Blueknight Energy Parnters, L.P. Annual Report 2018

Plain-text annual report

BLUEKNIGHT ENERGY PARTNERS, L.P. FORM 10-K (Annual Report) Filed 03/12/19 for the Period Ending 12/31/18 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 12/31 http://www.edgar-online.com © Copyright 2019, 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, 2018 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 every Interactive Data File required to be submitted pursuant to Rule 405 ofRegulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit 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. ýIndicate 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 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, 2018 , the aggregate market value of the registrant’s common units held by non-affiliates of the registrant was approximately $82.8 million ,based on $3.40 per common unit, the closing price of the common units as reported on the Nasdaq Global Market on such date. As of March 11, 2019 , there were 35,125,202 Series A Preferred Units and 40,714,857 common units outstanding. Table of ContentsTable of Contents PagePART I . 1Item 1.Business.1Item 1A.Risk Factors.15Item 1B.Unresolved Staff Comments.36Item 2.Properties.36Item 3.Legal Proceedings.37Item 4.Mine Safety Disclosures.37 PART II . 37Item 5.Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.37Item 6.Selected Financial Data.39Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations.41Item 7A.Quantitative and Qualitative Disclosures about Market Risk.62Item 8.Financial Statements and Supplementary Data.62Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.62Item 9A.Controls and Procedures.63Item 9B.Other Information63 PART III . 64Item 10.Directors, Executive Officers and Corporate Governance.64Item 11.Executive Compensation.69Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.79Item 13.Certain Relationships and Related Transactions, and Director Independence.80Item 14.Principal Accountant Fees and Services.81 PART IV . 83Item 15.Exhibits, Financial Statement Schedules.83Item 16.Form 10-K Summary.87iTable 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.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). Preferred Units: Series A Preferred Units representing limited partnership interests in our partnership.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.iiTable 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 services. On April 24, 2018, thePartnership sold the producer field services business. As a result of the sale of the producer field services business, the Partnership changed the name of the crudeoil trucking and producer field services operating segment to crude oil trucking services during the second quarter of 2018. See Note 8 to our consolidated financialstatements for additional information. 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. On October 5, 2016, Ergon purchased 100% 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 Membership Interest Purchase Agreement dated July 19, 2016, among CB-Blueknight,LLC (“CBB”), an indirect wholly-owned subsidiary of Charlesbank, Blueknight Energy Holding, Inc. (“BEHI”), an indirect wholly-owned subsidiary of Vitol, andErgon Asphalt Holdings, LLC, a wholly-owned subsidiary of Ergon (the “Ergon Change of Control”). In conjunction with the Ergon Change of Control, Ergoncontributed nine asphalt facilities plus $22.1 million in cash in return for total consideration of approximately $144.7 million, which consisted of the issuance of18,312,968 Preferred Units in a private placement. We also repurchased 6,667,695 Preferred Units from each of Vitol and Charlesbank in a private placement foran aggregate purchase price of approximately $95.3 million. Vitol and1Table of ContentsCharlesbank 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. 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 11, 2019 :2Table of ContentsOur Strengths and StrategiesStrategically placed assets . We own and operate a diversified portfolio of complementary midstream energy assets that includes approximately 8.8 millionbarrels of liquid asphalt storage located at 53 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 oil marketing hubs in the United States and the designated point of delivery specified in all New York Mercantile Exchange (“NYMEX”) crude oilfutures 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, wehave approximately 646 miles of strategically positioned gathering and transportation pipelines, primarily located in Oklahoma.Growth opportunities. Ergon has indicated that it views us as a vehicle of growth in the midstream sector. We cannot say with any certainty whether or notErgon will pursue future acquisition or expansion opportunities in the midstream energy space with us, or if we will choose to pursue any such opportunity Ergonpresents. 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 3,000 employees globally. Ergon and its subsidiaries are engaged in a wide range of operations that are categorized intoseven primary business segments: Refining & Marketing, Asphalt & Emulsions, Midstream & Logistic, Specialty Chemicals, Construction and Real Estate andCorporate & Other. This relationship may provide us with additional capital sources for future growth as well as increased opportunities to provide terminalling,gathering and transportation services. While this relationship may benefit us, it may also be a source of potential conflicts. Ergon is not restricted from competingwith us and may acquire, construct or dispose of additional assets in the future without any obligation to offer us the opportunity to purchase or construct thoseassets.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 53 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 and3Table of Contentsmicrosurfacing maintenance treatments, warm mix emulsion/aggregate mixtures, base stabilization and both central plant and in-place recycling. Asphaltemulsions and cutback asphalts are generally sold directly to government agencies but are also sold to contractors. The asphalt industry in the United States is characterized by a high degree of seasonality. Much of this seasonality is due to the impact that weather 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 and Kansas, where there are extensive crude oil production operations in place, and our assetsextend from gathering systems and trucking networks in and around producing fields to transportation pipelines carrying crude oil to logistics hubs, such as theCushing 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: 4Table 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 CorporationEnergy Transfer Partners Pony Express PipelineTransCanada Corp.White Cliffs Pipeline, LLCBlueknight Energy Partners, L.P. ConocoPhillipsDeeprock Energy Resources LLC Enbridge Inc.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 CorporationEnergy Transfer PartnersTransCanada 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 LLC EnergyTransfer PartnersTransCanada Corp. With our pipeline and terminalling infrastructure, we have the ability to receive and/or deliver, directly or indirectly, to almost all pipelines and terminalswithin the Cushing 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 8.8 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 1, 2019 , we have 53 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 1, 2019 , we have leases and storage agreements relating to all of our 53 asphalt facilities. These agreements have, on average, approximatelyfour years remaining under their terms. Six of the agreements expire by the end of 2019, and the remaining agreements expire at varying times thereafter, including23 that expire in 2023 . We may not be able to extend, renegotiate or replace these contracts when they expire and the terms of any renegotiated contracts may notbe as favorable as the contracts they replace. We operate the asphalt facilities that are contracted by storage, throughput and handling agreements, while ourcontract counterparties operate the asphalt facilities that are subject to 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 terminalling and storage facilities, as well as the processing and manufacturing equipment required for theprocessing of asphalt emulsions,5Table of Contentsasphalt cutbacks, polymer modified asphalt cement and other related finished asphalt products. After initial unloading, the liquid asphalt is moved via heat-tracedpipe into storage tanks. Those tanks are insulated and contain heating elements that allow the liquid asphalt to be stored in a heated state. The liquid asphalt canthen be directly sold by our customers to end users or used as a raw material for the processing of asphalt emulsions, asphalt cutbacks, polymer modified asphaltcement and related finished asphalt products that we process in accordance with the formulations and specifications provided by our customers. Depending on theproduct, the processing of asphalt entails combining asphalt cement and various other products such as emulsifying chemicals and polymers to achieve the desiredspecification and application requirements. At leased facilities, our customers conduct the operations at the asphalt facility, including the storage and processing of asphalt products, and we collect 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 1, 2019 :LocationNumber of FacilitiesTotal Tankage (in thousands of bbls) (1)Alabama1295Arizona166Arkansas121California166Colorado4401Georgia2192Idaho1285Illinois2232Indiana1156Kansas5662Missouri3662Mississippi1202Montana1123Nebraska1292New Jersey1459Nevada1280North Carolina1243Ohio138Oklahoma71,420Pennsylvania159Tennessee4770Texas4248Utah2300Virginia2635Washington3468Wyoming1220Total538,795_______________(1) Total tankage refers to the approximate total capacity of all tanks.6Table 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, 2018 , Ergon accounted for at least 40% but not more than 45% of our total asphalt terminallingservices revenue. Associated Asphalt and Delek US Holdings, Inc. each accounted for at least 10% but not more than 15% of asphalt terminalling servicesrevenue in 2018 . The loss of any of those 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 asphalt terminalling services revenue during 2018 . As of March 1, 2019 , we have storage, throughput and handlingagreements or operating leases with Ergon for 23 of our asphalt facilities. For more information regarding the Ergon agreements, please see “Item 13-CertainRelationships and Related-Party Transactions, 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 assets 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 11, 2019 , we have approximately 5.7 million barrels of crude oil storage under service contracts, including 3.5 million barrels of crude oilstorage contracts that expire in 2019. The remaining terms on the service contracts range from 4 months to 34 months. Storage contracts with Vitol represent 2.9million barrels of crude oil storage capacity under contract, and an additional 0.5 million barrels are under an intercompany contract. We may not be able to extend,renegotiate or replace these contracts when they expire and the terms of any renegotiated contracts may not be as favorable as the contracts they replace. 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, 2017 2018 (in thousands)Average crude oil barrels stored per month at our Cushing terminal5,413 1,275Average crude oil delivered (Bpd) to our Cushing terminal41 48Total storage capacity at our Cushing terminal (barrels at end of period)6,600 6,600Total other storage capacity (barrels at end of period)337 322 The following table outlines the location of our crude oil terminals and their storage capacities and number of tanks as of December 31, 2018 :LocationStorage Capacity(thousands of barrels)Number ofTanksCushing, Oklahoma6,60034Other (1)322111Total6,922145_______________(1) Consists of miscellaneous storage tanks located at various points along our pipeline 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. 7Table 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 15 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 Inc., SemGroupCorporation, Deeprock Energy Resources, LLC as well as truck stations. Our Cushing terminal’s pipeline connections to major markets in the Mid-Continentregion provide our customers with marketing flexibility. Our Cushing terminal can deliver crude oil via pipeline and, in the aggregate, is capable of receivingand/or delivering approximately 350,000 Bpd of crude oil. Significant Customers . For the year ended December 31, 2018 , Vitol accounted for at least 25% but not more than 30% of our total crude oil terminallingrevenue, and Citigroup Energy, Inc. and Sunoco Logistics Partners LP each accounted for at least 20% 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 2018 .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 646 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, 2017(Bpd)AverageThroughput forYear EndedDecember 31, 2018(Bpd)Pipe DiameterRangeMid-ContinentGathering and transportation pipelines64621,93124,9674” 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 646 miles of various sized pipeline, and has a capacity of approximately 50,000 Bpd. The majority of the Mid-Continentpipeline system is located in Oklahoma. Crude oil delivered into the Oklahoma portion of our Mid-Continent pipeline system is transported to our Cushingterminal or delivered to local area refiners. The Mid-Continent pipeline system also includes an approximately 35-mile gathering and transportation system in theTexas Panhandle near Dumas, Texas. Crude oil collected through the Texas Panhandle portion of our Mid-Continent system is transported by pipeline to a stationwhere it is then delivered to market via tanker truck.The 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 our Mid-Continent pipeline system due to discovery of a pipeline exposure caused by heavy rainsand 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 took action tomitigate the service suspension and worked with customers to divert volumes and, in certain circumstances, transported volumes to a third-party pipeline systemvia truck. In addition, the term of the throughput and deficiency agreement on our Eagle pipeline system expired on June 30, 2016, and in July 2016 we completeda connection of the southeastern-most portion of our Mid-Continent pipeline system to our Eagle pipeline system and concurrently reversed the Eagle pipelinesystem. This enabled us to recapture diverted volumes and deliver those barrels to Cushing, Oklahoma. We restored service of the second Oklahoma pipelinesystem in July 2018, increasing the transportation capacity of our pipeline systems by approximately 20,000 Bpd. The ability to fully utilize the capacity of thesesystems may be impacted by the market price of crude oil and producers’ decisions to increase or decrease production in the areas we serve.8Table of Contents East Texas Pipeline System . We previously owned and operated the East Texas pipeline system, which is located in Texas. In April 2017, we sold the EastTexas pipeline system. At closing of the sale, we received cash proceeds of approximately $4.8 million and recorded a gain of less than $0.1 million . Significant Customers . For the year ended December 31, 2018 , BP Products North America, Inc.; Enterprise Crude Pipeline, LLC; Continental Resources,and Vitol each accounted for at least 10% but not more than 25% of crude oil pipeline services revenue. The loss of any of these customers could have a materialadverse effect on our business, cash flows and results of operations. No other customer accounted for more than 10% of our crude oil pipeline services revenueduring 2018 .Crude Oil Trucking Services On April 24, 2018, we sold the producer field services business. As a result of the sale of the producer field services business, the Partnership changed thename of the crude oil trucking and producer field services operating segment to crude oil trucking services during the second quarter of 2018. See Note 8 to ourconsolidated financial statements for additional information. To complement our pipeline gathering, marketing and transportation business, we use our approximately 60 owned or leased tanker trucks, which have anaverage tank size of approximately 200 barrels, to move crude oil to aggregation points, pipeline injection stations and storage facilities. Our tanker trucks movedan average of 21,000 Bpd and 27,000 Bpd for the years ended December 31, 2017 and 2018 , respectively, from wellhead locations not served by pipelinegathering systems. The following table outlines the distribution of our trucking assets among our operating areas as of March 11, 2019 :LocationNumber of TrucksOklahoma40Kansas10Texas10Total60 Significant Customers. For the year ended December 31, 2018 , MV Purchasing, LLC accounted for at least 35% but not more than 40% and Devon GasServices, LP accounted for at least 10% but not more than 15% of crude oil trucking services revenue. The loss of either of these customers could have a materialadverse effect on our business, cash flows and results of operations. In addition, approximately 25% of crude oil trucking services revenue for the year endedDecember 31, 2018 , were earned by providing services to our crude oil pipeline services segment. No other customer accounted for more than 10% of our crudeoil trucking services revenue during 2018 .Competition We compete with national, regional and local liquid asphalt terminalling companies and crude oil gathering, storage and pipeline companies, including themajor integrated 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., ExxonMobil Corporation, ConocoPhillipsCo., NuStar Energy L.P., Ergon Refining, Inc., Marathon Petroleum Company LLC, Alon USA LP, Suncor Energy Inc. and Valero Energy Corporation; resellerssuch as Associated Asphalt Partners, LLC, Idaho Asphalt Supply, Inc. and Asphalt Materials, Inc.; and large road construction firms such as Old Castle Materials,Inc. and Colas SA. We compete for asphalt terminalling services with the national, regional and local industry participants as well as with liquid asphaltterminalling companies, including the major integrated oil companies and a variety of others, such as KinderMorgan Inc., International-Matex Tank Terminals andHouston Fuel 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 Inc., Enterprise Products Partners L.P., Plains All American Pipeline,L.P. and Rose Rock Midstream Partners, L.P., among others. Several of our competitors conduct portions of their operations through publicly9Table of Contentstraded 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 transportation services regulated by the Federal Energy Regulatory Commission (“FERC”). Our pipeline segments are subject toregulatory enforcement by the U.S. Department of Transportation’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 (the“OCC”). In the states in which we operate, regulation of crude gathering facilities and intrastate crude pipeline facilities generally includes various safety,environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. 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 other aspects of pipeline safety. These laws and regulations are subject to change,resulting in potentially more stringent requirements and increased costs. Applicable pipeline safety regulations establish minimum safety requirements and, forpipelines that pose a greater risk to populated areas or environmentally sensitive areas, impose a more rigorous requirement for the implementation of pipelineintegrity management programs for our pipelines. The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“Pipeline Safety Act”) was enacted inJanuary 2012. That legislation increased the maximum civil penalties for pipeline safety administrative enforcement actions; required the DOT to study and reporton the expansion of integrity management requirements, the sufficiency of existing gathering line regulations to ensure safety and the feasibility of leak detectionsystems for hazardous liquid pipelines; required pipeline operators to verify their records on maximum allowable operating pressure; and imposed new emergencyresponse and incident notification requirements. In 2016, the Pipeline Safety Act was reauthorized and amended to add additional construction inspectionrequirements, clarify integrity management rules and update federally incorporated standards. On January 23, 2017, PHMSA published a final rule that becameeffective on March 24, 2017. This rule amended the Pipeline Safety Act to include, among other provisions, a specific time frame for notifying PHMSA ofaccidents and incidents, allowance for PHMSA to recover costs associated with design reviews of new projects, renewal of expiring special permits, processes forrequesting protection of confidential commercial information, changes to the drug and alcohol testing requirements and incorporating consensus standards byreference for in-line inspection and stress corrosion cracking direct assessment. The states in which we operate pipelines incorporate into their state rules thosefederal safety standards for hazardous liquids pipelines contained in Title 49, Part 195 of the Federal Code of Regulations. As a result, the issuance of any newpipeline safety regulations, including additional requirements for integrity management, is likely to increase the operating costs of our pipelines subject to suchnew 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.10Table of ContentsEnvironmental, 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. Although we are not currentlyaware of any material effects that compliance with current and future environmental laws and regulations will have on our results of operations, financial positionor cash flows, we cannot provide any assurance that such costs will not result in such material effects in the future. 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. The 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, and the EPA has instituted rulemakings to both delay the effective date of the rule and to repeal the rule. InAugust 2018, the U.S. District Court for the District of South Carolina issued a nationwide injunction against EPA’s rule delaying implementation of the WOTUSdefinition. Pursuant to the court’s order, the 2015 Clean Water Rule is now in effect in a minority of states, the District of Columbia, and the U.S. territories.Litigation surrounding this rule is ongoing. More recently, in December 2018, the EPA and the U.S. Army Corps of Engineers released a proposal to revise the2015 Clean Water Rule so as to narrow the regulatory definition of waters of the U.S. The CWA and analogous laws provide significant penalties for unauthorizeddischarges and impose substantial potential liabilities for cleaning up releases into water. In addition, the CWA and analogous state laws require individual permitsor coverage 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 of11Table of Contentsdikes and other containment structures to prevent contamination of navigable or other waters in the event of an oil overflow, rupture or leak. We believe that weare 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 the rule. OnSeptember 11, 2018, the EPA also proposed targeted improvements to the rule, including amendments to the rule’s fugitive emissions monitoring requirements,and expects to “significantly reduce” the regulatory burden of the rule in doing so. The costs of compliance with any modified or newly issued rules cannot bepredicted. The Obama administration also announced in January 2015 that other federal agencies, including the Bureau of Land Management (“BLM”), PHMSAand the Department of Energy, will impose new or more stringent regulations on the oil and gas sector that are said to have the effect of reducing methaneemissions. For example, the BLM adopted rules that took effect on January 17, 2017, to reduce venting, flaring and leaks during oil and natural gas productionactivities on onshore federal and Indian leases. In December 2017, implementation of this rule was delayed until January 2019, and in September 2018 the BLMproposed a revised rule which scaled back the waste-prevention requirements of the 2016 rule. Environmental groups sued in federal district court a day later tochallenge the legality of aspects of the revised rule, and the outcome of this litigation is currently uncertain. Compliance with these rules could result in additionalcompliance costs for us and for others in our industry. In response to these and other regulatory developments, we may be required to incur certain capitalexpenditures in the next several years for air pollution control equipment and operational changes in connection with obtaining or maintaining permits andapprovals and complying with applicable regulations addressing air emission related issues. However, the status of recent and future rules and rulemakinginitiatives 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 cash flows. 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 emissions from specified sources in the United States., including, among others, certain onshore oil and natural gas processingand fractionating facilities. Monitoring obligations began in 2010 and the emissions reporting requirements took effect in 2011. These EPA rulemakings couldaffect our operations and ability to obtain air permits for new or modified facilities. In addition, efforts have been and continue to be made in the internationalcommunity toward the adoption of international treaties or protocols. In 2015, the United States participated in the United Nations Conference on Climate Change,which led to the adoption of the Paris Agreement that will require countries to review and “represent a progression” in their intended nationally determinedcontributions, which set GHG emission reduction goals, every five years beginning in 2020. However, in June 2017, President Trump announced that the UnitedStates plans to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new frameworkagreement. The Paris Agreement provides for a four-year exit process beginning in November 2016, which would result in an effective exit date of November2020. The United States’s adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiatedagreement are unclear at this time. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict thefinancial impact of related developments on 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 our12Table of ContentsGHG emissions and/or administer and manage a GHG emissions program. At this time, it is not possible to accurately estimate how laws or regulations addressingGHG emissions would impact our business. Although we do not expect we would be impacted to a greater degree than other similarly situated midstreamtransporters of petroleum products, the greenhouse gas control programs could have an adverse effect on our cost of doing business and could reduce demand forthe 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 owned or leased by us, or on or under other locations where these wastes were taken for disposal. In addition, many of these properties have beenoperated in the past by third parties whose treatment and disposal or release of hazardous substances or associated generated wastes were not under our control.These properties and the materials disposed on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required toremove or remediate previously released hazardous materials or associated generated wastes (including wastes disposed of or released by other site occupants or byprior owners or operators), or to clean up contaminated property (including contaminated groundwater). Contamination resulting from the release of hazardous substances or associated generated wastes is not unusual 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 pursued13Table of Contentsin the future. For example, several states, including states in which we operate, have imposed disclosure requirements on hydraulic fracturing, and several localgovernments have prohibited or severely restricted hydraulic fracturing within their jurisdictions. Restrictions on hydraulic fracturing could adversely affect ouroperations by reducing the volumes of crude oil that we transport.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, on November 20, 2007, issuedan Appendix A to CFATS that established chemicals of interest and their respective threshold quantities that trigger compliance with the interim rules. InDecember 2014, the Protecting and Securing Chemical Facilities from Terrorist Attacks Act of 2014 (“CFATS Act”) was enacted. The CFATS Act reauthorizedthe CFATS program for four years. The CFATS program utilizes a Chemical Security Assessment Tool (“CSAT”) to identify chemical facilities potentiallydeemed “high risk.” The first step of CSAT is user registration, followed by the completion of a top-screen evaluation. The top-screen evaluation analyzes whethera facility stores regulated chemicals above specified thresholds. If it does, the facility must complete a Security Vulnerability Assessment, which identifies afacility’s security vulnerabilities, and develop and implement a Site Security Plan, which must include measures that satisfy the identified risk-based performancestandards. DHS must review and approve or deny all security vulnerability assessments and site security plans. CFATS also requires regulated facilities to keepdetailed security records and allow DHS the right to enter, inspect, and audit the property, equipment, operations and records of such facilities. We believe we arein 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 retained14Table of Contentsand managed 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, 2018 , we had approximately 285 employees. None of these employees are represented by labor unions or covered by any collectivebargaining agreement. 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 21 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.Risks 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 current quarterly distribution of $0.08 per unit per quarter, or $0.32 per unit per year, we will require available cash of approximately $9.7million per quarter, or $38.8 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 current quarterly distribution rate. The amount of cash we can distribute onour units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things,the risks described 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.15Table of ContentsOur 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 3.5 million barrels of storage at this locationare month-to-month or expire in 2019. 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 our revenues. For example, Ergon Asphalt and Emulsion, Inc., a wholly-owned subsidiary of Ergon, Inc.,represented approximately $48.1 million , or 42% , of our total asphalt terminalling services revenue in 2018 . Vitol represented approximately $3.7 million , or30% , of our total crude oil terminalling revenue, $32.9 million , or 13% , of our crude oil pipeline services revenue and $1.5 million , or 8% , of our total crude oiltrucking services revenue in 2018 . Vitol and Ergon are private companies and we have limited information regarding their financial condition. Vitol and Ergoncomprised 27% and 3% , respectively, of total accounts receivable at December 31, 2018 . In addition to Vitol and Ergon , we have other key customers. Associated Asphalt and Delek US Holdings, Inc. accounted for at least 10% but not more than15% of total asphalt terminalling services revenue in 2018 . Citigroup Energy, Inc. and Sunoco Logistics Partners LP each accounted for at least 20% but no morethan 25% of total crude oil terminalling revenue in 2018 . MV Purchasing, LLC accounted for at least 35% but not more than 40% and Devon Gas Services, LPaccounted for at least 10% but not more than 15% of crude oil trucking services revenue in 2018 . BP Products North America, Inc.; Enterprise Crude Pipeline,LLC and Continental Resources each accounted for at least 10% but no more than 25% of total crude oil pipeline services revenue in 2018 . BP Products NorthAmerica, Inc.; Enterprise Crude Pipeline, LLC; Continental Resources and Atlantic Trading & Marketing, Inc. each comprised at least 10% but not more than 20%of total accounts receivable at December 31, 2018 . These balances all related to our crude oil marketing business, and were paid in full within 30 days of year end.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 us or to enforce performance of obligations under contractual arrangements. Additionally, many of our customers financetheir activities through cash flows from operations, the incurrence of debt or the issuance of equity. The reduction of cash flows resulting from declines incommodity prices, a reduction in borrowing bases under credit facilities, the lack of availability of debt or equity financing or any combination of such factors mayresult in a significant reduction of our customers’ liquidity and limit their ability to make payments or perform on their obligations to us. Furthermore, some of ourcustomers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations tous. The loss of all or even a portion of the contracted volumes of these key customers, as a result of competition, creditworthiness or otherwise, could 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.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.16Table of ContentsThe 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, 2018 , we had approximately $266.8 million in outstanding indebtedness, including approximately $1.2 million in outstanding letters ofcredit, under our $400.0 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.Restrictions 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.17Table of ContentsThe 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 11, 2019 , we have aggregate unused credit availability under our credit agreement of approximately $145.2 million , although our ability toborrow such funds may be limited by the financial covenants in our credit agreement, and cash on hand of approximately $2.3 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 the funds available to us for other purposes under our credit agreement, including amounts available for use inconnection with acquisitions and other business opportunities. If we are unable to pursue our growth strategy due to our limited ability to borrow funds, ouroperations may be materially and adversely affected. We are exposed to commodity price volatility. Our crude oil marketing activities conducted in our crude oil pipeline services segment have direct exposure to changes in crude oil prices. Typically, thevolume of crude oil we purchase in a given month will be sold in the same month. However, we may have market price exposure for inventory that is carried overmonth-to-month as well as pipeline linefill we maintain. We may also be exposed to price risk with respect to the differing qualities of crude oil we transport andour ability to effectively blend them to market specifications. In addition, the volumes of liquid asphalt and crude oil we terminal, gather or transport are affectedby commodity prices because many of our customers have direct commodity price exposure. Many of our customers have been, and continue to be, adverselyaffected by significant changes in commodity prices. If our customers continue to be negatively impacted by commodity price volatility, a sustained period ofdepressed commodity prices or other adverse conditions of the energy industry, they may, among other things, decrease the amount of services that we provide tothem. The prices of liquid asphalt and crude oil are inherently volatile, and we expect this volatility to continue. Any significant reduction in the amount ofservices we provide to our customers would have a material adverse effect on our results of operations and cash 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. 18Table of ContentsSome 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 1, 2019 , we had leases or storage agreements with third-party customers relating to each of our 53 asphalt facilities. Lease or storage agreementsrelated to six of these facilities have terms that expire by the end of 2019. 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. We are not fully insured against all risks incident to our business and could incur substantial liabilities as a result. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of changing market conditions, 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) higher19Table of Contentstaxes 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.We 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 or20Table of Contentsother causes could result in reduced throughput on our pipeline systems which 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 views us as a vehicle of growth in the midstream sector. We cannot say with any certainty whether or not Ergon will pursuefuture acquisition or expansion opportunities in the midstream energy space with us, or if we will choose to pursue any such opportunity Ergon presents. 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 whenthey are available; (ii) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them; (iii) unable to obtain financing forthese acquisitions on economically acceptable terms; or (iv) outbid by competitors, then our future growth and ability to increase distributions may be limited.Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated fromoperations 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. If 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. 21Table of ContentsExpanding 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 design, construction, operation, and maintenance regulations, including pipeline integritymanagement program requirements and any necessary pipeline repair or preventative or remedial measures, which could have a material adverse effect on ourresults of operations.Our pipeline operations are subject to pipeline safety laws and regulations administered by PHMSA of the United States Department of Transportation (DOT),and enforced by OCC. PHMSA has promulgated comprehensive pipeline safety regulations for hazardous liquids under 49 Code of Federal Regulations Part 195.These laws and regulations require us to comply with a significant set of requirements for the design, construction, maintenance, and operation of our pipelines.These laws and regulations, among other things, include requirements to monitor and maintain our pipelines, and determine the pressures at which our pipelinescan operate.Also included in the comprehensive regulatory scheme are regulations requiring pipeline operators to develop integrity management programs for pipelinesthat could affect “high consequence areas” including populated areas, areas that are unusually sensitive to environmental damage and commercially navigablewaterways. The regulations require operators 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. Effective 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,22Table of Contentsverifying maximum pressures through physical testing (including hydrostatic testing) or modifying or replacing facilities to meet the demands of verifiablepressures, could significantly increase an operator’s costs of compliance. 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 design reviews of new projects, renewal of expiring special permits, processes for requesting protection ofconfidential commercial information, changes to the drug and alcohol testing requirements and incorporating consensus standards by reference for in-lineinspection 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 the properties for which we may incur liability. Additionally, some sites we own or operate are located near current or former terminal and pipelineoperations, and there is a risk that contamination has migrated from those sites to ours. Increasingly strict environmental laws, regulations and enforcementpolicies, as well as claims for damages and other similar developments, could result in significant costs and liabilities, and our ability to make distributions to ourunitholders 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.Adoption of legislation and regulatory measures targeting GHG emissions or legal or other action taken by public or private entities related to climate changecould affect our operations, expose us to significant costs and liabilities, and reduce demand 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 these rules. 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 theserules do 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 alsonote, as previously23Table of Contentsmentioned, that the EPA finalized rules that took effect in August 2016 to set standards for methane and volatile organic compound emissions from new andmodified sources in the oil and gas sector, including transmission. However, the EPA is currently engaged in rulemaking to stay the effective date of and reducethe regulatory burden of these rules. We continue to monitor and review these regulations to determine future impacts, including potential reporting requirements.Legislation and regulations relating to control or reporting of GHG emissions are also in various stages of discussions or implementation in many of the states inwhich 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. In addition, therehave also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowmentfunds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Suchenvironmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations andability to access capital. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits brought by public and privateentities against oil and gas companies in connection with their greenhouse gas emissions. Should we be targeted by any such litigation, we may incur liabilitywhich, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to our causation of or contribution to theasserted 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.Additionally, 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. 24Table of ContentsPlease 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.Changes 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.25Table of ContentsTerrorist 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.The threat and impact of cyberattacks may adversely impact our operations and could result in information theft, data corruption, operational disruption,and/or financial loss.We depend on digital technology, including information systems and related infrastructure, as well as, cloud applications and services, to store, transmit,process and record sensitive information (including trade secrets, employee information and financial and operating data), communicate with our employees andbusiness partners and for many other activities related to our business. Our business processes depend on the availability, capacity, reliability and security of ourinformation technology infrastructure and our ability to expand and continually update this infrastructure in response to our changing needs and, therefore, it iscritical to our business that our facilities and infrastructure remain secure. While we have implemented strategies to mitigate impacts from these types of events,we cannot guarantee that measures taken to defend against cybersecurity threats will be sufficient for this purpose. The ability of the information technologyfunction to support our business in the event of a security breach or a disaster such as fire or flood and our ability to recover key systems and information fromunexpected interruptions cannot be fully tested, and there is a risk that, if such an event actually occurs, we may not be able to address immediately therepercussions of the breach or disaster. In that event, key information and systems may be unavailable for a number of days or weeks, leading to our inability toconduct business or perform some business processes in a timely manner. Moreover, if any of these events were to materialize, they could lead to losses ofsensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation,financial condition or results of operations.Our employees have been and will continue to be targeted by parties using fraudulent “spoof” and “phishing” emails to misappropriate information or tointroduce viruses or other malware through “trojan horse” programs to our computers. These emails appear to be legitimate emails but direct recipients to fakewebsites operated by the sender of the email or request that the recipient send a password or other confidential information through email or download malware.“Spoof” and “phishing” activities are a serious risk that may damage our information technology infrastructure.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. Any failure to maintain effective controls or difficulties encountered in the effective improvement of our internalcontrols could prevent us from timely and reliably reporting our financial results and may harm our operating results. Ineffective internal controls could also causeinvestors to lose confidence in our reported financial information. In addition, the Financial Accounting Standards Board or the SEC could enact new accountingstandards that might affect how we are required to record revenues, expenses, assets and liabilities. Any significant change in accounting standards or disclosurerequirements could have a material effect on our business, results of operations, financial condition and ability to comply with our debt obligations. 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. 26Table of ContentsErgon 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 consider the interests of parties other than us and our unitholders, such as Ergon and its affiliates, in resolvingconflicts 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.•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 decide to receive a quantity of our Class B units in exchange for resetting the target distribution levels related to its incentivedistribution 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 for27Table of Contentsresetting the target distribution levels related to its incentive distribution rights, the exercise of its limited call right, the exercise of its rights to transferor vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation of thepartnership 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.Ergon 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 only28Table of Contentsby or with the consent of our General Partner. As a result of these limitations, the price at which the common units will trade could be diminished because of theabsence or 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. 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 11, 2019 , Ergon owned approximately 28.2% 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 11, 2019 , the executive officers and directors of our General Partner beneficially own an aggregate of 1,078,187 common units and 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, our29Table of Contentsunitholders may be required to sell their units at an undesirable time or price and may not receive any return on their investment. Our unitholders also may incur atax liability upon a sale of their units. As of March 11, 2019 , Ergon owned 52.1% of our outstanding Preferred 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 $0.715 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.We 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 to force the conversion of theoutstanding Preferred Units at any time if (i) the daily volume-weighted average trading price of our common units is greater than $8.45 for 20 out of the trailing30 trading days ending two trading days before we furnish notice of conversion and (ii) the average trading volume of our common units has exceeded 20,000common units for 20 out of the trailing 30 trading days ending two trading days before we furnish notice of conversion. In addition, the conversion provisions maybe modified with the consent of a majority of the outstanding Preferred Units. As of March 11, 2019 , Ergon owned 52.1% of our outstanding Preferred Units andhas the ability to consent to amendments to such conversion provisions. As a result, our preferred unitholders may be required to convert their Preferred Units at anundesirable 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 11, 2019 , 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.30Table of Contents 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 the holder’s purchase price and the then-current market price of the units. The redemption price would be paid in cash or bydelivery of a promissory note, as determined 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 who31Table of Contentsknew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partnersare liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limitedpartner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnershipinterests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.Tax Risks to UnitholdersOur 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.Our 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. 32Table of ContentsThe 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.Our ability to deduct interest on indebtedness (including, under certain proposed regulations, regular distributions on our preferred units) properly allocable toour trade or business (which excludes investment interest) will be limited to an amount equal to the sum of (i) our business interest income during the taxable yearand (ii) 30% of our adjusted taxable income for such taxable year. For taxable years beginning before January 1, 2022, adjusted taxable income means earningsbefore interest, taxes, depreciation, and amortization; for taxable years beginning on or after January 1, 2022, adjusted taxable income is limited to earnings beforeinterest and taxes. Disallowed interest (and perhaps regular payments) deductions will be allocated to our unitholders and will be available to offset our futureexcess taxable income allocated to such unitholders. A unitholder’s tax basis in our interests will be reduced by the amount of disallowed interest (and perhapsregular payments) deductions allocated to such unitholder, even if such amounts do not give rise to a deduction to the unitholder in that taxable year. Suchunitholder’s tax basis in its partnership interests will be subsequently increased immediately prior to any disposition by such unitholder of its interest in us in anamount equal to the difference between the prior basis reduction and the amount of the disallowed interest (and perhaps regular payments) that has subsequentlybeen used to offset excess taxable income of the unitholder.The 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. 33Table of ContentsTax 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.If a non-U.S. unitholder sells or otherwise disposes of a common unit, the transferee is required to withhold 10% of the amount realized by 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 the transferee but were notwithheld. However, the U.S. Department of the Treasury and the IRS have determined that this withholding requirement should not apply to any disposition of apublicly traded interest in a publicly traded partnership (such as us) until regulations or other guidance have been issued clarifying the application of thiswithholding requirement to dispositions of interests in publicly traded partnerships. Accordingly, while this new withholding requirement does not currently applyto 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.Our 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 which34Table of Contentscurrently impose income taxes on corporations, and many of which impose income taxes on other entities and nonresident individuals. We may own property orconduct business 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. Underthe tax laws 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 aresident of that state. For example, in the case of Oklahoma, we are required to report annual tax information about our non-Oklahoma resident unitholders withincome in excess of five hundred dollars or withhold an amount equal to 5% of the portion of our distributions to unitholders which is deemed to be the Oklahomashare 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.Unitholders 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 Unrealized35Table of ContentsGain or Unrealized Loss will not be taxable to the converting preferred unitholder or to any other unitholders. If the Unrealized Gain or Unrealized Loss allocatedas a result of the conversion of a Preferred Unit is not sufficient to cause the capital account of each common unit received upon such conversion to equal the perunit capital account for each existing common unit, then capital account balances will be reallocated among the unitholders as needed to produce this result. In theevent that such a reallocation is needed, a converting preferred unitholder would be allocated taxable gross income in an amount equal to the amount of any suchreallocation to it.We 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 in36Table of Contentsconnection with acquisition of real property, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdensand minor easements, restrictions and other encumbrances to which the underlying properties were subject at the time of acquisition by our predecessor or us, webelieve that none of these burdens will materially interfere with their use in the operation of our business.Item 3. Legal Proceedings.The information required by this item is included under the caption “Commitments and Contingencies” in Note 18 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 7, 2019, there were 40,714,857 common units outstanding, held by approximately 770 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 7.5% ofthe common units and 52.1% of the Preferred Units.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;37•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. 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.38Table of ContentsItem 6. Selected Financial Data. The following table shows selected historical financial and operating data of Blueknight Energy Partners for the annual periods and as of the dates presented. 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.” 