Blueknight Energy Partners, L.P. - Annual Report: 2019 (Form 10-K)

DEFINITIONS

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

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

 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 the crude oil and petroleum products will be commingled with other products of similar quality; the storage of the crude oil and petroleum products; and the delivery of the crude oil and petroleum products as directed by a distributor into a truck, vessel or pipeline.

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

PART I.

As used in this annual report, unless we indicate otherwise: (1) “Blueknight Energy Partners,” “our,” “we,” “us” and similar terms refer to Blueknight Energy Partners, L.P., together with its subsidiaries, (2) our “General Partner” refers to Blueknight Energy Partners G.P., L.L.C.  and (3) “Ergon” refers to Ergon, Inc., its affiliates and subsidiaries (other than our General Partner and us).

Forward-Looking Statements

This report contains “forward-looking statements” within the meaning of the federal securities laws. Statements included in this annual report that are not historical facts (including any statements regarding plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto) are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “will,” “should,” “believe,” “expect,” “intend,” “anticipate,” “estimate,” “continue” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition, or state other “forward-looking” information. We and our representatives may from time to time make other oral or written statements that are also forward-looking statements.

Such forward-looking statements are subject to various risks and uncertainties that could cause actual results to differ materially from those anticipated as of the date of this report. Although we believe that the expectations or assumptions reflected in these forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will prove to be correct. Important factors that could cause our actual results to differ materially from the expectations reflected in these forward-looking statements include, among other things, those set forth in “Item 1A-Risk Factors,” included in this annual report, and those set forth from time to time in our filings with the Securities and Exchange Commission (“SEC”), which are available through the Investors - SEC Filings 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 to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements contained throughout this report.

Item 1.    Business.

Overview

We are a publicly traded master limited partnership with operations in 27 states. We provide integrated terminalling, gathering and transportation services for companies 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, the Partnership 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 crude oil trucking and producer field services operating segment to crude oil trucking services during the second quarter of 2018. See Note 6 to our consolidated financial statements for additional information.  

Our Operations

We were formed as a Delaware limited partnership in 2007 to own, operate and develop a diversified portfolio of complementary midstream energy assets.  Our operating assets are owned by, and our operations are conducted through, our subsidiaries.  Our General Partner has sole responsibility for conducting our business and for managing our operations.  Ergon owns 100% of the outstanding voting interests of Blueknight GP Holding, L.L.C., which owns 100% of the capital interest of our General Partner.

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 no assets 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 partnership agreement imposes no additional material liabilities upon our General Partner or obligations to contribute to us other than those liabilities and obligations imposed on 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 23, 2020:

Our Strengths and Strategies

Strategically placed assets.  We own and operate a diversified portfolio of complementary midstream energy assets that includes approximately 8.8 million barrels 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 serve throughout the continental United States. Our primary crude oil terminalling facilities are located within the Cushing Interchange in Cushing, Oklahoma, one of the largest crude oil marketing hubs in the United States and the designated point of delivery specified in all New York Mercantile Exchange (“NYMEX”) crude oil futures contracts. We believe that the Cushing Interchange will continue to serve as one of the largest crude oil marketing hubs in the United States. In addition, we have approximately 611 miles of strategically positioned gathering and transportation pipelines, primarily located in Oklahoma.

Growth opportunities.  We evaluate growth opportunities from multiple angles, including growth through third-party acquisitions, optimizing our existing asset base, and enhancing our pipeline and terminal connectivity.  In addition, Ergon has indicated that it views us as a potential vehicle of growth in the midstream sector. We cannot say with any certainty whether or not Ergon will pursue future acquisition or expansion opportunities in the midstream energy space with us, or if we will choose to pursue any such opportunity Ergon presents.

Experienced management team.  Our General Partner has an experienced and knowledgeable management team with extensive experience in the energy industry. We expect to directly benefit from this management team’s strengths, including significant relationships throughout the energy industry with customers of 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 and is 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 into six primary business segments: Refining & Marketing, Specialty Chemicals, Asphalt & Emulsions, Midstream & Logistics, Oil & Gas, and Construction & Real Estate. 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 competing with 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 those assets.

Industry Overview

Asphalt Industry

We provide asphalt terminalling services to marketers and distributors of liquid asphalt and asphalt-related products. We do not take title to the product. We lease certain facilities for operation by our customers and at some facilities we process, blend and manufacture products to meet our customers’ specifications. Our terminal network consists of 53 facilities located coast-to-coast throughout the United States.

Liquid asphalt is one of the oldest engineering materials. Liquid asphalt’s adhesive and waterproofing 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 hydrocarbons with the highest boiling points settle at the bottom. These tar-like fractions, called residuum, require relatively little additional processing to become products such as liquid asphalt. Liquid asphalt production typically represents only a small portion of the total product production in the crude oil refining process. The liquid asphalt produced by petroleum distillation can be sold by the refinery either directly into the wholesale and retail liquid asphalt markets or 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 or cut back with petroleum solvents (cutback asphalts), or emulsified in a water base with emulsifying chemicals by a colloid mill (asphalt emulsions). Hot mix asphalt is produced by mixing hot asphalt cement and heated aggregate (stone, sand and/or gravel). The hot mix asphalt is loaded into trucks for transport to the paving site, where it is placed on the road surface by paving machines and compacted by rollers. Hot mix asphalt is used for new construction, reconstruction and for thin maintenance 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 mix asphalt overlay, cold mix pothole patching material and preventive maintenance surface applications such as chip seals. Asphalt emulsions are also used for fog seal, slurry seal, scrub seal, sand seal and microsurfacing maintenance treatments, warm mix emulsion/aggregate mixtures, base stabilization and both central plant and in-place recycling. Asphalt emulsions and cutback asphalts are generally sold directly to government agencies but are also sold to contractors.

The asphalt industry in the United States is characterized by a high degree of seasonality. Much of this seasonality is due to the impact that weather conditions have on road construction schedules, particularly in cold weather states. Refineries produce liquid asphalt year-round, but the peak asphalt demand season is during the warm weather months when most of the road construction activity in the United States takes place.  Liquid asphalt marketers and finished asphalt product producers with access to storage capacity possess the inherent advantage of being able to purchase supply from refineries on a year-round basis and then sell finished 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 we serve, which begins at the source of production and extends to the point of distribution to the end user customer, is commonly referred to as the “midstream” market. Our crude oil operations are located primarily in Oklahoma and Kansas, where there are extensive crude oil production operations in place, and our assets extend from gathering systems and trucking networks in and around producing fields to transportation pipelines carrying crude oil to logistics hubs, such as the Cushing Interchange, where we have terminalling facilities that aid our customers in managing their crude oil.

Gathering, marketing and transportation.  Pipeline transportation is generally considered the lowest cost and safest method for shipping crude oil and refined petroleum products to other locations. Crude oil pipelines transport oil from the wellhead to logistics hubs and/or refineries. Logistics hubs like the Cushing Interchange provide storage and connections to other pipeline systems and other modes of transportation, such as truck, railroad, barge and tanker ship. Vessels and railroads provide additional transportation capabilities for shipping crude oil between gathering storage systems, pipelines, terminals and end users. Vessel transportation is typically a cost-efficient mode of transportation that allows for the ability to transport large volumes of crude oil over long distances.

