceed the total net taxable income allocated to the unitholder decrease the unitholder’s tax basis in his or her units, anysuch prior excess distribution will, in effect, become taxable income to the unitholder if the common units are sold by the unitholder at a price greater than their taxbasis, even if the price the unitholder receives is less than the original cost. Furthermore, a substantial portion of the amount realized, whether or not representinggain, may be taxed as ordinary income to the selling unitholder due to potential recapture items, including depreciation recapture. In addition, because the amountrealized includes a unitholder’s share of our non-recourse liabilities, a unitholder who sells common units may incur a tax liability in excess of the amount of cashreceived from the sale. If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicablepenalties and interest) directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.If the IRS makes audit adjustments to income tax returns for tax years beginning after 2017, it may assess and collect taxes (including any applicable penaltiesand interest) directly from us in the year in which the audit is completed. If we are required to make payments of taxes, penalties and interest resulting from auditadjustments, our cash available for distribution to our unitholders might be substantially reduced. In addition, because payment would be due for the taxable year inwhich the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the auditedtaxable year.Tax-exempt entities and non-United States persons face unique tax issues from owning units that may result in adverse tax consequences to them. Investment in our units by tax-exempt entities, such as individual retirement accounts (known as IRAs), pension plans and non-U.S. persons raises issuesunique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts andother retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholdingtaxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of ourtaxable income. If a potential unitholder is a tax-exempt entity or a non-U.S. person, it should consult its tax advisor before investing in our units.Pursuant to the TCJA, if a non-U.S. unitholder sells or otherwise disposes of a common unit, the transferee is required to withhold 10% of the amount realizedby the non-U.S. transferor, and we are required to deduct and withhold from distributions to the transferee amounts that should have been withheld by thetransferee but were not withheld. However, the U.S. Department of the Treasury and the IRS have determined that this withholding requirement should not applyto any disposition of a publicly traded interest in a publicly traded partnership (such as us) until regulations or other guidance have been issued clarifying theapplication of this withholding requirement to dispositions of interests in publicly traded partnerships. Accordingly, while this new withholding requirement doesnot currently apply to interests in us, there can be no assurance that such requirement will not apply in the future.We will treat each purchaser of our common units as having the same tax benefits without regard to the specific common units purchased. The IRS maychallenge 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 positionsthat may not conform with all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of taxbenefits 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 anegative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns.34Table of ContentsOur unitholders likely will be subject to state and local taxes and return filing or withholding requirements in states in which they do not live as a result ofinvesting in our 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 taxesand estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property. Our unitholders may berequired to file state and local income tax returns and pay state and local income taxes in certain of these various jurisdictions. Further, our unitholders may besubject to penalties for failure to comply with those requirements. We currently own property and conduct business in several states, most of which currentlyimpose income taxes on corporations, and many of which impose income taxes on other entities and nonresident individuals. We may own property or conductbusiness in other states or foreign countries in the future. It is each unitholder’s responsibility to file all federal, state, local and foreign tax returns. Under the taxlaws of some states where we conduct business, we may be required to withhold a percentage from amounts to be distributed to a unitholder who is not a residentof that state. For example, in the case of Oklahoma, we are required to either obtain a withholding exemption affidavit from and generally report detailed taxinformation about our non-Oklahoma resident unitholders or withhold an amount equal to 5% of the portion of our distributions to unitholders which is deemed tobe the Oklahoma share of our income.We hold certain assets located at certain of our liquid asphalt facilities in a subsidiary taxed as a corporation. Such subsidiary is subject to entity-level federaland 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 ourunitholders could be substantially reduced. We hold certain of our liquid asphalt processing assets and related fee income through BKEP Asphalt, L.L.C., a subsidiary taxed as a corporation. Suchsubsidiary is required to pay federal income tax on its income at the corporate tax rate, which is currently a maximum of 21%, and will likely pay state (andpossibly local) income tax at varying rates. Distributions from such subsidiary will generally be taxed again to unitholders as corporate distributions and none ofthe income, gains, losses, deductions or credits of such subsidiary will flow through to our unitholders. Currently, the maximum federal income tax rate applicableto dividend income from such subsidiary which is allocable to individuals is 20% plus an unearned Medicare tax of 3.8%. An individual unitholder’s share ofdividend and interest income from such subsidiary would constitute portfolio income which could not be offset by the unitholder’s share of our other losses ordeductions. If a material amount of entity-level taxes is incurred by such subsidiary, then our cash available for distribution to our unitholders could besubstantially reduced.We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership ofour common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge thistreatment, which could change the allocation of items of income, gain, loss and deduction among our common unitholders. We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership ofour common 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 bepermitted under existing Treasury regulations. The U.S. Department of the Treasury and the IRS issued final Treasury regulations pursuant to which a publiclytraded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax itemsmust be prorated on a daily basis. However, these Treasury regulations do not specifically authorize the use of the proration method we have adopted. If the IRSwere to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among ourunitholders. A unitholder whose units are loaned to a “short seller” to effect a short sale of units may be considered as having disposed of those units. If so, such unitholderwould 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 thedisposition. Because a unitholder whose units are loaned to a “short seller” to effect a short sale of units may be considered as having disposed of the loaned units, suchunitholder 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 mayrecognize 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 tothose 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 ordinaryincome. 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 consult a tax advisorto discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.35Table of ContentsUnitholders converting Preferred Units into common units could under certain limited circumstances receive a gross income allocation that may materiallyincrease the taxable income allocated to such unitholders.Under our partnership agreement and in accordance with Treasury regulations, immediately after the conversion of a Preferred Unit, we will adjust the capitalaccounts of all of our partners to reflect any positive difference (“Unrealized Gain”) or negative difference (“Unrealized Loss”) between the fair market value andthe carrying value of our assets at such time as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such asset for an amountequal to its fair market value at the time of such conversion. Such Unrealized Gain or Unrealized Loss (or items thereof) will be allocated first to the convertingpreferred unitholder in respect to common units received upon the conversion until the capital account of each such common unit is equal to the per unit capitalaccount for each existing common unit. This allocation of Unrealized Gain or Unrealized Loss will not be taxable to the converting preferred unitholder or to anyother unitholders. If the Unrealized Gain or Unrealized Loss allocated as a result of the conversion of a Preferred Unit is not sufficient to cause the capital accountof each common unit received upon such conversion to equal the per unit capital account for each existing common unit, then capital account balances will bereallocated among the unitholders as needed to produce this result. In the event that such a reallocation is needed, a converting preferred unitholder would beallocated taxable gross income in an amount equal to the amount of any such reallocation to it.The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrativechanges 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 byadministrative, legislative or judicial interpretation at any time. For example, from time to time, the President and members of Congress propose and considersubstantive changes to the existing federal income tax laws that affect publicly traded partnerships, including elimination of partnership tax treatment for publiclytraded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it moredifficult or impossible for us to meet the requirements that must be satisfied in order for us to be treated as a partnership for federal income tax purposes.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 ofan investment in our common units. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner whichsubjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, the minimum quarterly distribution and thetarget distribution levels will be adjusted to reflect the impact of that law on us.On January 24, 2017, the U.S. Department of the Treasury and the IRS published final regulations (the “Final Regulations”) regarding qualifying incomeunder Section 7704(d)(1)(E) of the Code. The Final Regulations provide guidance on the activities that generate qualifying income. In addition, under specialtransition rules, publicly traded partnerships are permitted to treat income from certain activities that the partnership engaged in prior to May 6, 2015, and thatwould not otherwise be considered to generate qualifying income under the Final Regulations, as qualifying income for 10 years. Under the Final Regulations,income we realize from the blending and storage of asphalt emulsions and certain types of polymer modified asphalt products, which we have historically treatedas generating qualifying income, might be considered to no longer constitute qualifying income. Moreover, we may not be able to apply the special transition ruleswith respect to a portion of such income. In such cases, we may determine to transfer part of the assets that are used to generate such income, as well as the incomeitself, to a subsidiary taxed as a corporation. Any such subsidiary would be subject to entity-level federal and state income taxes on its net taxable income and, if amaterial amount of entity-level taxes were incurred, then our cash available for distribution to our unitholders could be substantially reduced.36Table of ContentsWe may adopt certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss ordeduction between our General Partner and our common unitholders. The IRS may challenge this treatment, which could adversely affect the value of ouroutstanding units.When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gainor loss attributable to our assets to the capital accounts of our common unitholders and our General Partner. Our methodology may be viewed as understating thevalue of our assets. In that case, there may be a shift of income, gain, loss or deduction between certain common unitholders and our General Partner, which maybe unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of units may have a greater portion of their Internal RevenueCode Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuationmethods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss ordeduction between our General Partner and certain of our common unitholders.A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our commonunitholders. It also could affect the amount of taxable gain from our unitholders’ sale of units and could have a negative impact on the value of the units or resultin audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.Compliance with and changes in tax law could adversely affect our performance.We are subject to extensive tax laws and regulations, including federal and state income taxes and transactional taxes such as excise, sales/use, payroll,franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result inincreased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additionaltaxes as well as interest and penalties.Item 1B. Unresolved Staff Comments. None.Item 2. Properties.A description of our properties is contained in “Item 1-Business.”Title to Properties 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 ourasphalt assets required the consent of the counterparty to such lease. In certain instances, we have not entered into new leases with a lessor although we continue touse such leases and make payments to the lessor and are in the process of negotiating new leases. 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 which have not been subordinated to the right-of-way grants. We have also obtained, where necessary,easement agreements, licenses or permits 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 the event of a challenge to our pipeline location, we generally have theright of eminent domain or other recourse to retain the pipeline in place. In some cases, property on which our pipelines were built was purchased in fee. Our crudeoil terminals are on real property owned or leased by us. Other than as described above, we believe that we have satisfactory title to or rights in all of our assets. Although title or rights to such properties is subject toencumbrances in certain cases, such as customary interests generally retained in connection with acquisition of real property, liens related to environmentalliabilities associated with historical operations, liens for current taxes and other burdens and minor easements, restrictions and other encumbrances to which theunderlying 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 usein the operation of our business.37Table of ContentsItem 3. Legal Proceedings.The information required by this item is included under the caption “Commitments and Contingencies” in Note 17 to our consolidated financial statements andis incorporated herein by reference thereto.Item 4. Mine Safety Disclosures.Not applicable.PART II. OTHER INFORMATION Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.Our common units are traded on the Nasdaq Global Market under the symbol “BKEP” and our Preferred Units are traded on the Nasdaq Global Market underthe symbol “BKEPP”. On March 1, 2018 , there were 40,310,272 common units outstanding, held by approximately 904 unitholders of record and 35,125,202 Preferred Unitsoutstanding held by approximately 3 unitholders of record. The actual number of unitholders is greater than the number of holders of record. Ergon holds 7.6% ofthe common units and 52.1% of the Preferred Units.The following table shows the high and low sales prices per common unit and Preferred Unit, as reported by Nasdaq, as well as distributions declared byquarter during the periods indicated. Common UnitsLow High CashDistributionper Unit2016: First Quarter$3.81 $5.77 $0.1450Second Quarter4.56 5.61 0.1450Third Quarter5.07 6.50 0.1450Fourth Quarter5.72 7.00 0.1450 2017: First Quarter$6.55 $7.55 $0.1450Second Quarter6.17 7.35 0.1450Third Quarter5.30 6.45 0.1450Fourth Quarter4.65 5.95 0.1450 Preferred Units 2016: First Quarter$5.71 $7.13 $0.17875Second Quarter4.56 5.61 0.17875Third Quarter6.84 8.75 0.17875Fourth Quarter7.60 8.39 0.17875 2017: First Quarter$7.62 $8.20 $0.17875Second Quarter7.71 8.52 0.17875Third Quarter7.28 8.05 0.17875Fourth Quarter7.35 7.98 0.1787538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 partnershipagreement) 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 capitalborrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under a credit facility, commercialpaper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and withthe intent of the borrower to repay such borrowings within 12 months.Pursuant to our credit agreement, we are permitted to make quarterly distributions of available cash to unitholders so long as no default exists under the creditagreement on a pro forma basis after giving effect to such distribution. Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter in the following manner:•first, 98.4% to the holders of Preferred Units, pro rata, and 1.6% to our General Partner, until we distribute for each outstanding Preferred Unit anamount equal to the Series A Quarterly Distribution Amount (as defined in the partnership agreement) for that quarter;•second, 98.4% to the holders of Preferred Units, pro rata, and 1.6% to our General Partner, until we distribute for each outstanding Preferred Unit anamount equal to any arrearages in the payment of the Series A Quarterly Distribution Amount for any prior quarters;•third, 98.4% to all common unitholders and Class B unitholders (if any), pro rata, and 1.6% to our General Partner, until we distribute for eachoutstanding common and Class B unit an amount equal to the minimum quarterly distribution of $0.11 per unit for that quarter; and•thereafter, in the manner described in “-General Partner Interest and Incentive Distribution Rights” below. The preceding discussion is based on the assumptions that our General Partner maintains its 1.6% general partner interest and that we do not issue additionalclasses of equity securities. General Partner Interest and Incentive Distribution Rights The following discussion assumes that our General Partner maintains its approximate 1.6% general partner’s interest and continues to own the incentivedistribution rights.Our partnership agreement provides that our General Partner will be entitled to approximately 1.6% of all distributions that we make prior to our liquidation.Our General Partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its approximate 1.6% general partnerinterest if we issue additional units. Our General Partner’s approximate 1.6% interest, and the percentage of our cash distributions to which it is entitled, will beproportionately reduced if we issue additional units in the future (other than the issuance of partnership securities issued in connection with a reset of the incentivedistribution target levels relating to our General Partner’s incentive distribution rights or the issuance of partnership securities upon conversion of outstandingpartnership securities) and our General Partner does not contribute a proportionate amount of capital to us in order to maintain its then current general partnerinterest. Our General Partner will be entitled to make a capital contribution in order to maintain its then current general partner interest. Incentive distribution rights represent the right to receive an increasing percentage (13.0%, 23.0% and 48.0%) of quarterly distributions of available cash fromoperating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our General Partner currently holds the incentivedistribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement. 39If for any quarter:•we have distributed available cash from operating surplus to the holders of our Preferred Units in an amount equal to the Series A QuarterlyDistribution Amount;•we have distributed available cash from operating surplus to the holders of our Preferred Units in an amount necessary to eliminate any cumulativearrearages in the payment of the Series A Quarterly Distribution Amount; and•we have distributed available cash from operating surplus to the common unitholders and Class B unitholders in an amount equal to the minimumquarterly distribution; then our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the unitholders and ourGeneral Partner in the following manner:•first, 98.4% to all unitholders holding common units or Class B units, pro rata, and 1.6% to our General Partner, until each unitholder receives a total of$0.1265 per unit for that quarter (the “first target distribution”);•second, 85.4% to all unitholders holding common units or Class B units, pro rata, and 14.6% to our General Partner, until each unitholder receives atotal of $0.1375 per unit for that quarter (the “second target distribution”);•third, 75.4% to all unitholders holding common units or Class B units, pro rata, and 24.6% to our General Partner, until each unitholder receives a totalof $0.1825 per unit for that quarter (the “third target distribution”); and•thereafter, 50.4% to all unitholders holding common units or Class B units, pro rata, and 49.6% to our General Partner.For equity compensation plan information, see “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related StockholderMatters-Securities Authorized for Issuance under Equity Compensation Plans.”Unregistered Sales of Securities None.Item 6. Selected Financial Data. The following table shows selected historical financial and operating data of Blueknight Energy Partners, L.P. for the annual periods and as of the datespresented. 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, thehistorical financial statements and the accompanying notes thereto, including those 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.” 40Table of Contents 2013 2014 2015 2016 2017Statements of Operations Data:(in thousands, except for per unit data)Service revenue: Third-party revenue$142,916 $139,426 $137,415 $126,215 $113,772Related-party revenue (1)51,755 42,788 39,103 30,211 56,688Product sales revenue: Third-party revenue— 4,412 3,511 20,968 11,479Total revenue194,671 186,626 180,029 177,394 181,939Costs and expenses: Operating expense133,610 134,184 127,974 111,091 123,805Cost of product sales— 61 3,231 14,130 8,807General and administrative expense17,482 17,498 18,976 20,029 17,112Asset impairment expense524 — 21,996 25,761 2,400Total costs and expenses151,616 151,743 172,177 171,011 152,124Gain (loss) on sale of assets1,073 2,464 6,137 108 (975)Operating income44,128 37,347 13,989 6,491 28,840Other income (expense): Equity earnings (loss) in unconsolidated entity(502) 883 3,932 1,483 61Gain on sale of unconsolidated affiliate— — — — 5,337Interest expense(11,615) (12,268) (11,202) (12,554) (14,027)Unrealized gain on investments— 2,079 — — —Income (loss) before income taxes32,011 28,041 6,719 (4,580) 20,211Provision for income taxes593 469 323 260 166Net income (loss) from continuing operations31,418 27,572 6,396 (4,840) 20,045Loss from discontinued operations(3,383) — — — —Net income (loss)$28,035 $27,572 $6,396 $(4,840) $20,045Allocation of net income (loss) for purpose of calculating earningsper unit: General partner interest in net income$647 $641 $554 $433 $944Preferred interest in net income$21,564 $21,563 $21,564 $25,824 $25,115Net income (loss) available to limited partners$5,824 $5,368 $(15,722) $(31,097) $(6,014) Basic and diluted net income (loss) per common unit$0.25 $0.20 $(0.47) $(0.87) $(0.15) Cash distributions per unit to limited partners (2) : Paid$0.48 $0.52 $0.56 $0.58 $0.58Declared$0.49 $0.53 $0.57 $0.58 $0.58Cash distributions per unit to preferred partners: Paid$0.72 $0.72 $0.72 $0.72 $0.72Declared$0.72 $0.72 $0.72 $0.72 $0.72 Balance Sheet Data (at period end): Property, plant and equipment, net$297,400 $310,163 $312,934 $307,334 $296,069Total assets$354,748 $364,395 $364,746 $375,663 $340,869Long-term debt and other long-term liabilities$275,707 $219,736 $247,548 $329,546 $312,542Total partners’ capital$55,458 $119,956 $87,219 $25,576 $4,684________________(1)For the years ended December 31, 2013, 2014, 2015, 2016 and 2017, we recognized revenues of $51.2 million, $41.8 million, $37.8 million, $23.2 million and $21.5 million, respectively,for services provided to Vitol. Of these amounts, $5.3 million and $21.5 million are classified as third-party revenues for the years ended December 31, 2016 and 2017, respectively, whileall other amounts are classified as related-party revenues. For the years ended December 31, 2013, 2014, 2015, 2016 and 2017, we recognized revenues of $15.5 million, $15.3 million,$15.5 million, $22.2 million and $56.4 million, respectively, for services provided to Ergon. In the years ended December 31, 2016 and 2017, $10.9 million and $56.4 million, respectively,in revenue for services provided to Ergon subsequent to the Ergon Change of Control (as previously defined) are classified as related-party revenue, while all other amounts are classifiedas third-party revenues.41Table of Contents(2)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 distributionsdeclared per unit for the quarters within the period stated. Declared distributions were paid within 45 days following the close of each quarter.Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. Overview We are a publicly traded master limited partnership with operations in 27 states. We provide integrated terminalling, gathering and transportation services forcompanies engaged in the production, distribution and marketing of liquid asphalt and crude oil. We manage our operations through four operating segments:(i) asphalt terminalling services, (ii) crude oil terminalling services, (iii) crude oil pipeline services and (iv) crude oil trucking and producer field services. Potential Impact of Crude Oil Market Price Changes and Other Factors on Future RevenuesSince June of 2014, the market price of West Texas Intermediate crude oil has fluctuated significantly from a peak of approximately $108 per barrel to a lowof approximately $30 per barrel (as of March 1, 2018 , the price per barrel was approximately $ 63 ). Furthermore, during the fourth quarter of 2014, the WestTexas Intermediate crude oil forward price curve changed from a backwardated curve (in which the current crude oil price per barrel is higher than the future priceper barrel and a premium is placed on delivering product to market and selling as soon as possible) to a contango curve (in which future prices are higher thancurrent prices and a premium is placed on storing product and selling at a later time). As of December 31, 2017, the forward price curve is slightly backwardated.In addition to changes in the price of crude oil and changes in the forward pricing curve, there has been significant volatility in the overall energy industry andspecifically in publicly traded midstream energy partnerships. As a result there are a number of trends that may impact our partnership in the near term. Theseinclude the overall market price for crude oil and whether or not the forward price curve is in contango or backwardated, changes in production and the demand fortransportation capacity in the areas in which we serve, and overall changes in our cost of capital. We expect this volatility to have near-term impacts as discussedbelow.Asphalt Terminalling Services - Although there is no direct correlation between the price of crude oil and the price of asphalt, the asphalt industry tends tobenefit from a lower crude oil price environment, strong economy and an increase in infrastructure spend. As a result, we do not expect the changes in the price ofcrude oil to significantly impact our asphalt terminalling services operating segment.Crude Oil Terminalling Services - A contango crude oil curve tends to favor the crude oil storage business as crude oil marketers are incentivized to storecrude oil during the current month and sell into a future month. As a result of the decrease in the crude oil price and change in the crude oil futures pricing curve,our weighted average storage rates increased from September 2014 to March 2016. Since March of 2016, the crude oil curve has generally been in a shallowcontango, meaning the current price of oil is only slightly less than the price in future months. In these shallow contango markets there is no clear incentive formarketers to store barrels. As of December 31, 2017, the forward price curve is slightly backwardated. In addition, a shallow contango or a backwardated marketmay impact our ability to re-contract expiring contracts and/or decrease the storage rate at which we are able to re-contract.Crude Oil Pipeline Services - In late April 2016, as a precautionary measure, we suspended service on a segment of our Mid-Continent pipeline system due toa discovery of a pipeline exposure caused by heavy rains and the erosion of a riverbed in southern Oklahoma. There was no damage to the pipeline and no loss ofproduct. In the second quarter of 2016, we took action to mitigate the service suspension and worked with customers to divert volumes, and, in certaincircumstances, transported volumes to a third-party pipeline system via truck. In addition, the term of the throughput and deficiency agreement on our Eagle Northpipeline system expired at June 30, 2016, and, in July of 2016, we completed a connection of the southeastern most portion of our Mid-Continent pipeline systemto our Eagle North pipeline system and concurrently reversed the Eagle North pipeline system.We are currently operating one Oklahoma mainline system, which is a combination of both the Mid-Continent and Eagle North pipeline systems instead oftwo separate systems, providing us with a current capacity of approximately 20,000 to 25,000 Bpd. We are working to restore service of the second Oklahomapipeline system and expect to put the line back in service by the end of the second quarter of 2018, increasing the transportation capacity of our pipeline systems byapproximately 20,000 Bpd. The ability to fully utilize the capacity of these systems may be impacted by the market price of crude oil and producers’ decisions toincrease or decrease production in the areas we serve.42Table of ContentsWe experienced a decrease in revenue on our East Texas pipeline system as a result of an overall decrease in production in the area and the expiration of anincentive tariff on a section of the system in 2015. As a result of the decrease in revenues and resulting decline in market values, we recognized non-cashimpairment expenses of $12.6 million and $1.4 million related to our East Texas pipeline system and a portion of our Mid-Continent pipeline system, respectively,in the fourth quarter of 2015 and an additional $2.3 million related to our East Texas pipeline system in the fourth quarter of 2016. On April 18, 2017, we sold theEast Texas pipeline system. We received cash proceeds at closing of approximately $4.8 million and recorded a gain of less than $0.1 million.The Knight Warrior project was canceled during the second quarter of 2016 due to continued low rig counts in the Eaglebine/Woodbine area coupled withlower production volumes, competing projects and the overall impact of the decreased market price of crude oil. Consequently, shipper commitments related to theproject were cancelled, and an impairment expense of $22.6 million related to the project was recognized in June 2016.On April 3, 2017, Advantage Pipeline, L.L.C. (“Advantage Pipeline”), in which we owned an approximate 30% equity ownership interest, was acquired by ajoint venture formed by affiliates of Plains All American Pipeline, L.P. and Noble Midstream Partners LP. We received cash proceeds at closing from the sale ofour approximate 30% equity ownership interest in Advantage Pipeline of approximately $25.3 million and recorded a gain on the sale of the investment of $4.2million. Approximately 10% of the gross sale proceeds were held in escrow, subject to certain post-closing settlement terms and conditions. We receivedapproximately $1.1 million of the funds held in escrow in August 2017 and our remaining balance of $2.2 million in January 2018.Crude Oil Trucking and Producer Field Services - A backwardated crude oil curve tends to favor the crude oil transportation services business as crude oilmarketers are incentivized to deliver crude oil to market and sell as soon as possible. When the crude oil market curve changed from a backwardated curve to acontango curve in the fourth quarter of 2014, coupled with a decrease in the absolute price of crude oil, transported volumes started decreasing. Throughout 2015,we experienced downward rate pressure in our trucking and producer field services business as producers and marketers attempted to renegotiate service rates topreserve their operating margins in the changing market. In addition, during the second half of 2015, our West Texas operating margins and transported volumeswere negatively impacted by increased competition from transporters moving equipment from crude oil shale areas to West Texas, where crude oil volumes haveremained relatively consistent, and by producers and marketers quickly pipe-connecting transported barrels. As a result, we decided to cease trucking barrels inWest Texas in the fourth quarter of 2015 and refocus our efforts on transporting barrels around our owned crude oil pipelines and storage assets in Oklahoma andKansas. In the fourth quarter of 2015, we recorded a restructuring charge of $1.6 million associated with our exit from West Texas in addition to a non-cashimpairment expense of $0.5 million associated with a write-down of assets to their estimated net realizable value. See Note 6 to our consolidated financialstatements for additional detail regarding this restructuring expense. In addition, in December 2017, we evaluated our producer field services business forimpairment and recognized an impairment expense of $2.4 million to record our assets at their estimated fair value.Recent Events A time line of certain recent events is set forth below.•On March 7, 2018, we acquired an asphalt terminalling facility located in Oklahoma from a third party for $22.0 million .•On December 1, 2017, we consummated a Purchase & Sale Agreement, dated as of November 22, 2017, among us and Ergon Asphalt & Emulsions,Inc. and Ergon Terminaling, Inc., both subsidiaries of Ergon, Inc., relating to the acquisition of an asphalt terminalling facility located in Bainbridge,Georgia, from Ergon Asphalt & Emulsions, Inc. and Ergon Terminaling, Inc. for a total purchase price of $10.2 million, consisting of 1,898,380common units representing limited partner interests in us.•On May 11, 2017, we entered into an amended and restated credit agreement that consists of a $450.0 million revolving loan facility.•On April 18, 2017, we sold the East Texas pipeline system. We received cash proceeds at closing of approximately $4.8 million and recorded a gain ofless than $0.1 million .•April 3, 2017, Advantage Pipeline was acquired by a joint venture formed by affiliates of Plains All American Pipeline, L.P. and Noble MidstreamPartners LP. We received cash proceeds at closing from the sale of our approximate 30% equity ownership interest in Advantage Pipeline ofapproximately $25.3 million and recorded a gain on the sale of the investment of $4.2 million. Approximately 10% of the gross sale proceeds were heldin escrow, subject to certain post-closing settlement terms and conditions. We received approximately $1.1 million of the funds held in escrow inAugust 2017 and our remaining balance of $2.2 million in January 2018.43Table of Contents•October 5, 2016 - We completed the Ergon Transactions which consisted of the following transactions and agreements:◦Ergon purchased 100% of the outstanding voting stock of Blueknight GP Holding, L.L.C., which owns 100% of the capital stock of our GeneralPartner, pursuant to a Membership Interest Purchase Agreement dated July 19, 2016, among CBB, an indirect wholly-owned subsidiary ofCharlesbank, BEHI, an indirect wholly-owned subsidiary of Vitol, and Ergon Asphalt Holdings, LLC, a wholly-owned subsidiary of Ergon (thepreviously defined Ergon Change of Control);◦Ergon contributed nine asphalt terminals plus $22.1 million in cash in return for total consideration of approximately $144.7 million, whichconsisted of the issuance of 18,312,968 of Preferred Units in a private placement;◦we repurchased 6,667,695 Preferred Units from each of Vitol and Charlesbank in a private placement for an aggregate purchase price ofapproximately $95.3 million. Vitol and Charlesbank each retained 2,488,789 Preferred Units upon completion of these transactions;◦Ergon acquired an aggregate of $5.0 million of common units for cash in a private placement, pursuant to a Contribution Agreement between us,Blueknight Terminal Holding, L.L.C., and three indirect wholly-owned subsidiaries of Ergon;◦we and Ergon entered into the Storage, Throughput and Handling Agreement under which we operate certain asphalt terminals, storage tanks andrelated real property, contracts, permits, and related assets previously owned by Ergon, and we store and terminal Ergon’s asphalt products inexchange for the payment of certain fees by Ergon. The term of the agreement began on October 5, 2016 and will continue for a period of sevenyears. The agreement will then continue on a year-to-year basis unless cancelled by either party by delivering not less than 180 days’ notice; and◦we entered into the Omnibus Agreement, dated October 5, 2016 (the “Omnibus Agreement”), with Ergon pursuant to which Ergon was granted aright of first offer with respect to the (i) Wolcott, Kansas Asphalt Terminal; (ii) Ennis, Texas Asphalt Terminal; (iii) Chandler, ArizonaAsphalt/Emulsion Terminal; (iv) Mt. Pleasant, Texas Emulsion Terminal; (v) Pleasanton, Texas Emulsion Terminal; (vi) Birmingport, AlabamaAsphalt/Polymer/Emulsion Terminal; (vii) Memphis, Tennessee Asphalt/Polymer/Emulsion Terminal; (viii) Nashville, TennesseeAsphalt/Polymer Terminal; (ix) Yellow Creek, Mississippi Asphalt Terminal; (x) Fontana, California Asphalt/Emulsion Terminal; and (xi) LasVegas, Nevada Asphalt/Emulsion/Polymer Terminal (collectively, the “ROFO Assets”) to the extent that we, as the owner of the ROFO Assets,proposes to transfer such ROFO Asset while the Omnibus Agreement is in effect. In addition, the Omnibus Agreement also granted Ergon a rightof first refusal to purchase the (i) Fontana, California Asphalt/Emulsion Terminal and (ii) Las Vegas, Nevada Asphalt/Emulsion/Polymer Terminal(together, the “ROFR Assets”) if any owner of the ROFR Assets proposes or intends to sell any ROFR Asset to a third party through the periodending December 31, 2018.•July 26, 2016 - We issued and sold 3,795,000 common units for a public offering price of $5.90 per unit, resulting in proceeds of approximately $21.2million, net of underwriters’ discount and offering expenses of $1.5 million.•July 19, 2016 - We entered into a Second Amendment to Amended and Restated Credit Agreement (the “Credit Agreement Amendment”), whichamended the Amended and Restated Credit Agreement, dated as of June 28, 2013, with Wells Fargo Bank, National Association as administrative agentand the several lenders from time to time party thereto.