39Table of Contents 2014 2015 2016 2017 2018Statements of Operations Data:(in thousands, except for per unit data)Service revenue: Third-party revenue$139,426 $137,415 $126,215 $113,772 $58,756Related-party revenue (1)42,788 39,103 30,211 56,688 22,131Lease revenue: Third-party revenue— — — — 42,067Related-party revenue— — — — 25,961Product sales revenue: Third-party revenue4,412 3,511 20,968 11,479 235,438Related-party revenue— — — — 482Total revenue186,626 180,029 177,394 181,939 384,835Costs and expenses: Operating expense134,184 127,974 111,091 123,805 113,890Cost of product sales61 3,231 14,130 8,807 126,776Cost of product sales from related party— — — — 102,469General and administrative expense17,498 18,976 20,029 17,112 15,995Asset impairment expense— 21,996 25,761 2,400 53,068Total costs and expenses151,743 172,177 171,011 152,124 412,198Gain (loss) on sale of assets2,464 6,137 108 (975) 149Operating income37,347 13,989 6,491 28,840 (27,214)Other income (expense): Equity earnings (loss) in unconsolidated entity883 3,932 1,483 61 —Gain on sale of unconsolidated affiliate— — — 5,337 2,225Interest expense(12,268) (11,202) (12,554) (14,027) (16,860)Unrealized gain on investments2,079 — — — —Income (loss) before income taxes28,041 6,719 (4,580) 20,211 (41,849)Provision for income taxes469 323 260 166 198Net income (loss)$27,572 $6,396 $(4,840) $20,045 $(42,047)Allocation of net income (loss) for purpose of calculating earningsper unit: General partner interest in net income$641 $554 $433 $944 $(512)Preferred interest in net income$21,563 $21,564 $25,824 $25,115 $25,115Net income (loss) available to limited partners$5,368 $(15,722) $(31,097) $(6,014) $(66,650) Basic and diluted net income (loss) per common unit$0.20 $(0.47) $(0.87) $(0.15) $(1.61) Cash distributions per unit to limited partners (2) : Paid$0.52 $0.56 $0.58 $0.58 $0.45Declared$0.53 $0.57 $0.58 $0.58 $0.39Cash 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$310,163 $312,934 $307,334 $296,069 $248,261Total assets$364,395 $364,746 $375,663 $340,869 $323,304Long-term debt and other long-term liabilities$219,736 $247,548 $329,546 $312,542 $281,335Total partners’ capital$119,956 $87,219 $25,576 $4,684 $(6,896)________________(1)Prior to the Ergon Change of Control (as previously defined), Vitol was a related party. Subsequent to the Ergon Change of Control, Ergon is a related party. For the years ended December31, 2014, 2015, 2016, 2017 and 2018, we recognized revenues of $41.8 million, $37.8 million, $23.2 million, $21.5 million and $38.2 million , respectively, for services provided to Vitol.All amounts earned in 2014 and 2015 are classified as related-party revenues. For the year ended December 31, 2016, $17.9 million is classified as related-party revenues and $5.3 millionis classified as third-party revenues. For the years ended December 31, 2017 and 2018, all amounts are classified as related-party revenues. For the years ended December 31, 2014, 2015,2016, 2017 and 2018, we recognized revenues of $15.3 million, $15.5 million, $22.2 million, $56.4 million and $48.1 million , respectively, for services provided to40Table of ContentsErgon. All amounts earned in 2014 and 2015 are classified as third-party revenues. For the year ended December 31, 2016, $11.3 million is classified as third-party revenues and $10.9million is classified as related-party revenues. All amounts earned in 2017 and 2018 are classified as related-party revenues.(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 services. Potential Impact of Crude Oil Market Price Changes and Other Factors on Future RevenuesThe crude oil market price and the corresponding forward market pricing curve may fluctuate significantly from period to period. In addition, volatility in theoverall energy industry and specifically in publicly traded midstream energy partnerships may impact our partnership in the near term. Factors include the overallmarket price for crude oil and whether or not the forward price curve is in contango (in which future prices are higher than current prices and a premium is placedon storing product and selling at a later time) or backwardated (in which the current crude oil price per barrel is higher than the future price per barrel and apremium is placed on delivering product to market and selling as soon as possible), changes in crude oil production volume and the demand for storage andtransportation capacity in the areas in which we serve, geopolitical concerns and overall changes in our cost of capital. As of March 11, 2019 , the forward pricecurve is in a shallow contango. Potential impacts of these factors are discussed below.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.Our Wilmington, North Carolina, asphalt facility was affected by Hurricane Florence in September 2018. Damage to the plant was primarily limited to the lossof insulation on multiple storage tanks. While the impairment of these assets reflected in the year ended December 31, 2018 is minimal due to the low net bookvalue of the assets, costs in 2018 to replace the insulation and clean up debris were approximately $0.5 million, consisting of $0.4 million in maintenance capitalexpenditures and $0.1 million in maintenance expense. While we are pursuing insurance claims for this event, there can be no assurance of the amount or timing ofany proceeds we may receive under such claims. The majority of revenues earned at the Wilmington facility are fixed fees; however, we estimate a loss ofthroughput revenues to have been less than $0.1 million as we were unable to deliver product out of the terminal for several weeks. In addition, our Bainbridge,Georgia, asphalt facility was affected by Hurricane Michael in October 2018, and damages were primarily limited to the loss of insulation on two storage tanks.Costs to replace the insulation and clean up debris in 2018 were approximately $0.3 million, consisting of $0.2 million in maintenance capital expenditures and$0.1 million in maintenance expense. We expect less than $0.1 million in additional costs related to these repairs for both facilities in 2019.On July 12, 2018, we sold certain asphalt facilities, storage tanks and related real property, contracts, permits, assets andother interests located in Lubbock and Saginaw, Texas, and Memphis, Tennessee, to Ergon for a purchase price of $90.0 million.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. Since March of 2016, the crude oil curve has generally been in a shallow contango orbackwardation. In these shallow contango or backwardated markets there is no clear incentive for marketers to store crude oil. A shallow contango or abackwardated market may impact our ability to re-contract expiring contracts and/or decrease the storage rate at which we are able to re-contract. As a result of thecurrent shallow backwardation and overall demand for Cushing storage, we anticipate that we will continue to experience a challenging recontracting environmentwhich may impact both the volume of storage we are able to successfully recontract and the rate at which we recontract.41Table of ContentsCrude Oil Pipeline Services - A backwardated crude oil forward pricing curve tends to favor the crude oil pipeline transportation business as crude oilmarketers are incentivized to transport crude oil to market for sale as soon as possible. However, our crude oil pipeline services business has been impactedrecently by an out-of-service pipeline. Between April 2016 and July 2018, we had been operating one Oklahoma pipeline system, instead of two systems,providing us with a capacity of approximately 20,000 to 25,000 barrels per day (Bpd). In July 2018, we were able to restore service to a second system which hasincreased the transportation capacity of our pipeline systems by approximately 20,000 Bpd. The ability to fully utilize the capacity of these systems may beimpacted by the market price of crude oil and producers’ decisions to increase or decrease production in the areas we serve.In the last half of 2018, we increased the volumes of crude oil transported for our internal crude oil marketing operations with the objective of increasing theoverall utilization of our Oklahoma crude oil pipeline systems. Typically, the volume of crude oil we purchase in a given month will be sold in the same month.However, we may have market price exposure for inventory that is carried over month-to-month as well as pipeline linefill we maintain. We may also be exposedto price risk with respect to the differing qualities of crude oil we transport and our ability to effectively blend them to market specifications. Despite the increasein transported volumes, operating margin in our crude oil pipeline segment was negative for 2018, and in December 2018, we evaluated our pipeline system forimpairment and recorded an impairment expense of $40.7 million .On May 10, 2018, we, together with affiliates of Ergon and Kingfisher Midstream, LLC (“Kingfisher Midstream”), a subsidiary of Alta Mesa Resources, Inc.,announced the execution of definitive agreements to form Cimarron Express Pipeline, LLC (“Cimarron Express”). We have an agreement (the “Agreement”) withErgon that gives each party rights concerning the purchase or sale of Ergon’s interest in Cimarron Express, subject to certain terms and conditions. CimarronExpress was formed to build a new 16-inch diameter, 65-mile crude oil pipeline running from northeastern Kingfisher County, Oklahoma to the Partnership’sCushing, Oklahoma crude oil terminal, with an originally anticipated in-service date in the second half of 2019. Ergon formed a Delaware limited liabilitycompany, Ergon - Oklahoma Pipeline, LLC (“DEVCO”), which holds Ergon’s 50% membership interest in Cimarron Express. Under the Agreement, we have theright, at any time, to purchase 100% of the authorized and outstanding member interests in DEVCO from Ergon for the Purchase Price (as defined in theAgreement), which shall be computed by taking Ergon’s total investment in the Cimarron Express plus interest, by giving written notice to Ergon (the “Call”).Ergon has the right to require us to purchase 100% of the authorized and outstanding member interests of DEVCO for the Purchase Price (the “Put”) at any timebeginning the earlier of (i) 18 months from the formation, May 9, 2018, of the joint venture company to build the pipeline, (ii) six months after completion of thepipeline, or (iii) the event of dissolution of Cimarron Express. Upon exercise of the Call or the Put, we and Ergon will execute the Member Interest PurchaseAgreement, which is attached to the Agreement as Exhibit B. Upon receipt of the Purchase Price, Ergon shall be obligated to convey 100% of the authorized andoutstanding member interests in DEVCO to us or our designee. As of December 31, 2018, neither Ergon nor the Partnership has exercised their options under theAgreement.We and Ergon have been informed that Kingfisher Midstream has made the decision to suspend future investments in Cimarron Express as KingfisherMidstream has determined that the anticipated volumes from the currently dedicated acreage, and the resultant project economics, do not support additionalinvestment from Kingfisher Midstream. We and Ergon are evaluating the status of the investment in Cimarron Express. As of December 31, 2018, Cimarron Express has spent approximately $30.6 million on the pipeline project, primarily related to the purchase of steel pipe andequipment, rights of way and engineering and design services, and has cash on hand of approximately $1.9 million . Cimarron Express recorded a $20.9 millionimpairment charge in the fourth quarter of 2018 to reduce the carrying amount of its assets to their estimated fair value. In addition to its capital contributions toCimarron Express, Ergon’s interest in DEVCO includes internal Ergon labor and capitalized interest that bring its investment in DEVCO to approximately $17.6million . Ergon recorded a $10.0 million other-than-temporary impairment on its investment in Cimarron Express as of December 31, 2018 to reduce its investmentto its estimated fair value. As a result, we considered the SEC staff’s opinions outlined in SAB 107 Topic 5.T Accounting for Expenses or Liabilities Paid byPrincipal Stockholders. The Agreement was designed to have us, ultimately and from the onset, bear any risk of loss on the construction of the pipeline project andeventually own a 50% interest in the pipeline. As a result, we have recorded on a push down basis a $10.0 million impairment of Ergon’s investment in CimarronExpress in our consolidated results of operations during the year ended December 31, 2018, and a contingent liability payable to Ergon as of December 31, 2018.We experienced a decrease in revenue on our former East Texas pipeline system as a result of an overall decrease in production in the area and the expirationof an incentive tariff on a section of the system. As a result of the decrease in revenues and resulting decline in market values, we recognized an impairmentexpense of $2.3 million related to our East Texas pipeline system in the fourth quarter of 2016. In April 2017, we sold the East Texas pipeline system. We receivedcash proceeds at closing of approximately $4.8 million and recorded a gain of less than $0.1 million .42Table of ContentsThe 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.In April 2017, Advantage Pipeline, L.L.C. (“Advantage Pipeline”), in which we owned an approximate 30% equity ownership interest, was acquired by a jointventure formed by affiliates of Plains All American Pipeline, L.P. and Noble Midstream Partners LP. We received cash proceeds at closing from the sale of ourapproximate 30% equity ownership interest in Advantage Pipeline of approximately $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. We received approximately$1.1 million of the funds held in escrow in August 2017 and our remaining balance of $2.2 million in January 2018, for which we recognized an additional gain onsale of the unconsolidated affiliate in 2018.Crude Oil Trucking Services - Crude oil trucking, while potentially influenced by the shape of the crude oil forward price curve, is typically impacted more byoverall drilling and production activity and the ability to have the appropriate level of assets located properly to efficiently move the barrels to delivery points forcustomers.In December 2017, we evaluated our producer field services business for impairment and recognized an impairment expense of $2.4 million to reduce thecarrying amount of our assets to their estimated recoverable value. On April 24, 2018, we sold our producer field services business, which has been historicallyreported within the crude oil trucking services segment, and received cash proceeds at closing of approximately $3.0 million and recorded a gain of $0.4 million .Recent Events A time line of certain recent events is set forth below.•In December 2018, we evaluated our pipeline system for impairment and recorded an impairment expense of $40.7 million . We also recorded, on apush-down basis, an impairment expense of $10.0 million related to Ergon’s investment in Cimarron Express (see Note 14 to our consolidated financialstatements for additional information related to this impairment expense).•On July 12, 2018, we sold certain asphalt facilities, storage tanks and related real property, contracts, permits, assets and other interests located inLubbock and Saginaw, Texas and Memphis, Tennessee to Ergon for a purchase price of $90.0 million, subject to customary adjustments.•On June 28, 2018, the credit agreement was amended to, among other things, reduce the revolving loan facility from $450.0 million to $400.0 millionand raise the maximum permitted consolidated total leverage ratio for 2018 and 2019.•On April 24, 2018, the Partnership sold its producer field services business. The Partnership received cash proceeds at closing of approximately $3.0million and recorded a gain of $0.4 million . The sale of the producer field services business does not qualify as discontinued operations as it does notrepresent a strategic shift that will have a major effect on the Partnership’s operations or financial results.•On March 7, 2018, we acquired an asphalt facility located in Oklahoma from a third party for $22.0 million .•On December 1, 2017, we consummated a Purchase and 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 facility located in Bainbridge, Georgia, fromErgon Asphalt & Emulsions, Inc. and Ergon Terminaling, Inc. for a total purchase price of $10.2 million, consisting of 1,898,380 common unitsrepresenting 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 .•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. 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.•On October 5, 2016, we completed the Ergon Transactions which consisted of the following transactions and agreements:43Table of Contents◦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 facilities 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 facilities, 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.•On 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$21.2 million, net of underwriters’ discount and offering expenses of $1.5 million.•On 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.•In 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 and transportation revenues, (iii) product sales revenues and (iv) fuel surcharge revenues. OnOctober 5, 2016, Ergon acquired 100% of the outstanding voting stock of our General Partner from Vitol and Charlesbank. Beginning on October 5, 2016, revenuefrom 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 theyear ended December 31, 2018 , we derived approximately $48.5 million of our revenues from services we provided to related parties, with $48.1 million and $0.4million attributable to Ergon and Cimarron Express, 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 are recognized as the crude oil or asphalt product is delivered out of our terminal. Storage service revenues arerecognized as the44Table of Contentsservices are provided on a monthly basis. We earn terminalling revenues in two of our segments: (i) asphalt terminalling services and (ii) crude oil terminallingservices.As of March 11, 2019 , we have approximately 5.7 million barrels of crude oil storage under service contracts, including 3.5 million barrels of crude oilstorage contracts that expire in 2019. The remaining terms on the service contracts range from 4 months to 34 months. Storage contracts with Vitol represent 2.9million barrels of crude oil storage capacity under contract, and an additional 0.5 million barrels are under an intercompany contract.As of March 11, 2019 , we have leases and terminalling agreements for all of our 53 asphalt facilities, including 23 facilities under contract with Ergon. Theseagreements have, on average, approximately four years remaining under their terms. Six of the agreements expire by the end of 2019, and the remainingagreements expire at varying times thereafter, including 23 that expire in 2023 . We operate the asphalt facilities pursuant to terminalling agreements while ourcontract counterparties operate 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. We earn gathering and transportation revenues in two of our segments: (i) crude oil pipeline services and (ii) crude oil trucking services.The following is a summary of our average gathering and transportation volumes for the periods indicated (in thousands of barrels per day): Year Ended December 31, VarianceFavorable/(Unfavorable) 2017 2018 Average pipeline throughput volume 23 25 2 9%Average trucking transportation volume 21 27 6 29% We completed work on the Eagle pipeline system and restored service in July 2018, increasing the transportation capacity of our pipeline systems byapproximately 20,000 Bpd. See Crude oil pipeline services segment within our results of operations discussion for additional detail. Vitol accounted for 57% and36% of volumes transported in 2017 and 2018 , respectively.With our second Oklahoma pipeline system resuming service, we anticipate additional increases in volumes transported by our crude oil transport trucks as wegather barrels to be transported on this pipeline. Vitol accounted for approximately 43% and 9% of volumes transported in 2017 and 2018 , 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 facilities. Werecognize fuel surcharge revenues in the period in which the related fuel and power expenses are incurred.Our ExpensesOperating expenses decreased by 8% in 2018 as compared to 2017 . This decrease is primarily attributable to the sale of the field services business in April2018 and three asphalt facilities to Ergon in July 2018, as well as a decrease in depreciation due to certain asphalt assets reaching the end of their depreciable lives.These decreases were offset by increases related to the two asphalt facilities acquired in December 2017 and March 2018. General and administrative expensesdecreased by 7% in 2018 as compared to 2017 . This decrease is primarily attributable to decreases in compensation expense offset by a $0.9 million charge relatedto a Partnership vendor payment made in our capacity as the Cimarron Express construction manager to a fraudulent bank account in the third quarter of 2018.Although we do not hold any interest in Cimarron Express and are not contractually liable for the fraudulent payment made from the separate Cimarron Expressconstruction bank account, given that our general partner, Ergon, holds a 50% interest in Cimarron Express, we entered into a separate arrangement with CimarronExpress at the time the fraudulent payment was identified, whereby we agreed to reimburse the Cimarron Express construction bank account for the fraudulentpayment made to maintain a working relationship with the owners of Cimarron Express. Our45Table of Contentsinterest expense increased by $2.8 million in 2018 as compared to 2017 . See Interest expense within our results of operations discussion for additional detailregarding the factors that contributed to the increase in interest expense in 2018 .Income 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, 2018 .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 limited direct exposure to changes in liquid asphalt and crude oil prices, but the volumes of liquid asphalt and crude oilwe terminal, gather, market or transport are affected by commodity prices. We generate revenues by charging a fee for services provided at each transportationstage as crude oil is shipped from its origin at the wellhead to destination points such as the Cushing Interchange, to refineries in Oklahoma, Kansas and Texas orto pipelines and by charging a fee for services provided for the terminalling of liquid asphalt and crude oil.•Asphalt Terminalling Services. Our 53 asphalt facilities 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 8.8 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 53 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 646 miles of pipelines that gather crude oil for our customers andtransport it to refiners, to common46Table of Contentscarrier pipelines for ultimate delivery to refiners or to terminalling facilities owned by us and others. We previously owned and operated the East Texaspipeline system, which is located in Texas. On April 18, 2017, we sold the East Texas pipeline system. See Note 8 of our Consolidated FinancialStatements for additional information. •Crude oil trucking services. In addition to our pipelines, we use our approximately 60 owned or leased tanker trucks to gather crude oil in Oklahoma,Kansas and Texas for our customers at remote wellhead locations generally not connected to pipeline and gathering systems and transport the crude oilto aggregation points and storage facilities located along pipeline gathering and transportation systems. Factors That Will Significantly Affect Our Results Commodity Prices . Although our current operations (other than our crude oil marketing activities conducted in our crude oil pipeline services segment) havelimited direct exposure to commodity prices, the volumes of liquid asphalt and crude oil we terminal, gather or transport are affected by commodity prices.Petroleum product prices may be contango (future prices higher than current prices) or backwardated (future prices lower than current prices) depending on marketexpectations for future supply and demand. Our terminalling services benefit most from an increasing price environment, when a premium is placed on storage,and our gathering and transportation services benefit most from a declining price environment, when a premium is placed on prompt delivery. Volumes . Our results of operations are dependent upon the volumes of 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 AgreementsVitol was a related party until October 5, 2016. During 2016 , 2.2 million barrels of storage capacity were dedicated to Vitol under storage agreements.Service revenues under the agreements were based on the barrels of storage dedicated to Vitol under the applicable agreement at rates that, we believe, were fairand reasonable to us and our unitholders and were comparable with the rates we charged third parties. The Board’s conflicts committee reviewed and approvedthe agreements in accordance with our procedures for approval of related-party transactions and the provisions of the partnership agreement. For the year endedDecember 31, 2016, we generated revenue under these agreements of approximately $9.6 million , of which $7.5 million was classified as related-party revenue.Ergon AgreementsTwenty-three of our asphalt facilities 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. All of the agreements expire on December 31, 2023. We may not be able to extend, renegotiate or replace these contracts when theyexpire and the terms of any renegotiated contracts may not be as favorable as the contracts they replace. The Board’s conflicts committee reviewed and approvedthese agreements in accordance with our procedures for approval of related-party transactions and the provisions of the partnership agreement. For the year endedDecember 31, 2016, we recognized47Table of Contentsrevenues 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 yearsended December 31, 2017 and 2018 , we recognized revenues of $56.3 million and $48.0 million , respectively, for services provided to Ergon under theseagreements, 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, 2016 , 2017 and 2018 , reconciled to the most directly comparable GAAPmeasure: Favorable/(Unfavorable)Operating ResultsYear ended December 31, 2016-2017 2017-2018(dollars in thousands)2016 2017 2018 $ % $ %Operating margin, excluding depreciationand amortization Asphalt terminalling services operatingmargin$56,769 $64,623 $66,327 $7,854 14 % $1,704 3 %Crude oil terminalling services operatingmargin20,048 17,977 8,778 (2,071) (10)% (9,199) (51)%Crude oil pipeline services operatingmargin4,347 (1,700) (3,604) (6,047) (139)% (1,904) (112)%Crude oil trucking services operatingmargin1,829 (434) (442) (2,263) (124)% (8) (2)%Total operating margin, excludingdepreciation and amortization82,993 80,466 71,059 (2,527) (3)% (9,407) (12)% Depreciation and amortization30,820 31,139 29,359 (319) (1)% 1,780 6 %General and administrative expense20,029 17,112 15,995 2,917 15 % 1,117 7 %Asset impairment expense25,761 2,400 53,068 23,361 91 % (50,668) (2,111)%Gain (loss) on sale of assets108 (975) 149 (1,083) (1,003)% 1,124 (115)%Operating income (loss)6,491 28,840 (27,214) 22,349 344 % (56,054) (194)% Other income (expenses): Equity earnings in unconsolidatedaffiliate1,483 61 — (1,422) (96)% (61) (100)%Gain on sale of unconsolidated affiliate— 5,337 2,225 5,337 N/A (3,112) (58)%Interest expense(12,554) (14,027) (16,860) (1,473) (12)% (2,833) (20)%Provision for income taxes(260) (166) (198) 94 36 % (32) (19)%Net income (loss)$(4,840) $20,045 $(42,047) $24,885 514 % $(62,092) (310)% Total operating margin excluding depreciation and amortization decreased 12% from 2017 to 2018 . Asphalt terminalling services operating margin increased$1.7 million , or 3% , from 2017 to 2018 as a result of the acquisition of two asphalt48Table of Contentsfacilities in December 2017 and March 2018, partially offset by the sale of three asphalt facilities to Ergon in July 2018. This increase was offset by decreases inour other operating segments. The decrease in our crude oil terminalling services operating margin was primarily due to lower storage rates as well as theexpiration of a 2.2-million-barrel storage contract on April 30, 2018, that was not replaced until November 2018. Our second Mid-Continent pipeline was placedback in service in July 2018 and throughput volumes have increased in the fourth quarter of 2018. However, the increase in volumes is attributable primarily to thecrude oil marketing activities conducted in our crude oil pipeline services segment, and we have realized overall lower margins on those volumes as compared tovolume we transport for third parties.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 facilities 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.A more detailed analysis of changes in operating margin by segment follows.Analysis 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, 2016-2017 2017-2018(dollars in thousands)2016 2017 2018 $ % $ %Service revenue: Third-party revenue$75,655 $57,486 $26,108 $(18,169) (24)% $(31,378) (55)%Related-party revenue11,762 56,378 21,686 44,616 379 % (34,692) (62)%Lease revenue: Third-party revenue— — 41,319 — N/A 41,319 N/ARelated-party revenue— — 25,961 — N/A 25,961 N/AProduct sales revenue: Related-party revenue— — 482 — N/A 482 N/ATotal revenue87,417 113,864 115,556 26,447 30 % 1,692 1 %Operating expense, excluding depreciation andamortization30,648 49,241 49,229 (18,593) (61)% 12 — %Operating margin, excluding depreciation andamortization$56,769 $64,623 $66,327 $7,854 14 % $1,704 3 %The following is a discussion of items impacting our asphalt terminalling services segment operating margin for the periods indicated:•Due to the adoption of ASC 606 - Revenue from Contracts with Customers , revenue from contracts with customers is now presented separately from leaserevenue. Prior periods were not reclassified.49Table of Contents•Overall revenues have increased for the year ended December 31, 2018, as compared to the year ended December 31, 2017. Additional revenues from theacquisition of two asphalt facilities in December 2017 and March 2018 were partially offset by the sale of three asphalt facilities to Ergon in July 2018.•Operating expenses in 2018 decreased slightly as compared to 2017. Decreases due to the sale of the three asphalt facilities in July 2018 were offset byincreases due to the two terminals acquired in December 2017 and March 2018 as well as increased maintenance and repair expense.•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 facilities 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.Crude 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, 2016-2017 2017-2018(dollars in thousands)2016 2017 2018 $ % $ %Service revenue: Third-party revenue$16,387 $22,177 $11,928 $5,790 35 % $(10,249) (46)%Related-party revenue7,858 — — (7,858) (100)% — N/AIntersegment revenue— — 704 — N/A 704 N/ALease revenue: Third-party revenue— — 45 — N/A 45 N/ATotal revenue24,245 22,177 12,677 (2,068) (9)% (9,500) (43)%Operating expense, excluding depreciation andamortization4,197 4,200 3,899 (3) — % 301 7 %Operating margin, excluding depreciation andamortization$20,048 $17,977 $8,778 $(2,071) (10)% $(9,199) (51)% Average crude oil stored per month at ourCushing terminal (in thousands of barrels)5,536 5,413 1,275 (123) (2)% (4,138) (76)%Average crude oil delivered to our Cushingterminal (in thousands of barrels per day)78 41 48 (37) (47)% 7 17 %The following is a discussion of items impacting our crude oil terminalling services segment operating margin for the periods indicated:•Revenues earned from Vitol have moved from related-party to third-party beginning in October 2016 as a result of the Ergon Change of Control. We donot provide crude oil terminalling services to Ergon.•Total revenues for 2018 decreased compared to 2017 primarily as a result of a 2.2-million-barrel storage contract that expired on April 30, 2018 and a 0.7-million-barrel storage contract that expired on October 31, 2017. The expired50Table of Contentscontracts were not renewed or replaced until the fourth quarter of 2018 due to the backwardation of the crude oil forward price curve at the time thecontracts expired.•The decrease in operating expenses, excluding depreciation and amortization, from 2017 to 2018 is primarily related to decreased utility expenses.•Total revenues for 2017 decreased compared to 2016 due to a decrease in market rates for short-term, monthly storage contracts and decreased throughputfees as lower volumes were transferred in and out of our facilities.•Overall operating expenses for 2017 were comparable to 2016. Decreases in maintenance and repair expense were offset by an increase in property taxexpense.•As of March 11, 2019 , we have approximately 5.7 million barrels of crude oil storage under service contracts, including 3.5 million barrels of crude oilstorage contracts that expire in 2019. The remaining terms on the service contracts range from 4 months to 34 months. Storage contracts with Vitolrepresent 2.9 million barrels of crude oil storage capacity under contract, and an additional 0.5 million barrels are under an intercompany contract.51Table 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 as wellas crude oil marketing activity in which we purchase crude oil from producers in the field and transport the crude oil to our Cushing terminal to support our crudeoil marketing operations. Revenues are generated primarily through crude oil sales and pipeline 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, 2016-2017 2017-2018(dollars in thousands)2016 2017 2018 $ % $ %Service revenue: Third-party revenue$8,662 $9,580 $6,396 $918 11 % $(3,184) (33)%Related-party revenue5,433 310 445 (5,123) (94)% 135 44 %Lease revenue: Third-party revenue— — 484 — N/A 484 N/AProduct sales revenue: Third-party revenue20,968 11,094 235,428 (9,874) (47)% 224,334 2,022 %Total revenue35,063 20,984 242,753 (14,079) (40)% 221,769 1,057 %Operating expense, excluding depreciationand amortization15,270 13,310 11,828 1,960 13 % 1,482 11 %Operating expense (intersegment)890 417 5,284 473 53 % (4,867) (1,167)%Cost of product sales14,130 8,807 126,776 5,323 38 % (117,969) (1,339)%Related-party cost of product sales— — 102,469 — N/A (102,469) N/ACost of product sales (intersegment)426 150 — 276 65 % 150 100 %Operating margin, excluding depreciationand amortization$4,347 $(1,700) $(3,604) $(6,047) (139)% $(1,904) (112)% Pipeline transportation services averagethroughput volume (in thousands of barrelsper day) Mid-Continent27 22 25 (5) (19)% 3 14 %East Texas (1)9 3 — (6) (67)% (3) (100)% Crude oil marketing volumes (in thousandsof barrels per day) Sales1 1 10 — — % 9 900 %Purchases1 1 10 — — % 9 900 %_______________(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:•The majority of the increase in pipeline throughput volume from 2017 to 2018 is attributed to the crude oil marketing activities conducted in our crude oilpipeline services segment. Throughput volumes related to the crude oil marketing business were approximately 10,000 barrels per day, or 40% of totalthroughput, for 2018 compared to approximately 1,000 barrels per day in previous years. The service revenue for this activity associated with pipelinetariffs is eliminated on a intrasegment basis. Our crude oil pipeline recognized $4.8 million in intrasegment service revenue in 2018 that is not reflected inrevenues in the table above. In 2017, the intrasegment revenues were $0.1 million. In addition, we have realized overall lower margins within the pipelineservices segment on those volumes as compared to volume we transport for third parties as the crude oil marketing business incurs intercompany trucking52Table of Contentstransportation costs to gather crude oil purchased from producers and deliver it to our pipeline systems. The increases in product sales revenues,intersegment operating expense, and related-party and third-party cost of product sales is also due to the increase in our crude oil marketing business.•In July 2018, we restored service on the second Oklahoma pipeline that had been out of service since April 2016 due to a pipeline exposure on a riverbedin southern Oklahoma. This restored our transportation capacity to the full 50,000 barrels per day. Average throughput for the fourth quarter of 2018 was34,000 barrels per day, an increase of over 50% compared to 2017 and the first three quarters of 2018. As noted above, 40% of the barrels transported byour pipelines in 2018 were for our crude oil marketing business.•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.•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. In addition, as a result of one of our third-party customers utilizing a greaterpercentage of the capacity of our Red River pipeline, product sales revenue and cost of product sales declined from 2016 to 2017, which decreased thevolume of marketed barrels of crude oil, for which revenue and costs are both recorded gross. This decrease was offset by an increase in third-partytransportation revenue from 2016 to 2017.•Beginning in October 2016, revenues from services provided to Vitol moved from related-party to third-party due to Ergon’s acquisition of our GeneralPartner, at which time Vitol ceased to be a related party.•Operating expenses decreased $0.8 million from 2017 to 2018 due to the sale of both Advantage Pipeline and the East Texas pipeline system in April2017. 2017 results also included $0.3 million of right-of-way settlement expense incurred in December 2017 related to a pipeline exposure on a riverbedin southern Oklahoma.•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 a pipeline exposure on a riverbed in southernOklahoma.53Table of ContentsCrude oil trucking servicesOn April 24, 2018, the Partnership sold the producer field services business. As a result of the sale of the producer field services business, the Partnershipchanged the name of the crude oil trucking and producer field services operating segment to crude oil trucking services during the second quarter of 2018. Ourcrude oil trucking services segment operations generally consist of fee-based activity associated with transporting crude oil products on trucks. Revenues aregenerated primarily through transportation fees.The following table sets forth our operating results from our crude oil trucking services segment for the periods indicated: Favorable/(Unfavorable)Operating ResultsYear ended December 31, 2016-2017 2017-2018(dollars in thousands)2016 2017 2018 $ % $ %Service revenue: Third-party revenue$25,511 $24,529 $14,324 $(982) (4)% $(10,205) (42)%Related-party revenue5,158 — — (5,158) (100)% — N/AIntersegment revenue890 417 4,580 (473) (53)% 4,163 998 %Lease revenue: Third-party revenue— — 219 — N/A 219 N/AProduct sales revenue: Third-party revenue— 385 10 385 N/A (375) (97)%Intersegment revenue426 150 — (276) (65)% (150) (100)%Total revenue31,985 25,481 19,133 (6,504) (20)% (6,348) (25)%Operating expense, excluding depreciation andamortization30,156 25,915 19,575 4,241 14 % 6,340 24 %Operating margin, excluding depreciation andamortization$1,829 $(434) $(442) $(2,263) (124)% $(8) (2)% Average volume (in thousands of barrels perday)27 21 27 (6) (22)% 6 29 %The following is a discussion of items impacting our crude oil trucking services segment operating margin for the periods indicated:•Beginning in October 2016, revenues for services provided to Vitol moved from related-party to third-party due to Ergon’s acquisition of our GeneralPartner in October 2016, at which time Vitol ceased to be a related party. We do not provide crude oil transportation services to Ergon.•Service revenues decreased for the year ended December 31, 2018 , as compared to the year ended December 31, 2017 , by $6.3 million due primarily tothe sale of the producer field services business. Additionally, service revenues have decreased despite an increase in volumes as the volumes hauled in2018 were, on average, over a shorter distance than in 2017, which resulted in lower revenue and operating margin per barrel transported. •Furthermore, the growth in our crude oil pipeline services segment’s crude oil marketing business in 2018 resulted in an increase in volumes transportedon an intercompany basis to support our crude oil marketing business from less than 1,000 barrels per day to approximately 10,000 barrels per day.•Operating expense, excluding depreciation and amortization, decreased for the year ended December 31, 2018 , as compared to the year ended December31, 2017 , by $6.3 million due to the sale of our producer field services business in April 2018.•Third party and intersegment product sales revenues for all periods were the result of crude oil sales in our field services business to third parties and toour crude oil pipeline services segment.54Table of ContentsOther Income and Expenses Depreciation and amortization. Depreciation and amortization decreased to $29.4 million for 2018 compared to $31.1 million for 2017 and $30.8 million for2016 . The decrease is primarily the result of assets reaching the end of their depreciable lives as well as the sale of three asphalt facilities in July 2018, partiallyoffset by the acquisition of two asphalt facilities in December 2017 and March 2018.General and administrative expense . General and administrative expense was $16.0 million for the year ended December 31, 2018 , compared to $17.1million for 2017 and $20.0 million for 2016 . The decrease from 2017 to 2018 is primarily due to decreased compensation expense related to lower headcount andreduced incentive compensation in 2018. The year ended December 31, 2016, included $1.8 million of transaction fees related to the Ergon Change of Control andacquisition-related expenses.Asset impairment expense. Asset impairment expense in 2018 included a $10.0 million impairment on a push-down basis related to Ergon’s investment inCimarron Express. See Note 14 to our consolidated financial statements for more information. Asset impairment expense in 2018 also included $40.7 millionrelated to a markdown of our pipeline system to its estimated fair value and $1.7 million related to an impairment of our pipeline linefill due to the recoverablevalue of the linefill as indicated by market rates dropping below our historical average cost per barrel. Other impairments in 2018 were comprised primarily of awrite-down of an obsolete truck station. During 2017, we recorded fixed asset and intangible asset impairment expense, including an impairment of goodwill, of$2.4 million related to a write-down of our producer field services business to its estimated fair value. During 2016, we recorded fixed asset impairment expense of$25.8 million , 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. Gain (loss) on sale of assets. Gain on sale of assets was $0.1 million in 2018 compared to a loss of $1.0 million and a gain of $0.1 million for 2017 and 2016 ,respectively. The gain of $0.4 million related to the sale of our field services business in April 2018 was offset by losses on the sale of pipeline linefill and the saleand disposal of surplus, used property and equipment. Losses for 2017 include $0.4 million related to the disposal of an asphalt tank floor that had to be replaceddue to corrosion. Additional losses in 2017 were the result of sales and disposals of surplus, used property and equipment. The gain on sale of assets in 2016consists of the sale of surplus, used property and equipment.Equity earnings in unconsolidated affiliate. The equity earnings are attributable to our former investment in Advantage Pipeline. In April 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, for which we recognized an additional gain on sale of unconsolidated affiliate during the three months ended March 31, 2018.Interest expense. Interest expense was $16.9 million for 2018 compared to $14.0 million and $12.6 million for 2017 and 2016 , 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 following table presents the significant components of interest expense: Favorable/(Unfavorable) Year ended December 31, 2016-2017 2017-2018 2016 2017 2018 $ % $ %Credit agreement interest$10,108 $12,659 $15,749 (2,551) (25)% (3,090) (24)%Amortization of debt issuance costs1,107 1,123 1,015 (16) (1)% 108 10 %Write-off of debt issuance costs— 693 437 (693) N/A 256 37 %Interest rate swaps interest expense (income)2,498 1,317 (129) 1,181 47 % 1,446 110 %Gain on interest rate swaps mark-to-market(1,156) (1,790) (201) 634 55 % (1,589) (89)%Other(3) 25 (11) (28) 933 % 36 144 %Total interest expense$12,554 $14,027 $16,860 (1,473) (12)% (2,833) (20)%55Table of ContentsThe increases in credit agreement interest are due to higher interest rates and higher weighted average debt outstanding during the periods. Changes in interestrate swaps expense(income) and gain on interest rate swaps are due to higher market interest rates.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, 2016 , 2017 and 2018 : Year ended December 31, 2016 2017 2018 (in millions)Net cash provided by operating activities$52.8 $54.5 $48.8Net cash provided by (used in) investing activities(159.6) 17.1 39.5Net cash provided by (used in) financing activities107.0 (72.4) (89.3) Operating Activities . Net cash provided by operating activities was $48.8 million for the year ended December 31, 2018 , as compared to $54.5 million forthe year ended December 31, 2017 . The decrease in cash provided by operating activities is primarily the result of changes in net income as described in Results ofOperations and in working capital.Net cash provided by operating activities was $54.5 million for the year ended December 31, 2017 , as compared to $52.8 million for the year endedDecember 31, 2016 . The increase in cash provided by operating activities is primarily the result of changes in working capital.Investing Activities . Net cash provided by investing activities was $39.5 million for the year ended December 31, 2018 . Net cash provided by investingactivities consisted of $95.8 million of proceeds from the sale of assets, including $88.5 million related to the three asphalt facilities sold to Ergon and the sale ofour investment in Advantage Pipeline and other assets. Proceeds were offset by capital expenditures. Capital expenditures for the year ended December 31, 2018 ,included maintenance capital expenditures of $8.7 million , net of reimbursable expenditures of $0.5 million , and expansion capital expenditures of $24.8 million ,net of reimbursable expenditures of $0.3 million . Expansion capital expenditures for 2018 included $13.1 million of crude oil pipeline linefill to support our crudeoil marketing business’ activities. We also acquired an asphalt facility from a third party for $22.0 million in 2018.Net cash provided by investing activities was $17.1 million for the year ended December 31, 2017 . Capital expenditures for the year ended December 31,2017, included maintenance capital expenditures of $7.9 million , net of reimbursable expenditures of $0.8 million , and expansion capital expenditures of $9.4million , net of reimbursable expenditures of $0.6 million. These expenditures were offset by proceeds from the sale of our investment in Advantage Pipeline, theEast Texas pipeline system and other assets of $26.5 million, $4.8 million and $4.5 million, respectively.Net cash used by investing activities was $159.6 million for the year ended December 31, 2016 . Capital expenditures for the years ended December 31, 2016,included acquiring nine asphalt facilities from Ergon for $122.6 million, maintenance capital expenditures of $8.7 million, net of reimbursable expenditures of $1.9million, expansion capital expenditures of $9.4 million and other acquisitions of $19.0 million . These expenditures were partially offset by proceeds from the saleof assets of $2.0 million . Financing Activities . Net cash used in financing activities was $89.3 million for the year ended December 31, 2018 , and included net payments under ourcredit agreement of $42.0 million and distributions to unitholders of $44.7 million .56Table of ContentsNet cash used in financing activities was $72.4 million for the year ended December 31, 2017 . Financing activities for the year ended December 31, 2017 ,were primarily comprised of net payments under our credit agreement of $16.4 million and distributions to unitholders of $49.2 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 proceeds from equity issuances of $171.6 million. These increases to cash wereoffset by distributions to unitholders of $47.2 million and the repurchase of $95.3 million of Preferred Units.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, 2018 , we had a working capital deficit of $1.3 million . This is primarily a function of ourapproach to cash management. At December 31, 2018 , we had approximately $133.2 million of availability under our revolving loan facility, subject to covenantrestrictions, which limited our availability to $21.2 million .The Partnership has certain financial covenants associated with its credit agreement which include a maximum permitted consolidated total leverage ratio. The consolidated total leverage ratio is assessed quarterly based on the trailing twelve months of EBITDA, as defined in the credit agreement. The maximumpermitted consolidated total leverage ratio as of December 31, 2018, is 5.25 to 1.00, decreases to 5.00 to 1.00 as of September 30, 2019, and decreases to 4.75 to1.00 as of March 31, 2020 and thereafter. The Partnership’s consolidated total leverage ratio was 5.09 to 1.00 as of December 31, 2018. Management evaluates whether conditions and/or events raise substantial doubt about the Partnership’s ability to continue as a going concern within one yearafter the date that the consolidated financial statements are issued (the “assessment period”). In performing this assessment, management considered the riskassociated with its ongoing ability to meet the financial covenants.Based on the Partnership’s forecasted EBITDA during the assessment period, management believes that it will meet these financial covenants (as describedbelow). However, there are certain inherent risks associated with our continued ability to comply with our consolidated total leverage ratio covenant. These risksrelate, among other things, to potential future (a) decreases in storage volumes and rates as well as throughput and transportation rates realized; (b) weatherphenomenon that may potentially hinder the Partnership’s asphalt business activity; and (c) other items affecting forecasted levels of expenditures and uses of cashresources. Violation of the consolidated total leverage ratio covenant would be an event of default under the credit agreement, which would cause our $265.6million in outstanding debt, as of December 31, 2018, to become immediately due and payable. If this were to occur, the Partnership would not expect to havesufficient liquidity to repay these outstanding amounts then due, which could cause the lenders under the credit facility to pursue other remedies. Such remediescould include exercising their collateral rights to the Partnership’s assets.In response to the risks described above, management undertook a plan to seek, and ultimately obtained, support from Ergon, the owner of the Partnership’sgeneral partner interest, in the form of a $15.0 million prepayment for certain asphalt lease commitments through September 2019. The Partnership received thesefunds on March 8, 2019 , and, as of March 12, 2019, paid $14.0 million to reduce outstanding borrowings under the credit agreement, thus providing increasedflexibility under the consolidated total leverage ratio covenant. Given this added flexibility, and based on our current forecasts, we believe the Partnership will beable to comply with the consolidated total leverage ratio during the assessment period. However, we cannot make any assurances that we will be able to achieveour forecasts. If we are unable to achieve our forecasts, further actions may be necessary to remain in compliance with our consolidated total leverage ratiocovenant including, but not limited to, cost reductions, common and preferred unitholder distribution curtailments, and/or asset sales. We can make no assurancesthat we would be successful in undertaking these actions, or that, the Partnership will remain in compliance with the consolidated total leverage ratio during theassessment period.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; and57Table of Contents•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.The following table breaks out capital expenditures for the years ended December 31, 2017 and 2018 (in thousands): Year ended December 31, 2017 2018Acquisitions — 21,959 Expansion capital expenditures 9,998 25,157Reimbursable expenditures (616) (338)Net expansion capital expenditures 9,382 24,819 Gross Maintenance capital expenditures 8,717 9,239Reimbursable expenditures (781) (490)Net maintenance capital expenditures 7,936 8,749Expansion capital expenditures for the year ended December 31, 2018 , included the purchase of $13.1 million of crude oil pipeline linefill to support ourcrude oil marketing business’ activities. We currently expect our expansion capital expenditures for organic growth projects to be approximately $3.5 million to$4.5 million and our maintenance capital expenditures to be approximately $9.5 million to $11.0 million , each net of reimbursable expenditures, in 2019. Oursources of liquidity for expansion and maintenance capital expenditures in 2018 were a combination of cash flows from operations and borrowings under ourcredit agreement, and we expect to use the same sources in 2019.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 our General Partner to provide for the proper conduct of our business (includingfor future capital expenditures) and to comply with the provisions of our credit agreement. We may not grow as quickly as businesses that reinvest their availablecash to expand ongoing operations because we distribute all of our available cash.Description of Credit Agreement . On May 11, 2017, we entered into an amended and restated credit agreement. On June 28, 2018, the credit agreement wasamended to, among other things, reduce the revolving loan facility from $450.0 million to $400.0 million and amend the maximum permitted consolidated totalleverage ratio as discussed below. 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 3.25% 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 2.25% . 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 quarterly58Table of Contentsbased on our consolidated total leverage ratio (as defined in the credit agreement, being generally computed as the ratio of consolidated total debt to consolidatedearnings 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 5.50 to 1.00 for the fiscal quarter endingDecember 31, 2018; 5.25 to 1.00 for the fiscal quarters ending March 31, 2019, and June 30, 2019; 5.00 to 1.00 for the fiscal quarters ending September 30, 2019,and December 31, 2019; and 4.75 to 1.00 for the fiscal quarter ending March 31, 2020, and each fiscal quarter thereafter; provided that the maximum permittedconsolidated total leverage ratio will be 5.25 to 1.00 for certain quarters after December 31, 2019, based on the occurrence of a specified acquisition (as defined inthe credit agreement, but generally being an acquisition for which the aggregate consideration is $15.0 million or more).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.In 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, 2018 , our consolidated total leverage ratio was 5.09 to 1.00 and our consolidated interest coverage ratio was 3.34 to 1.00. We were incompliance with all covenants of our credit agreement as of December 31, 2018 . 