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

Terminalling.  Terminalling facilities complement the crude oil pipeline gathering and transportation systems. Terminals are facilities where crude oil is transferred to or from a storage facility or transportation system, such as a gathering pipeline, to another transportation system, such as trucks or another pipeline. Terminals play a key role in moving crude oil to end users such as refineries by providing 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 capacity is provided to third parties. Terminalling fees, also referred to as throughput fees, are generated when a terminal receives crude oil from a shipper and redelivers it to another shipper. Both storage fees and terminalling fees are earned from pipeline operators, refiners, gatherers and traders that need segregated storage, traders who 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 United States and the designated point of delivery specified in NYMEX crude oil futures contracts. As the NYMEX delivery point and a cash market hub, the Cushing Interchange serves as the primary source of refinery feedstock for Midwest refiners and plays an integral role in establishing and maintaining markets for many varieties of foreign and domestic crude oil. The following table lists certain of the entities with incoming pipelines connected to the Cushing Interchange, the proprietary terminals within the complex and outgoing pipelines from the Cushing Interchange for delivery throughout the United States: 

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

Asphalt Terminalling Services

With approximately 8.8 million barrels of asphalt cement storage capacity, we are able to provide our customers the ability to effectively manage their liquid asphalt inventories while allowing significant flexibility in their processing and marketing activities. As of March 23, 2020, we have 53 terminals located in 26 states 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 and providing terminalling services at certain facilities. We generate revenues by charging a fee for the lease of a facility or for services provided as asphalt products are terminalled in our facilities.

As of March 23, 2020, we have leases and storage agreements relating to all of our 53 asphalt facilities.  These agreements have, based on a weighted average by remaining fixed revenue, approximately 4.7 years remaining under their terms. One agreement expires at the end of 2020, and the remaining agreements expire at varying times thereafter, through 2026. 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. We operate the asphalt facilities that are contracted by storage, throughput and handling agreements, while our contract counterparties operate the asphalt facilities that are subject to lease agreements.

At leased facilities, our customers conduct the operations at the asphalt facility, including the storage and processing of asphalt products, and we collect a monthly rental fee relating to the lease of such facility.  Generally, under the terms of those leases, (i) title to the asphalt, raw materials or finished asphalt products received, 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 such authorizations and is responsible for insuring such asphalt facility; and (iv) most routine maintenance and repairs of such asphalt facility are the responsibility of the 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 direct exposure 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 23, 2020:

Our 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 in excess of 20 years.

Significant Customers.  For the year ended December 31, 2019, Ergon accounted for at least 30% but not more than 35% of our total asphalt terminalling services revenue. Associated Asphalt, Inc. and Delek US Holdings, Inc. each accounted for at least 10% but not more than 20% of asphalt terminalling services revenue in 2019.  The loss of any of those customers could have a material adverse effect on our business, cash flows and results of operations.  No other customer accounted for more than 10% of our asphalt terminalling services revenue during 2019. As of March 23, 2020, we have storage, throughput and handling agreements or operating leases with Ergon for 23 of our asphalt facilities. For more information regarding the Ergon agreements, please see Note 12 to our consolidated financial statements.

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 effectively manage their crude oil inventories and enhance flexibility in their marketing and operating activities. Our crude oil terminalling assets are located throughout our core 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 interstate common carrier pipelines and regional independent refiners, among other third parties.  Our crude oil terminals derive most of their revenues from terminalling fees charged to customers.

As of March 23, 2020, we have approximately 5.5 million barrels of crude oil storage under service contracts, including 3.3 million barrels of crude oil storage contracts that expire in 2020. The remaining terms on the service contracts that expire after 2020 range from 15 months to 21 months. Storage contracts with a subsidiary of Vitol Group (together with its subsidiaries, “Vitol”) represent 2.9 million barrels of crude oil storage capacity under 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 storage capacity at our Cushing terminal and at our other terminals at the end of such periods:

The following table outlines the location of our crude oil terminals and their storage capacities and number of tanks as of December 31, 2019:

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 additional acres of land within the Cushing Interchange that is available for future expansion.

Our 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 in our Cushing terminal has been built since 2002. We estimate that our storage tanks have a weighted average age of 16 years.

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

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 the Cushing 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 Centurion, Magellan Midstream Partners, Enterprise Products Partners, Sunoco Logistics Partners L.P., Plains All American Pipeline, L.P., Enbridge Inc., Energy Transfer LP, and Deeprock Energy Resources, LLC, as well as truck stations. Our Cushing terminal’s pipeline connections to major markets in the Mid-Continent region provide our customers with marketing flexibility. Our Cushing terminal can deliver crude oil via pipeline and, in the aggregate, is capable of receiving and/or delivering approximately 350,000 Bpd of crude oil. 

Significant Customers.  For the year ended December 31, 2019, Vitol accounted for at least 50% but not more than 55% of our total crude oil terminalling revenue, and Citigroup Energy, Inc. and Sunoco Logistics Partners L.P. each accounted for at least 10% but not more than 20% of our total crude oil terminalling revenue.  The loss of any of these customers could have a material adverse effect on our business, cash flows and results of operations. No other customer accounted for more than 10% of our crude oil terminalling revenue during 2019.

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 611 miles. In addition, we purchase crude oil at production leases in Oklahoma, and we market those barrels primarily at the Cushing Interchange.

Mid-Continent Pipeline System.  Our Mid-Continent pipeline system provides access to our Cushing terminal and other storage facilities. Our Mid-Continent pipeline system consists of approximately 611 miles of various sized pipeline, and has a capacity of approximately 50,000 Bpd. The majority of the Mid-Continent pipeline system is located in Oklahoma. Crude oil delivered into the Oklahoma portion of our Mid-Continent pipeline system is transported to our Cushing terminal or delivered to local area refiners. The Mid-Continent pipeline system previously included an approximately 35-mile gathering and transportation system in the Texas Panhandle near Dumas, Texas. This portion of the Mid-Continent system was sold in December 2019.

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.  From April 2016 to July 2018, a portion of our Oklahoma system was out of service, which reduced transportation capacity by approximately 20,000 Bpd. In July 2018, we were able to restore service to that portion of pipeline. The ability to fully utilize the capacity of these systems may be impacted by the market price of crude oil and producers’ decisions to increase or decrease production in the areas we serve.

Significant Customers. For the year ended December 31, 2019, Vitol accounted for 99% of crude oil pipeline services marketing revenue and 45% of crude oil pipeline transportation services revenue. Scout Energy Management, LLC and CP Energy, LLC accounted for at least 10% but not more than 20% of crude oil pipeline transportation services revenue.  Scout Energy Management, LLC was the sole customer on the 35-mile gathering and transportation system that was sold in December 2019. We do not expect the loss of this customer due to the sale of the system to have a material adverse effect on our crude oil pipeline services segment going forward as operating margin on the system was not significant. The loss of any of these other customers could have a material adverse effect on our business, cash flows and results of operations.

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 the name of the crude oil trucking and producer field services operating segment to crude oil trucking services during the second quarter of 2018. See Note 6 to our consolidated financial statements for additional information.

To complement our pipeline gathering, marketing and transportation business, we use our 63 owned or leased tanker trucks, which have an average tank size of approximately 200 barrels, to move crude oil to aggregation points, pipeline injection stations and storage facilities. Our tanker trucks moved an average of 27,000 Bpd and 26,000 Bpd for the years ended December 31, 2018 and 2019, respectively, from wellhead locations not served by pipeline gathering systems. The following table outlines the distribution of our trucking assets among our operating areas as of March 23, 2020:

Significant Customers. For the year ended December 31, 2019, MV Purchasing, LLC accounted for at least 40% but not more than 45% and Devon Gas Services, LP accounted for at least 15% but not more than 20% of crude oil trucking services revenue.  The loss of either of these customers could have a material adverse effect on our business, cash flows and results of operations.  In addition, approximately 33% of crude oil trucking services revenue for the year ended December 31, 2019, were earned by providing services to our crude oil pipeline services segment. No other customer accounted for more than 10% of our crude oil trucking services revenue during 2019.

Competition

We compete with national, regional and local liquid asphalt terminalling companies and crude oil gathering, storage and pipeline companies, including the major integrated oil companies, of widely varying sizes, financial resources and experience.  We are subject to competition from other crude oil gathering, pipeline transportation, terminalling operations and trucking operations that may be able to supply our customers with the same or comparable services on a more competitive basis.