•June 2016 - We evaluated the prospects of Knight Warrior, a previously announced East Texas Eaglebine/Woodbine crude oil pipeline project, anddecided to not pursue development of the project due to continued low rig counts in the Eaglebine/Woodbine area coupled with lower productionvolumes, competing projects and the overall impact of the decreased market price of crude oil. Consequently, shipper commitments related to theproject were canceled, and an impairment expense of $22.6 million related to the project was recognized in June 2016.Our Revenues Our revenues consist of (i) terminalling revenues, (ii) gathering, transportation and producer field services revenues, (iii) product sales revenues, and (iv) fuelsurcharge revenues. On October 5, 2016, Ergon acquired 100% of the outstanding voting stock of our General Partner from Vitol and Charlesbank. Beginning onOctober 5, 2016, revenue from services provided to Ergon is presented as related-party revenue and revenue from services provided to Vitol is presented as a third-party revenue. During the year ended December 31, 2017 , we derived approximately $56.7 million of our revenues from services we provided to related parties,with $56.4 million and $0.3 million attributable to Ergon and Advantage Pipeline, respectively.Terminalling revenues consist of (i) storage service fees resulting from short-term and long-term contracts for committed space that may or may not be utilizedby the customer in a given month; and (ii) terminal throughput service charges to pump crude oil to connecting carriers or to deliver asphalt product out of ourterminals. Terminal throughput service charges are44Table of Contentsrecognized as the crude oil or asphalt product is delivered out of our terminal. Storage service revenues are recognized as the services are provided on a monthlybasis. We earn terminalling revenues in two of our segments: (i) crude oil terminalling services and (ii) asphalt terminalling services.As of March 1, 2018 , we have approximately 5.4 million barrels of crude oil storage under service contracts, including 4.7 million barrels of crude oil storagecontracts that are either month-to-month contracts or expire in 2018. The weighted average remaining term on the service contracts is approximately 11 months ,with one contract having a remaining term of 47 months . Storage contracts with Vitol represent 2.2 million barrels of crude oil storage capacity under contract.As of March 7, 2018 , we have leases and terminalling agreements for all of our 56 asphalt facilities, including 26 facilities under contract with Ergon. Leaseand terminalling agreements related to 16 of these facilities have terms that expire by the end of 2018 , while the agreements relating to our additional 40 facilitieshave on average five years remaining under their terms. We operate the asphalt facilities pursuant to terminalling agreements while our contract counterpartiesoperate the asphalt facilities that are subject to lease agreements.Gathering and transportation services revenues consist of service fees recognized for the gathering of crude oil for our customers and the transportation ofcrude oil to refiners, to common carrier pipelines for ultimate delivery to refiners or to terminalling facilities owned by us and others. Revenue for the gatheringand transportation of crude oil is recognized when the service is performed and is based upon regulated and non-regulated tariff rates and the related transportvolumes. Producer field services revenue consists of a number of services ranging from gathering condensates from natural gas producers to hauling producedwater to disposal wells. Revenue for producer field services is recognized when the service is performed. We earn gathering and transportation revenues in two ofour segments: (i) crude oil pipeline services and (ii) crude oil trucking and producer field services.During the year ended December 31, 2017 , we transported approximately 23,000 Bpd on our pipelines, a decrease of 36% as compared to the year endedDecember 31, 2016 . The decrease in volumes is primarily attributable to suspended service on our Mid-Continent pipeline system due to a discovery of a pipelineexposure in April 2016. We are working torestore service of the second Oklahoma pipeline system and expect to put the line back in service by the end of the second quarter of 2018, increasing thetransportation capacity of our pipeline systems by approximately 20,000 Bpd. See Crude oil pipeline services within our results of operations discussion foradditional detail. Vitol accounted for 57% and 33% of volumes transported in 2017 and 2016 , respectively.During the year ended December 31, 2017 , we transported approximately 21,000 Bpd on our crude transport trucks, a decrease of 22% as compared to theyear ended December 31, 2016 . As noted above, we are working to restore service of the second Oklahoma pipeline system and expect to put the line back inservice by the end of the second quarter of 2018. When our second Oklahoma pipeline system resumes service, we anticipate an increase in volumes transported byour crude oil transport trucks as we gather barrels to be transported on this pipeline. See Crude oil trucking and producer field services within our results ofoperations discussion for additional detail. Vitol accounted for approximately 43% and 30% of volumes transported in 2017 and 2016 , respectively.Product sales revenues are comprised of (i) revenues recognized for the sale of crude oil to our customers that we purchaseat production leases and (ii) revenue recognized in buy/sell transactions with our customers. Product sales revenue isrecognized for products upon delivery and when the customer assumes the risks and rewards of ownership. We earn productsales revenue in our crude oil pipeline services operating segment.Fuel surcharge revenues are comprised of revenues recognized for the reimbursement of fuel and power consumed to operate our asphalt terminals. Werecognize fuel surcharge revenues in the period in which the related fuel and power expenses are incurred.Our ExpensesOperating expenses increased by 11% in 2017 as compared to 2016 . This increase is primarily attributable to the acquisition of the nine asphalt terminals fromErgon in October 2016. General and administrative expenses decreased by 15% in 2017 as compared to 2016 . This decrease is primarily attributable to expensesincurred in 2016 related to the Ergon Transactions. Our interest expense increased by $1.5 million in 2017 as compared to 2016 . See Interest expense within ourresults of operations discussion for additional detail regarding the factors that contributed to the increase in interest expense in 2017 .45Table of ContentsIncome TaxesAs part of the process of preparing the consolidated financial statements, we are required to estimate the federal and state income taxes in each of thejurisdictions in which our subsidiary that is taxed as a corporation operates. This process involves estimating the actual current tax exposure together with assessingtemporary differences resulting from differing treatment of items, such as depreciation, for tax and accounting purposes. These differences result in deferred taxassets and liabilities, which are included in our consolidated balance sheets. We must then assess, using all available positive and negative evidence, the likelihoodthat the deferred tax assets will be recovered from future taxable income. If we believe that recovery is not likely, we must establish a valuation allowance. To theextent we establish a valuation allowance or increase or decrease this allowance in a period, we must include an expense or reduction of expense within the taxprovisions in the consolidated statements of operations.Under ASC 740 – Accounting for Income Taxes , an enterprise must use judgment in considering the relative impact of negative and positive evidence. Theweight given to the potential effect of negative and positive evidence should be commensurate with the extent to which it can be objectively verified. The morenegative evidence that exists (a) the more positive evidence is necessary and (b) the more difficult it is to support a conclusion that a valuation allowance is notneeded for some portion, or all of the deferred tax asset. Among the more significant types of evidence that we consider are:•taxable income projections in future years;•whether the carryforward period is so brief that it would limit realization of tax benefits;•future revenue and operating cost projections that will produce more than enough taxable income to realize the deferred tax asset based on existingservice rates and cost structures; and•our earnings history exclusive of the loss that created the future deductible amount coupled with evidence indicating that the loss is an aberration ratherthan a continuing condition.Based on the consideration of the above factors for our subsidiary that is taxed as a corporation for purposes of determining the likelihood of realizing thebenefits of the deferred tax assets, we have provided a full valuation allowance against our deferred tax asset as of December 31, 2017 .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 of liquidasphalt and crude oil. Our operations have minimal direct exposure to changes in liquid asphalt and crude oil prices, but the volumes of liquid asphalt and crude oilwe terminal, gather or transport are affected by commodity prices. We generate revenues by charging a fee for services provided at each transportation stage ascrude 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 topipelines and by charging a fee for services provided for the terminalling of liquid asphalt and crude oil.•Asphalt Terminalling Services. Our 56 asphalt terminals are located in 26 states and are well-positioned to provide asphalt terminalling services in themarket areas they serve throughout the continental United States. With our approximately 10.3 million barrels of total liquid asphalt storage capacity,we are able to provide our customers the ability to effectively manage their liquid asphalt inventories while allowing significant flexibility in theirprocessing and marketing activities. We currently have terminalling contracts or leases with customers for all of our 56 asphalt facilities. •Crude oil terminalling assets and services. We provide crude oil terminalling services at our terminalling facility located in Oklahoma. We currentlyown and operate approximately 6.6 million barrels of storage capacity at our terminal in Cushing, Oklahoma. Our Cushing terminal is strategicallylocated within the Cushing Interchange, one of the largest crude oil marketing hubs in the United States and the designated point of delivery specifiedin all NYMEX crude oil futures contracts. Our terminal has the capacity to receive or deliver approximately 10.0 million barrels of crude oil permonth. We also own approximately 50 acres of additional land within the Cushing Interchange where we can develop additional storage capacity.•Crude oil pipeline assets and services. We currently own and operate one pipeline system. Our Mid-Continent pipeline system, which is located inOklahoma and the Texas Panhandle, consists of a combined length of approximately 655 miles of pipelines that gather crude oil for our customers andtransport it to refiners, to common carrier pipelines for ultimate delivery to refiners or to terminalling facilities owned by us and others. We previouslyowned and operated the East Texas pipeline system, which is located in Texas. On April 18, 2017, we sold the East Texas pipeline system. See Note 7of our Consolidated Financial Statements for additional information. 46Table of Contents•Crude oil trucking and producer field services. In addition to our pipelines, we use our approximately 65 owned or leased tanker trucks to gathercrude oil in Oklahoma, Kansas and Texas for our customers at remote wellhead locations generally not connected to pipeline and gathering systems andtransport the crude oil to aggregation points and storage facilities located along pipeline gathering and transportation systems. In connection with ourgathering services, we also provide a number of producer field services, ranging from gathering condensates from natural gas producers to haulingproduction waste water to disposal wells. Our producer service fleet consists of approximately 85 trucks in a number of different sizes. Factors That Will Significantly Affect Our Results Commodity Prices . Although our current operations have minimal direct exposure to commodity prices, the volumes of liquid asphalt and crude oil weterminal, gather or transport are affected by commodity prices. Petroleum product prices may be contango (future prices higher than current prices) orbackwardated (future prices lower than current prices) depending on market expectations for future supply and demand. Our terminalling services benefit mostfrom an increasing price environment, when a premium is placed on storage, and our gathering and transportation services benefit most from a declining priceenvironment, when a premium is placed on prompt delivery. Volumes . Our results of operations are dependent upon the volumes of liquid asphalt we terminal and crude oil we terminal, gather and transport. Anincrease 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 areasserved by our pipelines and terminal facilities will have a corresponding effect on the volumes we terminal, gather or transport. The production and demand forliquid asphalt and crude oil are driven by many factors, including the price of crude oil.Acquisition Activities . We may pursue acquisition opportunities. These acquisition efforts may involve assets that, if acquired, would have a material effecton our financial condition, results of operations and cash flows. We can give no assurance that any such acquisition efforts will be successful or that any suchacquisition will be completed on terms ultimately favorable to us. Organic Expansion Activities . We may pursue opportunities to expand our existing asset base and consider constructing additional assets in strategiclocations. 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. Distributions to our Unitholders. We may make distributions to holders of our Preferred Units and common units as well as to our General Partner. To theextent that substantially all of our cash generated by our operations is used to make such distributions, 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 workingcapital needs.Vitol Storage AgreementsIn recent years, a significant portion of our crude oil storage capacity has been dedicated to Vitol under multiple agreements. As of December 31, 2015 , 2016and 2017 , 2.2 million barrels of storage capacity were dedicated to Vitol under these storage agreements. Service revenues under these agreements are based onthe barrels of storage dedicated to Vitol under the applicable agreement at rates that, we believe, are fair and reasonable to us and our unitholders and arecomparable with the rates we charge third parties. The Board’s conflicts committee reviewed and approved these agreements in accordance with our proceduresfor approval of related-party transactions and the provisions of the partnership agreement. For the year ended December 31, 2015, we generated revenues underthese agreements of approximately $9.4 million , all of which is classified as related-party revenue. For the year ended December 31, 2016, we generatedrevenues under these agreements of approximately $9.6 million , of which $2.1 million was classified as third-party revenue. All revenue for 2017 is classified asthird-party revenue.As of March 1, 2018 , 2.2 million barrels of storage capacity were dedicated to Vitol under the crude oil storage agreement with the current term scheduled toexpire on April 30, 2018. We are in the process of renegotiating this contract, however, we may not be able to extend, renegotiate or replace this contract when itexpires and the terms of any renegotiated contracts may not be as favorable as the contracts they replace.47Table of ContentsErgon AgreementsTwenty-six of our asphalt terminals are contracted to Ergon under multiple agreements. Service revenues under these agreements are primarily based oncontracted monthly fees under the applicable agreement at rates, which we believe are fair and reasonable to us and our unitholders and are comparable with therates we charge third parties. As of March 7, 2018 , leases and storage agreements related to 15 of these facilities are scheduled to expire by the end of 2018 . Wemay 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 thecontracts they replace. The Board’s conflicts committee reviewed and approved these agreements in accordance with our procedures for approval of related-partytransactions and the provisions of the partnership agreement. For the year ended December 31, 2015, we recognized revenues of $15.5 million for servicesprovided to Ergon under these agreements, all of which is classified as third-party revenue. For the year ended December 31, 2016, we recognized revenues of$22.1 million for services provided to Ergon under these agreements, of which $10.9 million is classified as related-party revenue. For the year ended December31, 2017, we recognized revenues of $56.3 million for services provided to Ergon under these agreements, all of which is classified as related-party revenue.Results of OperationsNon-GAAP Financial Measures To supplement our financial information presented in accordance with GAAP, management uses additional measures that are known as “non-GAAP financialmeasures” in its evaluation of past performance and prospects for the future. The primary measure used by management is operating margin excludingdepreciation and amortization. Management believes that the presentation of such additional financial measures provides useful information to investors regarding our performance andresults of operations because these measures, when used in conjunction with related GAAP financial measures, (i) provide additional information about our coreoperating performance and ability to generate and distribute cash flow; (ii) provide investors with the financial analytical framework upon which managementbases financial, operational, compensation and planning decisions; and (iii) present measurements that investors, rating agencies and debt holders have indicatedare useful in assessing us and our results of operations. These additional financial measures are reconciled to the most directly comparable measures as reported inaccordance with GAAP, and should be viewed in addition to, and not in lieu of, our consolidated financial statements and footnotes. The table below summarizes our financial results for the years ended December 31, 2015 , 2016 and 2017 , reconciled to the most directly comparable GAAPmeasure: 48Table of Contents Favorable/(Unfavorable)Operating ResultsYear ended December 31, 2015-2016 2016-2017(dollars in thousands)2015 2016 2017 $ % $ %Operating margin, excluding depreciationand amortization Asphalt terminalling services operatingmargin$48,212 $56,769 $64,623 $8,557 18 % $7,854 14 %Crude oil terminalling services operatingmargin18,842 20,048 17,977 1,206 6 % (2,071) (10)%Crude oil pipeline services operatingmargin7,694 4,347 (1,700) (3,347) (44)% (6,047) (139)%Crude oil trucking and producer fieldservices operating margin1,304 1,829 (434) 525 40 % (2,263) (124)%Total operating margin, excludingdepreciation and amortization76,052 82,993 80,466 6,941 9 % (2,527) (3)% Depreciation and amortization27,228 30,820 31,139 (3,592) (13)% (319) (1)%General and administrative expense18,976 20,029 17,112 (1,053) (6)% 2,917 15 %Asset impairment expense21,996 25,761 2,400 (3,765) (17)% 23,361 91 %Gain (loss) on sale of assets6,137 108 (975) (6,029) (98)% (1,083) (1,003)% Operating income13,989 6,491 28,840 (7,498) (54)% 22,349 344 % Other income (expense): Equity earnings in unconsolidatedaffiliate3,932 1,483 61 (2,449) (62)% (1,422) (96)%Gain on sale of unconsolidated affiliate— — 5,337 — N/A 5,337 N/AInterest expense(11,202) (12,554) (14,027) (1,352) (12)% (1,473) (12)%Provision for income taxes(323) (260) (166) 63 20 % 94 36 %Net income (loss)$6,396 $(4,840) $20,045 $(11,236) (176)% $24,885 514 % Total operating margin excluding depreciation and amortization decreased 3% from 2016 to 2017 . Asphalt terminalling services operating margin increased$7.9 million or 14% from 2016 to 2017 as a result of the acquisition of eleven asphalt terminals in 2016, increased product throughput volumes and renegotiatedthroughput fees for some of our asphalt facilities. This increase was partially offset by decreases in our other operating segments. The decrease in our crude oilterminalling services operating margin was primarily due to decreased throughput fees as lower volumes were transferred in and out of our facilities, coupled withlower re-contracted storage rates as prior contracts expired throughout the year. The crude oil pipeline services operating margin decreased primarily due to adecrease in volume transported by our pipelines related to suspended service on our Mid-Continent pipeline system beginning in April 2016 after a discovery of apipeline exposure caused by heavy rains and erosion of a river in southern Oklahoma, as well as the sale of our East Texas pipeline system in April 2017.Total operating margin excluding depreciation and amortization increased 9% from 2015 to 2016. Asphalt terminalling services operating margin increased$8.6 million or 18% from 2015 to 2016 as a result of the acquisition of eleven asphalt terminals in 2016, increased product throughput volumes and renegotiatedthroughput fees for some of our asphalt facilities. This increase was partially offset by decreases in our crude oil pipeline services operating segment, primarily dueto a decrease in volume transported by our pipelines related to suspended service on our Mid-Continent pipeline system beginning in April 2016 after a discoveryof a pipeline exposure caused by heavy rains and erosion of a river in southern Oklahoma.A more detailed analysis of changes in operating margin by segment follows.49Table of ContentsAnalysis of Operating SegmentsAsphalt terminalling services segmentOur asphalt terminalling services segment operations generally consist of fee-based activities associated with providing terminalling services, includingstorage, blending, processing and throughput services, for asphalt product and residual fuel oil. Revenue is generated through short- and long-term storagecontracts.The following table sets forth our operating results from our asphalt terminalling services segment for the periods indicated: Favorable/(Unfavorable)Operating resultsYear ended December 31, 2015-2016 2016-2017(dollars in thousands)2015 2016 2017 $ % $ %Service revenue: Third-party revenue$72,152 $75,655 $57,486 $3,503 5 % $(18,169) (24)%Related-party revenue1,278 11,762 56,378 10,484 820 % 44,616 379 %Total revenue73,430 87,417 113,864 13,987 19 % 26,447 30 %Operating expense (excluding depreciationand amortization)25,218 30,648 49,241 (5,430) (22)% (18,593) (61)%Operating margin (excluding depreciationand amortization)$48,212 $56,769 $64,623 $8,557 18 % $7,854 14 %The following is a discussion of items impacting our asphalt terminalling services segment operating margin for the periods indicated:•Overall revenues have increased for the year ended December 31, 2017, as compared to the year ended December 31, 2016, primarily due to theacquisition of eleven asphalt terminals in 2016 as well as increased product throughput at our terminals and renegotiated throughput fees for some of ourasphalt facilities. Revenues earned from Ergon moved from third-party to related-party due to the Ergon Change of Control, which resulted in all revenuesgenerated from services provided to Ergon after October 5, 2016, being classified as related-party revenues.•Operating expenses increased in 2017 as compared to 2016 primarily as a result of the acquisitions noted above. In addition, operating expenses for 2017increased by $2.4 million as compared to 2016 as a result of two facilities that we previously leased to customers converting to facilities we operate underservice agreements.•Third-party revenues increased for the year ended December 31, 2016, as compared to the year ended December 31, 2015, primarily due to the acquisitionof two asphalt terminals in February 2016 as well as increased product throughput at our terminals and renegotiated throughput fees for some of ourasphalt facilities. Related-party revenues increased due to the acquisition of nine asphalt facilities from Ergon in October 2016 in conjunction with theErgon Change of Control, which resulted in all revenues generated from services provided to Ergon after October 5, 2016, being classified as related-party revenues.•Operating expenses increased in 2016 as compared to 2015 as a result of an increase in utilities, compensation and maintenance and repair expenseprimarily due to the acquisition of the eleven new terminals in 2016.50Table of ContentsCrude oil terminalling services segmentOur terminalling services segment operations generally consist of fee-based activities associated with providing terminalling services, including storage,blending, processing and throughput services, for crude oil. Revenue is generated through short- and long-term storage contracts.The following table sets forth our operating results from our crude oil terminalling services segment for the periods indicated: Favorable/(Unfavorable)Operating ResultsYear ended December 31, 2015-2016 2016-2017(dollars in thousands)2015 2016 2017 $ % $ %Service revenue: Third-party revenue$13,076 $16,387 $22,177 $3,311 25 % $5,790 35 %Related-party revenue11,522 7,858 — (3,664) (32)% (7,858) (100)%Total revenue24,598 24,245 22,177 (353) (1)% (2,068) (9)%Operating expense (excluding depreciationand amortization)5,756 4,197 4,200 1,559 27 % (3) — %Operating margin (excluding depreciationand amortization)$18,842 $20,048 $17,977 $1,206 6 % $(2,071) (10)% Average crude oil stored per month at ourCushing terminal (in thousands of barrels)5,322 5,536 5,413 214 4 % (123) (2)%Average crude oil delivered to our Cushingterminal (in thousands of barrels per day)117 78 41 (39) (33)% (37) (47)%The following is a discussion of items impacting our crude oil terminalling services segment operating margin for the periods indicated:•Total revenues for 2017 have decreased due to a decrease in market rates for short-term, monthly storage contracts and decreased throughput fees aslower volumes were transferred in and out of our facilities.•Revenues earned from Vitol have moved from related-party to third-party due to the October 2016 Ergon Change of Control. We do not provide crude oilterminalling services to Ergon.•Overall operating expenses for 2017 were comparable to 2016. Decreases in maintenance and repair expense were offset by an increase in property taxexpense.•Operating expenses for 2016 decreased compared to 2015, primarily as a result of decreases in utilities expense, as well as a decrease in compensationexpense due to the cancellation of an operating and maintenance agreement related to Vitol’s crude oil terminal located in Midland, Texas in the thirdquarter of 2015. •As of March 1, 2018 , we have approximately 5.4 million barrels of crude oil storage under service contracts, including 4.7 million barrels of crude oilstorage contracts that are month-to-month or expire in 2018. The weighted average remaining term on the service contracts is approximately 11 months ,with one contract having a remaining term of 47 months . Storage contracts with Vitol represent 2.2 million barrels of crude oil storage capacity undercontract.51Table of ContentsCrude oil pipeline servicesOur crude oil pipeline services segment operations generally consist of fee-based activity associated with transporting crude oil products on pipelines.Revenues are generated primarily through tariffs and other transportation fees.The following table sets forth our operating results from our crude oil pipeline services segment for the periods indicated: Favorable/(Unfavorable)Operating ResultsYear ended December 31, 2015-2016 2016-2017(dollars in thousands)2015 2016 2017 $ % $ %Service revenue: Third-party revenue$15,148 $8,662 $9,580 $(6,486) (43)% $918 11 %Related-party revenue10,687 5,433 310 (5,254) (49)% (5,123) (94)%Product sales revenue: Third-party revenue3,511 20,968 11,094 17,457 497 % (9,874) (47)%Total revenue29,346 35,063 20,984 5,717 19 % (14,079) (40)%Operating expense (excluding depreciationand amortization)18,162 15,270 13,310 2,892 16 % 1,960 13 %Operating expense (intersegment)259 890 417 (631) (244)% 473 53 %Cost of product sales3,231 14,130 8,807 (10,899) (337)% 5,323 38 %Cost of product sales (intersegment)— 426 150 (426) N/A 276 65 %Operating margin (excluding depreciationand amortization)$7,694 $4,347 $(1,700) $(3,347) (44)% $(6,047) (139)% Average throughput volume (in thousandsof barrels per day) Mid-Continent36 27 22 (9) (25)% (5) (19)%East Texas (1)16 9 3 (7) (44)% (6) (67)%_______________(1)Average throughput on the East Texas system for 2017 was calculated based on the period of time we operated the system (January 1, 2017 through April 18, 2017).The following is a discussion of items impacting our crude oil pipeline services segment operating margin for the periods indicated:•In late April 2016, as a precautionary measure we suspended service on our Mid-Continent pipeline system due to discovery of a pipeline exposurecaused by heavy rains and the erosion of a riverbed in southern Oklahoma. There was no damage to the pipe and no loss of product. In the second quarterof 2016, we took action to mitigate the service suspension and worked with customers to divert volumes and, in certain circumstances, transportedvolumes to a third-party pipeline system via truck. In addition, the term of the throughput and deficiency agreement on our Eagle North pipeline systemexpired on June 30, 2016, and in July 2016 we completed a connection of the southeastern-most portion of our Mid-Continent pipeline system to ourEagle North pipeline system and concurrently reversed the Eagle North pipeline system. This enabled us to recapture diverted volumes and deliver thosebarrels to Cushing, Oklahoma. We are currently operating one Oklahoma mainline system, which is a combination of both the Mid-Continent and EagleNorth pipeline systems, instead of two separate systems, providing us with a current capacity of approximately 20,000 to 25,000 Bpd. We are working torestore service of the second Oklahoma pipeline system and expect to put the line back in service by the end of the second quarter of 2018, increasing thetransportation capacity of our pipeline systems by approximately 20,000 Bpd. The ability to fully utilize the capacity of these systems may be impacted bythe market price of crude oil and producers’ decisions to increase or decrease production in the areas we serve.•Service revenues have moved from related-party to third-party due to Ergon’s acquisition of our General Partner in October 2016, at which time Vitolceased to be a related party.•Included in product sales revenue for the year ended 2016 is $4.2 million in sales of crude oil arising from accumulated product-loss allowances (“PLA”).Product sales revenue for 2017 included $0.3 million in PLA sales. In52Table of Contentsaddition, as a result of one of our third-party customers utilizing a greater percentage of the capacity of our Red River pipeline, product sales revenue andcost of product sales declined from 2016 to 2017, which decreased the volume of marketed barrels of crude oil, for which revenue and costs are bothrecorded gross. This decrease was offset by an increase in third-party transportation revenue.•On April 18, 2017, we sold the East Texas pipeline system. We received cash proceeds at closing of approximately $4.8 million and recorded a gain ofless than $0.1 million. The sale of the East Texas pipeline system resulted in decreased service revenues of $2.2 million for year ended 2017 as comparedto 2016.•Operating expenses decreased for 2017 by $1.5 million compared to 2016 as a result of the sale of the East Texas pipeline system and by $0.7 million as aresult of the sale of our investment in Advantage Pipeline, for which we provided operational and administrative services through August 1, 2017.Offsetting this decrease was a $0.3 million right-of-way settlement incurred in December 2017 related to the pipeline exposure described above.•Service revenues for 2016 decreased compared to 2015 due to the expiration of an increased tariff that was being charged from June 2014 through May2015 on certain barrels transported on our East Texas pipeline system under a throughput and deficiency agreement. The tariff returned to a lower rate inJune 2015, which decreased the service revenues generated on the East Texas pipeline system by $4.6 million compared to 2015.•Product sales revenues and cost of product sales for 2016 increased compared to 2015 due to our acquisition of the Red River pipeline in November 2015.In conjunction with our acquisition of the Red River pipeline, we began marketing crude oil that we purchase at production leases. Revenue from thisactivity is reflected in product sales revenue. In addition to the marketing revenue, we also had $4.2 million in sales of crude oil arising from accumulatedproduct loss allowances in 2016. There were no sales of accumulated pipeline loss allowances during 2015.•Operating expenses for 2016 decreased compared to 2015 primarily due to decreases in maintenance and repairs.Crude oil trucking and producer field servicesOur crude oil trucking and producer field services segment operations generally consist of fee-based activity associated with transporting crude oil products ontrucks. Revenues are generated primarily through transportation fees.The following table sets forth our operating results from our crude oil trucking and producer field services segment for the periods indicated: Favorable/(Unfavorable)Operating ResultsYear ended December 31, 2015-2016 2016-2017(dollars in thousands)2015 2016 2017 $ % $ %Service revenue: Third-party revenue$37,039 $25,511 $24,529 $(11,528) (31)% $(982) (4)%Related-party revenue15,616 5,158 — (10,458) (67)% (5,158) (100)%Intersegment revenue259 890 417 631 244 % (473) (53)%Product sales revenue: Third-party revenue— — 385 — N/A 385 N/AIntersegment revenue— 426 150 426 N/A (276) (65)%Total revenue52,914 31,985 25,481 (20,929) (40)% (6,504) (20)%Operating expense (excluding depreciationand amortization)51,610 30,156 25,915 21,454 42 % 4,241 14 %Operating margin (excluding depreciationand amortization)$1,304 $1,829 $(434) $525 40 % $(2,263) (124)% Average volume (in thousands of barrelsper day)51 27 21 (24) (47)% (6) (22)%53Table of ContentsThe following is a discussion of items impacting our crude oil trucking and producer field services segment operating margin for the periods indicated:•Service revenues and operating expenses have decreased as a result of the continued low crude oil price environmentand increased competition in the areas we serve. We continue to experience downward rate pressure in our trucking and producer field services businessas producers and marketers attempt to renegotiate service rates to preserve their operating margins in the changing market.•Revenues have moved from related-party to third-party due to Ergon’s acquisition of our General Partner in October 2016, at which time Vitol ceased tobe a related party. We do not provide crude oil transportation services to Ergon.•I ncreases in product sales revenues for 2017 are the result of a crude oil sale in our field services business to a third party. Intersegment product salesrevenues for all periods are the result of crude oil sales in our field services business to our crude oil pipeline services segment.•During the year ended December 31, 2017 , we recognized total fixed asset and intangible asset impairment charges of $2.4 million related to theproducer field services business.•During the second half of 2015, our West Texas operating margins and transported volumes were negatively impacted by increased competition fromtransporters and marketers quickly pipe-connecting transported barrels. As a result, we decided to cease trucking barrels in West Texas and refocus ourefforts on transporting barrels around our owned crude oil pipelines and storage assets in Oklahoma and Kansas. We recorded a restructuring expense of$1.6 million related to employee severance and idle equipment costs related to our exit from the West Texas trucking business in 2015. This restructuringled to the improvement in operating margin from 2015 to 2016 despite decreased volumes and rates.Other Income and Expenses Depreciation and amortization. Depreciation and amortization increased to $31.1 million for 2017 compared to $30.8 million for 2016 and $27.2 million for2015. These increases are primarily the result of pipeline and asphalt facility acquisitions made during the past two years.General and administrative expense . General and administrative expense was $17.1 million for the year ended December 31, 2017 , compared to $20.0million for 2016 and $19.0 million for 2015 . The increase in expense for 2016 over 2017 and 2015 is primarily related to $1.8 million of transaction fees related tothe Ergon Change of Control and acquisition-related expenses.Asset impairment expense. During 2017, we recorded fixed asset and intangible asset impairment expense, including an impairment of goodwill, of $2.4million related to a write-down of our producer field services business to estimated fair value. During 2016, we recorded fixed asset impairment expense of $25.8million , primarily due to an impairment recognized on the Knight Warrior pipeline project and the East Texas pipeline system. The Knight Warrior pipelineproject was canceled due to continued low rig counts in the Eaglebine/Woodbine area coupled with lower production volumes, competing projects and the overallimpact of the decreased market price of crude oil. Consequently, shipper commitments related to the project were canceled. During 2015, we recorded fixed assetimpairment expenses of $12.6 million , $1.4 million , and $0.5 million related to the write-down of our East Texas pipeline system, a portion of our Mid-Continentpipeline system and our West Texas trucking stations, respectively, to their estimated fair value. In 2015, we also recorded an impairment expense of $7.5 millionrelated to goodwill associated with our pipeline services reporting unit. We used a discounted cash flow model, supplemented by a market approach, to evaluategoodwill and the estimated fair value of assets. Key assumptions in the analysis include the use of an appropriate discount rate, volume and rate forecasts andestimates of operating costs. Due to the imprecise nature of our projections and assumptions, actual results can and often do differ from our estimates. If theassumptions used in our projections and analysis prove to be inaccurate or if the markets in which we operate experience future adverse conditions, we could incuradditional impairment charges in the future. Gain (loss) on sale of assets. Loss on sale of assets was $1.0 million in 2017 compared to gains of $0.1 million and $6.1 million for 2016 and 2015 ,respectively. Losses for 2017 include $0.4 million related to the disposal of an asphalt tank floor that had to be replaced due to corrosion. Additional losses in 2017were the result of sales and disposals of surplus, used property and equipment. The gain on sale of assets in 2016 consists of the sale of surplus, used property andequipment. The gain on sale of assets in 2015 includes a $6.0 million gain on the sale of crude oil pipeline linefill and storage tank bottoms related to the settlementof litigation with SemCorp in September 2015.54Table of ContentsEquity earnings in unconsolidated affiliate. The equity earnings are attributable to our former investment in Advantage Pipeline. On April 3, 2017, we sold ourinvestment in Advantage Pipeline and received cash proceeds at closing from the sale of approximately $25.3 million, recognizing a gain on sale of unconsolidatedaffiliate of $4.2 million. Approximately 10% of the gross sale proceeds were held in escrow, subject to certain post-closing settlement terms and conditions. Wereceived approximately $1.1 million of the funds held in escrow in August 2017, for which we recognized an additional gain on sale of unconsolidated affiliateduring the three months ended September 30, 2017. We received approximately $2.2 million for the pro rata portion of the remaining net escrow proceeds inJanuary 2018.Interest expense. Interest expense was $14.0 million for 2017 compared to $12.6 million and $11.2 million for 2016 and 2015 , respectively. Interest expenserepresents interest on borrowings under our credit agreement, as well as amortization of debt issuance costs and unrealized gains and losses related to the change infair value of interest rate swaps. The increase in interest expense from 2016 to 2017 was primarily the result of increases in the weighted average interest rate and in the weighted average debtoutstanding during the period. During 2016 and 2017, the weighted average interest rate under the credit agreement was 3.95% and 4.43% , respectively. Inaddition, we wrote off $0.7 million of debt issuance costs during 2017 due to the amendment of our credit agreement. These increases were partially offset bydecreases in interest expense related to our interest rate swap agreements of $1.8 million.The increase in interest expense from 2015 to 2016 was primarily the result of increases in the weighted average interest rate and in the weighted average debtoutstanding during the periods. During 2015 and 2016, the weighted average interest rate under the credit agreement was 3.37% and 3.95% , respectively. Inaddition, the interest expense resulting from the amortization of debt issuance costs increased by $0.2 million in 2016. These increases were partially offset bydecreases in interest expense related to our interest rate swap agreements of $2.1 million.Effects of InflationIn recent years, inflation has been modest and has not had a material impact upon the results of our operations. Off-Balance Sheet Arrangements We do not have any off-balance sheet arrangements as defined by Item 303 of Regulation S-K. Liquidity and Capital ResourcesCash Flows and Capital ExpendituresThe following table summarizes our sources and uses of cash for the years ended December 31, 2015 , 2016 and 2017 : Year ended December 31, 2015 2016 2017 (in millions)Net cash provided by operating activities$60.5 $52.8 $54.5Net cash provided by (used in) investing activities(44.6) (159.6) 17.1Net cash provided by (used in) financing activities(15.6) 107.0 (72.4) Operating Activities . Net cash provided by operating activities was $54.5 million for the year ended December 31, 2017 , as compared to $52.8 million forthe year ended December 31, 2016 . The increase in cash provided by operating activities is primarily the result of changes in working capital.Net cash provided by operating activities was $52.8 million for the year ended December 31, 2016 , as compared to $60.5 million for the year endedDecember 31, 2015 . The decrease in cash provided by operating activities is primarily the result of changes in working capital and lower net income.Investing Activities . Net cash provided by investing activities was $17.1 million for the year ended December 31, 2017 , as compared to net cash used ininvesting activities of $159.6 million for the year ended December 31, 2016 . Capital expenditures for the year ended December 31, 2017 , included maintenancecapital expenditures of $7.9 million , net of reimbursable55Table of Contentsexpenditures of $0.8 million , and expansion capital expenditures of $9.4 million , net of reimbursable expenditures of $0.6 million . These expenditures wereoffset by proceeds from the sale of our investment in Advantage Pipeline, the East Texas pipeline system and other assets of $26.5 million , $4.8 million and $4.5million, respectively.Net cash used in investing activities was $159.6 million for the year ended December 31, 2016, as compared to $44.6 million for the year ended December 31,2015. Capital expenditures for the years ended December 31, 2016, included acquiring nine asphalt terminal facilities from Ergon for $122.6 million, maintenancecapital expenditures of $8.7 million , net of reimbursable expenditures of $1.9 million , expansion capital expenditures of $9.4 million and other acquisitions of$19.0 million . These expenditures were partially offset by proceeds from the sale of assets of $2.0 million . Capital expenditures for the year ended December 31,2015, included maintenance capital expenditures of $7.9 million, net of reimbursable expenditures of $0.5 million, expansion capital expenditures of $33.2 million,primarily related to the Knight Warrior pipeline project, and acquisitions of $21.0 million. These expenditures were partially offset by proceeds from the sale ofassets of $14.7 million as well as $2.3 million related to proceeds from the sale of investments in 2015.Financing Activities . Net cash used in financing activities was $72.4 million for the year ended December 31, 2017 . Financing activities for the year endedDecember 31, 2017 , included net payments under our credit agreement of $16.4 million and distributions to unitholders of $49.2 million . In addition, we receivedproceeds from equity issuances of $0.2 million .Net cash provided by financing activities was $107.0 million for the year ended December 31, 2016. Financing activities for the year ended December 31,2016, included net borrowings under our credit agreement of $79.0 million and distributions to unitholders of $47.2 million . In addition, we received proceedsfrom equity issuances of $26.3 million and repurchased $95.3 million of Preferred Units.Net cash used in financing activities was $15.6 million for the year ended December 31, 2015. Financing activities for the year ended December 31, 2015,consisted primarily of net borrowings under our credit agreement of $29.0 million and distributions to unitholders of $41.6 million.Our Liquidity and Capital Resources Cash flows from operations and borrowings under our credit agreement are our primary sources of liquidity. Our ability to borrow funds under our creditagreement may be limited by financial covenants. At December 31, 2017 , we had a working capital deficit of $0.1 million . This is primarily a function of ourapproach to cash management. At December 31, 2017 , we had approximately $140.9 million of availability under our revolving loan facility, and we could borrowup to $317.0 million , or an additional $7.9 million , and still remain within our covenant restrictions. As of March 1, 2018 , we have aggregate unusedcommitments under our revolving loan facility of approximately $139.9 million and cash on hand of approximately $1.3 million . Capital Requirements . Our capital requirements consist of the following: •maintenance capital expenditures, which are capital expenditures made to maintain the existing integrity and operating capacity of our assets andrelated 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 theoperating capacity or revenue of existing