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:59Table of Contents(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, 2018 , is as follows: Payments Due by PeriodContractual ObligationsTotal Less than1 Year 1-3 Years 4-5 Years More than5 Years (in millions)Debt obligations (1)$319.7 $16.1 $32.2 $271.4 $—Operating lease obligations8.5 2.9 3.1 1.2 1.3Capital lease obligation0.6 0.2 0.4 — —____________________(1)Represents required future principal repayments of borrowings of $265.6 million and variable-rate interest payments of $54.0 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, 2018 , 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 is60Table of Contentsbased on estimates, assumptions and judgments relative to useful lives and salvage values. As assets are disposed of or sold, the cost and related accumulateddepreciation are removed from the accounts, and any resulting gain or loss is 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. We 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. In 2016, an impairment was indicated in the crude oilpipeline services reporting unit and an impairment expense of $7.5 million was recorded. In 2017 , an impairment was indicated in the crude oil trucking servicesreporting unit and an impairment expense of $0.9 million was recorded. In 2018 , no impairment expense was recorded.61Table of ContentsRecent Accounting Pronouncements For information regarding recent accounting developments that may affect our future financial statements, see Note 23 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 11, 2019 , we had $253.6 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. At times we have used i nterest rate swapagreements to manage a portion of the exposure related to changing interest rates by converting floating-rate debt to fixed-rate debt. In March 2014, we enteredinto two interest rate swap agreements with an aggregate notional value of $200.0 million . The first $100.0 million agreement became effective June 28, 2014, andmatured on June 28, 2018. Under the terms of the first interest rate swap agreement, we paid a fixed rate of 1.45% and received one-month LIBOR with monthlysettlement. The second $100.0 million agreement became effective January 28, 2015, and matured on January 28, 2019. Under the terms of the second interest rateswap agreement, we paid a fixed rate of 1.97% and received one-month LIBOR with monthly settlement. The fair market value of the interest rate swaps atDecember 31, 2018 , consists of a current asset of less than $0.1 million recorded on the consolidated balance sheets in other current assets. The interest rate swapsdo not receive hedge accounting treatment under ASC 815 - Derivatives and Hedging . Changes in the fair value of the interest rate swaps are recorded in interestexpense in the consolidated statements of operations. During the year ended December 31, 2018 , the weighted average interest rate under our credit agreement was 5.49% .Changes 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, 2018 , 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 $2.6 million .Commodity Price Risk. As a result of our crude oil marketing activities conducted in our crude oil pipeline services segment, we have direct exposure to risksassociated with changes in crude oil prices. Typically, the volume of crude oil we purchase in a given month will be sold in the same month. However, we mayhave market price exposure for inventory that is carried over month-to-month as well as pipeline linefill we maintain. We may also be exposed to price risk withrespect to the differing qualities of crude oil we transport and our ability to effectively blend them to market specifications. In addition, the volumes of liquidasphalt and crude oil we terminal, gather or transport are affected by commodity prices because many of our customers have direct commodity priceexposure. Many of our customers have been, and continue to be, adversely affected by significant changes in commodity prices. If our customers continue to benegatively impacted by commodity 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 thisvolatility to continue. Any significant reduction in the amount of services we provide to our customers would have a material adverse effect on our results ofoperations and cash flows.We do not intend to mitigate this risk to our revenues by hedging this limited commodity price exposure. For additional information regarding the anticipatedimpact of this risk on our future revenues, see “Item 7-Management’s Discussion and Analysis of Financial Condition and Results of Operations-Potential Impactof 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-34 of this report and are incorporated herein by reference.Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. None.62Table of ContentsItem 9A. Controls and Procedures.Evaluation of disclosure controls and procedures. Our General Partner’s management, including the Chief Executive Officer and Chief Accounting Officer,the principal executive officer and acting principal financial officer, respectively, of our General Partner, evaluated as of the end of the period covered by thisreport, the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934. Basedon that evaluation, the Chief Executive Officer and Chief Accounting Officer of our General Partner concluded that our disclosure controls and procedures wereeffective as of December 31, 2018.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 Accounting 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. Based on its evaluation under the framework inInternal Control - Integrated Framework , our management concluded that our internal control over financial reporting was effective as of December 31, 2018.Our internal control over financial reporting as of December 31, 2018 has been audited by PricewaterhouseCoopers LLP, our independent registered publicaccounting firm, as stated in their report appearing on page F-1.Changes in internal control over financial reporting. There were no changes to our internal control over financial reporting that occurred during the threemonths ended December 31, 2018 , that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.Item 9B. Other Information.Amendments to Storage, Throughput and Handling AgreementOn October 5, 2016, BKEP Materials, L.L.C., a Texas limited liability company and wholly owned subsidiary of the Partnership(“BKEP Materials”), BKEP Asphalt, L.L.C., a Texas limited liability company and wholly owned subsidiary of the Partnership (“BKEPAsphalt”), and Ergon Asphalt & Emulsions, Inc., a wholly owned subsidiary of Ergon (“Ergon A&E”), entered into that certain Storage,Throughput and Handling Agreement (the “Original Storage, Throughput and Handling Agreement”), pursuant to which BKEP Materials andBKEP Asphalt agreed to provide storage and terminalling services to Ergon A&E and Ergon A&E agreed to receive such services on theterms and conditions set forth therein. Effective January 1, 2019, BKEP Materials, BKEP Asphalt and Ergon A&E entered into theAmendment to Storage, Throughput and Handling Agreement (“Amendment I”) to extend the term of the Original Storage, Throughput andHandling Agreement to December 31, 2023 and otherwise amend the Original Storage, Throughput and Handling Agreement as providedtherein. In addition, effective March 7, 2019, BKEP Materials, BKEP Asphalt and Ergon A&E entered into the Amendment to Storage,Throughput and Handling Agreement (“Amendment II” and, together with Amendment I, the “Amendments”) to reflect Ergon A&E’sprepayment of storage fees under the Original Storage, Throughput and Handling Agreement for the months of April, May, June, July,August and September 2019. The Board’s conflicts committee reviewed and approved the Amendment’s in accordance with the Partnership’sprocedures for approval of related-party transactions and the provisions of the partnership agreement.Lease AgreementEffective January 1, 2019, BKEP Materials, BKEP Asphalt and Ergon A&E entered the Lessee Operated Facilities Lease AgreementNo. 2019-00068 (the “Lease Agreement”), pursuant to which BKEP Materials and BKEP Asphalt agreed to lease Ergon A&E certainfacilities identified therein. The term of the Lease Agreement is five years, beginning on January 1, 2019 and continuing until December 31,2023. The Lease Agreement encompasses 12 facilities, which includes facilities previously accounted for under the now expired ErgonMaster Facilities Sublease and Sublicense Agreement. The Board’s conflicts committee reviewed and approved the Lease Agreement inaccordance with the Partnership’s procedures for approval of related-party transactions and the provisions of the partnership agreement.Storage, Throughput and Handling Agreement63Table of ContentsEffective January 1, 2019, BKEP Materials, BKEP Asphalt and Ergon A&E entered the Owner Operated Storage, Throughput andHandling Agreement No. 2019-00069 (the “Storage, Throughput and Handling Agreement”), pursuant to which BKEP Materials and BKEPAsphalt agreed to provide to or for Ergon A&E storage and terminalling services related to the receipt of certain feedstocks, raw materials,and finished product identified therein (“Product”) at certain product storage tanks identified therein (the “Terminal”) and the storage,terminalling, and delivery of Product into and out of the Terminal, in exchange for the payment of certain fees by Ergon A&E. The term ofthe Storage, Throughput and Handling Agreement began on January 1, 2019 and will continue until December 31, 2023. Each party hasagreed to indemnify the other party (and its affiliates) for any and all liabilities arising from (i) its breach of the Storage, Throughput andHandling Agreement, (ii) its negligence or willful misconduct, or the negligence or willful misconduct of an affiliate, or (iii) its failure tocomply with applicable law with respect to the sale, transportation, storage, handling or disposal of product. The Board’s conflicts committeereviewed and approved the Storage, Throughput and Handling Agreement in accordance with the Partnership’s procedures for approval ofrelated-party transactions and the provisions of the partnership agreement.The foregoing descriptions of the Amendments, the Lease Agreement and the Storage, Throughput and Handling Agreement are notcomplete and are qualified in their entirety by reference to the full text of the agreements, which are filed as Exhibits 10.18, 10.19, 10.28 and10.29 to this Annual Report on Form 10-K.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), Joel D. Pastorek (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 11, 2019 . 64Table of ContentsName Age Position with Blueknight Energy Partners G.P., L.L.C.Mark A. Hurley 60 Chief Executive OfficerJoel W. Kanvik 49 Chief Legal Officer and SecretaryJames R. Griffin 41 Chief Accounting OfficerJeffery A. Speer 52 Chief Operating OfficerBrian L. Melton 49 Chief Commercial OfficerDuke R. Ligon 77 Director, chairman of the Board and audit committeeSteven M. Bradshaw 70 Director, chairman of the conflicts committeeJohn A. Shapiro 67 Director, chairman of the compensation committeeW.R. “Lee” Adams 50 DirectorEdward D. Brooks 36 DirectorJoel D. Pastorek 36 DirectorRobert H. Lampton 58 DirectorWilliam W. Lampton 63 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, most recently as President of Shell Pipeline Co., LP. Mr. Hurley received his Bachelor of Science in chemicalengineering from North Carolina State University.Joel W. Kanvik has served as Chief Legal Officer of our General Partner since November 2016. Mr. Kanvik has served as Secretary since September 2018.Mr. Kanvik previously served as the Director of U.S. Law and Assistant Secretary for Enbridge Energy Company, Inc., which he joined in January 2001. Heprovided legal and business counsel to a family of corporations/limited partnerships, including the development and execution for large-scaleconstruction/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 from Northwestern 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 Devon65Table of ContentsEnergy Corporation from January 1997 until he retired in February 2007. From February 2007 to February 2010, Mr. Ligon served in the capacity of StrategicAdvisor to Love’s Travel Stops & Country Stores, Inc., based in Oklahoma City, Oklahoma, and previously acted as Executive Director of the Love’sEntrepreneurship Center at Oklahoma City University. He is also a member of the board of directors of Heritage Trust Company, Security State Bank (in which hehas a 14% beneficial ownership), Cavaloz Holdings, Inc. and Pardus Oil and Gas. He was formerly on the board of directors of PostRock Energy Corporation,System One, Orion California LP, Emerald Oil, Inc., SteelPath MLP, TransMontaigne Partners L.P., Pre-Paid Legal Services, Inc., Panhandle Oil and GasInc.,Vantage Drilling Company and TEPPCO Partners, L.P. Mr. Ligon received his undergraduate degree in chemistry from Westminster College and his lawdegree from the University of Texas School of Law. Mr. Ligon was selected to serve as a director on the Board due to his extensive business and leadershipexperience derived from his background as a director of various companies in the energy industry, as well as his 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 and marketing capacities atKirby Corporation, including as President-Refined Products Division from 1992 to 1996. Mr. Bradshaw also served as an officer in the United States Navy. Hereceived his Master of Business Administration from Harvard University and a bachelor’s degree in mathematics from the University of Missouri. Mr. Bradshawwas 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 currently serves as Senior Vice President - Finance. He also serves as Chairman of Ergon’s Senior Management Team. He is a certified publicaccountant in the state of Mississippi and previously worked at Arthur Anderson and Haddox Reid Burkes & Calhoun, PLLC, where he specialized in assuranceand advisory services in the areas of oil and gas, manufacturing, investments and employee benefit plans. Mr. Adams received his Bachelor of Accountancy fromMississippi State University, and also holds the designations of Chartered Global Management Accountant, Certified Fraud Examiner and Certified InternalAuditor. Mr. Adams currently serves as a member of the advisory council for Mississippi State’s Adkerson School of Accountancy and is the Chairman of theBoard of Hartfield Academy. He has previously served as Chairman/President of the Petroleum Accounting Society of Mississippi and of the Mississippi Societyof Certified Public Accountants, a 2,600-member trade association for CPAs practicing in the state of Mississippi. Mr. Adams was selected to serve as a director onthe Board due to his affiliation with 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.Joel D. Pastorek has served as a director of our General Partner since August 2018. Mr. Pastorek serves as the Executive Vice President - Midstream &Logistics and as President of Ergon Terminalling, Inc. He also serves as the Vice Chairman of the Ergon Senior Management Team. Mr. Pastorek joined Ergon in2005. Prior to taking the role of Executive Vice President, Mr. Pastorek held various positions within Ergon including Senior Project Manager, Manager ofCorporate Maintenance,66Table of ContentsGeneral Manager - Ergon Terminaling, Inc., Vice President - Ergon Terminaling, Inc., and President - Ergon Terminaling, Inc. Mr. Pastorek received his Bachelorof Science in mechanical engineering from Mississippi State University and is a licensed professional engineer in the state of Mississippi. Mr. Pastorek wasselected 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. He previously served as President of Ergon Terminalling, Inc., Ergon Trucking, Inc., Ergon Marine andIndustrial Supply and Ergon Properties, Inc. He is a member of Ergon’, Inc.’s board of directors. He was a board member for Mississippi Valley Title Companyfrom 2005 to 2015. Mr. Lampton received his degree in business administration with a minor 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 Ergon and 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 is a member of the Dean’s Advisory Council of MississippiState University’s Bagley College of Engineering, and served as co-chair of the Mississippi Works initiative under Governor Phil Bryant. Mr. Lampton wasselected to serve 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. 67Table of ContentsBoard 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. Conflicts 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, 2018 . 68Table of ContentsReimbursement 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 2018 , each person who served as the Principal FinancialOfficer (“PFO”) during 2018 , the three most highly compensated executive officers other than the PEO and PFO serving at December 31, 2018 , and up to twoadditional individuals for whom disclosure would have been provided but for the fact that the individual was not serving as an executive officer at December 31,2018 , are referred to as the Named Executive Officers (“NEOs”). The NEOs during 2018 were:•Mark A. Hurley, Chief Executive Officer;•Alex G. Stallings, Chief Financial Officer and Secretary until September 2018;•James R. Griffin, Chief Accounting Officer;•Jeffery A. Speer, Chief Operating Officer;•Brian L. Melton, Chief Commercial Officer; and•Joel W. Kanvik, Chief Legal Officer and Secretary.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 the69Table of Contentscompensation survey data when making decisions to change any individual NEO’s compensation, or when making changes or additions to any compensationprogram or methodologies. Aon’s work for the compensation committee did not raise any conflicts of interest 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 2018 were as follows:•base salary;•discretionary bonus awards;•long-term incentive plan awards; and•other benefits.The 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 2018, our General Partner’s compensation committee increased the base salaries of Messrs. Speer and Kanvik to $276,000 and $265,000,respectively. These base salary increases reflected the scope of each executive’s responsibilities and the compensation committee’s consideration of competitivemarket 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 2019, the compensation committee awarded discretionary bonuses of $150,000 ; $115,000 ; $150,000 ; $25,000 and $100,000 to each ofMessrs. Hurley, Griffin, Speer, Melton and Kanvik, respectively, relating to our results of operations in 2018. Please see “-2018 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 2018, the compensation committee made awards of 61,448 ; 27,447 ; 17,001 ; 29,700 ; 19,663 and 20,278 phantom units to Messrs. Hurley,Stallings, Griffin, 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’s phantom units vested on January 1, 2019. Mr. Stallings’s employment with our General Partner was ended on September 30, 2018, and, accordingly,his unvested phantom units were forfeited at such time. These phantom units contain distribution equivalent rights that entitle the holder of such units to receive acash payment equal to the amount of any ordinary quarterly cash distribution paid to our common unitholders. During March 2019, the compensation committee made awards of 38,558 ; 62,867 and 38,558 phantom units to Messrs. Griffin, Speer, and Kanvik,respectively, relating to our results of operations in 2018. The awards vest on January 1, 2022. These phantom units contain distribution equivalent rights thatentitle 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. Pleasesee “-2018 Incentive Compensation” for a discussion of these awards.70Table of ContentsOther Benefits. The employment agreements entered into by Messrs. Hurley and Griffin 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 2018 , 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 historically provided auto allowances to certain of our NEOs.2018 Incentive Compensation. For 2018 , 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 $51.0 million in cash flow generated prior todistributions, incentive compensation and reserves established by our General Partner.•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 2018 , actual cash flow generated prior to distributions,incentive compensation and reserves established by our General Partner was $36.9 million, resulting in 37% of the bonus pool being contributed based on thismetric. In addition, partnership-wide goals were partially achieved resulting in 10% of the bonus pool being contributed, environmental, health and safety targetswere also partially achieved resulting in 5% of the bonus pool being contributed, and company growth goals were not met resulting in 0% of the bonus pool beingcontributed.In March 2019, 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 2018 as follows: $115,000 ; $150,000 ; $25,000 and $100,000 for Messrs.Griffin, Speer, Melton and Kanvik, respectively; and(ii)awards of phantom units relating to our results of operations for 2018 as follows: 38,558 units, 62,867 units and 38,558 units to Messrs. Griffin,Speer and Kanvik, respectively.On March 8, 2019 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 $150,000 relating to our results of operations in 2018 . The discretionary bonus awards were paid inMarch 2019. 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 2018 . However, Mr. Hurley does not make any recommendations regarding his personalcompensation. In addition, the employment agreement entered into by Mr. Griffin was originally approved by the management committee of SemGroup, L.P.’s(now SemGroup Corporation) general partner pursuant to its limited liability company agreement. Employment Agreements. As indicated above, Messrs. Hurly and Griffin have each entered into an employment agreement with our General Partner or oneof 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.71Table of ContentsPursuant to Mr. Hurley’s employment agreement, Mr. Hurley was paid an initial annual base salary of $425,000. Our General Partner’s compensation committeehas increased the base salary of Mr. Hurley to $450,000 since the initial employment agreement. Mr. Hurley also received 500,000 non-participating phantom unitsin September 2012 under the General Partner’s Long-Term Incentive Plan, which vested ratably over five years pursuant to the Phantom Unit Agreement heentered into with the General Partner. The units were fully vested as of December 31, 2017. The employment agreement also provides that Mr. Hurley is eligible toparticipate in any employee benefit plans maintained by the General Partner and is entitled to reimbursement for certain out-of-pocket expenses. Mr. Hurley hasagreed not to disclose any confidential information obtained by him while 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 continued participation in our General Partner’s welfare benefit programs for a period of 18 months following termination. Based upon Mr. Hurley’scurrent base salary, the maximum amount of the lump sum severance payment would be approximately $0.5 million , in addition to continued participation in theGeneral Partner’s welfare benefit 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. Griffin. The employment agreement entered into by Mr. Griffin had an initial term of two years that automatically renews forsubsequent one-year periods unless either party gives 90 days advance notice of termination. This employment agreement provides for Mr. Griffin’s annual basesalary as described above. In addition, Mr. Griffin is eligible for discretionary bonus awards and long-term incentives which may be made from time to time at thesole discretion of the Board. The employment agreement also provides that Mr. Griffin is eligible to participate in any employee benefit plans maintained by ourGeneral Partner during the term of his employment with the General Partner and for up to 12 months thereafter, and is entitled to reimbursement for certain out-of-pocket expenses. Pursuant to the employment agreement, Mr. Griffin 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. Griffin, 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. Griffin in certain circumstances. Except in the event of termination for Cause (asdefined therein), termination by Mr. Griffin 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. Griffin is terminated by ourGeneral Partner without Cause (as defined therein) or Mr. Griffin terminates the agreement for Good Reason (as defined therein), he will be entitled to payment ofany 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. Griffin’s current base salary, the maximum amount of the lump sum severance payment would be approximately $0.5 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. 72Table of ContentsPotential Payments Upon Change of Control.As described above, the employment agreements with Messrs. Hurley and Griffin 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 Griffin been terminated under the scenarios listed below on December 31, 2018, they would have received the following amounts andbenefits: NameBenefit 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$450,000 $925,000 Benefits Continuation$—(1) $—(1) James R. GriffinLump Sum Severance$227,000 $454,000 Benefits Continuation$36,900 $36,900 _______________(1)Mr. Hurley did not participate in our General Partner’s group health plans as of December 31, 2018, 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,73Table of Contentsconsistent 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 ofgrant. 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. 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, 2018 , 210,824 common units have been delivered under the Unit Purchase Plan.74Table of ContentsSummary Compensation TableThe following table summarizes the compensation of our NEOs for the years ended 2018 , 2017 and 2016 . Mr. Kanvik was not an NEO in 2016.Name and PositionYear Salary($) Bonus($) (1) StockAwards($) (2)OptionAwards($)Non-EquityIncentiveCompensation($)All OtherCompensation($) (3) Total($)Mark A. HurleyChief Executive Officer2018450,000150,000299,866——53,016952,8822017448,750400,000———42,991891,7412016445,000475,000———43,075963,075Alex G. StallingsFormer Chief FinancialOfficerand Secretary (4)2018244,500—133,941——63,716442,1572017324,450160,000155,870——76,541716,8612016319,800165,000142,528——71,237698,565James R. GriffinChief Accounting Officer2018227,000115,00082,965——41,427466,3922017225,625115,000100,565——46,280487,4702016221,500110,00080,766——41,272453,538Jeffery A. SpeerChief Operating Officer2018274,000150,000144,936——63,523632,4592017258,333187,000160,904——73,424679,6612016237,000160,000175,784——65,310638,094Brian L. MeltonChief Commercial Officer2018244,00025,00095,955——49,308414,2632017242,250110,000110,611——60,578523,4392016237,000155,000104,520——57,005553,525Joel W. KanvikChief Legal Officer andSecretary2018263,750200,00098,957——36,805599,5122017260,000256,00090,505——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 2016. In connection with his appointment as ChiefLegal Officer, Mr. Kanvik received a signing and relocation bonus, of which $115,000 and $100,000 was paid in 2017 and 2018, respectively.(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 15 to our consolidated financial statementsfor assumptions used in calculating these amounts. Mr. Hurley was granted an award in 2012 with a five year vesting period in connection with his appointment as Chief Executive Officer,and he was not granted additional awards from 2013 through 2017.(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 2018 , payments related to these items were as follows: DERs Auto Allowance 401(k) plancontributions Other TotalMark A. Hurley$18,742 $3,600 $23,327 $7,347 $53,016Alex G. Stallings$25,297 $3,600 $23,327 $11,492 $63,716James R. Griffin$19,134 $— $21,753 $540 $41,427Jeffery A. Speer$35,769 $3,600 $22,913 $1,241 $63,523Brian L. Melton$22,820 $3,600 $20,192 $2,696 $49,308Joel W. Kanvik$11,881 $3,600 $18,980 $2,344 $36,805(4)Mr. Stallings resigned as Chief Financial Officer on September 30, 2018, The Partnership has not yet replaced him and Mr. Griffin is serving as interim CFO.Pension BenefitsWe do not have a pension plan in which our named executive officers are eligible to participate.Non-Qualified Deferred CompensationWe do not have a non-qualified deferred compensation plan.75Table of ContentsGrants of Plan-Based Awards for Fiscal Year 2018The following tables provide information concerning each grant of an award made to a NEO during 2018 , including, but not limited to, awards made underour General Partner’s LTIP. Estimated Future PaymentsUnder Non-Equity Incentive PlanAwards Estimated Future Payouts UnderEquity Incentive Plan Awards NameGrantDateThreshold($)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($)Mark A.HurleyMarch9,2018——— ———61,448——293,107Alex G.StallingsMarch9,2018——— ———27,447——130,922JamesR.GriffinMarch9,2018——— ———17,001——81,095JeffreyA. SpeerMarch9,2018——— ———29,700——141,669Brian L.MeltonMarch9,2018——— ———19,663——93,793Joel W.KanvikMarch9,2018——— ———20,278——96,726____________________(1)This amount represents grants of phantom units under our General Partner’s LTIP. See Note 15 to our consolidated financial statements. (2)Mr. Stallings’s employment with our General Partner ended effective September 30, 2018. Accordingly, Mr. Stallings’s unvested phantom units were forfeited at such time.Outstanding Equity Awards at Fiscal Year-End 2018The following tables provide information concerning all outstanding equity awards made to a NEO as of December 31, 2018 , including, but not limited to,awards made under our General Partner’s LTIP. Option Awards Stock AwardsNameNumber ofSecuritiesUnderlyingUnexercisedOptions (#)ExercisableNumber ofSecuritiesUnderlyingUnexercisedOptions(#)UnexercisableEquityIncentivePlanAwards:Number ofSecuritiesUnderlyingUnexercisedUnearnedOptions (#)OptionExercisePrice($)OptionExpirationDate Numberof UnitsThatHaveNotVested(#)MarketValue ofUnitsThatHaveNotVested($)EquityIncentivePlanAwards:Number ofUnearnedUnits orOtherRightsThat HaveNotVested (#) EquityIncentivePlanAwards:Market orPayoutValue ofUnearnedUnits orOtherRightsThat HaveNot Vested($) (1)Mark A. Hurley————— ——61,448(2) 70,665James R. Griffin————— ——17,001(3) 19,551————— ——14,065(4) 16,175————— ——16,932(5) 19,472Jeffery A. Speer————— ——29,700(3) 34,155————— ——22,504(4) 25,880————— ——36,852(5) 42,380Brian L. Melton————— ——19,663(3) 22,612————— ——15,471(4) 17,792————— ——21,912(5) 25,199Joel W. Kanvik————— ——20,278(3) 23,320————— ——12,658(4) 14,557____________________76Table of Contents(1)Market value of awards is calculated as the product of the closing market price of $1.15 of the Partnership’s common units at December 31, 2018, and the number of phantom unitsoutstanding at December 31, 2018 .(2)Represents phantom units granted in 2018 under our General Partner’s LTIP. These phantom units vested on January 1, 2019.(3)Represents phantom units granted in 2018 under our General Partner’s LTIP. These phantom units will vest on January 1, 2021. All of the distribution equivalent rights associated withthese phantom units are currently payable.(4)Represents phantom units granted in 2017 under our General Partner’s LTIP. These phantom units will vest on January 1, 2020. All of the distribution equivalent rights associated withthese phantom units are currently payable.(5)Represents phantom units granted in 2016 under our General Partner’s LTIP. These phantom units vested on January 1, 2019.Option Exercises and Stock Vested for Fiscal Year 2018The following table provides information regarding each vesting during 2018 of phantom units held by our NEOs. Our NEOs have not been granted stockoption awards. Stock Awards (1) NameNumber ofShares Acquiredon Vesting (#) ValueRealized onVesting ($) Alex G. Stallings7,818 41,670(2) James R. Griffin4,837 25,781(2) Jeffrey A. Speer7,924 42,235(2) Brian L. Melton6,626 35,317(2) ____________________(1)No awards vested in 2018 for Messrs. Hurley and Kanvik. (2)This value is based on the average of the high and low trading prices of our common units on January 16, 2018, the date of issuance of such common units.Director Compensation for Fiscal Year 2018NameFeesEarned orPaid inCash($)StockAwards (4)($)OptionAwards($)Non-EquityIncentive PlanCompensation($)Change inPension ValueandNonqualifiedDeferredCompensationEarnings($)All OtherCompensation($)Total($)Duke R. Ligon151,00020,624————171,624Steven M. Bradshaw151,00016,874————167,874John A. Shapiro151,00016,874————167,874Donald M. Brooks (1)(2)———————Edward D. Brooks (1)———————Joel D. Pastorek (1)———————W.R. “Lee” Adams (1)———————Jimmy A. Langdon (1)(3)———————Robert H. Lampton (1)———————William W. Lampton (1)———————____________________(1)Affiliated with Ergon.(2)Mr. Brooks resigned from the Board in February 2018.(3)Mr. Langdon passed away in July 2018.(4)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 15 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;77Table of Contents(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.In 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 2018 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, 2018 . 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 2018 annual total compensation of our CEO was $ 952,882 , the 2018 annual total compensation of ourmedian compensated employee was $75,012 and the ratio of these amounts was 12.7:1. 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, 2018 , 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 Chair78Table of ContentsSteven 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 11, 2019 held by:•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 40,714,857common units and 35,125,202 Preferred Units outstanding as of March 11, 2019 .Name of Beneficial Owner (1)CommonUnitsBeneficiallyOwnedPercentage ofCommonUnitsBeneficiallyOwned PreferredUnitsBeneficiallyOwnedPercentage ofPreferredUnitsBeneficiallyOwned Percentage ofTotalCommon and PreferredUnitsBeneficiallyOwnedErgon Asphalt & Emulsions, Inc. (2)2,745,8376.7% 18,312,96852.1% 27.8%Mark A. Hurley (5)425,6291.0% —— *James R. Griffin (5)67,947* —— *Jeffery A. Speer (5)72,428* —— *Joel W. Kanvik4,078* —— *Brian L. Melton (5)38,903* 400* *Duke R. Ligon (4)70,394* —— *Steven M. Bradshaw (4)48,524* —— *John A. Shapiro (4)46,934* —— *W.R. “Lee” Adams (2)(6)50,000* —— *Edward D. Brooks (2)(6)—— —— —Joel D. Pastorek (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%Neuberger Berman Group LLC (9)2,522,5896.2% —— 5.0%DG Capital Management, Inc. (10)2,901,0317.1% 1,131,7293.2% 5.1%Clearbridge Investments, LLC (11)3,269,6748% —— 4.3%Oppenheimer Funds, Inc. (12)2,980,1657.3% —— 4.0%All current executive officers anddirectors as a group (13 persons)1,078,1872.6% 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. (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, Pastorek, R. Lampton and W. Lampton are affiliated with Ergon.79Table of Contents(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.(9)Based on a Schedule 13G filed February 13, 2019, 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 2,313,042 common units and shared dispositive power with respect to 2,522,589 common units. Their address as reported in suchSchedule 13G is 1290 Avenue of the Americas, New York, New York 10104.(10)Based on a Schedule 13G filed February 14, 2019, 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 2,901,031 common units and 1,131,729 Preferred Units. Their address as reported in such Schedule 13G is 460 Park Avenue, 22nd Floor, New York, NewYork 10022.(11)Based on a Schedule 13G filed February 14, 2019, by Clearbridge Investments, LLC with the SEC. Their address as reported in such Schedule 13G is 620 8th Avenue, New York, NewYork 10018.(12)Based on a Schedule 13G filed January 30, 2019, 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 11, 2019 )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 1,156,666 $— 1,598,860Equity compensation plans notapproved by security holders N/A N/A N/ATotal 1,156,666 $— 1,598,860________________(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 of1,119,379 , 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 responsesare as follows: (a) 37,287 , (b) $0 and (c) 2,718,239 . 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 11, 2019 , 274,164 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 40,714,857outstanding common units, representing an aggregate 28.2% limited partner interest in us as of March 11, 2019 . 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 14 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:•our General Partner;80Table of Contents•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, 2017 2018Audit fees (1) $671,164 $695,605Audit-related fees (2) — —Tax fees (3) 299,261 266,077All 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.(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.81Table of Contents(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.82Table 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 ExhibitNumberDescription2.1Asset Purchase Agreement, dated June 29, 2018, by and between BKEP Materials, L.L.C., BKEP Terminalling, L.L.C., BKEP Asphalt, L.L.C., andErgon Asphalt & Emulsions, Inc. (filed as Exhibit 2.1 to the Partnership’s Current Report on Form 8-K, filed June 29, 2018, and incorporatedherein by reference).3.1Amended and Restated Certificate of the Partnership, dated November 19, 2009, but effective as of December 1, 2009 (filed as Exhibit 3.1 to thePartnership’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 20, 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).4.3Rights 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).4.4Specimen 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).4.5Registration 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).4.6Amended 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†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).10.2*†First Amendment to the Blueknight Energy Partners G.P., L.L.C. Long-Term Incentive Plan, dated January 17, 2018 (filed as Exhibit 10.7 to thePartnership’s Annual Report on Form 10-K, file March 8, 2018, and incorporated herein by reference).10.3†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).10.4*†Form of Phantom Unit Agreement (for grants during and after 2018) (filed as Exhibit 10.9 to the Partnership’s Annual Report on Form 10-K, filedon March 8, 2018, and incorporated herein by reference).10.5†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).10.6*†Form of Director Restricted Common Unit Agreement (for post-2017 grants) (filed as Exhibit 10.11 to the Partnership’s Annual Report on Form10-K, filed March 8, 2018, and incorporated herein by reference).83Table of Contents10.7†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).10.8†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).10.9†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).10.10†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).10.11Mutual 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).10.12Pipeline 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).10.13†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).10.14Second Amended and Restated Credit Agreement, dated as of May 11, 2017, by and among Blueknight Energy Partners, L.P. Wells Fargo Bank,National Association, as Administrative Agent, and the several lenders from time to time party thereto (filed as Exhibit 10.1 to the Partnership’sCurrent Report on Form 8-K, filed May 12, 2017 (Commission File No. 001-33503), and incorporated herein by reference).10.15First Amendment to Second Amended and Restated Credit Agreement, dated as of June 28, 2018, by and among the Partnership, Wells FargoBank, National Association, as Administrative Agent, and the lenders party thereto (filed as Exhibit 10.1 to the Partnership’s Current Report onForm 8-K, filed June 29, 2018, and incorporated herein by reference).10.16#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).10.17#First Amendment to the Storage, Throughput and Handling Agreement, dated July 12, 2018, by and between BKEP Materials, L.L.C., BKEPTerminalling, L.L.C., BKEP Asphalt, L.L.C., and Ergon Asphalt & Emulsions, Inc. (filed as Exhibit 10.1 to the Partnership’s Current Report onForm 8-K, filed July 13, 2018, and incorporated herein by reference).10.18*Amendment to the Storage, Throughput and Handling Agreement, effective January 1, 2019, by and between BKEP Materials, L.L.C., BKEPAsphalt, L.L.C., and Ergon Asphalt & Emulsions, Inc.10.19*Amendment to the Storage, Throughput and Handling Agreement, effective March 7, 2019, by and between BKEP Materials, L.L.C., BKEPAsphalt, L.L.C., and Ergon Asphalt & Emulsions, Inc.10.20#Amended and Restated Omnibus Agreement, dated July 12, 2018, by and between Ergon Asphalt & Emulsions, Inc., Blueknight Energy PartnersG.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 asExhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed July 13, 2018, and incorporated herein by reference).10.21#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).10.22#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).10.23Second 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).10.24Agreement, dated May 9, 2018, by and between Ergon Terminalling, Inc. and Blueknight Energy Partners, L.P. (filed as Exhibit 10.1 to thePartnership’s Current Report on Form 8-K, filed May 18, 2018, and incorporated herein by reference).10.25Domestic Crude Oil and Condensate Agreement, dated March 28, 2018, by and between Ergon Oil Purchasing, Inc. and BKEP Supply andMarketing, LLC (filed as Exhibit 10.3 to the Partnership’s Quarterly Report on Form 10-Q, filed August 2, 2018, and incorporated herein byreference).84Table of Contents10.26Partial 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 (filed as Exhibit 10.26 to the Partnership’s Annual Report on Form 10-K, filed March 8, 2018,and incorporated herein by reference).10.27Fifth 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 (filed as Exhibit 10.27 to the Partnership’s Annual Report on Form 10-K, filed March 8, 2018, and incorporatedherein by reference).10.28*Lessee Operated Facilities Lease Agreement, dated January 1, 2019, by and between BKEP Materials, L.L.C., BKEP Asphalt, L.L.C., and ErgonAsphalt & Emulsions, Inc.10.29*Owner Operated Storage, Throughput and Handling Agreement, dated January 1, 2019, by and between BKEP Materials, L.L.C., BKEP Asphalt,L.L.C., and Ergon 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 Accounting Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.32.1*Certification of Chief Executive Officer and Chief Accounting Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 ofthe Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”101**The following financial information from Blueknight Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2018,formatted in XBRL (eXtensible Business Reporting Language): (i) Document and Entity Information; (ii) Consolidated Balance Sheets as ofDecember 31, 2017 and 2018; (iii) Consolidated Statements of Operations for the years ended December 31, 2016, 2017 and 2018; (iv)Consolidated Statement of Changes in Partners’ Capital for the years ended December 31, 2016, 2017 and 2018; (v) Consolidated Statements ofCash Flows for the years ended December 31, 2016, 2017 and 2018; 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.85Table 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 12, 2019 By: /s/ James R. Griffin James R. Griffin Chief Accounting Officer and Authorized Signatory 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 12, 2019 . Signature Title /s/ Mark A. HurleyChief Executive Officer and Director(Principal Executive Officer)Mark A. Hurley /s/ James R. GriffinChief Accounting Officer(Principal Financial Officer and 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/ Joel D. PastorekDirectorJoel D. Pastorek /s/ Robert H. LamptonDirectorRobert H. Lampton /s/ William W. LamptonDirectorWilliam W. Lampton 86Table of ContentsItem 16. Form 10-K Summary.None.87Table 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, 2017 and 2018F-3Consolidated Statements of Operations for the Years Ended December 31, 2016, 2017 and 2018F-4Consolidated Statement of Changes in Partners’ Capital (Deficit) for the Years Ended December 31, 2016, 2017 and2018F-5Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2017 and 2018F-6Notes to the Consolidated Financial StatementsF-888Table of ContentsReport of Independent Registered Public Accounting FirmTo the Board of Directors of Blueknight Energy Partners G.P., L.L.C. as 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 (the “Partnership”) as of December 31,2018 and 2017, and the related consolidated statements of operations, changes in partners’ capital, and cash flows for each of the three years in the period endedDecember 31, 2018, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Partnership's internalcontrol over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committeeof Sponsoring 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 in conformitywith accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effectiveinternal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by theCOSO.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 on Internal Control Over Financial Reportingappearing under Item 9A. Our responsibility is to express opinions on the Partnership’s consolidated financial statements and on the Partnership's internal controlover financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States)(PCAOB) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules andregulations of the Securities and Exchange Commission and 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 ReportingA 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.F-1Table of Contents/s/ PricewaterhouseCoopers LLPTulsa, OklahomaMarch 12, 2019We have served as the Partnership’s auditor since 2007. F-2Table of ContentsBLUEKNIGHT ENERGY PARTNERS, L.P.CONSOLIDATED BALANCE SHEETS(in thousands, except per unit data) As of December 31, 2017 2018ASSETS Current assets: Cash and cash equivalents$2,469 $1,455Accounts receivable, net of allowance for doubtful accounts of $28 and $26 at December 31, 2017and 2018, respectively7,589 35,683Receivables from related parties, net of allowance for doubtful accounts of $0 at both dates3,070 1,043Prepaid insurance2,009 1,860Other current assets8,438 7,485Total current assets23,575 47,526Property, plant and equipment, net of accumulated depreciation of $316,591 and $263,554 atDecember 31, 2017 and 2018, respectively296,069 248,261Goodwill3,870 6,728Debt issuance costs, net4,442 3,349Intangibles and other assets, net12,913 17,440Total assets$340,869 $323,304LIABILITIES AND PARTNERS’ CAPITAL Current liabilities: Accounts payable$4,439 $3,707Accounts payable to related parties2,268 2,263Accrued crude oil purchases1,115 13,949Accrued crude oil purchases to related parties— 10,219Accrued interest payable694 465Accrued property taxes payable2,432 3,089Unearned revenue2,393 3,206Unearned revenue with related parties551 4,835Accrued payroll6,119 3,667Other current liabilities3,632 3,465Total current liabilities23,643 48,865Long-term unearned revenue with related parties1,052 1,714Other long-term liabilities3,673 4,010Long-term interest rate swap liabilities225 —Contingent liability with related party (Note 14)— 10,019Long-term debt307,592 265,592Commitments and contingencies (Note 18) Partners’ capital: Common unitholders (40,158,342 and 40,424,372 units issued and outstanding at December 31,2017 and 2018, respectively)454,358 370,972Preferred Units (35,125,202 units issued and outstanding at both dates)253,923 253,923General partner interest (1.6% interest with 1,225,409 general partner units outstanding at bothdates)(703,597) (631,791)Total partners’ capital4,684 (6,896)Total liabilities and partners’ capital$340,869 $323,304The accompanying notes are an integral part of these consolidated financial statements.F-3Table of ContentsBLUEKNIGHT ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OF OPERATIONS(in thousands, except per unit data) Year ended December 31, 2016 2017 2018Service revenue: Third-party revenue$126,215 $113,772 $58,756Related-party revenue30,211 56,688 22,131Lease revenue: Third-party revenue— — 42,067Related-party revenue— — 25,961Product sales revenue: Third-party revenue20,968 11,479 235,438Related-party revenue— — 482Total revenue177,394 181,939 384,835Costs and expenses: Operating expense111,091 123,805 113,890Cost of product sales14,130 8,807 126,776Cost of product sales from related party— — 102,469General and administrative expense20,029 17,112 15,995Asset impairment expense25,761 2,400 53,068Total costs and expenses171,011 152,124 412,198Gain (loss) on sale of assets108 (975) 149Operating income (loss)6,491 28,840 (27,214)Other income (expenses): Equity earnings in unconsolidated affiliate1,483 61 —Gain on sale of unconsolidated affiliate— 5,337 2,225Interest expense(12,554) (14,027) (16,860)Income (loss) before income taxes(4,580) 20,211 (41,849)Provision for income taxes260 166 198Net income (loss)$(4,840) $20,045 $(42,047) Allocation of net income (loss) for calculation of earnings per unit: General partner interest in net income (loss)$433 $944 $(512)Preferred interest in net income$25,824 $25,115 $25,115Net loss available to limited partners$(31,097) $(6,014) $(66,650) Basic and diluted net loss per common unit$(0.87) $(0.15) $(1.61) Weighted average common units outstanding - basic and diluted35,093 38,342 40,348The accompanying notes are an integral part of these consolidated financial statements.F-4Table of ContentsBLUEKNIGHT ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL (DEFICIT)(in thousands) CommonUnitholders PreferredUnitholders General PartnerInterest Total Partners’CapitalBalance, 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 ofunderwriters’ discount and offering expenses of $1.5million20,931 — — 20,931Proceeds from sale of 71,807 common units pursuantto 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 common units5,000 — — 5,000Proceeds from issuance of 97,654 general partner units— — 680 680Consideration paid in excess of historical cost of assetsacquired 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 units pursuantto the Employee Unit Purchase Plan240 — — 240Value of 1,898,380 common units issued foracquisitions10,156 — — 10,156Consideration paid in excess of historical cost of assetsacquired from Ergon— — (3,725) (3,725)Balance, December 31, 2017$454,358 $253,923 $(703,597) $4,684Net income(66,818) 25,115 (344) (42,047)Equity-based incentive compensation1,811 — 34 1,845Distributions(18,587) (25,115) (1,034) (44,736)Capital contributions— — 183 183Capital contributions related to sale of terminal assetsto Ergon— — 72,967 72,967Proceeds from sale of 61,327 common units pursuantto the Employee Unit Purchase Plan208 — — 208Balance, December 31, 2018$370,972 $253,923 $(631,791) $(6,896)The accompanying notes are an integral part of this consolidated financial statement.F-5Table of ContentsBLUEKNIGHT ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OF CASH FLOWS(in thousands) Year ended December 31, 2016 2017 2018Cash flows from operating activities: Net income (loss)$(4,840) $20,045 $(42,047)Adjustments to reconcile net income (loss) to net cash provided by operating activities: Provision for uncollectible receivables from third parties15 (21) (2)Provision for uncollectible receivables from related parties(229) — —Depreciation and amortization30,820 31,139 29,359Intangible asset impairment charge— 1,107 189Amortization and write-off of debt issuance costs1,107 1,816 1,451Unrealized gain related to interest rate swaps(1,156) (1,790) (201)Fixed asset impairment charge25,761 1,293 42,860Other impairment charge recorded on a push-down basis (Note 14)— — 10,019Loss (gain) on sale of assets(108) 975 (149)Gain on sale of unconsolidated affiliate— (5,337) (2,225)Equity-based incentive compensation2,087 1,451 1,845Equity earnings in unconsolidated affiliate(1,483) (61) —Changes in assets and liabilities: Decrease (increase) in accounts receivable1,138 (24) (25,450)Decrease (increase) in receivables from related parties213 (1,210) 2,027Decrease in prepaid insurance3,008 2,507 2,085Decrease (increase) in other current assets237 (983) 1,314Decrease (increase) in other non-current assets(498) 84 442Increase (decrease) in accounts payable(237) 952 (592)Increase in payables to related parties1,053 749 342Increase in accrued oil purchases— — 13,949Increase in accrued oil purchases to related parties— — 10,219Increase (decrease) in accrued interest payable222 281 (229)Increase (decrease) in accrued property taxes(242) (72) 1,031Increase (decrease) in unearned revenue(1,568) 898 785Increase in unearned revenue from related parties187 580 5,714Decrease in accrued payroll(905) (239) (2,452)Increase (decrease) in other accrued liabilities(1,733) 354 (1,500)Net cash provided by operating activities52,849 54,494 48,784Cash flows from investing activities: Acquisition of assets from Ergon(122,572) — —Acquisitions(18,989) — (21,959)Capital expenditures(19,995) (18,715) (34,400)Proceeds from sale of assets1,993 9,297 5,051Proceeds from sale of terminal assets to Ergon— — 88,538Proceeds from sale of unconsolidated affiliate— 26,489 2,225Net cash provided by (used in) investing activities(159,563) 17,071 39,455Cash flows from financing activities: Payment on insurance premium financing agreement(3,425) (2,965) (2,399)Payment on capital leases— — (151)Debt issuance costs(956) (4,208) (358)Borrowings under credit agreement170,000 378,592 324,000Payments under credit agreement(91,000) (395,000) (366,000)Proceeds from issuance of common units, net of offering costs26,269 240 208Proceeds from issuance of Preferred Units144,672 — —Proceeds from issuance of general partner units680 — —Repurchase of Preferred Units(95,348) — —Capital contributions2,384 104 183Capital contributions related to profits interest923 — —Distributions(47,219) (49,163) (44,736)F-6Table of ContentsBLUEKNIGHT ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OF CASH FLOWS(in thousands) Year ended December 31, 2016 2017 2018Net cash provided by (used in) financing activities106,980 (72,400) (89,253)Net increase (decrease) in cash and cash equivalents266 (835) (1,014)Cash and cash equivalents at beginning of period3,038 3,304 2,469Cash and cash equivalents at end of period$3,304 $2,469 $1,455 Supplemental disclosure of non-cash financing and investing cash flow information: Assets acquired through non-cash equity issuance$— $10,156 $—Non-cash changes in property, plant and equipment$(1,825) $779 $(715)Non-cash change in assets and liabilities due to settlement items related to the sale ofterminal assets to Ergon$— $— $(1,308)Increase in accrued liabilities related to insurance premium financing agreement$3,189 $2,938 $2,184Cash paid for interest, net of amounts capitalized$12,404 $13,732 $16,088Cash paid for income taxes$282 $158 $133The accompanying notes are an integral part of these consolidated financial statements. F-7Table 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 services. On April 24, 2018, the Partnership sold the producer field services business. As aresult of the sale of the producer field services business, the Partnership changed the name of the crude oil trucking and producer field services operating segmentto crude oil trucking services during the second quarter of 2018. See Note 8 for additional information. 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, 2017 and 2018 , and the consolidated results of the Partnership’s operations, cash flows and changes in partners’ capital for the years endedDecember 31, 2016 , 2017 and 2018 . 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. F-8Table of ContentsACCOUNTS RECEIVABLE - The majority of the Partnership’s accounts receivable relates to its crude oil pipeline services segment, specifically the crudeoil marketing business. Accounts receivable included in the consolidated balance sheets are reflected net of the allowance for doubtful accounts of less than $0.1million at both December 31, 2017 and 2018 . 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 18 ). 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, 2018 , the Partnership recognized fixed asset impairment expenses of approximately $40.7 million related to a markdownof our pipeline system to estimated fair value, $1.7 million related to the market value of its pipeline linefill assets and $0.4 million related to the value of obsoletetrucking stations in Oklahoma and Colorado. In addition, the Partnership recognized a $10.0 million impairment on a push-down basis related to Ergon’sinvestment in Cimarron Pipeline. See Note 14 for more information.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.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 .Acquired customer relationships are capitalized and amortized over useful lives ranging from 5 to 20 years using the straight-line method of amortization. Animpairment loss is recognized for definite-lived intangibles if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fairvalue. No impairment charges were recognized during the year ended December 31, 2016 , with respect to intangible assets. During the year ended December 31,2017 , the Partnership recognized intangible asset impairment charges of $0.2 million on customer relationships related to the former producer field servicesbusiness, primarily operated in the Texas panhandle. During the year ended December 31, 2018 , the Partnership recognized intangible asset impairment charges of$0.2 million related to a customer contract asset in the crude oilF-9Table of Contentspipeline services business. Intangible asset impairment charges are included in the line item “Asset impairment expense” on the consolidated statements ofoperations. 