The asphalt industry is highly fragmented and regional in nature. Participants range in size from major oil companies to small family-owned businesses.  Participants in the asphalt business include refiners such as BP p.l.c., Flint Hills Resources, L.P., CHS, Inc., ExxonMobil Corporation, ConocoPhillips Co., NuStar Energy L.P., Ergon Refining, Inc., Marathon Petroleum Company LLC, Alon USA LP, Suncor Energy Inc. and Valero Energy Corporation; resellers such 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.

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 Energy Transfer LP, among others. With respect to our crude oil terminalling services, our competitors include Magellan Midstream Partners, L.P., Enbridge Inc., Enterprise Products Partners L.P., Plains All American Pipeline, L.P. and Energy Transfer LP, among others.  Several of our competitors conduct portions of their operations through publicly traded partnerships with structures similar to ours, including Plains All American Pipeline, L.P., Enterprise Products Partners L.P., Sunoco Logistics Partners L.P. and Magellan Midstream Partners, L.P.  Our ability to compete could be harmed by factors we cannot control, including:

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

Pipeline Regulation

We currently do not offer transportation services regulated by the Federal Energy Regulatory Commission (“FERC”). Our pipeline segments are subject to regulatory 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, for pipelines that pose a greater risk to populated areas or environmentally sensitive areas, impose a more rigorous requirement for the implementation of pipeline integrity management programs for our pipelines. The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“Pipeline Safety Act”) was enacted in January 2012.  That legislation increased the maximum civil penalties for pipeline safety administrative enforcement actions; required the DOT to study and report on the expansion of integrity management requirements, the sufficiency of existing gathering line regulations to ensure safety and the feasibility of leak detection systems for hazardous liquid pipelines; required pipeline operators to verify their records on maximum allowable operating pressure; and imposed new emergency response and incident notification requirements. In 2016, the Pipeline Safety Act was reauthorized and amended to add additional construction inspection requirements, clarify integrity management rules and update federally incorporated standards. 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 of confidential commercial information, changes to the drug and alcohol testing requirements and incorporating consensus standards by reference for in-line inspection and stress corrosion cracking direct assessment. On October 1, 2019, PHMSA published a final rule “Safety of Hazardous Liquids Pipelines,” which will take effect July 1, 2020.  The rule requires inspection of all pipelines in areas affected by extreme weather and natural disasters, implements integrity assessment criteria, and extends the requirements for the rule of detection systems. The states in which we operate pipelines incorporate into their state rules those federal 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 new pipeline safety regulations, including additional requirements for integrity management, is likely to increase the operating costs of our pipelines subject to such new requirements, and such future costs may be material.

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

Environmental, Health and Safety Risks

General.  Our midstream crude oil gathering, transportation and terminalling operations, as well as our asphalt assets, are subject to stringent federal, state and local laws and regulations relating to the discharge of materials into the environment or otherwise relating to protection of the environment, 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 to revocation, modification and renewal. These laws and regulations may also require notice to stakeholders of proposed and ongoing operations; require the installation of expensive pollution control equipment; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with transporting through pipelines; or establish specific safety and health criteria addressing worker protection. As with liquid asphalt and midstream industries generally, compliance with current and anticipated environmental laws and regulations increases our overall cost of business, including our capital costs to construct, maintain and upgrade equipment and facilities. Failure to comply with these laws and regulations may result in the assessment of significant administrative, civil and/or criminal penalties, the imposition of investigatory and remedial liabilities and issuance of injunctions that may restrict or prohibit some or all of our operations. We believe that our operations are in substantial compliance with applicable laws, regulations and permits. However, environmental laws and regulations are subject to change, along with varying degrees of interpretation and departmental policies, resulting in potentially more stringent requirements. The recent legislative and regulatory trend has been to place increasingly stringent restrictions and limitations on activities that may affect the environment. Federal, state or local administrative decisions, developments in the federal or state court systems or other governmental or judicial actions may influence the interpretation and/or enforcement of environmental laws and regulations and may thereby increase compliance costs. Although we are not currently aware of any material effects that compliance with current and future environmental laws and regulations will have on our results of operations, financial position or 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 both our liquid asphalt and midstream operations. A discharge of petroleum products or hazardous materials into the environment could, to the extent such event is not covered by insurance, subject us to substantial expense, including costs related to environmental cleanup or restoration, compliance with applicable laws and regulations and any personal injury, natural resource or property damage claims made by neighboring landowners and other third parties.

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

Water.  The federal Clean Water Act (“CWA”) and analogous state and local laws impose restrictions, strict controls and permitting requirements on the discharge 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, in 2015, 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 of the United States.”  However, in 2019 the EPA repealed this rule and in January 2020 announced a revised rule clarifying the “waters of the United States” definition. Litigation surrounding the repeal of 2015 rule and litigation over the new revised rule is anticipated once the rule is published in the Federal Register. The CWA and analogous laws provide significant penalties for unauthorized discharges and impose substantial potential liabilities for cleaning up releases into water. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. We believe that we are in substantial compliance with any such applicable state requirements.

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

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 that our operations are in substantial compliance with applicable laws in those areas in which we operate. Amendments to the CAA enacted in 1990 imposed a federal operating 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 and processing operations that took effect on October 15, 2012. To respond to challenges, the EPA revised certain aspects of the rules and has indicated it may reconsider other aspects. The EPA finalized a rule, which took effect August 2, 2016, to set standards for methane and volatile organic compound emissions from new 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. On September 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.  Separately, on August 28, 2019, the EPA proposed amendments to the 2012 and 2016 NSPS for the Oil and Natural Gas Industry which would remove all sources in the transmission and storage segment of the oil and natural gas industry from regulation under the NSPS, both for ozone-forming VOCs, and for “greenhouse gases” (“GHGs”).  The existing NSPS regulates GHGs through limitations on emissions of methane. The amendments also would rescind the methane requirements in the 2016 NSPS that apply to sources in the production and processing segments of the industry.  As an alternative, the EPA also is proposing to rescind the methane requirements that apply to all sources in the oil and natural gas industry, without removing any sources from the current source category.  The costs of compliance with any modified or newly issued rules cannot be predicted.  For example, the Bureau of Land Management (“BLM”) adopted rules that took effect on January 17, 2017, to reduce venting, flaring and leaks during oil and natural gas production activities on onshore federal and Indian leases. In December 2017, implementation of this rule was delayed until January 2019, and in September 2018 the BLM proposed a revised rule which scaled back the waste-prevention requirements of the 2016 rule. Environmental groups sued in federal district court a day later to challenge the legality of aspects of the revised rule, and the outcome of this litigation is currently uncertain. Compliance with these rules could result in additional compliance costs for us and for others in our industry. In response to these and other regulatory developments, we may be required to incur certain capital expenditures in the next several years for air pollution control equipment and operational changes in connection with obtaining or maintaining permits and approvals and complying with applicable regulations addressing air emission related issues. However, the status of recent and future rules and rulemaking initiatives under the new administration is uncertain. Although we can provide no assurance, we believe future compliance with the CAA, as currently amended, will not have a material adverse effect on our financial condition, results of operations or 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, regional and state levels. The oil and gas industry is a direct source of certain GHG emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. In the United States, the U.S. Congress, in the past, has considered but not enacted federal legislation requiring GHG controls. The EPA has adopted regulations under existing provisions of the CAA that require Prevention of Significant Deterioration (“PSD”) pre-construction permits, and Title V operating permits for GHG emissions from certain large stationary sources. Furthermore, in 2009, the EPA adopted rules requiring the monitoring and reporting of GHG emissions 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. These EPA rulemakings could affect 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 international community 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 determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. However, in November 2019 President Trump initiated the United States’ withdrawal from the Paris Agreement, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial 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 states in which we operate. Passage of climate change legislation or other federal or state legislative or regulatory initiatives that regulate or restrict GHG emissions in areas in which we conduct business could adversely affect the demand for our products and services, and depending on the particular program adopted could increase the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions (e.g., from natural gas fired combustion units), pay any taxes related to our GHG emissions and/or administer and manage a GHG emissions program.  At this time, it is not possible to accurately estimate how laws or regulations addressing GHG emissions would impact our business.  Although we do not expect we would be impacted to a greater degree than other similarly situated midstream transporters of petroleum products, the greenhouse gas control programs could have an adverse effect on our cost of doing business and could reduce demand for the products we transport.