or new assets, whether through construction, acquisition or modification.Expansion capital expenditures for organic growth projects totaled $10.0 million in the year ended December 31, 2017 , compared to $9.4 million in the yearended December 31, 2016 . These capital expenditures were funded by cash flows from operations, borrowings under our credit agreement and proceeds from theissuance of common units. We currently expect our expansion capital expenditures for organic growth projects to be approximately $10.0 million to $12.0 million, net of reimbursable expenditures, in 2018. Maintenance capital expenditures totaled $7.9 million , net of reimbursable expenditures of $0.8 million , in the yearended December 31, 2017 , compared to $8.7 million in the year ended December 31, 2016 . We currently expect maintenance capital expenditures to beapproximately $8.0 million to $10 million , net of reimbursable expenditures, in 2018. Our sources of liquidity for these expansion and maintenance capitalexpenditures in 2018 are expected to be a combination of cash flows from operations and borrowings under our credit agreement.Our Ability to Grow Depends on Our Ability to Access External Expansion Capital . Our partnership agreement requires that we distribute all of our availablecash to our unitholders. Available cash is reduced by cash reserves established by our56Table of ContentsGeneral Partner to provide for the proper conduct of our business (including for future capital expenditures) and to comply with the provisions of our creditagreement. We may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations because we distribute all of our availablecash.Description of Credit Agreement . On May 11, 2017, we entered into an amended and restated credit agreement which consists of a $450.0 million revolvingloan facility. Our credit agreement is guaranteed by all of our existing subsidiaries. Obligations under our credit agreement are secured by first priority liens on substantiallyall of our assets and those of the guarantors. Our credit agreement includes procedures for adding financial institutions as revolving lenders or for increasing the revolving commitment of any currentlycommitted revolving lender, subject to the consent of the new or increasing lenders and an aggregate maximum of $600.0 million for all revolving loancommitments under our credit agreement.The credit agreement will mature on May 11, 2022 , and all amounts outstanding under our credit agreement shall become due and payable on such date. Thecredit agreement requires mandatory prepayments of amounts outstanding thereunder with the net proceeds from certain asset sales, property or casualty insuranceclaims and condemnation proceedings, unless we reinvest such proceeds in accordance with the credit agreement, but these mandatory prepayments will notrequire any reduction of the lenders’ commitments under the credit agreement. Borrowings under our credit agreement bear interest, at our option, at either the reserve-adjusted eurodollar rate (as defined in the credit agreement) plus anapplicable margin which ranges from 2.0% to 3.0% or the alternate base rate (the highest of the agent bank’s prime rate, the federal funds effective rate plus 0.5% ,and the 30-day eurodollar rate plus 1.0% ) plus an applicable margin which ranges from 1.0% to 2.0% . We pay a per annum fee on all letters of credit issued under the credit agreement, which fee equals the applicable margin for loans accruing interest based onthe eurodollar rate, and we pay a commitment fee on the unused commitments under the credit agreement. The applicable margins for the interest rate, the lettersof credit fee and the commitment fee vary quarterly based on our consolidated total leverage ratio (as defined in the credit agreement, being generally computed asthe ratio of consolidated total debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges).The credit agreement includes financial covenants which are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day ofeach fiscal quarter.Prior to the date on which we issue qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notes previously orconcurrently issued) that equals or exceeds $200.0 million , the maximum permitted consolidated total leverage ratio is 4.75 to 1.00; provided that the maximumpermitted consolidated total leverage ratio will be 5.25 to 1.00 for certain quarters based on the occurrence of a specified acquisition (as defined in thePartnership’s credit agreement, but generally being an acquisition for which the aggregate consideration is $15.0 million or more). The acquisition of the nineasphalt terminals from Ergon in 2016 qualified as a specified acquisition.From and after the date on which we issue qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notespreviously or concurrently issued) that equals or exceeds $200.0 million , the maximum permitted consolidated total leverage ratio is 5.00 to 1.00; provided thatfrom and after the fiscal quarter ending immediately preceding the fiscal quarter in which a specified acquisition occurs to and including the last day of the secondfull fiscal quarter following the fiscal quarter in which such acquisition occurred, the maximum permitted consolidated total leverage ratio is 5.50 to 1.00.The maximum permitted consolidated senior secured leverage ratio (as defined in the credit agreement, but generally computed as the ratio of consolidatedtotal secured debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) is 3.50 to 1.00, but this covenant isonly tested from and after the date on which we issue qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notespreviously or concurrently issued) that equals or exceeds $200.0 million .The minimum permitted consolidated interest coverage ratio (as defined in the credit agreement, but generally computed as the ratio of consolidated earningsbefore interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest expense) is 2.50 to 1.00.57Table of ContentsIn addition, the credit agreement contains various covenants that, among other restrictions, limit our ability to:•create, issue, incur or assume indebtedness;•create, incur or assume liens;•engage in mergers or acquisitions;•sell, transfer, assign or convey assets;•repurchase our equity, make distributions to unitholders and make certain other restricted payments;•make investments;•modify the terms of certain indebtedness, or prepay certain indebtedness;•engage in transactions with affiliates;•enter into certain hedging contracts;•enter into certain burdensome agreements;•change the nature of our business; and•make certain amendments to our partnership agreement.At December 31, 2017 , our consolidated total leverage ratio was 4.63 to 1.00 and our consolidated interest coverage ratio was 4.76 to 1.00. We were incompliance with all covenants of our credit agreement as of December 31, 2017 . The credit agreement permits us to make quarterly distributions of available cash (as defined in our partnership agreement) to unitholders so long as no defaultor event of default exists under the credit agreement on a pro forma basis after giving effect to such distribution. We are currently allowed to make distributions toour unitholders in accordance with this covenant; however, we will only make distributions to the extent we have sufficient cash from operations afterestablishment of cash reserves as determined by the General Partner in accordance with our cash distribution policy, including the establishment of any reserves forthe proper conduct of our business. In addition to other customary events of default, the credit agreement includes an event of default if:(i)our General Partner ceases to own 100% of our general partner interest or ceases to control us;(ii)Ergon ceases to own and control 50.0% or more of the membership interests of our General Partner; or(iii)during any period of 12 consecutive months, a majority of the members of the Board of our General Partner ceases to be composed ofindividuals:(A)who were members of the Board on the first day of such period;(B)whose election or nomination to the Board was approved by individuals referred to in clause (A) above constituting at the time of suchelection or nomination at least a majority of the Board; or(C)whose election or nomination to the Board was approved by individuals referred to in clauses (A) and (B) above constituting at the timeof such election or nomination at least a majority of the Board,provided that any changes to the composition of individuals serving as members of the Board approved by Ergon will not cause an event ofdefault.If an event of default relating to bankruptcy or other insolvency events occurs with respect to our General Partner or us, all indebtedness under our creditagreement will immediately become due and payable. If any other event of default exists under our credit agreement, the lenders may accelerate the maturity ofthe obligations outstanding under our credit agreement and exercise other rights and remedies. In addition, if any event of default exists under our creditagreement, the lenders may commence foreclosure or other actions against the collateral. If any default occurs under our credit agreement, or if we are unable to make any of the representations and warranties in our credit agreement, we will beunable to borrow funds or have letters of credit issued under our credit agreement. Contractual Obligations . A summary of our contractual cash obligations over the next several fiscal years as of December 31, 2017 , is as follows: 58Table of Contents Payments Due by PeriodContractual ObligationsTotal Less than1 Year 1-3 Years 4-5 Years More than5 Years (in millions)Debt obligations (1)$368.8 $14.0 $28.1 $326.7 $—Operating lease obligations12.9 4.8 5.0 1.8 1.3____________________(1)Represents required future principal repayments of borrowings of $307.6 million and variable-rate interest payments of $61.2 million . All amounts outstanding under our credit agreementmature in May 2022. For our variable-rate debt, we calculated interest obligations assuming the weighted average interest rate of our variable-rate debt at December 31, 2017 , on amountsoutstanding through the assumed repayment date.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 theseconsolidated financial statements in conformity with accounting principles generally accepted in the United States of America. As such, we are required to makecertain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reportedamounts of revenue and expenses during the periods presented. We based our estimates on historical experience, available information and various otherassumptions we believe to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates; however, actual results may differ from theseestimates under different assumptions or conditions. The accounting policies that we believe require our most difficult, subjective or complex judgments and arethe 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 accounting principles generally accepted in the United States of Americarequires management to make estimates and assumptions that affect the reported amounts and disclosure of contingencies. Management makes significantestimates including: (1) allowance for doubtful accounts receivable; (2) estimated useful lives of assets, which impacts depreciation; (3) estimated cash flows andfair values inherent in impairment tests; (4) accruals related to revenues and expenses; (5) the estimated fair value of financial instruments; and (6) liability andcontingency accruals. Although management believes 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 orextend 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 livesand 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 lossis included in operating income in the consolidated statements of operations. We calculate depreciation using the straight-line method based on estimated useful lives of our assets. These estimates are based on various factors, includingage (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertaintiesthat impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply anddemand 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 ourasset groups are as follows: Asset GroupEstimated Useful Lives (Years)Land improvements10-20Pipelines and facilities5-30Storage and terminal facilities10-35Transportation equipment3-10Office property and equipment and other3-30 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 operating income in the consolidated statements of operations. 59Table of ContentsWe have contractual obligations to perform dismantlement and removal activities in the event that some of our assets are abandoned. These obligationsinclude varying levels of activity, including completely removing the assets and returning the land to its original state. We have determined that the settlementdates related to the retirement obligations are indeterminate. The assets with indeterminate settlement dates have been in existence for many years and with regularmaintenance will continue to be in service for many years to come. In addition, it is not possible to predict when demands for our services will cease, and we donot believe that such demand will cease for the foreseeable future. Accordingly, we believe the date when these assets will be abandoned is indeterminate. With noreasonably determinable abandonment date, we cannot reasonably estimate the fair value of the associated asset retirement obligations. We believe that if our assetretirement obligations were settled in the foreseeable future the potential cash flows that would be required to settle the obligations based on current costs are notmaterial. We will record asset retirement obligations for these assets in the period in which sufficient information becomes available for us to reasonablydetermine the settlement dates. 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 toestimated fair value. Assets are tested for impairment when events or circumstances indicate that their carrying values may not be recoverable. The carrying valueof 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. Ifthe 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 isrecognized. Fair value is generally determined from estimated discounted future net cash flows.Goodwill. Goodwill represents the excess of the cost of acquisitions over the amounts assigned to assets acquired and liabilities assumed. Goodwill is notamortized, but is tested annually for impairment and when events and circumstances warrant an interim evaluation. Goodwill is tested for impairment at a level ofreporting referred to as a reporting unit. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered to beimpaired. The impairment test is generally based on the estimated discounted future net cash flows of the respective reporting unit, utilizing discount rates andother factors in determining the fair value of the reporting unit. Inputs in the Partnership’s estimated discounted future net cash flows include existing andestimated future asset utilization, estimated growth rates in future cash flows and estimated terminal values. During the fourth quarter of 2015, our goodwillimpairment test indicated that the fair value of the asphalt services and crude oil trucking and producer field services reporting units exceeded their carrying valuesand no impairments were indicated. In 2016 , an impairment was indicated in the crude oil pipeline services reporting unit and an impairment expense of $7.5million was recorded. In 2017 , an impairment was indicated in the crude oil trucking and field services reporting unit and an impairment expense of $0.9 millionwas recorded.Recent Accounting Pronouncements For information regarding recent accounting developments that may affect our future financial statements, see Note 22 to our consolidated financialstatements.I tem 7A. Quantitative and Qualitative Disclosures about Market Risk.Interest Rate Risk. We are exposed to market risk due to variable interest rates under our credit agreement. As of March 1, 2018 , we had $308.6 million outstanding under our credit agreement that was subject to a variable interest rate. Borrowings under our credit agreement bear interest, at our option, at either thereserve adjusted eurodollar rate (as defined in the credit agreement) plus an applicable margin or the alternate base rate (the highest of the agent bank’s prime rate,the federal funds effective rate plus 0.5%, and the 30-day eurodollar rate plus 1.0%) plus an applicable margin. I nterest rate swap agreements are used to manage aportion of the exposure related to changing interest rates by converting floating-rate debt to fixed-rate debt. In March 2014, we entered into two interest rate swapagreements with an aggregate notional value of $200.0 million . The first agreement became effective June 28, 2014, and matures on June 28, 2018. Under theterms of the first interest rate swap agreement, we pay a fixed rate of 1.45% and receive one-month LIBOR with monthly settlement. The second agreementbecame effective January 28, 2015, and matures on January 28, 2019. Under the terms of the second interest rate swap agreement, we pay a fixed rate of 1.97% andreceive one-month LIBOR with monthly settlement. The fair market value of the interest rate swaps at December 31, 2017 , consists of a current asset of $0.1million and a long-term liability of $0.2 million recorded on the consolidated balance sheets in other current assets and in long-term interest rate swap liabilities,respectively. The interest rate swaps do not receive hedge accounting treatment under ASC 815 - Derivatives and Hedging . Changes in the fair value of the interestrate swaps are recorded in interest expense in the consolidated statements of operations. During the year ended December 31, 2017 , the weighted average interest rate under our credit agreement was 4.43% .60Table of ContentsChanges in economic conditions could result in higher interest rates, thereby increasing our interest expense and reducing our funds available for capitalinvestment, operations or distributions to our unitholders. Based on borrowings as of December 31, 2017 , the terms of our credit agreement, current interest ratesand the effect of our interest rate swap agreements, an increase or decrease of 100 basis points in the interest rate would result in increased or decreased annualinterest expense of approximately $1.1 million .Commodity Price Risk. As we do not take ownership of the liquid asphalt or crude oil we terminal or transport for our customers and as we engage in limitedcommodity marketing, we have limited direct exposure to risks associated with changes in liquid asphalt and crude oil prices. However, the volumes of liquidasphalt and crude oil we gather, transport, market or terminal are indirectly affected by commodity prices because many of our customers have direct commodityprice exposure. We do not intend to mitigate this risk to our revenues by hedging this limited commodity price exposure. For additional information regarding theanticipated impact of this risk on our future revenues, see “Item 7-Management’s Discussion and Analysis of Financial Condition and Results of Operations-Potential Impact of Crude Oil Market Price Changes and Other Factors on Future Revenues.” 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 setforth on pages F-1 through F-32 of this report and are incorporated herein by reference.Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. None.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 ofour 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 Rules13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of ourGeneral Partner concluded that our disclosure controls and procedures were not effective as of December 31, 2017, due to the material weakness in internal controlover financial reporting as described below.Management’s Report on Internal Control Over Financial Reporting . Our General Partner’s management is responsible for establishing and maintainingadequate internal control over financial reporting. Our General Partner’s management, including the Chief Executive Officer and Chief Financial Officer of ourGeneral Partner, conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in “Internal Control -Integrated Framework” (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. A material weakness is a deficiency, or acombination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual orunaudited interim financial statements will not be prevented or detected on a timely basis. Management did not maintain effective controls over the presentation oftransactions within the consolidated statement of cash flows. Specifically, in connection with the preparation of our financial statements for the year endedDecember 31, 2017, management identified a material weakness in the operating effectiveness of internal control over financial reporting related to our process foridentifying and presenting the non-cash components of an acquisition transaction. This material weakness was identified prior to the issuance of our consolidatedfinancial statements for the year ended December 31, 2017, and resulted in an adjustment to the consolidated financial statements. Additionally, this materialweakness could result in misstatements of cash flows that would result in a material misstatement to the annual or interim consolidated financial statements thatwould not be prevented or detected.As a result of the material weakness described above, management concluded that our internal control over financial reporting was not effective as ofDecember 31, 2017, based on the criteria established in “Internal Control - Integrated Framework” (2013) issued by the COSO. The effectiveness of our internalcontrol over financial reporting as of December 31, 2017, has been audited by PricewaterhouseCoopers LLP, our independent registered public accounting firm, asstated 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 during the quarter endedDecember 31, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.61Table of ContentsRemediation Activities. To address the material weakness, management will implement a remediation plan which will supplement the existing controls. Theremediation plan will include additional training of financial reporting personnel with respect to the preparation of the consolidated statements of cash flows withspecific focus on the control that identifies non-cash components of transactions on the statement of cash flows. The material weakness will be fully remediatedwhen, in the opinion of management, the control processes have been operating for a sufficient period of time to provide reasonable assurance as to theireffectiveness. The remediation and ultimate resolution of the material weakness will be reviewed with the Audit Committee of the Board.PART III.Item 10. Directors, Executive Officers and Corporate Governance. 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 aregular 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 ordirectly or indirectly participate in our management or operations. Our General Partner owes a limited fiduciary duty to our unitholders. Our General Partner willbe 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 specificallynonrecourse to it. Our General Partner, therefore, may cause us to incur indebtedness or other obligations that are nonrecourse to it. Borrowings under our existingcredit facility are nonrecourse to our General Partner.Directors and Executive Officers The Board currently consists of W. R. “Lee” Adams (affiliated with Ergon), Edward D. Brooks (affiliated with Ergon), Jimmy A. Langdon (affiliated withErgon), Robert H. Lampton (affiliated with Ergon), William W. Lampton (affiliated with Ergon), Duke R. Ligon (an independent director), Steven M. Bradshaw(an independent director) and John A. Shapiro (an independent director). Mr. Ligon serves as the Chairman of the Board, the chairman of the audit committee anda member of the compensation committee and the conflicts committee of the Board. Mr. Bradshaw serves as the chairman of the conflicts committee and amember of the compensation committee and the audit committee of the Board. Mr. Shapiro serves as the chairman of the compensation committee and a memberof the conflicts committee and the audit committee of the Board. The following table shows information regarding the current directors and executive officers of our General Partner as of March 1, 2018 . Name Age Position with Blueknight Energy Partners G.P., L.L.C.Mark A. Hurley 59 Chief Executive OfficerAlex G. Stallings 50 Chief Financial Officer and SecretaryJoel W. Kanvik 48 Chief Legal Officer and General CounselJames R. Griffin 40 Chief Accounting OfficerJeffery A. Speer 51 Chief Operating OfficerBrian L. Melton 48 Chief Commercial OfficerDuke R. Ligon 76 Director, Chairman of the Board and Audit CommitteeSteven M. Bradshaw 69 Director, Chairman of the Conflicts CommitteeJohn A. Shapiro 66 Director, Chairman of the Compensation CommitteeW.R. “Lee” Adams 49 DirectorEdward D. Brooks 35 DirectorJimmy A. Langdon 53 DirectorRobert H. Lampton 57 DirectorWilliam W. Lampton 62 DirectorOur 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. Robert H. Lampton and William W. Lampton are brothers. There are no other family relationships between officersand directors.Mark A. Hurley became the Chief Executive Officer of our General Partner in September 2012. Mr. Hurley served as the Senior Vice President, Crude Oiland Offshore of Enterprise Products, LLC from 2010 to 2012, where he led the newly formed crude oil and offshore business segment. Mr. Hurley began his careerat Shell, where he served from 1981 to 2009, most62Table of Contentsrecently as President of Shell Pipeline Co., LP. Mr. Hurley received his Bachelor of Science in chemical engineering from North Carolina State University.Alex G. Stallings has served as Chief Financial Officer and Secretary of our General Partner since March 2009. Mr. Stallings served as Chief AccountingOfficer and Secretary of our General Partner from February 2007 to March 2009. Additionally, Mr. Stallings served as SemCorp’s Chief Accounting Officer fromSeptember 2002 to July 2008. Prior to joining SemCorp, Mr. Stallings served as Chief Accounting Officer for Staffmark, Inc., a temporary staffing company wherehe was responsible for the public reporting and integration of numerous acquisitions during his tenure. Mr. Stallings was also previously an audit manager for thepublic accounting firm of Coopers & Lybrand, working in its Tulsa, Oklahoma office. Mr. Stallings received his Bachelor of Business Administration inaccounting from Baylor University and is a certified public accountant in the state of Oklahoma.Joel W. Kanvik has served as General Counsel and Chief Legal Officer of our General Partner since November 2016. Mr. Kanvik previously served as theDirector of U.S. Law and Assistant Secretary for Enbridge Energy Company, Inc., which he joined in January 2001. He provided legal and business counsel to afamily of corporations/limited partnerships, including the development and execution for large-scale construction/acquisition projects, mergers and acquisitions,contracts and licenses, intellectual property, litigation management and corporate governance. Mr. Kanvik received his Bachelor of Arts in political science fromNorthwestern University and his Juris Doctor from the University of Wisconsin. 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 controllerfrom May of 2007 to March 2009. Mr. Griffin previously served as an audit manager for the public accounting firm of PricewaterhouseCoopers LLP. Mr. Griffinreceived his Bachelor of Science in business administration from Oklahoma State University and is a certified public accountant in the state of Oklahoma. Jeffery A. Speer has served as Chief Operating Officer of our General Partner since July 2013. Mr. Speer served as Senior Vice President-Operations of ourGeneral Partner from February 2010 to July 2013. Previously, Mr. Speer served as the Vice President of Operations of our asphalt and emulsion subsidiary sinceJune 2009. Prior to joining our team, Mr. Speer served as Vice President of Operations for Koch Industries, Inc. and had operational responsibility for Koch’scrude oil, pipeline and trucking divisions in Oklahoma, Texas and Canada, as well as Koch’s agricultural and asphalt businesses. Mr. Speer has more than 27 yearsof experience in the energy industry and received his Bachelor of Science in mechanical engineering from Kansas State University.Brian L. Melton has served as Chief Commercial Officer since January 2017 and previously as Vice President Pipeline Marketing and Business Developmentof our General Partner since December 2013. Previously, he served as Vice President of Business Development/Corporate Strategy for Crestwood Equity Partners,L.P., Crestwood Midstream Energy Partners, L.P. and Inergy, L.P. from September 2008 until December 2013. Prior to joining Inergy in 2008, he was a director inthe Energy Corporate Investment Banking groups of A.G. Edwards/Wachovia Securities. He has served on the board of directors of Abraxas PetroleumCorporation since October of 2009. Mr. Melton received his Bachelor of Science in management and his Master of Business Administration in finance fromArkansas State University. Duke R. Ligon has served as a director of our General Partner since October 2008. He is an attorney and the current owner and manager of Mekusukey OilCompany, LLC. He served as Senior Vice President and General Counsel of Devon Energy Corporation from January 1997 until he retired in February 2007. FromFebruary 2007 to February 2010, Mr. Ligon served in the capacity of Strategic Advisor to Love’s Travel Stops & Country Stores, Inc., based in Oklahoma City,Oklahoma, and previously acted as Executive Director of the Love’s Entrepreneurship Center at Oklahoma City University. He is also a member of the board ofdirectors of Heritage Trust Company, Security State Bank (in which he has a 14% beneficial ownership), Cavaloz Holdings, Inc. and Pardus Oil and Gas. He wasformerly on the board of directors of PostRock Energy Corporation, System One, Orion California LP, Emerald Oil, Inc., SteelPath MLP, TransMontaigne PartnersL.P., Pre-Paid Legal Services, Inc., Panhandle Oil and Gas Inc.,Vantage Drilling Company and TEPPCO Partners, L.P. Mr. Ligon received his undergraduatedegree in chemistry from Westminster College and his law degree from the University of Texas School of Law. Mr. Ligon was selected to serve as a director onthe Board due to his extensive business and leadership experience derived from his background as a director of various companies in the energy industry, as well ashis financial and legal expertise. Steven M. Bradshaw has served as a director of our General Partner since November 2009. He has over 35 years of experience in the global logistics andtransportation industry and currently serves as the Managing Director at Global Logistics Solutions. From 2005 to 2009, Mr. Bradshaw served as Vice President-Administration of Premium Drilling, Inc., an offshore drilling contractor that provides jack-up drilling services to the international oil and gas industry. Previously,he served as Executive Vice President of Skaugen PetroTrans, Inc. from 2001 to 2003. He also served for 16 years in various operating and63Table of Contentsmarketing capacities at Kirby Corporation, including as President-Refined Products Division from 1992 to 1996. Mr. Bradshaw also served as an officer in theUnited States Navy. He received his Master of Business Administration from Harvard University and a bachelor’s degree in mathematics from the University ofMissouri. Mr. Bradshaw was selected to serve as a director on the Board due to his business judgment and extensive industry knowledge and experience. John A. Shapiro has served as a director of our General Partner since November 2009. Mr. Shapiro retired as an officer at Morgan Stanley & Co., where hehad served for more than 24 years in various capacities, most recently as Global Head of Commodities. While an officer at Morgan Stanley, Mr. Shapiroparticipated in the successful acquisitions of TransMontaigne Inc. and Heidmar Inc., and served as a member of the board of directors of both companies. Prior tojoining Morgan Stanley & Co., Mr. Shapiro worked for Conoco, Inc. and New England Merchants National Bank. Mr. Shapiro has been a lecturer at PrincetonUniversity, Harvard University School of Government, HEC Business School (Paris, France) and Oxford University Energy Program (Oxford, UK). In addition, heserves on the board of directors of Citymeals-on-Wheels and serves as a senior advisor to Mountain Capital Partners, a Houston-based private equity firm focusedon upstream E&P investments. Mr. Shapiro has served on the board of directors of Blue Wolf Mongolia Holdings. He received his Master of BusinessAdministration from Harvard University and his bachelor’s degree in economics from Princeton University. Mr. Shapiro was selected to serve as a director on theBoard due to his financial expertise and extensive industry experience developed through his work at Morgan Stanley & Co., and by serving as a director of otherenergy companies.W.R. “Lee” Adams has served as a director of our General Partner since February 2018. Mr. Adams joined Ergon, Inc. as the Vice President of Internal Auditin 2011 and continues to serve in that position. He also serves as Chairman of Ergon’s Senior Management Team. He is a certified public accountant in the state ofMississippi and previously worked at Arthur Anderson and Haddox Reid Burkes & Calhoun, PLLC, where he specialized in assurance and advisory services in theareas of oil and gas, manufacturing, investments and employee benefit plans. Mr. Adams received his Bachelor of Accountancy from Mississippi State University,and also holds the designations of Chartered Global Management Accountant, Certified Fraud Examiner and Certified Internal Auditor. Mr. Adams currentlyserves as a member of the advisory council for Mississippi State’s Adkerson School of Accountancy and is the Chairman of the Board of Hartfield Academy. Hehas previously served as Chairman/President of the Petroleum Accounting Society of Mississippi and of the Mississippi Society of Certified Public Accountants, a2,600-member trade association for CPAs practicing in the state of Mississippi. Mr. Adams was selected to serve as a director on the Board due to his affiliationwith Ergon and his financial and business expertise.Edward D. Brooks has served as a director of our General Partner since October 2016. Mr. Brooks has been the Vice President of Business Development forErgon Asphalt & Emulsions, Inc. since 2013. Mr. Brooks joined Ergon in 2007 to serve as the Manager of Business Development. Prior to joining Ergon, Mr.Brooks worked with Haddox Reid Burkes & Calhoun, PLLC as a manager in the assurance services division. Mr. Brooks received his Bachelor of Science inBusiness Administration in accounting and his Master of Business Administration from Mississippi College and is a certified public accountant in the state ofMississippi. He also holds a Chartered Global Management Accountant designation. Mr. Brooks was selected to serve as a director on the Board due to hisaffiliation with Ergon and his financial and business expertise.Jimmy A. Langdon has served as a director of our General Partner since October 2016. Mr. Langdon currently holds the following positions: Executive VicePresident and Chief Operating Officer for Ergon; Sr. Vice President for ISO Panels, Inc.; Sr. Vice President for Ergon Teminalling, Inc.; Sr. Vice President forErgon Baton Rouge, Inc.; Sr. Vice President for Ergon Knoxville, Inc.; Sr. Vice President for Ergon St. James, Inc.; Sr. Vice President for Ergon Texas Pipeline,Inc.; and Sr. Vice President for Ergon-Ironton, LLC. He also serves on the Ergon Operating Committee as the chairman and Ergon’s Executive Committee as amember. Mr. Langdon began his full-time professional career with Tenneco working as an associate engineer with their Tennessee Gas Pipeline group based inHouston, Texas. He joined Ergon Refining, Inc. in 1989 as a maintenance engineer in Vicksburg, Mississippi and held various other positions through 1997. In1997, he assisted Ergon with the formation of Ergon-West Virginia, Inc. in Newell, West Virginia and held the position of Maintenance/Engineering Manager until2000. In 2000, Mr. Langdon joined the Ergon corporate office group and assisted the Real Estate segment of the company for the next two years in thedevelopment business. Over the next 14 years, he held various positions within Ergon including Vice President-Corporate Engineering and Vice President-Corporate Maintenance, as well as Sr. Vice President for Ergon Asphalt & Emulsions, Inc. Mr. Langdon received his degree in civil engineering from MississippiState University. Mr. Langdon was selected to serve as a director on the Board due to his affiliation with Ergon and his financial and business expertise.Robert H. Lampton has served as a director of our General Partner since October 2016. Mr. Lampton has been with Ergon since 1983, and currently servesas President of the Supply and Distribution Division, President of Ergon Terminalling, Inc. and President of Ergon Trucking, Inc. Mr. Lampton is also President ofErgon Marine and Industrial Supply and of Ergon Real Estate. He serves on Ergon’s Executive Committee and is a member of their board of directors. He was aboard member for Mississippi Valley Title Company from 2005 to 2015. Mr. Lampton received his degree in business administration with a64Table of Contentsminor in business psychology from The University of Mississippi. Mr. Lampton was selected to serve as a director on the Board due to his affiliation with Ergonand his financial and business expertise.William W. Lampton has served as a director of our General Partner since October 2016. Mr. Lampton has been with Ergon since 1979, and currently is amember of Ergon’s board of directors. He previously served as President of Ergon’s Asphalt Groups and as Chairman of the board of directors of Ergon Asphalt &Emulsions, Inc. Mr. Lampton currently is a board member of Mississippi Economic Council, Boy Scouts of America, Andrew Jackson Council, Greater JacksonChamber Partnership (of which he is a past chairman), and Mississippi Baptist Health Foundation. He sits on the Dean’s Advisory Council of Mississippi StateUniversity’s Bagley College of Engineering, and served as co-chair of the Mississippi Works initiative under Governor Phil Bryant. Mr. Lampton was selected toserve as a director on the Board due to his affiliation with Ergon and his financial and business expertise.Independence of Directors Our General Partner currently has eight directors, three of whom (Messrs. Bradshaw, Ligon and Shapiro) are “independent” as defined under the independencestandards established by Nasdaq. Nasdaq’s independence definition includes a series of objective tests, including that the director is not an employee of thecompany and has not engaged in various types of business dealings with the company. In addition, the Board has made a subjective determination as to eachindependent director that no relationships exist which, in the opinion of the Board, would interfere with the exercise of independent judgment in carrying out theresponsibilities of a director. In making these determinations, the directors reviewed and discussed information provided by the directors and us with regard to eachdirector’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 amajority of independent directors on the Board 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 auditcommittees, and the audit committee includes at least one member who is determined by the Board to meet the qualifications of an “audit committee financialexpert” in accordance with SEC rules, including that the person meets the relevant definition of an “independent” director. John A. Shapiro is the independentdirector who has been determined to be an audit committee financial expert. Unitholders should understand that this designation is a disclosure requirement of theSEC related to experience and understanding with respect to certain accounting and auditing matters. The designation does not impose any duties, obligations orliability that are greater than are generally imposed on a member of the audit committee and the Board, and the designation of a director as an audit committeefinancial expert pursuant to this SEC requirement does not affect the duties, obligations or liability of any other member of the audit committee or the Board. Board Leadership Structure and Risk Oversight The Chief Executive Officer and Chairman of the Board positions of our General Partner are held by separate individuals in recognition of the differencesbetween the two roles. We have taken this position to achieve an appropriate balance with regard to our strategic direction, oversight of management, unitholderinterests and director independence. Our General Partner’s Chief Executive Officer is responsible for setting our strategic direction and overseeing our day-to-dayperformance. Our General Partner’s Chairman of the Board is an independent director who provides guidance to the Chief Executive Officer and sets the agendafor and presides over Board meetings. Our Board is engaged in the oversight of risk through regular updates from our management team regarding those risks confronting us, the actions andstrategies necessary to mitigate those risks and the status and effectiveness of those actions and strategies. These regular updates are provided at meetings of theBoard and the audit committee as well as other meetings with the Chairman of the Board, the Chief Executive Officer and other members of our General Partner’smanagement team. Board Committees We have standing conflicts, audit and compensation committees of the Board. Each member of the audit, compensation and conflicts committees is anindependent director in accordance with Nasdaq and applicable securities laws. Each of the audit, compensation and conflicts committees has a written charterapproved by the Board. The written charter for each of these committees is available on our web site at www.bkep.com under the “Investors - CorporateGovernance” 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 attentionof Investor Relations at 6060 American Plaza, Suite 600, Tulsa, Oklahoma 74135. The current members of the audit, compensation and conflicts committees ofthe Board and a brief description of the functions performed by each committee are set forth below. 65Table of ContentsConflicts Committee . The members of the conflicts committee are Messrs. Bradshaw (chairman), Ligon and Shapiro. The primary responsibility of theconflicts committee is to review matters that the directors believe may involve conflicts of interest. The conflicts committee determines if the resolution of theconflict of interest is fair and reasonable to us. The conflicts committee may retain independent legal and financial advisors to assist in its evaluation of atransaction. The members of the conflicts committee may not be officers or employees of our General Partner or directors, officers or employees of its affiliatesand must meet the independence standards to serve on an audit committee of a board of directors established by any national securities exchange upon which ourcommon 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 byall 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. Bradshaw, Ligon (chairman) and Shapiro. The primary responsibilities of the auditcommittee are to assist the Board in its general oversight of our financial reporting, internal controls and audit functions, and it is directly responsible for theappointment, retention, compensation and oversight of the work of our independent auditors. For information regarding our audit committee financial expert, see “Independence of Directors” above. Compensation Committee . The members of the compensation committee are Messrs. Bradshaw, Ligon and Shapiro (chairman). The primary responsibilityof 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 administer the General Partner’s Long-Term Incentive Plan. 