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. and Noble Midstream Partners LP. The Partnership’s share of net income or loss is reflected as one line item on the Partnership’s consolidatedstatements of operations entitled “Equity earnings in unconsolidated affiliate” and increased or decreased, as applicable, the carrying value of the Partnership’sinvestment in the unconsolidated affiliate on the consolidated balance sheets. Distributions to the Partnership reduced the carrying value of its investment and arereflected in the Partnership’s consolidated statements of cash flows in the line item “Distributions from unconsolidated affiliate.” In turn, contributions increasedthe carrying value of the Partnership’s investment and were reflected in the Partnership’s consolidated statements of cash flows in investing activities. See Note 6for additional information.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.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 services. If the fair value of a reporting unit exceeds its carryingamount, goodwill of the reporting unit is not considered to be impaired. The impairment test is generally based on the estimated discounted future net cash flows ofthe respective reporting unit, utilizing discount rates and other factors in determining the fair value of the reporting unit. Inputs in the Partnership’s estimateddiscounted future net cash flows include existing and estimated future asset utilization, estimated growth rates in future cash flows and estimated 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): AsphaltTerminallingServices Crude Oil TruckingServices TotalBalance, 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 $— $3,870Acquisition2,858 — 2,858Balance, December 31, 2018$6,728 $— $6,728During the fourth quarter of 2017, impairment testing indicated that the fair value of the crude oil trucking services reporting unit was less than the carryingvalue based on the estimated market value of the crude oil trucking services business, and the Partnership recognized impairment of goodwill of $0.9 millionrelated to this reporting unit. Impairment testing indicated there was no impairment of goodwill in 2016 or in 2018. 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 loss contingencies related to environmental matters of $0.1 million and $0.2 million as of December 31, 2017and 2018 , respectively. REVENUE RECOGNITION - On January 1, 2018, the Partnership adopted the new accounting standard ASC 606 - Revenue from Contracts with Customersand all related amendments (“new revenue standard”) using the modified retrospectiveF-10Table of Contentsmethod, and as a result applied the new guidance only to contracts that are not completed at the adoption date. Results for reporting periods beginning on January1, 2018, are presented under the new revenue standard, while prior period amounts are not adjusted and continue to be reported in accordance with thePartnership’s historic accounting under ASC 605 - Revenue Recognition . See Note 4 for detailed discussion regarding the Partnership’s revenue recognitionpolicies. 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 the year ended 2016 , and $0.2 million for each of the years endedDecember 31, 2017 and 2018 . This liability is reflected on the Partnership’s consolidated statements of operations as “Provision for income taxes.” See Note 22for 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, 2018 , 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. 4 . REVENUEOn January 1, 2018, the Partnership adopted the new accounting standard ASC 606 - Revenue from Contracts with Customers and all related amendments(“new revenue standard”) using the modified retrospective method, and as a result applied the new guidance only to contracts that are not completed at theadoption date. Results for reporting periods beginning on January 1, 2018, are presented under the new revenue standard, while prior period amounts are notadjusted and continue to be reported in accordance with the Partnership’s historic accounting under ASC 605 - Revenue Recognition .The majority of the Partnership’s service revenue continues to be recognized as services are performed. Under the new revenue standard, the timing of revenuerecognition on variable throughput fees changed, within a single reporting year, compared to the previous recognition. The effect is straight-line recognition ofunconstrained estimated annual throughput volumes over each contract year. See further discussion on variable throughput fees below. In addition, as a result ofthe adoption of the new revenue standard, revenue from leases is required to be presented separately from revenue from customers. As the Partnership applied themodified retrospective method, prior periods have not been reclassified.Upon adoption of the new revenue standard, there was no cumulative adjustment to the balance sheet at January 1, 2018. The adoption of the new revenuestandard resulted in a shift in revenue recognition between quarters within a fiscal year; therefore, there is no net effect on the consolidated statements ofoperations or consolidated balance sheet as of December 31, 2018 , compared to what would have been recorded under ASC 605. The impact of adoption of thenew revenue standard is notF-11Table of Contentsexpected to be material to net income on an ongoing basis because the analysis of contracts under the new revenue standard supports the recognition of revenue asservices are performed, which is consistent with the previous revenue recognition model.There are two types of contracts in the asphalt terminalling segment: (i) operating lease contracts, under which customers operate the facilities, and (ii)storage, throughput and handling contracts, under which the Partnership operates the facilities. The operating lease contracts are accounted for in accordance withASC 840 - Leases . The storage, throughput and handling contracts contain both lease revenue and non-lease service revenue. In accordance with ASC 840 and606, fixed consideration is allocated to the lease and service components based on their relative stand-alone selling price. The stand-alone selling price of the leasecomponent is calculated using the average internal rate of return under the operating lease agreements. The stand-alone selling price of the service component iscalculated by applying an appropriate margin to the expected costs to operate the facility. The service component contains a single performance obligation thatconsists of a stand-ready obligation to perform activities as directed by the customer, and revenue is recognized on a straight-line basis over time as the customerreceives and consumes benefits. The lease component is recognized on a straight-line basis over the term of the initial lease. Fixed consideration, consisting of themonthly storage and handling fees, is billed a month prior to the performance of services and is due by the first day of the month of service. Payments received inadvance of the month of service are recorded as unearned revenue until the service is performed, and the service component is treated as a contract liability.Asphalt storage, throughput and handling contracts also contain variable consideration in the form of reimbursements of utility, fuel and power expenses andthroughput fees. Asphalt operating lease contracts also contain variable consideration in the form of throughput fees. Utility, fuel and power reimbursements areallocated entirely to the service component of the storage, throughput and handling contracts. Utility, fuel and power reimbursements relate directly to the distinctmonthly service that makes up the overall performance obligation and revenue is recognized in the period in which the service takes place. Variable considerationrelated to reimbursements of utility, fuel and power expenses is billed in the month subsequent to the period of service, and payment is due within 30 days ofbilling. Throughput fees are allocated to both the lease and service component of the storage, throughput and handling contracts using the allocation percentagesfrom contract inception as described above. Total throughput fees are estimated at contract inception and updated at the beginning of each reporting period basedon historical trends, current year throughput activities at the facilities, and analysis with customers regarding expectations for the current year. This considerationcan be constrained when there is a lack of historical data or other uncertainties exist regarding expected throughput volumes. The service component of throughputfees is recognized on a straight-line basis over time as the customer receives and consumes benefits. In accordance with ASC 840, the lease component of variablethroughput fees for both types of contracts is recognized in the period when the changes in facts and circumstances on which the variable payment is based occur.Fees related to actual throughput are billed in the month subsequent to the period of movement, which can result in the recognition of un-billed accounts receivable(contract assets) when there is a variance in the straight-line service revenue recognition and actual throughput fees billed. Payment on variable throughputconsideration is due within 30 days of billing. Changes in estimated throughput fees affect the total transaction price for the service component of storage,throughput and handling contracts and will be recorded as an adjustment to revenue in the period in which the change in estimate occurs. As of December 31,2018, all throughput fees are realized.Certain asphalt storage, throughput and handling contracts contain provisions for reimbursement of specified major maintenance costs above a specifiedthreshold over the life of the contract. Reimbursements of specified major maintenance costs are allocated to both the lease and service component of the contractsusing the allocation percentages from contract inception as described above. Reimbursements of specified major maintenance costs are reviewed and paidquarterly, which may result in overpayments that must be paid back to the customer in future years. As such, the service component of this consideration isconstrained and recorded in unearned revenue (contract liability) until facts and circumstances indicate it is probable that the minimum threshold will be met, atwhich point it is treated as a change in estimate with a prior period catch-up and the remainder to be recognized over the remaining contract term. The leasecomponent is recognized in the period in which the facts and circumstances indicate the variable revenue is assured. In the event the minimum threshold is not met,the Partnership will return the reimbursement to the customer.As of December 31, 2018 , the Partnership has service revenue performance obligations satisfied over time under asphalt storage, throughput and handlingcontracts that are wholly or partially unsatisfied. The service revenue related to these performance obligations will be recognized as follows (in thousands):F-12Table of ContentsRevenue Related to Future Performance Obligations Due by Period (1) 2019 $28,4252020 27,2962021 24,1542022 16,8532023 11,444Thereafter 9,142Total revenue related to future performance obligations $117,314____________________(1)Excluded from the table is revenue that is either constrained or related to performance obligations that are wholly unsatisfied as of December 31, 2018 .In addition, as of December 31, 2018 , the Partnership has minimum future annual lease rentals contracted to be received under asphalt operating leasecontracts and asphalt storage, throughput and handling contracts. The lease revenue related to these minimum rentals will be recognized as follows (in thousands):Year ended December 31, 2019 $47,7322020 42,8902021 38,8732022 28,1902023 19,248Thereafter 22,342Total revenue related to minimum future annual lease rentals $199,275The Partnership recognized variable lease consideration of $4.4 million for each of the years ended ended December 31, 2016 and 2017, and $5.1 million forthe year ended December 31, 2018, under operating lease agreements. Crude oil terminalling services contracts can be either short- or long-term written contracts. The contracts contain a single performance obligation that consistsof a series of distinct services provided over time. Customers are billed a month prior to the performance of terminalling services and payment is due by the firstday of the month of service. Payments received in advance of the month of service are recorded as unearned revenue (contract liability) until the service isperformed. These contracts also contain provisions under which customers are invoiced for product throughput in the month following the month in which theservice is provided. Payment on product throughput is due within 30 days . The Partnership has elected to use the right-to-invoice expedient on crude oilterminalling services contracts as the right to consideration corresponds directly with the value to the customer of performance completed to date.There are primarily two types of contracts in the crude oil pipeline segment: (i) monthly transportation contracts and (ii) product sales contracts.Under crude oil pipeline services monthly transportation contracts, customers submit nominations for transportation monthly and a contract is created upon thePartnership’s acceptance of the nomination under its published tariffs. Crude oil pipeline services contracts have a single performance obligation to perform thetransportation service. The transportation service is provided to the customer in the same month in which the customer makes the related nomination. Revenue isrecorded in the month of service and invoiced in the following month. Payment is due within 30 days . The Partnership has elected to use the right-to-invoiceexpedient on crude oil pipeline services contracts as the right to consideration corresponds directly with the value to the customer of performance completed todate.The Partnership also purchases crude oil and resells to third parties under written product sales contracts. Product sales contracts have a single performanceobligation, and revenue is recognized at the point in time that control is transferred to the customer. Control is considered transferred to the customer on the day ofthe sale. Revenue is recorded in the month of service and invoiced in the following month. Payment is due within 30 days . The Partnership has elected to use theright-to-invoice expedient on product sales contracts as the right to consideration corresponds directly with the value to the customer of performance completed todate.Services in the crude oil trucking segment are provided under master service agreements with customers that include rate sheets. Contracts are initiated when acustomer requests service and both parties are committed upon the Partnership’sF-13Table of Contentsacceptance of the customer’s request. Crude oil trucking contracts have a single performance obligation to perform the service, which is completed in a day.Revenue is recorded in the month of service and invoiced in the following month. Payment is due within 30 days . The Partnership has elected to use the right-to-invoice expedient on crude oil trucking revenues as the right to consideration corresponds directly with the value to the customer of performance completed todate.Disaggregation of RevenueDisaggregation of revenue from contracts with customers for each operating segment by revenue type is presented as follows (in thousands): Year ended December 31, 2018 Asphalt TerminallingServices Crude OilTerminallingServices Crude OilPipelineServices Crude OilTruckingServices TotalThird-party revenue: Fixed storage, throughput and other revenue $18,100 $10,966 $— $— $29,066Variable throughput revenue 918 962 — — 1,880Variable reimbursement revenue 7,090 — — — 7,090Crude oil transportation revenue — — 6,396 14,324 20,720Crude oil product sales revenue — — 235,428 10 235,438Related-party revenue: Fixed storage, throughput and other revenue 15,352 — 215 — 15,567Variable throughput revenue 762 — — — 762Variable reimbursement revenue 5,572 — 230 — 5,802Product sales revenue 482 — — — 482Total revenue from contracts with customers $48,276 $11,928 $242,269 $14,334 $316,807Contract BalancesThe timing of revenue recognition, billings and cash collections result in billed accounts receivable, un-billed accounts receivable (contract assets) andunearned revenue (contract liabilities) on the consolidated balance sheet as noted in the contract discussions above. Accounts receivable and un-billed accountsreceivable are both reflected in the line items “Accounts receivable” and “Receivables from related parties” on the consolidated balance sheet. Unearned revenue isincluded in the line items “Unearned revenue,” “Unearned revenue with related parties,” “Long-term unearned revenue with related parties” and “Other long-termliabilities” on the consolidated balance sheet.Billed accounts receivable from contracts with customers were $8.5 million and $34.6 million at December 31, 2017 and 2018 , respectively. There were noun-billed accounts receivable at December 31, 2017 or 2018 .The Partnership records unearned revenues when cash payments are received in advance of performance. Unearned revenue related to contracts withcustomers was $3.7 million and $5.9 million at December 31, 2017 and 2018 , respectively. The change in the unearned revenue balance for the year endedDecember 31, 2018 , is driven by $4.0 million in cash payments received in advance of satisfying performance obligations, partially offset by $1.8 million ofrevenues recognized that were included in the unearned revenue balance at the beginning of the period.Practical Expedients and ExemptionsThe Partnership does not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less and (ii)contracts for which revenue is recognized at the amount to which the Partnership has the right to invoice for services performed. The Partnership is using the right-to-invoice practical expedient on all contracts with customers in its crude oil terminalling services, crude oil pipeline services and crude oil trucking servicessegments.5 . ACQUISITIONSOn March 7, 2018, the Partnership acquired an asphalt terminalling facility located in Oklahoma from a third party for $22.0 million .F-14Table of ContentsOn 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 .6 . 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 2017and approximately $2.2 million for its pro rata portion of the remaining net escrow proceeds in January 2018. The Partnership’s proceeds were used to repayrevolving debt under its credit facility. The operating and administrative services agreement to which the Partnership and Advantage Pipeline were parties andunder which the Partnership operated the 70-mile, 16-inch Advantage crude oil pipeline, located in the southern Delaware Basin in Texas, was terminated atclosing. The Partnership and the Plains/Noble joint venture entered into a short-term transition services agreement under which the Partnership provided certainservices through August 1, 2017.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): Period endedApril 3, 2017Income Statement Operating revenues$3,150Operating expenses$465Net income$1877 . RESTRUCTURING CHARGESDuring the fourth quarter of 2015, the Partnership recognized certain restructuring charges in its crude oil trucking services segment pursuant to an approvedplan to exit the trucking market in West Texas. The restructuring charges included an accrual related to leased vehicles that were idled as part of the restructuringplan. This accrual was being amortized over the remaining lease term of the vehicles. In June 2018, the Partnership purchased the vehicles off lease and resoldthem to a third party, paying off the remaining liability.F-15Table of ContentsChanges in the accrued amounts pertaining to the restructuring plan are summarized as follows: Year ended December 31, 2016 2017 2018 (in thousands)Beginning balance$1,565 $474 $286Cash payments1,091 188 286Ending balance$474 $286 $—8 . PROPERTY, PLANT AND EQUIPMENT Estimated UsefulLives (Years) As of December 31, 2017 2018 (dollars in thousands)LandN/A $24,776 $24,705Land improvements10-20 6,787 5,758Pipelines and facilities5-30 166,004 116,155Storage and terminal facilities10-35 370,056 321,096Transportation equipment3-10 3,293 2,798Office property and equipment and other3-20 32,011 26,980Pipeline linefill and tank bottomsN/A 3,233 10,297Construction-in-progressN/A 6,500 4,026Property, plant and equipment, gross 612,660 511,815Accumulated depreciation (316,591) (263,554)Property, plant and equipment, net $296,069 $248,261 Plant, property and equipment under operating leases at December 31, 2018 , in which the Partnership is the lessor, had a cost basis of $280.3 million andaccumulated depreciation of $170.2 million .Depreciation expense for the years ended December 31, 2016 , 2017 and 2018 was $29.6 million , $29.9 million and $26.9 million , respectively.During the year ended December 31, 2016 , the Partnership recorded fixed asset impairment expense of $25.8 million , primarily due to an impairmentrecognized on the Knight Warrior pipeline project and the East Texas pipeline system. During the year ended December 31, 2017 , the Partnership recorded fixedasset impairment expense of $1.2 million related to the crude oil trucking reporting unit. During the year ended December 31, 2018 , the Partnership recognizedfixed asset impairment expenses of approximately $40.7 million related to a markdown of our pipeline system to estimated fair value, $1.7 million related to themarket value of its pipeline linefill assets and $0.4 million related to the value of obsolete trucking stations in Oklahoma and Colorado. In addition, the Partnershiprecognized a $10.0 million impairment on a push-down basis related to Ergon’s investment in Cimarron Pipeline. See Note 14 for more information.On July 12, 2018, the Partnership sold certain asphalt terminals, storage tanks and related real property, contracts, permits, assets and other interests located inLubbock and Saginaw, Texas and Memphis, Tennessee (the “Divestiture”) to Ergon Asphalt & Emulsion, Inc. for a purchase price of $90.0 million , subject tocustomary adjustments. The Divestiture does not qualify as discontinued operations as it does not represent a strategic shift that will have a major effect on thePartnership’s operations or financial results. The Partnership used the proceeds received at closing to prepay revolving debt under its credit agreement.In April 2018, the Partnership sold its producer field services business. The Partnership received cash proceeds at closing of approximately $3.0 million andrecorded a gain of $0.4 million . The Partnership used the proceeds received at closing to repay revolving debt under its credit facility. The sale of the producerfield services business does not qualify as discontinued operations as it does not represent a strategic shift that will have a major effect on the Partnership’soperations or financial results.F-16Table of ContentsIn April 2017, the Partnership sold its East Texas pipeline system. The Partnership received cash proceeds at closing of approximately $4.8 million andrecorded a gain of less than $0.1 million . The Partnership used the proceeds received at closing to repay revolving debt under its credit facility. The sale of theEast Texas pipeline business does not qualify as discontinued operations as it does not represent a strategic shift that will have a major effect on the Partnership’soperations or financial results.9. INTANGIBLES AND OTHER ASSETS, NETIntangibles and other assets, net of accumulated amortization, consist of the following: As of December 31, 2017 2018 (in thousands)Customer relationships$12,221 $19,214Deferred charges related to pipeline connection agreements2,716 2,716Deposits302 283Prepaid insurance353 248Other prepaid expenses103 75Intangibles and other assets, gross15,695 22,536Accumulated amortization of intangible assets(2,782) (5,096)Intangibles and other assets, net$12,913 $17,440 Amortization expense related to intangibles for the years ended December 31, 2016 , 2017 and 2018 was $1.2 million , $1.3 million and $2.5 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, 2019$2,746December 31, 20202,746December 31, 20212,746December 31, 20222,746December 31, 20231,321Thereafter4,529Total estimated aggregate amortization expense$16,834 Customer relationships include $7.6 million and $8.4 million related to the acquisition of asphalt facilities in March 2018 and February 2016, respectively, and$3.2 million related to the acquisition of a pipeline and crude oil marketing business in November 2015. The customer relationships are being amortized over arange of 5 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. During the year ended December 31 2018 , the Partnership recognized intangibleasset impairment charges of $0.2 million related to a customer contract asset in crude oil pipeline services business. 10. DEBTOn May 11, 2017, the Partnership entered into an amended and restated credit agreement. On June 28, 2018, the credit agreement was amended to, amongother things, reduce the revolving loan facility from $450.0 million to $400.0 million and amend the maximum permitted consolidated total leverage ratio asdiscussed below.As of March 11, 2019 , approximately $253.6 million of revolver borrowings and $1.2 million of letters of credit were outstanding under the credit agreement,leaving the Partnership with available capacity of approximately $145.2 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.F-17Table of ContentsThe 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 3.25% 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 2.25% . The Partnership pays a perannum fee on all letters of credit issued under the credit agreement, which fee equals the applicable margin for loans accruing interest based on the eurodollar rate,and the Partnership pays a commitment fee ranging from 0.375% to 0.5% on the unused commitments under the credit agreement. The 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 will be 5.50 to 1.00 for thefiscal quarter December 31, 2018; 5.25 to 1.00 for the fiscal quarters ending March 31, 2019, and June 30, 2019; 5.00 to 1.00 for the fiscal quarters endingSeptember 30, 2019, and December 31, 2019; and 4.75 to 1.00 for the fiscal quarter ending March 31, 2020, and each fiscal quarter thereafter; provided that themaximum permitted consolidated total leverage ratio may be increased to 5.25 to 1.00 for certain quarters after December 31, 2019, based on the occurrence of aspecified acquisition (as defined in the credit agreement, but generally being an acquisition for which the aggregate consideration is $15.0 million or more).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.In addition, the credit agreement contains various covenants that, among other restrictions, limit the Partnership’s ability to:•create, issue, incur or assume indebtedness;•create, incur or assume liens;•engage in mergers or acquisitions;F-18Table of Contents•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, 2018 , the Partnership’s consolidated total leverage ratio was 5.09 to 1.00 and the consolidated interest coverage ratio was 3.34 to 1.00. ThePartnership was in compliance with all covenants of its credit agreement as of December 31, 2018 .Management evaluates whether conditions and/or events raise substantial doubt about the Partnership’s ability to continue as a going concern within one yearafter the date that the consolidated financial statements are issued (the “assessment period”). In performing this assessment, management considered the riskassociated with its ongoing ability to meet the financial covenants.Based on the Partnership’s forecasted EBITDA during the assessment period, management believes that it will meet these financial covenants (as describedbelow). However, there are certain inherent risks associated with our continued ability to comply with our consolidated total leverage ratio covenant. These risksrelate, among other things, to potential future (a) decreases in storage volumes and rates as well as throughput and transportation rates realized; (b) weatherphenomenon that may potentially hinder the Partnership’s asphalt business activity; and (c) other items affecting forecasted levels of expenditures and uses of cashresources. Violation of the consolidated total leverage ratio covenant would be an event of default under the credit agreement, which would cause our $265.6million in outstanding debt, as of December 31, 2018, to become immediately due and payable. If this were to occur, the Partnership would not expect to havesufficient liquidity to repay these outstanding amounts then due, which could cause the lenders under the credit facility to pursue other remedies. Such remediescould include exercising their collateral rights to the Partnership’s assets.In response to the risks described above, management undertook a plan to seek, and ultimately obtained, support from Ergon, the owner of the Partnership’sgeneral partner interest, in the form of a $15.0 million prepayment for certain asphalt lease commitments through September 2019. The Partnership received thesefunds on March 8, 2019 , and, as of March 12, 2019, paid $14.0 million to reduce outstanding borrowings under the credit agreement, thus providing increasedflexibility under the consolidated total leverage ratio covenant. Given this added flexibility, and based on management’s current forecasts, management believesthe Partnership will be able to comply with the consolidated total leverage ratio during the assessment period. However, the Partnership cannot make anyassurances that it will be able to achieve management’s forecasts. If the Partnership is unable to achieve management’s forecasts, further actions may be necessaryto remain in compliance with the Partnership’s consolidated total leverage ratio covenant including, but not limited to, cost reductions, common and preferredunitholder distribution curtailments, and/or asset sales. The Partnership can make no assurances that it would be successful in undertaking these actions, or that,the Partnership will remain in compliance with the consolidated total leverage ratio during the assessment period.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, provided,however, in no event shall aggregate quarterly distributions in any individual fiscal quarter exceed $10.7 million through, and including, the fiscal quarter endingDecember 31, 2019. The Partnership is currently allowed to make distributions to its unitholders in accordance with this covenant; however, the Partnership willonly make distributions to the extent it has sufficient cash from operations after establishment of cash reserves as determined by the Board of Directors (the“Board”) of Blueknight Energy Partners G.P., L.L.C (the “general partner”) in accordance with the Partnership’s cash distribution policy, including theestablishment of any reserves for the proper conduct of the Partnership’s business. See Note 12 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; orF-19Table of Contents(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 asmembers of the Board approved by Ergon will not cause an event of default.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 in May 2017, the Partnership expensed $0.7 million of debt issuance costs related to theprior revolving loan facility, leaving a remaining balance of $0.9 million ascribed to those lenders with commitments under both the prior and the amended andrestated credit agreement. Additionally, due to the reduction in available borrowing capacity, the Partnership expensed $0.4 million of debt issuance costs upon theexecution of the first amendment to its credit agreement in June 2018. During the years ended December 31, 2016 , 2017 and 2018 , the Partnership capitalizeddebt issuance costs related to its credit agreement of $1.0 million , $4.2 million and $0.4 million , respectively. The debt issuance costs are being amortized overthe term of the credit agreement. Interest expense related to debt issuance cost amortization for each of the years ended December 31, 2016 and 2017 , was $1.1million . Interest expense related to debt issuance cost amortization for the year ended December 31, 2018 was $1.0 million . During the years ended December 31, 2016 , 2017 and 2018 , the weighted average interest rate under the Partnership’s credit agreement, excluding the $0.7million and $0.4 million of debt issuance costs related to the prior credit agreement that were expensed as described above, was 3.95% , 4.43% and 5.49% ,respectively, resulting in interest expense of approximately $11.2 million , $13.8 million and $16.8 million , respectively.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, 2017 and 2018 , the Partnershiphad interest rate swaps with notional amounts totaling $200.0 million and $100.0 million , respectively, to hedge the variability of its LIBOR-based interestpayments. An interest rate swap agreement with a notional amount of $100.0 million expired on June 28, 2018. Interest rate swap agreements with notionalamounts totaling $100.0 million matured on January 28, 2019. During the years ended December 31, 2016 , and 2017 , the Partnership recorded swap interestexpense of $2.5 million and $1.3 million , respectively. During the year ended December 31, 2018 the Partnership recorded swap interest income of $0.1 million .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 Derivatives As of December 31, 2017 2018Interest rate swap assets - current Other current assets $68 $44Interest rate swap liabilities - noncurrent Long-term interest rate swap liabilities $225 $— Changes in the fair value of the interest rate swaps are reflected in the consolidated statements of operations as follows (in thousands):F-20Table of ContentsDerivatives Not Designated asHedging Instruments Location of Gain Recognized in NetIncome on Derivatives Amount of Gain Recognized in Net Income onDerivatives Year ended December 31, 2016 2017 2018Interest rate swaps Interest expense, net of capitalizedinterest $1,156 $1,790 $201 11. NET INCOME PER LIMITED PARTNER UNIT For purposes of calculating earnings per unit, the excess of distributions over earnings or excess of earnings over distributions for each period are allocated tothe Partnership’s general partner based on the general partner’s ownership interest at the time. The following sets forth the computation of basic and diluted netincome per common unit (in thousands, except per unit data): Year ended December 31, 2016 2017 2018Net income (loss)$(4,840) $20,045 $(42,047)General partner interest in net income (loss)433 944 (512)Preferred interest in net income25,824 25,115 25,115Net loss available to limited partners$(31,097) $(6,014) $(66,650) Basic and diluted weighted average number of units: Common units35,093 38,342 40,348Restricted and phantom units803 862 1,011Total units35,896 39,204 41,359 Basic and diluted net loss per common unit$(0.87) $(0.15) $(1.61)12 . 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 asphalt facility inBainbridge, Georgia. See additional detail in Note 5 .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; andF-21Table of Contents•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:•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 15 .The Partnership paid the following distributions on the Preferred Units during the years ended December 31, 2016 , 2017 and 2018 (in thousands):YearPaidPeriods CoveredTotal Paid toPreferredUnitholders Paid toGeneralPartner2016Quarters 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 $4202018Quarters ending December 31, 2017, March 31, 2018, June 30, 2018 andSeptember 30, 2018$25,523 $25,115 $408In addition, on January 25, 2019 , the Board approved a cash distribution of $0.17875 per outstanding Preferred Unit for the quarter ending December 31,2018 . The Partnership paid this distribution on the Preferred Units on February 14, 2019 , to unitholders of record as of February 4, 2019 . 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.F-22Table of ContentsThe Partnership paid the following distributions on the common units during the years ended December 31, 2016 , 2017 and 2018 (in thousands):YearPaidPeriods CoveredTotal Paid toCommonUnitholders Paid toGeneralPartner Paid to Phantomand RestrictedUnitholdersUnder the LTIP2016Quarters 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 $4882018Quarters ending December 31, 2017, March 31, 2018, June30, 2018 and September 30, 2018$19,213 $18,154 $626 $433In addition, on January 25, 2019 , the Board approved a cash distribution of $0.08 per outstanding common unit for the quarter ending December 31, 2018 .The distribution was paid on February 14, 2019 , to unitholders of record as of February 4, 2019 . The total distribution was approximately $3.4 million , withapproximately $3.3 million and $0.1 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.13. 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, 2016, Ergon accounted for approximately 13% of the Partnership’s total revenues, all of which were earned in asphaltterminalling services. One third-party customer accounted for approximately 13% of the Partnership’s total revenues, which were earned in all of the Partnership’soperating segments.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. One third-party customer accounted for approximately 12% of the Partnership’s total revenues, which were earned in all of the Partnership’soperating segments.For the year ended December 31, 2018, Ergon accounted for approximately 13% of the Partnership’s total revenues, which were earned in asphalt terminallingservices and crude oil pipeline services. One third-party customer accounted for approximately 10% of the Partnership’s total revenues, which were earned in all ofthe Partnership’s operating segments. In addition, two other third-party customers each accounted for 15% of the Partnership’s total revenues, which were allearned in the Partnership’s crude oil pipeline services.14 . 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, 2016 , the Partnershiprecognized revenues of $22.2 million for services provided to Ergon, of which $11.0 million is classified as related-party revenues. For the years ended December31, 2017 and 2018 , the Partnership recognized revenues of $56.4 million and $48.5 million , respectively, for services provided to Ergon, all of which is classifiedas related-party revenue. See additional discussion below regarding material asphalt operating lease contracts and storage, throughput and handling contracts. As ofDecember 31, 2017 and 2018 , the Partnership had receivables from Ergon of $3.1 million and $1.0 million , respectively. On March 8, 2019 , Ergon made a $15.0million prepayment of fees representing six months’ of future services under the Ergon Lessee Operated Facility Lease Agreements and Ergon Fontana and LasVegas Storage Throughput and Handling Agreement. The Partnership used the proceeds of this prepayment to prepay revolving debt under its credit agreement.The Partnership and Ergon have an agreement (the “Agreement”) that gives each party rights concerning the purchase or sale of Ergon’s interest in CimarronExpress Pipeline, LLC (“Cimarron Express”), subject to certain terms and conditions. The Agreement was filed as Exhibit 10.1 to the Partnership’s Current Reporton Form 8-K, filed May 14, 2018. Cimarron Express is planned to be a new 16-inch diameter, 65-mile crude oil pipeline running from northeastern KingfisherCounty, Oklahoma toF-23Table of Contentsthe Partnership’s Cushing, Oklahoma crude oil terminal, with an originally anticipated in-service date in the second half of 2019. Ergon has formed a Delawarelimited liability company, Ergon - Oklahoma Pipeline, LLC (“DEVCO”), which holds Ergon’s 50% membership interest in Cimarron Express. Under theAgreement, the Partnership has the right, at any time, to purchase 100% of the authorized and outstanding member interests in DEVCO from Ergon for thePurchase Price (as defined in the Agreement), which shall be computed by taking Ergon’s total investment in the Cimarron Express plus interest, by giving writtennotice to Ergon (the “Call”). Ergon has the right to require BKEP to purchase 100% of the authorized and outstanding member interests of DEVCO for thePurchase Price (the “Put”) at any time beginning the earlier of (i) 18 months from the formation, May 9, 2018, of the joint venture company to build the pipeline,(ii) six months after completion of the pipeline, or (iii) the event of dissolution of Cimarron Express. Upon exercise of the Call or the Put, Ergon and thePartnership will execute the Member Interest Purchase Agreement, which is attached to the Agreement as Exhibit B. Upon receipt of the Purchase Price, Ergonshall be obligated to convey 100% of the authorized and outstanding member interests in DEVCO to BKEP or its designee. There is not a separate amount ofconsideration for the Put or the Call exchanged between the parties. Therefore, based on applicable GAAP, no value was assigned to the combined instrument onthe Partnership's balance sheet upon the execution of the put/call instrument. As of December 31, 2018, neither Ergon nor the Partnership has exercised theiroptions under the Agreement.In December of 2018, the Partnership and Ergon became aware of circumstances adversely impacting the projected economic performance of CimarronExpress. The Partnership and Ergon have worked together to evaluate available information about Cimarron Express, and have determined that Cimarron Expressis likely no longer economically viable.As of December 31, 2018, Cimarron Express has spent approximately $30.6 million on the pipeline project, primarily related to the purchase of steel pipe andequipment, rights of way and engineering and design services, and has cash on hand of approximately $1.9 million . Cimarron Express recorded a $20.9 millionimpairment charge in the fourth quarter of 2018 to reduce the carrying amount of its assets to their estimated fair value. In addition to its capital contributions toCimarron Express, Ergon’s interest in DEVCO includes internal Ergon labor and capitalized interest that bring its investment in DEVCO to approximately $17.6million . Ergon recorded a $10.0 million other-than-temporary impairment on its investment in Cimarron Express as of December 31, 2018 to reduce its investmentto its estimated fair value. As a result, the Partnership considered the SEC staff’s opinions outlined in SAB 107 Topic 5.T. Accounting for Expenses or LiabilitiesPaid by Principal Stockholders. The Agreement was designed to have the Partnership, ultimately and from the onset, bear any risk of loss on the construction of thepipeline project and eventually own a 50% interest in the pipeline. As a result, the Partnership has recorded on a push down basis a $10.0 million impairment ofErgon’s investment in Cimarron Express in its consolidated results of operations during the year ended December 31, 2018, and a contingent liability payable toErgon as of December 31, 2018.Effective April 1, 2018, the Partnership entered into an agreement with Ergon under which the Partnership purchases crude oil in connection with its crude oilmarketing operations. For the year ended December 31, 2018 , the Partnership made purchases of crude oil under this agreement totaling $ 108.8 million . As ofDecember 31, 2018 , the Partnership had payables to Ergon related to this agreement of $ 10.2 million related to the December crude oil settlement cycle, and thisbalance was paid in full on January 22, 2019 .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, 2016 and 2017 , the Partnership recognizedrevenues of $1.3 million and $0.3 million , respectively, for services provided to Advantage Pipeline.The Partnership provides crude oil gathering, transportation and terminalling services to Vitol. For the year ended December 31, 2016 , the Partnershiprecognized related-party revenues of $17.9 million for services provided to Vitol.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 facilities. The term of this agreement commenced on January 1, 2017, and was to continuefor six years. In July 2018, the Partnership sold the Lubbock and Saginaw facilities to Ergon and this agreement was terminated. The Board’s conflicts committeereviewed and approved this agreement in accordance with the Partnership’s procedures for approval of related-party transactions and the provisions of thepartnership agreement. During the years ended December 31, 2017 and 2018 , the Partnership generated revenues under this agreement of $12.9 million and $6.7million , respectively, all of which is classified as related-party revenue.F-24Table of ContentsErgon 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 facilities. The term of the Ergon 2016 Storage, Throughput andHandling Agreement commenced on October 5, 2016, and continues for seven years. The Board’s conflicts committee reviewed and approved this agreement inaccordance with the Partnership’s procedures for approval of related-party transactions and the provisions of the partnership agreement. During the years endedDecember 31, 2016 , 2017 and 2018 , the Partnership generated revenue under this agreement of $6.2 million , $26.4 million and $24.8 million , respectively, all ofwhich is classified as related-party revenue.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 originalErgon Fontana and Las Vegas Master Facilities Lease Agreement commenced on May 18, 2009, and was a part of Ergon Master Facilities Lease and SubleaseAgreement. See Ergon Master Facilities Lease and Sublease Agreement for additional detail regarding prior terms and conditions. The term of the Ergon Fontanaand Las Vegas Storage Throughput and Handling Agreement commenced on October 5, 2016, and expired on December 31, 2018. A new agreement was executedin March 2019 with an effective date of January 1, 2019. This agreement has an initial term of five years. The Board’s conflicts committee reviewed and approvedthese agreements in accordance with the Partnership’s procedures for approval of related-party transactions and the provisions of the partnership agreement.During the years ended December 31, 2016 , 2017 and 2018 , the Partnership generated revenues under this agreement of $1.5 million , $6.2 million and $6.6million , 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 encompassed eight facilities through June 2018. In July 2018, the Partnership sold one of the facilities covered by this agreement and it was amended toremove that facility. This agreement expired on December 31, 2018, and a new agreement, the Lessee Operated Facility Lease Agreement, was executed in March2019. The new agreement encompasses 12 facilities, which includes facilities previously accounted for under this agreement and the Ergon Master FacilitiesSublease and Sublicense Agreement. The new agreement has an effective date of January 1, 2019, and an initial term of five years. The Board’s conflictscommittee reviewed and approved these agreements in accordance with the Partnership’s procedures for approval of related-party transactions and the provisionsof the partnership agreement. During the year ended December 31, 2016 , the Partnership generated revenues under this agreement of $9.2 million , of which $1.8million is classified as related-party revenue. During the years ended December 31, 2017 and 2018, the Partnership generated revenues under this agreement of$5.2 million and $5.3 million , respectively, 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 expired on December 31, 2018. This agreement expired on December 31, 2018,and a new agreement, the Lessee Operated Facility Lease Agreement, was executed in March 2019. The new agreement combined the facilities under thisagreement and the Ergon Master Facilities Lease and Sublease Agreement. The new agreement has an effective date of January 1, 2019, and an initial term of fiveyears. During the year ended December 31, 2016 , the Partnership generated revenues under this agreement of $3.6 million , of which $1.0 million is classified asrelated-party revenue. During the years ended December 31, 2017 and 2018, the Partnership generated revenues under this agreement of $3.7 million and $2.8million , all of which is classified as related-party revenue.Vitol Storage AgreementsIn recent years, a significant portion of the Partnership’s crude oil storage capacity has been dedicated to Vitol under multiple agreements. During the yearended December 31, 2016 , when Vitol was a related party, 2.2 million barrels of storage capacity were dedicated to Vitol under these storage agreements. Servicerevenues under these agreements are basedF-25Table of Contentson the barrels of storage capacity dedicated to Vitol under the applicable agreement at rates that, the Partnership believes, are fair and reasonable to thePartnership and its unitholders and are comparable with the rates the Partnership charges third parties. The Board’s conflicts committee reviewed and approvedthese agreements in accordance with the Partnership’s procedures for approval of related-party transactions and the provisions of the partnership agreement. Forthe year ended December 31, 2016, the Partnership generated revenues under these agreements of approximately $9.6 million , of which $7.5 million is classifiedas related-party revenue.15 . 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 201610,950 $6.85 $75December 201715,306 $4.85 $74December 201823,436 $1.20 $28In 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 $69December 201821,875 $1.20 $26The 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 2016416,131 $4.77 $1,985October 20169,960 $5.85 $58March 2017323,339 $7.15 $2,312March 2018396,536 $4.77 $1,891 F-26Table of ContentsThe unrecognized estimated compensation cost relating to outstanding phantom units at December 31, 2018 , was $1.9 million , which will be recognized overthe remaining vesting period. On January 1, 2019, 302,786 units of the March 2016 grant vested.The Partnership’s equity-based incentive compensation expense for the years ended December 31, 2016 , 2017 and 2018 was $2.5 million , $2.2 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, 2017923,551 $6.29Granted503,295 4.45Vested311,927 6.71Forfeited116,700 5.44Nonvested, December 31, 2018998,219 $5.8816. 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 $1.2 million for each of the years ended December 31, 2016 , 2017 and 2018 , for discretionarycontributions 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 $0.8 million for each of the years ended December 31, 2016 and 2017 , respectively, and $0.2 million for the year ended December 31, 2018, for discretionary profit sharing contributions under the 401(k) Plan.Under the Partnership’s Employee Unit Purchase Plan (the “Unit Purchase Plan”), which was instituted in January 2015, employees have the opportunity toacquire or increase their ownership of common units representing limited partner interests in the Partnership. Eligible employees who enroll in the Unit PurchasePlan may elect to have a designated whole percentage, up to a specified maximum, of their eligible compensation for each pay period withheld for the purchase ofcommon units at a discount to the then current market value. A maximum of 1,000,000 common units may be delivered under the Unit Purchase Plan, subject toadjustment for a recapitalization, split, reorganization, or similar event pursuant to the terms of the Unit Purchase Plan. The Partnership recognized expense of $0.1million for each of the years ended December 31, 2016 , 2017 and 2018 , in connection with the Unit Purchase Plan. 17. 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 $0.9 million in relation to the Profits Interest during the year ended December 31, 2016 .F-27Table of Contents18 . COMMITMENTS AND CONTINGENCIESThe Partnership leases certain real property and equipment 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 be required foroperations. Future non-cancellable commitments related to these items at December 31, 2018 , are summarized below (in thousands): For year ending:OperatingLeasesDecember 31, 2019$2,862December 31, 20201,904December 31, 20211,242December 31, 2022640December 31, 2023548Thereafter1,259Total future minimum lease payments$8,455 Rental expense was $6.5 million , $6.2 million and $5.0 million for the years ended December 31, 2016 , 2017 and 2018 , 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.19. 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 that the Partnership considers reasonable and not excessive. Consistent withinsurance coverage generally available in the industry, in certain circumstances the Partnership’s insurance policies provide limited coverage for losses or liabilitiesrelating to gradual pollution, with broader coverage for sudden and accidental occurrences. Although the Partnership maintains a program designed to prevent and,as applicable, to detect and address such releases promptly, damages and liabilities incurred due to environmental releases from its assets may substantially affectits business. At December 31, 2017 and 2018 , 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 loss contingencies of $0.1 million and $0.2 million as of December 31, 2017 and 2018 , respectively. Changesin the Partnership’s estimates and assumptions may occur as a result of the passage of time and the occurrence of future events.20. 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 orF-28Table of Contentsreplacement cost) to value these assets and liabilities as appropriate. The Partnership uses an exit price when determining the fair value. The exit price representsamounts that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The Partnership utilizes a three-tier fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels.The following is a brief description of those three levels:Level 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, 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 Measurements as of December 31, 2018DescriptionTotal Quoted Pricesin ActiveMarkets forIdentical Assets(Level 1) SignificantOtherObservableInputs(Level 2) SignificantUnobservableInputs (Level 3)Assets: Interest rate swap assets$44 $— $44 $—Total swap assets$44 $— $44 $—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. F-29Table of ContentsAt December 31, 2018 , 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, 2018 , 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 3.21 . 