In addition to potential impacts on our business directly or indirectly resulting from climate change legislation or regulations, our business also could be negatively 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 that provide 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 and services.  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, on certain classes of persons associated with the release of a “hazardous substance” into the environment. These persons include the owner or operator and certain former owners and operators of the site or sites where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Under CERCLA, such persons may be subject to strict 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 for personal injury and property damage allegedly caused by releases of hazardous substances or other pollutants. We generate materials in the course of our operations that fall within CERCLA’s hazardous substance definition. Beyond the federal statute, many states have enacted environmental response statutes that are 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 effect on our financial conditions, we could incur substantial expense in the future if the RCRA exemption for certain oil and gas “exploration and production” waste were eliminated.  Should any oil and gas exploration and production wastes become subject to RCRA, we would also become subject to more rigorous and costly disposal requirements, resulting in additional capital expenditures or operating expenses for us.

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

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

Regulation of Hydraulic Fracturing. A portion of our customers’ production is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the production process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into shale formations to stimulate crude oil and/or natural 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, hydraulic fracturing have been pursued at the local, state and federal levels of government, and may be pursued in the future. For example, several states, including states in which we operate, have imposed disclosure requirements on hydraulic fracturing, and several local governments have prohibited or severely restricted hydraulic fracturing within their jurisdictions. Restrictions on hydraulic fracturing could adversely affect our operations 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 their habitats. 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 in substantial compliance with the ESA. However, the designation of previously unlisted endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans or limit future development in the affected areas. The Migratory Bird Treaty Act (“MBTA”) implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds. Pursuant to the MBTA, the taking, killing or possessing of migratory birds is unlawful without a permit, thereby potentially requiring the implementation of operating restrictions or a temporary, seasonal, or permanent 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. In addition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements 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 of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process has the potential to delay or even halt the development of oil and natural gas projects.

Anti-Terrorism Measures.  The federal Department of Homeland Security Appropriations Act of 2007 (“Appropriations Act”) requires the Department of Homeland Security (“DHS”) to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 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, issued an Appendix A to CFATS that established chemicals of interest (“COI”) and their respective threshold quantities that trigger compliance with the interim rules. In December 2014, the Protecting and Securing Chemical Facilities from Terrorist Attacks Act of 2014 (“CFATS Act”) was enacted. The CFATS Act reauthorized the CFATS program for four years. The CFATS program utilizes a Chemical Security Assessment Tool (“CSAT”) to identify chemical facilities potentially deemed “high risk.” The first step of CSAT is user registration, followed by the completion of a top-screen evaluation. The top-screen evaluation analyzes whether a facility stores regulated chemicals above specified thresholds. If it does, the facility must complete a Security Vulnerability Assessment, which identifies a facility’s security vulnerabilities, and develop and implement a Site Security Plan, which must include measures that satisfy the identified risk-based performance standards. DHS must review and approve or deny all security vulnerability assessments and site security plans. CFATS also requires regulated facilities to keep detailed security records and allow DHS the right to enter, inspect, and audit the property, equipment, operations and records of such facilities. We believe we are in substantial compliance with the CFATS program at our facilities that handle, store, use or process COI above the applicable threshold.

Operational Hazards and Insurance

Terminals, pipelines and similar facilities may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance of various types and varying levels of coverage which we consider adequate under the circumstances to cover our operations and properties, including coverage for pollution-related events. However, such insurance does not cover every potential risk associated with operating terminals, pipelines and other facilities. While the overall cost of the insurance program has decreased over the last five years due to a variety of both internal and external factors, we expect to experience increased costs in the foreseeable future as insurers are increasing premiums to ameliorate recent losses. Through the utilization of deductibles and retentions, we self-insure the “working layer” of loss activity to create a more efficient and cost-effective program. The working layer consists of high-frequency/low-severity losses that are best retained and managed in-house. We continue to monitor our retentions as they relate to the overall cost and scope of our insurance program.

Employees

As of December 31, 2019, we had approximately 270 employees.  None of these employees are represented by labor unions or covered by any collective bargaining 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 19 to our consolidated financial statements included in this annual report on Form 10-K.

 Available Information

We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these reports filed with the SEC under the Securities and Exchange Act of 1934. These documents may be accessed free of charge on our website, www.bkep.com, as soon as is reasonably practicable after their filing with the SEC. Information contained on our website is not incorporated by reference in this report or any of our other filings.  The SEC also maintains a website which contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. The SEC’s website is www.sec.gov.

Item 1A.    Risk Factors.

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this report. If any of the following risks were actually to occur, our business, financial condition, results of operations and cash flows could 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 our unitholders could lose all or part of their investment.

Risks Related to our Business

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our General Partner, to enable us to make cash distributions to holders of our 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 on our common units at the current quarterly distribution of $0.04 per unit per quarter, or $0.16 per unit per year, we will require available cash of approximately $8.1 million per quarter, or $32.4 million per year. We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions 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 on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things, the risks described herein.

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

Our cash available for distributions to our unitholders could be negatively impacted if we are unable to extend existing storage contracts or enter into new storage 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 3.3 million barrels of storage at this location are month-to-month or expire in 2020. We may not be able to extend, renegotiate or replace these contracts when they expire and the terms of any renegotiated contracts may not be as favorable as the contracts they replace.  In addition, to the degree that we operate outside of long-term contracts, our revenues can be significantly more volatile than would be the case with a pricing structure negotiated through a long-term storage contract. If we cannot successfully renew significant contracts or must renew them on less favorable terms, our revenues from these arrangements could decline, which could have a material adverse effect on 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 or nonperformance 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 at least 30% but not more than 35% of our total asphalt terminalling services revenue in 2019. Vitol represented at least 50% but not more than 55% of our total crude oil terminalling revenue, and at least 95% but less than 100% of our crude oil pipeline services revenue in 2019. Vitol and Ergon are private companies and we have limited information regarding their financial condition.  Vitol and Ergon comprised 81% and 4%, respectively, of total accounts receivable at December 31, 2019.   

In addition to Vitol and Ergon, we have other key customers. Associated Asphalt, Inc. and Delek US Holdings, Inc. accounted for at least 10% but not more than 20% of total asphalt terminalling services revenue in 2019. Citigroup Energy, Inc. and Sunoco Logistics Partners LP accounted for at least 10% but no more than 20% of total crude oil terminalling revenue in 2019. MV Purchasing, LLC accounted for at least 40% but not more than 45% and Devon Gas Services, LP accounted for at least 15% but not more than 20% of crude oil trucking services revenue in 2019. There were no other customers with accounts receivables balances of at least 10% at December 31, 2019.

We may be unable to negotiate extensions or replacements of contracts with key customers on favorable terms. In addition, some of these key customers may experience financial problems which could have a significant effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us or to enforce performance of obligations under contractual arrangements. Additionally, many of our customers finance their activities through cash flows from operations, the incurrence of debt or the issuance of equity. The reduction of cash flows resulting from declines in commodity prices, a reduction in borrowing bases under credit facilities, the lack of availability of debt or equity financing or any combination of such factors may result in a significant reduction of our customers’ liquidity and limit their ability to make payments or perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us.  The loss of all or even a portion of the contracted volumes of these key customers, as a result of competition, creditworthiness or otherwise, could have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, unit price, results of operations and ability to conduct our business.