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, andincluding our General Partner’s independent directors, who are not employees of our General Partner, with regard to their activities relating to us. The Code ofBusiness Conduct and Ethics incorporates guidelines designed to deter wrongdoing and to promote honest and ethical conduct and compliance with applicablelaws and regulations. It also incorporates our expectations of our General Partner’s employees that enable us to provide accurate and timely disclosure in ourfilings 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 - Code of Business Conduct and Ethics” section of our web site at www.bkep.com. The information contained on, or connectedto, 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 SEC. We will also provide a copy of the Code of Business Conduct and Ethics to any of our unitholders without charge upon written request tothe attention of Investor Relations at 6060 American Plaza, Suite 600, Tulsa, Oklahoma 74135. If any substantive amendments are made to the Code of BusinessConduct 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’sexecutive 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 all directors, officers, beneficial owners ofmore than 10% of any class of our securities or any other person subject to Section 16 of the Exchange Act complied with the Section 16(a) filing requirements ofthem during the year ended December 31, 2017 , except for one Form 4 filed late on behalf of one of our directors in February 2018 with respect to one transaction. Reimbursement of Expenses of our General Partner Pursuant to our partnership agreement, our General Partner and its affiliates are entitled to receive reimbursement for the payment of expenses related to ouroperations and for the provision of various general and administrative services for our benefit. Item 11. Executive Compensation.Compensation Discussion and Analysis Throughout this section, each person who served as the Principal Executive Officer (“PEO”) during 2017 , each person who served as the Principal FinancialOfficer (“PFO”) during 2017 and the three most highly compensated executive officers other66Table of Contentsthan the PEO and PFO serving at December 31, 2017 , and up to two additional individuals for whom disclosure would have been provided but for the fact that theindividual was not serving as an executive officer at December 31, 2017 , are referred to as the Named Executive Officers (“NEOs”). The NEOs during 2017were:•Mark A. Hurley, Chief Executive Officer;•Alex G. Stallings, Chief Financial Officer and Secretary;•Jeffery A. Speer, Chief Operating Officer;•Brian L. Melton, Chief Commercial Officer; and•Joel W. Kanvik, Chief Legal Officer and General Counsel.As is the case with many publicly traded partnerships, we have not historically directly employed any persons responsible for managing or operating us or forproviding services relating to day-to-day business affairs. Our General Partner manages our operations and activities, and its Board and officers make decisions onour behalf. The compensation for the NEOs for services rendered to us is determined by the compensation committee of our General Partner. Compensation Methodology. The compensation committee of the Board seeks to provide a total compensation package designed to drive performance andreward contributions in support of our business strategies and to attract, motivate and retain high-quality talent with the skills and competencies required byus. Once every two to three years, our compensation committee examines the compensation practices of certain of our peer companies which, as of our mostrecent examination in March 2017, includes Sprague Resources, LP; CrossAmerica Partners, LP; Martin Midstream Partners, L.P.; Southcross Energy Partners,L.P.; JP Energy Partners, LP; Summit Midstream Partners, LP; American Midstream Partners, LP; CONE Midstream Partners, LP; Transmontaigne Partners, L.P.;PBF Logistics, LP; World Point Terminals, LP; Noble Midstream Partners, LP; Arc Logistics Partners, LP; USD Partners, LP and PennTex Midstream Partners,LP. The compensation committee may review and, in certain cases participate in, various relevant compensation surveys and consult with compensationconsultants with respect to determining compensation for the NEOs. In March 2017, the compensation committee of the Board engaged Aon Hewitt (“Aon”) as its independent compensation consultant to provide thecompensation committee with comparable market-based compensation data applicable to the NEOs of our General Partner. In its consultation role, Aon was taskedwith conducting an assessment of our peer group and benchmarking the compensation of our NEOs against our peer group.The objective of the analysis was to review and ensure the market competitiveness of our NEOs’ compensation. The scope of Aon’s review included themarket competitiveness of the following compensation elements:•base salary;•target annual incentive opportunity (annual incentive paid for achieving target performance levels);•target total annual compensation (base salary + target annual incentive);•long-term incentive (“LTI”) awards; and•target total direct compensation (base salary + target annual incentive + LTI awards).Market data presented by Aon represented the compensation paid to a “typical” employee in a particular position and was considered as one data point whenmaking compensation determinations. Individual performance, longevity and internal equity were also factors in determining individual pay levels. Thecompensation committee expects to continue to utilize the compensation survey data when making decisions to change any individual NEO’s compensation, orwhen making changes or additions to any compensation program or methodologies. Aon’s work for the compensation committee did not raise any conflicts ofinterest in 2017.Elements of Compensation . Historically, the primary elements of our General Partner’s compensation program have been a combination of annual cash andlong-term equity-based compensation, and the principal elements of compensation for the NEOs in 2017 were as follows:•base salary;•discretionary bonus awards;•long-term incentive plan awards; and•other benefits.67Table of ContentsThe compensation committee reviews and makes recommendations regarding the mix of compensation, both among short- and long-term compensation andcash and non-cash compensation, to establish structures that it believes are appropriate for each of the NEOs. We believe that the mix of base salary, discretionarybonus awards, awards under the long-term incentive plan and other benefits fit our overall compensation objectives. We believe this mix of compensation providescompetitive compensation opportunities to align and drive employee performance in support of our business strategies and to attract, motivate and retain high-quality talent with the skills and competencies that we require.Base Salary. Our General Partner’s compensation committee establishes base salaries for the NEOs and reviews these annually considering various factors,including the amounts it considers necessary to attract and retain the highest quality executives, the responsibilities of the NEOs and market data including publiclyavailable market data for the peer companies listed above as reported in their filings with the SEC. In March 2017, our General Partner’s compensation committee increased the base salaries of Messrs. Hurley, Stallings, Speer, Melton and Kanvik to$450,000, $326,000, $268,000, $244,000 and $260,000, respectively. These base salary increases reflected the scope of each executive’s responsibilities and thecompensation committee’s consideration of competitive market compensation paid by similar companies for comparable positions. Discretionary Bonus Awards. Our General Partner’s compensation committee may also award discretionary bonus awards to the NEOs. Our General Partnergrants discretionary bonus awards to encourage and reward achievement of financial and operational goals and individual performance objectives. During March 2018, the compensation committee awarded discretionary bonuses of $400,000 , $160,000 , $187,000 , $110,000 and $141,000 to each ofMessrs. Hurley, Stallings, Speer, Melton and Kanvik, respectively, relating to our results of operations in 2017. Please see “-2017 Incentive Compensation” for adiscussion of these discretionary bonuses. Long-Term Incentive Plan Awards . Our General Partner has adopted the Long-Term Incentive Plan for employees, consultants and directors of our GeneralPartner and its affiliates who perform services for us. Each of the NEOs is eligible to participate in the Long-Term Incentive Plan. The Long-Term Incentive Planprovides for the grant of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights and substitute awards. Fora more detailed description of our Long-Term Incentive Plan, please see “-Long-Term Incentive Plan.”During March 2017, the compensation committee made awards of 21,800 , 22,504 , 15,471 and 12,658 phantom units to Messrs. Stallings, Speer, Melton andKanvik, respectively, relating to our results of operations in 2016. The awards vest on January 1, 2020. These phantom units contain distribution equivalent rightsthat entitle the holder of such units to receive a cash payment equal to the amount of any ordinary quarterly cash distribution paid to our common unitholders. During March 2018, the compensation committee made awards of 61,448 , 27,447 , 29,700 , 19,663 and 20,278 phantom units to Messrs. Hurley, Stallings,Speer, Melton and Kanvik, respectively, relating to our results of operations in 2017. For all but Mr. Hurley, the awards vest on January 1, 2021. Mr. Hurley’sphantom units will vest on January 1, 2019. These phantom units contain distribution equivalent rights that entitle the holder of such units to receive a cashpayment equal to the amount of any ordinary quarterly cash distribution paid to our common unitholders. Please see “-2017 Incentive Compensation” for adiscussion of these awards.Other Benefits. The employment agreements entered into by Messrs. Hurley and Stallings with our General Partner provide that such NEO is eligible toparticipate in any employee benefit plans maintained by our General Partner during the term of his employment with the General Partner. During 2017 , ourGeneral Partner, in addition to the Long-Term Incentive Plan described above, maintained an employee health insurance plan and an Exec-U-Care plan underwhich our officers (including all NEOs) were reimbursed for certain co-pays and deductibles for medical expenses. In addition, the employment agreementsprovide that each NEO is entitled to reimbursement for out-of-pocket expenses incurred while performing his duties under the employment agreement.Furthermore, we currently provide auto allowances to our NEOs.2017 Incentive Compensation. For 2017 , the Board approved a cash bonus plan whereby 90% of an aggregate bonus pool for all employees, including theNEOs, was to be funded as follows:•75% of this portion of the bonus pool was to be funded based on the achievement of approximately $54.6 million in cash flow generated prior todistributions, incentive compensation and reserves established by our General Partner.68Table of Contents•An additional 15% of this portion of the bonus pool was to be funded based on the achievement of partnership-wide goals (with a range of 0% to15% being contributed based on this performance metric).•An additional 10% of this portion of the bonus pool was to be funded based on the achievement of environmental, health and safety targets (witha range of 0% to 20% being contributed based on this performance metric).An additional 10% of the bonus pool was to be funded based on the achievement of our growth goals (with a range of 0% to 20% being contributed based onthis performance metric).Individual awards (which, as in prior years, were expected to be paid in a combination of cash bonuses and equity compensation) were to be determined by thecompensation committee at its discretion based on individual performance, exceptional service to the Partnership, challenges and opportunities not reasonablyforeseeable at the beginning of the year, internal equities and external competition or opportunities. In 2017 , actual cash flow generated prior to distributions,incentive compensation and reserves established by our General Partner was $52.6 million, resulting in 65% of the bonus pool being contributed based on thismetric. In addition, partnership-wide goals were achieved resulting in 15% of the bonus pool being contributed, 9% of the bonus pool was contributed based on thepartial achievement of environmental, health and safety targets and company growth goals were partially met resulting in 7% of the bonus pool being contributed.In March 2018, our General Partner’s chief executive officer recommended cash bonus and Long-Term Incentive Plan awards for the remaining NEOs. After athorough discussion, the compensation committee approved the following for each of our NEOs (other than Mr. Hurley):(i)a discretionary bonus award relating to our results of operations in 2017 as follows: $160,000 , $187,000 , $110,000 and $141,000 for Messrs.Stallings, Speer, Melton and Kanvik, respectively; and(ii)awards of phantom units relating to our results of operations for 2017 as follows: 27,447 units, 29,700 units, 19,663 units and 20,278 units toMessrs. Stallings, Speer, Melton and Kanvik, respectively.On March 5, 2018 the compensation committee made these discretionary bonus awards and phantom unit grants in accordance with such recommendations andalso awarded Mr. Hurley a discretionary bonus award of $400,000 relating to our results of operations in 2017 . The discretionary bonus awards were paid inMarch 2018. The compensation committee considered the achievement of performance metrics outlined in the prior paragraph as well as the performance of theindividual NEO in determining to make such awards.Role of Executive Officers in Executive Compensation. Our General Partner’s compensation committee determines the compensation of the NEOs. OurGeneral Partner’s chief executive officer, Mr. Hurley, made recommendations to the compensation committee for the awards of phantom units and discretionarybonuses to be paid to our NEOs relating to our results of operations in 2017 . However, Mr. Hurley does not make any recommendations regarding his personalcompensation. In addition, the employment agreement entered into by Mr. Stallings was originally approved by the management committee of SemCorp’s generalpartner pursuant to its limited liability company agreement. Employment Agreements. As indicated above, each of the NEOs except Messrs. Speer, Melton and Kanvik has entered into an employment agreement withour General Partner or one of its subsidiaries. Employment Agreement of Mr. Hurley. Mr. Hurley’s employment agreement had an initial term of five years that now automatically renews for subsequentone-year periods unless either party gives 90 days advance notice of termination. Pursuant to Mr. Hurley’s employment agreement, Mr. Hurley was paid an initialannual base salary of $425,000. Our General Partner’s compensation committee has increased the base salary of Mr. Hurley to $450,000 since the initialemployment agreement. Mr. Hurley also received 500,000 non-participating phantom units in September 2012 under the General Partner’s Long-Term IncentivePlan, which vested ratably over five years pursuant to the Phantom Unit Agreement he entered into with the General Partner. The units were fully vested as ofDecember 31, 2017. The employment agreement also provides that Mr. Hurley is eligible to participate in any employee benefit plans maintained by the GeneralPartner and is entitled to reimbursement for certain out-of-pocket expenses. Mr. Hurley has agreed not to disclose any confidential information obtained by himwhile employed under his employment agreement and has agreed to a one-year post-termination non-solicitation covenant.Except in the event of termination for Cause as defined therein, termination by Mr. Hurley other than for Good Reason as defined therein, termination after theexpiration of the term of Mr. Hurley’s employment agreement or termination due to death or disability, Mr. Hurley’s employment agreement provides for paymentof any unpaid base salary and vested benefits under any incentive plans, a lump sum payment equal to 12 months of base salary and Mr. Hurley will also beentitled to continued69Table of Contentsparticipation in our General Partner’s welfare benefit programs for a period of 18 months following termination. Based upon Mr. Hurley’s current base salary, themaximum amount of the lump sum severance payment would be approximately $0.5 million, in addition to continued participation in the General Partner’s welfarebenefit programs and the amounts of earned but unpaid base salary and benefits under any incentive plans. The employment agreement contains payment obligations that may be triggered by a termination after a Change of Control (as defined therein). See “-Potential Payments Upon Change of Control or Termination.” Pursuant to the employment agreement, if, within 18 months after a Change of Control (as definedtherein) occurs, Mr. Hurley is terminated by our General Partner without Cause (as defined therein) or Mr. Hurley terminates the agreement for Good Reason (asdefined therein), he will be entitled to payment of any unpaid base salary and vested benefits under any incentive plans, a lump sum payment equal to 12 months ofbase salary and Mr. Hurley’s most recent annual bonus and continued participation in our General Partner’s welfare benefit programs for the longer of theremainder of the term of the employment agreement or one year after termination. Based upon Mr. Hurley’s current base salary and most recent annual bonus, themaximum amount of the lump sum severance payment would be approximately $0.9 million , in addition to continued participation in the General Partner’swelfare benefit programs and the amounts of earned but unpaid base salary and benefits under any incentive plans.Employment Agreement of Mr. Stallings. The employment agreement entered into by Mr. Stallings had an initial term of two years that automatically renewsfor subsequent one-year periods unless either party gives 90 days advance notice of termination. This employment agreement provides for Mr. Stallings’ annualbase salary as described above. In addition, Mr. Stallings is eligible for discretionary bonus awards and long-term incentives which may be made from time to timeat the sole discretion of the Board. The employment agreement also provides that Mr. Stallings is eligible to participate in any employee benefit plans maintainedby our General Partner during the term of his employment with the General Partner and for up to 12 months thereafter, and is entitled to reimbursement for certainout-of-pocket expenses. Pursuant to the employment agreement, Mr. Stallings has agreed not to disclose any confidential information obtained by him while employed under theagreement. In addition, the employment agreement contains payment obligations that may be triggered by a termination after a Change of Control (as definedtherein). See “- Potential Payments Upon Change of Control or Termination.” Under the employment agreement entered into with Mr. Stallings, our General Partner may be required to pay certain amounts upon a Change of Control (asdefined therein) of us or our General Partner or upon the termination of Mr. Stallings in certain circumstances. Except in the event of termination for Cause (asdefined therein), termination by Mr. Stallings other than for Good Reason (as defined therein) or termination after the expiration of the term of the employmentagreement, the employment agreement provides for payment of any unpaid base salary and vested benefits under any incentive plans, a lump sum payment equal to12 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 theemployment agreement or one year after termination. The employment agreement also provides that if, within one year after a Change of Control (as defined therein) occurs, Mr. Stallings is terminated by ourGeneral Partner without Cause (as defined therein) or Mr. Stallings terminates the agreement for Good Reason (as defined therein), he will be entitled to paymentof 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 ourGeneral Partner’s welfare benefit programs for the longer of the remainder of the term of the employment agreement or one year after termination. Based uponMr. Stallings’ current base salary, the maximum amount of the lump sum severance payment would be approximately $0.7 million , in addition to continuedparticipation in the General Partner’s welfare benefit programs and the amounts of earned but unpaid base salary and benefits under any incentive plans. Potential Payments Upon Change of Control.As described above, the employment agreements with Messrs. Hurley and Stallings contain provisions that could result in the payment of amounts describedabove to such individuals upon a qualifying termination or Change of Control (as defined in such employment agreements). Had Messrs. Hurley or Stallings been terminated under the scenarios listed below on December 31, 2017, they would have received the following amounts andbenefits: 70Table of ContentsNameBenefit TypeTermination without Cause orResignation for Good Reason Termination without Cause or Resignation forGood Reason in Connection with A Change inControl Mark A. HurleyLump Sum Severance$925,000(1) $925,000(1) Benefits Continuation$—(2) $—(2) Alex G. StallingsLump Sum Severance$326,000 $652,000 Benefits Continuation$34,000 $34,000 _______________(1)As described above, on October 5, 2016, Ergon purchased 100% of the outstanding voting stock of Blueknight GP Holding, L.L.C. from Charlesbank Capital Partner, LLC and VitolHolding B.V., triggering a Change of Control under the employment agreements. Mr. Hurley was still within his 18-month protection period following such Change in Control and, thus,would have been entitled to enhanced severance benefits upon any termination of his employment without Cause or for Good Reason on December 31, 2017.(2)Mr. Hurley did not participate in our General Partner’s group health plans as of December 31, 2017, and thus would not have received any continued benefits under such plans had heexperienced a qualifying termination of employment on such date. Long-Term Incentive Plan. General . Our General Partner has adopted the Long-Term Incentive Plan (“LTIP”) for employees, consultants and directors ofour General Partner and its affiliates who perform services for us. The summary of the LTIP contained herein does not purport to be complete and is qualified in itsentirety by reference to the LTIP. The LTIP provides for the grant of unit awards, restricted units, phantom units, unit options, unit appreciation rights anddistribution equivalent rights. Effective April 29, 2014, the Partnership’s unitholders voted to approve an amendment to the LTIP, which increased the number ofcommon units reserved for issuance thereunder by 1,500,000 common units, from 2,600,000 common units to 4,100,000 common units, subject to adjustment forcertain events. Units that are canceled, forfeited or withheld to satisfy our General Partner’s tax withholding obligations are available for delivery pursuant to otherawards. The LTIP is administered by the compensation committee of the Board. The LTIP has been designed to furnish additional compensation to employees,consultants and directors and to align their economic interests with those of other common unitholders. Unit Awards . The compensation committee may grant unit awards to eligible individuals under the LTIP. A unit award is an award of common units that arefully vested upon grant and not subject to forfeiture.Restricted Units and Phantom Units . A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and therecipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vestingof the phantom unit or, at the discretion of the compensation committee, cash equal to the fair market value of a common unit. The compensation committee maymake grants of restricted units and phantom units under the LTIP to eligible individuals containing such terms, consistent with the LTIP, as the compensationcommittee may determine, including the period over which restricted units and phantom units granted will vest. The compensation committee may, at itsdiscretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified performance goals or other criteria. Distributions made by us with respect to awards of restricted units may, at the compensation committee’s discretion, be subject to the same vestingrequirements as the restricted units. The compensation committee, at its discretion, may also grant tandem distribution equivalent rights with respect to phantomunits. We intend for restricted units and phantom units granted under the LTIP to serve as a means of incentive compensation for performance and not primarily asan opportunity to participate in the equity appreciation of the common units. Therefore, participants will not pay any consideration for the common units theyreceive 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. Options and Unit Appreciation Rights . The LTIP also permits the grant of options covering common units and unit appreciation rights. Options represent theright to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of anumber of common units over a specified exercise price, either in cash or in common units as determined by the compensation committee. Options and unitappreciation rights may be granted to such eligible individuals and with such terms as the compensation committee may determine, consistent with the LTIP;however, an option or unit appreciation right must have an exercise price equal to the fair market value of a common 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 aspecified time. Distribution equivalent rights may be granted alone or in combination with another award.71Table of Contents By giving participants the benefit of distributions paid to unitholders generally, grants of distribution equivalent rights provide an incentive for participants tooperate our business in a manner that allows our partnership to provide increasing partnership distributions. Typically, distribution equivalent rights will be grantedin 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 thatunitholders receive while the award is outstanding. We believe this aligns the participant’s incentives directly to the measures that drive returns for our unitholders.Source of Common Units; Cost. Common units to be delivered with respect to awards may be common units acquired by our General Partner on the openmarket, common units already owned by our General Partner, common units acquired by our General Partner directly from us or any other person or anycombination of the foregoing. Our General Partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. With respect tooptions, our General Partner will be entitled to reimbursement by us for the difference between the cost incurred by our General Partner in acquiring these unitsand the proceeds received from an optionee at the time of exercise. Thus, we will bear the cost of the 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 awardto 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 LTIP. The Board, at its discretion, may terminate the LTIP at any time with respect to the units for which a grant has nottheretofore been made. The LTIP will automatically terminate on the earlier of the 10th anniversary of the date it was initially approved by our unitholders or whenunits are no longer available for delivery pursuant to awards under the LTIP. The Board will also have the right to alter or amend the LTIP or any part of it fromtime to time and the compensation committee may amend any award; provided, however, that no change in any outstanding award may be made that wouldmaterially impair the rights of the participant without the consent of the affected participant.Unit Purchase Plan. On June 23, 2014, the Partnership’s unitholders approved the Blueknight Energy Partners, L.P. Employee Unit Purchase Plan (the “UnitPurchase Plan”). The Unit Purchase Plan provides employees of the General Partner and its affiliates who perform services for the Partnership the opportunity toacquire or increase their ownership of common units. Eligible employees who enroll in the Unit Purchase Plan may elect to have a designated whole percentage(ranging from 1% to 15%) of their eligible compensation for each pay period withheld for the purchase of common units. A maximum of 1,000,000 common unitsmay be delivered under the Unit Purchase Plan, subject to adjustment for a recapitalization, split, reorganization or similar event pursuant to the terms of the UnitPurchase Plan. The purpose of the Unit Purchase Plan is to promote our interests by providing employees of the General Partner and its affiliates a cost-effectiveprogram to enable them to acquire or increase their ownership of common units and to provide a means whereby such individuals may develop a sense ofproprietorship and personal involvement in our development and financial success, and to encourage them to devote their best efforts to our business, therebyadvancing our interests. As of December 31, 2017 , 154,961 common units have been delivered under the Unit Purchase Plan.72Table of ContentsSummary Compensation TableThe following table summarizes the compensation of our NEOs for the years ended 2017 , 2016 and 2015 . Mr. Kanvik was not an NEO in 2016 or 2015.Name and PositionYear Salary($) Bonus($) (1) StockAwards($) (2)OptionAwards($)Non-EquityIncentiveCompensation($)All OtherCompensation($) (3) Total($)Mark A. HurleyChief Executive Officer2017448,750400,000———42,991891,7412016445,000475,000———43,075963,0752015442,500450,000———43,929936,429Alex G. StallingsChief Financial Officer andSecretary2017324,450160,000155,870——76,541716,8612016319,800165,000142,528——71,237698,5652015317,850145,000120,187——63,228646,265Jeffery A. SpeerChief Operating Officer2017258,333187,000160,904——73,424679,6612016237,000160,000175,784——65,310638,0942015226,105135,000106,951——59,535527,591Brian L. MeltonChief Commercial Officer2017242,250110,000110,611——60,578523,4392016237,000155,000104,520——57,005553,5252015235,250155,000101,858——45,154537,262Joel W. KanvikChief Legal Officer2017260,000256,00090,505——29,401635,906_______________(1)In connection with his appointment as Chief Commercial Officer, Mr. Melton received a signing bonus, of which $45,000 was paid in both 2015 and 2016. In connection with hisappointment as Chief Legal Officer, Mr. Kanvik received a signing and relocation bonus, of which $115,000 was paid in 2017.(2)Dollar amounts represent the grant date fair value of awards granted in each year with respect to phantom unit grants under the LTIP. See Note 14 to our consolidated financial statementsfor assumptions used in calculating these amounts.(3)We provide distribution equivalent rights (“DERs”) under the LTIP, auto allowances, reimbursement of certain deductibles and co-pays for medical expenses and discretionary matchingand profit sharing contributions to our 401(k) plan to our NEOs. In 2017 , payments of $35,820, $39,178, $27,072 and $5,506 related to the DERs were made to Messrs. Stallings, Speer,Melton and Kanvik, respectively. In 2017 , auto allowances of $10,800 were paid each to Messrs. Hurley, Stallings, Speer, Melton and Kanvik. In 2017 , matching and profit sharingcontributions to our 401(k) plan of $26,910, $26,910, $22,204, $19,348 and $10,578 were made for Messrs. Hurley, Stallings, Speer, Melton and Kanvik, respectively.Pension BenefitsWe do not have a pension plan in which our named executive officers are eligible to participate.Non-Qualified Deferred CompensationWe do not have a non-qualified deferred compensation plan.73Table of ContentsGrants of Plan-Based Awards for Fiscal Year 2017The following tables provide information concerning each grant of an award made to a NEO during 2017 , including, but not limited to, awards made underour General Partner’s LTIP. Estimated Future PaymentsUnder Non-Equity Incentive PlanAwards Estimated Future Payouts UnderEquity Incentive Plan Awards NameGrantDateThreshold($)Target($)Maximum($) Threshold($)Target($)Maximum($)All OtherUnitAwards:Numberof Units(#) (1)(2)All Other UnitAwards: Numberof SecuritiesUnderlyingOptions (#)Exercise orBase Price ofOptionAwards($/Sh)GrantDate FairValue ofUnit andOptionAwards($)Alex G.StallingsMarch9,2017——— ———21,800——155,870JeffreyA. SpeerMarch9,2017——— ———22,504——160,904Brian L.MeltonMarch9,2017——— ———15,471——110,611Joel W.KanvikMarch9,2017——— ———12,658——90,505____________________(1)This amount represents grants of phantom units under our General Partner’s LTIP. See Note 14 to our consolidated financial statements. (2)No awards were granted to Mr. Hurley in 2017 .Outstanding Equity Awards at Fiscal Year-End 2017The following tables provide information concerning all outstanding equity awards made to a NEO as of December 31, 2017 , including, but not limited to,awards made under our General Partner’s LTIP. Option Awards Stock AwardsNameNumber ofSecuritiesUnderlyingUnexercisedOptions (#)ExercisableNumber ofSecuritiesUnderlyingUnexercisedOptions(#)UnexercisableEquityIncentivePlanAwards:Number ofSecuritiesUnderlyingUnexercisedUnearnedOptions (#)OptionExercisePrice($)OptionExpirationDate Numberof UnitsThatHaveNotVested(#)MarketValue ofUnitsThatHaveNotVested($)EquityIncentivePlanAwards:Number ofUnearnedUnits orOtherRightsThat HaveNotVested (#) EquityIncentivePlanAwards:Market orPayoutValue ofUnearnedUnits orOtherRightsThat HaveNot Vested($) (1)(5)Alex G. Stallings————— ——21,800(2) 111,180————— ——29,880(3) 152,388————— ——15,528(4) 79,193Jeffery A. Speer————— ——22,504(2) 114,770————— ——26,892(3) 137,149————— ——13,818(4) 70,472Brian L. Melton————— ——15,471(2) 78,902————— ——21,912(3) 111,751————— ——13,160(4) 67,116Joel W. Kanvik————— ——12,658(2) 64,556____________________(1)Market value of awards is calculated as the product of the closing market price of $5.10 of the Partnership’s common units at December 29, 2017, and the number of phantom unitsoutstanding at December 31, 2017 .(2)Represents phantom units granted in 2017 under our General Partner’s LTIP. These phantom units will vest on January 1, 2020. All of the distribution equivalent rights associated withthese phantom units are currently payable.(3)Represents phantom units granted in 2016 under our General Partner’s LTIP. These phantom units will vest on January 1, 2019. All of the distribution equivalent rights associated withthese phantom units are currently payable.(4)Represents phantom units granted in 2015 under our General Partner’s LTIP. These phantom units vested on January 1, 2018. All of the distribution equivalent rights associated with thesephantom units are currently payable.(5)Mr. Hurley held no equity awards as of December 31, 2017 .74Table of ContentsOption Exercises and Stock Vested for Fiscal Year 2017The following table provides information regarding each vesting during 2017 of phantom units held by our NEOs. Our NEOs have not been granted stockoption awards. Stock Awards (1) NameNumber of SharesAcquired onVesting (#) ValueRealized onVesting ($) Mark A. Hurley100,000 575,000(2) Alex G. Stallings17,089 120,477(3) Jeffrey A. Speer16,538 116,593(3) Brian L. Melton12,679 89,387(3) ____________________(1)No awards vested in 2017 for Mr. Kanvik. (2)This value is based on the average of the high and low trading prices of our common unit on September 21, 2017, the date of issuance of such common units.(3)This value is based on the average of the high and low trading prices of our common units on January 17, 2017, the date of issuance of such common units.Director Compensation for Fiscal Year 2017NameFeesEarned orPaid inCash($)StockAwards (3)($)OptionAwards($)Non-EquityIncentive PlanCompensation($)Change inPension ValueandNonqualifiedDeferredCompensationEarnings($)All OtherCompensation($)Total($)Duke R. Ligon131,11755,000————186,117Steven M. Bradshaw131,11745,000————176,117John A. Shapiro131,11745,000————176,117Donald M. Brooks (1)(2)———————Edward D. Brooks (1)———————Jimmy A. Langdon (1)———————Robert H. Lampton (1)———————William W. Lampton (1)———————____________________(1)Affiliated with Ergon.(2)Mr. Brooks resigned from the Board in February 2018.(3)These amounts represent the grant date fair value of restricted and unrestricted units awarded under the LTIP. The grant date fair value of these awards is computed in accordance withASC 718 - Compensation—Stock Compensation . See Note 14 to our consolidated financial statements for assumptions used in calculating these amounts. Directors who are not officers or employees of any controlling entity or their affiliates receive compensation for attending meetings of the Board andcommittees thereof. Such directors receive the following:(i)$75,000 per year as an annual retainer fee paid in cash;(ii)$5,000 per year for each Board committee on which such director serves (except that the chairperson of each committee will receive $10,000per year for serving as chairperson of such committee), payable in unrestricted common units;(iii)$10,000 per year if Chairman of the Board, payable in unrestricted common units;(iv)$2,000 per diem for each Board or committee meeting attended;(v)5,000 restricted units upon becoming a director, vesting in one-third increments over a three-year period;(vi)$25,000 of restricted units based on the grant date fair value on each anniversary of becoming a director, vesting in one-third increments overa three-year period;(vii)reimbursement for out-of-pocket expenses associated with attending Board or committee meetings; and(viii)director and officer liability insurance coverage.75Table of ContentsIn addition, each director is fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law.Pay Ratio Disclosure We believe our executive compensation program must be consistent and internally equitable to motivate our employees to perform in ways that enhanceshareholder value. We are committed to internal pay equity, and the compensation committee monitors the relationship between the pay of our executive officersand the pay of our non-executive employees. The compensation committee reviewed a comparison of our Chief Executive Officer’s (“CEO”) annual totalcompensation during fiscal year 2017 to that of our median compensated employee for the same period. For purposes of identifying our median compensatedemployee we calculated the total of the following amounts based on our payroll records:•salary received;•annual bonus;•auto allowance;•company-paid group term life insurance;•fair market value of vesting stock units; and•company-paid Unit Purchase Plan discount.We identified all active employees as of December 31, 2017 . We then determined our median compensated employee by calculating the sum of the amountsdescribed above for each of our employees, which we annualized for any employee who did not work for the entire year. We ranked the employees from highest tolowest and selected the median employee from this listing. We then calculated the annual total compensation of the median compensated employee and the CEO inaccordance with SEC requirements.Based on our calculation as described above, the 2017 annual total compensation of our CEO was $891,741, the 2017 annual total compensation of ourmedian compensated employee was $70,584 and the ratio of these amounts was 12.6:1. This pay ratio is a reasonable estimate calculated in a manner consistentwith SEC rules based on our payroll and employment records and the methodology described above.Compensation Committee Interlocks and Insider Participation During the year ended December 31, 2017 , the compensation committee of our General Partner was comprised of Messrs. Ligon, Bradshaw and Shapiro(chairman). No member of the compensation committee was an officer or employee of our General Partner or had any relationship requiring disclosure under Item404 of Regulation S-K.Compensation Committee Report The compensation committee of the General Partner of Blueknight Energy Partners, L.P. has reviewed and discussed the Compensation Discussion andAnalysis section of this report as required by Item 402(b) of Regulation S-K with management of the General Partner of Blueknight 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 John A. Shapiro, Committee ChairSteven M. BradshawDuke R. LigonItem 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.Security Ownership of Certain Beneficial Owners and Management The following table sets forth the beneficial ownership of our units as of March 1, 2018 held by:76Table of Contents•each person or group of persons who beneficially own 5% or more of the then outstanding common units or Preferred Units;•all of the directors of our General Partner;•each NEO of our General Partner; and•all current directors and NEOs 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 ownedby them, subject to community property laws where applicable. Percentage of total common and Preferred Units beneficially owned is based on 40,310,272common units and 35,125,202 Preferred Units outstanding as of March 1, 2018 .Name of Beneficial Owner (1)CommonUnitsBeneficiallyOwnedPercentage ofCommonUnitsBeneficiallyOwned PreferredUnitsBeneficiallyOwnedPercentage ofPreferredUnitsBeneficiallyOwned Percentage ofTotalCommon and PreferredUnitsBeneficiallyOwnedErgon Asphalt & Emulsions, Inc. (2)2,745,8376.8% 18,312,96852.1% 27.9%Mark A. Hurley (5)362,999* —— *Alex G. Stallings (3)(5)97,834* 20,000* *Jeffery A. Speer (5)52,031* —— *Joel W. Kanvik3,982* —— *Brian L. Melton (5)22,371* 400* *Duke R. Ligon (4)58,101* —— *Steven M. Bradshaw (4)39,356* —— *John A. Shapiro (4)37,766* —— *W.R. “Lee” Adams (2)(6)50,000* —— *Edward D. Brooks (2)(6)—— —— —Jimmy A. Langdon (2)(6)—— —— —Robert H. Lampton (2)(6)150,000* —— *William W. Lampton (2)(6)103,350* —— *Blueknight Energy Holding, Inc. (7)—— 2,488,7897.1% 3.3%CB-Blueknight, LLC (8)—— 2,488,7897.1% 3.3%MSD Capital, L.P. (9)240,000* 1,907,7115.4% 2.8%Swank Capital, L.L.C. (10)4,430,92911.0% 2,269,7296.5% 8.9%Neuberger Berman Group LLC (11)6,175,10815.3% —— 8.2%DG Capital Management, Inc. (12)3,175,9477.9% —— 4.2%Clearbridge Investments, LLC (13)3,278,8948.1% —— 4.3%Oppenheimer Funds, Inc. (14)2,825,4827.0% —— 3.7%All current executive officers anddirectors as a group (14 persons)1,037,2122.6% 20,400* 1.4%_______________*Less than 1%.(1)Unless otherwise indicated, the address for all beneficial owners in this table is 6060 American Plaza, Suite 600, Tulsa, Oklahoma 74135.(2)Ergon Asphalt & Emulsions, Inc. owns Ergon Asphalt Holdings, LLC. The address for Ergon is 2829 Lakeland Drive, Suite 2000, Jackson, Mississippi 39215. Ergon Asphalt Holdings,LLC owns 100% of Blueknight GP Holding, LLC, which owns the membership interest in our General Partner. (3)Mr. Stallings has pledged as collateral to a bank 62,054 common units and 20,000 Preferred Units.