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 services. ASPHALT TERMINALLING SERVICES — The Partnership provides liquid asphalt cement and residual fuel oil terminalling services at its 53terminalling 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 8 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 SERVICES — The Partnership uses its owned and leased tanker trucks to gather crude oil for its customers at remote wellheadlocations generally not covered by pipeline and gathering systems and to transport the crude oil to aggregation points and terminalling facilities located alongpipeline gathering and transportation systems. On April 24, 2018, the Partnership sold the producer field services business. As a result of the sale of the producerfield services business, the Partnership changed the name of this operating segment to crude oil trucking services during the second quarter of 2018. See Note 8 foradditional information.The 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-30Table of Contents Year ended December 31, 2016 2017 2018Asphalt Terminalling Services Service revenue: Third-party revenue$75,655 $57,486 $26,108Related-party revenue11,762 56,378 21,686Lease revenue: Third-party revenue— — 41,319Related-party revenue— — 25,961Product sales revenue: Related-party revenue— — 482Total revenue for reportable segments87,417 113,864 115,556Operating expense, excluding depreciation and amortization30,648 49,241 49,229Operating margin, excluding depreciation and amortization56,769 64,623 66,327Additions to long-lived assets148,622 22,046 30,068Total assets (end of period)$141,280 $146,966 $138,245 Crude Oil Terminalling Services Service revenue: Third-party revenue$16,387 $22,177 $11,928Related-party revenue7,858 — —Intersegment revenue— — 704Lease revenue: Third-party revenue— — 45Total revenue for reportable segments24,245 22,177 12,677Operating expense, excluding depreciation and amortization4,197 4,200 3,899Operating margin, excluding depreciation and amortization20,048 17,977 8,778Additions to long-lived assets2,126 2,194 3,394Total assets (end of period)$71,689 $69,149 $68,480 F-31Table of Contents Year ended December 31, 2016 2017 2018Crude Oil Pipeline Services Service revenue: Third-party revenue$8,662 $9,580 $6,396Related-party revenue5,433 310 445Lease revenue: Third-party revenue— — 484Product sales revenue: Third-party revenue20,968 11,094 235,428Total revenue for reportable segments35,063 20,984 242,753Operating expense, excluding depreciation and amortization15,270 13,310 11,828Intersegment operating expense890 417 5,284Third-party cost of product sales14,130 8,807 126,776Related-party cost of product sales— — 102,469Intersegment cost of product sales426 150 —Operating margin, excluding depreciation and amortization4,347 (1,700) (3,604)Additions to long-lived assets8,250 2,934 19,654Total assets (end of period)$150,043 $117,749 $112,429 Crude Oil Trucking Services Service revenue: Third-party revenue$25,511 $24,529 $14,324Related-party revenue5,158 — —Intersegment revenue890 417 4,580Lease revenue: Third-party revenue— — 219Product sales revenue: Third-party revenue— 385 10Intersegment revenue426 150 —Total revenue for reportable segments31,985 25,481 19,133Operating expense, excluding depreciation and amortization30,156 25,915 19,575Operating margin, excluding depreciation and amortization1,829 (434) (442)Additions to long-lived assets2,558 1,701 3,243Total assets (end of period)$12,651 $7,005 $4,150 Total operating margin, excluding depreciation and amortization (1)$82,993 $80,466 $71,059 Total segment revenues178,710 182,506 390,119Elimination of intersegment revenues(1,316) (567) (5,284)Consolidated revenues177,394 181,939 384,835____________________(1)The following table reconciles segment operating margin, excluding depreciation and amortization to income (loss) before income taxes (in thousands):F-32Table of Contents Year ended December 31, 2016 2017 2018Operating margin (excluding depreciation and amortization) $82,993 $80,466 $71,059Depreciation and amortization (30,820) (31,139) (29,359)General and administrative expenses (20,029) (17,112) (15,995)Asset impairment expense (25,761) (2,400) (53,068)Gain (loss) on sale of assets 108 (975) 149Equity earnings in unconsolidated affiliate 1,483 61 —Gain on sale of unconsolidated affiliate — 5,337 2,225Interest expense (12,554) (14,027) (16,860)Income (loss) before income taxes $(4,580) $20,211 $(41,849)22 . 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 willgenerally be taxed again to unitholders as corporate distributions and none of the income, gains, losses, deductions or credits of this subsidiary will flow through tothe Partnership’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, 2018 , are presented below (in thousands): Deferred Tax Asset Difference in bases of property, plant and equipment$273Deferred tax asset273 Less: valuation allowance(273)Net deferred tax asset$— F-33Table of ContentsThe 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, 2018 .23 . 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, were not revised. See Note 4 for disclosures related to the adoption of thisstandard and the impact on the Partnership’s financial position, results of operations and 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 adopted this update as of January 1, 2018, and there was noimpact on the Partnership’s financial position, 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 adopted this standard as of January 1, 2019, using the modifiedretrospective approach, and elected to apply the provisions at the beginning of the period of adoption. In addition, the Partnership elected the package of practicalexpedients permitted under the transition guidance within the new standard, which among other things, allowed the Partnership to carry forward the historical leaseclassification. The Partnership will have no cumulative adjustment to equity on the effective date. The overall impact to the Partnership’s results is not expected tobe material; however, the Partnership expects a change in classification from operating lease to financing lease for heavy-duty tractor and trailer leases entered intoafter the period of adoption under the new guidance. The opening balance sheet impact will be to record operating lease right of use assets of $11.7 million andoperating leaselease liabilities of $11.9 million on January 1, 2019. Our finance lease assets and liabilities of $0.6 million did not change as a result of adopting thisstandard.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 adopted this update as of January 1, 2018, and there was no impact on thePartnership’s financial position, results of operations or cash flows.F-34Table of ContentsIn 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 adopted this update as of January 1, 2018, and there was 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 adopted this update as of January 1, 2018, and there was no impact on the Partnership’sfinancial position, results of operations 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 with evaluating whether transactions should be accounted for as acquisitions (ordisposals) of assets or businesses. This update is effective for financial statements issued for annual periods beginning after December 15, 2017, and interimperiods within those fiscal years. The Partnership adopted this update as of January 1, 2018, and there was no impact on the Partnership’s financial position, resultsof 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 adopted this update as of January 1, 2018, and there was no 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 adopted this update as of January 1, 2018, and there was no impact on the Partnership’sfinancial position, results of operations or cash flows.24. QUARTERLY FINANCIAL DATA (UNAUDITED) Summarized quarterly financial data is as follows (in thousands, except per unit data): FirstQuarter SecondQuarter ThirdQuarter FourthQuarter Full Year2017: Revenues$46,340 $43,877 $47,474 $44,248 $181,939Operating income (loss) (1)6,557 6,50512,219 3,559 28,840Net income (loss) (1)3,542 6,3719,771 361 20,045Basic and diluted net income (loss) per common unit(0.08) —0.08 (0.15) (0.15) 2018: Revenues (2)$44,660 $83,493$133,158 $123,524 $384,835Operating income (loss) (3)5,815 6,8306,663 (46,522) (27,214)Net income (loss) (3)4,442 1,7852,408 (50,682) (42,047)Basic and diluted net income (loss) per common unit(0.05) (0.11) (0.09) (1.36) (1.61)F-35Table of Contents____________________(1)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.(2)The increase in revenue during 2018 is due to an increase in volume in the Partnership’s crude oil marketing business.(3)Operating loss and net loss for the fourth quarter and full year 2018 are impacted by asset impairment charges of $52.4 million .F-36Exhibit 10.18*** Where this marking appears throughout this Exhibit 10.18, information has been omitted pursuant to a request for confidential treatment and such informationhas been filed with the Securities and Exchange Commission separately.AMENDMENT TO STORAGE, THROUGHPUTAND HANDLING AGREEMENTThis Amendment to Storage, Throughput and Handling Agreement (this “ Amendment ”) is entered into effective as ofJanuary 1, 2019 (“ Amendment Date ”), by and between BKEP Materials, L.L.C., a Texas limited liability company (“ BKEPMaterials ”), BKEP Asphalt, L.L.C., a Texas limited liability company (“ BKEP Asphalt ” and together with BKEP Materials, “Owner ”), and Ergon Asphalt & Emulsions, Inc., a Mississippi corporation (“ Customer ”). Owner and Customer are sometimesreferred to individually as “ Party ” and collectively as the “ Parties ”.R E C I T A L SWHEREAS , Owner and Customer are parties to that certain Storage, Throughput and Handling Agreement dated as ofOctober 5, 2016 (the “ FLV Agreement ”); andWHEREAS , the Parties desire to extend the Term of the FLV Agreement and otherwise amend such agreement as providedherein.NOW THEREFORE , in consideration of the mutual promises contained in this Amendment, the Parties agree to that theFLV Agreement is amended as follows:1.The defined terms “Aggregate Operating Expenses” and “Assumed OPEX” in Section 1 are deleted. The definition of“Term” in Section 1 is amended to refer to Section 17.1.2.The defined term “Abatement Costs” is inserted in alphabetical order: “” Abatement Costs ” has the meaning assigned toit in Section 4.9 .”3.The defined term “Abatement Equipment” is inserted in alphabetical order: ““ Abatement Equipment ” has the meaningassigned to it in Section 4.9.”4.Section 3.2 is deleted in its entirety.5.Section 4.2 is amended by adding the following sentences to the end of such section: “Customer acknowledges thatOwner requires Third Parties operating on Customer’s behalf and entering or accessing the Terminal to have separateaccess or service agreements with Owner. Owner will use reasonable efforts to put in place agreements with any suchThird Parties and Owner, at its reasonable discretion, will approve, negotiate, and finalize such agreements. Owner willpromptly notify Customer of Third Parties operating on Customer’s behalf that are denied access to the Terminal.”6.Section 4.9 is created to read:“4.9 If, at any time during the Term, a complaint is made regarding offensive or obnoxious odors emitted from theProduct delivered to or stored at the Terminal, or if such Products violate any applicable regulation relating to odor,Owner shall notify Customer of such complaint or violation. In such case, Owner and Customer shall cooperate in goodfaith to investigate and determine the source of the odor, and shall mutually determine the best method to abate suchodor. If reasonable changes to the Product would fully or partially abate the odor, Customer shall make such reasonablechanges to abate the odor. Owner shall not be obligated to accept Product reasonably known to have excessive potentialfor odor that may affect the Terminal’s property boundaries. If the Parties’ investigation determines that abatement of theodor requires the installation of additional equipment reasonably necessary to abate the odor (“ Abatement Equipment ”),Owner shall undertake procurement and installation of the Abatement Equipment. Customer shall be responsible for andshall pay to or reimburse Owner for the cost of (i) the investigation to determine the cause of such odor, and (ii) theAbatement Equipment ((i) and (ii), the “ Abatement Costs ”), up to a maximum of $*** in the aggregate in the aggregatefor each Terminal. Owner shall be responsible for all Abatement Costs in excess of $***. Except to the extent a defect inor failure of any of the equipment at the Terminal is the cause of such odor issue, Customer shall indemnify, defend, andhold harmless Owner from and against any and all fines, assessments, damages, penalties, and other expenses, includingreasonable attorneys’ fees and costs, incurred by Owner as a result of such odor. If a defect in or failure of any of theequipment at the Terminal is the cause of such odor issue, Owner shall indemnify, defend, and hold harmless Customerfrom and against any and all fines, assessments, damages, penalties, and other expenses, including reasonable attorneys’fees and costs, incurred by Customer as a result of such odor. If at any time Customer desires to add Products to theFacilities in addition to those listed in Attachment B , such addition shall be subject to this Section 4.9 .”7.Section 17.1 is restated as follows: “The term of this Agreement (the “ Term ”) is hereby extended, commencing January1, 2019, and continuing until December 31, 2023.”8.Section 17.2 is deleted in its entirety. 9.Section 3(a) of Attachment A is amended by replacing the storage fee table with the following: Fontana, CATerminalLas Vegas, NVTerminalTotalStorage Fee$ ***$***$***Minimum Capacity Commitment*********Per Barrell Storage Fee$ ***$***$***10.The final sentence of Section 4 of Attachment A is deleted.11.Owner acknowledges that on December 21, 2018, Customer prepaid the Storage Fees for the months of January,February and March, 2019, in the amount of $***. Additionally, Customer has paid to Owner upon execution of thisAmendment the sum of $*** in prepayment of the Storage Fees for the months of April, May, June, July, August andSeptember, 2019. These payments represent a discounted prepayment of Storage Fees for the months indicated and arenon-refundable in the event of termination of this Agreement prior to date through which payments have been made.12.Except as otherwise stated in this Amendment, all terms and conditions of the FLV Agreement shall remain in full forceand effect without change, and are hereby ratified by each of the Parties. Capitalized terms used but not defined hereinshall have the meanings ascribed to them in the FLV Agreement.13.This Amendment may be executed by the Parties in counterparts and delivered by facsimile or by electronic mail in pdfor similar format, which signatures shall have the same effect as originals, and all such counterparts shall collectivelyconstitute one and the same instrument.14.This Amendment shall be governed by and construed in accordance with the laws of the State of Oklahoma withoutgiving effect to its conflicts of law principles.This Amendment has been executed by the authorized representatives of each Party as indicated below to be effective as ofthe date first written above. OWNER: BKEP MATERIALS, L.L.C. By:/s/ Mark A. Hurley Name:Mark A. Hurley Title:Chief Executive Officer BKEP ASPHALT, L.L.C. By:/s/ Mark A. Hurley Name:Mark A. Hurley Title:Chief Executive Officer CUSTOMER: ERGON ASPHALT & EMULSIONS, INC. By:/s/ J. Baxter Burns, II Name:J. Baxter Burns, II Title:PresidentSignature page to Amendment to Storage, Throughput and Handling Agreement (FLV)Exhibit 10.19*** Where this marking appears throughout this Exhibit 10.19, information has been omitted pursuant to a request for confidential treatment and such informationhas been filed with the Securities and Exchange Commission separately.AMENDMENT TO STORAGE, THROUGHPUTAND HANDLING AGREEMENTThis Amendment to Storage, Throughput and Handling Agreement (this “ Amendment ”) is entered into effective as ofMarch __, 2019 (“ Amendment Date ”), by and between BKEP Materials, L.L.C., a Texas limited liability company (“ BKEPMaterials ”), BKEP Asphalt, L.L.C., a Texas limited liability company (“ BKEP Asphalt ” and together with BKEP Materials, “Owner ”), and Ergon Asphalt & Emulsions, Inc., a Mississippi corporation (“ Customer ”). Owner and Customer are sometimesreferred to individually as “ Party ” and collectively as the “ Parties ”.R E C I T A L SWHEREAS , Owner and Customer are parties to that certain Storage, Throughput and Handling Agreement dated as ofOctober 5, 2016, as amended (the “ Agreement ”); andWHEREAS , the Parties desire to amend such Agreement as provided herein.NOW THEREFORE , in consideration of the mutual promises contained in this Amendment, the Parties agree to that theAgreement is amended as follows:1.Customer has paid to Owner upon execution of this Amendment the sum of $*** in prepayment of the Storage Fees forthe months of April, May, June, July, August and September, 2019. These payments represent a discounted prepaymentof Storage Fees for the months indicated and are non-refundable in the event of termination of this Agreement prior todate through which payments have been made.2.Except as otherwise stated in this Amendment, all terms and conditions of the Agreement shall remain in full force andeffect without change, and are hereby ratified by each of the Parties. Capitalized terms used but not defined herein shallhave the meanings ascribed to them in the Agreement.3.This Amendment may be executed by the Parties in counterparts and delivered by facsimile or by electronic mail in pdfor similar format, which signatures shall have the same effect as originals, and all such counterparts shall collectivelyconstitute one and the same instrument.4.This Amendment shall be governed by and construed in accordance with the laws of the State of Oklahoma withoutgiving effect to its conflicts of law principles.This Amendment has been executed by the authorized representatives of each Party as indicated below to be effective as ofthe date first written above. OWNER: BKEP MATERIALS, L.L.C. By:/s/ Mark A. Hurley Name:Mark A. Hurley Title:Chief Executive Officer BKEP ASPHALT, L.L.C. By:/s/ Mark A. Hurley Name:Mark A. Hurley Title:Chief Executive Officer CUSTOMER: ERGON ASPHALT & EMULSIONS, INC. By:/s/ J. Baxter Burns, II Name:J. Baxter Burns, II Title:President Signature page to Amendment to Storage, Throughput and Handling AgreementExhibit 10.28*** Where this marking appears throughout this Exhibit 10.28, information has been omitted pursuant to a request for confidential treatment and such informationhas been filed with the Securities and Exchange Commission separately.LESSEE OPERATEDFACILITIES LEASE AGREEMENT NO. 2019-00068This Lessee Operated Facilities Lease Agreement N o. 2019-00068 (“ Agreement ”) is entered into as of January 1, 2019 (“ EffectiveDate ”), by and between BKEP Materials, L.L.C., a Texas limited liability company (“ BKEP Materials ”), BKEP Asphalt, L.L.C., a Texaslimited liability company (“ BKEP Asphalt ” collectively with BKEP Materials, “ Lessor ”), and Ergon Asphalt & Emulsions, Inc., aMississippi corporation (“ Lessee ”) Lessor and Lessee are sometimes referred to individually as “ Party ” and collectively as the “ Parties ”.RECITALSWHEREAS , Lessor owns and/or leases certain facilities listed in Exhibit A-1 that are used to process, handle and store asphalt andhas rights under certain rail leases listed in Exhibit A-2 (“ Rail Leases ”) that serve certain of the facilities listed in Exhibit A-1 (the facilitiesand Rail Leases, collectively, the “ Facilities ”); andWHEREAS , Lessee desires to lease from Lessor the Facilities and Lessor desires to lease the Facilities to Lessee; andWHEREAS , Lessee and Lessor are parties to that certain Master Facilities Lease Agreement and Master Facilities Sublease andSublicense Agreement, each dated as of November 11, 2010 and expiring December 31, 2018 (the “ 2010 Agreements ”); andWHEREAS, the Parties desire to terminate and supersede the 2010 Agreements as of the Effective Date; andWHEREAS , Lessee shall be responsible for operating and maintaining the Facilities as set forth herein.NOW THEREFORE , in consideration of the mutual promises contained in this Agreement, the Parties agree to the following termsand conditions.Article 1. Definitions .In this Agreement, unless the context requires otherwise, the terms defined in the preamble and text of this Agreement have themeanings indicated and the following terms will have the meanings indicated below:“ 2009 Agreements ” means those certain Facilities Lease Agreements dated May 18, 2009 relating to the lease and use of Lessor’sFacilities in Austin, Texas; Dodge City, Kansas; Halstead, Kansas; Lawton, Oklahoma; Little Rock, Arkansas; Memphis, Tennessee; Salina,Kansas and Garden City, Georgia, and those certain Facility Sublease Agreements and Facility Sublicense Agreement, also dated May 18,2009, relating to the sublease and/or sublicense of Lessor’s Facilities in Catoosa, Oklahoma, Ardmore, Oklahoma, Parsons, Tennessee,Muskogee, Oklahoma and El Dorado, Kansas.1“ Abatement Equipment ” has the meaning set forth in Section 10.8 .“ Affiliate(s) ” means, in relation to a Party, any Person that (i) directly or indirectly controls such Party, (ii) is directly or indirectlycontrolled by such Party or (iii) is directly or indirectly controlled by a Person that directly or indirectly controls such Party. For this purpose,“control” of any entity or Person means the possession, directly or indirectly, of the power to direct or cause the direction of the managementand policies of any Person, whether through the ownership of a majority of equity interests or voting power or control in fact of the entity orPerson or otherwise. For the purposes of this Agreement, however, Blueknight Energy Partners, L.P. and each of its subsidiaries, either director indirect, shall not be considered the Affiliate of Lessee and any of Lessee’s other Affiliates.“ Applicable Law ” means (i) any law, statute, regulation, code, ordinance, license, decision, order, writ, injunction, decision,directive, judgment, policy, rule or decree of any Governmental Authority and any judicial or administrative interpretations thereof, (ii) anyagreement, concession or arrangement with any Governmental Authority and (iii) any license, permit or compliance requirement by anyGovernmental Authority, in each case applicable to either Party and as amended or modified from time to time.“ Bankrupt ” means a person or entity that (i) is dissolved, other than pursuant to a consolidation, amalgamation, or merger, (ii)becomes insolvent or is unable to pay its debts or fails or admits in writing its inability generally to pay its debts as they become due, (iii)makes a general assignment, arrangement or composition with or for the benefit of its creditors, (iv) institutes or has instituted against it aproceeding seeking a judgment of insolvency or bankruptcy or any other relief under any bankruptcy or insolvency law or other similar lawaffecting creditor’s rights, or a petition is presented for its winding-up or liquidation, (v) has a resolution passed for its winding-up, officialmanagement, or liquidation, other than pursuant to a consolidation, amalgamation, or merger, (vi) seeks or becomes subject to theappointment of an administrator, provisional liquidator, conservator, receiver, trustee, custodian, or other similar official for all orsubstantially all of its assets, (vii) has a secured party take possession of all or substantially all of its assets, or has a distress, execution,attachment, sequestration, or other legal process levied, enforced, or sued on or against all or substantially all of its assets, (viii) causes or issubject to any event which, under Applicable Law, has an analogous effect to any of the events specified in clauses (i) through (vii) above,inclusive, or (ix) takes any action in furtherance of, or indicating its consent to, approval of, or acquiescence in any of the foregoing acts.“ Business Day ” means a twenty-four (24) hour period ending at 5:00 p.m., at the prevailing time in the Central Time Zone, on aweekday on which banks are open for general commercial business in Oklahoma City.“ Calendar Year ” means a period of 365 consecutive days commencing on January 1st and each successive period of 365consecutive days during the Term of this Agreement with the exception of any Calendar Year in which February has 29 days when the periodwill be 366 consecutive days.“ Casualty ” has the meaning set forth in Section 12.9 .“ Commencement Date ” has the meaning set forth in Article 3 .“ Confidential Information ” has the meaning set forth in Article 9 .“ Continuing Rail Use Rights ” has the meaning set forth in Section 2.1(b).2“ Cost ” has the meaning set forth in Section 12.9 .“ Default ” or “ Event of Default ” means an occurrence of the events or circumstances described in Article 17 .“ Defaulting Party ” has the meaning set forth in Section 17.2 .“ Disclosing Party ” has the meaning set forth in Article 9 .“ Encumbrances ” has the meaning set forth in Section 26 .“ Environmental, Health, Safety, Transportation, and Security Laws ” shall mean and include all applicable federal, state, local, ormunicipal laws, rules, regulations, statutes, ordinances, or orders of any Governmental Authority relating to (i) the control of any pollutant, orprotection of health or the air, water, or land; (ii) waste generation, handling, treatment, storage, disposal, discharge, release, emission, ortransportation; (iii) exposure to hazardous, toxic, or other substances alleged to be harmful; (iv) the protection of any endangered or at-riskplant or animal life; (v) occupational or public health and safety; (vi) transportation, including transportation of materials; or (vi) site orhomeland security, including prevention and disruption of terrorist attacks, the protection of the public, resources, and infrastructure, orresponse to terrorist attacks. Environmental, Health, Safety, Transportation, and Security Laws shall include, but not be limited to, the CleanAir Act, 42 U.S.C. 7401 et seq., the Clean Water Act, 33 U.S.C. § 1251 et seq., the Resource Conservation Recovery Act (" RCRA "), 42U.S.C. § 6901 et seq., the Toxic Substances Control Act, 15 U.S.C. § 2601 et seq., the Safe Drinking Water Act, 42 U.S.C. § 300f et seq., theComprehensive Environmental Response, Compensation and Liability Act (" CERCLA "), 42 U.S.C. § 9601 et seq., the Atomic Energy Act,42 U.S.C. § 2011 et seq., the Occupational Health and Safety Act (" OSHA "), 29 U.S.C. § 651 et seq., the Ports and Waterways Safety Act,33 U.S.C. § 1221 et seq., the Hazardous Materials Transportation Act, 49 U.S.C. § 1801 et seq., and the Homeland Security Act, 6 U.S.C. §101 et seq. and the Critical Infrastructure Information Act, 6 U.S.C. § 131 et seq.; and all applicable executive orders and state, local, andmunicipal laws, rules, regulations, statutes, ordinances, and orders dealing with the subject matter of the above federal statutes.“ Expiration Exercise Notice ” has the meaning set forth in Section 28.2 . “ Expiration Offered Facilities ” has the meaning set forth in Section 28.2 .“ Expiration ROFO Notice ” has the meaning set forth in Section 28.2 .“ Expiration ROFO Period ” has the meaning set forth in Section 28.2 .“ Facilities ” has the meaning indicated in the Recitals.“ Facilities Lease Agreement ” has the meaning set forth in the Recitals.“ Fixed Lessee Improvements ” has the meaning set forth in Section 8.1.“ Force Majeure ” means (i) strikes, lockouts, or other industrial disputes or disturbances, (ii) acts of the public enemy or ofbelligerents, hostilities or other disorders, wars (declared or undeclared), blockades, thefts, insurrections, riots, civil disturbances, or sabotage,(iii) acts of nature, landslides, severe lightning, earthquakes, fires, tornadoes, hurricanes, storms, and warnings for any of the foregoing whichmay necessitate the precautionary shut-down of pipelines, trucks, docks, loading and unloading facilities, storage tanks, or other relatedfacilities, floods, washouts, freezing of machinery, equipment, or lines of pipe, inclement3weather that necessitates extraordinary measures and expense to construct facilities or maintain operations, tidal waves, perils of the sea, andother adverse weather conditions or unusual or abnormal conditions of the sea or other water, (iv) arrests and restraints of, or otherinterference or restrictions imposed by, governments (either federal, state, civil, or military and whether legal or de facto or purporting to actunder some constitutions, decree, law, or otherwise), necessity for compliance with any court order, or any law, statute, ordinance, regulation,or order promulgated after the Effective Date by a Governmental Authority having or asserting jurisdiction , embargoes or export or importrestrictions, expropriation, requisition, confiscation, or nationalization, (v) epidemics or quarantine, explosions, electric power shortages, (vi)breakage or accidents to equipment, machinery, plants, facilities, lines of pipe, or trucks or vessels, which were not reasonably foreseeableand which were not within the control of the Party claiming suspension of its obligations under this Agreement pursuant to Section 24 andwhich by the exercise of reasonable due diligence such Party is unable to prevent or overcome, or (vii) or any other causes, whether of thekind enumerated above or otherwise, which were not reasonably foreseeable, and which are not within the control of the Party claimingsuspension of its obligations under this Agreement pursuant to Section 24 and which by the exercise of reasonable due diligence such Party isunable to prevent or overcome.“ Formula ” has the meaning set forth in Section 12.9 .“ Governmental Authority ” means any foreign or U.S. federal, state, regional, local or municipal governmental body, agency,instrumentality, board, bureau, commission, department, authority, or entity established or controlled by a government or subdivision thereof,including any legislative, administrative, or judicial body, or any person purporting to act therefor.“ Hazardous Materials ” shall mean any (i) for the purpose of this Agreement, petroleum or petroleum products; (ii) asbestos orasbestos-containing materials; (iii) hazardous substances as defined by § 101(14) of CERCLA; (iv) radioactive substances; and (v) any otherchemical, substance, or waste that is regulated by any Governmental Authority under any Environmental, Health, Safety, Transportation, andSecurity Law.“ Initial Offer ” has the meaning set forth in Section 28.2.“ Last Look Offer ” has the meaning set forth in Section 28.3 .“ Lessee Indemnitees ” has the meaning set forth in Section 11.2 .“ Lessor Indemnitees ” has the meaning set forth in Section 11.1 .“ Liability ” means any obligation, liability, charge, deficiency, assessment, interest, penalty, judgment, award, and costs (includingreasonable attorneys’ fees and other fees, court costs, and other disbursements) . The term also includes any liability that directly orindirectly arises out of or is related to any claim, proceeding, judgment, settlement, or judicial or administrative order made or commenced byany Third Party or Governmental Authority.“ Loss Notice ” has the meaning set forth in Section 12.9 .“ Month ” means a calendar month.4“ Non-Compliance Notice ” has the meaning set forth in Section 10.4 .“ Performing Party ” has the meaning set forth in Section 17.2 .“ Permitted Encumbrances ” has the meaning set forth in Section 26 .“ Premises ” has the meaning set forth in Section 2.3 .“ Product ” means asphalt-related goods.“ Rail Leases ” has the meaning set forth in the Recitals.“ Receiving Party ” has the meaning set forth in Article 9 .“ Released Party ” has the meaning set forth in Section 12.8 .“ Releasing Party ” has the meaning set forth in Section 12.8 .“ Rejection Notice ” has the meaning set forth in Section 28.2 .“ Term ” has the meaning set forth in Article 3 .“ Term Exercise Notice ” has the meaning set forth in Section 28.1 .“ Term First Refusal Right ” has the meaning set forth in Section 28.1 .“ Term Offered Facilities ” has the meaning set forth in Section 28.1 .“ Term ROFR Notice ” has the meaning set forth in Section 28.1 .“ Term ROFR Period ” has the meaning set forth in Section 28.1 .“ Transfer ” has the meaning set forth in Section 28.3 .“ Third Party ” means any entity other than Lessor, Lessee, or their respective Affiliates.“ Underlying Lease ” has the meaning set forth in Section 2.1 .“ Underlying Lessor ” has the meaning set forth in Section 2.1 .“ Volumes Report ” has the meaning set forth in Section 23.1 .Article 2. Premises and Uses .2.1 Facilities .(a) Lessor owns and/or leases the Facilities described on Exhibit A-1 . To the extent Lessor leases the Facilities, Lesseeacknowledges this Agreement is deemed a “sublease” and is therefore further subject to the applicable lease agreement, which may beamended or revised from time to time, described in Exhibit A-3 describing Parsons, TN, Catoosa, OK; Ardmore, OK; El Dorado, KS (eachapplicable lease agreement referred to as an “ Underlying Lease ”). The lessor under an Underlying Lease is referred to herein as the “Underlying Lessor .” References to Underlying Lessor and the rights and obligations of5Underlying Lessor shall only apply at the respective subleased locations of Parsons, TN, Catoosa, OK; Ardmore, OK; El Dorado, KS. Lesseeshall strictly comply with all rights and obligations set forth in any applicable Underlying Lease. Lessor shall not voluntarily terminate anyUnderlying Lease without Lessee’s prior written consent and shall consult with Lessee regarding any renewals of any Underlying Lease. Iffor any reason the term of any Underlying Lease shall terminate prior to the expiration or termination of the Term and the Parties are nototherwise able to procure the continuing use of the property covered by the Underlying Lease from the applicable Underlying Lessor (“Continuing Sublease Rights ”), then this Agreement shall be automatically terminated with respect to the Facility covered by suchUnderlying Lease and the fees set forth in Exhibit B shall be equitably adjusted to reflect the partial termination as to such Facility.(b) Lessee shall have the rights of Lessor under the Rail Leases, and Lessee shall be subject to the terms and conditions ofthe Rail Leases and perform all obligations of Lessor as lessee under each of the Rail Leases which accrue during the Term (but not anyobligations which survive the termination of any Rail Lease which is terminated prior to the expiration of the Term), except that Lessor shallbe obligated to timely pay rents or other sums due thereunder so long as Lessee pays all rent due under this Agreement. Lessee agrees toindemnify Lessor, and hold Lessor harmless, from and against any and all claims, damages, losses, expenses, and liabilities (includingreasonable attorneys’ fees) incurred as a result of Lessee’s non-performance or non-observance of any of Lessor’s obligations as lessee underthe Rail Leases which, as a result of this Agreement, became an obligation of Lessee. If Lessee makes any payment to Lessor pursuant to thisindemnity, Lessee shall be subrogated to the rights of Lessor concerning such payment. Lessee shall not do, nor permit to be done, any act orthing which is, or with notice or the passage of time would be, a default under the Rail Leases. Lessee shall look solely to the lessors undereach of the Rail Leases for all services to be provided by such lessors thereunder and shall not, under any circumstances, seek nor requireLessor to perform any of such services, nor shall Lessee make any claim upon Lessor for any damages which may arise by reason of any suchlessor’s default under the Rail Leases. However, Lessor shall reasonably cooperate with Lessee to exercise or enable Lessee to exercise anyrights or remedies available to enforce each Rail Lease for Lessee’s benefit in the event of a default by the lessor under each Rail Lease.Lessor agrees to indemnify Lessee, and hold Lessee harmless, from and against any and all claims, damages, losses, expenses, and liabilities(including reasonable attorneys’ fees) incurred as a result of Lessor’s non-performance of its obligations with respect to the Rail Leases as setforth in this paragraph, so long as Lessee has paid all rent due under this Agreement. Lessor shall not do, nor permit to be done, any act orthing which is, or with notice or the passage of time would be, a default under the Rail Leases. Lessor shall not voluntarily terminate any RailLease without Lessee’s prior written consent and shall consult with Lessee with respect to any renewals of any Rail Lease. If for any reasonthe term of any Rail Lease shall terminate prior to the expiration or termination of the Term and the Parties are not otherwise able to procurethe continuing use of the property covered by the Rail Lease from the applicable landlord (“ Continuing Rail Use Rights ”), then Lessee shallhave the option to terminate this Agreement with respect to the Facility served by such Rail Lease or continue this Lease in effect, and ineither case the fees set forth in Exhibit B shall be equitably adjusted to reflect the partial termination as to such Facility or continuation of theLease without such rail service.2.2 For the rentals and upon and subject to the terms and conditions hereinafter set forth, Lessor agrees to and hereby does lease(including sublease as applicable) the Facilities to Lessee, and Lessee agrees to and hereby does lease (including sublease as applicable) theFacilities from Lessor. This Agreement amends, restates and supersedes the 2009 Agreement and the 2010 Agreements.62.3 The Facilities include the land, buildings, improvements, asphalt storage, rail track (if present), and processing assets(collectively, the “ Premises ”) along with the associated: (i) storage, use, and occupancy rights to, of, or in any buildings, fixtures,equipment, or other physical assets on the Premises or hereinafter constructed on the Premises, (ii) necessary rights of ingress, egress,storage, and transportation (including all existing rights to rail service) to, on, or over the Premises for Lessee and Lessee's agents, invitees,customers, or representatives, as reasonably necessary to further Lessee's operations at the Premises, and (iii) right to receive, use, and enjoypublic and private utility services at the Premises, to include, but not limited to sewer, water, electricity, fuel, waste disposal, and telephone,all at Lessee's sole expense; provided, however, subject to Section 8.1 , that nothing in this Section 2.3 shall be deemed to vest in Lessor titleto any Lessee Improvements. Lessee may use the Premises for the uses permitted hereunder and for no other purpose unless agreed to inwriting by the Parties.2.4 Lessee accepts the Facilities on the Commencement Date of the Term of this Agreement AS-IS, WHERE-IS, and withoutwarranty of any kind, express or implied, including, but not limited to, any warranty of habitability, suitability, or fitness for a particularpurpose; provided, however, that the foregoing shall not constitute a waiver by Lessee of Lessor’s obligations with respect to, or Lessee’sacceptance of, any maintenance or repair items existing as of the Effective Date.2.5 The Facilities are to be used for the receipt, storage, manufacturing, blending, shipping and delivery of Products and allpurposes reasonably related thereto. No other uses are allowed without Lessor’s prior written approval, such approval not to be unreasonablywithheld, conditioned or delayed.2.6 No water rights or mineral rights of any type are conveyed to Lessee by this Agreement. Water may be used for all ordinaryand necessary purposes incident to operation of the Facilities, including, without limitation for the manufacturing and for the dilution ofProducts, but for no other purpose without Lessor’s prior written approval, such approval not to be unreasonably withheld, conditioned ordelayed. Article 3. Term .This term of this Agreement shall be deemed to have commenced on January 1, 2019 (“ Commencement Date ”) and shall terminateon December 31, 2023 (the “ Term ”).Article 4. Compensation .4.1 Except as provided elsewhere herein, during the Term of this Agreement, Lessee shall pay to Lessor the fees set forth onExhibit B attached hereto.4.2 All fees and charges reflected in Lessor’s invoices are due and payable within thirty (30) days of the date of receipt of Lessor’sinvoice. Payment must be made by electronic wire transfer of same day available federal funds to Lessor’s account and bank, both asindicated on Lessor’s invoice. Invoices may be sent by electronic mail and telephone facsimile. Payments that are not disputed and that arenot made within the agreed or designated terms shall bear interest from the original due date at the lesser of (i) the rate of 18% per annum and(ii) the highest rate allowed by Applicable Law. If Lessee disputes any portion of an invoice, Lessee must pay the undisputed portion of theinvoice as set forth in this Section 4.2 . Overdue amounts or disputed amounts that are resolved in favor of the Lessor will accrue interest atthe Interest Rate from the date that payment is due until paid in full and Lessee will pay all of Lessor’s reasonable, out-of-pocket costs(including reasonable attorneys’ fees and court costs) of collecting past due payments and late payment charges, whether or not suit isbrought.7Article 5. Asphalt and Raw Materials .Lessee shall be solely responsible to furnish all asphalt, related raw materials, and all Products at the Premises, including storage tankheels.Article 6. Contract Limited to Available Capability and Capacity .Lessee will only process those qualities, grades, and quantities of Products that are compatible with the processing capabilities of thePremises as of the Effective Date, unless otherwise agreed by the Parties. Lessee shall not process at the Facilities any Products or othermaterials which damage the Facilities or reduce the capacity or capability of the Facilities and, in the event Lessee processes any suchProduct or material at the Facilities, Lessee shall repair and restore the Facilities to their condition immediately prior to the CommencementDate of this Agreement.Article 7. Title and Risk of Loss .Title to asphalt, raw materials, and Products received, unloaded, stored, or otherwise handled at the Premises shall be in the name ofLessee, contractors, or its customers and asphalt, raw materials and Products shall be the sole responsibility of Lessee.Article 8. Improvements .8.1 Subject to (i) Lessor's written approval, which approval may relate to design, location, construction methods, and installationprocedures and which shall not be unreasonably withheld, conditioned or delayed and (ii) the terms, provisions, and conditions of thisAgreement, Lessee may construct or place upon the Premises, at Lessee’s sole expense, improvements required by Lessee (“ LesseeImprovements ”) for the purpose of furthering Lessee's permitted use of the Premises. Such improvements, if permanently placed or affixedto the Premises, shall become the property of Lessor at termination or expiration of this Agreement (the “ Fixed Lessee Improvements ”),except as otherwise agreed to in writing by the Parties. Lessee shall not remove or dispose of any of the leased assets or Fixed LesseeImprovements at the Premises (but expressly excluding all other Lessee Improvements which may be removed at Lessee’s discretion) withoutthe prior written approval of Lessor, such approval not to be unreasonably withheld, conditioned or delayed. Lessee shall notify Lessor withinthree (3) days of any damage to any part of the Premises. Nothing in this section shall limit Lessee’s right to remove its trade fixtures andmoveable equipment installed by Lessee. Lessee shall not impair or negatively impact the original capability of the Facilities.8.2 Subject to the prior written approval of Lessor, which approval shall not be unreasonably withheld, Lessee shall have the rightto install and maintain signage at the Leased Premises at Lessee’s sole cost and expense (including but not limited to construction costs,permits, and licensing fees) and in conformity with all Applicable Laws, restrictive covenants, ordinances, rules, and regulations; providedthat such signage shall only relate to Lessee’s occupancy of and operations on the Leased Premises. During the Term of this Agreement,Lessee shall maintain any such signage at the Leased Premises in good repair and in compliance with Applicable Laws. Upon the expirationor earlier termination of this Agreement, Lessee shall remove all signage and repair and restore any damage to the Premise resulting from theinstallation or removal of any such signage at Lessee’s sole cost and expense.8Article 9. Confidentiality .9.1 Confidential Information . The term “ Confidential Information ” means all nonpublic information, including technicalinformation, trade or business secrets, or the like, disclosed by either Party to the other Party in carrying out the terms and purpose of thisAgreement, either directly or indirectly, in writing, orally or by inspection of tangible objects (including without limitation written or printeddocuments, email correspondence and attachments, electronic files, and computer disks, whether machine or user readable). “ConfidentialInformation” includes, without limitation, information relating to a Party's research, development, trade secrets or business affairs that theParty treats as confidential. The Parties acknowledge and agree that any and all information regarding this Agreement, including withoutlimitation the terms and conditions of this Agreement, shall be deemed to be Confidential Information. Without limiting the generality of theforegoing, Lessor acknowledges and agrees that all Volume Reports and the contents thereof submitted pursuant to Section 23.1 constituteConfidential Information. The term “ Receiving Party ” means a Party that receives Confidential Information of the other Party (“ DisclosingParty ”).9.2 Restrictions on Disclosure . The Receiving Party shall maintain in confidence the Confidential Information so received and willnot use such information, except to the extent permitted under this Agreement, to the detriment of the Disclosing Party, until such time as theConfidential Information so received enters the public domain other than by the act or omission of the Receiving Party. A Receiving Partyshall limit disclosure of the Disclosing Party’s Confidential Information to those of its employees, subcontractors, attorneys, agents, andconsultants with a need to know the Confidential Information, subject to a nondisclosure obligation comparable in scope to this Article 9 .Each Party shall protect the other Party’s Confidential Information using the same degree of care (but no less than a reasonable degree ofcare) that it uses to protect its own Confidential Information. The obligations imposed by this Section shall be during the Term of thisAgreement and for six (6) years thereafter; provided , however , such obligations shall not apply to any Confidential Information that: (i) is orbecomes publicly known through no fault of the Receiving Party; (ii) is developed independently by the Receiving Party prior to the date ofdisclosure; (iii) is obtained by the Receiving Party from a Third Party not known by Receiving Party to be prohibited from disclosing theinformation without confidentiality restrictions or (iv) as required by Applicable Law or by regulation. A Receiving Party also may discloseConfidential Information to the extent required by a court or other Governmental Authority, provided that the Receiving Party, if not legallyprohibited from doing so, promptly notifies the Disclosing Party of the disclosure requirement prior to disclosure and cooperates with theDisclosing Party (at the latter’s expense and at its request) to resist or limit the disclosure.9.3 Injunctive Relief . Receiving Party acknowledges and agrees that a breach or threatened breach of the confidentialityobligations set forth herein may result in immediate and irreparable damage to the Disclosing Party for which there may be no adequateremedy at law, and, in such event, the Disclosing Party may seek appropriate injunctive relief. Disclosing Party’s pursuit of any remedy willnot constitute a waiver of any other right or remedy available under this Agreement or under Applicable Law.9Article 10. Environmental, Health, Safety, Transportation, and Security .10.1 Lessee shall use the Premises only for the purpose contemplated by this Agreement and related purposes associated withasphalt facility operations consistent with the Products and Facilities and in compliance with Environmental, Health, Safety, Transportation,and Security Laws.10.2 Lessee shall not permit the Premises to be used for any unlawful purpose.10.3 Lessee shall conduct operations on the Premises in compliance with all applicable Environmental, Health, Safety,Transportation, and Security Laws and manage Hazardous Materials on the Premises for which Lessee is responsible hereunder incompliance with all Applicable Laws. Lessee shall promptly, and in any event within twenty-four hours of Lessee becoming aware of theoccurrence, notify Lessor of (i) any spill of fifty (50) gallons or more of any asphalt cement or asphalt cement containing Product; (ii) anyspill of five (5) gallons or more of any chemical, diluent, or related product; (iii) any release or spill of a Hazardous Material at the Premisesthat requires reporting under any Applicable Law or by a Governmental Authority or requires a response action, including remediation, underEnvironmental, Health, Safety, Transportation, and Security Laws; (iv) any tank leak or tank over-fill; and (v) any Notice of Violation, Ceaseand Desist or Consent Decree from any Governmental Authority, or the negotiation of any of these. Lessee shall promptly and completelyimplement any response action with respect to such release or spill required under any Applicable Law or by a Governmental Authority.Lessee shall provide Lessor with copies of any reports or monitoring results provided to a Governmental Authority with respect to any suchrelease, spill, or response action no later than five (5) Business Days following the submittal thereof to any Governmental Authority.Furthermore, Lessee also shall provide to Lessor copies of any and all correspondence to or from any Governmental Authority relating to therelease, spill, or response action within five (5) Business Days of the date the correspondence is sent or received by Lessee, as applicable. Inthe event of any spill, Lessee shall remediate any environmental contamination resulting from such spill, and clean or re-skin structures andpiping to remove any staining at the Premises caused by such spill.10.4 Without limiting the generality of the foregoing,(a) Lessee shall be responsible for complying with any and all notification or reporting requirements under Environmental,Health, Safety, Transportation, and Security Laws arising out of Lessee's use of the Premises; provided, however, that Lessor retains the rightbut not the obligation to make, after prior written notice to the Lessee, any environmental notification or report required by law and involvingthe Premises which has not been completely performed or provided by Lessee. Lessee shall keep Lessor fully informed and provide Lessorwith documentation pertaining to any notification or reporting under Environmental, Health, Safety, Transportation, and Security Lawsapplicable to the Premises or Lessee's operations thereon.(b) Lessee shall, at Lessee's own cost and expense, obtain and maintain in effect during the Term of this Agreement suchenvironmental, health, safety, transportation, and security permits, licenses, plans, approvals, or other such authorizations underEnvironmental, Health, Safety, Transportation, and Security Laws as are necessary for Lessee to comply with Lessee's duties and obligationsunder this Agreement, as are necessary for Lessee to comply in all respects with Applicable Law, and as are necessary for Lessee to conductits operations on the Premises. By way of example, but not limitation, such necessary environmental permits or plans may include, but willnot be limited to, Title V and applicable state Air Operating Permits, Spill Prevention Control, Countermeasure Plan, and Facility ResponsePlan as both plans are set forth in 40 CFR Part 112, U.S. Coast Guard Facility Security Plans, and such other plans or permits that may berequired by any and all local, state, and federal agencies. By way of further example, but not limitation, and more specific to requirementsunder the Spill Prevention Control and Countermeasure regulations as outlined in 40 CFR Part 112 as applied to above-ground oil storagecontainers, Lessee shall,10at Lessee's own cost and expense, obtain and maintain in effect during the Term of this Agreement all permits, plans, schedules, testingrequirements, tank preparation and cleaning, administrative processes, consultant requirements, procedures, and internal/external tankinspections. Lessee will provide Lessor with all proposed testing schedules and tank inspection methodology in advance of Lessee'simplementation of such inspections. Lessee will provide Lessor with copies of all information pertaining to the actual findings of the tankinspections and any other tank integrity information from Lessee's implementation of such tank inspections. In the event any inspectionsconducted by Lessee or its contractor(s) uncover any probable areas of concern, Lessee shall submit to Lessor a proposed schedule outliningthe estimated timing and costs for repair. The cost for any such tank repairs shall be allocated between Lessor and Lessee pursuant to theprovisions of Article 15 . Lessee will give Lessor written notice and obtain Lessor's prior written approval, such approval not to beunreasonably withheld, conditioned or delayed, for any and all additions or improvements to the Premises requiring a new permit or a permitmodification under Environmental, Health, Safety, Transportation, and Security Laws.