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

We are subject to risks of loss resulting from nonpayment or nonperformance by our third-party customers. Some of our customers may be highly leveraged and subject to their own operating and regulatory risks, including risks relating to commodity price deterioration or other conditions in the energy industry. In addition, any material nonpayment or nonperformance by our customers could require us to pursue substitute customers for our affected assets or to provide alternative services. Any such efforts may not be successful, may be expensive to undertake and may not provide similar fees. These events could have a material adverse effect on our financial condition, results of operations and cash flows.

The amount of cash we have available for distribution to holders of our units depends primarily on our cash flows and not solely on earnings reflected in our financial statements. Consequently, even if we are profitable and are otherwise able to pay distributions, we may not be able to make cash distributions to holders of our 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 earnings reflected in our financial statements, which will be affected by non-cash items. As a result, we may make cash distributions, if permitted by our credit agreement, during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

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

As of December 31, 2019, we had approximately $256.6 million in outstanding indebtedness, including approximately $1.0 million in outstanding letters of credit, 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 service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors. Our ability to service debt under our credit agreement also will depend on market interest rates, 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 to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms, or at all.

Restrictions in our credit agreement could materially adversely affect our business, financial condition, results of operations, ability to make cash distributions to 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 our unitholders. The operating and financial restrictions and covenants in our credit agreement and any future financing agreements could restrict our ability to finance future 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:

Our credit agreement also contains covenants requiring us to maintain certain financial ratios and meet certain financial tests. Our ability to meet those financial ratios and financial tests can be affected by events beyond our control, and we cannot guarantee that we will meet those ratios and tests.

The provisions of our credit agreement may affect our ability to obtain future financing and pursue attractive business opportunities as well as affect our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our credit agreement could result in 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 be immediately due and payable. If we were unable to repay the accelerated amounts, the lenders under our credit agreement could proceed against the collateral granted 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 could experience 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, and the 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 23, 2020, we have aggregate unused credit availability under our credit agreement of approximately $125.4 million, although our ability to borrow such funds may be limited by the financial covenants in our credit agreement, and cash on hand of approximately $3.0 million. Our ability to access the public capital markets on terms acceptable to us or at all may be limited due to, among other things, commodity price volatility and deterioration, general economic conditions, rising interest rates, capital market volatility, the uncertainty of our future cash flows, adverse business developments and other contingencies.  In addition, 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 these uncertainties.  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 could have 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 or expansion 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 a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, unit price, results of operations and ability to conduct our business.

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

Available cash for the purpose of making distributions to unitholders includes working capital borrowings. If we borrow funds to pay one or more quarterly distributions, such amounts will incur interest and must be repaid in accordance with the terms of our credit agreement. In addition, any amounts borrowed for permitted distributions to our unitholders will reduce the funds available to us for other purposes under our credit agreement, including amounts available for use in connection with acquisitions and other business opportunities.  If we are unable to pursue our growth strategy due to our limited ability to borrow funds, our operations may be materially and adversely affected.

We 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, 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 exposed to price risk with respect to the differing qualities of crude oil we transport and our ability to effectively blend them to market specifications. In addition, the volumes of liquid asphalt and crude oil we terminal, gather or transport are affected by commodity prices because many of our customers have direct commodity price exposure.  Many of our customers have been, and continue to be, adversely affected by significant changes in commodity prices. If our customers continue to be negatively 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 this volatility to continue.  In March of 2020, WTI crude oil pricing dropped below $30 a barrel.  This is primarily due to a projected weakened world demand for crude oil in the industrial and manufacturing segments as a result of the coronavirus strain known as COVID-19.  There is also a projected increase in crude oil supply due to a potential increase in production from Saudi Arabia and Russia, the second and third largest producers of crude oil in the world after the United States of America. The Organization of the Petroleum Exporting Countries (“OPEC”) has been unable to come to an agreement to maintain or reduce production in response to this weakened demand. There can be no assurance that commodity prices will not be subject to continued wide fluctuations in the future. Any significant reduction in the amount of services 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 or suspend performance in some circumstances, which could cause our revenues from those contracts to decline and reduce our ability to make distributions to our unitholders.

Some of our contract-based revenues from customers are generated under contracts with terms which allow the customer to reduce or suspend performance under the contract in specified circumstances, such as the occurrence of a catastrophic event to our or the customer’s operations. The occurrence of an event which results in a material reduction or suspension of our customer’s performance could have a material adverse effect on our financial condition, results of operations and 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. We may 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 the contracts they replace. In particular, our ability to extend or replace contracts could be harmed by numerous competitive factors, such as those described above under “Item 1. Business - Competition.”  We face intense competition in our terminalling, gathering, pipeline transportation and trucking activities. Competition from other providers of crude oil gathering, pipeline transportation, terminalling and trucking services that are able to supply our customers with those services at a lower price could reduce our ability to make distributions to our unitholders. Additionally, we may incur substantial costs if modifications to our terminals are required in order to attract substitute customers or provide alternative services. If we cannot successfully renew significant contracts or must renew them on less favorable terms, or if we incur substantial costs in modifying our terminals, our revenues from these arrangements could decline, which could have a material adverse 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 short notice.

As of March 23, 2020, we had leases or storage agreements with third-party customers relating to each of our 53 asphalt facilities. One of these facilities has a term that expires by the end of 2020. We may not be able to renew or extend our existing contracts or enter into new leases or storage agreements when such contracts expire on terms acceptable to us or at all. In addition, certain key customers account for a significant portion of our asphalt terminalling services revenues, the loss of which could result in a significant decrease in revenues from our asphalt operations. A significant decrease in the revenues we receive from our asphalt operations could result in violations of covenants under our credit agreement and could have a material adverse effect on our 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 as short 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 such lease 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 ability to 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 leases and 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, it could 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, premiums and deductibles for certain of our insurance policies may increase substantially in the future. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, 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 make distributions 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 significantly reduce our revenues and, therefore, reduce our ability to make or increase distributions to our unitholders. Factors that could lead to a decrease in market demand for liquid asphalt and crude oil products include:

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 expenses may 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 experience declines 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 producing refineries. Liquid asphalt production may decline for a number of reasons, including refiners processing more light, sweet crude oil or refiners installing coker units 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 or permanent material decrease in production from the suppliers of liquid asphalt, our throughput could decline, reducing our revenue and cash flows and adversely affecting 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 our unitholders.

The throughput on our crude oil pipelines depends on the availability and demand for transportation and storage of crude oil produced from the oil fields served by such pipelines or through connections with pipelines owned by third parties. Crude oil production may decline for a number of reasons, including natural declines due to depleting wells, a material decrease in the price of crude oil or the inability of producers to obtain necessary drilling or other permits from applicable governmental authorities. If commodity prices remain depressed for any sustained period of time, production may slow and our customers may decrease the 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 oil fields served by our crude oil pipelines, our throughput could decline, reducing our revenue and cash flows and adversely affecting our financial condition and results 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 a result, third-party shippers on our pipeline systems may experience difficulty acquiring crude oil at the wellhead in areas where there are existing relationships between producers and other gatherers and purchasers of crude oil.

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

We are subject to competition from other crude oil terminalling, gathering, and transportation operations that may be able to supply our customers with the same or comparable services on a more competitive basis. We compete with national, regional and local gathering, terminalling and pipeline companies, including the major integrated oil companies, of widely varying sizes, financial resources and experience. Some of these competitors are substantially larger than us, have greater financial resources, and control substantially greater storage capacity than we do. Our ability to compete could be harmed by numerous factors, including:

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 of operations 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 these interconnecting pipelines as a result of testing, line repair, reduced operating pressures or other causes could result in reduced throughput on our pipeline systems 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 from operations.  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 pursue future 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 when they are available; (ii) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them; (iii) unable to obtain financing for these acquisitions on economically acceptable terms; or (iv) outbid by competitors, then our future growth and ability to 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 from operations per unit.