(4)Does not include unvested restricted units granted under the Long-Term Incentive Plan, none of which will vest within 60 days of the date hereof.(5)Does not include unvested phantom units granted under the Long-Term Incentive Plan, none of which will vest within 60 days of the date hereof.(6)Messrs. Adams, Brooks, Langdon, R. Lampton and W. Lampton are affiliated with Ergon.(7)Blueknight Energy Holding, Inc. is a subsidiary of Vitol. The address for Vitol is 2925 Richmond Avenue, 11th Floor, Houston, Texas 77098. Blueknight Energy Holding, Inc. previouslyowned 50% of Blueknight GP Holding, LLC, which owns the membership interest in our General Partner, but this ownership was terminated effective October 6, 2016.(8)CB-Blueknight, LLC is a subsidiary of Charlesbank. The address for Charlesbank is 200 Clarendon Street, 54th Floor, Boston, Massachusetts. CB-Blueknight, LLC previously owned50% of Blueknight GP Holding, LLC, which owns the membership interest in our General Partner, but this ownership was terminated effective October 6, 2016.77Table of Contents(9)Based on a Schedule 13G/A filed January 30, 2018, by MSD Partners, L.P. with the SEC. The filing was made jointly with MSD Torchlight Partners, L.P., MSD Partners (GP), LLC,Glenn R. Fuhrman, John C. Phelan and Marc R. Lisker, and reported that they have shared voting power with respect to 240,000 common units and 1,907,711 Preferred Units. Theiraddress as reported in such Schedule 13G/A is 645 Fifth Avenue, 21st Floor, New York, New York 10022.(10)Based on Schedules 13G/A filed February 14, 2018, with the SEC by Swank Capital, LLC. The filings were made jointly with Cushing Asset Management, LP and Jerry V. Swank, andreport that they have shared voting power with respect to 4,430,929 common units and 2,269,729 Preferred Units. Their address as reported in such Schedules 13G/A is 8117 Preston Road,Suite 440, Dallas, Texas 75225.(11)Based on a Schedule 13G/A filed February 15, 2018, by Neuberger Berman Group LLC with the SEC. The filing was made jointly with Neuberger Berman Investment Advisers LLC, andreports that they have shared voting power with respect to 5,918,530 common units and shared dispositive power with respect to 6,175,108 common units. Their address as reported in suchSchedule 13G/A is 1290 Avenue of the Americas, New York, New York 10104.(12)Based on a Schedule 13G/A filed January 25, 2018, by DG Capital Management, LLC with the SEC. The filing was made jointly with Dov Gertzulin, and reports that they have sharedvoting power with respect to 3,175,947 common units. Their address as reported in such Schedule 13G/A is 460 Park Avenue, 22nd Floor, New York, New York 10022.(13)Based on a Schedule 13G filed February 14, 2018, by Clearbridge Investments, LLC with the SEC. Their address as reported in such Schedule 13G is 620 8th Avenue, New York, NewYork 10018.(14)Based on a Schedule 13G filed February 6, 2018, by Oppenheimer Funds, Inc. with the SEC. Their address as reported in such Schedule 13G is 225 Liberty Street, New York, New York10281.Securities Authorized for Issuance under Equity Compensation Plans (as of March 1, 2018 )Equity Compensation Plan Information (1) (a)Number of securities tobe issued upon exercise of outstandingoptions, warrants and rights (b)Weighted-average exerciseprice of outstanding options, warrants and rights (c)Number of securitiesremaining available for future issuance under equitycompensation plans (excluding securities reflected in column (a))Equity compensation plansapproved by security holders 702,548 $— 2,387,563Equity compensation plans notapproved by security holders N/A N/A N/ATotal 702,548 $— 2,387,563________________(1)Our General Partner has adopted and maintains the LTIP for employees, consultants and directors of our General Partner and its affiliates who perform services for us. An aggregate of679,943 phantom units that have been granted to our executive officers and other employees remain outstanding and have not yet vested. Excluding phantom unit grants, the responses areas follows: (a) 22,605, (b) $0 and (c) 3,067,506. No value is shown in column (b) of the table because the phantom units and restricted units do not have an exercise price. For moreinformation about the LTIP, please see “Item 11-Executive Compensation-Compensation Discussion and Analysis-Long-Term Incentive Plan.” In addition, on June 23, 2014, ourunitholders approved the Unit Purchase Plan. A maximum of 1,000,000 common units may be delivered under the Unit Purchase Plan, subject to adjustment for a recapitalization, split,reorganization or similar event pursuant to the terms of the Unit Purchase Plan. As of March 1, 2018, 170,743 common units had been delivered under the Unit Purchase Plan. For moreinformation about the Unit Purchase Plan, please see “Item 11-Executive Compensation-Compensation Discussion and Analysis-Unit Purchase Plan.”Item 13. Certain Relationships and Related Transactions, and Director Independence.Distributions and Payments to Our General Partner and Its Affiliates Our General Partner is owned by Ergon, which also owns 18,312,968 of the 35,125,202 outstanding Preferred Units and 3,049,187 of the 40,310,272outstanding common units, representing an aggregate 28.3% limited partner interest in us as of March 1, 2018 . In addition, our General Partner owns a 1.6%general partner interest in us and the incentive distribution rights. For a description of the distributions and payments our General Partner is entitled to receive, see“Item 5-Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities-General Partner Interest and IncentiveDistribution Rights.”Agreements with Related Parties and AffiliatesFor information regarding material agreements with related parties and affiliates, see Note 13 to our consolidated financial statements.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 alllosses, claims, damages or similar events:78Table of Contents•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 orany 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 anyobligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against usand expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under ourpartnership agreement. We and our General Partner have also entered into separate indemnification agreements with each of the directors and officers of our General Partner. Theterms of the indemnification agreements are consistent with the terms of the indemnification provided by our partnership agreement and our General Partner’slimited liability company agreement. The indemnification agreements also provide that we and our General Partner must advance payment of certain expenses tosuch 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 isultimately determined that the indemnitee is not entitled to indemnification.Approval and Review of Related-Party Transactions If we contemplate entering into a transaction, other than a routine or ordinary course of business transaction, in which a related person will have a direct orindirect material interest, the proposed transaction is submitted for consideration to the Board of our General Partner or to our management, as appropriate. If theBoard is involved in the approval process, it determines whether to refer the matter to the conflicts committee of the Board, as constituted under our limitedpartnership agreement. If a matter is referred to the conflicts committee, it obtains information regarding the proposed transaction from management anddetermines whether to engage independent legal counsel or an independent financial advisor to advise the members of the committee regarding the transaction. Ifthe 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 towhether the transaction is fair and reasonable to us and to our unitholders.Director IndependencePlease see “ Item 10-Directors, Executive Officers and Corporate Governance ” of this report for a discussion of director independence matters.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 LLPfor independent auditing, tax and related services for each of the last two fiscal years: Year ended December 31, 2016 2017Audit fees (1) $817,822 $671,164Audit-related fees (2) — —Tax fees (3) 238,697 299,261All 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 internalcontrols over financial reporting, (b) the review of our quarterly financial statements and (c) those services normally provided in connection with statutory and regulatory filings orengagements, including comfort letters, consents and other services related to SEC matters.(2)Audit-related fees represent amounts billed for each of the years presented for assurance and related services that are reasonably related to the performance of the annual audit or quarterlyreviews.79Table of Contents(3)Tax fees represent amounts billed for each of the years presented for professional services rendered in connection with tax compliance, tax advice and tax planning. This categoryprimarily includes services relating to the preparation of unitholder annual K-1 statements.(4)All other fees represent amounts billed for 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 ofsuch services do not impair the auditor’s independence. Under our pre-approval policy, the audit committee is informed of each engagement of the independentauditor to provide services under the policy. The audit committee of our General Partner has approved the use of PricewaterhouseCoopers LLP as our independentprincipal accountant.80Table of ContentsPART IV. FINANCIAL INFORMATIONItem 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 theconsolidated financial statements or notes thereto(3)ExhibitsINDEX TO EXHIBITS ExhibitNumberDescription2.1Contribution Agreement, dated July 19, 2016, among Blueknight Energy Partners, L.P., Blueknight Terminal Holding, L.L.C., Ergon Asphalt &Emulsions, Inc., Ergon Terminaling, Inc. and Ergon Asphalt Holdings, LLC (filed as Exhibit 2.1 to the Partnership’s Current Report on Form 8-K,filed on July 20, 2016, and incorporated herein by reference).3.1Amended and Restated Certificate of Blueknight Energy Partners, L.P. (the “Partnership”), dated November 19, 2009, but effective as of December1, 2009 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed on November 25, 2009, and incorporated herein by reference).3.2Fourth Amended and Restated Agreement of Limited Partnership of the Partnership, dated September 14, 2011 (filed as Exhibit 3.1 to thePartnership’s Current Report on Form 8-K, filed on September 14, 2011, and incorporated herein by reference).3.3Amended and Restated Certificate of Formation of the General Partner, dated November 19, 2009, but effective as of December 1, 2009 (filed asExhibit 3.2 to the Partnership’s Current Report on Form 8-K, filed on November 25, 2009, and incorporated herein by reference).3.4Second Amended and Restated Limited Liability Company Agreement of the General Partner, dated December 1, 2009 (filed as Exhibit 3.2 to thePartnership’s Current Report on Form 8-K, filed on December 7, 2009, and incorporated herein by reference).4.1Specimen Unit Certificate (included in Exhibit 3.2).4.2Registration Rights Agreement, dated as of October 25, 2010, by and among Blueknight Energy Partners, L.P., Blueknight Energy Holding, Inc.and CB-Blueknight, LLC (filed as Exhibit 4.1 to the Partnership’s Current Report on Form 8-K, filed on October 25, 2010, and incorporated hereinby reference).4.3Specimen Right Certificate (filed as Exhibit 4.2 to the Partnership’s Current Report on Form 8-K, filed on September 27, 2011, and incorporatedherein by reference).4.4Rights Agent Agreement, dated as of September 27, 2011, between Blueknight Energy Partners, L.P. and American Stock Transfer & TrustCompany, LLC, as rights agent (filed as Exhibit 4.1 to the Partnership’s Current Report on Form 8-K, filed on September 27, 2011, andincorporated herein by reference).4.5Specimen Series A Preferred Unit Certificate (filed as Exhibit 4.3 to the Partnership’s Current Report on Form 8-K, filed on September 27, 2011,and incorporated herein by reference).4.6Registration Rights Agreement, dated October 5, 2016, by and among Blueknight Energy Partners, L.P., Ergon Asphalt & Emulsions, Inc., ErgonTerminaling, Inc. and Ergon Asphalt Holdings, LLC (filed as Exhibit 4.1 to the Partnership’s Current Report on Form 8-K, filed on October 5,2016, and incorporated herein by reference).4.7Amended and Restated Registration Rights Agreement, dated December 1, 2017, by and among Blueknight Energy Partners, L.P., Ergon Asphalt& Emulsions, Inc., Ergon Terminaling, Inc. and Ergon Asphalt Holdings, LLC (filed as Exhibit 4.1 to the Partnership’s Current Report on Form 8-K, filed on December 1, 2017, and incorporated herein by reference).10.1#Operating and Maintenance Agreement, dated August 17, 2011 to be effective as of July 1, 2011, by and between BKEP Pipeline, L.L.C. and VitolMidstream LLC (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed on August 18, 2011, and incorporated herein byreference).10.2#Crude Oil Storage Services Agreement, effective as of May 1, 2010, by and between BKEP Crude, LLC and Vitol Inc. (filed as Exhibit 10.54 tothe Partnership’s Annual Report on Form 10-K, filed on March 30, 2010, and incorporated herein by reference).10.3#First Amendment to Crude Oil Storage Services Agreement, dated to be effective as of March 1, 2013, by and between BKEP Crude, LLC andVitol Inc (filed as Exhibit 10.13 to the Partnership’s Quarterly Report on Form 10-Q, filed on March 14, 2013, and incorporated by reference).10.4#Second Amendment to Crude Oil Storage Services Agreement, effective May 1, 2015, by and between BKEP Crude, LLC and Vitol, Inc. (filed asExhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed on January 26, 2015, and incorporated herein by reference).81Table of Contents10.5Third Amendment to Crude Oil Storage Services Agreement, dated August 12, 2016 but effective as of May 1, 2017 (filed as Exhibit 10.1 to thePartnership’s Current Report on Form 8-K, filed on August 19, 2016, and incorporated herein by reference).10.6†Blueknight Energy Partners G.P., L.L.C. Long-Term Incentive Plan (as amended and restated effective April 29, 2014) (filed as Exhibit 10.2 to thePartnership’s Current Report on Form 8-K, filed on June 27, 2014, and incorporated herein by reference).10.7*†First Amendment to the Blueknight Energy Partners G.P., L.L.C. Long-Term Incentive Plan10.8†Form of Phantom Unit Agreement (for pre-2018 grants) (filed as Exhibit 10.19 to the Partnership’s Annual Report on Form 10-K, filed on March16, 2011, and incorporated herein by reference).10.9*†Form of Phantom Unit Agreement (for grants during and after 2018)10.10†Form of Director Restricted Common Unit Agreement (for grants during and before 2017) (filed as Exhibit 10.2 to the Partnership’s CurrentReport on Form 8-K, filed on December 23, 2008, and incorporated herein by reference).10.11*†Form of Director Restricted Common Unit Agreement (for post-2017 grants)10.12†Employee Phantom Unit Agreement, dated October 4, 2012, between Mark Hurley and Blueknight Energy Partners G.P., L.L.C. (filed as Exhibit10.2 to the Partnership’s Current Report on Form 8-K/A, filed on October 4, 2012, and incorporated herein by reference).10.13†Form of Employment Agreement (filed as Exhibit 10.6 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-141196), filed onMay 25, 2007, and incorporated herein by reference).10.14†Form of Indemnification Agreement (filed as Exhibit 10.7 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-141196), filed onMay 25, 2007, and incorporated herein by reference).10.15†Employment Agreement, dated October 4, 2012, between Mark Hurley and BKEP Management, Inc. (filed as Exhibit 10.1 to the Partnership’sCurrent Report on Form 8-K/A, filed on October 4, 2012, and incorporated herein by reference).10.16Mutual Easement Agreement, dated as of April 7, 2009 to be effective as of 11:59 PM CDT March 31, 2009, among SemCrude, L.P., SemGroupEnergy 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 onApril 10, 2009, and incorporated herein by reference).10.17Pipeline 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 onForm 8-K, filed on April 10, 2009, and incorporated herein by reference).10.18†Blueknight Energy Partners, L.P. Employee Unit Purchase Plan, dated to be effective as of June 23, 2014 (filed as Exhibit 10.1 to the Partnership’sCurrent Report on Form 8-K, filed on June 27, 2014, and incorporated herein by reference).10.19Preferred Unit Repurchase Agreement, dated July 19, 2016, among Blueknight Energy Partners, L.P., CB-Blueknight, LLC and Blueknight EnergyHolding, Inc. (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed on July 20, 2016, and incorporated herein by reference).10.20Amended and Restated Credit Agreement, dated as of May 11, 2017, by and among Blueknight Energy Partners, L.P. Wells Fargo Bank, NationalAssociation, as Administrative Agent, and the several lenders from time to time party thereto (filed as Exhibit 10.1 to the Partnership’s CurrentReport on Form 8-K, filed May 12, 2017 (Commission File No. 001-33503), and incorporated herein by reference).10.21#Storage, Throughput and Handling Agreement, dated October 5, 2016, by and among BKEP Materials, L.L.C., BKEP Terminalling, L.L.C., BKEPAsphalt, L.L.C., and Ergon Asphalt & Emulsions, Inc. (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed on October 5,2016, and incorporated herein by reference).10.22Omnibus Agreement, dated October 5, 2016, by and among Ergon Asphalt & Emulsions, Inc., Blueknight Energy Partners G.P., L.L.C.,Blueknight Energy Partners, L.P., Blueknight Terminalling, L.L.C., BKEP Materials, L.L.C. and BKEP Asphalt, L.L.C. (filed as Exhibit 10.2 tothe Partnership’s Current Report on Form 8-K, filed on October 5, 2016, and incorporated herein by reference).10.23#Facilities Lease Agreement, dated May 18, 2009, by and between BKEP Materials, L.L.C, BKEP Asphalt, L.L.C and Ergon Asphalt & Emulsions,Inc. (filed as Exhibit 10.6 to the Partnership’s Quarterly Report on Form 10-Q, filed on November 2, 2016, and incorporated herein by reference).10.24#Master Facilities Lease Agreement, dated November 11, 2010, by and between BKEP Materials, L.L.C, BKEP Asphalt, L.L.C and Ergon Asphalt& Emulsions, Inc. (filed as Exhibit 10.7 to the Partnership’s Quarterly Report on Form 10-Q, filed on November 2, 2016, and incorporated hereinby reference).10.25#Second Amendment to Master Facilities Lease Agreement, dated July 2, 2012, by and between BKEP Materials, L.L.C, BKEP Asphalt, L.L.C andErgon Asphalt & Emulsions, Inc. (filed as Exhibit 10.8 to the Partnership’s Quarterly Report on Form 10-Q, filed on November 2, 2016, andincorporated herein by reference).82Table of Contents10.26*Partial Lease Termination No. 5 to Master Facilities Lease Agreement, dated March 7, 2018, by and between BKEP Materials, L.L.C, BKEPAsphalt, L.L.C and Ergon Asphalt & Emulsions, Inc.10.27*Fifth Amendment to Master Facilities Lease Agreement, dated March 7, 2018, by and between BKEP Materials, L.L.C, BKEP Asphalt, L.L.C andErgon Asphalt & Emulsions, Inc.21.1*List of Subsidiaries of Blueknight Energy Partners, L.P.23.1*Consent of PricewaterhouseCoopers, L.L.P.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 theSarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”101**The following financial information from Blueknight Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2017,formatted in XBRL (eXtensible Business Reporting Language): (i) Document and Entity Information; (ii) Consolidated Balance Sheets as ofDecember 31, 2016 and 2017; (iii) Consolidated Statements of Operations for the years ended December 31, 2015, 2016 and 2017; (iv)Consolidated Statement of Changes in Partners’ Capital for the years ended December 31, 2015, 2016 and 2017; (v) Consolidated Statements ofCash Flows for the years ended December 31, 2015, 2016 and 2017; and (vi) Notes to Consolidated Financial Statements. _________*Filed herewith.**Furnished herewith#Certain portions of this exhibit are subject to a request for confidential treatment by the Securities and Exchange Commission. The omitted portions have been separately filed with theSecurities and Exchange Commission.†As required by Item 15(a)(3) of Form 10-K, this exhibit is identified as a compensatory plan or arrangement.83Table of ContentsSIGNATURES 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 itsbehalf by the undersigned thereunto duly authorized. BLUEKNIGHT ENERGY PARTNERS, L.P. By:Blueknight Energy Partners G.P., L.L.C. Its General Partner March 8, 2018 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 registrantand in the capacities indicated on March 8, 2018 . 84Table of ContentsSignature Title /s/ Mark A. HurleyChief Executive Officer and Director(Principal Executive Officer)Mark A. Hurley /s/ Alex G. StallingsChief Financial Officer and Secretary(Principal Financial Officer)Alex G. Stallings /s/ James R. GriffinChief Accounting Officer(Principal Accounting Officer)James R. Griffin /s/ Duke R. LigonDirectorDuke R. Ligon /s/ Steven M. BradshawDirectorSteven M. Bradshaw /s/ John A. ShapiroDirectorJohn A. Shapiro /s/ W.R. “Lee” AdamsDirectorW.R. “Lee” Adams /s/ Edward D. BrooksDirectorEdward D. Brooks /s/ Jimmy A. LangdonDirectorJimmy A. Langdon /s/ Robert H. LamptonDirectorRobert H. Lampton /s/ William W. LamptonDirectorWilliam W. Lampton 85Table of ContentsItem 16. Form 10-K Summary.None.86Table of ContentsINDEX TO BLUEKNIGHT ENERGY PARTNERS, L.P. CONSOLIDATED FINANCIAL STATEMENTS Report of Independent Registered Public Accounting FirmF-1Consolidated Balance Sheets as of December 31, 2016 and 2017F-3Consolidated Statements of Operations for the Years Ended December 31, 2015, 2016 and 2017F-4Consolidated Statement of Changes in Partners’ Capital for the Years Ended December 31, 2015, 2016 and 2017F-5Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2016 and 2017F-6Notes to the Consolidated Financial StatementsF-887Table of ContentsReport of Independent Registered Public Accounting FirmTo the Board of Directors of Blueknight Energy Partners G.P., L.L.C., the general partner of Blueknight Energy Partners, L.P. and unit holders of BlueknightEnergy Partners, L.P.Opinions on the Financial Statements and Internal Control over Financial ReportingWe have audited the accompanying consolidated balance sheets of Blueknight Energy Partners, L.P. and its subsidiaries as of December 31, 2017 and 2016, andthe related consolidated statements of operations, changes in partners’ capital, and cash flows for each of the three years in the period ended December 31, 2017,including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Partnership's internal control overfinancial reporting as of December 31, 2017 based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee ofSponsoring Organizations of the Treadway Commission (COSO).In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Partnership as ofDecember 31, 2017 and 2016, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2017, inconformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership did not maintain, in all materialrespects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework(2013) issued by the COSO because a material weakness in internal control over financial reporting related to maintaining effective controls over the presentationof transactions within the consolidated statement of cash flows existed as of that date.A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that amaterial misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. The material weakness referred to above isdescribed in Management's Report on Internal Control Over Financial Reporting appearing under Item 9A. We considered this material weakness in determiningthe nature, timing, and extent of audit tests applied in our audit of the 2017 consolidated financial statements, and our opinion regarding the effectiveness of thePartnership’s internal control over financial reporting does not affect our opinion on those consolidated financial statements.Basis for OpinionsThe Partnership's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and forits assessment of the effectiveness of internal control over financial reporting, included in management's report referred to above. Our responsibility is to expressopinions on the Partnership’s consolidated financial statements and on the Partnership's internal control over financial reporting based on our audits. We are apublic accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent withrespect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commissionand the PCAOB.We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonableassurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internalcontrol over financial reporting was maintained in all material respects.Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financialstatements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidenceregarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significantestimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financialreporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing andevaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as weconsidered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.Definition and Limitations of Internal Control over Financial ReportingF-1Table of ContentsA company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and thepreparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financialreporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactionsand dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financialstatements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance withauthorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorizedacquisition, use, or disposition of the company’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 ofeffectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance withthe policies or procedures may deteriorate./s/ PricewaterhouseCoopers LLPTulsa, OklahomaMarch 8, 2018We have served as the Partnership’s auditor since 2007.F-2Table of ContentsBLUEKNIGHT ENERGY PARTNERS, L.P.CONSOLIDATED BALANCE SHEETS(in thousands, except per unit data) As of December 31, 2016 2017ASSETS Current assets: Cash and cash equivalents$3,304 $2,469Accounts receivable, net of allowance for doubtful accounts of $49 and $28 at December 31, 2016and 2017, respectively7,544 7,589Receivables from related parties, net of allowance for doubtful accounts of $0 at both dates1,860 3,070Prepaid insurance1,578 2,009Other current assets7,934 8,438Total current assets22,220 23,575Property, plant and equipment, net of accumulated depreciation of $292,117 and $316,591 atDecember 31, 2016 and 2017, respectively307,334 296,069Assets held for sale, net of accumulated depreciation of $3,041 at December 31, 20164,237 —Investment in unconsolidated affiliate20,561 —Goodwill4,746 3,870Debt issuance costs, net2,050 4,442Intangibles and other assets, net14,515 12,913Total assets$375,663 $340,869LIABILITIES AND PARTNERS’ CAPITAL Current liabilities: Accounts payable$3,174 $4,439Accounts payable to related parties1,053 2,268Accrued interest payable413 694Accrued property taxes payable2,531 2,432Unearned revenue2,350 2,393Unearned revenue with related parties383 551Accrued payroll6,358 6,119Other current liabilities4,279 4,747Total current liabilities20,541 23,643Long-term unearned revenue with related parties640 1,052Long-term interest rate swap liabilities1,947 225Other long-term liabilities2,959 3,673Long-term debt324,000 307,592Commitments and contingencies (Note 17) Partners’ capital: Preferred Units (35,125,202 units issued and outstanding at both dates)253,923 253,923Common unitholders (38,003,397 and 40,158,342 units issued and outstanding at December 31,2016 and 2017, respectively)471,180 454,358General partner interest (1.7% and 1.6% interest at December 31, 2016 and 2017, respectively, with1,225,409 general partner units outstanding at both dates)(699,527) (703,597)Total partners’ capital25,576 4,684Total liabilities and partners’ capital$375,663 $340,869The accompanying notes are an integral part of these consolidated financial statements.F-3Table of ContentsBLUEKNIGHT ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OF OPERATIONS(in thousands, except per unit data) Year ended December 31, 2015 2016 2017Service revenue: Third-party revenue$137,415 $126,215 $113,772Related-party revenue39,103 30,211 56,688Product sales revenue: Third-party revenue3,511 20,968 11,479Total revenue180,029 177,394 181,939Costs and expenses: Operating expense127,974 111,091 123,805Cost of product sales3,231 14,130 8,807General and administrative expense18,976 20,029 17,112Asset impairment expense21,996 25,761 2,400Total costs and expenses172,177 171,011 152,124Gain (loss) on sale of assets6,137 108 (975)Operating income13,989 6,491 28,840Other income (expense): Equity earnings in unconsolidated affiliate3,932 1,483 61Gain on sale of unconsolidated affiliate— — 5,337Interest expense (net of capitalized interest of $184, $41, and $18, respectively)(11,202) (12,554) (14,027)Income (loss) before income taxes6,719 (4,580) 20,211Provision for income taxes323 260 166Net income (loss)$6,396 $(4,840) $20,045 Allocation of net income (loss) for calculation of earnings per unit: General partner interest in net income$554 $433 $944Preferred interest in net income$21,564 $25,824 $25,115Net loss available to limited partners$(15,722) $(31,097) $(6,014) Basic and diluted net loss per common unit$(0.47) $(0.87) $(0.15) Weighted average common units outstanding - basic and diluted32,945 35,093 38,342The accompanying notes are an integral part of these consolidated financial statements.F-4Table of ContentsBLUEKNIGHT ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL(in thousands) CommonUnitholders PreferredUnitholders General PartnerInterest Total Partners’CapitalBalance, December 31, 2014$525,767 $204,599 $(610,410) $119,956Net income (loss)(15,281) 21,564 113 6,396Equity-based incentive compensation2,095 — 36 2,131Profits interest contribution— — 150 150Distributions(18,943) (21,564) (1,093) (41,600)Proceeds from sale of 30,075 common unitspursuant to the Employee Unit PurchasePlan186 — — 186Balance, December 31, 2015$493,824 $204,599 $(611,204) $87,219Net income (loss)(30,004) 24,939 225 (4,840)Equity-based incentive compensation2,051 — 36 2,087Profits interest contribution— — 923 923Distributions(20,960) (24,939) (1,320) (47,219)Capital contributions— — 2,384 2,384Proceeds from sale of 3,795,000 common units,net of underwriters’ discount and offeringexpenses of $1.5 million20,931 — — 20,931Proceeds from sale of 71,807 common unitspursuant to the Employee Unit Purchase Plan338 — — 338Repurchase of 13,335,390 Preferred Units— (95,348) — (95,348)Proceeds from issuance of 18,312,968 Preferred Units— 144,672 — 144,672Proceeds from issuance of 847,457 commonunits5,000 — — 5,000Proceeds from issuance of 97,654 general partner units— — 680 680Consideration paid in excess of historical costof assets acquired from Ergon— — (91,251) (91,251)Balance, December 31, 2016$471,180 $253,923 $(699,527) $25,576Net income (loss)(6,009) 25,116 938 20,045Equity-based incentive compensation1,424 — 27 1,451Distributions(22,633) (25,116) (1,414) (49,163)Capital contributions— — 104 104Proceeds from sale of 53,079 common unitspursuant to the Employee Unit Purchase Plan240 — — 240Value of 1,898,380 common units issued foracquisitions10,156 — — 10,156Consideration paid in excess of historical costof assets acquired from Ergon— — (3,725) (3,725)Balance, December 31, 2017$454,358 $253,923 $(703,597) $4,684The accompanying notes are an integral part of this consolidated financial statement.F-5Table of ContentsBLUEKNIGHT ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OF CASH FLOWS(in thousands) Year ended December 31, 2015 2016 2017Cash flows from operating activities: Net income (loss)$6,396 $(4,840) $20,045Adjustments to reconcile net income (loss) to net cash provided by operating activities: Provision for uncollectible receivables from third parties(184) 15 (21)Provision for uncollectible receivables from related parties— (229) —Depreciation and amortization27,228 30,820 31,139Impairment of intangible assets7,498 — 1,107Amortization and write-off of debt issuance costs884 1,107 1,816Unrealized loss (gain) related to interest rate swaps469 (1,156) (1,790)Fixed asset impairment charge14,498 25,761 1,293Loss (gain) on sale of assets(6,137) (108) 975Gain on sale of unconsolidated affiliate— — (5,337)Equity-based incentive compensation2,131 2,087 1,451Equity earnings in unconsolidated affiliate(3,932) (1,483) (61)Distributions from unconsolidated affiliate4,313 — —Gain related to investments(267) — —Changes in assets and liabilities: Decrease (increase) in accounts receivable538 1,138 (24)Decrease (increase) in receivables from related parties472 213 (1,210)Decrease in prepaid insurance3,998 3,008 2,507Decrease (increase) in other current assets(579) 237 (983)Decrease (increase) in other assets(1,485) (498) 84Increase (decrease) in accounts payable(792) (237) 952Increase in payables to related parties— 1,053 749Increase (decrease) in accrued interest payable(42) 222 281Increase (decrease) in accrued property taxes727 (242) (72)Increase (decrease) in unearned revenue2,075 (1,568) 898Increase (decrease) in unearned revenue from related parties(189) 187 580Increase (decrease) in accrued payroll743 (905) (239)Increase (decrease) in other accrued liabilities2,169 (1,733) 354Net cash provided by operating activities60,532 52,849 54,494Cash flows from investing activities: Acquisition of assets from Ergon— (122,572) —Acquisitions(20,951) (18,989) —Capital expenditures(41,609) (19,995) (18,715)Proceeds from sale of assets14,687 1,993 9,297Distributions from unconsolidated affiliate922 — —Proceeds from sale of investments2,346 — —Proceeds from sale of unconsolidated affiliate— — 26,489Net cash provided by (used in) investing activities(44,605) (159,563) 17,071Cash flows from financing activities: Payment on insurance premium financing agreement(3,286) (3,425) (2,965)Debt issuance costs— (956) (4,208)Borrowings under credit agreement112,000 170,000 378,592Payments under credit agreement(83,000) (91,000) (395,000)Proceeds from issuance of common units, net of offering costs186 26,269 240Proceeds from issuance of Preferred Units— 144,672 —Proceeds from issuance of general partner units— 680 —Repurchase of Preferred Units— (95,348) —Capital contributions— 2,384 104Capital contribution related to profits interest150 923 —Distributions(41,600) (47,219) (49,163)Net cash provided by (used in) financing activities(15,550) 106,980 (72,400)F-6Table of ContentsBLUEKNIGHT ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OF CASH FLOWS(in thousands) Year ended December 31, 2015 2016 2017Net increase (decrease) in cash and cash equivalents377 266 (835)Cash and cash equivalents at beginning of period2,661 3,038 3,304Cash and cash equivalents at end of period$3,038 $3,304 $2,469 Supplemental disclosure of cash flow information: Assets acquired through non-cash equity issuance$— $— $10,156Increase (decrease) in accounts payable related to purchases of property, plant andequipment$(1,598) $(1,825) $779Increase in accrued liabilities related to insurance premium financing agreement$3,813 $3,189 $2,938Cash paid for interest, net of amounts capitalized$9,915 $12,404 $13,732Cash paid for income taxes$412 $282 $158The accompanying notes are an integral part of these consolidated financial statements. F-7Table of ContentsBLUEKNIGHT ENERGY PARTNERS, L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND NATURE OF BUSINESS Blueknight Energy Partners, L.P. and subsidiaries (collectively, the “Partnership”) is a publicly traded master limited partnership with operations in 27 states.The Partnership provides integrated terminalling, gathering and transportation services for companies engaged in the production, distribution and marketing ofliquid asphalt and crude oil. The Partnership manages its operations through four operating segments: (i) asphalt terminalling services, (ii) crude oil terminallingservices, (iii) crude oil pipeline services and (iv) crude oil trucking and producer field services. The Partnership’s common units and Preferred Units, whichrepresent limited partnership interests in the Partnership, are listed on the Nasdaq Global Market under the symbols “BKEP” and “BKEPP,” respectively. ThePartnership was formed in February 2007 as a Delaware master limited partnership initially to own, operate and develop a diversified portfolio of complementarymidstream energy assets. On October 5, 2016, the Partnership completed the following transactions (the “Ergon Transactions”): (i) a subsidiary of Ergon, Inc. (together with itssubsidiaries, “Ergon”) purchased 100% of the outstanding voting stock of Blueknight GP Holding, L.L.C., which owns 100% of the capital stock of thePartnership’s general partner, Blueknight Energy Partners G.P., L.L.C., pursuant to a Membership Interest Purchase Agreement dated July 19, 2016, among CB-Blueknight, LLC, an indirect wholly-owned subsidiary of Charlesbank, Blueknight Energy Holding, Inc., an indirect wholly-owned subsidiary of Vitol HoldingB.V. (together with its affiliates and subsidiaries “Vitol”), and Ergon Asphalt Holdings, LLC, a wholly-owned subsidiary of Ergon (the “Ergon Change ofControl”); (ii) Ergon contributed nine asphalt terminals plus $22.1 million in cash in return for total consideration of approximately $144.7 million , whichconsisted of the issuance of 18,312,968 of Preferred Units in a private placement; and (iii) Ergon acquired an aggregate of $5.0 million of common units for cash ina private placement, pursuant to a Contribution Agreement between the Partnership and Ergon. In addition, the Partnership repurchased 6,667,695 Preferred Unitsfrom each Vitol and Charlesbank for an aggregate purchase price of approximately $95.3 million . Vitol and Charlesbank each retained 2,488,789 Preferred Unitsupon completion of these transactionsThe Partnership’s acquisition of nine asphalt terminals from Ergon on October 5, 2016, was accounted for as a transaction among entities under commoncontrol. As a result, the Partnership recorded the acquired assets at Ergon’s historical cost of $31.3 million , net of accumulated depreciation of $63.0 million . The$91.3 million of consideration in excess of Ergon’s historical net book value was recorded as a deemed distribution to the Partnership’s general partner and isreflected as “Consideration paid in excess of historical cost of assets acquired from Ergon” on the Partnership’s consolidated statement of changes in partners’capital.2. BASIS OF CONSOLIDATION AND PRESENTATION The accompanying consolidated financial statements and related notes present and discuss the Partnership’s consolidated financial position as ofDecember 31, 2016 and 2017 , and the consolidated results of the Partnership’s operations, cash flows and changes in partners’ capital for the years endedDecember 31, 2015 , 2016 and 2017 . The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in theUnited States of America (“GAAP”). All significant intercompany accounts and transactions have been eliminated in the preparation of the accompanyingconsolidated financial statements. Certain reclassifications have been made to the prior period consolidated financial statements to conform to the current periodpresentation.3 . SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES USE OF ESTIMATES - The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions thataffect 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; (4) accruals related torevenues and expenses; (5) the estimated fair value of financial instruments; and (6) liability and contingency accruals. Although management believes theseestimates are reasonable, actual results could differ from these estimates. CASH AND CASH EQUIVALENTS - Cash and cash equivalents includes cash and all investments with original maturities of three months or less whichare readily convertible into known amounts of cash. ACCOUNTS RECEIVABLE - The majority of the Partnership’s accounts receivable relates to its asphalt terminalling services, crude oil pipeline servicesand crude oil trucking and producer field services activities. Accounts receivable includedF-8Table of Contentsin the consolidated balance sheets are reflected net of the allowance for doubtful accounts of less than $0.1 million at both December 31, 2016 and 2017 . The Partnership reviews all outstanding accounts receivable balances on a monthly basis and records a reserve for amounts that the Partnership expects willnot be fully recovered. Although the Partnership considers its allowance for doubtful trade accounts receivable to be adequate, there is no assurance that actualamounts 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 addcapacity or extend the useful life of an asset are expensed as incurred. The carrying values of the assets are based on estimates, assumptions and judgments relativeto useful lives and salvage values. As assets are disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gainor loss is included in operating income in the consolidated 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, includingage (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertaintiesthat impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply anddemand 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 residualfuel oil terminalling assets are abandoned (see Note 17 ). Such obligations are recognized in the period incurred if reasonably estimable.IMPAIRMENT OF LONG-LIVED ASSETS AND OTHER INTANGIBLE ASSETS - Long-lived assets with recorded values that are not expected to berecovered through future cash flows are written down to estimated fair value. A long-lived asset is tested for impairment when events or circumstances indicatethat 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 flowsexpected 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 lossequal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discountedfuture net cash flows.During the year ended December 31, 2015 , the Partnership recognized fixed asset impairment charges of $12.6 million , $1.4 million and $0.5 million relatedto the East Texas pipeline system, a portion of the Mid-Continent pipeline system and the West Texas trucking stations, respectively.During the year ended December 31, 2016 , the Partnership recognized fixed asset impairment charges of $25.8 million , primarily due to impairmentrecognized on the Knight Warrior pipeline project and the East Texas pipeline system. The Knight Warrior pipeline project was canceled due to continued low rigcounts in the Eaglebine/Woodbine area coupled with lower production volumes, competing projects and the overall impact of the decreased market price of crudeoil. Consequently, shipper commitments related to the project were canceled and an impairment expense of $22.6 million was recognized during the year endedDecember 31, 2016 .During the year ended December 31, 2017 , the Partnership recognized fixed asset impairment charges of $1.2 million related to the producer field servicesbusiness, primarily operated in the Texas panhandle.Acquired customer relationships and non-compete agreements are capitalized and amortized over useful lives ranging from 4 to 20 years using the straight-linemethod of amortization. An impairment loss is recognized for definite-lived intangibles if the carrying amount of an intangible asset is not recoverable and itscarrying amount exceeds its fair value. No impairment charges were recognized