(c) Lessee shall promptly, and in any event within five (5) Business Days of receipt or, as applicable, issuance orassessment, notify and provide copies to Lessor of any and all warning letters, notices of violation, consent orders or decrees, notices ofstipulation, including any monetary penalties assessed, and any similar correspondence from any Governmental Authority (collectively, “Non-Compliance Notices ”) relating to any allegation or declaration of non-compliance with, or need for investigation, remedial, or otherresponse action under, any Environmental, Health, Safety, Transportation, and Security Law, regardless of whether Lessee disputes suchNon-Compliance Notice. Lessee is further obligated to provide Lessor with copies of its response to any such Non-Compliance Notice nolater than five (5) Business Days after submittal thereof, fully explaining how the non-compliance matter or required investigation, remedial,or other response action is to be resolved or why Lessee believes that the alleged non-compliance matter or requested action is not accurate ornot applicable. Lessee shall continue to provide to Lessor any and all correspondence relating to the Non-Compliance Notice until such timeas Lessee demonstrates to the reasonable satisfaction of Lessor that the Non-Compliance Notice has been resolved.10.5 Other than the environmental assessments already performed in connection with the 2009 Agreements, without the priorwritten approval of Lessor, such approval not to be unreasonably withheld, conditioned or delayed., Lessee shall not conduct any soil, groundwater, surface water, or other similar site investigation, sampling, or monitoring of the Premises, unless so ordered by a GovernmentalAuthority, required by the express terms of any permit for the Premises issued under applicable Environmental, Health, Safety,Transportation and Security Laws, or advised by Lessee’s counsel as immediately necessary due to emergency or exigent circumstances. TheLessor shall make the final determination as to whether any discretionary investigation, monitoring, or sampling is warranted. If sowarranted, the Lessor shall have the right to enter the Premises to routinely monitor the Lessee's progress and to ensure that the scope-of-work adheres to that which the Lessor approved. Nothing in this Section 10.5 is intended to be or shall be construed to constitute authority oran exercise of control by Lessor for environmental, health, safety, transportation, or security aspects of Lessee's operations on the Premises,such activities being under the sole control of Lessee.1110.6 Within forty-five (45) days of the end of the Term, except to the extent otherwise requested by Lessor, Lessee shall beresponsible, at its cost and in compliance with Environmental, Health, Safety, Transportation, and Security Laws, for (a) removal and propermanagement of all Hazardous Materials on or in the vicinity of the Premises resulting from or used in connection with Lessee's operation anduse of the Premises; (b) all environmental conditions on or in the vicinity of the Premises resulting from Lessee’s operation and use of thePremises; and (c) all environmental conditions on or in the vicinity of the Premises to the extent resulting from Lessee’s acceleration of,contribution to, or exacerbation of pre-existing environmental conditions resulting from Lessee’s use or operations. Each of the foregoingshall be subject to Lessee’s indemnification obligations hereunder. Violations of Environmental, Health, Safety, Transportation and SecurityLaws and the removal of any Hazardous Material on or in the vicinity of the Premises which existed on or prior to the 2009 Agreements shallbe the responsibility of Lessor and subject to Lessor’s indemnification obligations hereunder. Lessee shall not make any disclosure, unlessrequired by applicable Environmental, Health, Safety, Transportation, and Security Laws, regarding any environmental condition on or in thevicinity of the Premises without Lessor’s prior written consent. The Parties’ obligations under this Section 10.6 shall survive termination ofthis Agreement.10.7 At the end of the Term, Lessee shall reasonably cooperate with Lessor to transfer to Lessor or its designee any permits orother authorizations relating to the Premises issued to Lessee under applicable Environmental, Health, Safety, Transportation, and SecurityLaws; provided, however, if requested by Lessor, instead of transferring a permit or other authorization, Lessee shall at its cost and expenseand in compliance with Environmental, Health, Safety, Transportation, and Security Laws initiate and complete any actions required toterminate such permits or other authorization. Lessee's obligation under this Section 10.7 shall survive termination of this Agreement.10.8 If, at any time during the Term, a complaint is made to Lessor regarding offensive or obnoxious odors emitted from theProduct delivered to or stored at a Terminal, or if such Products violate any applicable regulation relating to odor, Lessor shall notify Lesseeof such complaint or violation. In such case, Lessee shall investigate and determine the source of the odor, and shall determine the bestmethod to abate such odor. If reasonable changes to the Product would fully abate the odor, Lessee shall make such changes and abate theodor. Lessee shall not permit any Product reasonably known to have excessive potential for odor that may affect the Terminal’s propertyboundaries to be stored or handled at a Terminal. If abatement of the odor requires the installation of additional equipment, Lessee and Lessorshall negotiate in good faith to determine what additional equipment is reasonably necessary to abate the odor (“ Abatement Equipment ”),whereupon Lessee shall undertake procurement and installation of the Abatement Equipment. Lessee shall be responsible for and shall pay toor reimburse Lessor for the cost of (i) the investigation to determine the cause of such odor, and (ii) the Abatement Equipment ((i) and (ii),the “ Abatement Costs ”), up to a maximum of $500,000 in the aggregate for each Facility. Lessor shall be responsible for all AbatementCosts in excess of $500,000. In addition to such obligations, Lessee shall indemnify, defend, and hold harmless Lessor from and against anyand all fines, assessments, damages, penalties, and other expenses, including reasonable attorneys’ fees and costs, incurred by Lessor as aresult of such odor.Article 11. Indemnity .11.1 Lessee's Indemnity to Lessor . Lessee shall indemnify and defend Lessor, Lessor’s Affiliates, and their respective employees,directors, partners, members, representatives, agents (“ Lessor Indemnitees ”) against any and all Liabilities for personal injury, death orproperty damage, or any other loss or claim arising out of, from, or otherwise related to (i) Lessee's operation and use of the Premises or (ii)any violation by Lessee of Environmental, Health, Safety, Transportation, and Security Laws or (iii) Lessee’s breach of its obligations underSection 10.6(a), (b) or (c), regardless of whether any Lessor Indemnitee would be subject to strict liability for any such Liability. Lessee shallnot indemnify or agree to defend Lessor to the extent12such Liabilities are caused by the negligence, gross negligence or willful misconduct of any Lessor Indemnitee. Lessee's obligation under thisSection 11.1 shall survive termination of this Agreement.11.2 Lessor's Indemnity to Lessee . Lessor shall indemnify, defend and hold harmless Lessee, Lessee’s Affiliates, and theirrespective employees, directors, partners, members, representatives, , and agents (“ Lessee Indemnitees ”) against any and all Liabilities forpersonal injury, death, property damage, or any other loss or claim to the extent arising out of the acts or omissions of any Lessor Indemniteewhile on the Leased Premises or otherwise to the extent in connection with Lessor’s performance under this Agreement, or any matter subjectto indemnification by Lessor pursuant to Section 10.6, except that Lessor shall not indemnify or agree to defend Lessee to the extent suchLiabilities are caused by the negligence, gross negligence, willful misconduct or Lessee Indemnitees or for Liabilities for which Lessee isindemnifying Lessor pursuant to Section 11.1. Lessor’s obligations under this Section 11.2 shall survive termination of this Agreement.Article 12. Insurance .12.1 Lessee agrees to secure and maintain insurance with the following coverage and terms, and the stipulated levels of insurancecoverage may be satisfied through primary insurance or a combination of primary and excess or umbrella liability insurance, provided theexcess/umbrella coverage follows form over the underlying primary coverage.12.2 Worker's Compensation Insurance in accordance with the statutory requirements of the state or states in which the Facility islocated and the U.S. Longshore and Harbor Workers Act, as applicable, and employer's liability insurance with minimum limits of$5,000,000.12.3 Commercial General Liability Insurance with minimum limits of $10,000,000 per occurrence for property damage and bodilyinjury, sudden and accidental pollution, premises liability, products liability, broad form contractual liability. For Facilities involving marineoperations, such policy(ies) shall include marine terminal operator’s liability (MTOL) covering Lessee's operations at the Premises or beprovided by standalone MTOL policy with same coverage limit of $10,000,000 per occurrence.12.4 Automobile Liability with minimum limits of $5,000,000 for property damage and bodily injury, covering all vehicles owned,hired, rented, contracted for, or used by Lessee, or Lessee's successors, assigns, employees, agents, licensees, or invitees. Auto Liabilityinsurance shall include broadened pollution coverage using ISO endorsement CA-99-48 Broadened Pollution Coverage (or an endorsementthat offers similar or greater coverage) and MCS-90.12.5 Lessor shall maintain “all risk” or equivalent special cause of loss form insurance on the Premises, but not on Lessee'spersonal property or inventory, for full replacement cost value.12.6 Lessor shall be named as an additional insured on the policies specified in this Section 12 to be maintained by Lessee, otherthan Worker’s Compensation insurance. Lessee shall furnish Lessor with evidence of waiver of subrogation on the policy(ies) specified inthis Section 12 , and certificates of insurance or letters of self-insurance evidencing the insurance coverage specified herein within five (5)days of the Commencement Date of this Agreement and annually thereafter upon date(s) of Lessee’s insurance renewal(s). Lessee will usereasonable efforts to obtain from its insurers their undertaking to provide thirty (30) days’ prior written notice to Lessor of cancellation ornonrenewal. All insurance required to be maintained under the terms of this Agreement shall be written by financially reputable insurancecarriers, with A.M. Best ratings of A-/XII or higher (or its equivalent), authorized to write insurance in the State where the Facilities arelocated.1312.7 Insurance on Lessee’s Product, if any, that may be desired by Lessee in its sole discretion, shall be carried by Lessee atLessee's expense. Lessee further represents and acknowledges that under no circumstances, terms, or conditions of this Agreement shallLessor provide any insurance coverage for Lessee’s Product.12.8 Each of Lessor and Lessee (“ Releasing Party ”) hereby releases the other (“ Released Party ”) from any liability which theReleased Party would, but for this paragraph, have had to the Releasing Party arising out of or in connection with any damage to the propertyof Releasing Party at the Premises which is or would be covered by a special causes of loss form of property insurance with no deductible inthe state in which such Premises is located, regardless of whether or not such coverage is actually being carried by the Releasing Party.Lessor and Lessee shall use reasonable efforts to have their respective policies of insurance endorsed to contain a waiver of subrogationprovision incorporating the foregoing and providing that the insurance shall not be invalidated by the insured’s written waiver prior to a lossof any or all right of recovery against any Party for any insured loss.12.9 Lessor’s and Lessee’s obligations with respect to the restoration of any Facility following any casualty event, whether insured oruninsured (“ Casualty ”), shall be governed by the terms and provisions of this Section 12.9 . Within thirty (30) days following the Casualty,Lessor shall consult with Lessee in good faith and advise Lessee of the estimated cost (the “ Cost ”) and time required to restore and repairsuch Facility to substantially its pre-loss condition (the “ Loss Notice ”). If the Cost is less than or equal to the sum of (i) the greater of (A)$250,000.00 or (B) the annual Base Rental Fee for such Facility as defined in Exhibit B attached hereto (or, if the number of monthsremaining in the Term is less than twelve (12) months, the sum of Base Rental Fees for the months remaining in the Term) and (ii) estimatedinsurance proceeds, if any (the “ Formula ”), Lessor shall have an obligation to restore and repair the Facility to substantially its pre-losscondition, and Lessor shall commence such repair work promptly and complete same as expeditiously as reasonably possible, unless Lesseeelects to terminate its obligations hereunder with respect to such Facility pursuant to the following provisions of this section. If the Cost isgreater than the Formula, then Lessor shall have no obligation to restore and repair the Facility and may terminate its obligations hereunderwith respect to such Facility. In the event that the damage caused by the Casualty is such that it materially interferes with Lessee’s ability toconduct its normal business operations at the Facility and the restoration and repair (i) cannot, based upon the estimated time for repair setforth in the Loss Notice, reasonably be expected to be completed, or is not completed, within one hundred twenty (120) days from the date ofloss or (ii) cannot, based upon the estimated time for repair set forth in the Loss Notice, reasonably be expected to be completed by June 1 ofany year during the Term of this Agreement, Lessee may terminate its obligations hereunder with respect to such Facility effective on thedate of the Casualty, provided it does so by notice to Lessor no later than five (5) business days after: (A) the date of receipt of the LossNotice, or (B) the expiration of 120 days from date of loss or June 1, as applicable, if repairs are not substantially complete by such date sothat Lessee is able to resume operations. During the period of restoration, the Base Rental Fee shall be equitably abated based upon the effectof the Casualty upon Lessee’s ability to conduct normal business operations at the Facility. Notwithstanding anything to the contrarycontained herein, Lessee shall be solely responsible for the repair and restoration of any temporary improvements, trade fixtures, equipmentand any other property of Lessee made, installed or brought upon the Facility by Lessee. In the event that a Party terminates its obligationswith respect to any Facility pursuant to the terms of this Section 12.9 , this Agreement shall be deemed to be automatically revised andreformed to exclude such Facility as of the effective date of such termination and neither Party shall have any further obligations with respectto such Facility, except with respect to obligations accrued prior to the date of such termination or obligations accruing upon termination.14Article 13. Condemnation .If any Facility shall be in its entirety taken or condemned for any public purpose the Parties' obligations with respect to such Facility shallcease as of the date of condemnation, including, but not limited to, Lessee's obligation hereunder to pay rent, taxes, and insurance premiumswith respect to such Facility. If any portion of any Facility is taken or condemned to such an extent as to, in Lessee's reasonabledetermination, materially interfere with Lessee's ability to conduct its normal business operations at such Facility for a period of one hundredtwenty (120) days or more, Lessee shall have the right to terminate its obligations with respect to such Facility by giving written notice oftermination to Lessor within thirty (30) days of receiving notice of such condemnation, whereupon the obligations of the Parties with respectto such Facility, including, but not limited to Lessee's rent obligations, shall cease as to such Facility. If any Facility is partially condemnedand Lessee determines the taking will not materially interfere with Lessee's ability to conduct its normal business operations at such Facility,Lessee shall be entitled to an equitable reduction in rent taking into account the effect upon Lessee's operations of the property so taken.Lessee shall be entitled to make a separate claim against the condemning authority for an award for the value of any of Lessee's property, formoving and relocation expenses, and for such business damages and/or consequential damages as may be allowed by law. In the event that aParty terminates its obligations with respect to any Facility pursuant to the terms of this Section 13, this Agreement shall be deemed to beautomatically revised and reformed to exclude such Facility as of the effective date of such termination and neither Party shall have anyfurther obligations with respect to such Facility, except with respect to obligations accrued prior to the date of such termination or obligationsaccruing upon termination or obligations which by their terms survive termination.Article 14. Limitations .Except for Third Party claims for which there is an indemnification obligation hereunder, neither Party to this Agreement shall beliable to the other Party for consequential, incidental, punitive, or indirect damages (including, but not limited to, lost profits or lost savings)arising from, relating to, or in connection with this Agreement and/or the Premises, even if such Party has been advised of the possibility ofor could have foreseen such damages. This limitation applies regardless of the form of action, including, but not limited to, an action in law orequity.Article 15. Maintenance .15.1 Subject to the limitations set forth in this Article 15 , Lessee shall be responsible for the maintenance and repair of thePremises including all tanks, equipment, or improvements placed or installed on the Premises, whether placed or installed by Lessee orLessor. Lessee shall maintain and operate the Premises in accordance with the equipment manufacturer's standards and observed historicalmaintenance performed at the Facility. . Lessee shall keep the Premises free of all liens, pledges, mortgages, deeds of trust, security interests,leases, subleases, easements, servitudes, and other encumbrances of any kind or nature.1515.2 Notwithstanding anything to the contrary in this Section, and except for repairs and maintenance to the Facilities resultingfrom the negligence or willful misconduct, of a Lessee Indemnitee, Lessor, and not Lessee, shall be responsible for (at its expense andwithout reimbursement from Lessee) for any repairs or maintenance in excess of $*** per individual repair or maintenance occurrence, to theextent necessary for the operations of Lessee’s business on the Premises in connection with the following improvements: (i) tank foundations,tank shells, tank roof, tank floor, and insulation; (ii) dikes, containment areas and security fencing; (iii) scales; (iv) rail spurs, docks, anddredging, if applicable; (v) heaters and boilers; (vi) buildings and HVAC; (vii) Motor Control Center, Motor Starters (including VFD); (viii)pumps; (ix) mills; and (x) tank gauge systems. Except as set forth above, the $*** repair and maintenance obligation of Lessor set forthherein shall not apply to annual maintenance retooling of the mills or tank cleaning and inspection expenses. If replacement of a mill isrequired, Lessor shall replace such mill and Lessee shall reimburse Lessor the first $*** of the cost to replace said mill. Notwithstanding anyof the foregoing, Lessor and Lessee have agreed that tank foundation ring wall defects at the Halstead, Kansas Facility, regardless of numberof tanks affected, will be treated as one repair and subject to only one payment of $*** by Lessee. Notwithstanding the foregoing, Lesseeshall be solely responsible for all costs and expenses related to the maintenance of any Lessee Improvements.15.3 Lessee shall obtain Lessor's prior written approval for all repair and maintenance costs expected to exceed $*** per individualrepair or maintenance occurrence, such approval not to be unreasonably withheld, conditioned or delayed. Lessee may not make repairs onbehalf of Lessor without such prior approval, which may be in electronic form via email. If approved by Lessor, Lessee may make suchrepairs on behalf of Lessor and submit an invoice, along with supporting documentation, to Lessor for the amount of each such repair andmaintenance occurrence and said amount shall be paid in full by Lessor to Lessee within thirty (30) calendar days after receipt of the invoiceand supporting documentation by Lessor.15.4 Lessee shall maintain the Facilities at a level that is clean, free of clutter and debris, and that all paint, insulation systems,product stains, soil stains, vegetation control and general appearances are such that the Facilities and the Lessee are in good standing with thecommunity and surrounding neighbors.Article 16. Possession and Access .Lessee shall enjoy exclusive possession of the Premises at all times during the Term of this Agreement, and Lessor and its respectiveagents, and representatives shall have access to the Premises for the purpose of (i) inspection, including inspection for the purpose ofidentifying issues and advising Lessee of any required changes to operating or maintenance practices to meet the requirements of thisAgreement, provided that such inspection does not relieve Lessee of its obligations under this Agreement to address matters whether or notidentified during such inspection, (ii) in the case of an emergency, (iii) inspection by potential purchasers of the Facility, lenders, insurers, orinvestors, and (iv) for any other purpose contemplated by this Agreement such as auditing records or ensuring compliance by Lessee with theterms of this Agreement.16Article 17. Default and Remedies .17.1 Events of Default . Notwithstanding any other provision of this Agreement, an event of default (“ Default ” or “ Event ofDefault ”) shall be deemed to occur with respect to a Party when:(a) Such Party fails to make payment to the other Party when due under this Agreement, within ten (10) Business Days of awritten demand therefor.(b) Other than a Default described in Sections 17.1(a) and (c) , such Party fails to perform any obligation or covenant tothe other Party under this Agreement, which failure is not cured to the reasonable satisfaction of the other Party within thirty (30)from the date that such Party receives written notice that corrective action is needed, or, if such default is of a nature that it cannotreasonably be cured within thirty (30) days, such Party fails to commence to cure same within such thirty (30) day period andcontinuously pursue such cure thereafter to completion with reasonable diligence.(c) Such Party becomes a Bankrupt.17.2 Remedies . Notwithstanding any other provision of this Agreement, upon the occurrence of an Event of Default with respectto either Party (the “ Defaulting Party ”), the other Party (the “ Performing Party ”) shall, in addition to all other remedies available to it andwithout incurring any Liabilities to the Defaulting Party or to Third Parties, be entitled to do one or more of the following: (a) suspend itsperformance under this Agreement as to the affected Facility(ies) without prior notice to the Defaulting Party, (b) proceed against theDefaulting Party for damages occasioned by the Defaulting Party’s failure to perform, and (c) upon one (1) Business Day’s notice to theDefaulting Party, terminate and liquidate this Agreement but only as to the affected Facility(ies). Notwithstanding the foregoing, in the caseof an Event of Default described in Section 17.1(d) , no prior notice shall be required.17.3 Non-Exclusive Remedy . The Performing Party’s rights under this Article 17 shall be in addition to, and not in limitation orexclusion of, any other rights that it may have (whether by agreement, operation of law or otherwise), including any rights and remediesunder any applicable Uniform Commercial Code. The Performing Party may enforce any of its remedies under this Agreement successivelyor concurrently at its option. No delay or failure on the part of a Performing Party to exercise any right or remedy to which it may becomeentitled on account of an Event of Default shall constitute an abandonment of any such right, and the Performing Party shall be entitled toexercise such right or remedy at any time during the continuance of an Event of Default. All of the remedies and other provisions of thisArticle 17 shall be without prejudice and in addition to any right of setoff, recoupment, combination of accounts, lien, or other right to whichany Party is at any time otherwise entitled (whether by operation of law, in equity, under contract or otherwise).Article 18. Independent Entities .Neither Party shall have authority to bind the other by any contract, representation, understanding, act, or deed concerning the otherParty, nor shall this Agreement be deemed to establish a partnership or joint venture. Neither Party shall have any right to use trademarks,trade names, or the corporate name of the other. Each Party shall have the sole responsibility for the acts and compensation of its ownemployees, its taxes, and the expenses of the conduct of its own business.17Article 19. Assignment .Lessee shall not assign its rights and obligations under this Agreement without the prior written consent of Lessor, such consent notto be unreasonably withheld, conditioned or delayed; provided , however , that, Lessee may assign, without the prior written consent ofLessor, this Agreement or its respective rights and obligations hereunder, in whole or in part, to an Affiliate or any successor in interest ofLessee, including the purchaser of all or substantially all of the assets of Lessee; provided that , (i) such Affiliate or successor assumes inwriting all of Lessee's obligations hereunder and a copy of such assumption is provided to Lessor, and (ii) Lessee shall not be relieved orreleased from Liability hereunder. Lessor may assign, without the prior written consent of Lessee, this Agreement or its respective rights andobligations hereunder, in whole or in part, to one or more subsidiaries that are directly or indirectly wholly-owned by Lessor or to any personor entity which purchases or is otherwise a successor in interest to Lessor's right, title, and interest in the Facility and Lessor agrees to providenotice thereof before, or within three (3) days following, such assignment, provided , however, Lessor shall have no liability to Lessee norshall Lessee have any remedies under this Agreement for failure to provide such notice, although Lessee shall not be required to recognizesuch assignment until notice thereof is provided by Lessor. This Agreement shall inure to the benefit of, and shall be binding upon, the Partiesand their respective permitted successors and assigns.Article 20. Notices .All notices and other communications given pursuant to this Agreement shall be in writing and sent by email, facsimile, or overnightcourier to the respective Party’s address set forth below and to the attention of the person and department indicated. A notice given by emailor facsimile shall be deemed to have been received when transmitted to the other Party (if, in the case of email, confirmed by the receivingParty’s email system as received and opened, and if by fax confirmed by the notifying Party’s transmission report). A notice given byovernight courier shall be deemed to have been received when the notice is actually delivered to or refused by the other Party, as reflected inthe courier company’s delivery records. Any notice received after 5:00 p.m. is not deemed received until 11:00 a.m. the following BusinessDay. A Party may change its address, email or facsimile number by giving written notice in accordance with this Section, which change iseffective upon receipt.If to Lessor:BKEP Materials, L.L.C.6060 American Plaza Suite 600Tulsa OK 74135Phone: (918) 237-4000Fax: (918) 237-4001Attention: Chief Operating OfficerWith copy to:Chief Legal Officer18If to Lessee:Ergon Asphalt & Emulsions, Inc.2829 Lakeland Drive, Suite 2000Flowood, MS 39232Phone: (601) 933-3000Fax: (601) 933-3363E-mail: baxter.burns@ergon.comAttention: J. Baxter Burns, II, PresidentWith a copy to:Watson Heidelberg, PLLC2829 Lakeland Drive, Suite 1502Flowood, MS 39232Phone: (601) 939-8900Fax: (601) 932-4400E-mail: kwatson@whjpllc.comAttention: J. Kevin WatsonArticle 21. Termination .21.1 This Agreement may be terminated in accordance with the following provisions:(a) The Performing Party may terminate this Agreement following an Event of Default by the other Party, in accordancewith the provisions of Section 17.1 .(b) The Parties may terminate this Agreement by execution of a written agreement signed by authorized representatives ofboth Parties, in which event the termination shall be effective on the date specified in such agreement.21.2 Upon any termination or expiration of this Agreement, Lessee shall return the Facilities to Lessor in the condition in whichthe Facilities were immediately preceding the Commencement Date, normal wear and tear and insured casualty excepted. Lessee shallpeaceably surrender the Facilities, and, unless otherwise agreed to by the Parties, remove all asphalt, raw materials, and Product from theFacilities. In the event Lessee has not removed all asphalt, raw materials, tank heels, and Product on the date this Agreement is terminated orexpires, Lessee agrees to reimburse Lessor for the actual costs of such removal, which shall include the expense of any necessary cleaningand restoration to the previous condition, subject to normal wear and tear, of the Premises, plus a ten percent (10%) administrative fee.21.3 Each Party’s obligations under this Agreement shall end as of the effective date of its termination or expiration in accordancewith this Agreement; provided , however , that each Party shall remain liable to the other hereunder with respect to (a) any obligationsaccruing under this Agreement prior to the effective date of such termination, including any indemnification obligations provided hereunderor (b) as otherwise provided in this Agreement. Notwithstanding anything in this Agreement to the contrary, Articles 4, 9 (for the periodtherein specified), 11, 14 and 20 shall survive the expiration or termination of this Agreement.1921.4 Lessee shall vacate the Facilities no later than the termination of this Agreement. Notwithstanding Section 21.3 , if Lesseedoes not vacate the Facilities following termination of this Agreement, Lessee shall be deemed to be holding over and will become a tenant atsufferance and shall not constitute a renewal or extension for any further term. Under such tenancy at sufferance, the fees set forth in ExhibitB and charged to Lessee shall be increased to one hundred fifty percent (150%) of the values set forth in Exhibit B , prorated based on theactual number of holdover days and charged only with respect to the Facility or Facilities being held over. Such tenancy at sufferance shall besubject to every other applicable term, covenant and agreement contained in this Agreement. Nothing contained in this section shall beconstrued as consent by Lessor to any holding over by Lessee, and Lessee expressly reserves the right to require Lessee to surrenderpossession of the Facilities to Lessor as provided in this Agreement upon the expiration or other termination of this Agreement. Theprovisions of this Section 21.4 shall not be deemed to limit or constitute a waiver of any other rights or remedies of Lessor provided in thisAgreement or at law. If Lessee fails to surrender the Facilities upon the termination or expiration of this Agreement, in addition to any otherliabilities to Lessor accruing therefrom, Lessee shall protect, defend, indemnify and hold Lessor harmless from all loss, costs (includingreasonable attorneys’ fees) and liability resulting from such failure, including any claims made by any succeeding lessee founded upon suchfailure to surrender (excluding such lessee’s lost profits).Article 22. Subordination and Estoppel Certificate .22.1 This Agreement is subject and subordinate to all mortgages, deeds of trust, and related security instruments which may nowor hereafter encumber the Facility and to all renewals, modifications, consolidations, replacements, and extensions thereof and to eachadvance made or hereafter to be made thereunder. This subordination shall be selfoperative and no further instrument of subordination isrequired. In confirmation of such subordination, however, Lessee shall, at Lessor's request, execute promptly any appropriate certificate orinstrument that Lessor may request. In the event of the enforcement by the trustee or the beneficiary under any such mortgage or deed of trustof the remedies provided for by Applicable Law or by any such mortgage or deed of trust, Lessee will, upon request of any person or partysucceeding to the interest of said trustee or beneficiary as a result of such enforcement, automatically become the tenant of, and attorn to,such successor in interest without change in the terms or provisions of this Agreement; provided, however, that such successor in interestshall not be bound by: (i) any payment of Base Rental Fee for more than one (1) month in advance; or (ii) any amendment or modification ofthis Agreement made without the written consent of such trustee or such beneficiary or such successor in interest. Upon request by suchtrustee, beneficiary, or successor in interest, Lessee shall execute and deliver an instrument or instruments confirming the attornmentprovided for herein. Lessor shall use commercially reasonable efforts to provide to Lessee within thirty (30) days following the date of thisAgreement, nondisturbance agreements from Lessor's lenders in form and substance reasonably satisfactory to Lessee. Lessor shall likewiseprovide to Lessee non-disturbance agreements in form and substance reasonably satisfactory to Lessee from any successor or replacementlender(s) in connection with placement of any mortgage, deed of trust or similar encumbrance against the Leased Premises within thirty (30)days following the date such encumbrance is placed of record. Lessor acknowledges that Lessee's inventories may serve as collateral forLessee's financing and agrees to subordinate in writing any applicable landlord liens to the extent same may affect Lessee's inventory.22.2 At either Party’s request, the other Party will execute either an estoppel certificate or a three-party agreement among Lessor,Lessee, and any third party dealing with the requesting Party certifying to such facts (if true) and agreeing to such notice provisions and othermatters as such third party may reasonably require in connection with the business dealings of requesting Party and such third party.20Article 23. Reporting Requirements .23.1 Within fifteen (15) days after the end of each calendar month, Lessee shall deliver to Lessor a schedule showing the amountof all product by type delivered from the Facility (“ Volumes Report ”). In addition, the Volumes Report shall specifically identify thethroughput at the Facilities by asphalt cement, emulsions, modified emulsions, modified asphalt cement, interplant transfers, and otherProducts and any Throughput Charges that are payable pursuant to this Agreement.23.2 Within thirty (30) days after the end of each calendar quarter, Lessee shall deliver to Lessor a certification, signed by anauthorized officer of Lessee, that Lessee has paid all taxes (other than real property taxes, which shall be paid by Lessor and reimbursed byLessee in accordance with Exhibit B ) and utility payments for the prior quarter and that Lessee has otherwise kept the Premises free of allmortgages, deeds of trust, leases, subleases, easements, servitudes, and other encumbrances of any kind or nature.Article 24. Force Majeure .24.1 If either Party is unable to perform or is delayed in performing, wholly or in part, its obligations under this Agreement, otherthan the obligation to pay funds when due, as a result of an event of Force Majeure, that Party shall be excused from such performance andshall give the other Party prompt written notice of any event that is or, in the reasonable estimation of the affected party, could become anevent of Force Majeure with reasonably full particulars thereof. The obligations of the Party giving notice, so far as such obligations areaffected by the event of Force Majeure, will be suspended during, but not longer than, the continuance of the event of Force Majeurebeginning with the time that the event first occurs and continuing until the effects of the Force Majeure Event have been remedied. Theaffected Party must act with commercially reasonable diligence to overcome or remedy the effects of the event of Force Majeure and resumeperformance as quickly as possible. Once the event of Force Majeure and its effects are remedied, the affected Party shall notify the otherParty that the event of Force Majeure no longer affects such obligations.24.2 The requirement that any Force Majeure event be remedied with all reasonable diligence shall not require the settlement ofstrikes, lockouts, or other labor difficulty by the Party claiming excuse due to an event of Force Majeure contrary to its wishes.Article 25. Miscellaneous .25.1 Headings . The headings of the sections and subsections of this Agreement are for convenience only and shall not be used inthe interpretation of this Agreement.25.2 Amendment or Waiver . This Agreement may not be amended, modified, or waived except by written instrument executed byofficers or duly authorized representatives of the respective Parties. No waiver or failure of enforcement by any Party of any Default by anyother Party in the performance of any provision, condition, or requirement herein shall be deemed to be a waiver of, or in any manner arelease of the Defaulting Party from, performance of any other provision, condition, or requirement herein, nor deemed to be a waiver of, orin any manner a release of the Defaulting Party from, future performance of the same provision, condition, or requirement; nor shall anydelay or omission of any Performing Party to exercise any right hereunder in any manner impair the exercise of any such right or any likeright accruing to it thereafter.2125.3 Severability . Any provision of this Agreement that is prohibited or not enforceable in any jurisdiction shall, as to thatjurisdiction, be ineffective only to the extent of the prohibition or lack of enforceability without invalidating the remaining provisions of thisAgreement or affect the validity or enforceability of those provisions in another jurisdiction or the validity or enforceability of this Agreementas a whole.25.4 Entire Agreement and Conflict with Attachments . This Agreement (including Attachments) contains the entire and exclusiveagreement between the Parties with respect to the subject matter hereof, and there are no other promises, representations, or warrantiesaffecting it. The terms of this Agreement may not be contradicted, explained, or supplanted by any usage of trade, course of dealing, orcourse of performance. Any other representation, promise, statement, or warranty made by either Party or their agents that differs in any wayfrom the terms contained herein will be given no force or effect. In the case of any conflict between the body of this Agreement and any of itsAttachments, the terms contained in the Attachments will govern.25.5 Governing Law and Jurisdiction; Waiver of Jury Trial . This Agreement will be construed and governed by the laws of theState of Oklahoma except the choice of law rules of that State that may require the application of the laws of another jurisdiction. Exclusivejurisdiction and venue is agreed to be the state or federal courts within the State of Oklahoma. Lessee and Lessor hereby irrevocably waiveany right to a trial by jury with respect to any dispute regarding, breach of, or any enforcement of the terms and conditions of this Agreement.The prevailing party in any proceeding brought to enforce or interpret this Agreement shall be entitled to recover, in addition to other relief,such prevailing party’s expenses of litigation, including reasonable attorneys fees.25.6 Counterparts . This Agreement may be executed in any number of counterparts each of which, when so executed anddelivered (including by facsimile or electronic mail transmission), will be deemed original but all of which together will constitute one andthe same instrument. Delivery of an executed signature page of this Agreement in Portable Document Format (pdf) or by facsimiletransmission shall be effective as delivery of an executed original counterpart of this Agreement.25.7 Further Assurances . Subject to the terms and conditions of this Agreement, each of the Parties hereto will use commerciallyreasonable efforts to take, or cause to be taken, all action, and to do, or cause to be done, all things necessary under Applicable Laws andregulations to consummate the transactions contemplated by this Agreement.25.8 No Third-Party Beneficiaries . Nothing contained in this Agreement, expressed or implied, is intended or shall be construed toconfer upon or give to any Person other than the Parties hereto and their successors or permitted assigns, any rights or remedies under or byreason of this Agreement.25.9 No Strict Construction . The Parties to this Agreement have participated jointly in the negotiation and drafting of thisAgreement. In the event an ambiguity or question of intent or interpretation arises with respect to this Agreement, this Agreement shall beconstrued as if drafted jointly by the Parties, and no presumption or burden of proof shall arise favoring or disfavoring a Party by virtue of theauthorship of any of the provisions of this Agreement.2225.10 Binding Effect . Each and all of the covenants, terms, and conditions of this Agreement shall extend to and firmly bind thesuccessors, trustees, legal representatives, receivers, and assigns of the Parties as though the Parties were themselves bound.Article 26. Title to Leased Premises; Condition of Improvements .Lessor hereby represents and warrants to Lessee that it has good and marketable title to each Facility (good and marketable leaseholdtitle in the case of Underlying Leases) subject only to (i) the restrictions, covenants, conditions, easements, servitudes, liens and otherencumbrances to title to such Facility (collectively, “ Encumbrances ”) that are identified in the applicable Owner’s Policy of Title Insurancelisted on Exhibit C attached hereto; (ii) liens in favor of Lessor’s commercial lenders, including, but not limited to, Wells Fargo Bank,National Association as Administrative Agent, in connection with the Second Amended and Restated Credit Agreement dated as of May 11,2017 (as amended); (iii) taxes not yet due or payable or which are being contested in good faith, and mechanic’s, materialman’s, supplier’s,vendor’s or similar liens arising in the ordinary course of business securing amounts that are not delinquent or past due or that are beingcontested in good faith; and (iv) any other Encumbrances or title defects which do not, individually or in the aggregate, materially andadversely affect the value of the leasehold estate granted herein or the ability of Lessee to use the applicable Facility for the purposespermitted under this Agreement (collectively, the “ Permitted Encumbrances ”).Article 27. Quiet Enjoyment.Lessor covenants that if Lessee shall pay rent due hereunder and perform all of its obligations hereunder, Lessee shall, for the Termof this Agreement, freely, peaceably and quietly occupy and enjoy the full possession of the Leased Premises without interruption orhindrance by Lessor, its agents or employees.Article 28. Rights of First Refusal; Right of First Offer.28.1 Subject to the terms and conditions set forth below (including, without limitation, Section 28.3 ), if Lessor proposes or intendsto sell any Facility(ies) (the “ Term Offered Facilities ”) to a third party during the Term of this Agreement then Lessee shall have the rightto purchase the Term Offered Facilities (the “ Term First Refusal Right ”) on the following terms and conditions:(a) If Lessor executes a contract or letter of intent to sell the Term Offered Facilities to a Third Party, which transaction isexpected to close during the Term of this Agreement, Lessor shall provide Lessee with written notice setting forth the Term OfferedFacilities, the proposed sale price and other material terms and conditions upon which Lessor intends to sell the Term Offered Facilities to athird party (the “ Term ROFR Notice ”). Within 30 days after it receives the Term ROFR Notice (the “ Term ROFR Period ”), Lessee maydeliver written notice (the “ Term Exercise Notice ”) to Lessor that Lessee is exercising its Term First Refusal Right and will purchase theTerm Offered Facilities for the price and upon the terms and conditions contained in the Term ROFR Notice. If Lessee does not deliver theTerm Exercise Notice to Lessor during the Term ROFR Period, then Lessor shall thereafter be free to sell the Term Offered Facilities to athird party substantially on the terms and conditions contained in the Term ROFR Notice or pursuant to higher or more favorable terms andconditions.(b) Notwithstanding anything to the contrary contained herein, the Term First Refusal Right shall not apply to anymortgage of the Premises or the Facilities or any portion thereof to secure the repayment of borrowings by Lessor or any of its Affiliates. Aforeclosure sale by such lender shall not be a sale to which the Term First Refusal Right shall be applicable, and upon any such foreclosuresale the Term First Refusal Right shall terminate automatically and be of no further force or effect notwithstanding the existence of, or anyterm contained in, any non-disturbance agreement from Lessor’s lenders. In clarification23of the foregoing, after any such foreclosure sale, the Term First Refusal Right shall never apply. In the event of a foreclosure sale, to theextent that Lessor receives notice thereof, Lessor shall provide Lessee notice of such sale, including the date, time and place of sale, if knownby Lessor; such notice to be provided by Lessor within five (5) business days following Lessor’s receipt of such information, if any. As usedherein, “foreclosure sale” shall include a conveyance in lieu of foreclosure. It is the intention of the Parties that the Term First Refusal Rightbe subordinate to any mortgage presently encumbering the Premises and the Facilities.28.2 Subject to the terms and conditions set forth below (including, without limitation, Section 28.3 ), if Lessor proposes or intendsto sell or lease any Facility(s) (the “ Expiration Offered Facilities ”) commencing upon the expiration of the Term of this Agreement, thenLessor shall give written notice to Lessee no later than eighteen (18) months prior to the expiration of the Term of this Agreement (the “Expiration ROFO Notice ”). Within five (5) business days after the receipt of the Expiration ROFO Notice, Lessee may elect to exercise itsrights of first offer by delivering a notice of exercise (“ Expiration Exercise Notice ”) to Lessor. During the 30-day period following receiptof the Expiration Exercise Notice (the “ Expiration ROFO Period ”), Lessee shall have the right to make an offer to Lessor for the purchaseor lease, as applicable, of such Expiration Offered Facilities (the “ Initial Offer ”). Lessor shall consider the Initial Offer and any other offersfor any or all of the Expiration Offered Facilities in good faith and shall select the offer(s) that Lessor deems most attractive in its solediscretion, or no offer. If Lessor selects an offer(s) other than the Initial Offer or no offer, it shall give written notice to Lessee that it has notselected the Initial Offer (the “ Rejection Notice ”). Lessee shall have the right to submit a revised offer (the “ Last Look Offer ”) to Lessorfor the Expiration Offered Facilities within five (5) business days after receipt of the Rejection Notice. Lessor shall consider the Last LookOffer and any other offers for any or all of the Expiration Offered Facilities in good faith and shall select the offer(s) that Lessor deems mostattractive in its sole discretion, or no offer. For the avoidance of doubt, Lessor shall not be required to provide, and Lessee shall not have theright to know, the terms or conditions of any other offer for any or all of the Expiration Offered Facilities. If Lessee does not deliver (i) theExpiration Exercise Notice to Lessor within five (5) business days after receipt of the Expiration ROFO Notice or (ii) the Initial Offer or theLast Look Offer to Lessor within the time periods specified above, then Lessor shall thereafter be free to sell or lease any or all of theExpiration Offered Facilities to a third party or parties on such terms and conditions as it may deem appropriate.28.3 The obligation of Lessor to provide the Term ROFR Notice, the Expiration ROFO Notice and the corresponding rights ofLessee contained in this Section 28 , including, without limitation, the Term First Refusal Right and the right to make the Initial Offer and theLast Look Offer, shall only apply if Lessee is not in default under this Agreement. In addition, the rights and obligations in this Section 28 ,including, without limitation, the Term First Refusal Right, shall not apply to any proposed sale or lease of more than two-thirds of the totalasphalt facilities owned or leased by Lessor in a single transaction or a series of related transactions (collectively, a “ Transfer ”) or to theproposed sale or lease of any Facility in connection with any such Transfer.24Article 29. Memorandum of Lease.Promptly upon execution of this Agreement, Lessor and Lessee shall execute and deliver a memorandum of this Agreement in formreasonably satisfactory to Lessor and Lessee for recording in the land records of the jurisdictions in which the Facilities are located.[SIGNATURE PAGE FOLLOWS.]25This Agreement 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/ Mark A. Hurley Name:Mark A. Hurley Title:Chief Executive Officer BKEP ASPHALT, L.L.C. By:/s/ Mark A. Hurley Name:Mark A. Hurley Title:Chief Executive Officer LESSEE ERGON ASPHALT & EMULSIONS, INC. By:/s/ J. Baxter Burns, II Name:J. Baxter Burns, II Title:PresidentSignature page to Lessee Operated Facilities Lease AgreementEXHIBIT A-1DESCRIPTION OF FACILITIES/PREMISESAUSTIN, TXBEING 3.29 ACRES OF LAND, MORE OR LESS, OUT OF AND A PART OF TRACT 5-B, OF SUBDIVISION OF THE MRS. A.B.PAYTON ESTATE, A PORTION OF THE JAMES P. WALLACE LEAGUE, IN TRAVIS COUNTY, TEXAS, ACCORDING TO THEMAP OR PLAT THEREOF RECORDED IN/UNDER BOOK 3, PAGE 259 OF THE PLAT RECORDS OF TRAVIS COUNTY, TEXAS,SAID 3.29 ACRE TRACT BEING OUT OF 5.58 ACRES AS DESCRIBED IN/UNDER VOLUME 2274, PAGE 504 OF THE REALPROPERTY RECORDS OF TRAVIS COUNTY, TEXAS, SAID 3.29 ACRE TRACT BEING MORE PARTICULARLY DESCRIBED BYMETES AND BOUNDS AS FOLLOWS, TO-WIT:BEGINNING AT A ½ INCH IRON ROD FOUND ON THE WESTERLY RIGHT-OF-WAY LINE OF THE MISSOURI PACIFICRAILROAD, SAID POINT ALSO BEING THE NORTHEAST CORNER OF LOT THREE (3) OF THE ATRIUM, A SUBDIVISIONRECORDED IN VOLUME 83, PAGE 125C OF THE PLAT RECORDS OF TRAVIS COUNTY, STATE OF TEXAS; THENCE NORTH61° 07’ 47” WEST, ALONG THE NORTHERLY LINE OF SAID LOT 3 (PLAT CALL IS NORTH 61° 06’ 34” WEST), A DISTANCE OF403.53 FEET (PLAT CALL IS 403.29 FEET), TO A FOUND 1/2 INCH IRON ROD AT THE NORTHWEST CORNER OF SAID LOT 3,SAID NORTHWEST CORNER ALSO BEING IN THE EASTERLY RIGHT-OF-WAY LINE OF MO-PAC EXPRESSWAY; THENCENORTHEASTERLY ALONG SAID EASTERLY RIGHT-OF-WAY LINE, ALONG A CURVE TO THE RIGHT, WITH A CHORDBEARING OF NORTH 41° 58’ 04” EAST, A CHORD DISTANCE OF 358.93 FEET, A RADIUS OF 627.07 FEET, AND AN ARCDISTANCE OF 364.01 FEET TO A FOUND TEXAS DEPARTMENT OF TRANSPORTATION (TXDOT) BRASS MONUMENT;THENCE CONTINUING ALONG SAID EASTERLY RIGHT-OF-WAY LINE, NORTH 58° 37’ 22” EAST, A DISTANCE OF 97.65FEET TO A FOUND 3/4 INCH IRON ROD ON THE SOUTHERLY LINE OF A TRACT CONVEYED TO JOHN JOSEPH, RECORDEDIN VOLUME 3365, PAGE 1163 OF THE DEED RECORDS OF TRAVIS COUNTY, STATE OF TEXAS, FROM WHICH BEARS AFOUND 3/4 INCH BOLT NORTH 58° 38’ 17” EAST, A DISTANCE OF 84.82 FEET; THENCE SOUTH 61° 11’ 45” EAST, ALONGSAID SOUTHERLY LINE, A DISTANCE OF 204.56 FEET TO A FOUND 1/2 INCH IRON ROD IN THE WESTERLY RIGHT-OF-WAY LINE OF THE MISSOURI PACIFIC RAILROAD, FROM WHICH BEARS A FOUND 1/2 INCH BOLT, NORTH 19° 49’ 45”EAST, A DISTANCE OF 75.00 FEET; THENCE SOUTH 19° 49’ 34” WEST, ALONG SAID WESTERLY RIGHT-OF-WAY LINE, ADISTANCE OF 440.07 FEET TO THE POINT OF BEGINNING.DODGE CITY, KSLots 1, 2, 3, 4, 5 and 6, Block 1, Gremar Addition, a subdivision of part of the North Half (N/2) of the Northwest Quarter (NW/4) of Section32, Township 26 South, Range 24 West of the 6th P.M., Ford County, KansasHALSTEAD, KSLots 1 and 2, Block 1, Industrial Park, an addition to the City of Halstead, Harvey County, Kansas.LAWTON, OKLot 1, Block 3, Lawton Industrial Park Part II, an addition to the City of Lawton, Oklahoma, Comanche County, Oklahoma, which Lot isdescribed in the Warranty Deed recorded in Book 1450, page 38, as follows:A tract of land described as beginning at a point on the south right of way line of the Burlington Northern Railroad, said point being 3,216.47feet North 00°24’28” East and 977.856 feet North 85°01’03.47” West of the Southeast Corner of the Southwest Quarter of Section 31,Township 2 North, Range 12 West, I.M., Comanche County, Oklahoma;THENCE South 00°21’22” West a distance of 382 feet;THENCE North 89°38’38” West a distance of 320 feet;THENCE North 00°21’22” East a distance of 215 feet;THENCE North 33°59’11.39” West a distance of 261.236 feet;THENCE in an easterly direction along a curve to the left having a radius of 5779.578 feet a distance of 354.065 feet;THENCE South 85°01’03.47” East a distance of 115.935 feet to the point of beginning.LITTLE ROCK, ARPart of the West half (W 1/2) of the Northwest Quarter (NW 1/4), Northeast Quarter (NE 1/4), Section Thirty-Five (35), Township 1 North,Range 12 West, Pulaski County, Arkansas, more particularly described as follows: starting at the Northwest corner of said NE 1/4, Section35; thence South 0 degrees 5 minutes West 326.95 feet deeded (South 1 degrees 45 minutes 29 seconds West 326.95 feet measured) along theNorth-South center line of Section 35 to the point of beginning; thence South 89 degrees 53 minutes East 659.8 feet deeded (South 88 degrees12 minutes 50 seconds East 659.80 feet measured) to a point; thence South 0 degrees 03 minutes East 328.2 feet deeded (South 1 degrees 45minutes 15 seconds West 328.20 feet measured) to a point; thence North 89 degrees 47 minutes West 660.6 feet deeded (North 88 degrees 06minutes 20 seconds West 659.82 feet measured) to a point; thence North 0 degrees 05 minutes East 326.95 feet deeded (North 1 degrees 45minutes 29 seconds East 326.95 feet measured) along the North-South center line of Section 35, to the point of beginning.MEMPHIS (EM), TNPARCEL 1:Lots 109 and 110 of the Memphis and Shelby County Port Commission’s Industrial Subdivision, as shown on record in Plat Book 17, Page 2,in the Register’s Office of Shelby County, Tennessee, to which plat reference is hereby made for a more particular description of saidproperty.PARCEL 2:Lot 111 of the Memphis and Shelby County Port Commission’s Industrial Subdivision, as shown on record in Plat Book 17, Page 2, in theRegister’s Office of Shelby County, Tennessee, to which plat reference is hereby made for a more particular description of said property.SALINA, KSTRACT A: A tract in the Northwest Quarter (NW 1/4) of the Northeast Quarter (NE 1/4) of Section Eleven (11), Township Fourteen (14)South, Range Three (3) West of the 6th P.M., Saline County, Kansas, which is described as follows:Beginning at the Northwest corner of said NE/4; thence South along the West line of said NE/4, 378.92 feet; thence East 93.61 feet; thenceNorth 122.22 feet; thence S88°25’00”E, 621.84 feet to the West Right-of-Way Line of Dry Creek Channel; thence N05°22’00”E 272.80 feetto the North line of said NE/4; thence N89°49’26” W along said North line 740.73 feet to the point of beginning; said property including allor a substantial portion of portion of Lot Five (5), Block One (1), Final Plat of Hixson-Lehenbaurer Subdivision PUD, Saline County,Kansas.As measured:Beginning at the Northwest corner of said NE/4; thence South along the West line of said NE/4, 378.69 feet; thence East 93.66 feet; thenceNorth 122.11 feet; thence S88°31’47”E, 621.79 feet to the West Right-of-Way line of Dry Creek Channel; thence N05°24’37”E, 271.50 feetto the North line of said NE/4; thence N89°49’26”W along said North line 741.03 feet to the point of beginning; said property including all ora substantial portion of Lot Five (5), Block One (1), Final Plat of Hixson-Lehenbaurer Subdivision PUD, Saline County, Kansas.TRACT B: A tract of land in the South Half of Section 2, Township 14 South, Range 3 West of the 6th Principal Meridian in Saline County,Kansas more particularly described as follows:Beginning at the SW Corner of the SE 1/4 of Section 2, Township 14 South, Range 3 West; thence east along the south line of said SE 1/4 ofan assumed bearing of N89°15’14” E a distance of 1270.13 feet to the center of the old channel of Dry Creek; thence along center of thechannel of Dry Creek on the following described courses; 1. N02°33’00”E, 37.00 feet; 2. N14°02’00”W, 50.00 feet; 3. N29°34’00”W, 60.00feet; 4. N54°55’00”W, 47.00 feet; 5. N58°46’00”W, 46.00 feet; 6. N87°32’00”W, 59.00 feet; 7. S76°50’00”W, 32.00 feet; 8. S68°24’00”W,120.00 feet; 9. N59°38’00”W, 45.00 feet; 10. N33°27’00”W, 184.00 feet; 11. N16°40’00”E, 114.00 feet; 12. N06°13’00”W, 112.00 feet; 13.N30°57’00”E, 47.00 feet; 14. N67°30’00”E, 57.00 feet; 15. N38°57’00”E, 43.00 feet; 16. N37°03’00”W, 38.00 feet; 17. N64°41’00”W,96.00 feet; 18. N46°53’00”W, 54.00 feet; 19. N13°37’00”W, 87.00 feet; 20. N20°27’00”E, 56.00 feet; 21. N57°56’00”E, 45.00 feet; 22.N78°05’00”E, 54.00 feet; 23. S79°04 ’00”E, 70.00 feet; 24. S71°11’00”E, 170.00 feet; 25. S74°29’00”E, 72.00 feet ; 26. S23°36’00”E, 52.00feet; 27. S01°43’00”W, 40.00 feet; 28. S13°54’00”W, 148.00 feet; 29. S05°18’00”E, 62.00 feet; 30. S47°00’00”E, 45.00 feet; 31.S71°48’00”E, 87.00 feet; 32. S88°10 ’00”E, 40.00 feet; 33. N49°00’00”E, 31.00 feet; 34. N39°20’00”E, 59.00 feet; 35. N00°18’00”E, 45.00feet; 36. N03°28’00”W, 121.00 feet; 37. N10°48 ’00”E, 102.00 feet; 38. N10°12’00”E, 120.00 feet; 39. N04°06’00”W, 24.71 feet; thenceleaving the center of the channel of Dry Creek S89°15’14”W, 1714.94 feet to a point on the Easterly right-of-way of the Union PacificRailroad; thence S11°37’44”E, along said Easterly right-of-way 962.19 feet to a point on the South line of the SW 1/4 of said Section 2;thence N89°36’26”E, 108.58 feet back to the Point of Beginning.GARDEN CITY, GEORGIAALL that certain lot, tract or parcel of land situated, lying and being in Chatham County, Georgia, being known as Lot ‘B’, Koch Fuels, aportion of the Foundation Tract and being more particularly described as follows:Commencing at a point at the intersection of the northern right-of-way line of Foundation Road and the eastern right-of-way of U.S. Highway17 thence along a paved road (Foundation Road) in a northeasterly direction 2545 feet more or less to a point on the northern right-of-way ofNorfolk Southern Railroad; thence along said right-of-way North 48°31’41” East a distance of 183.49 feet to an iron rod, the Point ofBeginning; thence departing said right-of-way North 00°29’22” West a distance of 281.37 feet to a “PK” Nail; thence North 48°31 ‘36” Easta distance of 890.55 feet to a railroad iron; thence South 41 ‘28’55” East a distance of 281.37 feet to a railroad iron on the northern right-of-way line of Norfolk Southern Railroad; thence along said right-of-way South 48°31 ‘41” West a distance of 887.05 feet to an iron rod, thesaid Point of Beginning.Said parcel contains 250,075.26 square feet (5.74 acre).The parcel as a whole is bounded on the west by lands now or formerly owned by Carroll & Carroll, Inc., on the north by lands now orformerly owned by Southern Region Industrial Realty, Inc., on the east by lands now or formerly owned by Savannah EconomicDevelopment, and on the south by Norfolk Southern Railroad. This is the same property described in Exhibit A in the title commitment50214.04 by LandAmerica Lawyers Title dated February 24, 2005.TOGETHER WITH easement rights set forth in the following:a. Access Easement Agreement by and between Carroll & Carroll, Inc. and Koch Materials Company, dated December 11, 1995, filedJanuary 30, 1996, recorded in Deed Book 176-V, Page 632, Chatham County records; andb. Right of Way Agreement by and between Imbrie Securities Company, Ltd. Mexican Petroleum Corporation of Georgia and SouthernBuilding Products Corporation, dated September 20, 1929, recorded in Deed Book 25-W, Page 491, aforesaid records.Exhibit A-2RAIL LEASESDodge City, KansasLease of Land (Short Term) (Contract No. 157011) between The Atchison, Topeka and Santa Fe Railway Company, predecessor in interestto The Burlington and Northern Santa Fe Railway Company, and Kansas Emulsions, Inc., predecessor in interest to SemMaterials, L.P., datedFebruary 12, 1979, as amended.Memphis (EM), TennesseeLease between The Memphis Grain and Hay Association and Southern States Asphalt Co., a division of Ashland Oil, Inc., predecessor ininterest to SemMaterials, L.P., dated April 24, 1989.EXHIBIT A-3UNDERLYING LEASESParsons, TNMaster Lease:Lease Agreement dated effective as of May 1, 2003 between Nancy Ivey, Joe T. Burton,James H. Burton, Sarah Vise, Lori Duke, Kirn Parks (collectively, "Master Lessor") andKoch Materials CompanyAmendment to Lease Agreement dated effective as of May 1, 2003 between Nancy Ivey, Joe T. Burton, James H. Burton, Sarah Vise, LoriDuke, Kim Parks and Koch Materials CompanyMemorandum of Lease dated September 27, 2005 executed by SernMaterials, L.P., recorded in Book 209, Page 730 of the Register's Officeof Decatur County, TennesseeAssignment and Assumption of Lease Agreement dated February 20, 2008, between SernMaterials, L.P. and SernMaterials Energy Partners,L.L.C., recorded in Book 240, Page 206 of the Register's Office of Decatur County, TennesseeAssignment and Assumption of Retained Leasehold Rights, effective March 31, 2009, between SernMaterials, L.P. and SernMaterials EnergyPartners, L.L.C., recorded in Book 249, Page 129 of the Register's Office of Decatur County, TennesseeFacility Legal Description:Tract 1:Land lying in the Seventh Civil District, Decatur County, Tennessee, North of Tennessee State Highway 100 and West of the TennesseeRiver and being more particularly described as follows:Beginning at a 1/2 inch iron pin (found), said pin being the Southeasterly comer of the Sarah Vise property as described in Deed Book 168Page 901 and also being in the Northerly right-of-way for Tennessee State Highway 100, right of way varies; thence with the Southerlyboundary of said Vise property North 69 Degrees 00 Minutes 46 Seconds West a distance of 100.06 feet to a PK nail (found); thencecontinuing with said Vise boundary North 26 Degrees 22 Minutes 24 Seconds East a distance of 100.06 feet to an iron pin (found) said pinbeing the Northwesterly comer of said Vise and also being the Northeasterly comer of the A. A. Burton property as shown on the taxassessor's map 54 parcel 14 and being the True Point of Beginning; thence with said Burton property North 69 Degrees 58 Minutes 07Seconds West a distance of 100.00 feet being the Northwesterly comer of said Burton and also being in the boundary of the Joe Burton, et alproperty as described in Deed Book 65 Page 131; thence continuing with said Burton property North 69 Degrees 58 Minutes 07 SecondsWest a distance of 224.06 feet to an iron pin (set) capped and stamped Southern States Survey hereinafter iron pin (set); thence South 21Degrees 41 Minutes 00 Seconds West a distance of 100 feet to an iron pin (set) said pin being in the Northerly right-of-way for TennesseeState Highway 100, right of way varies; North 70 Degrees 03 Minutes 07 Seconds West a distance of 70.00 feet to an iron pin (set) said pinbeing the Southwesterly comer of the herein described Lease tract; thence with said Lease boundary North 15 Degrees 03 Minutes 00Seconds East a distance of 792.29 feet to an iron pin (found) said pin being the Northwesterly comer of said Lease tract; thence South 84Degrees 59 Minutes 30 Seconds East a distance of 354.54 feet to an iron pipe(found) said pipe being located in the westerly boundary of the David W. Reed property as described in Deed Book 95 Page 361 and alsobeing the Northeasterly comer of said Lease Tract; thence with the westerly boundary of said Reed property South 01 Degrees 01 Minutes 00Seconds West a distance of 414.44 to an angle iron post (found) said post being the Southwesterly corner of said Reed property and alsobeing the Northwesterly comer of the U.S. T.V.A. property as shown on the Kentucky Reservation Map 208-D; thence with the Westerlyboundary of said T.V.A. property South 01 Degrees 01 Minutes 00 Seconds West 305.49 feet to an iron pin (set); thence continuing with saidT.V.A. property South 26 Degrees 19 Minutes 52 Seconds West a distance of 102. 