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

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

If we acquire assets that are distinct and separate from our existing terminalling, gathering and transportation operations, it could subject us to additional business 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 business is a complex, costly and time-consuming process. Failure to timely and successfully integrate acquired entities’ lines of business with our existing operations may have a material adverse effect on our business, financial condition, results of operations and cash flows. The difficulties of integrating a new business with our existing operations include, among other things:

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

Expanding our business by constructing new assets subjects us to risks that projects may not be completed on schedule and that the costs associated with projects 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 be completed 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 in which 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 phases of these projects; however, the operating cash flows we expect these projects to generate will not materialize, if at all, until sometime after the projects are completed and placed into service. As a result, to the extent we finance our projects with borrowings, our leverage may increase during the period prior to the generation of those operating cash flows and, to the extent we finance our projects with equity, our cash available for distribution on a common unit basis may decrease during the period prior to the generation of those operating cash flows. If we experience unanticipated or extended delays in generating operating cash flows 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 order to 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 integrity management program requirements and any necessary pipeline repair or preventative or remedial measures, which could have a material adverse effect on our results of operations.

Our pipeline operations are subject to pipeline safety laws and regulations administered by PHMSA of the 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 pipelines can operate.

Also included in the comprehensive regulatory scheme are regulations requiring pipeline operators to develop integrity management programs for pipelines that could affect “high consequence areas” including populated areas, areas that are unusually sensitive to environmental damage and commercially navigable waterways. The regulations require operators of covered pipelines to: 

Effective July 2008, the DOT broadened the scope of coverage of its existing pipeline safety standards, including its integrity management programs, to include certain rural onshore hazardous liquid and low-stress pipeline systems found near “unusually sensitive areas,” including non-populated areas requiring extra protection because of the presence of sole source drinking water resources, endangered species or other ecological resources. Also, in December 2006, the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (“PIPES”) was enacted. PIPES reauthorized and amended the DOT’s pipeline safety programs and included a provision eliminating the regulatory exemption for low-stress hazardous liquid pipelines. The Pipeline Safety Act established additional safety requirements for newly constructed pipelines and required the DOT to study safety issues that could result in the adoption of additional regulatory requirements for existing pipelines. On August 13, 2012, PHMSA published rules to update pipeline safety regulations, including increasing maximum civil penalties 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 changing PHMSA’s enforcement process. This maximum penalty authority established by statute has been and will continue to be adjusted periodically to account for inflation. PHMSA also issued an Advisory Bulletin in May 2012 which advised pipeline operators that they must have records to document the maximum operating pressure for each section of their pipeline and that the records must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing (including hydrostatic testing) or modifying or replacing facilities to meet the demands of verifiable pressures, 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 of confidential commercial information, changes to the drug and alcohol testing requirements and incorporating consensus standards by reference for in-line inspection and Stress Corrosion Cracking Direct Assessment. Please read “Item 1. Business-Pipeline Regulation-Pipeline Safety” for more information.

Our operations are subject to environmental and worker safety laws and regulations that may expose us to significant costs and liabilities. Failure to comply with 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 governmental authorities, including the EPA, have the power to enforce compliance with these laws and regulations and the permits issued under them. Violators of environmental laws and regulations are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. We may experience delays in obtaining, or be unable to obtain, required environmental permits, which may delay or interrupt our operations and limit our growth and revenue. Joint and several strict liability may be incurred without regard to the legality of the original conduct under CERCLA, RCRA and analogous state laws for the remediation of contaminated areas. Private parties also may have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. Moreover, new laws, regulations or enforcement policies could be implemented that significantly 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 properties which for many years have been used for asphalt activities and midstream activities, including properties in and around the Cushing Interchange. Activities by us or 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 or under the properties for which we may incur liability. Additionally, some sites we own or operate are located near current or former terminal and pipeline operations, and there is a risk that contamination has migrated from those sites to ours. Increasingly strict environmental laws, regulations and enforcement policies, as well as claims for damages and other similar developments, could result in significant costs and liabilities, and our ability to make distributions to our unitholders could suffer as a result. Please see “Item 1-Business-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 state statutes that regulate the protection of the health and safety of workers. The OSHA hazard communication standard requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees, state and local government authorities and local residents. Failure to comply with OSHA requirements, including general industry standards, recordkeeping requirements and monitoring of occupational exposure to regulated substances, could subject us to fines or significant compliance costs and have a material adverse effect on our financial condition, results of operations and 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 change could 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 restrictions on such emissions could impact our future operations. Federal legislation requiring GHG controls has been considered in the past but has not been enacted.  The EPA has adopted regulations under existing provisions of the CAA which require PSD pre-construction permits and Title V operating permits for GHG emissions from certain large stationary sources. These EPA rulemakings could affect our operations by effectively reducing demand for motor fuels from crude oil and could affect our ability to obtain air permits for new or modified facilities. Furthermore, in 2009, the EPA adopted rules requiring the monitoring and reporting of GHG emissions 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 combustion units which may become subject to these rules. These facilities are required to annually calculate their GHG emissions to determine whether they trigger reporting and monitoring requirements. To date, none of our facilities have exceeded the thresholds established for reporting or monitoring requirements. Although these rules 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 also note, as previously mentioned, that the EPA finalized rules that took effect in August 2016 to set standards for methane and volatile organic compound emissions from new and modified sources in the oil and gas sector, including transmission. However, the EPA is currently engaged in rulemaking to reduce the 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 in which we operate.

Passage of climate change legislation or other federal or state legislative or regulatory initiatives that regulate or restrict GHG emissions in areas in which we conduct business or that have the effect of requiring or encouraging reduced consumption or production of crude oil and petroleum-based products could potentially:

Additionally, there are increasing potential financial risks for oil and gas companies as environmental activists concerned about the potential effects of climate change are focusing intensive lobbying efforts on institutional lenders, including financial institutions and institutional investors, not to provide funding to such companies. Institutional lenders may, of their own accord, elect not to provide funding to oil and gas companies based on climate change concerns. Limitation of investments in oil and gas companies could result in the restriction, delay, or cancellation of drilling programs or development or production activities of our customers, and, consequently, reduce their demand for our services.

In addition to potential impacts on our business directly or indirectly resulting from climate change legislation or regulations, our business also could be negatively 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 severe weather 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 as a 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, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits brought by public and private entities against oil and gas companies in connection with their greenhouse gas emissions. Should we be targeted by any such litigation, we may incur liability which, 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 the asserted damage, or to other mitigating factors.

A portion of our customers’ production is developed from unconventional sources, such as shale, which require hydraulic fracturing as part of the production process. 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, hydraulic fracturing have been pursued at the local, state and federal levels of government and may be pursued in the future. For example, several states, including states in which we operate, have imposed disclosure requirements on hydraulic fracturing, and several local governments have prohibited or severely restricted hydraulic fracturing within their jurisdictions. Restrictions on hydraulic fracturing could adversely affect our operations by reducing the volumes of crude oil that we transport.

Please also see “Item 1. Business-Environmental, Health and Safety Risks-Climate.”

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

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

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

We could be negatively impacted by the recent outbreak of coronavirus (COVID-19).

In light of the uncertain and rapidly evolving situation relating to the spread of the coronavirus (COVID-19), this public health concern could pose a risk to our employees, our customers, our vendors and the communities in which we operate, which could negatively impact our business. The extent to which the coronavirus (COVID-19) may impact our business will depend on future developments, which are highly uncertain and cannot be predicted at this time. We continue to monitor the situation, have actively implemented policies and practices to address the situation, and may adjust our current policies and practices as more information and guidance become available.