during the years ended December 31, 2015 or 2016 , with respect to intangibleassets. During the year ended December 31, 2017 , the Partnership recognized intangible asset impairment charges of $0.2 million on customer relationshipsrelated to the producer field services business, primarily operated in the Texas panhandle. EQUITY METHOD INVESTMENTS - The Partnership’s approximate 30% ownership investment in Advantage Pipeline, L.L.C. (“Advantage Pipeline”),over which the Partnership had significant influence but not control, was accounted for by the equity method. The Partnership did not consolidate any part of theassets or liabilities of its equity method investee. On April 3, 2017, Advantage Pipeline was acquired by a joint venture formed by affiliates of Plains All AmericanPipeline, L.P.F-9Table of Contentsand Noble Midstream Partners LP. The Partnership’s share of net income or loss is reflected as one line item on the Partnership’s consolidated statements ofoperations entitled “Equity earnings in unconsolidated affiliate” and increased or decreased, as applicable, the carrying value of the Partnership’s investment in theunconsolidated affiliate on the consolidated balance sheets. Distributions to the Partnership reduced the carrying value of its investment and are reflected in thePartnership’s consolidated statements of cash flows in the line item “Distributions from unconsolidated affiliate.” In turn, contributions increased the carryingvalue of the Partnership’s investment and were reflected in the Partnership’s consolidated statements of cash flows in investing activities.DEBT ISSUANCE COSTS - Costs incurred in connection with the issuance of long-term debt related to the Partnership’s credit agreement are capitalizedand 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 “effectiveinterest” method of amortization.INVESTMENTS - In November 2014, the Partnership received 30,393 Class A Common Units of SemCorp in connection with the settlement of twounsecured claims the Partnership filed in connection with SemCorp’s predecessor’s bankruptcy filing in 2008. The fair market value of these units on the date ofreceipt was $2.5 million . In March 2015, the Partnership sold all of these units for a total of $2.3 million . GOODWILL - Goodwill represents the excess of the cost of acquisitions over the amounts assigned to assets acquired and liabilities assumed. Goodwill isnot amortized but is tested annually in December for impairment or when events and circumstances warrant an interim evaluation. Goodwill is tested forimpairment at a level of reporting referred to as a reporting unit. The Partnership has four reporting units comprised of its (i) asphalt terminalling services,(ii) crude oil terminalling services, (iii) crude oil pipeline services and (iv) crude oil trucking and producer field services. If the fair value of a reporting unitexceeds its carrying amount, goodwill of the reporting unit is not considered to be impaired. The impairment test is generally based on the estimated discountedfuture net cash flows of the respective reporting unit, utilizing discount rates and other factors in determining the fair value of the reporting unit. Inputs in thePartnership’s estimated discounted future net cash flows include existing and estimated future asset utilization, estimated growth rates in future cash flows andestimated terminal values (these are all considered Level 3 inputs).Changes in the carrying amount of goodwill are summarized below for the periods indicated (in thousands): AsphaltTerminalling Services Crude Oil PipelineServices Crude Oil Truckingand Producer FieldServices TotalBalance, December 31, 2014$— $6,340 $876 $7,216Acquisition3,511 1,158 — 4,669Impairment— (7,498) — (7,498)Balance, December 31, 2015$3,511 $— $876 $4,387Acquisition359 — — 359Balance, December 31, 2016$3,870 $— $876 $4,746Impairment— — (876) (876)Balance, December 31, 2017$3,870 $— $— $3,870During the fourth quarter of 2015, impairment testing indicated that the fair value of the crude oil pipeline services reporting unit was less than the carryingvalue due to declining volumes, and the Partnership recognized impairment of goodwill of $7.5 million related to this reporting unit. During the fourth quarter of2017, impairment testing indicated that the fair value of the crude oil trucking and producer field services reporting unit was less than the carrying value based onthe estimated market value of the producer field services business, and the Partnership recognized impairment of goodwill of $0.9 million related to this reportingunit. Impairment testing indicated there was no impairment of goodwill in 2016. ENVIRONMENTAL MATTERS - Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation,fines, 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 remediationcan be reasonably estimated. The Partnership had no such loss contingencies as of December 31, 2016 . The Partnership had loss contingencies related toenvironmental matters of $0.1 million as of December 31, 2017 . F-10Table of ContentsREVENUE RECOGNITION - The Partnership’s revenues consist of (i) terminalling revenues, (ii) gathering, transportation and producer field servicesrevenues, (iii) product sales revenues and (iv) fuel surcharge revenues. Terminalling revenues consist of (i) storage service fees resulting from short-term and long-term contracts for committed space that may or may not be utilizedby the customer in a given month and (ii) terminal throughput service charges to pump crude oil to connecting carriers or to deliver asphalt product out of thePartnership’s terminals. Terminal throughput service charges are recognized as asphalt products or crude oil exits the terminal and is delivered out of thePartnership’s terminal. Storage service revenues are recognized as the services are provided and the amounts earned on a monthly basis.Gathering and transportation services revenues consist of service fees recognized for the gathering of crude oil for the Partnership’s customers and thetransportation of the crude oil to refiners, to common carrier pipelines for ultimate delivery to refiners or to terminalling facilities owned by the Partnership andothers. Revenue for the gathering and transportation of crude oil is recognized when the service is performed and is based upon regulated and non-regulated tariffrates and the related transport volumes. Producer field services revenue consists of a number of services ranging from gathering condensates from natural gasproducers to hauling produced water to disposal wells. Revenue for producer field services is recognized when the services are performed.Product sales revenues are comprised of (i) revenues recognized for the sale of crude oil to the Partnership’s customers that it purchases at production leasesand (ii) revenue recognized in buy/sell transactions with the Partnership’s customers. Product sales revenue is recognized for products upon delivery and when thecustomer assumes the risks and rewards of ownership. Fuel surcharge revenues are comprised of revenues recognized for the reimbursement of fuel and power consumed to operate the Partnership’s asphalt productterminals. The Partnership recognizes fuel surcharge revenues in the period in which the related fuel and power expenses are incurred. INCOME AND OTHER TAXES - For federal and most state income tax purposes, the majority of income, gains, losses, deductions and tax creditsgenerated by the Partnership flow through to the unitholders of the Partnership and are subject to income tax at the individual partner level. The Partnership issubject to the Texas state franchise (margin) tax, and the earnings associated with the Partnership’s taxable subsidiary are subject to federal and state incometaxes. The Partnership has estimated its liability related to these taxes to be $0.3 million for each of the years ended December 31, 2015 and 2016 , and $0.2 millionfor the year ended December 31, 2017 . This liability is reflected on the Partnership’s consolidated statements of operations as “Provision for income taxes”. SeeNote 21 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 - The Partnership’s general partner adopted the Blueknight Energy Partners G.P. L.L.C. Long-Term Incentive Plan (the“LTIP”). The compensation committee of the Board administers the LTIP. Effective April 29, 2014, the Partnership’s unitholders approved an amendment to theLTIP to increase the number of common units reserved for issuance under the incentive plan to 4.1 million common units, subject to adjustment for certain events.Although other types of awards are contemplated under the LTIP, awards issued to date include “phantom” units, which convey the right to receive common unitsupon vesting, and “restricted” units, which are grants of common units restricted until the time of vesting. Certain of the phantom unit awards also includedistribution equivalent rights (“DERs”). A DER entitles the grantee to a cash payment equal to the cash distribution paid on an outstanding common unit prior tothe vesting date of the underlying award. Cash distributions paid on DERs are accounted for as partnership distributions. Recipients of restricted units are entitledto receive cash distributions paid on common units during the vesting period. The Partnership classifies unit award grants as either equity or liability awards. All award grants made under the LTIP from its inception throughDecember 31, 2017 , have been classified as equity awards. Fair value for award grants classified as equity is determined on the grant date of the award and thisvalue is recognized as compensation expense ratably over the requisite service period of unit award grants, which generally is the vesting period. Fair value forequity awards is calculated as the closing price of the Partnership’s common units representing limited partner interests in the Partnership (“common units”) on thegrant date and is reduced by the present value of estimated cash distributions to be paid on common units during the vesting period to the extent a unit award doesnot include DERs. Compensation expense related to unit-based payments is included in operating and general and administrative expenses on the Partnership’sconsolidated statements of operations. FAIR VALUE OF FINANCIAL INSTRUMENTS - The Partnership measures all financial instruments, including derivatives embedded in other contracts,at fair value and recognizes them in the consolidated balance sheets as an asset or a liability, depending on its rights and obligations under theapplicable contract. The changes in the fair value of financial instruments are recognized currently in earnings in the consolidated statements of operations. F-11Table of Contents4 . ACQUISITIONSOn December 1, 2017, the Partnership acquired an asphalt terminalling facility in Bainbridge, Georgia, from Ergon Asphalt & Emulsions, Inc. and ErgonTerminaling, Inc., both subsidiaries of Ergon, for a total purchase price of $10.2 million , consisting of 1,898,380 common units representing limited partnerinterests in the Partnership. The acquisition was accounted for as a transaction among entities under common control. As a result, the Partnership recorded theacquired assets at Ergon’s historical cost of $6.4 million , net of accumulated depreciation of $7.9 million . The $3.7 million of consideration in excess of Ergon’shistorical net book value was recorded as a deemed distribution to the Partnership’s general partner and is reflected as ”Consideration paid in excess of historicalcost of assets acquired from Ergon” on the Partnership’s consolidated statement of changes in partners’ capital.On October 5, 2016, as part of the Ergon Transaction, the Partnership acquired nine asphalt terminals from Ergon. which accounted for as a transaction amongentities under common control. As a result, the Partnership recorded the acquired assets at Ergon’s historical cost of $31.3 million , net of accumulated depreciationof $63.0 million . The $91.3 million of consideration in excess of Ergon’s historical net book value was recorded as a deemed distribution to the Partnership’sgeneral partner and is reflected as “Consideration paid in excess of historical cost of assets acquired from Ergon” on the Partnership’s consolidated statement ofchanges in partners’ capital.In February 2016, the Partnership acquired two asphalt terminalling facilities located in Virginia and North Carolina from a third party for $19.0 million .In May 2015, the Partnership acquired an asphalt terminalling facility in Wyoming from a third party for $13.9 million . In November 2015, the Partnershipacquired a 75-mile pipeline system and related crude oil marketing business in southern Oklahoma for $7.0 million from a third party.5 . EQUITY METHOD INVESTMENT On April 3, 2017, Advantage Pipeline was acquired by a joint venture formed by affiliates of Plains All American Pipeline, L.P. and Noble MidstreamPartners LP. The Partnership received cash proceeds at closing from the sale of its approximate 30% equity ownership interest in Advantage Pipeline ofapproximately $25.3 million and recorded a gain on the sale of the investment of $4.2 million . Approximately 10% of the gross sale proceeds were held in escrow,subject to certain post-closing settlement terms and conditions. The Partnership received approximately $1.1 million of the funds held in escrow in August 2017.The Partnership received approximately $2.2 million for its pro rata portion of the remaining net escrow proceeds in January 2018. The Partnership’s proceedswere used to prepay revolving debt (without a commitment reduction). The operating and administrative services agreement to which the Partnership andAdvantage Pipeline were parties and under which the Partnership operated the 70-mile, 16-inch Advantage crude oil pipeline, located in the southern DelawareBasin in Texas, was terminated at closing. The Partnership and the Plains/Noble joint venture entered into a short-term transition services agreement under whichthe Partnership provided certain services through August 1, 2017, when the agreement was terminated.Summarized financial information for Advantage Pipeline is set forth in the tables below for the periods indicated in which the Partnership held the investmentin Advantage Pipeline (in thousands): As of December 31, 2016Balance sheet Current assets$2,075Noncurrent assets89,065Total assets$91,140Current liabilities1,327Long-term liabilities20,910Member’s equity68,903Total liabilities and member’s equity$91,140F-12Table of Contents Year ended December 31, Period endedApril 3, 2015 2016 2017Income statements Operating revenues$26,398 $17,091 $3,150Operating expenses$3,059 $2,776 $465Net income$14,909 $5,434 $1876 . RESTRUCTURING CHARGESDuring the fourth quarter of 2015, the Partnership recognized certain restructuring charges in its crude oil trucking and producer field services segmentpursuant to an approved plan to exit the trucking market in West Texas. The following restructuring charges were accrued as of December 31, 2015, and reportedin operating expense in the Partnership’s consolidated statement of operations for the year ended December 31, 2015: Year ended December 31, 2015 (in thousands)Severance charges$315Lease payments related to operating leases for idled equipment1,250Total restructuring costs$1,565Changes in the accrued amounts pertaining to the above charges are summarized as follows: Year ended December 31, 2015 2016 2017 (in thousands)Beginning balance$— $1,565 $474Charged to expense1,565 — —Cash payments— 1,091 188Ending balance$1,565 $474 $286The remaining accrual relates to lease payments that will be paid over the remaining lease terms, which extend through July 2019.7 . PROPERTY, PLANT AND EQUIPMENT Estimated UsefulLives (Years) As of December 31, 2016 2017 (dollars in thousands)LandN/A $25,863 $24,776Land improvements10-20 6,698 6,787Pipelines and facilities5-30 165,293 166,004Storage and terminal facilities10-35 347,656 370,056Transportation equipment3-10 12,391 3,293Office property and equipment and other3-20 35,578 32,011Pipeline linefill and tank bottomsN/A 3,234 3,233Construction-in-progressN/A 2,738 6,500Property, plant and equipment, gross 599,451 612,660Accumulated depreciation (292,117) (316,591)Property, plant and equipment, net $307,334 $296,069F-13Table of Contents Depreciation expense for the years ended December 31, 2015 , 2016 and 2017 was $27.0 million , $29.6 million and $29.9 million , respectively. During theyear ended December 31, 2015 , the Partnership recorded fixed asset impairment expense of $14.0 million related to its crude oil pipeline services reporting unitand $0.5 million related to its crude oil trucking and field services reporting unit. During the year ended December 31, 2016 , the Partnership recorded fixed assetimpairment expense of $25.8 million , primarily due to an impairment recognized on the Knight Warrior pipeline project and the East Texas pipeline system.During the year ended December 31, 2017 , the Partnership recorded fixed asset impairment expense of $1.2 million related to the crude oil trucking and fieldservices reporting unit.Included in assets held for sale on the consolidated balance sheets as of December 31, 2016 , is the East Texas pipeline system, with a net book value of $4.2million . On April 18, 2017, the Partnership sold its East Texas pipeline system. The Partnership received cash proceeds at closing of approximately $4.8 millionand recorded a gain of less than $0.1 million . The Partnership used the proceeds received at closing to prepay revolving debt (without a commitment reduction).8. INTANGIBLES AND OTHER ASSETS, NETOther assets, net of accumulated amortization, consist of the following: As of December 31, 2016 2017 (in thousands)Customer relationships$12,579 $12,221Deferred charges related to pipeline connection agreements2,653 2,716Deposits435 302Prepaid insurance428 353Other prepaid expenses24 103Intangibles and other assets, gross16,119 15,695Accumulated amortization of intangible assets(1,604) (2,782)Intangibles and other assets, net$14,515 $12,913 Amortization expense related to intangibles for the years ended December 31, 2015 , 2016 and 2017 was $0.2 million , $1.2 million and $1.3 million ,respectively. The estimated aggregate future amortization expense on amortizable intangible assets currently owned by the Partnership is as follows (in thousands):For year ending: December 31, 2018$1,314December 31, 20191,269December 31, 20201,267December 31, 20211,267December 31, 20221,267Thereafter5,771Total estimated aggregate amortization expense$12,155 Customer relationships include $8.4 million related to the acquisition of asphalt facilities in February 2016, $3.5 million related to the acquisition of a pipelineand crude oil marketing business in November 2015 and $0.3 million related to the acquisition of a producer field services business in December 2010. Thecustomer relationships are being amortized over a range of 4 to 20 years.During the year ended December 31, 2017, the Partnership recognized intangible asset impairment charges of $0.2 million on customer relationships related tothe producer field services business, primarily operated in the Texas panhandle.9. DEBTOn May 11, 2017, the Partnership entered into an amended and restated credit agreement which consists of a $450.0 million revolving loan facility.F-14Table of ContentsAs of March 1, 2018 , approximately $308.6 million of revolver borrowings and $1.5 million of letters of credit were outstanding under the credit agreement,leaving the Partnership with available capacity of approximately $139.9 million for additional revolver borrowings and letters of credit under the credit agreement,although the Partnership’s ability to borrow such funds may be limited by the financial covenants in the credit agreement. The proceeds of loans made under theamended and restated credit agreement may be used for working capital and other general corporate purposes of the Partnership. All references herein to the creditagreement on or after May 11, 2017, refer to the amended and restated credit agreement.The credit agreement is guaranteed by all of the Partnership’s existing subsidiaries. Obligations under the credit agreement are secured by first priority liens onsubstantially all of the Partnership’s assets and those of the guarantors. The credit agreement includes procedures for additional financial institutions to become revolving lenders, or for any existing lender to increase its revolvingcommitment thereunder, subject to an aggregate maximum of $600.0 million for all revolving loan commitments under the credit agreement. The credit agreement will mature on May 11, 2022 , and all amounts outstanding under the credit agreement will become due and payable on such date. Thecredit agreement requires mandatory prepayments of amounts outstanding thereunder with the net proceeds from certain asset sales, property or casualty insuranceclaims and condemnation proceedings, unless the Partnership reinvests such proceeds in accordance with the credit agreement, but these mandatory prepaymentswill not require any reduction of the lenders’ commitments under the credit agreement.Borrowings under the credit agreement bear interest, at the Partnership’s option, at either the reserve-adjusted eurodollar rate (as defined in the creditagreement) plus an applicable margin which ranges from 2.0% to 3.0% or the alternate base rate (the highest of the agent bank’s prime rate, the federal fundseffective rate plus 0.5% and the 30-day eurodollar rate plus 1.0% ) plus an applicable margin which ranges from 1.0% to 2.0% . The Partnership pays a per annumfee on all letters of credit issued under the credit agreement, which fee equals the applicable margin for loans accruing interest based on the eurodollar rate, and thePartnership pays a commitment fee ranging from 0.375% to 0.5% on the unused commitments under the credit agreement. The applicable margins for thePartnership’s interest rate, the letters of credit fee and the commitment fee vary quarterly based on the Partnership’s consolidated total leverage ratio (as defined inthe credit agreement, being generally computed as the ratio of consolidated total debt to consolidated earnings before interest, taxes, depreciation, amortization andcertain other non-cash charges).The credit agreement includes financial covenants which are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day ofeach fiscal quarter.Prior to the date on which the Partnership issues qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notespreviously or concurrently issued) that equals or exceeds $200.0 million , the maximum permitted consolidated total leverage ratio is 4.75 to 1.00; provided that themaximum permitted consolidated total leverage ratio will be 5.25 to 1.00 for certain quarters based on the occurrence of a specified acquisition (as defined in thePartnership’s credit agreement, but generally being an acquisition for which the aggregate consideration is $15.0 million or more). The acquisition of the nineasphalt terminals from Ergon in 2016 qualified as a specified acquisition.From and after the date on which the Partnership issues qualified senior notes in an aggregate principal amount (when combined with all other qualified seniornotes previously or concurrently issued) that equals or exceeds $200.0 million , the maximum permitted consolidated total leverage ratio is 5.00 to 1.00; providedthat from and after the fiscal quarter ending immediately preceding the fiscal quarter in which a specified acquisition occurs, to and including the last day of thesecond full fiscal quarter following the fiscal quarter in which such acquisition occurred, the maximum permitted consolidated total leverage ratio is 5.50 to 1.00.The maximum permitted consolidated senior secured leverage ratio (as defined in the credit agreement, but generally computed as the ratio of consolidatedtotal secured debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) is 3.50 to 1.00, but this covenant isonly tested from and after the date on which the Partnership issues qualified senior notes in an aggregate principal amount (when combined with all other qualifiedsenior notes previously or concurrently issued) that equals or exceeds $200.0 million .The minimum permitted consolidated interest coverage ratio (as defined in the credit agreement, but generally computed as the ratio of consolidated earningsbefore interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest expense) is 2.50 to 1.00.F-15Table of ContentsIn addition, the credit agreement contains various covenants that, among other restrictions, limit the Partnership’s ability to:•create, issue, incur or assume indebtedness;•create, incur or assume liens;•engage in mergers or acquisitions;•sell, transfer, assign or convey assets;•repurchase the Partnership’s equity, make distributions to unitholders and make certain other restricted payments;•make investments;•modify the terms of certain indebtedness, or prepay certain indebtedness;•engage in transactions with affiliates;•enter into certain hedging contracts;•enter into certain burdensome agreements;•change the nature of the Partnership’s business; and•make certain amendments to the Partnership’s partnership agreement.At December 31, 2017 , the Partnership’s consolidated total leverage ratio was 4.63 to 1.00 and the consolidated interest coverage ratio was 4.76 to 1.00. ThePartnership was in compliance with all covenants of its credit agreement as of December 31, 2017 .The credit agreement permits the Partnership to make quarterly distributions of available cash (as defined in the Partnership’s partnership agreement) tounitholders so long as no default or event of default exists under the credit agreement on a pro forma basis after giving effect to such distribution. The Partnershipis currently allowed to make distributions to its unitholders in accordance with this covenant; however, the Partnership will only make distributions to the extent ithas sufficient cash from operations after establishment of cash reserves as determined by the Board in accordance with the Partnership’s cash distribution policy,including the establishment of any reserves for the proper conduct of the Partnership’s business. See Note 11 for additional information regarding distributions.In addition to other customary events of default, the credit agreement includes an event of default if:(i)the general partner ceases to own 100% of the Partnership’s general partner interest or ceases to control the Partnership;(ii)Ergon ceases to own and control 50.0% or more of the membership interests of the general partner; or(iii)during any period of 12 consecutive months, a majority of the members of the Board of the general partner ceases to be composed of individuals:(A)who were members of the Board on the first day of such period;(B)whose election or nomination to the Board was approved by individuals referred to in clause (A) above constituting at the time of suchelection or nomination at least a majority of the Board; or(C)whose election or nomination to the Board was approved by individuals referred to in clauses (A) and (B) above constituting at the timeof such election or nomination at least a majority of the Board,provided that any changes to the composition of individuals serving as members of the Board approved by Ergon will not cause an event ofdefault.If an event of default relating to bankruptcy or other insolvency events occurs with respect to the general partner or the Partnership, all indebtedness under thecredit agreement will immediately become due and payable. If any other event of default exists under the credit agreement, the lenders may accelerate the maturityof the obligations outstanding under the credit agreement and exercise other rights and remedies. In addition, if any event of default exists under the creditagreement, the lenders may commence foreclosure or other actions against the collateral. If any default occurs under the credit agreement, or if the Partnership is unable to make any of the representations and warranties in the credit agreement, thePartnership will be unable to borrow funds or have letters of credit issued under the credit agreement. Upon the execution of the amended and restated credit agreement, the Partnership expensed $0.7 million of debt issuance costs related to the prior revolvingloan facility, leaving a remaining balance of $0.9 million ascribed to those lenders with commitments under both the prior and the amended and restated creditagreement. During the year ended December 31, 2015 , the Partnership capitalized no debt issuance costs. During the years ended December 31, 2016 and 2017 ,the Partnership capitalized debt issuance costs related to its credit agreement of $1.0 million and $4.2 million , respectively. The debt issuance costs are beingamortized over the term of the credit agreement. Interest expense related to debt issuance cost amortization forF-16Table of Contentsthe year ended December 31, 2015 , was $0.9 million . Interest expense related to debt issuance cost amortization for each of the years ended December 31, 2016and 2017 was $1.1 million . During the years ended December 31, 2015 , 2016 and 2017 , the weighted average interest rate under the Partnership’s credit agreement, excluding the $0.7million of debt issuance costs related to the prior credit agreement that were expensed during the year ended December 31, 2017, was 3.37% , 3.95% and 4.43% ,respectively, resulting in interest expense of approximately $7.9 million , $11.2 million and $13.8 million , respectively.During the year ended December 31, 2015 , the Partnership capitalized interest of $0.2 million . During each of the years ended December 31, 2016 and 2017 ,the Partnership capitalized interest of less than $0.1 million . The Partnership is exposed to market risk for changes in interest rates related to its credit agreement. Interest rate swap agreements are used to manage aportion of the exposure related to changing interest rates by converting floating-rate debt to fixed-rate debt. As of December 31, 2016 and 2017 , the Partnershiphad interest rate swaps with notional amounts totaling $200.0 million to hedge the variability of its LIBOR-based interest payments, with half maturing on June 28,2018, and the other half maturing on January 28, 2019. During the years ended December 31, 2015 , 2016 and 2017 , the Partnership recorded swap interestexpense of $2.9 million , $2.5 million and $1.3 million , respectively. The interest rate swaps do not receive hedge accounting treatment under ASC 815 -Derivatives and Hedging .The following provides information regarding the Partnership’s assets and liabilities related to its interest rate swap agreements as of the periods indicated (inthousands):Derivatives Not Designated as HedgingInstruments Balance Sheet Location Fair Values of Derivative Instruments December 31, 2016 December 31, 2017Interest rate swap assets - current Other current assets $— $68Interest rate swap liabilities - noncurrent Long-term interest rate swapliabilities $1,947 $225 Changes in the fair value of the interest rate swaps are reflected in the consolidated statements of operations as follows (in thousands):Derivatives Not Designated asHedging Instruments Location of Gain (Loss) Recognizedin Net Income on Derivatives Amount of Gain (Loss) Recognized in Net Incomeon Derivatives Year ended December 31, 2015 2016 2017Interest rate swaps Interest expense, net of capitalizedinterest $(469) $1,156 $1,790 10. NET INCOME PER LIMITED PARTNER UNIT For purposes of calculating earnings per unit, the excess of distributions over earnings or excess of earnings over distributions for each period are allocated tothe Partnership’s general partner based on the general partner’s ownership interest at the time. The following sets forth the computation of basic and diluted netincome per common unit (in thousands, except per unit data): F-17Table of Contents Year ended December 31, 2015 2016 2017Net income (loss)$6,396 $(4,840) $20,045General partner interest in net income554 433 944Preferred interest in net income21,564 25,824 25,115Net loss available to limited partners$(15,722) $(31,097) $(6,014) Basic and diluted weighted average number of units: Common units32,945 35,093 38,342Restricted and phantom units685 803 862Total units33,630 35,896 39,204 Basic and diluted net loss per common unit$(0.47) $(0.87) $(0.15)11 . PARTNERS’ CAPITAL AND DISTRIBUTIONSOn December 1, 2017, the Partnership issued 1,898,380 common units to Ergon in a private placement for $10.2 million in exchange for an asphaltterminalling facility in Bainbridge, Georgia. See additional detail in Note 4 .On October 5, 2016, the Partnership completed the following transactions:•issued 847,457 common units to Ergon in a private placement for $5.0 million ;•repurchased 6,667,695 Preferred Units from each Vitol and Charlesbank for an aggregate purchase price of approximately $95.3 million , leaving bothVitol and Charlesbank with 2,488,789 Preferred Units upon completion of these transactions; and•issued 18,312,968 Preferred Units to Ergon for $144.7 million , as well as 97,654 general partner units to Ergon for $0.7 million .On July 26, 2016, the Partnership issued and sold 3,795,000 common units for a public offering price of $5.90 per unit, resulting in proceeds of approximately$20.9 million , net of underwriters’ discount and offering expenses of $1.5 million .In accordance with the terms of its partnership agreement, each quarter the Partnership distributes all of its available cash (as defined in the partnershipagreement) to its unitholders. Generally, distributions are allocated as follows:•first, 98.4% to the preferred unitholders and 1.6% to its general partner until the Partnership distributes for each Preferred Unit an amount equal to thePreferred Units quarterly distribution amount discussed below;•second, 98.4% to the preferred unitholders and 1.6% to its general partner until the Partnership distributes for each Preferred Unit an amount equal toany Preferred Units cumulative distribution arrearage; and•thereafter, 98.4% to the common unitholders and 1.6% to its general partner until the common unitholders receive the minimum quarterly distributionof $0.11 per unit.The Preferred Units are convertible at the holders’ option into common units. Holders of the Preferred Units are entitled to quarterly distributions of $0.17875per unit per quarter. If the Partnership fails to pay in full any distribution on the Preferred Units, the amount of such unpaid distribution will accrue and accumulatefrom the last day of the quarter for which such distribution is due until paid in full.The general partner receives incentive distribution rights. Incentive distribution rights represent the right to receive an increasing percentage ( 13.0% , 23.0%and 48.0% ) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have beenachieved. The general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject torestrictions in the partnership agreement. If for any quarter:F-18Table of Contents•the Partnership has distributed available cash from operating surplus to the holders of our Preferred Units in an amount equal to the Preferred Unitsquarterly distribution amount;•the Partnership has distributed available cash from operating surplus to the holders of our Preferred Units in an amount necessary to eliminate anycumulative arrearages in the payment of the Preferred Units quarterly distribution amount; and•the Partnership has distributed available cash from operating surplus to the common unitholders and Class B unitholders in an amount equal to theminimum quarterly distribution; then the partnership agreement requires that the Partnership distribute any additional available cash from operating surplus for that quarter among the unitholdersand the general partner in the following manner:•first, 98.4% to all unitholders holding common units or Class B units, pro rata, and 1.6% to the general partner, until each unitholder receives a total of$0.1265 per unit for that quarter (the “first target distribution”);•second, 85.4% to all unitholders holding common units or Class B units, pro rata, and 14.6% to the general partner, until each unitholder receives a totalof $0.1375 per unit for that quarter (the “second target distribution”);•third, 75.4% to all unitholders holding common units or Class B units, pro rata, and 24.6% to the general partner, until each unitholder receives a totalof $0.1825 per unit for that quarter (the “third target distribution”); and•thereafter, 50.4% to all unitholders holding common units or Class B units, pro rata, and 49.6% to the general partner.Distributions are also paid to the holders of restricted units and phantom units as disclosed in Note 14 .The Partnership paid the following distributions on the Preferred Units during the years ended December 31, 2015 , 2016 and 2017 (in thousands):YearPaidPeriods CoveredTotal Paid toPreferredUnitholders Paid toGeneralPartner2015Quarters ending December 31, 2014, March 31, 2015, June 30, 2015 andSeptember 30, 2015$21,949 $21,563 $3852016Quarters ending December 31, 2015, March 31, 2016, June 30, 2016 andSeptember 30, 2016$22,837 $22,449 $3882017Quarters ending December 31, 2016, March 31, 2017, June 30, 2017 andSeptember 30, 2017$25,534 $25,115 $420In addition, on January 23, 2018 , the Board approved a cash distribution of $0.17875 per outstanding Preferred Unit for the quarter ending December 31,2017 . The Partnership paid this distribution on the Preferred Units on February 14, 2018 , to unitholders of record as of February 2, 2018 . The total distributionwas approximately $6.4 million , with approximately $6.3 million and $0.1 million paid to the Partnership’s preferred unitholders and general partner, respectively.The Partnership paid the following distributions on the common units during the years ended December 31, 2015 , 2016 and 2017 (in thousands):YearPaidPeriods CoveredTotal Paid toCommonUnitholders Paid toGeneralPartner Paid to Phantomand RestrictedUnitholdersUnder the LTIP2015Quarters ending December 31, 2014, March 31, 2015, June30, 2015 and September 30, 2015$19,651 $18,567 $707 $3762016Quarters ending December 31, 2015, March 31, 2016, June30, 2016 and September 30, 2016$21,900 $20,509 $933 $4582017Quarters ending December 31, 2016, March 31, 2017, June30, 2017 and September 30, 2017$23,629 $22,147 $994 $488In addition, on January 23, 2018 , the Board approved a cash distribution of $0.1450 per outstanding common unit for the quarter ending December 31, 2017 .The distribution was paid on February 14, 2018 , to unitholders of record as of February 2, 2018 . The total distribution was approximately $6.2 million , withapproximately $5.8 million and $0.3 million paid to the Partnership’s common unitholders and general partner, respectively, and $0.1 million paid to holders ofphantom and restricted units pursuant to awards granted under the LTIP.F-19Table of Contents12. MAJOR CUSTOMERS AND CONCENTRATION OF CREDIT RISK Significant customers are defined as those who represent 10% or more of our total consolidated revenues during the year.For the year ended December 31, 2015, Vitol accounted for approximately 21% of the Partnership’s total revenues across all of the Partnership’s operatingsegments.For the year ended December 31, 2016, Ergon accounted for approximately 13% of the Partnership’s total revenues, all of which were earned in asphaltterminalling services. Vitol also accounted for approximately 13% of the Partnership’s total revenues, which were earned in all of the Partnership’s operatingsegments.For the year ended December 31, 2017, Ergon accounted for approximately 31% of the Partnership’s total revenues, all of which were earned in asphaltterminalling services. Vitol accounted for approximately 12% of the Partnership’s total revenues, which were earned in all of the Partnership’s operating segments.13 . RELATED-PARTY TRANSACTIONSOn October 5, 2016, Ergon purchased 100% of the Partnership’s general partner from Vitol and Charlesbank, resulting in Ergon being classified as a relatedparty and Vitol and Charlesbank no longer being classified as related parties as of October 5, 2016.The Partnership leases facilities to Ergon and provides liquid asphalt terminalling services to Ergon. For the year ended December 31, 2015 , the Partnershiprecognized revenues of $15.5 million for services provided to Ergon, all of which is classified as third-party revenues. For the year ended December 31, 2016 , thePartnership recognized revenues of $22.2 million for services provided to Ergon, of which $11.0 million is classified as related-party revenue. For the year endedDecember 31, 2017 , the Partnership recognized revenues of $56.4 million for services provided to Ergon, all of which is classified as related-party revenue. As ofDecember 31, 2016 and 2017 , the Partnership had receivables from Ergon of $1.7 million and $3.1 million , respectively.A subsidiary of Ergon provides natural gas service to one of the Partnership’s asphalt terminalling facilities. For the year ended December 31, 2017 , thePartnership recognized $0.5 million of expense for services provided by this subsidiary.The Partnership also provided operating and administrative services to Advantage Pipeline. On April 3, 2017, the Partnership sold its investment in AdvantagePipeline and the operating and administrative services agreement was terminated. For the years ended December 31, 2015 , 2016 and 2017 , the Partnershiprecognized revenues of $1.3 million , $1.3 million and $0.3 million , respectively, for services provided to Advantage Pipeline. As of December 31, 2016 , thePartnership had receivables from Advantage Pipeline of $0.1 million .The Partnership provides crude oil gathering, transportation and terminalling services to Vitol. For the years ended December 31, 2015 and 2016, thePartnership recognized related-party revenues of $37.8 million and $17.9 million , respectively, for services provided to Vitol. As of December 31, 2016 , thePartnership had receivables, net of allowances for doubtful accounts, from Vitol of $1.0 million .Ergon 2017 Lubbock and Saginaw Storage and Handling Agreement In September 2016, the Partnership and Ergon entered into a storage, throughput and handling agreement pursuant to which the Partnership provides Ergonstorage and terminalling services at the Lubbock and Saginaw asphalt terminal facilities. The term of this agreement commenced on January 1, 2017, and continuesfor six years. The Board’s conflicts committee reviewed and approved this agreement in accordance with the Partnership’s procedures for approval of related-partytransactions and the provisions of the partnership agreement. During the year ended December 31, 2017 , the Partnership generated revenues under this agreementof $12.9 million .Ergon 2016 Storage and Handling AgreementIn October 2016, the Partnership and Ergon entered into a storage, throughput and handling agreement (the “Ergon 2016 Storage and Handling Agreement”)pursuant to which the Partnership provides Ergon storage and terminalling services at nine asphalt terminal facilities. The term of the Ergon 2016 Storage,Throughput and Handling Agreement commenced on October 5, 2016, and continues for seven years. The Board’s conflicts committee reviewed and approved thisagreement in accordanceF-20Table of Contentswith the Partnership’s procedures for approval of related-party transactions and the provisions of the partnership agreement. During the years ended December 31,2016 and 2017 , the Partnership generated revenue under this agreement of $6.2 million and $26.4 million , respectively, all of which is classified as related-partyrevenue.Ergon Fontana and Las Vegas Storage Throughput and Handling AgreementIn October 2016, the Partnership and Ergon entered into a storage, throughput and handling agreement (the “Ergon Fontana and Las Vegas StorageThroughput and Handling Agreement”) pursuant to which the Partnership provides Ergon storage and terminalling services at two asphalt facilities. The term ofthe Ergon Fontana and Las Vegas Storage Throughput and Handling Agreement commenced on October 5, 2016, and is scheduled to expire on December 31,2018. The original Ergon Fontana and Las Vegas Master Facilities Lease Agreement commenced on May 18, 2009, and was a part of Ergon Master FacilitiesLease and Sublease Agreement. See Ergon Master Facilities Lease and Sublease Agreement for additional detail regarding prior terms and conditions. The Board’sconflicts committee reviewed and approved this agreement in accordance with the Partnership’s procedures for approval of related-party transactions and theprovisions of the partnership agreement. During the years ended December 31, 2016 and 2017 , the Partnership generated revenues under this agreement of $1.5million and $6.2 million , respectively, all of which is classified as related-party revenue.Ergon Master Facilities Lease and Sublease AgreementIn May 2009, the Partnership and Ergon entered into a facilities lease and sublease agreement (the “Ergon Master Facilities Lease and Sublease Agreement”)pursuant to which the Partnership leases Ergon certain facilities. The original term of the Ergon Master Facilities Lease and Sublease Agreement commenced onMay 18, 2009, for two years, until December 31, 2011. The Ergon Master Facilities Lease and Sublease Agreement has been amended and extended several timesand currently encompasses eight facilities and is scheduled to expire on December 31, 2018. The Board’s conflicts committee reviewed and approved theseagreements in accordance with the Partnership’s procedures for approval of related-party transactions and the provisions of the partnership agreement. During theyear ended December 31, 2015 , the Partnership generated revenues under this agreement of $10.5 million , all of which is classified as third-party revenue. Duringthe year ended December 31, 2016, the Partnership generated revenues under this agreement of $9.2 million , of which $1.8 million is classified as related-partyrevenue. During the year ended December 31, 2017, the Partnership generated revenues under this agreement of $5.2 million , all of which is classified as related-party revenue.Ergon Master Facilities Sublease and Sublicense Agreement In May 2009, the Partnership and Ergon entered into multiple sublease and sublicense agreements covering five facilities. The original terms of theseagreements commenced on May 18, 2009, for two years, until December 31, 2011. In November 2010, these multiple leases were consolidated under one mastersublease and sublicense agreement. This agreement was amended in June 2015 and has a term scheduled to expire on December 31, 2018. During the year endedDecember 31, 2015 , the Partnership generated revenues under this agreement of $3.2 million , all of which is classified as third-party revenue. During the yearended December 31, 2016, the Partnership generated revenues under this agreement of $3.6 million , of which $1.0 million is classified as related-party revenue.During the year ended December 31, 2017, the Partnership generated revenues under this agreement of $3.7 million , all of which is classified as related-partyrevenue.Vitol Storage AgreementsIn recent years, a significant portion of the Partnership’s crude oil storage capacity has been dedicated to Vitol under multiple agreements. As of December31, 2015 , 2016 and 2017 , 2.2 million barrels of storage capacity were dedicated to Vitol under these storage agreements. Service revenues under theseagreements are based on the barrels of storage capacity dedicated to Vitol under the applicable agreement at rates that, the Partnership believes, are fair andreasonable to the Partnership and its unitholders and are comparable with the rates the Partnership charges third parties. The Board’s conflicts committeereviewed and approved these agreements in accordance with the Partnership’s procedures for approval of related-party transactions and the provisions of thepartnership agreement. For the year ended December 31, 2015, the Partnership generated revenues under these agreements of approximately $9.4 million , all ofwhich is classified as related-party revenue. For the year ended December 31, 2016, the Partnership generated revenues under these agreements of approximately$9.6 million , of which $7.5 million is classified as related-party revenue. All revenue under these agreements for 2017 is classified as third-party revenue.As of March 1, 2018 , 2.2 million barrels of storage capacity were dedicated to Vitol under the crude oil storage agreement with the current term scheduled toexpire on April 30, 2018.F-21Table of Contents Vitol Operating and Maintenance AgreementIn August 2011, the Partnership and Vitol entered into an operating and maintenance agreement (the “Vitol O&M Agreement”) relating to the operation andmaintenance of Vitol’s crude oil terminal located in Midland, Texas (the “Midland Terminal”) and Vitol’s crude oil gathering system located near Midland, Texas(the “Midland Gathering System”). Pursuant to the Vitol O&M Agreement, the Partnership provided certain operating and maintenance services with respect to theMidland Terminal and Midland Gathering System. The term of the Vitol O&M Agreement commenced on September 1, 2012, and was terminated in July 2015.During the year ended December 31, 2015 , the Partnership generated revenues of $2.5 million under the Vitol O&M Agreement, which included a termination feeof $1.2 million and transition services fees of $0.1 million . The Partnership believes that the rates it charged Vitol under the Vitol O&M Agreement were fair andreasonable to the Partnership and its unitholders and were comparable with the rates the Partnership charges third parties. The Board’s conflicts committeereviewed and approved the Vitol O&M Agreement in accordance with the Partnership’s procedures for approval of related-party transactions and the provisions ofthe partnership agreement. 