77 feet to an iron pin (found) said pin being theNortheasterly comer of said Sarah Vise property; thence with the Northerly boundary of said Vise property North 69 Degrees 00 Minutes 53Seconds West a distance of 99.98 feet to the Point of Beginning and containing 7.84 acres more or less.Tract 2:Land lying in the Seventh Civil District, Decatur County, Tennessee, North of Tennessee State Highway 100 and West of the TennesseeRiver and being more particularly described as follows:Beginning at a 1/2 inch iron pin (found), said pin being the Southeasterly comer of the Sarah Vise property as described in Deed Book 168Page 901 and also being in the Northerly right-of-way for Tennessee State Highway 100, right of way varies; thence with the Southerlyboundary of said Vise property North 69 Degrees 00 Minutes 46 Seconds West a distance of 100.06 feet to a PK nail (found) said nail beingthe Southeasterly comer of the A. A. Burton property as shown on the tax assessor's map 54 parcel 14 and also being the True Point ofBeginning; thence with said Burton property North 70 Degrees 03 Minutes 41 Seconds West a distance of 100.02 feet to an iron pin (found)said pin being the Southeasterly comer of the Joe Burton, et al property as described in Deed Book 65 Page 131; thence with said Burtonproperty the following two calls both to iron pins (set) capped and stamped Southern States Survey, North 70 Degrees 03 Minutes 41 SecondsWest a distance of 215.87 feet and North 21 Degrees 41 Minutes 00 Seconds East a distance of 100.00 feet; thence South 69 Degrees 58Minutes 07 Seconds East a distance of 224.06 feet to the Northwesterly comer of said A. A. Burton property; thence South 69 Degrees 58Minutes 07 Seconds East a distance of 100.00 feet to an iron pin (found) at the Northwesterly comer of said Vise property; thence South 26Degrees 22 Minutes 24 Seconds West a distance of 100.06 feet to the Point of Beginning and containing 0.73 acres more or less.Being a portion of the same property in which Ethel Burton conveyed a life estate in 1 /2 undivided interest to A. A. Burton, remainder to JoeTinker Burton, Houston Burton, Betty Burton Laster and Nancy Burton Ivey, but reserving unto herself a life estate interest by Deed ofrecord in Book 65, Page 131, Register's Office for Decatur County, Tennessee. Also being a portion of the same property in which EthelBurton conveyed a life estate in 1/2 undivided interest to Carmon McMurry, remainder to Edward McMurry and Billie McMurry Vise, butreserving unto herself a life estate interest by Deed ofrecord in Book 65, page 137, said Register's Office The said Betty Burton Laster has since died. A Quitclaim Deed from Jerry Laster to LoriDuke and Kim Parks was recorded in Book 184, page 679, said Register's Office. The said Billie McMurry Vise has since died and her LastWill and Testament recorded in Book 168, page 901, said Register's Office lists Sarah Vise as her sole heir.Tract 3:Land lying in the Seventh Civil District, Decatur County, Tennessee, North of Tennessee State Highway 100 and West of the TennesseeRiver and being more particularly described as follows:Beginning at a 1/2 inch iron pin (found), said pin being the Southeasterly corner of the Sarah Vise property as described in Deed Book 168Page 901 and also being in the Northerly right-of-way for Tennessee State Highway 100, right of way varies; thence with the Southerlyboundary of said Vise property North 69 Degrees 00 Minutes 46 Seconds West a distance of 100.06 to a PK nail (found) said nail being theSoutheasterly corner of the A. A. Burton property as shown on the tax assessor's map 54 parcel 14; thence with said Burton property North 26Degrees 22 Minutes 24 East a distance of 100.06 feet to an iron pin (found) in the southerly boundary of the Joe Burton property as describedin Deed Book 65 Page 131; thence with said Burton property South 69 Degrees 00 Minutes 53 East a distance of 99.98 feet to an iron pin(found) said pin being the Southwesterly corner of the U.S. T.V.A. property as shown on the Kentucky Reservation Map 208-D; thence South26 Degrees 19 Minutes 52 West a distance of 100.06 feet to the Point of Beginning and containing 0.23 acres more or less.Being a portion of the same property conveyed to Carmon McMurry, reserving a life estate in Ethel Burton, by Deed of record in Book 65,Page 138, Register's Office for Decatur County, Tennessee.El Dorado, KSMaster LicenseLicense dated as of July 12, 1985 between the Atchison, Topeka and Santa Fe Railway Company and Kansas Emulsions, Inc.Assignment Contract dated December 26, 1986 between the Atchison, Topeka and Santa Fe Railway Company, Kansas Emulsions, Inc., andBituminous Materials Company, Inc.Consent to Sublicense dated December 26, 1986 between the Atchison, Topeka and Santa Fe Railway Company, Bituminous MaterialsCompany, Inc., and Riffe Petroleum CompanySupplemental Agreement dated June 3, 1987 between the Atchison, Topeka and Santa Fe Railway Company and Bituminous MaterialsCompany, Inc.Letter Agreement dated March 1, 1988 between the Atchison, Topeka and Santa Fe Railway Company and Elf Asphalt, Inc.Letter Agreement dated February 24, 1993 between the Atchison, Topeka and Santa Fe Railway Company and Elf Asphalt, Inc.Lease Assignment and Assumption Agreement, dated 2005, by and among Koch Materials, LLC, SemMaterials, L.P., and the Atchison,Topeka and Santa Fe Railway CompanyAssignment and Assumption of Lease Agreement dated as of February 20, 2008 between SemMaterials, L.P., SemMaterials Energy partners,L.L.C. and the Atchison, Topeka and Santa Fe Railway CompanyAssignment and Assumption of Retained Leasehold Rights, effective March 31, 2009, between SemMaterials, L.P. and SemMaterials EnergyPartners, L.L.C.Facility Legal DescriptionA tract of land located in the Railroad right-of-way in a portion of in the West Half of the SW1/4 of Section 36, Township 25, Range 5, Eastof the 6thP.M., Butler County, Kansas, being more particularly described as follows:Commencing at the North right-of-way line of Track No. 39 and the East right-of-way line of Oak Street; thence S 00°00'00" W, along saidEast right-of-way line, a distance of 85.00 feet to the Point of Beginning; thence S 69°12'21" E, a distance of 282.35 feet; thence N 85°16'45"E, a distance of 195.00 feet; thence N 11 °14'23" W, a distance of 64.00 feet to a point approximately 9 feet South of the centerline of TrackNo. 39; thence along a curve to the left, having a radius of 1151.44 feet, an arc length of 511.00 feet, and a chord bearing and distance N72°06' 17" E, 506.82 feet; thence S 33°35' 17" E, a distance of 136.00 feet to a point approximately 9 feet West of the centerline of the TrackNo. 46; thence S 29°08'37" W a distance of 45.36 feet; thence along a curve to the left, having a radius of 1023.07 feet, an arc length of208.42 feet, and a chord bearing and distance of S 20°52'31" W, 208.14 feet; thence a curve to the left, having a radius of 4159.36 feet, an arclength of 133.10 feet, a chord bearing a distance of S 16°14'49" W, 133.10 feet; thence N 89°26'58" W, a distance of 448.00 feet; thence N55°48'40" W, a distance of 510.00 to the East right-of-way line of Oak Street; thence N 00°00'00" E, along said right-of-way line, a distanceof 50.00 feet to the Point of Beginning. Containing 5.61 acres.Catoosa, OKMaster LeaseLease Agreement dated November 1, 2001 between the City of Tulsa-Rogers County Port Authority ("Master Lessor") and Koch MaterialsCompanyAs evidenced by: Memorandum of Lease, recorded in Book 1967, Page 862 of the records of Rogers County, OklahomaLease Assignment and Assumption Agreement dated as of May 31, 2005 between Koch Materials, L.L.C., SemMaterials, L.P. and the City ofTulsa-Rogers County Port AuthorityFirst Amendment of Lease Agreement dated as of November 1, 2006 between SemMaterials, L.P. and the City of Tulsa-Rogers County PortAuthorityAssignment and Assumption of Lease Agreement dated as of February 20, 2008, among SemMaterials, L.P., SemMaterials Energy Partners,L.L.C. and City of Tulsa-Rogers County Port Authority, filed July 22, 2008, recorded in Book 1967, Page 875 of the records of RogersCounty, OklahomaAssignment and Assumption of Retained Leasehold Rights dated effective as of March 31, 2009, between SemMaterials, L.P. andSemMaterials Energy Partners, L.L.C., recorded in Book 202, Page 522 of the records of Rogers County, OklahomaFacility Legal DescriptionA tract of land in Section 6, Township 20 North, Range 15 East of the Indian Base and Meridian, Rogers County, Oklahoma, according to theU.S. Government Survey thereof, more particularly described as follows, to wit:Beginning at a point 13.80 feet due West and 3,564.35 feet due North of the Southeast comer of said Section 6; thence due West a distance of517.64 feet. Thence on a curve to the left having a radius of 1,617.39 feet, a distance of 32.36 feet; thence N 00° 13' 19" W a distance of400.32 feet; thence due East a distance of 550.00 feet; thence S 00° 13' 19" E a distance of 400.00 feet to the point of beginning.Ardmore, OKMaster Lease #1Lease dated as of February 3, 2004 between Bacon Incorporated and Koch Materials CompanyMemorandum of Lease executed by SemMaterials, L.P. dated February 19, 2008Assignment and Assumption of Lease Agreement dated February 20, 2008 executed by SemMaterials, L.P. in favor of SemMaterials EnergyPartners, L.L.C.Assignment and Assumption of Retained Leasehold Rights dated effective as of March 31, 2009, between SemMaterials, L.P. andSemMaterials Energy Partners, L.L.C.Facility Legal Description #1Tract 2, Lots 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 32, 33, 34, 35, 36, 37, 38 and 39, all in Block 20, Industrial Addition of theCity of Ardmore; Carter County, State of Oklahoma, according to the recorded plat thereof.Master Lease #2Lease dated as of July 29, 1983 between Margaret Banker Bacon, O.G. Bacon, III, Jane Bacon Reddick, and Riffe Petroleum CompanyFirst Amendment to Lease dated as of January 1, 1990 between O.G. Bacon, III, Jane Bacon Reddick, and Elf Asphalt, Inc.Second Amendment to Lease dated as of December 15, 1993 between O.G. Bacon, III, Jane Bacon Reddick, and Koch Materials CompanyThird Amendment to Lease dated as of January 1, 1999 between O.G. Bacon, III, Jane Bacon Reddick, and Koch Materials CompanyFourth Amendment to Lease dated as of January 1, 2004 between O.G. Bacon, III, Jane Bacon Reddick, and Koch Materials CompanyMemorandum of Lease executed by SemMaterials, L.P. dated February 19, 2008Assignment and Assumption of Lease Agreement dated February 20, 2008 executed by SemMaterials, L.P. in favor of SemMaterials EnergyPartners, L.L.C.Assignment and Assumption of Retained Leasehold Rights dated effective as of March 31, 2009, between SemMaterials, L.P. andSemMaterials Energy Partners, L.L.C.Facility Legal Description #2Tract 1, Lots 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30 and 31 all in Block 20, Industrial Addition to the City of Ardmore; Carter County,State of Oklahoma, according to the recorded plat thereofMaster Lease #3Lease dated as of February 3, 2004 between Bacon Incorporated and Koch Materials CompanyMemorandum of Lease executed by SemMaterials, L.P. dated February 19, 2008Assignment and Assumption of Lease Agreement dated February 20, 2008 executed by SemMaterials, L.P. in favor of SemMaterials EnergyPartners, L.L.C.Assignment and Assumption of Retained Leasehold Rights dated effective as of March 31, 2009, between SemMaterials, L.P. andSemMaterials Energy Partners, L.L.C.Facility Legal Description #3Tract 2, Lots 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 32, 33, 34, 35, 36, 37, 38 and 39, all in Block 20, Industrial Addition of theCity of Ardmore; Carter County, State of Oklahoma, according to the recorded plat thereof.Exhibit BFeesBase Rental Fee:With respect to Facilities under this Agreement, for each Contract Year Lessee shall pay to Lessor a base rental fee (the “ Base Rental Fee ”)equal to a total of $*** , as adjusted as provided in this Exhibit B. The Base Rental Fee shall be payable in equal monthly installments. TheBase Rental Fee for all Facilities shall be payable in advance on or before the first day of each month, commencing on January 1, 2019 andshall be prorated for any partial month during the Term.Lessor acknowledges that on December 21, 2018, Lessee prepaid the Base Rental Fee for the months of January, February and March, 2019,in the amount of $***, and property taxes totaling $***. Additionally, Lessee has paid to Lessor upon execution of this Agreement, the sumof $*** in prepayment of the Base Rental Fee for the months of April, May, June, July, August and September, 2019. These paymentsrepresent a discounted prepayment of Base Rental Fees for the months indicated and are non-refundable in the event of termination of thisAgreement prior to date through which payments have been made.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.Minimum Incentive Throughput Fee : If, in any Contract Year, Lessee fails to produce, handle, sell, or deliver at least *** tons of Product(“ Minimum Throughput Quantity ”) at the Facilities, Lessee shall pay to Lessor a fee (" Minimum Throughput Charge ") representing thedifference between the Minimum Throughput Quantity and the amount of Product actually handled, produced, sold, or delivered from theFacilities during such Contract Year (“ Actual Throughput ”). The Minimum Throughput Charge shall be computed by subtracting theActual Throughput from the Minimum Throughput Quantity, and multiplying that difference by $***/ton. Lessor shall calculate theMinimum Throughput Charge on or before the thirtieth (30th) day following the end of such Contract Year and shall issue an invoice toLessee therefor.Excess Throughput Charge:An excess throughput fee (“ Excess Fee ”) will be applied to all Products handled, produced, sold, or delivered exceeding the MinimumThroughput Quantity at the Facilities (“ Excess Throughput Quantity ”) during the Contract Year and each subsequent Contract Year. TheExcess Fee shall be calculated as set forth in the following table:Excess Throughput Quantity (> Minimum Throughput Quantity)Fee (per ton) for such ThroughputThroughput of *** to *** tons$***Throughput of *** to *** tons$***Throughput > *** tons$***To illustrate such calculations, if Lessee handles a throughput of *** tons during any month, Lessee would owe a total of $*** as its ExcessFee, calculated: ($*** x *** tons) + ($*** x *** tons) +_($*** x *** tons)For purposes of this Agreement, “ Contract Year ” means a period of 365 consecutive days commencing on January 1, 2019 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.In the event that the terminal located in Austin, Texas is removed from coverage under this Agreement, Lessee and Lessor agree to deduct$***, as adjusted as set forth in this Attachment A, from the Base Rental Fee and to make a proportionate adjustment to MinimumThroughput Quantity consistent with past practice. If the removal of Austin occurs at other than the end of a Calendar Year, then the amountto be deducted from the Base Rental Fee shall be reduced in proportion with the number of days that have elapsed in such Calendar Year.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, 2020 and every January 1 st 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.In no event shall any of the fees de-escalate. The component of the Base Rental Fee attributable to the Memphis, Tennessee terminal shall notbe escalated as set forth in this paragraph unless such terminal is used at any time during a Contract Year, in which case the componentattributable to Memphis shall be escalated on January 1 of the year following such Contract Year.InvoicesCustomer shall pay the Base Rental Fee outlined in this Exhibit B in advance each Month based upon the then-current Base Rental Fee. Forany periods less than one full calendar month, the monthly Base Rental Fee will be prorated for the actual days of occupancy. Owner shallinvoice Customer for all other fees on amonthly basis or upon the expiration of a Contract Year, as applicable. All invoices shall be paid in accordance with Section 4.2 of theAgreement.Allocation of Base Rental Fee :As of January 1, 2019 the Base Rental Fee is allocated among the Facilities as set forth below:FacilityBase Rental Fee Allocation(in US$)Ardmore, OK$***Austin, TX$***Catoosa, OK$***Dodge City, KS$***El Dorado, KS$***Garden City, GA$***Halstead, KS$***Lawton, OK$***Little Rock, AR$***Memphis, TN$***Parson, TN$***Salina, KS$***Exhibit 10.29*** Where this marking appears throughout this Exhibit 10.29, information has been omitted pursuant to a request for confidential treatment and such informationhas been filed with the Securities and Exchange Commission separately.OWNER OPERATED STORAGE, THROUGHPUTAND HANDLING AGREEMENT NO. 2019-00069This Owner Operated Storage, Throughput and Handling Agreement No. 2019-00069 (“ Agreement ”) is entered into effective as ofJanuary 1, 2019 (“ Commencement Date ”), by and between BKEP Materials, L.L.C., a Texas limited liability company (“ BKEP Materials”), BKEP Asphalt, L.L.C., a Texas limited liability company (“ BKEP Asphalt ” and together with BKEP Materials, “ Owner ”), and ErgonAsphalt & Emulsions, Inc., a Mississippi corporation (“ Customer ”). Owner and Customer are sometimes referred to individually as “ Party” and collectively as the “ Parties ”.R E C I T A L SWHEREAS , Owner owns and operates certain petroleum storage terminals; andWHEREAS, Owner and Customer are parties to that certain Storage and Handling Agreement dated as of November 1, 2009, asamended (the “ P33 Agreement ”) which agreement is terminated and superseded by this Agreement; andWHEREAS , Owner desires to provide certain services to Customer for Customer’s Product (as defined below) and Customerdesires to receive said services on the terms and conditions set forth herein;NOW THEREFORE , in consideration of the mutual promises contained in this Agreement, the Parties agree to the following termsand conditions.Section 1. Definitions .In this Agreement, unless the context requires otherwise, the terms defined in the preamble have the meanings indicated and thefollowing terms will have the meanings indicated below:“ Abatement Costs ” has the meaning assigned to such term in Section 5.10 .“ Abatement Equipment ” has the meaning assigned to such term in Section 5.10 .“ Affiliate ” means, in relation to a Party, any Person that (i) directly or indirectly controls such Party, (ii) is directly or indirectlycontrolled by such Party or (iii) is directly or indirectly controlled by a Person that directly or indirectly controls such Party. For this purpose,“control” of any entity or Person means the possession, directly or indirectly, of the power to direct or cause the direction of the managementand policies of any Person, whether through the ownership of a majority of equity interests or voting power or control in fact of the entity orPerson or otherwise. For the purposes of this Agreement, however, Blueknight Energy Partners, L.P. and each of its subsidiaries, either director indirect, shall not be considered the Affiliate of Lessee and any of Lessee’s other Affiliates.“ Applicable Law ” means (i) any law, statute, regulation, rule, code, ordinance, license, decision, order, writ, injunction, decision,directive, judgment, policy, or decree of any Governmental Authority and any judicial or administrative interpretations thereof, (ii) anyagreement, concession or arrangement with any Governmental Authority and (iii) any license, permit or compliance requirement by anyGovernmental Authority, in each case applicable to either Party and as amended or modified from time to time.1“ Bankrupt ” means a person or entity that (i) is dissolved, other than pursuant to a consolidation, amalgamation or merger, (ii)becomes insolvent or is unable to pay its debts or fails or admits in writing its inability generally to pay its debts as they become due, (iii)makes a general assignment, arrangement or composition with or for the benefit of its creditors, (iv) institutes or has instituted against it aproceeding seeking a judgment of insolvency or bankruptcy or any other relief under any bankruptcy or insolvency law or other similar lawaffecting creditor’s rights, or a petition is presented for its winding-up or liquidation, (v) has a resolution passed for its winding-up, officialmanagement or liquidation, other than pursuant to a consolidation, amalgamation or merger, (vi) seeks or becomes subject to the appointmentof an administrator, provisional liquidator, conservator, receiver, trustee, custodian or other similar official for all or substantially all of itsassets, (vii) has a secured party take possession of all or substantially all of its assets, or has a distress, execution, attachment, sequestration orother legal process levied, enforced or sued on or against all or substantially all of its assets, (viii) causes or is subject to any event which,under Applicable Law, has an analogous effect to any of the events specified in clauses (i) through (vii) above, inclusive, or (ix) takes anyaction in furtherance of, or indicating its consent to, approval of, or acquiescence in any of the foregoing acts.“ Barrel ” means forty-two (42) Gallons.“ BOL ” has the meaning assigned to such term in Section 7.2 .“ Business Day ” means a twenty-four (24) hour period ending at 5:00 p.m., at the prevailing time in the Central Time Zone,on a weekday on which banks are open for general commercial business in Oklahoma City.“ Commencement Date ” has the meaning assigned to such term in the Preamble .“ Confidential Information ” has the meaning assigned to such term in Section 20.1 .“ Contract Year ” means a period of 365 consecutive days commencing on the Commencement Date and each successive period of365 consecutive days during the Term of this Agreement with the exception of any Contract Year in which February has 29 days when theperiod will be 366 consecutive days.“ Cost ” has the meaning assigned to such term in Section 10.1.“ Default ” or “ Event of Default ” has the meaning indicated in Section 16.1 .“ Defaulting Party ” has the meaning indicated in Section 16.2 .“ Disclosing Party ” has the meaning assigned to such term in Section 21.1 .“ Force Majeure ” means (i) strikes, lockouts or other industrial disputes or disturbances, (ii) acts of the public enemy or ofbelligerents, hostilities or other disorders, wars (declared or undeclared), blockades, thefts, insurrections, riots, civil disturbances or sabotage,(iii) acts of nature, landslides, severe lightning, earthquakes, fires, tornadoes, hurricanes, storms, and warnings for any of the foregoing whichmay necessitate the precautionary shut-down of pipelines, trucks, docks, loading and unloading facilities storage tanks or other relatedfacilities, floods, washouts, freezing of machinery, equipment, or lines of pipe, inclement weather that necessitates extraordinary measuresand expense to construct facilities or maintain operations, tidal waves, perils of the sea and other adverse weather conditions or unusual orabnormal conditions of the sea or other water, (iv) arrests and restraints of, or other interference or restrictions imposed by, governments(either federal, state, civil or military and whether legal or de facto or purporting to act under some constitutions, decree, law or otherwise),necessity for compliance with any court order, or any law, statute, ordinance, regulation, or order promulgated after the Effective Date by aGovernmental Authority having or asserting jurisdiction, embargoes or export or import restrictions, expropriation, requisition, confiscation2or nationalization, (v) epidemics or quarantine, explosions, electric power shortages, (vi) breakage or accidents to equipment, machinery,plants, facilities, lines of pipe or trucks or vessels, which were not reasonably foreseeable and which were not within the control of the Partyclaiming suspension of its obligations under this Agreement pursuant to Section 11 and which by the exercise of reasonable due diligencesuch Party is unable to prevent or overcome or (vii) or any other causes, whether of the kind enumerated above or otherwise, which were notreasonably foreseeable, and which are not within the control of the Party claiming suspension of its obligations under this Agreementpursuant to Section 11 and which by the exercise of reasonable due diligence such Party is unable to prevent or overcome. Such term willlikewise include, in those instances where either Party is required to obtain servitudes, rights-of-way, grants, permits, or licenses to enablesuch Party to fulfill its obligations under this Agreement, the inability of such Party to acquire, or delays on the part of such Party inacquiring, at reasonable cost and after the exercise of reasonable diligence, such servitudes, rights-of-way grants, permits or licenses, and inthose instances where either Party is required to furnish materials and supplies for the purpose of constructing or maintaining facilities toenable such Party to fulfill its obligations under this Agreement, the inability of such Party to acquire, or delays on the part of such Party inacquiring, at reasonable cost and after the exercise of reasonable diligence, such materials and supplies. If Owner or Customer is claiming asuspension of its obligations under this Agreement pursuant to Section 11 , any of the above listed events or circumstances will constitute anevent of Force Majeure upon the first occurrence of the event or circumstance.“ Gallon ” means a U.S. gallon of 231 cubic inches corrected to 60 degrees Fahrenheit.“ Governmental Authority ” means any foreign or U.S. federal, state, regional, local or municipal governmental body, agency,instrumentality, board, bureau, commission, department, authority or entity established or controlled by a government or subdivision thereof,including any legislative, administrative or judicial body, or any person purporting to act therefor.“ Indemnified Party ” has the meaning assigned to such term in Section 20.1 .“ Indemnifying Party ” has the meaning assigned to such term in Section 20.1 .“ Independent Inspector ” means a licensed Person who performs sampling, quality analysis and quantity determination of theProduct received or delivered.“ Initial Term ” has the meaning indicated in Section 3 .“ Interest Rate ” means the one-Month London Interbank Offered Rate.“ Liability ” means any obligation, liability, charge, deficiency, assessment, interest, penalty, judgment, award, cost or expense of anykind (including reasonable attorneys’ fees, other fees, court costs and other disbursements). The term also includes any liability that directlyor indirectly arises out of or is related to any claim, proceeding, judgment, settlement or judicial or administrative order made or commencedby any Third Party or Governmental Authority.“ Loading Facilities ” has the meaning indicated in Section 5.2 .“ Month ” means a calendar month.“ Out of Service Shell Barrel Fee Reduction” has the meaning assigned such term in Section 5.6.“ Out of Service Storage Tank ” has the meaning assigned such term in Section 5.6.3“ Product ” means the particular stored, received, delivered feedstocks, raw materials, and finished products identified in AttachmentB .“ Product Loss ” means any loss of or damage to Product, including contamination, while Product is in the custody of Owner, andwhich is caused by the failure of Owner to use generally accepted terminalling practices in the handling, testing, or storage of Product,provided, however, that Product Loss shall not include the result of loss of or damage to Product (i) directly resulting from an event of ForceMajeure, (ii) caused by the act or omission of Customer, (iii) due to normal Product evaporation, shrinkage, clingage, (iv) Productmeasurement inaccuracies within tolerance acceptable under current industry practices (including by way of example, measurementtolerances of weigh scales, flow meters, and level indicators) or as provided for in Section 7.2 or (v) any other loss for any reason whatsoever,provided such loss pursuant to clauses (iii), (iv) and (v) does not exceed *** percent (***%) (" Volumetric Deduction ") of Product receivedby Owner at the Terminal during the term of this Agreement. If Product Loss exceeds *** percent (***%) of Customer’s Product received byOwner at the Terminals, Owner shall only be responsible for the amount in excess of *** percent (***%). Owner shall be accountable for thedelivery of that quantity of Product accepted for receipt at the Terminals after the Volumetric Deduction above above for actual losses.Losses shall be calculated and reported on a monthly basis. Owner, at its option, shall either replace or pay the Customer the actual laid incost for losses in excess of the loss allowance. For the purposes hereof, actual laid in costs of the Product means the costs incurred byCustomer to place Product at the Terminals, including the invoice price, freight, and state and local taxes, if any. If freight costs incurred isnot specifically identified for a particular Product or known for a published freight cost point to the Terminals, then the parties agree tomutually work to account for comparable freight costs with other comparable transactions and comparable geographic markets. Settlementwill be made at the expiration of the Term of this Agreement.“ Receiving Party ” has the meaning assigned to such term in Section 21.1 .“ Scheduling Notice ” has the meaning assigned to such term in Section 5.3 .“SDS ” means a safety data sheet.“ Services ” has the meaning assigned to such term in Section 2.2 .“ Specifications ” means the Product specifications set forth in Attachment B and any additional specifications set forth in aScheduling Notice.“ Storage Fee ” has the meaning assigned to such term in Attachment A .“ Storage Tanks ” means those asphalt cement storage tanks listed on Attachment A that are located at the Terminal and used toprovide the terminalling and storage services to Customer pursuant to this Agreement.“ Temporary Event ” has the meaning assigned to such term in Section 5.1 .“ Term ” has the meaning indicated in Section 3 .“ Terminal ” has the meaning indicated in Attachment A .“ Third Party ” means any entity other than Owner, Customer or their Affiliates.“ Third Party Claim ” has the meaning assigned to such term in Section 19.3 .4“ Ton ” means a U.S. short ton of 2,000 pounds.“Volumetric Deduction” has the meaning assigned to such term in the definition of “Product Loss” above.Section 2. Facilities, Services, Statements, Invoices, Documents and Records . Subject to Terminal capabilities existing as of theCommencement Date:2.1 Owner agrees to provide an area for the purpose of loading or unloading Product and the Storage Tanks for storage ofCustomer’s Product. Owner further agrees to provide terminal and related facilities required to perform all Services to be provided by Ownerherein. All such facilities are to be maintained in good working order by Owner at its own cost and expense at all times during the Term ofthis Agreement.2.2 Owner will provide to or for Customer the following storage and terminalling services related to the receipt of Product at theTerminal and to the storage, terminalling, and delivery of Product into and out of the Terminal (collectively, the “ Services ”):(a) receive and unload all Product delivered by barge, truck, or rail, as applicable, by or on behalf of Customer, to theTerminal from time to time during the Term of this Agreement;(b) load Product into trucks or barges, as directed by Customer;(c) provide all pumping and heating necessary for proper performance of each of the foregoing services including heatingfacilities, within existing Facility capabilities, adequate to maintain the temperature of Product normally maintained at a Terminal or asdirected by Customer for the loading of trucks or barges;(d) handle, store, and test Product in accordance with the instructions and Specifications provided by Customer, as suchmay be updated from time to time and agreed upon by the Parties;(e) prepare all tank or vessel gauging reports, bills of lading, and other shipping papers and deliver copies thereof toCustomer as required; and(f) keep records and accounts and make reports relating to Product received in storage, or withdrawn from storage andloaded into vessels from the Terminal, with such reports being provided to Customer on a monthly basis.2.3 The Services will be performed in compliance with Applicable Law and in accordance with generally accepted terminallingpractices. Owner may adapt its performance of the Services, although not to a standard less than commercially reasonable, in order (i) to beconsistent with industry practices; (ii) to meet the requirements of Applicable Law; or (iii) to achieve the efficient utilization of the Terminaland Storage Tanks. In no event shall Owner accept Product in excess of the storage capacity of the Storage Tanks at the Terminal.2.4 Customer agrees to perform the following duties with the use of the Terminal and the Storage Tanks during the Term of thisagreement;(a) Customer shall provide to Owner, which can include electronic communications in the form of email, a SDS and othermaterial information regarding the proper and safe means and methods of storing and handling Customer’s Product.5(b) Customer agrees to execute in its name, pay for, and furnish to Owner all information and documents, which may berequired by Applicable Law relating to the description, receipt, storage, dispatch, and scheduling in and out, handling or discharge of theProduct, including, but not limited to, sludges, flushing materials, or other portions, admixtures, components or residues of, at, or from theTerminals of Owner.(c) Customer shall be responsible for advising Owner in writing of any changes in such requirements prior to the date suchchanges take effect, as well as any revised information and documents required. Customer acknowledges that it is responsible for providingOwner in writing, which can also include electronic communications in the form of email, with the processing instructions, theSpecifications, and state agency quality control plan and quality assurance testing requirements relating to the manufacturing of any Product.(d) Customer shall be responsible for providing all Products and Storage Tank heels (when not already provided byOwner) used in the manufacturing, storing, and handling of Product. Customer also agrees to provide Owner with further information oradvice upon request to assist Owner in performing its responsibilities for receipt, storage, and redelivery of Product.(e) Customer shall be responsible, in accordance with Section 4.3, for arranging and payment for all transportation ofProduct (excluding water used in manufacturing of Product) to and from the Terminals.(f) Customer Authorized Employee Representative(s) shall be available (i) on a reasonable basis during normal operatinghours that match the Operating Hours during truck loading and (ii) during emergency events to consult with Owner on Services issues andquestions, and to receive notifications of any modifications to or deviations from normal Services provided.(g) Owner shall not provide Services to Customer relating to any Product until such time as Owner has approved andCustomer has, to the reasonable satisfaction of Owner, informed Owner about the product characteristics and safety precautions necessary toproperly and safely handle and store the Product, which can also include electronic communication in the form of email. Customer shall, inaccordance with Section 7.4 , provide Owner with an SDS for each Product prior to Owner providing Services for that Product and shall beresponsible for providing all SDS and related documentation to Owner and to Customer’s customers and carriers. 2.5 Customer acknowledges that it is responsible for the content of the Specifications relating to the handling of any Product.Owner shall not be responsible for, and Customer shall indemnify and hold Owner harmless from and against, any Liability relating toOwner’s handling of the Product in compliance with the Specifications.2.6 Except as provided below in this Section 2.6 , each Party will maintain a true and correct set of records pertaining to itsperformance of this Agreement and will retain copies of all such records for a period of not less than two (2) years following termination orcancellation of this Agreement. Upon reasonable prior notice, a Party or its authorized representative may at its sole cost, during the Term ofthis Agreement and thereafter during the aforesaid two (2) year period, inspect such records of the other Party during normal business hoursat the other Party’s place of business. Unless a Party has taken written exception to a statement or invoice within twelve (12) Monthsfollowing the end of the year in which the statement or invoice is delivered, the statement or invoice shall be conclusively presumed to betrue and correct.6Section 3. Term.The term of this Agreement (“ Term ”) begins on January 1, 2019, and continues until December 31, 2023.Section 4. Fees, Charges, Taxes, Disputed Amounts .4.1 Customer will pay Owner the fees, rates, and charges set forth in Attachment A with respect to the Services. All suchpayments, as well as any taxes and other amounts to which Owner is entitled under this Agreement, shall be paid in accordance with theterms and conditions set forth in this Agreement.4.2 All fees and charges reflected in Owner’s invoices are due and payable within thirty (30) days of the date of receipt of Owner’sinvoice. Payment must be made by electronic wire transfer of same day available federal funds to Owner’s account and bank, both asindicated on Owner’s invoice. Invoices may be sent by electronic mail and telephone facsimile. Payments that are not disputed and that arenot made within the agreed or designated terms shall bear interest from the original due date at the lesser of (i) the rate of 18% per annum and(ii) the highest rate allowed by Applicable Law. If Customer disputes any portion of an invoice, Customer must pay the undisputed portion ofthe invoice. Overdue amounts or disputed amounts that are resolved in favor of the Owner will accrue interest at the Interest Rate from thedate that payment is due until paid in full and Customer will pay all of Owner’s reasonable, out-of-pocket costs (including reasonableattorneys’ fees and court costs) of collecting past due payments and late payment charges, whether or not suit is brought.4.3 Customer will pay, and will indemnify and hold harmless Owner from and against, any and all sales, use, excise and similartaxes, fees or other charges and assessments imposed on the Services and the fees and charges therefor. Customer will also pay, and willindemnify and hold harmless Owner from and against, any ad valorem or property ownership taxes, if any, on Customer’s Product located atthe Terminal or in the Storage Tanks and Customer’s other property, if any. Owner shall be responsible for and pay all other applicable taxeslevied upon Owner, including its own income and franchise taxes and any property and ad valorem taxes levied on the Terminal and StorageTanks.Section 5. Operations, Receipts and Deliveries .5.1 Receipts and deliveries of Product will be handled within the normal business hours of the Terminal. Owner may, withoutCustomer’s approval, make temporary changes in business hours or temporarily close any Terminal or Storage Tank because of anextraordinary event (“ Temporary Event ”); provided, however, that a Temporary Event shall not include events caused by failure ofequipment that Owner is obligated to maintain pursuant to this Agreement. Owner will notify Customer of such Temporary Event in advance,or as soon after implementation as is practicable. Except as required pursuant to Sections 5.2 , 10.1 , or 19 of this Agreement, Owner will notbe responsible for the payment of any costs incurred by Customer or its transportation carrier for any delay in receiving or delivering Productor any other costs or fees, including freight, car leases and demurrage, as a result of such Temporary Event.5.2 As part of the facility, Owner shall make available to Customer facilities serving the Terminal for receiving and unloading ofProduct from Customer and loading Products to Customer or Customer’s carrier (such unloading and loading facilities, collectively, the “Loading Facilities ”). The Loading Facilities, being used for purposes defined in Section 2.2 , are available on a “first-come, first-served”basis. In no event will Owner be responsible for accruing any expense, including demurrage, for following Customer’s instructions for theLoading Facilities. Any demurrage shall be at Customer’s sole expense, unless and to such extent demurrage is established by Customer ascaused by Owner’s gross negligence or willful misconduct. Owner and Customer agree to use reasonable efforts to minimize any demurragethat may be incurred by Customer in accordance with the foregoing. Customer acknowledges that Owner requires Third7Parties operating on Customer’s behalf and entering or accessing the Terminal to have separate access or service agreements with Owner.Owner will put in place agreements with any such Third Parties and Owner, at its sole discretion, will approve, negotiate and finalize suchagreements. Owner will notify Customer of Third Parties operating on Customer’s behalf that are denied access to the Terminal.5.3 Customer must arrange for and pay all costs related to the delivery of Customer’s Product to the Terminal and Third-Partycosts from the Storage Tanks. Owner is not responsible for such Third-Party costs except as otherwise specifically provided herein. Unlessotherwise provided by Owner in writing, Customer must provide notice reasonably acceptable to Owner containing all necessary instructions,including without limitation, the identity and quantity and any other specifications of the Product and the tentative date of delivery to theTerminal (“ Scheduling Notice ”). The Scheduling Notice may also be provided to Owner by Customer through electronic communicationsin the form of email. The Parties shall reasonably coordinate with each other in advance with regard to scheduling of all Product movementsand the in-bound quality, volume, and grade, the times of delivery to Terminal, and all material movements prior to shipment of all Productdelivered to Owner hereunder. Each Scheduling Notice delivered hereunder to Owner by Customer for deliveries of Product to a Terminalshall be sent to those individuals that Owner has specified to Customer to receive such Scheduling Notice for the applicable Terminal withrespect to such Product delivery.5.4 Upon receipt by Owner of instructions from Customer, Owner will deliver to Customer, or to such Third Parties as Customermay direct, the Product held by Owner in the Storage Tanks for the account of Customer. Customer is responsible for providing to Ownerdocumentation required to authorize deliveries for or on its behalf from the Terminal.5.5 Owner will provide the Services to Customer only with respect to Product. Customer will have access to the Terminal andStorage Tanks for other products only with prior written notice to and consent by Owner, such consent not to be unreasonably withheld,conditioned or delayed. Any other product approved by Owner will then become part of Product as defined in this Agreement. If a specialmethod of providing the Services is required for the Product, then Customer must notify Owner in sufficient time to enable Owner to considerwhether, in Owner’s sole discretion, it will accept the proposed changes in the method of delivering the Services and to take the necessarypreparatory measures if it agrees with such changes. Absent such notice and absent Owner’s written approval with respect to a change in theProduct to another Product or the method of delivering the Services, Owner will not be liable for losses, tank heels, line fill or damageincurred during the terminalling and storage of Product (except for losses and damages resulting from Product Loss), nor will Owner beobligated to provide such special Service. It is understood that the cost of any additional or special equipment required by Customer or ofalterations made necessary by the nature of Product will be for the account of Customer, and Customer will be responsible for the expense ofany necessary cleaning and restoration to their previous condition of the Terminal and Storage Tanks, including, without limitation, pumps,tank heels and loading facilities, unless otherwise explicitly stated in this Agreement. All fixtures, equipment, and appurtenances attached tothe Storage Tanks will be installed by the Owner and will remain the property of Owner.5.6 If any Storage Tank is damaged or destroyed by fire or other casualty, Owner will use reasonable efforts to make other storagetanks available to Customer at the monthly tankage fee as set forth in the applicable Schedules. If other storage tanks are unavailable, themonthly tankage fee, together with Owner’s requirement to handle the volume of Product in consideration of said monthly Storage Fee as setforth in the applicable Schedules, shall be reduced by a prorated amount equal to the tank capacity that is unusable by Customer for thepurposes set forth herein. This abatement shall continue until the damaged or destroyed tank is repaired and ready for service, or until asubstitute tank is provided and Owner is able to handle the required volume of Product. If, however, such tank is not damaged as a result ofan event of Force Majeure and is not repaired and returned to its prior existing capacity within nine (9) Months after the date on which thedamage or destruction occurred, and a substitute tank is not provided and Owner cannot8handle the volume of Product in consideration, the Customer shall have the right to terminate that storage capacity from this Agreement uponwritten notice to Owner. Should such Storage Tank become repaired and returned to service after nine (9) Months, Customer shall have theright to add such Storage Tank to the applicable Schedule. If Customer does not add such Storage Tank to the applicable Schedules, Ownermay lease such Storage Tanks to a Third Party or Third Parties. In the event the unavailability of a Storage Tank is a result of the negligenceor willful misconduct of Customer, any of its Affiliates, or their respective employees, directors, officers, representatives, agents, orcontractors, the reduction in Storage Fee shall not apply.5.7 Owner may take any Storage Tank out of service during the Term in order to perform scheduled inspections, maintenance orrepairs. If a Storage Tank is out of service for forty-five (45) days or less, Customer will be obligated to continue to pay the applicableStorage Fees during such 45-day period such Storage Tank is out of service. If a Storage Tank is out of service for more than 45 days for anyreason other than Force Majeure or the negligence or willful misconduct of Customer, any of its Affiliates, or their employees, directors,officers, representatives, agents or contractors: (a) Owner, at Owner’s option and at Owner’s cost, may move Customer’s Product tosubstantially equivalent alternate tank(s) while the original Storage Tank is out of service, and Customer will continue to pay the applicableStorage Fees; (b) if Owner has not affected Customer’s capacity to receive or deliver Products while the Original Storage Tank is out ofservice, Customer will continue to pay any Storage Fee applicable to the original Storage Tank; or (c) after the 45 days that the Storage Tankis out of service, Customer’s obligation to pay the applicable Storage Fees will be reduced as provided herein to address the loss of capacityavailable. The abatement shall continue until the storage capacity is repaired and ready for service, or until substitute storage is provided, oruntil Customer’s need to receive or deliver Products is unaffected at the Terminal. In the event the unavailability of a Storage Tank is a resultof the negligence or willful misconduct of Customer, any of its Affiliates, or their respective employees, directors, officers, representatives,agents or contractors, the reduction in Storage Fee shall not apply. 