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 possibility of 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. We obtain 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 a specific period of time. Our loss of these rights through our inability to renew leases, right-of-way contracts or otherwise could have a material adverse effect on our business, results of operations, financial condition, cash flows and ability to make cash distributions to our unitholders.  In addition, we are in the process of obtaining consents from the lessors for certain leased property that was transferred to us as part of the acquisition of our asphalt assets.  If any consent is denied, it could have a material adverse effect on our business, results of operations, financial condition, cash flows and our ability to make cash distributions to our unitholders.

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 or severity of accidents or workers’ compensation claims or the unfavorable development of existing claims could materially adversely affect our results of operations. 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 insurance obligations 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 permit requirements of state highway, and safety authorities. These regulatory authorities exercise broad powers over our trucking operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing and specifications and insurance requirements. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may impact our operations and affect the economics of the industry by requiring changes in operating practices or by changing the demand for or the costs of providing truckload services. Some of these possible changes include increasingly stringent fuel emission limits, 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 other matters, 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 our business, financial condition or results of operations.

Terrorist attacks and threats, cyber-attacks, escalation of military activity or acts of war may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business.  Terrorist or cyber-attacks, rumors or threats of war, actual conflicts involving the United States or its allies or military or trade disruptions may significantly affect our operations and those 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 not maintain specialized insurance for possible exposures resulting from a cyber-attack on our assets that may shut down all or part of our business.  Disruption or significant 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 and business partners and for many other activities related to our business. Our business processes depend on the availability, capacity, reliability and security of our information technology infrastructure and our ability to expand and continually update this infrastructure in response to our changing needs and, therefore, it is critical 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 technology function 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 from unexpected interruptions cannot be fully tested, and there is a risk that, if such an event occurs, we may not be able to address immediately the repercussions 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 to conduct business or perform some business processes in a timely manner. Moreover, if any of these events were to materialize, they could lead to losses of sensitive 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 to introduce viruses or other malware through “trojan horse” programs to our computers. These emails appear to be legitimate emails but direct recipients to fake websites 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.

If 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 and reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We continue to enhance our internal controls and financial reporting capabilities. These enhancements require a significant commitment of resources, personnel and the development and maintenance of formalized internal reporting procedures to ensure the reliability of our financial reporting. Our efforts to update and maintain our internal controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting now or in the future, including future compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective controls or difficulties encountered in the effective improvement of our internal controls could prevent us from timely and reliably reporting our financial results and may harm our operating results. Ineffective internal controls could also cause investors to lose confidence in our reported financial information. In addition, the Financial Accounting Standards Board or the SEC could enact new accounting standards that might affect how we are required to record revenues, expenses, assets and liabilities. Any significant change in accounting standards or disclosure requirements could have a material effect on our business, results of operations, financial condition and ability to comply with our debt obligations. 

Risks Inherent in an Investment in Us

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

Ergon owns and controls our General Partner.  Some of our General Partner’s directors are directors and officers of Ergon.  Therefore, conflicts of interest may arise between our General Partner, on the one hand, and us and our unitholders, on the other hand.  In resolving those conflicts of interest, our General Partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. Although the conflicts committee of the board of directors of our General Partner (the “Board”) may review such conflicts of interest, the Board is not required to submit such matters to the conflicts committee. These conflicts include, among others, the following situations:

Our partnership agreement limits the fiduciary duties our General Partner owes to holders of our units and restricts the remedies available to holders of our units for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.

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

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

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 or indirectly 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 or construct any of those assets.  Ergon is a privately held company engaged in a wide range of operations. Ergon has significantly greater resources and experience than 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 a result, 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 and will 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 for the provision of various general and administrative services for our benefit. Payments for these services may be substantial and reduce the amount of cash available for distribution to unitholders. In addition, under Delaware partnership law, our General Partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our General Partner. To the extent our General Partner incurs obligations on our behalf, we are obligated under our partnership agreement to reimburse or indemnify our General Partner. If we are unable or unwilling to reimburse or indemnify our General Partner, our General Partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments would reduce the amount of cash otherwise available for distribution to our unitholders.

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, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our General Partner or the Board and have no right to elect our General Partner or the Board on an annual or other continuing basis. The Board is chosen by Ergon. Furthermore, if the unitholders are dissatisfied with the performance of our General Partner, they have little ability to remove our General Partner. Amendments to our partnership agreement may be proposed only by or with the consent of our General Partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Control of our General Partner may be transferred to a third party without unitholder consent.

Our General Partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Ergon, the owner of our General Partner, from transferring all or a portion of its 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 of our 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 of additional 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 not be subject to the shareholder approval requirements relating to the issuance of securities (other than in connection with the establishment or material amendment of a stock option or purchase plan or the making or material amendment of any other equity compensation arrangement) contained in Nasdaq Marketplace Rule 5635.  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 partnership agreement restricts the voting rights of unitholders, other than our General Partner and its affiliates, including Ergon, owning 20% or more of 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 any class of units then outstanding, other than our General Partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the Board, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions.

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 substantial number 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 23, 2020, Ergon owned approximately 27.7% 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 23, 2020, the executive officers and directors of our General Partner beneficially own an aggregate of 841,393 common units and Ergon owns 2,795,837 common units and 18,312,968 Preferred Units. The sale of these units in the public markets could have an adverse impact 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 not the 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 price not less than the then-current market price. As a result, our unitholders may be required to sell their units at an undesirable time or price and may not receive any return on their investment. Our unitholders also may incur a tax liability upon a sale of their units. As of March 23, 2020, 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 Preferred Units 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 any distribution on our Preferred Units, the amount of such unpaid distribution will accrue and accumulate from the last day of the quarter for which such distribution is 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 Preferred Units 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 combinations of 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 and dilute 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 in other 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 right at 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 a situation 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 all remaining outstanding Preferred Units to convert to common units. Ergon, the owner of our General Partner, owns enough Preferred Units such that if they were all 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 the outstanding 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 trailing 30 trading days ending two trading days before we furnish notice of conversion and (ii) the average trading volume of our common units has exceeded 20,000 common 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 may be modified with the consent of a majority of the outstanding Preferred Units. As of March 23, 2020, Ergon owned 52.1% of our outstanding Preferred Units and has 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 an undesirable time and may not receive their expected return on investment.

Ergon, as the holder of a majority of the outstanding Preferred Units, has the ability to consent to the amendments to the provisions of the Preferred Units.

The Preferred Units have voting rights that are identical to the voting rights of common units and vote with the common units as a single class, so that each 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 common unit 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 affects any 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 Units disproportionately in relation to the holders of common units, including, without limitation, any action that would (i) reduce the distribution amount to the Preferred Units or change the time or form of payment of distributions, (ii) reduce the amount payable to the Preferred Units upon the liquidation of our partnership, (iii) modify the conditions relating to the conversion of the Preferred Units or (iv) issue any equity security that, with respect to distributions or rights upon liquidation, ranks equal to or senior to the Preferred Units or issue any additional Preferred Units. As of March 23, 2020, Ergon owned 52.1% of our outstanding Preferred Units and has the ability to consent to amendments to the terms of the Preferred Units without the consent of other unitholders.

Holders of the Preferred Units will not have rights to distributions as holders of common units until they acquire our common units.

Until our preferred unitholders acquire common units upon conversion of the Preferred Units, such preferred unitholders will have no rights with respect to distributions 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 to matters 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 all indebtedness and other non-equity claims on our partnership with respect to assets available to satisfy claims on our partnership, including in a liquidation of our partnership. 

 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 require transferees 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 these certification 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 purposes under 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 the entity’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 who are not Eligible Holders at the lesser of the holder’s purchase price and the then-current market price of the units. The redemption price would be paid in cash or by delivery of a promissory note, as determined by our General Partner.