14 . LONG-TERM INCENTIVE PLANIn July 2007, the general partner adopted the LTIP, which is administered by the compensation committee of the Board. Effective April 29, 2014, thePartnership’s unitholders approved an amendment to the LTIP to increase the number of common units reserved for issuance under the incentive plan to 4.1million common units, subject to adjustment for certain events. Although other types of awards are contemplated under the LTIP, currently outstanding awardsinclude “phantom” units, which convey the right to receive common units upon vesting, and “restricted” units, which are grants of common units restricted untilthe time of vesting. Certain of the phantom unit awards also include 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 tothe vesting date of the underlying award. Recipients of restricted and phantom units are entitled to receive cash distributions paid on common units during thevesting period which are reflected initially as a reduction of partners’ capital. Distributions paid on units that ultimately do not vest are reclassified ascompensation expense. Awards granted to date are equity awards and, accordingly, the fair value of the awards as of the grant date is expensed over the vestingperiod. In connection with each anniversary of joining the Board, restricted common units are granted to the independent directors. The units vest in one-thirdincrements over three years. The following table includes information on grants made to the directors under the LTIP subject to vesting requirements:Grant DateNumber ofUnits Weighted AverageGrant Date FairValue Grant Date TotalFair Value(in thousands)December 201515,120 $5.06 $77December 201610,950 $6.85 $75December 201715,306 $4.85 $74In October 2016, all of the independent directors’ remaining unvested 2015 units vested due to the Ergon Change of Control. The Partnership recordedcompensation cost of $0.1 million during the year ended December 31, 2016 , related to this early vesting.In addition, the independent directors received common unit grants that have no vesting requirement as part of their compensation. The following tableincludes information on grants made to the directors under the LTIP that have no vesting requirement:Grant DateNumber ofUnits Weighted AverageGrant Date FairValue Grant Date TotalFair Value(in thousands)December 201610,220 $6.85 $70December 201714,286 $4.85 $69F-22Table of ContentsThe Partnership also grants phantom units to employees. These grants are equity awards under ASC 718 – Stock Compensation and, accordingly, the fair valueof the awards as of the grant date is expensed over the vesting period. The following table includes information on the outstanding grants:Grant DateNumber ofUnits Weighted AverageGrant Date FairValue Grant Date TotalFair Value(in thousands)March 2015266,076 $7.74 $2,059March 2016416,131 $4.77 $1,985October 20169,960 $5.85 $58March 2017323,339 $7.15 $2,312 The unrecognized estimated compensation cost relating to outstanding phantom units at December 31, 2017 , was $2.1 million , which will be recognized overthe remaining vesting period. On January 1, 2018, 206,238 units of the March 2015 grant vested.In September 2012 , Mark Hurley was granted 500,000 phantom units under the LTIP upon his employment as the Chief Executive Officer of the generalpartner. These grants were equity awards under ASC 718 – Stock Compensation and, accordingly, the fair value of the awards as of the grant date was expensedover the vesting period. These units vested ratably over five years pursuant to the Employee Phantom Unit Agreement between Mr. Hurley and the general partnerand did not include DERs. The weighted average grant date fair value per unit of $5.62 was determined based on the closing market price of the Partnership’scommon units on the grant date of the award, less the present value of the estimated distributions to be paid to holders of an outstanding common unit prior to thevesting of the underlying award. The value of this award grant was approximately $2.8 million on the grant date. The final portion of this award vested duringSeptember 2017, and there was no unrecognized estimated compensation cost as of December 31, 2017 .The Partnership’s equity-based incentive compensation expense for the years ended December 31, 2015 , 2016 and 2017 was $2.7 million , $2.5 million and$2.2 million , respectively.Activity pertaining to phantom common units and restricted common unit awards granted under the LTIP is as follows: Number ofUnits Weighted AverageGrant Date FairValueNonvested, December 31, 2016915,180 $6.61Granted352,931 6.96Vested331,860 7.82Forfeited12,700 6.69Nonvested, December 31, 2017923,551 $6.2915. EMPLOYEE BENEFIT PLAN Under the Partnership’s 401(k) Plan, which was instituted in 2009 , employees who meet specified service requirements may contribute a percentage of theirtotal compensation, up to a specified maximum, to the 401(k) Plan. The Partnership may match each employee’s contribution, up to a specified maximum, in fullor on a partial basis. The Partnership recognized expense of $1.5 million for the year ended December 31, 2015 , and $1.2 million for each of the years endedDecember 31, 2016 and 2017 , for discretionary contributions under the 401(k) Plan.The Partnership may also make annual lump-sum contributions to the 401(k) Plan irrespective of the employee’s contribution match. The Partnership maymake a discretionary annual contribution in the form of profit sharing calculated as a percentage of an employee’s eligible compensation. This contribution isretirement income under the qualified 401(k) Plan. Annual profit sharing contributions to the 401(k) Plan are submitted to the Board for approval. The Partnershiprecognized expense of $0.9 million for the year ended December 31, 2015 , and $0.8 million for each of the years ended December 31, 2016 and 2017 ,respectively, for discretionary profit sharing contributions under the 401(k) Plan. F-23Table of Contents16. PROFITS INTEREST OF BLUEKNIGHT GP HOLDING, LLCIn October 2012, the owners of Blueknight GP Holding, LLC (“HoldCo”), the owner of the general partner, admitted Mr. Hurley as a member of HoldCo. Inconnection with his admission as a member of HoldCo, Mr. Hurley was issued a non-voting economic interest in HoldCo (the “Profits Interest”). Upon the ErgonChange of Control, Vitol and Charlesbank, the previous owners of HoldCo, repurchased and canceled the Profits Interest.Although the entire economic burden of the Profits Interest, which was equity classified, was borne solely by HoldCo and did not impact the Partnership’scash or units outstanding, the intent of the Profits Interest was to provide a performance incentive and encourage retention of Mr. Hurley. Therefore, thePartnership recognized the grant date fair value of the Profits Interest as compensation expense over the service period and the repurchase of the Profits Interest inthe period paid. The expense is also reflected as a capital contribution and, therefore, results in a corresponding credit to partners’ capital in the Partnership’sconsolidated financial statements. The Partnership recognized expense of $0.1 million and $0.9 million in relation to the Profits Interest during the years endedDecember 31, 2015 and 2016 , respectively.17 . COMMITMENTS AND CONTINGENCIESThe Partnership leases certain real property, equipment and operating facilities under various operating 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 no longer berequired for operations. Future non-cancellable commitments related to these items at December 31, 2017 , are summarized below (in thousands): For year ending:OperatingLeasesDecember 31, 2018$4,813December 31, 20193,307December 31, 20201,707December 31, 20211,022December 31, 2022736Thereafter1,284Total future minimum lease payments$12,869 Rental expense related to operating leases was $9.5 million , $6.5 million and $6.2 million for the years ended December 31, 2015 , 2016 and 2017 ,respectively.The Partnership is from time to time subject to various legal actions and claims incidental to its business. Management believes that these legal proceedingswill not have a material adverse effect on the financial position, results of operations or cash flows of the Partnership. Once management determines thatinformation pertaining to a legal proceeding indicates that it is probable that a liability has been incurred and the amount of such liability can be reasonablyestimated, an accrual is established equal to its estimate of the likely exposure. The Partnership has contractual obligations to perform dismantlement and removal activities in the event that some of its asphalt product and residual fuel oilterminalling assets are abandoned. These obligations include varying levels of activity, including completely removing the assets and returning the land to itsoriginal state. The Partnership has determined that the settlement dates related to the retirement obligations are indeterminate. The assets with indeterminatesettlement 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 possibleto predict when demands for the Partnership’s terminalling services will cease, and the Partnership does not believe that such demand will cease in the foreseeablefuture. 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 assetretirement obligations were settled in the foreseeable future, the potential cash flows that would be required to settle the obligations based on current costs are notmaterial. The Partnership will record asset retirement obligations for these assets in the period in which sufficient information becomes available for it toreasonably determine the settlement dates.18. ENVIRONMENTAL REMEDIATIONThe Partnership maintains insurance of various types with varying levels of coverage that it considers adequate under the circumstances to cover its operationsand properties. The insurance policies are subject to deductibles and retention levels thatF-24Table of Contentsthe Partnership considers reasonable and not excessive. Consistent with insurance coverage generally available in the industry, in certain circumstances thePartnership’s insurance policies provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidentaloccurrences. Although the Partnership maintains a program designed to prevent and, as applicable, to detect and address such releases promptly, damages andliabilities incurred due to environmental releases from its assets may substantially affect its business. At December 31, 2016 and 2017 , the Partnership was aware of existing conditions that may cause it to incur expenditures in the future for the remediation ofexisting environmental matters. The Partnership had no related loss contingencies as of December 31, 2016 . The Partnership had loss contingencies of $0.1million related to environmental matters as of December 31, 2017 . Changes in the Partnership’s estimates and assumptions may occur as a result of the passage oftime and the occurrence of future events.19. FAIR VALUE MEASUREMENTS The Partnership uses valuation techniques, such as the market approach (comparable market prices), the income approach (present value of future income orcash flow) and the cost approach (cost to replace the service capacity of an asset or replacement cost) to value these assets and liabilities as appropriate. ThePartnership uses an exit price when determining the fair value. The exit price represents amounts that would be received to sell an asset or paid to transfer aliability in an orderly transaction between market participants. The Partnership utilizes a three-tier fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels.The following is a brief description of those three levels:Level 1Observable inputs such as quoted prices (unadjusted) in active markets for identical assets or liabilities.Level 2Inputs other than quoted prices that are observable for these assets or liabilities, either directly or indirectly. These include quoted prices forsimilar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active.Level 3Unobservable inputs in which there is little market data, which requires the reporting entity to develop its own assumptions. This hierarchy requires the use of observable market data, when available, to minimize the use of unobservable inputs when determining fair value. In periodsin which they occur, the Partnership recognizes transfers into and out of Level 3 as of the end of the reporting period. Transfers out of Level 3 represent existingassets and liabilities that were classified previously as Level 3 for which the observable inputs became a more significant portion of the fair value estimates.Determining the appropriate classification of the Partnership’s fair value measurements within the fair value hierarchy requires management’s judgment regardingthe degree to which market data is observable or corroborated by observable market data.The Partnership’s recurring financial assets and liabilities subject to fair value measurements and the necessary disclosures are as follows (in thousands): Fair Value Measurements as of December 31, 2016DescriptionTotal Quoted Pricesin ActiveMarkets forIdentical Assets(Level 1) SignificantOtherObservableInputs(Level 2) SignificantUnobservableInputs (Level 3)Liabilities: Interest rate swap liabilities$1,947 $— $1,947 $—Total swap liabilities$1,947 $— $1,947 $—F-25Table of Contents Fair Value Measurements as of December 31, 2017DescriptionTotal Quoted Pricesin ActiveMarkets forIdentical Assets(Level 1) SignificantOtherObservableInputs(Level 2) SignificantUnobservableInputs (Level 3)Assets: Interest rate swap assets$68 $— $68 $—Total swap assets$68 $— $68 $—Liabilities: Interest rate swap liabilities$225 $— $225 $—Total swap liabilities$225 $— $225 $—Fair Value of Other Financial InstrumentsThe following disclosure of the estimated fair value of financial instruments is made in accordance with accounting guidance for financial instruments. ThePartnership has determined the estimated fair values by using available market information and valuation methodologies. Considerable judgment is required ininterpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect onthe estimated fair value amounts. At December 31, 2017 , the carrying values on the consolidated balance sheets for cash and cash equivalents (classified as Level 1), accounts receivable andaccounts payable approximate their fair value because of their short-term nature. Based on the borrowing rates currently available to the Partnership for credit agreement debt with similar terms and maturities and consideration of thePartnership’s non-performance risk, long-term debt associated with the Partnership’s credit agreement at December 31, 2017 , approximates its fair value. The fairvalue of the Partnership’s long-term debt was calculated using observable inputs (LIBOR for the risk-free component) and unobservable company-specific creditspread information. As such, the Partnership considers this debt to be Level 3.20 . OPERATING SEGMENTSThe Partnership’s operations consist of four operating segments: (i) asphalt terminalling services, (ii) crude oil terminalling services, (iii) crude oil pipelineservices and (iv) crude oil trucking and producer field services. ASPHALT TERMINALLING SERVICES — The Partnership provides liquid asphalt cement and residual fuel oil terminalling services at its 56terminalling facilities located in 26 states. CRUDE OIL TERMINALLING SERVICES — The Partnership provides crude oil terminalling services at its terminalling facility located in Oklahoma.CRUDE OIL PIPELINE SERVICES — The Partnership owns and operates pipeline systems that gather crude oil purchased by its customers and transportsit to refiners, to common carrier pipelines for ultimate delivery to refiners or to terminalling facilities owned by the Partnership and others. The Partnership refersto its pipeline system located in Oklahoma and the Texas Panhandle as the Mid-Continent pipeline system. The Partnership previously owned and operated theEast Texas pipeline system, which is located in Texas. On April 18, 2017, the Partnership sold the East Texas pipeline system. See Note 7 for additionalinformation. Crude oil marketing revenues consist of sales proceeds recognized for the sale of crude oil to third-party customers. Revenue for the sale of crude oilis recognized when title to the crude oil transfers to the customer and is based on contractual prices for the sale of crude oil. CRUDE OIL TRUCKING AND PRODUCER FIELD SERVICES — The Partnership uses its owned and leased tanker trucks to gather crude oil for itscustomers at remote wellhead locations generally not covered by pipeline and gathering systems and to transport the crude oil to aggregation points andterminalling facilities located along pipeline gathering and transportation systems. Crude oil producer field services consist of a number of producer field services,ranging from gathering condensates from natural gas companies to hauling produced water to disposal wells.F-26Table of ContentsThe Partnership’s management evaluates performance based upon segment operating margin, which includes revenues from related parties and externalcustomers and operating expense excluding depreciation and amortization. The non-GAAP measure of operating margin (in the aggregate and by segment) ispresented in the following table. The Partnership computes the components of operating margin by using amounts that are determined in accordance with GAAP.The Partnership accounts for intersegment product sales as if the sales were to third parties, that is, at current market prices. A reconciliation of operating margin toincome before income taxes, which is its nearest comparable GAAP financial measure, is included in the following table. The Partnership believes that investorsbenefit from having access to the same financial measures being utilized by management. Operating margin is an important measure of the economic performanceof 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 howto allocate capital resources among segments. Income before income taxes, alternatively, includes expense items, such as depreciation and amortization, generaland administrative expenses and interest expense, which management does not consider when evaluating the core profitability of the Partnership’s operations.The following table reflects certain financial data for each segment for the periods indicated (in thousands): F-27Table of Contents Year ended December 31, 2015 2016 2017Asphalt Terminalling Services Service revenue: Third-party revenue$72,152 $75,655 $57,486Related-party revenue1,278 11,762 56,378Total revenue for reportable segments73,430 87,417 113,864Operating expense (excluding depreciation and amortization)25,218 30,648 49,241Operating margin (excluding depreciation and amortization)48,212 56,769 64,623Additions to long-lived assets19,769 148,622 22,046Total assets (end of period)$98,848 $141,280 $146,966 Crude Oil Terminalling Services Service revenue: Third-party revenue$13,076 $16,387 $22,177Related-party revenue11,522 7,858 —Total revenue for reportable segments24,598 24,245 22,177Operating expense (excluding depreciation and amortization)5,756 4,197 4,200Operating margin (excluding depreciation and amortization)18,842 20,048 17,977Additions to long-lived assets3,282 2,126 2,194Total assets (end of period)$73,502 $71,689 $69,149 Crude Oil Pipeline Services Service revenue: Third-party revenue$15,148 $8,662 $9,580Related-party revenue10,687 5,433 310Product sales revenue: Third-party revenue3,511 20,968 11,094Total revenue for reportable segments29,346 35,063 20,984Operating expense (excluding depreciation and amortization)18,162 15,270 13,310Operating expense (intersegment)259 890 417Cost of product sales3,231 14,130 8,807Cost of product sales (intersegment)— 426 150Operating margin (excluding depreciation and amortization)7,694 4,347 (1,700)Additions to long-lived assets34,953 8,250 2,934Total assets (end of period)$175,142 $150,043 $117,749 Crude Oil Trucking and Producer Field Services Service revenue: Third-party revenue$37,039 $25,511 $24,529Related-party revenue15,616 5,158 —Intersegment revenue259 890 417Product sales revenue: Third-party revenue— — 385Intersegment revenue— 426 150F-28Table of Contents Year ended December 31, 2015 2016 2017Total revenue for reportable segments52,914 31,985 25,481Operating expense (excluding depreciation and amortization)51,610 30,156 25,915Operating margin (excluding depreciation and amortization)1,304 1,829 (434)Additions to long-lived assets4,556 2,558 1,701Total assets (end of period)$17,256 $12,651 $7,005 Total operating margin (excluding depreciation and amortization) (1)$76,052 $82,993 $80,466 Total segment revenues180,288 178,710 182,506Elimination of intersegment revenues(259) (1,316) (567)Consolidated revenues180,029 177,394 181,939____________________(1)The following table reconciles segment operating margin (excluding depreciation and amortization) to income (loss) before income taxes (in thousands): Year ended December 31, 2015 2016 2017Operating margin (excluding depreciation and amortization) $76,052 $82,993 $80,466Depreciation and amortization (27,228) (30,820) (31,139)General and administrative expenses (18,976) (20,029) (17,112)Asset impairment expense (21,996) (25,761) (2,400)Gain (loss) on sale of assets 6,137 108 (975)Equity earnings in unconsolidated affiliate 3,932 1,483 61Gain on sale of unconsolidated affiliate — — 5,337Interest expense (11,202) (12,554) (14,027)Income (loss) before income taxes $6,719 $(4,580) $20,21121 . INCOME TAXES The anticipated after-tax economic benefit of an investment in the Partnership’s common units depends largely on the Partnership being treated as apartnership 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 forthat 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 applicable corporatetax rate and would likely pay state income tax at varying rates. Distributions would generally be taxed again to unitholders as corporate distributions and none ofthe Partnership’s income, gains, losses, deductions or credits would flow through to its unitholders. Because a tax would be imposed upon the Partnership as anentity, cash available for distribution to its unitholders would be substantially reduced. Treatment of the Partnership as a corporation would result in a materialreduction 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’scommon units.The Partnership has entered into storage contracts and leases with third-party customers with respect to substantially all of its asphalt facilities. At the time ofentering into such agreements, it was unclear under current tax law as to whether the rental income from the leases, and the fees attributable to certain of theprocessing services the Partnership provides under certain of the storage contracts, constitute “qualifying income.” In the second quarter of 2009, the Partnershipsubmitted a request for a ruling from the IRS that rental income from the leases constitutes “qualifying income.” In October 2009, the Partnership received afavorable ruling from the IRS. As part of this ruling, however, the Partnership agreed to transfer, and has transferred, certain of its asphalt processing assets andrelated fee income to a subsidiary taxed as a corporation. This transfer occurred in the first quarter of 2010. Such subsidiary is required to pay federal income taxon its income at the applicable corporate tax rate and will likely pay state (and possibly local) income tax at varying rates. Distributions from this subsidiary willgenerallyF-29Table of Contentsbe taxed again to unitholders as corporate distributions and none of the income, gains, losses, deductions or credits of this subsidiary will flow through to thePartnership’s unitholders.On December 22, 2017, the Tax Cut and Jobs Act (“TCJA”) was enacted into law. Among its many tax reform provisions, TCJA reduced the federal corporateincome tax rate from 35% to 21% for the tax year beginning after December 31, 2017. As a result, the Partnership revalued the deferred tax effects of thetemporary differences between its taxable subsidiary’s tax basis of assets and liabilities and the financial reporting amounts at December 31, 2017 , which resultedin a reduction of the taxable subsidiary’s gross deferred tax asset of $0.3 million . The net deferred tax effect of the taxable entity’s temporary differences atDecember 31, 2017 , are presented below (in thousands): Deferred Tax Asset Difference in bases of property, plant and equipment$484Deferred tax asset484 Less: valuation allowance(484)Net deferred tax asset$— The Partnership has considered the taxable income projections in future years, whether the carryforward period is so brief that it would limit realization of taxbenefits, whether future revenue and operating cost projections will produce enough taxable income to realize the deferred tax asset based on existing service ratesand cost structures, and the Partnership’s earnings history exclusive of the loss that created the future deductible amount for the Partnership’s subsidiary that istaxed as a corporation for purposes of determining the likelihood of realizing the benefits of the deferred tax assets. As a result of the Partnership’s consideration ofthese factors, the Partnership has provided a full valuation allowance against its deferred tax asset as of December 31, 2017 .22 . RECENTLY ISSUED ACCOUNTING STANDARDSIn May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers.” The amendments in this update create Topic 606, Revenue fromContracts with Customers, and supersede the revenue recognition requirements in Topic 605, Revenue Recognition, including most industry-specific revenuerecognition guidance throughout the Industry Topics of the Codification. In summary, the core principle of Topic 606 is that an entity recognizes revenue to depictthe transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for thosegoods or services. Throughout 2015, 2016 and 2017, the FASB issued a series of subsequent updates to the revenue recognition guidance in Topic 606.The amendments in ASU 2014-09 and the related updates are effective for public entities for annual reporting periods beginning after December 15, 2017, andfor interim periods within that reporting period. The Partnership adopted this standard as of January 1, 2018, using the modified retrospective approach, whichallows for applying the new standard to (i) all new contracts entered into after January 1, 2018, and (ii) all existing contracts for which all (or substantially all) ofthe revenue has not been recognized under legacy revenue guidance as of January 1, 2018, through a cumulative adjustment to equity. Revenues presented in thecomparative consolidated financial statements for periods prior to January 1, 2018, will not be revised.The impact of adopting the new standard on the Partnership’s financial statements is not material, and the Partnership will have no cumulative adjustment toPartners’ capital as of January 1, 2018, related to the adoption of the standard. The impact of adopting Topic 606 primarily relates to the timing of the Partnership’srevenue recognition on some of its minimum throughput fees, which could be deferred within a single reporting year. As a result, some revenue that washistorically recognized in the third quarter will now be recognized in the fourth quarter of each year. The overall impact to the Partnership’s results is not materialas the analysis of the Partnership’s contracts under the new revenue recognition standard supports the recognition of revenue as services are performed, which isconsistent with the Partnership’s current revenue recognition model. Revenue from the majority of the Partnership’s contracts will continue to be recognized asservices are performed. Topic 606 requires the separate presentation of revenue from customers accounted for under Topic 606 and revenue from leases accountedfor under Topic 840 on the face of the statement of operations and, as a result, the Partnership will begin separately presenting these two components of revenue inits consolidated financial statements to be included in the Partnership’s Form 10-Q for the three-month period ending March 31, 2018. In addition, the adoption ofthe new guidance will require expanded disclosures. F-30Table of ContentsIn November 2015, the FASB issued ASU 2015-17, “Income Taxes (Topic 740).” This update simplifies the presentation of deferred income taxes on thebalance sheet. This update is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those fiscalyears. The Partnership adopted this update in the three-month period ended March 31, 2017, and there was no impact on the Partnership’s financial position, resultsof operations or cash flows.In January 2016, the FASB issued ASU 2016-01, “Financial Instruments - Overall (Subtopic 825-10).” This update is intended to enhance the reporting modelfor financial instruments in order to provide users of financial statements with more decision-useful information. The amendments in the update address certainaspects of recognition, measurement, presentation and disclosure of financial instruments. This update is effective for financial statements issued for annual periodsbeginning after December 15, 2017, and interim periods within those fiscal years. The Partnership has evaluated the impact of this guidance, which will be adoptedbeginning with the Partnership’s quarterly report for the three-month period ending March 31, 2018, and there will be no impact on the Partnership’s financialposition, results of operations or cash flows.In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” This update introduces a new lease model that requires the recognition of leaseassets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. Throughout 2017 and 2018, the FASB issued aseries of subsequent updates to the guidance in Topic 842. This update, as well as related updates, is effective for financial statements issued for annual periodsbeginning after December 15, 2018, and interim periods within those fiscal years. The Partnership is evaluating the impact of this guidance, which will be adoptedbeginning with the Partnership’s quarterly report for the three-month period ending March 31, 2019.In March 2016, the FASB issued ASU 2016-09, “Compensation - Stock Compensation (Topic 718).” This update is intended to simplify the accounting forshare-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statementof cash flows. This update is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those fiscalyears. The Partnership adopted this update in the three-month period ended March 31, 2017, and there was no impact on the Partnership’s financial position, resultsof operations or cash flows.In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.” Thisupdate addresses the following eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or otherdebt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments madeafter a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies (includingbank-owned life insurance policies); distributions received from equity method investees; beneficial interests in securitization transactions; and separatelyidentifiable cash flows and application of the predominance principle. This update is effective for financial statements issued for annual periods beginning afterDecember 15, 2017, and interim periods within those fiscal years. The Partnership has evaluated the impact of this guidance, which will be adopted beginning withthe Partnership’s quarterly report for the three-month period ending March 31, 2018, and there will be no impact on the Partnership’s financial position, results ofoperations or cash flows.In October 2016, the FASB issued ASU 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory.” This update is intendedto improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. The amendments in the update eliminate theprohibition of recognizing current and deferred income taxes for an intra-entity asset transfer other than inventory until the asset has been sold to an outside party.This update is effective for financial statements issued for annual periods beginning after December 15, 2017, and interim periods within those fiscal years. ThePartnership has evaluated the impact of this guidance, which will be adopted beginning with the Partnership’s quarterly report for the three-month period endingMarch 31, 2018, and there will be no impact on the Partnership’s financial position, results of operations or cash flows.In November 2016, the FASB issued ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash (a Consensus of the FASB Emerging Issues TaskForce).” This update requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generallydescribed as restricted cash or restricted cash equivalents . This update is effective for financial statements issued for annual periods beginning after December 15,2017, and interim periods within those fiscal years. The Partnership has evaluated the impact of this guidance, which will be adopted beginning with thePartnership’s quarterly report for the three-month period ending March 31, 2018, and there will be no impact on the Partnership’s financial position, results ofoperations or cash flows.In January 2017, the FASB issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business.” This update clarifies thedefinition of a business with the objective of adding guidance to assist entities withF-31Table of Contentsevaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This update is effective for financial statementsissued for annual periods beginning after December 15, 2017, and interim periods within those fiscal years. The Partnership has evaluated the impact of thisguidance, which will be adopted beginning with the Partnership’s quarterly report for the three-month period ending March 31, 2018.In January 2017, the FASB issued ASU 2017-04, “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” This updatesimplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwillimpairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. This update is effective for financialstatements issued for annual periods beginning after December 15, 2019, and interim periods within those fiscal years. The Partnership early-adopted this update inthe fourth quarter of 2017 and there was no impact on the Partnership’s financial position, results of operations or cash flows.In February 2017, the FASB issued ASU 2017-05, “Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20).” Thisupdate clarifies the scope of Subtopic 610-20 and adds guidance for partial sales of nonfinancial assets. Subtopic 610-20, which was issued in May 2014 as a partof ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)”, provides guidance for recognizing gains and losses from the transfer of nonfinancialassets in contracts with noncustomers. The amendments in ASU 2017-05 are effective for public entities for annual reporting periods beginning after December 15,2017, and for interim periods within that reporting period. Early adoption is permitted for annual reporting periods beginning after December 15, 2016. ThePartnership has evaluated the impact of this standard, which will be adopted beginning with the Partnership’s quarterly report for the three-month period endingMarch 31, 2018, and does not expect a material impact on the Partnership’s financial position, results of operations or cash flows.In May 2017, the FASB issued ASU 2017-09, “Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting.” This update providesclarity and reduces both diversity in practice and cost and complexity when applying the guidance of Topic 718, Compensation - Stock Compensation, to a changein the terms or conditions of a share-based payment award. This update is effective for financial statements issued for annual periods beginning after December 15,2017, and interim periods within those fiscal years. The Partnership has evaluated the impact of this guidance, which will be adopted beginning with thePartnership’s quarterly report for the three-month period ending March 31, 2018, and does not expect a material impact on the Partnership’s financial position,results of operations or cash flows.23. QUARTERLY FINANCIAL DATA (UNAUDITED) Summarized quarterly financial data is as follows (in thousands, except per unit data): FirstQuarter SecondQuarter ThirdQuarter FourthQuarter Full Year2016: Revenues$41,009 $43,425 $46,939 $46,021 $177,394Operating income (loss) (1)5,013 (15,348)13,398 3,428 6,491Net income (loss) (1)726 (18,936)11,419 1,951 (4,840)Basic and diluted net income (loss) per common unit(0.14) (0.71)0.13 (0.18) (0.87) 2017: Revenues (2)$46,340 $43,877$47,474 $44,248 $181,939Operating income (2)6,557 6,50512,219 3,559 28,840Net income (2)3,542 6,3719,771 361 20,045Basic and diluted net income (loss) per common unit(0.08) — 0.08 (0.15) (0.15)____________________(1)Operating loss and net loss for the second quarter of 2016 are impacted by asset impairments as described in Note 3 .