5.8 If any Governmental Authority requires installation of any improvement, alteration, or addition to any Terminal for purposes ofcompliance with Applicable Law, and if the installation would require Owner to make substantial and unanticipated capital expenditures,other than continued maintenance and capital expenditures not affected by such requirement, Owner will be entitled to impose a reasonableservice surcharge (which surcharge may include the Owner’s cost of capital) in addition to the fees set out in Attachment A. Owner willnotify Customer of (i) the cost of making any such improvement, alteration, or addition, after Owner’s efforts to mitigate such costs, (ii) whensuch improvement, alteration, or addition must be completed and (iii) the Owner’s reasonable estimate of the service surcharge related to thecapital expenditure to be paid by Customer over the remaining Term. In calculating the surcharge, Owner shall calculate the cost of theimprovement, alteration, or addition and the surcharge using reasonable assumptions and estimates. In addition to actual capital andinstallation costs, the costs to be recovered through the surcharge will include engineering and interest expense (at a rate of ***% over theprime lending rate as reported in The Wall Street Journal on the date of completion of such installation) and subsequent reasonable expenses,if any, of operating or maintaining such installation as reasonably determined by Owner. Owner will not be required to make anyimprovements, alterations, or additions to the Terminal or the Storage Tanks in such circumstance, unless Customer agrees to pay thesurcharge. (a) If Customer elects, after commercially reasonable negotiation with Owner in good faith, not to pay the surcharge andthe Owner chooses not to pay for such improvement, alteration or addition, and if the Services are not reduced by Owner’s decision to foregosuch improvement, alteration or addition, then the terms and conditions of this Agreement shall remain in full force and effect, includingthose set forth in Attachment A . 9(b) If Customer elects, after commercially reasonable negotiation with Owner in good faith, not to pay the surcharge andthe Owner would be required by the Governmental Authority to reduce or terminate the Services to be provided under this Agreement, thenthe Parties shall negotiate in good faith the charges to be assessed by Owner and paid by Customer for such reduced scope of services thatcan be provided at the Terminal in compliance with Applicable Law. If the Parties are unable to agree on the charges to be assessed by Ownerand paid by Customer for the reduced scope of services within thirty (30) days after Owner’s notification to Customer as set forth in thisSection 5.8 , then this Agreement will terminate immediately with no further action by the Parties.(c) If Customer elects to pay the service surcharge, Owner shall proceed with the installation of the required improvement,alteration, or addition. Owner will calculate the surcharge required to recover the portion of Owner’s costs for the improvement, alteration,or addition attributable to Customer’s use of the impacted portion of the Terminal and/or Storage Tanks. The portion of Owner’s costs to berecovered through the surcharge to Customer shall equal the percentage of total revenues from the impacted segment of the Terminal and/orStorage Tanks attributable to Customer’s use of such Terminal or Storage Tank segment for the six (6) full Months preceding the date ofOwner’s notice to Customer for the cost of the improvement, alteration, or addition. Customer may pay the surcharge either (A) in equalmonthly installments over the remaining Term, with each monthly installment payment increased by an interest component calculated on thesurcharge at a rate of ***% over the prime lending rate as reported in The Wall Street Journal on the date of completion of such installation,or (B) by paying the surcharge in one lump sum within thirty (30) days after completion of the required improvement, addition, or alteration.5.9 Owner will provide tank heels at the Terminal to the extent that it currently owns such tank heels, on a tank-by-tank basis. Atany time during the Term, Customer may be required to provide a tank heel for various reasons, including but not limited to requiredmaintenance, repairs, or inspection. To the extent that Owner does not own tank heels at the Terminal on a tank-by-tank basis, Customer willbe responsible for providing tank heels. Owner or Customer, as applicable, will retain ownership of the tank heels it provides.5.10 If, at any time during the Term, a complaint is made regarding offensive or obnoxious odors emitted from the Productdelivered to or stored at the Terminal, or if such Products violate any applicable regulation relating to odor, Owner shall notify Customer ofsuch complaint or violation. In such case, Owner and Customer shall cooperate in good faith to investigate and determine the source of theodor, and shall mutually determine the best method to abate such odor. If reasonable changes to the Product would fully or partially abate theodor, Customer shall make such reasonable changes to abate the odor. Owner shall not be obligated to accept Product reasonably known tohave excessive potential for odor that may affect the Terminal’s property boundaries. If the Parties’ investigation determines that abatementof the odor requires the installation of additional equipment reasonably necessary to abate the odor (“ Abatement Equipment ”) Owner shallundertake procurement and installation of the Abatement Equipment. Customer shall be responsible for and shall pay to or reimburse Ownerfor the cost of (i) the investigation to determine the cause of such odor, and (ii) the Abatement Equipment ((i) and (ii), the “ Abatement Costs”), up to a maximum of $*** in the aggregate. Owner shall be responsible for all Abatement Costs in excess of $***. Except to the extent adefect in or failure of any of the equipment at the Terminal is the cause of such odor issue, Customer shall indemnify, defend, and holdharmless Owner from and against any and all fines, assessments, damages, penalties, and other expenses, including reasonable attorneys’ feesand costs, incurred by Owner as a result of such odor. If a defect in or failure of any of the equipment at the Terminal is the cause of suchodor issue, Owner shall indemnify, defend, and hold harmless Customer from and against any and all fines, assessments, damages, penalties,and other expenses, including reasonable attorneys’ fees and costs, incurred by Customer as a result of such odor. If at any time Customerdesires to add Products to the Facilities in addition to those listed in Attachment B , such addition shall be subject to this Section 5.10 .10Section 6. Product Quality Standards and Requirements .6.1 Customer warrants to Owner that all Product tendered by or for the account of Customer for receipt into the Terminal andStorage Tanks (i) conforms to the Customer processing instructions to meet Specifications for such Product at the time it is tendered, (ii)complies with industry standards and (iii) complies with all Applicable Law. Owner may rely upon the Specifications and representations ofCustomer, if any, set forth in the Scheduling Notice as to Product quality. Owner will not be obligated to receive Product into the Terminaland Storage Tanks that is contaminated or that otherwise fails to meet the Specifications, nor will Owner be obligated to accept Product thatfails to meet Product grade, if any, set forth in the Scheduling Notice. Should Owner remove, clean, dispose of, or otherwise have to treat theProduct for any water, contamination, or other materials to handle in or associated with the Product at any time, Customer shall pay orreimburse all costs and expense associated with such removal, cleaning, disposal, or treatment. Owner shall not remove or dispose of orotherwise treat the Product for any water, other material, or contaminants without the prior approval of Customer.6.2 Owner may randomly test delivered Product to ensure it is not contaminated and otherwise meets the Specifications. If avessel’s cargo of Product does not meet the Specifications or Owner has not provided a prior written waiver for unloading said Product,Owner shall contact a representative of Customer before unloading Product at the applicable Terminal and shall not unload such Productwithout first obtaining Customer’s approval. The Owner shall not be required to test all inbound Product on receipt, and Owner may rely onthe Customer’s supplier’s bill of lading for content and grade. Customer may procure Product with the intention of blending with otherProduct to change the properties to meet specifications. Customer acknowledges and agrees that it shall be responsible for any reasonabledelay costs (including, but not limited to, demurrage, transportation costs and energy costs) incurred by Owner for handling, re-deliveringand/or waiting for Customer’s decision with respect to Product not meeting the Specifications. Customer understands it is responsible for allfield performance issues related to any Product delivered by Customer to Owner and/or any Product delivered by Owner to Customer underthis Agreement.6.3 The quality of Product tendered into the Terminal and Storage Tanks for Customer’s account may be verified either byCustomer’s laboratory analysis, or by an Independent Inspector’s analysis indicating that the Product so tendered meets the minimum ProductSpecifications. Such analysis may be conducted on a periodic basis in accordance with a quality compliance program implemented byCustomer, which program shall be subject to the approval of Owner, which approval shall not be unreasonably withheld, conditioned ordelayed. All costs associated with such compliance program shall be borne by Customer. Upon reasonable notice to Customer, Owner, at itsexpense, may sample any Product tendered to Owner for Customer’s account for the purpose of confirming the accuracy of the analysis.6.4 Each Party may at all reasonable times and without unreasonable disruption to the other Party’s operations conduct appropriatetests to determine whether Product meets the applicable Specifications. Owner will be liable to Customer for Liability incurred by Customerby reason of contamination of Product occurring at the Terminal or in the Storage Tanks that causes the Product to fail to meet Specifications,but only to the extent such contamination involves a Product Loss. In all other cases, Customer shall indemnify Owner for any Liabilityincurred by Owner to parties who purchase Product from Customer.11Section 7. Title, Custody, Measurement and Custody of Product .7.1 Title and Custody . Customer warrants that it shall hold clear title to the Product delivered to Owner pursuant to thisAgreement. Title to the Product will remain with Customer at all times subject to any lien in favor of Owner created under Applicable Law.Owner shall have custody and risk of loss of Customer’s Product beginning when such Product passes the flange connection at the Terminalbetween the delivering barge, tank truck or rail car and Owner’s receiving hose, if applicable, at the applicable Terminal and ending whenCustomer’s Product passes the last hard flange connection at the applicable Terminal into a barge, tank truck, or rail car for delivery toCustomer, its customers or its other designees.7.2 Measurement at Receipt .(a) Barges/River Tows. The quantity of Product received by Owner from Customer shall be determined by gauging thereceiving tanks containing such Products, immediately before and after the unloading. If Customer requests that such measurement beconducted by a Third Party, Customer shall be solely responsible for all costs associated with such measurement.(b) Truck/Rail Cars. Owner will assume receipt of the volumes set forth on the designated bill of lading (“ BOL ”) of adelivery truck or rail car. Owner reserves the right, at its discretion, to randomly measure and/or meter (using commercially reasonablestandards) the volume of Product actually delivered against the volume of Product set forth on the designated BOL of a delivering truck orrail car. Owner reserves the right to base receipt of volumes based on such random measurement if it deems appropriate.(c) Measurement Standards. All measurements shall be made in all respects in accordance with the applicable AmericanPetroleum Institute standards, and all quantities, however measured, shall be (1) adjusted to volume equivalents at 60ºF in accordance withTable No. 7 of the ASTM/IP Petroleum Measurements Tables as in effect at the time of the measurement, or other Tables as accepted by bothOwner and Customer, and (2) converted into Tons on the basis of actual specific gravity at 60ºF, in accordance with that same Table.7.3 Measurement of Storage Quantities . The quantities of Product in storage at any time at the Terminal shall be determined bygauges of the Storage Tank(s) or by count at the Terminal. All gauging of the Storage Tank(s) and count at the Terminal to measure Productsin storage shall be taken by Owner’s personnel. Customer shall have the right to witness the gauging and counting or to provide anIndependent Inspector to witness the gauging or counting.7.4 Measurement at Delivery . Once Product has been loaded onto Customer’s designated transport for shipment out of theTerminal, Owner will provide the transport driver a BOL on behalf of Customer, as Customer’s limited agent, indicating the quantity (byweight), Product type, and the destination of the Product as determined by Customer and on a BOL form approved by or provided to Ownerby Customer. Owner will issue the Customer’s BOL and such will be the official document verifying the quantity (by weight) of Product,delivered to Customer, or Customer’s designee, at the Terminal. Each BOL shall name Customer as the person delivering the goods forshipment and Customer will be the DOT shipper of record for all shipments out of the Terminal. Customer shall be responsible for providingall MSDS and related documentation to Owner and to Customer’s customers and carriers. Customer will make written notification of anydiscrepancies or exceptions to the information on any BOL within twenty (20) days of the BOL date.12Section 8. Limitation of Liability and Damages .8.1 The maximum Liability of Owner for Product Loss will not exceed, and is strictly limited to, the market value of the Product atthe time of the Product Loss or immediately prior to its contamination. Owner may, in lieu of payment for Product Loss, replace such Productwith Product of like grade and quality.8.2 EXCEPT FOR THE PARTIES’ INDEMNIFICATION OBLIGATIONS WITH RESPECT TO CLAIMS OF THIRDPARTIES, THE PARTIES’ LIABILITY FOR DAMAGES HEREUNDER IS LIMITED TO DIRECT, ACTUAL DAMAGES ONLY, ANDNEITHER PARTY SHALL BE LIABLE TO THE OTHER FOR SPECIFIC PERFORMANCE, LOST PROFITS, DIMINUTION INVALUE OR OTHER BUSINESS INTERRUPTION DAMAGES, OR SPECIAL, CONSEQUENTIAL, INCIDENTAL PUNITIVE,EXEMPLARY OR INDIRECT DAMAGES, IN TORT, CONTRACT OR OTHERWISE, OF ANY KIND, ARISING OUT OF OR IN ANYWAY CONNECTED WITH THE PERFORMANCE, THE SUSPENSION OF PERFORMANCE, THE FAILURE TO PERFORM, OR THETERMINATION OF THIS AGREEMENT. EACH PARTY ACKNOWLEDGES ITS DUTY TO MITIGATE DAMAGES HEREUNDER.Section 9. Loading and Transporting Conditions .9.1 Right to Reject Transport Vehicles and Refuse to Load/Transfer Under Unsafe Conditions . Owner reserves the sole right toreject any rail cars, trucks, transports, barges, vessels, or containers presented for loading which Owner reasonably believes would present anunsafe or potentially unsafe situation or condition, and Owner reserves the right, in its sole discretion, to refuse to load goods under anycondition Owner deems unsafe, which is caused by, including but not limited to, drivers, personnel, equipment, minimum vessel size,quantity, and type, procedures, and/or weather conditions.9.2 Compliance with Owner’s Designated Policies and Procedures . Customer agrees that it, including its contractors, agents, andemployees, will comply with all of Owner’s safety regulations and rules when Customer, its contractors, agents, or employees are on Owner’spremises in connection with the performance of this Agreement.9.3 Compliance with Hazmat Laws . Both Owner and Customer shall comply with all Applicable Law.9.4 Accident Reporting and Emergency Response .(a) Product Release at Owner’s Terminal.(i) Reporting and Response Obligation . If a release of Customer’s Product occurs at Owner’s Terminal, asbetween Owner and Customer, Owner shall make all release notifications and reports that are legally required and shall also provideCustomer with written notice of such legally required release notifications and reports within three (3) business days of making suchnotifications and reports. Further, as between Owner and Customer, Owner shall be responsible to perform any and all response actionsrequired to address such releases on Owner’s Terminal.(ii) Financial Responsibility . Owner shall be financially responsible for all releases occurring at Owner’s Terminalwith respect to Product in its custody; except that, to the extent a release of Product occurring on Owner’s Terminal while in Owner’s custodyis caused by Customer or Customer’s contractors or agents, Customer shall indemnify Owner for all costs of response actions andremediation related thereto. Customer shall also indemnify Owner for all costs of response actions and remediation related to a releaseoccurring at Owner’s Terminal if at the time of such release, the Product is in the custody of Customer or Customer’s contractors or agents;except that, to the extent such release is caused by Owner or Owner’s contractors or agents, Owner shall indemnify Customer for all costs ofresponse13actions and remediation related thereto. For purposes hereof, financial responsibility shall include responsibility for all Liabilities relating toenvironmental remediation and clean-up costs, and damages in connection with personal injuries, death or damage to property or theenvironment arising from or relating to the subject release.(b) Product Release Outside Owner’s Terminal.(i) Reporting and Response Obligation . If a release occurs while Customer’s Product is any place other thanOwner’s Terminal, as between Owner and Customer, Customer or Customer’s agents or contractors shall make all release notifications andreports that are legally required and shall provide Owner with written notice of such release notifications and reports within three (3) businessdays of making such notifications and reports. Further, as between Owner and Customer, Customer shall be responsible for and shall clean upand take any and all response actions required to address all releases that occur while the Product is not on Owner’s Terminal.(ii) Financial Responsibility . Customer shall be financially responsible for all releases occurring at any place otherthan Owner’s Terminal. For purposes hereof, financial responsibility shall include responsibility for all Liabilities relating to environmentalremediation and clean-up costs, and damages in connection with personal injuries, death or damage to property or the environment arisingfrom or relating to the subject release.Section 10. Product Loss and Product Gain .10.1 Subject to Section 2. 5, during such time as Owner has custody of the Product pursuant to Section 7. 1, Owner will indemnifyCustomer against, and is responsible for, any Product Loss that occurs while the Product is in Owner’s custody at the Terminal or remains inthe Storage Tanks. In the event of the foregoing Product Losses, the total quantity of net Product Loss of Customer’s receipts at thetermination of the Agreement will be determined and Owner will reimburse Customer. In no way shall Owner have claim to any product gainat the Terminal. Other than pursuant to Section 20 , Owner shall have no responsibility for any loss, damage, or injury to persons or property(including the Product) arising out of possession or use of the Product, except to the extent that such loss, damage, or injury involves aProduct Loss.10.2 Each Month, Owner will use the measurement procedures set out in Section 7.3 to determine the amount of Product located atthe Terminal or in the Storage Tanks.Section 11. Force Majeure .11.1 If either Party is unable to perform or is delayed in performing, wholly or in part, its obligations under this Agreement, otherthan the obligation to pay funds when due, as a result of an event of Force Majeure, that Party may be excused from such performance bygiving the other Party prompt written notice of any event that is or in the reasonable estimation of the affected Party, could become an eventof Force Majeure with reasonably full particulars thereof. The obligations of the Party giving notice, so far as such obligations are affected bythe event of Force Majeure, will be suspended during, but not longer than, the continuance of the event of Force Majeure beginning with thetime that the event first occurs and continuing until the effects of the Force Majeure Event have been remedied. The affected Party must actwith commercially reasonable diligence to overcome or remedy the event of Force Majeure and resume performance as quickly as possible.Once the event of Force Majeure is remedied, the affected Party shall notify the other Party that the event of Force Majeure no longer affectssuch obligations. If Owner is excused from providing service pursuant to this Agreement due to an event of Force Majeure, the feeshereunder, not already due and payable, that are directly affected by such Force Majeure event will be excused or14proportionately reduced, on a daily basis, for so long as the Owner’s performance is excused due to the event of Force Majeure.11.2 The requirement that any Force Majeure event be remedied with all reasonable diligence shall not require the settlement ofstrikes, lockouts, or other labor difficulty by the Party claiming excuse due to an event of Force Majeure contrary to its wishes.Section 12. Inspection of and Access to Terminal .12.1 Customer shall have the right during Owner’s normal business hours and after reasonable notice to Owner so as not to disruptthe operations of the Terminal or the Storage Tanks or Owner’s other operations (i) to make periodic operational inspections of the Terminaland Storage Tanks, (ii) to conduct audits of any pertinent books and records, including those related to receipts, deliveries, and inventories ofProduct and (iii) to conduct physical verifications of the amount of Product delivered to the Terminal and stored in the Storage Tanks or at theTerminal. Customer’s right and that of its authorized representatives to inspect the Terminal and Storage Tanks will be exercised byCustomer in a way that will not unreasonably interfere with or diminish Owner’s control over or its operation of the Terminal or StorageTanks and will be subject to reasonable rules and regulations promulgated by Owner. Parties agree that any overpayments discovered andsubstantiated shall be paid within thirty (30) days after written notice to the other Party from whom such payment is sought.12.2 Customer acknowledges that any grant of the right of access to the Terminal and Storage Tanks under this Agreement orunder any document related to this Agreement is a grant of a license only and shall convey no interest in or to the Terminal or Storage Tanksor any part of it, and may be withdrawn by Owner at its discretion at any time.Section 13. Maintenance.Owner shall be responsible for the maintenance and repair of the Terminal. Owner will maintain and operate the Terminal inaccordance with the equipment manufacturer’s standards and/or industry practices.Section 14. Assignment .No Party hereto may assign this Agreement, in whole or in part, except with the prior written approval of each other Party, whichapproval shall not be unreasonably withheld, delayed, or conditioned; provided , however , that Owner may assign, without the prior writtenconsent of Customer, part or all of its rights and obligations hereunder to one or more subsidiaries that are directly or indirectly wholly-owned by Owner or to any person or entity which purchases or is otherwise a successor in interest to Owner’s right, title, and interest in theTerminal; provided , further , that Customer may (i) with the prior written consent of Owner (which shall not be unreasonably withheld,conditioned or delayed), assign all of its rights and obligations hereunder to any Person which purchases or is otherwise a successor ininterest to Customer, provided such Person assumes in writing the obligations of Customer under this Agreement, and (ii) assign in part onlyits right to receive the Services hereunder to any Person, (A) that is an Affiliate of Customer (without the prior written consent of Owner), or(B) that is not an Affiliate of Customer (with the prior written consent of Owner, which shall not be unreasonably withheld, conditioned ordelayed), provided that Customer shall act as the sole agent for any such Person described in this clause (ii) for all purposes under thisAgreement, including making any representations and warranties of Customer on behalf of such Person and Owner shall have no recourseagainst such Person described in this clause (ii) and shall look solely to Customer for performance of the obligations of Customer hereunder.No such assignment by Customer of its rights or obligations hereunder shall relieve Customer of any of its obligations hereunder, includingpayment obligations.15Section 15. Notice .All notices and other communications given pursuant to this Agreement shall be in writing and sent by email, facsimile, or overnightcourier to the respective Party’s address set forth on Attachment A and to the attention of the person and department indicated. A notice givenby email or facsimile shall be deemed to have been received when transmitted to the other Party (if, in the case of email, confirmed by thereceiving Party’s email system as received and opened, and if by fax confirmed by the notifying Party’s transmission report). A notice givenby overnight courier shall be deemed to have been received when the notice is actually delivered to or refused by the other Party, as reflectedin the courier company’s delivery records. Any notice received after 5:00 p.m. is not deemed received until 11:00 a.m. the following businessday. A Party may change its address, email or facsimile number by giving written notice in accordance with this Section, which change iseffective upon receipt.Section 16. Compliance with Law and Safety .16.1 Customer warrants that the Product tendered by it has been and will be produced, transported and handled in full compliancewith all Applicable Law. Owner warrants that the services provided by it under this Agreement are and will be in full compliance with allApplicable Law. Each Party also warrants that it may lawfully receive and handle the Product, and it will furnish to the other Party anyevidence required to provide compliance with Applicable Law and to file with applicable Governmental Authorities reports evidencing suchcompliance with Applicable Law.16.2 Customer will furnish Owner with written information (including any applicable SDS) concerning the safety and healthaspects of the Product received, terminalled, or stored under this Agreement. Customer will make available such information to all personswho request copies of such information, including without limitation, Owner’s agents and contractors.Section 17. Default and Remedies.17.1 Events of Default. Notwithstanding any other provision of this Agreement, an event of default (“ Default ” or “ Event ofDefault ”) shall be deemed to occur with respect to a Party when:(a) Such Party fails to make payment to the other Party when due under this Agreement, within ten (10) Business Days of awritten demand therefor.(b) Other than a Default described in Sections 16.1(a) and (c) , such Party fails to perform any obligation or covenant to theother Party under this Agreement, which failure is not cured to the reasonable satisfaction of the other Party within thirty (30) days from thedate that such Party receives written notice that corrective action is needed or, if such default is of a nature that it cannot reasonably be curedwithin thirty (30) days, such Party fails to commence to cure same within such thirty (30) days period and continuously pursue such curethereafter to completion with reasonable diligence.(c) Such Party becomes a Bankrupt.17.2 Remedies. Notwithstanding any other provision of this Agreement, upon the occurrence of an Event of Default with respect toeither Party (the “ Defaulting Party ”), the other Party (the “ Performing Party ”) shall in its sole discretion, in addition to all other remediesavailable to it and without incurring any Liabilities to the Defaulting Party or to Third Parties, be entitled to do one or more of the following:(a) suspend its performance under this Agreement without prior notice to the Defaulting Party, (b) proceed against the Defaulting Party fordamages occasioned by the Defaulting Party’s failure to perform, and (c) upon one (1) Business Day’s notice to the Defaulting Party,terminate and liquidate this Agreement. Notwithstanding the foregoing, in the case of an Event of Default described in Section 17.1(d) , noprior notice shall be required.1617.3 Non-Exclusive Remedy. The Performing Party’s rights under this Article 16 shall be in addition to, and not in limitation orexclusion of, any other rights that it may have (whether by agreement, operation of law or otherwise), including any rights and remediesunder any applicable Uniform Commercial Code. The Performing Party may enforce any of its remedies under this Agreement successivelyor concurrently at its option. No delay or failure on the part of a Performing Party to exercise any right or remedy to which it may becomeentitled on account of an Event of Default shall constitute an abandonment of any such right, and the Performing Party shall be entitled toexercise such right or remedy at any time during the continuance of an Event of Default. All of the remedies and other provisions of thisArticle 17 shall be without prejudice and in addition to any right of setoff, recoupment, combination of accounts, lien or other right to whichany Party is at any time otherwise entitled (whether by operation of law, in equity, under contract or otherwise).17.4 Subject to any lien rights Owner has with respect to the Product, upon any termination of this Agreement, Customer shallremove or cause to be removed all Product from the Terminal and Storage Tanks. In the event Customer has not removed or caused to beremoved all Product on the date that this Agreement is terminated, Owner at its sole discretion may elect to have the Product removed fromthe Terminal, and Customer agrees to reimburse Owner for the actual costs of such removal, which shall include the expense of any necessarycleaning and restoration to their previous condition of the Terminal and Storage Tanks, plus a *** percent (***%) administrative fee.17.5 Each Party’s obligations under this Agreement shall end as of the effective date of its termination in accordance with thisAgreement; provided , however , that each Party shall remain liable to the other hereunder with respect to (a) any obligations accruing underthis Agreement prior to the effective date of such termination, including any indemnification obligations provided hereunder or (b) asotherwise provided in this Agreement. Notwithstanding anything in this Agreement to the contrary, Sections 2.6 , 8 , 10.1 , 14.5 , 19 , 20 , and21 shall survive the expiration or termination of this Agreement.Section 18. Insurance.18.1 Owner’s Insurance . Owner, at its sole cost and expense, shall procure and maintain in full force and effect during the Term ofthis Agreement and any extensions thereto the following types of insurance and in the amounts indicated:(a) Worker’s Compensation & Employer’s Liability . Statutory benefits covering all of Owner’s employees, contractorsand subcontractors engaged in providing work or services under this Agreement. The policy shall also be endorsed to provide a Waiver ofSubrogation in favor of Customer. Owner shall also maintain Employer’s Liability coverage with limits of at least $1,000,000 for bodilyinjury caused by any accident - each accident; $1,000,000 bodily injury caused by disease - policy limit; and $1,000,000 bodily injury causedby disease - each employee.(b) Commercial General Liability Insurance : Such insurance shall include coverage for premises liability, personal &advertising injury, products and completed operations liability, property damage and contractual liability insurance. Coverage shall be on an“occurrence form” with limits of at least $5,000,000 per occurrence (use of primary and excess limits to achieve the total required limit isacceptable as long as all excess insurance follows form over the underlying). The policy(ies) shall be endorsed to name Customer as“additional insureds” and the coverages for the “additional insureds” shall be primary and non-contributory before any other insurance or selfinsurance, including deductible, maintained by or provided to the Customer. The policy(ies) shall also be endorsed to provide a Waiver ofSubrogation in favor of Customer.(c) Terminal Operators’ Legal Liability Insurance : The limits of which shall be at least $5,000,000 per occurrence. Thepolicy(ies) shall be endorsed to name Customer as “additional insureds”17and the coverages for the “additional insureds” shall be primary and non-contributory before any other insurance or self-insurance, includingdeductible, maintained by or provided to the Customer.(d) Pollution Liability Insurance : The limits of which shall be at least $10,000,000 for each incident and aggregate,including coverage for Third Party Claims of bodily injury and property damage both on-site and off-site, arising out of or involving directlyor indirectly work or services of Owner which is the subject of this Agreement. The policy shall be endorsed to name Customer as “additionalinsureds” and this coverage shall be primary and non-contributory before any other insurance or self-insurance, including any deductible,maintained by the or provided to the Customer.(e) Automobile Liability Insurance : Applicable to all of Owner’s owned, leased, hired or non-owned vehicles with acombined single limit of at least $1,000,000 for any one loss. The policy shall be endorsed to name Customer as an “additional insured” andthis coverage shall be primary and non-contributory before any other insurance or self-insurance, including any deductible, maintained by orprovided to Customer. The policy shall also be endorsed to provide a Waiver of Subrogation in favor of Customer. If hauling Product thepolicy shall be endorsed with Broadened pollution coverage using ISO endorsements CA-99-48 and MCS-90.18.2 Customer’s Insurance . Customer, at its sole cost and expense, shall procure and maintain in full force and effect during theterm of this Agreement and any extensions thereto the following types of insurance and in the amounts indicated:(a) Commercial General Liability Insurance: Including coverage for premises liability, personal and advertising injury,products and completed operations liability, sudden and accidental pollution, property damage and contractual liability insurance. Coverageshall be on an “occurrence form” with limits of at least $5,000,000 per occurrence (use of primary and excess limits to achieve the totalrequired limit is acceptable as long as all excess insurance follows form over the underlying). The policy(ies) shall be endorsed to nameOwner as “additional insureds” and the coverages for the “additional insureds” shall be primary and non-contributory before any otherinsurance or self insurance, including deductible, maintained by or provided to the Owner. The policy(ies) shall also be endorsed to provide aWaiver of Subrogation in favor of Owner.18.3 Additional Insurance Requirements . With respect to the coverages required pursuant to Sections 17.1 and 17.2 above:(a) Each insurance policy must be maintained with an insurance company having an A.M. Best Financial Strength Ratingof A-, VIII or higher.(b) Each Party shall cause the issuing insurance company to provide at least thirty (30) days prior written notice to theother Party of any cancellation or non-renewal, except that ten (10) days notice shall apply in the case of cancellation for non-payment ofpremium.(c) No less than five (5) business days prior to the start of any work or services performed for Customer or prior to theCommencement Date of this Agreement (whichever occurs first), each Party shall furnish to the other Party original certificates of insuranceevidencing the insurance coverage required of such Party pursuant to this Section 17 . The certificates of insurance shall show the other Partyas “certificate holder” and “additional insured” as required by the above insurance requirements using the specific wording indicated andshowing the primary and non-contributing coverage. No later than the renewal date of any insurance policies required by this Agreement,each Party shall supply the other Party with new, original certificates of insurance in compliance with the terms of this Agreement.18Section 19. Compliance.All Customer trucks, common carriers, and other Third Parties used by Customer in accessing the Terminal will be required to meetOwner’s reasonable approval. Owner’s requirements for approval shall include meeting Owner’s insurance requirements and execution of aterminal access agreement provided by Owner. All Customer trucks, common carriers, and other Third Parties used by Customer in accessingthe Terminal will also be required to comply with all of Owner’s health, safety, training, loading procedures, and environmental procedures inplace at the Terminal.Section 20. Indemnity.20.1 Indemnity . Subject to Section 8 , each Party (“ Indemnifying Party ”) shall indemnify and hold the other Party, its Affiliates,and their employees, directors, officers, representatives, agents, and contractors (collectively, the “ Indemnified Party ”) harmless from andagainst any and all Liabilities, regardless of whether such Liabilities are attributable to the strict liability of the Indemnified Party, to theextent arising from the Indemnifying Party’s (i) breach of this Agreement, (ii) negligence or willful misconduct of it, its Affiliates, and theiremployees, directors, officers, invitees, representatives, agents, or contractors in connection with the performance of such Party’s obligationsunder this Agreement, or (iii) failure to comply with Applicable Law with respect to the sale, transportation, storage, handling, or disposal ofthe Product, unless and to such extent that such Liability results from the Indemnified Party’s breach of this Agreement, negligence or willfulmisconduct, or failure to comply with Applicable Law. In addition, Customer shall indemnify and hold Owner, its Affiliates, and theiremployees, directors, officers, representatives, and agents, harmless from and against any and all Liabilities arising from the instructions andspecifications for processing any Product provided in writing by Customer or the use of any Product by Customer or a Third Party, and allprovisions of this Section 19 shall apply to such indemnity unless and to such extent that such Liability results from Owners breach of thisAgreement, negligence, gross negligence, willful misconduct, or failure to comply with Applicable Law.20.2 No Third Party Rights . The Parties’ obligations to defend, indemnify, and hold each other harmless under the terms of thisAgreement shall not vest any rights in or be enforceable by any Third Party, whether a Governmental Authority or private entity, nor shallthey be considered an admission of liability or responsibility for any purposes other than those enumerated in this Agreement. The terms ofthis Agreement are enforceable only by the Parties and their permitted successors and assigns, and no Third Party, including a member ofOwner, shall have a separate right to enforce any provision of this Agreement, or to compel any Party to comply with the terms of thisAgreement.20.3 Notice . The Indemnified Party shall notify the Indemnifying Party as soon as practicable after receiving notice of any claimor proceeding brought against it that might give rise to an indemnity claim under this Agreement (“ Third Party Claim ”) and shall furnish tothe Indemnifying Party the complete details within its knowledge. Any delay or failure by the Indemnified Party to give notice to theIndemnifying Party shall not relieve the Indemnifying Party of its obligations except to the extent, if any, that the Indemnifying Party shallhave been materially prejudiced by reason of such delay or failure.20.4 Claims . The Indemnifying Party shall have the right to assume the defense, at its own expense and by its own counsel, of anyThird Party Claim; provided , however , that such counsel is reasonably acceptable to the Indemnified Party. Notwithstanding theIndemnifying Party’s appointment of counsel to represent an Indemnified Party, the Indemnified Party shall have the right to employ separatecounsel reasonably acceptable to the Indemnifying Party, and the Indemnifying Party shall bear the reasonable fees, costs and expenses ofsuch separate counsel if in the Indemnified Party’s reasonable judgment (i) the use of counsel chosen by the Indemnifying Party to representthe Indemnified Party would present such counsel with a conflict of interest or defenses that are available to the Indemnified Party that arenot available to the Indemnifying Party or (ii) the Indemnifying Party shall not have employed counsel to represent the19Indemnified Party within a reasonable time after notice of the institution of such Third Party Claim. If requested by the Indemnifying Party,the Indemnified Party agrees to reasonably cooperate with the Indemnifying Party and its counsel in contesting any claim or proceeding thatthe Indemnifying Party defends, including, if appropriate, making any counterclaim or cross-complaint. All reasonably incurred costs andexpenses incurred in connection with the Indemnified Party’s cooperation shall be borne by the Indemnifying Party.20.5 Settlement . No Third Party Claim may be settled or compromised by (i) the Indemnified Party without the consent of theIndemnifying Party or (ii) by the Indemnifying Party without the consent of the Indemnified Party.Section 21. Confidentiality.21.1 Confidential Information . The term “ Confidential Information ” means all nonpublic information, including technicalinformation, trade or business secrets, or the like, disclosed by either Party to the other Party in carrying out the terms and purpose of thisAgreement, either directly or indirectly, in writing, orally or by inspection of tangible objects (including without limitation written or printeddocuments, email correspondence and attachments, electronic files, and computer disks, whether machine or user readable). “ConfidentialInformation” includes, without limitation, information relating to a Party's research, development, trade secrets, or business affairs that theParty treats as confidential. The Parties acknowledge and agree that any and all information regarding this Agreement, including withoutlimitation the terms and conditions of this Agreement, shall be deemed to be Confidential Information. The term “ Receiving Party ” means aParty that receives Confidential Information of the other Party (“ Disclosing Party ”).21.2 Restrictions on Disclosure . The Receiving Party shall maintain in confidence the Confidential Information so received andwill not use such information, except to the extent permitted under this Agreement, to the detriment of the Disclosing Party, until such time asthe Confidential Information so received enters the public domain other than by the act or omission of the Receiving Party. A Receiving Partyshall limit disclosure of the Disclosing Party’s Confidential Information to those of its employees, subcontractors, attorneys, agents andconsultants with a need to know the Confidential Information, subject to a nondisclosure obligation comparable in scope to this Section 20 .Each Party shall protect the other Party’s Confidential Information using the same degree of care (but no less than a reasonable degree ofcare) that it uses to protect its own Confidential Information. The obligations imposed by this Section shall be unlimited in duration; provided, however , such obligations shall not apply to any Confidential Information that: (i) is or becomes publicly known through no fault of theReceiving Party; (ii) is developed independently by the Receiving Party prior to the date of disclosure; (iii) is rightfully obtained by theReceiving Party from a Third Party entitled to disclose the information without confidentiality restrictions or (iv) as required by ApplicableLaw or by regulation. A Receiving Party also may disclose Confidential Information to the extent required by a court or other GovernmentalAuthority, provided that the Receiving Party promptly notifies the Disclosing Party of the disclosure requirement prior to disclosure andcooperates with the Disclosing Party (at the latter’s expense and at its request) to resist or limit the disclosure.21.3 Injunctive Relief . Receiving Party acknowledges and agrees that a breach or threatened breach of the confidentialityobligations set forth herein may result in immediate and irreparable damage to the Disclosing Party for which there may be no adequateremedy at law, and, in such event, the Disclosing Party may seek appropriate injunctive relief. Disclosing Party’s pursuit of any remedy willnot constitute a waiver of any other right or remedy available under this Agreement or under Applicable Law.Section 22. Miscellaneous.22.1 Headings . The headings of the sections and subsections of this Agreement are for convenience only and shall not be used inthe interpretation of this Agreement.2022.2 Amendment or Waiver . This Agreement may not be amended, modified, or waived except by written instrument executed byofficers or duly authorized representatives of the respective Parties. No waiver or failure of enforcement by any Party of any default by anyother Party in the performance of any provision, condition or requirement herein shall be deemed to be a waiver of, or in any manner arelease of the defaulting Party from, performance of any other provision, condition, or requirement herein, nor deemed to be a waiver of, or inany manner a release of the defaulting Party from, future performance of the same provision, condition, or requirement; nor shall any delay oromission of any non-defaulting Party to exercise any right hereunder in any manner impair the exercise of any such right or any like rightaccruing to it thereafter.22.3 Severability . Any provision of this Agreement that is prohibited or not enforceable in any jurisdiction shall, as to thatjurisdiction, be ineffective only to the extent of the prohibition or lack of enforceability without invalidating the remaining provisions of thisAgreement, or affect the validity or enforceability of those provisions in another jurisdiction or the validity or enforceability of thisAgreement as a whole.22.4 Entire Agreement and Conflict with Attachments . This Agreement (including Attachments) contains the entire and exclusiveagreement between the Parties with respect to the subject matter hereof, and there are no other promises, representations, or warrantiesaffecting it. The terms of this Agreement may not be contradicted, explained, or supplanted by any usage of trade, course of dealing, orcourse of performance and any other representation, promise, statement, or warranty made by either Party or their agents that differs in anyway from the terms contained herein will be given no force or effect. In the case of any conflict between the body of this Agreement and anyof its Attachments, the terms contained in the Attachments will govern.22.5 Governing Law and Jurisdiction; Jury Trial Waiver . This Agreement will be construed and governed by the laws of the Stateof Oklahoma except the choice of law rules of that State that may require the application of the laws of another jurisdiction. Exclusivejurisdiction and venue is agreed to be the state or federal courts within the State of Oklahoma. Each Party irrevocably waives any right to atrial by jury in any proceeding related to this Agreement.22.6 Counterparts . This Agreement may be executed in any number of counterparts each of which, when so executed anddelivered (including by facsimile or electronic mail transmission), will be deemed original but all of which together will constitute one andthe same instrument.22.7 Further Assurances . Subject to the terms and conditions of this Agreement, each of the Parties hereto will use commerciallyreasonable efforts to take, or cause to be taken, all action, and to do, or cause to be done, all things necessary under applicable laws andregulations to consummate the transactions contemplated by this Agreement.22.8 Independent Contractor . In performing services pursuant to this Agreement, Owner is acting solely as an independentcontractor maintaining complete control over its employees and operations. Neither Party is authorized to take any action in any waywhatsoever on behalf of the other, except as specified in this Agreement, or in subsequent written agreements between the parties.2122.9 No Third-Party Beneficiaries . Except as provided in Section 19 , nothing contained in this Agreement, expressed or implied,is intended or shall be construed to confer upon or give to any Person (including any limited partners of Blueknight Energy Partners, L.P.)other than the Parties hereto and their successors or permitted assigns, any rights or remedies under or by reason of this Agreement.22.10 No Strict Construction . The Parties to this Agreement have participated jointly in the negotiation and drafting of thisAgreement. In the event an ambiguity or question of intent or interpretation arises with respect to this Agreement, this Agreement shall beconstrued as if drafted jointly by the Parties, and no presumption or burden of proof shall arise favoring or disfavoring a Party by virtue of theauthorship of any of the provisions of this Agreement.[Signature page follows.]22This Agreement 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/ Mark A. Hurley Name:Mark A. Hurley Title:Chief Executive Officer BKEP ASPHALT, L.L.C. By:/s/ Mark A. Hurley Name:Mark A. Hurley Title:Chief Executive Officer LESSEE ERGON ASPHALT & EMULSIONS, INC. By:/s/ J. Baxter Burns, II Name:J. Baxter Burns, II Title:PresidentSignature page to Storage, Throughput and Handling AgreementATTACHMENT ANoticesIf to Owner:BKEP Materials, L.L.C.6060 American Plaza Ste 600Tulsa OK 74135Phone: (918) 237-4000Fax: (918) 237-4001Attention: Chief Operating OfficerWith copy to:General CounselIf to Customer:Ergon Asphalt & Emulsions, Inc.2829 Lakeland Drive, Suite 2000Flowood, MS 39232Phone: (601)933-3000Fax: (601) 933-3363Attention: J. Baxter Burns, II, PresidentE-Mail: baxter.burns@ergon.comWith a copy to:Watson Heidelberg, PLLC2829 Lakeland Drive, Suite 1502Flowood, MS 39232Phone: (601) 939-8900Fax: (601) 932-4400Attention: J. Kevin WatsonE-mail: kwatson@whjpllc.comFees for Storage and Terminalling Services; Reimbursement of Energy Costs(a) Storage Fee : For all periods on or after January 1, 2019, Customer will be obligated to pay for storage capacity at the Terminal eachMonth, subject to Sections 5.6 and 5.7 . The storage fee shall be equal to $*** per Contract Year (“ Storage Rate ”), as may be adjusted asprovided in this Attachment A. The Storage Rate shall be paid in advance in equal monthly installments.Owner acknowledges that on December 21, 2018, Customer prepaid the Storage Fees for the months of January, February and March, 2019,in the amount of $***. Additionally, Customer has paid to Owner upon execution of this Agreement the sum of $*** in prepayment of theStorage Fees for the months of April, May, June, July, August and September, 2019. These payments represent a discounted prepayment ofStorage Fees for the months indicated and are non-refundable in the event of termination of this Agreement prior to date through whichpayments have been made.Attachment A- 1(b) Reimbursement of Energy Costs : Customer shall reimburse Owner for all energy costs (e.g., electricity, fuel oil, natural gas, steam)applicable to the Services provided hereunder at the Terminal. Energy costs will be based upon the determination of Owner of the portion ofTerminal energy costs applicable to the Services provided hereunder. Energy costs will be invoiced monthly for the prior Month’s energyusage as available.Adjustments :All fees will be escalated January 1, 2020 and will be escalated every January 1st thereafter such that the prior year escalated fee is multipliedby the percentage change, if any, in the Consumer Price Index - All Urban Consumers - all items less food and energy (U.S. city average base1982-84 = 100) ("CPI"), as published by the Bureau of Labor Statistics of the United States Department of Labor, for the last two calendaryears for which data is available based on the average of the monthly CPI data for November to October of the most current year availablecompared to the same months of the prior year (“ CPI Adjustment ”). In no event shall any of the fees de-escalate.InvoicesCustomer shall pay the Storage Fee outlined in this Attachment A in advance each Month based upon the then-current Storage Fee. For anyperiods less than one full calendar month, the monthly Storage Fee will be prorated for the actual days of occupancy. Owner shall invoiceCustomer for all other fees on a monthly basis or upon the expiration of a Contract Year, as applicable. All invoices shall be paid inaccordance with Section 3.2 of the Agreement.Operating HoursThe operating hours of the Terminal shall be: (i) 12 hours per day with the specific starting time to be agreed upon by the Parties, Monday toFriday seasonally, excluding all Owner recognized holidays, or (ii) as otherwise mutually agreed upon by the Parties. Owner will provideovertime for Customer as needed outside of the Terminal operating hours set forth above at the following rates:(i) Monday through Friday - $*** per hour or portion thereof per employee with a four hour daily minimum per employee unless(i) the beginning of such overtime period is within two hours of the beginning of the normal operating hours of the Terminal or (ii)the end of such overtime period is within two hours of the end of the normal operating hours of the Terminal, in each case, there shallbe no daily minimum hour requirement.(ii) Saturday, Sunday and holidays - $*** per hour or portion thereof per employee with a four-hour daily minimum per employee.TerminalTerminal means the Product Storage Tanks and related equipment of Owner located at Port 33, Oklahoma.Storage TanksStorage Tanks means Tank #120-5, 48-1, 48-3, 24-2, and 20-6.Attachment A- 2ATTACHMENT BProductsIf any Product handled hereunder fails to meet the Specifications provided by Customer pursuant to this Attachment B , Owner shall ceaseshipment of such Product and notify Customer within a reasonable time period of such non-conformity and await further instructions fromCustomer regarding such non-conformity. In no event shall Owner be responsible for any non-conformity caused by any action or omissionof Customer.Owner makes no representation or warranty, express or implied, except that the Product it delivers hereunder shall have been handled inaccordance with Customers instructions as set forth on this Attachment B . Owner MAKES NO OTHER WARRANTY, EXPRESSED ORIMPLIED, AND EXPRESSLY DISCLAIMS ALL WARRANTIES OF MERCHANTABILITY OR FITNESS FOR A PARTICULARPURPOSE.ProductAsphalt cementsWith the following specifications:Closed Cup Flash Point of 275°F or aboveAttachment BExhibit 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. TexasExhibit 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 12, 2019 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 12, 2019Exhibit 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 12, 2019 /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, James R. Griffin, 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 12, 2019 /s/ James R. GriffinJames R. GriffinChief Accounting Officer and Authorized SignatoryBlueknight 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, 2018 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 Jams R. Griffin, Chief Accounting Officer and Authorized Signatory 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 12, 2019 /s/ James R. GriffinJames R. GriffinChief Accounting Officer and Authorized SignatoryBlueknight Energy Partners G.P., L.L.C.,general partner of Blueknight Energy Partners, L.P. March 12, 2019*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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