(2)In April 2017, the Partnership sold the East Texas pipeline system and its investment in Advantage Pipeline. See “Item 7-Management’s Discussion and Analysis” for discussion on theimpact these changes had on the Partnership’s consolidated financial statements.24. SUBSEQUENT EVENTSOn March 7, 2018, the Partnership acquired an asphalt terminalling facility located in Oklahoma from a third party for $22.0 million .F-32Exhibit 10.7FIRST AMENDMENT TO THEBLUEKNIGHT ENERGY PARTNERS, G.P, L.L.C.LONG-TERM INCENTIVE PLANWHEREAS , Blueknight Energy Partners G.P., L.L.C., a Delaware limited liability company (the “ Company ”) and the generalpartner of Blueknight Energy Partners, L.P., a Delaware limited partnership, maintains the Blueknight Energy Partners, G.P., L.L.C. Long-Term Incentive Plan, as amended from time to time (the “ Plan ”); andWHEREAS , the Company has determined that amendments should be made to the Plan to revise the definition of “Change ofControl” contained therein.NOW, THEREFORE , the Plan is hereby amended as follows:1. The defined term “Change of Control” contained in Section 2 of the Plan is deleted in its entirety and replaced with thefollowing:“ Change of Control ” means, and shall be deemed to have occurred upon the occurrence of one or more of the following events: (i)any “person” or “group” within the meaning of those terms as used in Sections 13(d) and 14(d)(2) of the Exchange Act, other thanErgon, Inc. or its Affiliates, shall become the beneficial owner, by way of merger, consolidation, recapitalization, reorganization orotherwise, of 50% or more of the combined voting power of the equity interests in the Company or the Partnership; (ii) the limitedpartners of the Partnership approve, in one or a series of transactions, a plan of complete liquidation of the Partnership; (iii) the sale orother disposition by either the Company or the Partnership of all or substantially all of its assets in one or more transactions to anyPerson other than the Company or an Affiliate of the Company; or (iv) a transaction resulting in a Person other than the Company oran Affiliate of the Company being the general partner of the Partnership. Anything in this definition to the contrary notwithstanding,with respect to any Award which constitutes deferred compensation subject to, and not exempt from, Code Section 409A, no Changeof Control shall be deemed to have occurred unless such event constitutes an event specified in Code Section 409A(a)(2)(A)(v) andthe Treasury Regulations promulgated thereunder.2. Except as expressly provided herein, all other provisions of the Plan shall remain in full force and effect and are hereby ratifiedand confirmed.[Signature Page Follows.]IN WITNESS WHEREOF, this First Amendment to the Plan is executed and effective this 17 day of January, 2018. Blueknight Energy Partners G.P., L.L.C., a Delaware limited liability company By: /s/ Alex. G. Stallings Name:Alex G. Stallings Title:Chief Financial Officer and Secretary  Exhibit 10.9BLUEKNIGHT ENERGY PARTNERS G.P., L.L.C.LONG-TERM INCENTIVE PLANEMPLOYEE PHANTOM UNIT AGREEMENTThis Phantom Unit Agreement (“Agreement”) between Blueknight Energy Partners G.P., L.L.C. (the “Company”) and [[FirstLast]] (the “Participant”), regarding an award (“Award”) of [[# of units]] Phantom Units (as defined in the Blueknight Energy Partners G.P.,L.L.C. Long-Term Incentive Plan (the “Plan”)) granted to the Participant on [[Grant Date]] (the “Grant Date”), such number of PhantomUnits subject to adjustment as provided in the Plan, and further subject to the following terms and conditions:1. Relationship to Plan. This Award is subject to all of the terms, conditions and provisions of the Plan and administrativeinterpretations thereunder, if any, which have been adopted by the Committee thereunder and are in effect on the date hereof. Except asotherwise provided herein, capitalized terms shall have the same meanings ascribed to them under the Plan.2. Definitions.“ Cause ” means (i) conviction of the Participant by a court of competent jurisdiction of any felony or a crime involvingmoral turpitude; (ii) the Participant’s willful and intentional failure or willful and intentional refusal to follow reasonable and lawfulinstructions of the Board; (iii) the Participant’s material breach or default in the performance of his obligations under this Agreement; or (iv)the Participant’s act of misappropriation, embezzlement, intentional fraud or similar conduct involving the Company or any of its Affiliates.“ Disability ” means the Participant either (i) is unable to engage in any substantial gainful activity by reason of anymedically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuousperiod of not less than 12 months or (ii) the Participant is, by reason of any medically determinable physical or mental impairment that can beexpected to result in death or can be expected to last for a continuous period of not less than 12 months, receiving income replacementbenefits for a period of not less than three months under an accident and health plan covering employees of the Company or any entity thatwould be considered a single “service recipient” with the Company pursuant to Section 409A of the Internal Revenue Code of 1986, asamended (the “Code”).“Retirement” means the Participant’s employment with the Company and all its Affiliates terminates (other than due todeath, Disability or Cause) on or after he attains age 57 with at least five years of service with the Company or its Affiliates.3. Vesting Schedule; Settlement.(a) The Phantom Units subject to this Award shall vest as follows:1 [each] such vesting date, ([a/the] “Vesting Date”). The Participant must be continuously employed with the Company or any of itsAffiliates from the Grant Date through the [applicable] Vesting Date in order for the Award to become vested with respect to thePhantom Units on such date.(b) Notwithstanding any provision in the Plan to the contrary, (i) the occurrence of a Change of Control shall have no effecton the vesting of the Phantom Units and (ii) following the occurrence of a Change of Control, the Phantom Units shall continue tovest in accordance with this Agreement.(c) Within 60 days following vesting with respect to a Phantom Unit, the Participant shall be entitled to receive a CommonUnit. Common Units will be evidenced, at the sole option and in the sole discretion of the Committee, either (i) in book-entry form inthe Participant’s name in the Common Unit register of the Partnership maintained by the Partnership’s transfer agent or (ii) a unitcertificate issued in the Participant’s name. Upon delivery of a Common Unit in respect of a Phantom Unit, such Phantom Unit shallcease to be outstanding in the Participant’s notional account described below in Section 5.4. Forfeiture of Award.(a) If the Participant’s employment with the Company and all Affiliates is terminated by Participant’s employer withoutCause (and, for the avoidance of doubt, not due to Retirement), or by reason of death or Disability, all unvested Phantom Units shallimmediately vest and the Restricted Period shall terminate as of the date of the Participant’s termination.(b) If the Participant’s employment with the Company and all Affiliates is terminated due to Retirement, the unvestedPhantom Units shall not be forfeited and shall instead continue to vest and be payable in accordance with this Agreement as if theParticipant had remained continuously employed by the Company or an Affiliate.(c) If the Participant’s employment with the Company and all Affiliates terminates for any reason not described in Section4(a) or 4(b), all unvested Phantom Units shall be immediately forfeited as of the date of the Participant’s termination.Immediate vesting of units under Section 4.(a), other than by reason of death, are conditioned on the execution by the Participant of arelease of all employment-related claims within the applicable period following the Participant’s date of termination provided in such releasethat is not revoked by the Participant during any applicable revocation period provided in such release; provided, however , that such releaseshall be contingent upon the Company’s satisfaction of all terms and conditions of this Section.5. Distribution Equivalent Rights. During the Restricted Period, the Award of Phantom Units hereunder shall beevidenced by entry in a bookkeeping account and shall include a tandem Distribution Equivalent Right with respect to the Phantom Units.Distribution Equivalent Rights shall only be paid with respect to ordinary quarterly cash distributions and shall not be paid with respect to anyspecial, make-up or extraordinary distributions, in each case as determined by the Committee in its sole discretion.2 Notwithstanding the foregoing, no Distribution Equivalent Rights shall be paid in excess of the Minimum Quarterly Distributions (as definedin the Partnership Agreement) during the one year period following the Grant Date. Pursuant to the Distribution Equivalent Right, within 45days following the end of each fiscal quarter for which a cash distribution is made with respect to Common Units, the Participant shall beentitled to receive a cash payment with respect to each Phantom Unit then outstanding equal to the cash distribution made by the Partnershipwith respect to each Common Unit.6. Rights as Unitholder; Delivery of Common Units. Until delivery of Common Units as described in Section 3(c), theParticipant shall have no rights as a unitholder as a result of the grant of Phantom Units hereunder. The Company shall not be obligated todeliver any Common Units if counsel to the Company determines that such sale or delivery would violate any applicable law or any rule orregulations of any governmental authority or any rule or regulation of, or agreement of the Company with, any securities exchange orassociation upon which the Common Units are listed or quoted. The Company shall in no event be obligated to take any affirmative action inorder to cause the delivery of Common Units to comply with any such law, rule, regulations or agreement.7. Assignment of Award. The Participant’s rights under this Agreement and the Plan are personal; no assignment ortransfer of the Participant’s rights under and interest in this Award may be made by the Participant other than by will, by beneficiarydesignation, by the laws of descent and distribution or by a qualified domestic relations order.8. Withholding. No certificates representing Common Units hereunder shall be delivered to or in respect of a Participantunless the amount of all federal, state and other governmental withholding tax requirements imposed upon the Company with respect to theissuance of such Common Units has been remitted to the Company or unless provisions to pay such withholding requirements have beenmade to the satisfaction of the Committee. The Committee may make such provisions as it may deem appropriate for the withholding of anytaxes which it determines is required in connection with this Award. The Participant may pay all or any portion of the taxes required to bewithheld by the Company or paid by the Participant in connection with the vesting of all or any portion of this Award by delivering cash, or,with the Committee’s approval, by electing to have the Company withhold Common Units, or by delivering previously owned CommonUnits, having a Fair Market Value equal to the amount required to be withheld or paid. The Participant may only request the withholding ofCommon Units having a Fair Market Value equal to the statutory minimum withholding amount. The Participant must make the foregoingelection on or before the date that the amount of tax to be withheld is determined.9. No Employment Guaranteed. No provision of this Agreement shall confer any right upon the Participant to continuedemployment with the Company or any Affiliate.10. Governing Law. This Agreement shall be governed by, construed, and enforced in accordance with the laws of theState of Delaware.3 11. Amendment. This Agreement cannot be modified, altered or amended, except by an agreement, in writing, signed byboth the Company and the Participant.12. Section 409A.(a) The Phantom Units granted pursuant to this Agreement are intended to comply with or be exempt from Code Section409A, and ambiguous provisions hereof, if any, shall be construed and interpreted in a manner consistent with such intent. Nopayment, benefit or consideration shall be substituted for the Phantom Units if such action would result in the imposition of taxesunder Code Section 409A. Notwithstanding anything in this Agreement to the contrary, if any Plan provision or this Agreementresults in the imposition of an additional tax under Code Section 409A, that Plan provision or provision of this Agreement shall bereformed, to the extent permissible under Code Section 409A, to avoid imposition of the additional tax, and no such action shall bedeemed to adversely affect the Participant’s rights to the Phantom Units.(b) Notwithstanding any provision of the Agreement to the contrary, if the Participant is identified by the Company as a“specified employee” within the meaning of Code Section 409A(a)(2)(B)(i) on the date on which the Participant has a “separationfrom service” (other than due to death) within the meaning of Treasury Regulation § 1.409A-1(h), the Phantom Units payable orsettled on account of a separation from service that are deferred compensation subject to Code Section 409A shall be paid or settledon the earliest of (i) the first business day following the expiration of six months from the Participant’s separation from service, (ii)the date of the Participant’s death, or (iii) such earlier date as complies with the requirements of Code Section 409A.(c) For all purposes of this Agreement, the Participant shall be considered to have terminated employment with theCompany and its Affiliates when the Participant incurs a “separation from service” with the Company within the meaning of TreasuryRegulation § 1.409A-1(h).4 IN WITNESS WHEREOF , the Company and the Participant have executed this Phantom Unit Agreement as of the dates set forthbelow.BLUEKNIGHT ENERGY PARTNERS G.P., L.L.C. By: Name: Title: Date: PARTICIPANT: Name: Date: Signature Page to Phantom Unit AgreementExhibit 10.11BLUEKNIGHT ENERGY PARTNERS G.P., L.L.C.LONG-TERM INCENTIVE PLANDIRECTOR RESTRICTED UNIT AGREEMENTThis Restricted Unit Agreement ("Agreement") is entered into between Blueknight Energy Partners G.P., L.L.C. ("Company") and[NAME] ("Participant"), a Director of the Company, regarding an award ("Award") of [NUMBER] Restricted Units (as defined in theBlueknight Energy Partners G.P., L.L.C. Long-Term Incentive Plan (as the same may be amended from time to time, "Plan") granted to theParticipant on [DATE] ("Grant Date"), such number of Restricted Units subject to adjustment as provided in the Plan, and further subject tothe following terms and conditions:1. Relationship to Plan. This Award is subject to all of the terms, conditions and provisions of the Plan and administrativeinterpretations thereunder, if any, which have been adopted by the Committee thereunder. Except as defined herein, capitalized terms shallhave the same meanings ascribed to them under the Plan.2. Vesting Schedule.(a) This Award shall vest and the Restricted Period with respect to the Restricted Units subject thereto shall end ininstallments in accordance with the following schedule:The number of Restricted Units that vest as of each date described above will be rounded down to the nearest wholeRestricted Unit, with any remaining Restricted Units to vest with the final installment. Except as otherwise provided below, theParticipant must be continuously serving as a Director from the Grant Date through the applicable vesting date in order for the Awardto become vested with respect to additional Restricted Units on such date.(b) All Restricted Units subject to this Award shall vest immediately prior to the occurrence of a Change of Control,irrespective of the limitations set forth in subparagraph (a) above, provided that the Participant has been continuously serving as aDirector from the Grant Date through the date of the Change of Control.As used herein, the term “Change of Control” means, and shall be deemed to have occurred upon the occurrence of one or more of thefollowing events: (i) any “person” or “group” within the meaning of those terms as used in Sections 13(d) and 14(d)(2) of the Exchange Act,other than Ergon, Inc. or its Affiliates, shall become the beneficial owner, by way of merger, consolidation, recapitalization, reorganization orotherwise, of 50% or more of the combined voting power of the equity interests in the Company or the Partnership; (ii) the limited partners ofthe Partnership approve, in one or a series of transactions, a plan of complete liquidation of the Partnership; (iii) the sale or other dispositionby either the Company or the Partnership of all or substantially all of its assets in one or more transactions to any Person other than theCompany or an Affiliate of the Company; or (iv) a transaction resulting in a Person other than the Company or an Affiliate of the Companybeing the general partner of the Partnership.3. Forfeiture of Award. If the Participant's service with the Company or any of its Affiliates terminates for any reason allunvested Restricted Units granted hereunder shall be immediately forfeited as of the date of the Participant's termination; provided, however,all of the Restricted Units subject to this Award shall become fully vested on the date on which the Participant experiences a QualifyingEvent. A "Qualifying Event" means the Participant's status as a Director of the Company and/or an Affiliate of the Company (collectively, the"Affiliated Group") is terminated due to (A) death or (B) the Participant's removal as, or not being re-elected or re-appointed as, a Director ofone or more entity member(s) of the Affiliated Group by the member(s), shareholder(s) or Board of Directors, as appropriate, of such entityor entities, as applicable, which removal or failure to re-elect or reappoint shall not have been as a result of, caused by, or related to,Participant's resignation, or Participant's unwillingness to serve, for whatever reason, as a Director of such entity or entities.4. Delivery of Units; Rights as Unitholder. The Restricted Units will be evidenced, at the sole option and in the sole discretion ofthe Committee, either (i) in book-entry form in the Participant's name in the Unit register of the Partnership maintained by the Partnership'stransfer agent or (ii) a Unit certificate issued in the Participant's name. Participant shall have voting rights and shall be entitled to receive alldistributions made by the Partnership as if such Restricted Units were Units free and clear of any restrictions. If the Restricted Units areevidenced by a certificate, the certificate shall bear the following legend:THE UNITS EVIDENCED BY THIS CERTIFICATE HAVE BEEN ISSUED PURSUANT TO AN AGREEMENT MADEAS OF [DATE], A COPY OF WHICH IS ATTACHED HERETO AND INCORPORATED HEREIN, BETWEEN THEBLUEKNIGHT ENERGY PARTNERS, G.P., L.L.C. ("GENERAL PARTNER") AND THE REGISTERED HOLDER OFTHE UNITS, AND ARE SUBJECT TO FORFEITURE TO THE GENERAL PARTNER UNDER CERTAINCIRCUMSTANCES DESCRIBED IN SUCH AGREEMENT. THE SALE, ASSIGNMENT, PLEDGE OR OTHERTRANSFER OF THE UNITS EVIDENCED BY THIS CERTIFICATE IS PROHIBITED UNDER THE TERMS ANDCONDITIONS OF SUCH AGREEMENT, AND SUCH UNITS MAY NOT BE SOLD, ASSIGNED, PLEDGED OROTHERWISE TRANSFERRED EXCEPT AS PROVIDED IN SUCH AGREEMENT.The Committee may cause the certificate to be delivered upon issuance to the secretary of the Company as a depository for safekeeping untilthe forfeiture occurs or the Restricted Period ends pursuant to the terms of this Agreement. Upon request of the Committee, the Participantshall deliver to the Company a unit power, endorsed in blank, relating to the Restricted Units then subject to the Restricted Period. TheCompany may place a "stop transfer" order against Units issued pursuant to this Award until all restrictions andconditions set forth in the Plan or this Agreement and in the legends referred to in this Section 4 have been complied with. Upon terminationof the Restricted Period, the Company shall release the restrictions on any vested Units and a certificate representing such vested Units shallbe delivered to the Participant upon request.5. Purchase for Investment. The Units covered by this Agreement have not been registered under the Securities Act of 1933, asamended ("Act"). The Participant represents and warrants that, as of the date hereof, he (1) is an "accredited investor" within the meaning ofRule 501 of Regulation D promulgated by the SEC pursuant to the Act and (2) is acquiring such Units for his own account for investment andnot with a view to, or for sale in connection with, the distribution of such Units or any part thereof. The Participant may be required toexecute such documents as the Company determines are necessary and appropriate to effectuate the issuance and transfer of the Units to theParticipant.The certificates evidencing Units issued pursuant to this Agreement will bear the following legend or such other legend asdetermined by the Company:THE SECURITIES REPRESENTED BY THIS CERTIFICATE HAVE BEEN ACQUIRED FOR INVESTMENT ANDTHE OFFER AND SALE OF SUCH SECURITIES HAVE NOT BEEN REGISTERED UNDER THE SECURITIES ACTOF 1933 OR ANY STATE SECURITIES OR BLUE SKY LAWS. THESE SECURITIES MAY NOT BE SOLD ORTRANSFERRED IN THE ABSENCE OF SUCH REGISTRATION OR AN EXEMPTION THEREFROM UNDER SAIDACT OR APPLICABLE STATE SECURITIES OR BLUE SKY LAWS. ADDITIONALLY, THE TRANSFER OF THESESECURITIES IS SUBJECT TO THE CONDITIONS SPECIFIED IN THE BLUEKNIGHT ENERGY PARTNERS G.P.,L.L.C. LONG TERM INCENTIVE PLAN, THE ASSOCIATED AWARD AGREEMENT, THE PARTNERSHIPAGREEMENT AND ANY APPLICABLE UNITHOLDER AGREEMENT, AND NO TRANSFER OF THESESECURITIES SHALL BE VALID OR EFFECTIVE UNTIL SUCH CONDITIONS HAVE BEEN FULFILLED. COPIESOF SUCH PLAN, AWARD AGREEMENT, PARTNERSHIP AGREEMENT AND APPLICABLE UNITHOLDERAGREEMENT MAY BE OBTAINED AT NO COST BY WRITTEN REQUEST MADE BY THE HOLDER OF RECORDOF THIS CERTIFICATE TO THE SECRETARY OF THE ISSUER HEREOF.The Company may also impose stop-transfer instructions with respect to any matter contemplated by the Plan or Agreement.6. Receipt of Information. The Participant acknowledges that he has (a) had access to Blueknight Energy Partners, L.P.'s("Partnership's") periodic filings with the SEC, including the Partnership'sAnnual Report on Form 10-K, Quarterly Reports on Form 10-Q, and Current Reports filed on Form 8-K and (b) been provided areasonable opportunity to ask questions of and receive answers from representatives of the Partnership and the Company regarding suchmatters sufficient to enable the Participant to evaluate the risks and merits of entering into this Agreement.7. Code Section 83(b) Election. The Participant shall be permitted to make an election under Section 83(b) of the Code, toinclude an amount in income in respect of the Award of Restricted Units in accordance with the requirements of Section 83(b) of the Code.8. Assignment of Award. The Participant's rights under this Agreement and the Plan are personal; no assignment or transfer ofthe Participant's rights under and interest in this Award may be made by the Participant other than by will, by beneficiary designation, by thelaws of descent and distribution.9. No Guarantee of Continued Service. No provision of this Agreement shall confer any right upon the Participant to continueserving as a Director.10. Governing Law. This Agreement shall be governed by, construed, and enforced in accordance with the laws of the State ofDelaware without regard to its conflict of laws principles.11. Amendment. This Agreement may be modified pursuant to provisions of Section 10 of the Plan.12. Entire Agreement. The Plan and this Agreement represent the entire agreement between the Participant and the Company withrespect to the subject matter hereof, and supersede and are in full substitution for any and all prior agreements or understandings, whether oralor written, relating to the subject matter hereof.[SIGNATURES ON NEXT PAGE]BLUEKNIGHT ENERGY PARTNERS G.P., L.L.C.BLUEKNIGHT ENERGY PARTNERS G.P., L.L.C. By: Name: Title: Date: The Participant hereby accepts the foregoing Agreement, subject to the terms and provisions of the Plan and administrativeinterpretation thereof referred to above. PARTICIPANT: [NAME] Date: Exhibit 10.26PARTIAL LEASE TERMINATION NO. 5This Partial Lease Termination Agreement No. 5 (“Agreement”) is entered into as of March 7, 2018 (the “Effective Date”) by and amongBKEP Asphalt, L.L.C., a Texas limited liability company (“BKEP Asphalt”), BKEP Materials, L.L.C., a Texas limited liability company(“BKEP Materials” and, together with BKEP Asphalt, “Lessor”), and Ergon Asphalt & Emulsions, Inc., a Mississippi corporation (“Lessee”).Recitals: Lessor and Lessee entered into that certain Master Facilities Lease Agreement as of November 11, 2010, as amended by FirstAmendment to Master Facilities Lease Agreement as of November 30, 2011, Second Amendment to Master Facilities Lease Agreement as ofJuly 2, 2012, Third Amendment to Master Facilities Lease Agreement dated October 5, 2016, and Fourth Amendment to Master FacilitiesLease dated November 1, 2016 ( collectively, the "Lease") for the lease and use of certain of Lessor's asphalt facilities, including the asphaltfacilities located on property located in Muskogee, Oklahoma (the "Muskogee Facilities"), which consist of the buildings, improvements,asphalt storage and processing assets located on the land described on Exhibit A-1 to the Lease under the headings "Muskogee, Oklahoma."Lessor and Lessee mutually desire to terminate the Lease as to the Muskogee Facilities prior to its scheduled expiration as set forth herein.NOW, THEREFORE, in consideration of the premises and other good and valuable consideration, the receipt and sufficiency of which arehereby acknowledged, Lessor and Lessee agree as follows:1.Capitalized Terms. Capitalized terms used and not otherwise defined herein shall have the meaning set forth in the Lease.2.Partial Termination of Lease. Lessor and Lessee hereby agree that subject to the terms and conditions of this Agreement and as ofthe Effective Date, the Lease shall be terminated with respect to the Muskogee Facilities. From and after the Effective Date,“Facilities” as used in the Lease shall not include the Muskogee Facilities and any references to Lessor’s property located inMuskogee, Oklahoma shall be deleted from the Lease.3.No Further Rights. By execution of this Agreement, Lessee acknowledges and agrees that, from and after the Effective Date, Lesseeshall not have any further rights or interests in the Muskogee Facilities.4.Mutual Release. Lessor and Lessee each release the other from all claims, demands, debts, and causes of action of whatever kind ornature, which have or could in the future arise due to the performance of their respective obligations under the Lease with respect tothe Muskogee Facilities accruing after the Effective Date.5.Broker. No outside broker has negotiated this Agreement nor is entitled to any commission in connection therewith, and Lessee andLessor agree to indemnify and hold the other party harmless against any and all other claims for commissions by any broker used bysuch party in connection with this Agreement.6.Full Force and Effect. The Lease, as modified hereby, remains in full force and effect without any further amendments, alterationsor modifications thereto except as expressly set forth herein, and Lessor and Lesseeexpressly ratify and confirm the Lease, as amended by this Agreement.7.Counterparts. This Agreement may be signed in separate and multiple counterparts, each of which shall be considered an original,but all of which taken together shall constitute one and same instrument.Lessor and Lessee are signing this Agreement as of the Effective Date. LESSOR: LESSEE: BKEP ASPHALT, L.L.C. ERGON ASPHALT & EMULSIONS, INC. By: /s/ Jeffery Speer By: /s/ J. Baxter Burns, II Jeffery Speer J. Baxter Burns, II Chief Operating Officer President BKEP MATERIALS, L.L.C. By: /s/ Jeffery Speer Jeffery Speer Chief Operating Officer Exhibit 10.27*** Where this marking appears throughout this Exhibit 10.54, information has been omitted pursuant to a request for confidential treatmentand such information has been filed with the Securities and Exchange Commission separately.FIFTH AMENDMENTTO MASTER FACILITIES LEASE AGREEMENTTHIS FIFTH AMENDMENT TO MASTER FACILITIES LEASE AGREEMENT (this “ Fifth Amendment ”) is entered into on March 7,2018 (the “ Effective Date ”) by and among BKEP Materials, L.L.C., a Texas limited liability company (“ BKEP Materials ”), BKEPAsphalt, L.L.C., L.L.C., a Texas limited liability company (“ BKEP Asphalt ”, and together with BKEP Materials, “ Lessor ”), and ErgonAsphalt & Emulsions, Inc., a Mississippi corporation (“ Lessee ”). Lessor and Lessee are individually referred to herein as a “ Party ” andcollectively as the “ Parties ”.A.Lessor and Lessee entered into that certain Master Facilities Lease Agreement dated November 11, 2010 (the “ Master Lease ”),with respect to Lessee’s use and lease of certain of Lessor’s asphalt facilities, including the asphalt facilities located on certainproperties in Muskogee, Oklahoma (the “ Removed Facilities ”);B.Lessor and Lessee amended the Master Lease pursuant to that certain First Amendment to Master Facilities Lease Agreementdated November 30, 2011 (the “ First Amendment ”);C.The Parties entered into that certain Partial Lease Termination dated December 31, 2011, related to Lessee’s purchase of theEnnis, Texas Facility and the associated partial termination of the Master Lease solely with respect to the Ennis, Texas Facility(the “ Partial Lease Termination No. 1 ”);D.Lessor and Lessee amended the Master Lease pursuant to that certain Second Amendment to Master Facilities Lease Agreementdated July 2, 2012 (the “ Second Amendment ”);E.The Parties entered into that certain Partial Lease Termination Agreement dated June 25, 2015, related to the Parties’ mutualdesire to terminate the Master Lease solely with respect to the Reading, Pennsylvania Facility (the “ Partial Lease TerminationNo. 2 ”);F.Lessor and Lessee amended the Master Lease pursuant to that certain Third Amendment to Master Facilities Lease Agreementdated October 5, 2016 (the “ Third Amendment ”) and that certain Partial Lease Termination dated October 5, 2016 (“ PartialLease Termination No. 3 ”);G.Lessor and Lessee amended the Master Lease pursuant to that certain Fourth Amendment to Master Facilities Lease Agreementdated November 1, 2016 (the “ Fourth Amendment ”) and that certain Partial Lease Termination dated November 1, 2016 (“Partial Lease Termination No. 4 ”);H.Concurrently with the execution of this Fifth Amendment, the parties are entering into that certain Partial Lease Termination No.5 in order to terminate the Master Lease with respect to the Removed Facilities (the “ Partial Lease Termination No. 5 ”), andtogether with Partial Lease Termination No. 1, Partial Lease Termination No. 2, Partial Lease Termination No. 3, and PartialLease Termination No. 4, the “ Lease Terminations ); andI.The Parties now desire to amend the Master Lease in accordance with the terms hereof. NOW, THEREFORE , in consideration of the premises and respective promises, conditions, terms, and agreements containedherein, and other good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, the Parties do hereby agreeas follows:1.Effective as of the Effective Date, Exhibit B of the Master Lease is hereby amended and replaced in its entirety with Exhibit Battached hereto.2.Except as otherwise stated in this Fifth Amendment, all terms and conditions of the Master Lease, as amended or otherwise modifiedby this Fifth Amendment and the First Amendment, the Second Amendment, the Third Amendment, the Fourth Amendment, andPartial Lease Terminations, shall remain in full force and effect without change, and are hereby ratified by each of the Parties.Capitalized terms used but not defined in this Fifth Amendment shall have the meanings ascribed to them in the Master Lease. TheParties agree to cooperate with one another and to use their commercially reasonable efforts to effect, or cause to be effected, as thecase may be, the transactions contemplated by this Fifth Amendment. Each of the Parties shall, at any time and from time to timeafter the date hereof, upon the request of any other Party, execute, acknowledge, and deliver all such further instruments orassurances as may be necessary, in the reasonable judgement of the requesting Party to carry out the provisions and intent of thisFifth Amendment.3.This Fifth Amendment may be executed by the Parties in separate counterparts and initially delivered by electronic transmission orotherwise, with all such counterparts together constituting one and the same instrument.4.This Fifth Amendment shall be governed by, construed and enforced under the laws of the State of Oklahoma without giving effect toits conflicts of laws principles.[ Signatures on next page. ] This Fifth Amendment has been executed by the authorized representatives of each Party as indicated below to be effective as of theEffective Date. LESSOR: BKEP MATERIALS, L.L.C. By: /s/ Jeffery Speer Jeffery Speer Chief Operating Officer BKEP ASPHALT, L.L.C. By: /s/ Jeffery Speer Jeffery Speer Chief Operating Officer LESSEE: ERGON ASPHALT & EMULSIONS, INC. By: /s/ J. Baxter Burns, II J. Baxter Burns, II President EXHIBIT BFEESBase Rental Fee :With respect to each Facility under this Agreement, Lessee shall pay to Lessor a monthly base rental fee (the “ Base Rental Fee ”) equal tothe base rental fee specified in the applicable 2009 Agreement for such Facility, as escalated as of January 1 , 2016. The Base Rental Fee forall Facilities shall be payable in advance on or before the first day of each month, commencing on November 1, 2016 and shall be proratedfor any partial month during the Term.In addition to the Base Rental Fee, Lessee shall pay to Lessor an amount equal to Property Taxes and Insurance Premiums (as hereafterdefined) attributable to the Leased Premises. Lessee shall pay Property Taxes on a monthly basis with each monthly payment equal to 1/12 ofthe prior year’s Property Taxes for each Facility. After Property Taxes for the current year are paid, Lessee or Lessor, as applicable, will paythe other Party an amount equal to the difference of the actual Property Taxes paid for such year and the aggregate monthly payments thathave been made by Lessee for such year. Lessor shall provide reasonable backup documentation of Property Taxes and Insurance Premiums.For purposes of this Exhibit B , “ Insurance Premiums ” shall mean premiums payable by Lessor for the property insurance which Lessor isrequired to carry pursuant to Section 11.6 hereof. Insurance Premiums will be invoiced on an annual basis. Lessee shall pay all such invoicedamounts for Property Taxes and Insurance Premiums within ten (10) days of the date of the applicable invoice.Excess Throughput Charge :With respect to the Facilities under this Agreement and the facilities under the Master Sublease Agreement (the “ Cumulative Facilities ”),Lessee shall also pay to Lessor an excess throughput charge (the “ Excess Throughput Charge ”) equal to the product of the ExcessThroughput Fee and the Excess Throughput Quantity for the Cumulative Facilities. For purposes hereof, the “ Excess Throughput Fee ” shallbe equal to the excess throughput fee specified in the applicable 2009 Agreement for the Cumulative Facilities, as escalated, as of January 1,2016, and the “ Excess Throughput Quantity ” shall be equal to the positive difference between the quantity of asphalt product which ishandled, produced, sold or delivered from the Cumulative Facilities in a Contract Year and *** tons (the “ Threshold Quantity ”). The ExcessThroughput Charge shall be computed monthly (starting from the first day of each Contract Year) and Lessee shall pay Lessor an amountequal to the Excess Throughput Charge less an amount equal to the cumulative sum of all Excess Throughput Charges already paid by Lesseeto Lessor during such Contract Year. The Excess Throughput Charge shall be due on or before the thirtieth (30 th ) day following the end ofeach month for which the cumulative quantity of all asphalt products handled, produced, sold or delivered exceeds the Threshold Quantity.For the avoidance of doubt, the cumulative quantity of all asphalt products handled, produced, sold or delivered shall include the totalquantity of all asphalt products delivered from the Cumulative Facilities, including (i) volumes transferred from one Facility to another and(ii) 100% of the quantity of all emulsion products without reduction of any kind. Excess Throughput Charges shall be subject to audit byLessor.Lessee shall also pay to Lessor an additional throughput incentive charge (the “ Incentive Throughput Charge ”) equal to the product of theapplicable Incentive Throughput Factor and the aggregate annual Base Rental Fee for the Cumulative Facilities. For purposes hereof, the “Incentive Throughput Factor ” shall be: (a) 3% if the Excess Throughput Quantity is less than or equal to *** tons; (b) ***% if the ExcessThroughput Quantity is greater than *** tons but less than *** tons; or (c) *% if the ExcessThroughput Quantity is *** tons or greater. The Incentive Throughput Charge shall be computed annually and shall be paid within sixty (60)days of the end of each Contract Year.For purposes of this Agreement, “ Contract Year ” means a period of 365 consecutive days commencing on January 1, 2016 and eachsuccessive period of 365 consecutive days during the Term of this Agreement with the exception of any Contract Year in which February has29 days when the period will be 366 consecutive days.Utilities and Taxes :Lessee is solely responsible for all utilities relating to the Facilities and any associated deposits and all such utilities shall be in Lessee’sname. Lessee will directly pay when due the actual cost of the utilities used at the Facilities. Lessee shall be solely responsible for all costs ofstoring and manufacturing asphalt products at the Facilities.Lessee shall be responsible for, and shall indemnify and hold Lessor harmless from and against, all taxes, including but not limited to sales,use, personal property and income (Lessee’s) taxes generated from or otherwise related to Lessee’s use of the Facilities.Adjustments :The Base Rental Fee will be escalated January 1, 2017 and every January 1st thereafter by the percentage change, if any, in the ConsumerPrice Index - All Urban Consumers - all items less food and energy (U.S. city average base 1982-84 = 100) (“ CPI ”), as published by theBureau of Labor Statistics of the United States Department of Labor, for the last two calendar years for which data is available based on theaverage of the monthly CPI data for November to October of the most current year available compared to the same months of the prior year.The Excess Throughput Fee will be escalated January 1, 2017 and every January 1st thereafter by the percentage change, if any, in the abovenoted Consumer Price Index. For the avoidance of doubt, the Incentive Throughput Factor percentages shall not be escalated. In no eventshall any of the fees de-escalate.Exhibit 21.1List of SubsidiariesofBlueknight Energy Partners, L.P.Name of Subsidiary State of OrganizationBKEP Finance Corporation DelawareBKEP Operating, L.L.C. DelawareBKEP Management, Inc. DelawareBKEP Crude, L.L.C. DelawareBKEP Sub, L.L.C. DelawareBKEP Pipeline, L.L.C. DelawareBlueknight Motor Carrier LLC DelawareBKEP Red River System LLC DelawareBKEP Supply and Marketing LLC DelawareBKEP Services LLC TexasBKEP Materials, L.L.C. TexasBKEP Asphalt, L.L.C. TexasKnight Warrior LLC TexasBKEP Terminal Holding, L.L.C. TexasBKEP Terminalling, L.L.C. TexasExhibit 23.1CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMWe hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-213872 and 333-221175) and Form S-8 (Nos. 333-202538, 333-202537, 333-144737 and 333-177005) of Blueknight Energy Partners, L.P. of our report dated March 8, 2018 relating to the consolidated financialstatements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K./s/ PricewaterhouseCoopers LLPTulsa, OklahomaMarch 8, 2018Exhibit 31.1CERTIFICATIONPURSUANT TO AND IN CONNECTION WITH THE REPORTSTO BE FILED UNDER SECTION 13 AND 15(d) OF THESECURITIES EXCHANGE ACT OF 1934, AS AMENDEDI, Mark Hurley, certify that:1.I have reviewed this annual report on Form 10-K of Blueknight Energy Partners, L.P.;2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have:a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared;b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles;c.Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; andd.Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscalquarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect,the registrant's internal control over financial reporting; and5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant's ability to record, process, summarize and report financial information; andb.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controlover financial reporting.Date:March 8, 2018 /s/ Mark HurleyMark HurleyChief Executive OfficerBlueknight Energy Partners, G.P., L.L.C.,general partner of Blueknight Energy Partners, L.P.Exhibit 31.2CERTIFICATIONPURSUANT TO AND IN CONNECTION WITH THE REPORTSTO BE FILED UNDER SECTION 13 AND 15(d) OF THESECURITIES EXCHANGE ACT OF 1934, AS AMENDEDI, Alex G. Stallings, certify that:1.I have reviewed this annual report on Form 10-K of Blueknight Energy Partners, L.P.;2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have:a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared;b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles;c.Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; andd.Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscalquarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect,the registrant's internal control over financial reporting; and5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant's ability to record, process, summarize and report financial information; andb.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controlover financial reporting.Date:March 8, 2018 /s/ Alex G. StallingsAlex G. StallingsChief Financial Officer and Secretary ofBlueknight Energy Partners, G.P., L.L.C.,general partner of Blueknight Energy Partners, L.P.Exhibit 32.1CERTIFICATION PURSUANT TO SECTION 906 OF THESARBANES-OXLEY ACT OF 2002 (18 U.S.C. SECTION 1350)*In connection with the Annual Report of Blueknight Energy Partners, L.P., a Delaware limited partnership (the “Partnership”), on Form 10-K for the yearended December 31, 2017 as filed with the Securities and Exchange Commission (the “Report”), each of the undersigned, Mark Hurley, Chief Executive Officer ofBlueknight Energy Partners G.P., L.L.C., and Alex G. Stallings, Chief Financial Officer and Secretary of Blueknight Energy Partners G.P., L.L.C., certifies,pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), that to his knowledge:(1)the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Partnership./s/ Mark HurleyMark HurleyChief Executive Officer ofBlueknight Energy Partners G.P., L.L.C.,general partner of Blueknight Energy Partners, L.P. March 8, 2018 /s/ Alex G. StallingsAlex G. StallingsChief Financial Officer and Secretary ofBlueknight Energy Partners G.P., L.L.C.,general partner of Blueknight Energy Partners, L.P. March 8, 2018*A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnishedto the Securities and Exchange Commission or its staff upon request. The foregoing certification is being furnished to the Securities and ExchangeCommission as an exhibit to the Report.

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