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 market interest 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 from time to time, including:

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

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

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

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

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

Tax Risks to Unitholders

Our common unitholders have been and will be required to pay taxes on their share of our taxable income even if they have not received or do not receive any cash 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, our common 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 if our common unitholders receive no cash distributions from us.  Our common unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from 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-level taxation by individual states. If the IRS were to treat us as a corporation, or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on us being treated as a partnership for federal income tax purposes.  If less than 90% of the gross income of a publicly traded partnership, such as us, for any taxable year is “qualifying income” from sources such as the transportation, marketing (other than to end users) or processing of crude oil, natural gas or products thereof, interest, dividends or similar sources, that partnership will be taxable as a corporation under Section 7704 of the Internal Revenue Code for federal income tax purposes for that taxable year and all subsequent years.  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 to unitholders as corporate distributions and none of our income, gains, losses, deductions or credits would flow through to our unitholders.  Because a tax would be imposed upon us as a corporation, cash available for distribution to our unitholders would be substantially reduced.  Therefore, treatment of us as a corporation would 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 the value 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 to assess and collect taxes (including any applicable penalties and interest) resulting from partnership-level federal income tax audits 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 audit adjustments, our cash available for distribution 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 the imposition 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, as adjusted 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 us by 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 a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us. No such adjustments have been made to date, but there can be no assurance that no 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 administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us or an investment in our common units, may be modified by administrative, legislative or judicial interpretation at any time.  Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively.  Moreover, any such modification could make it more difficult or impossible for us to meet the exception which allows publicly traded partnerships that generate qualifying income to be treated as partnerships (rather than corporations) for U.S. federal income tax purposes, affect or cause us to change our business activities or affect the tax consequences of an investment in our common units.  For example, members of Congress have considered substantive changes to existing federal income tax laws that would affect the tax treatment of certain publicly traded partnerships.  We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our 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 such contest will reduce our cash available for distribution to our unitholders.

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

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), any losses 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 activities or investments. Unused losses may be deducted when the unitholder disposes of the unitholder’s entire investment in us in a fully taxable transaction with an unrelated 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 other passive 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 gain attributable 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 carried forward into the following taxable year. This limitation shall be applied after the passive loss limitations and, unless amended, applies only to taxable years beginning 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 to our 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 year and (ii) 30% of our adjusted taxable income for such taxable year. For taxable years beginning before January 1, 2022, adjusted taxable income means earnings before interest, taxes, depreciation, and amortization; for taxable years beginning on or after January 1, 2022, adjusted taxable income is limited to earnings before interest and taxes. Disallowed interest (and perhaps regular payments) deductions will be allocated to our unitholders and will be available to offset our future excess taxable income allocated to such unitholders. A unitholder’s tax basis in our interests will be reduced by the amount of disallowed interest (and perhaps regular payments) deductions allocated to such unitholder, even if such amounts do not give rise to a deduction to the unitholder in that taxable year. Such unitholder’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 an amount equal to the difference between the prior basis reduction and the amount of the disallowed interest (and perhaps regular payments) that has subsequently been 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 interest deductions will be carried forward by our corporate subsidiaries and treated as business interest paid or accrued in the succeeding taxable year. The deductibility of such business interest expense carried forward from a prior taxable year will be subject to the limitation described above.

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

If our unitholders sell their units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those units. Because distributions to a unitholder that exceed the total net taxable income allocated to the unitholder decrease the unitholder’s tax basis in his or her units, any such 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 tax basis, even if the price the unitholder receives is less than the original cost.  Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income to the selling unitholder due to potential recapture items, including depreciation recapture.  In addition, because the amount realized 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 cash received 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 applicable penalties 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 penalties and 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 audit adjustments, our cash available for distribution to our unitholders might be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited taxable 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 issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If a potential unitholder is a tax-exempt entity or a 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 not withheld. However, the U.S. Department of the Treasury and the IRS have determined that this withholding requirement should not apply to any disposition of a publicly traded interest in a publicly traded partnership (such as us) until regulations or other guidance have been issued clarifying the application of this withholding requirement to dispositions of interests in publicly traded partnerships. Accordingly, while this new withholding requirement does not currently apply to interests in us, there can be no assurance that such requirement will not apply in the future.

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

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

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 of investing 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 taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property. Our unitholders may be required 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 be subject to penalties for failure to comply with those requirements. We currently own property and conduct business in several states, most of which currently impose income taxes on corporations, and many of which impose income taxes on other entities and nonresident individuals. We may own property or conduct business in other states or foreign countries in the future. It is each unitholder’s responsibility to file all federal, state, local and foreign tax returns. Under the 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 a resident of that state. For example, in the case of Oklahoma, we are required to report annual tax information about our non-Oklahoma resident unitholders with income 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 Oklahoma share of our income.

We hold certain assets located at certain of our liquid asphalt facilities in a subsidiary taxed as a corporation.  Such subsidiary is subject to entity-level federal and state income taxes on its net taxable income and, if a material amount of entity-level taxes were incurred, then our cash available for distribution to our unitholders could be substantially reduced.

We hold certain of our liquid asphalt processing assets and related fee income through BKEP Asphalt, L.L.C., a subsidiary taxed as a corporation. Such subsidiary 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 (and possibly local) income tax at varying rates. Distributions from such subsidiary will generally be taxed again to unitholders as corporate distributions and none of the income, gains, losses, deductions or credits of such subsidiary will flow through to our unitholders. Currently, the maximum federal income tax rate applicable to 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 of dividend and interest income from such subsidiary would constitute portfolio income which could not be offset by the unitholder’s share of our other losses or deductions. If a material amount of entity-level taxes is incurred by such subsidiary, then our cash available for distribution to our unitholders could be substantially 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 of our 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 this treatment, 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 of our 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 be permitted under existing Treasury regulations. The U.S. Department of the Treasury and the IRS issued final Treasury regulations pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must 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 IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. 

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 unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to effect a short sale of units may be considered as having disposed of the loaned units, such unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder, and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. 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 advisor to 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 materially increase 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 capital accounts of all of our partners to reflect any positive difference (“Unrealized Gain”) or negative difference (“Unrealized Loss”) between the fair market value and the 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 amount equal 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 converting preferred 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 capital account for each existing common unit.  This allocation of Unrealized Gain or Unrealized Loss will not be taxable to the converting preferred unitholder or to any other unitholders.  If the Unrealized Gain or Unrealized Loss allocated as a result of the conversion of a Preferred Unit is not sufficient to cause the capital account of each common unit received upon such conversion to equal the per unit capital account for each existing common unit, then capital account balances will be reallocated among the unitholders as needed to produce this result.  In the event 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 such reallocation 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 or deduction between our General Partner and our common unitholders.  The IRS may challenge this treatment, which could adversely affect the value of our outstanding 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 gain or loss attributable to our assets to the capital accounts of our common unitholders and our General Partner.  Our methodology may be viewed as understating the value of our assets.  In that case, there may be a shift of income, gain, loss or deduction between certain common unitholders and our General Partner, which may be unfavorable to such unitholders.  Moreover, under our valuation methods, subsequent purchasers of units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets.  The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss or deduction 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 common unitholders.  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 result in 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 in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes 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 our asphalt 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 to use 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. A small portion of our pipelines is constructed on rights-of-way that are owned by Native American tribes and/or allottees and administered by the U.S. Department of the Interior, Bureau of Indian Affairs, and which must be renewed periodically.  There is no guarantee that we will be able to renew such easements, or that such renewals will be on terms favorable to us. 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 the right 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 crude oil terminal is on real property owned 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 to encumbrances in certain cases, such as customary interests generally retained in connection with acquisition of real property, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens and minor easements, restrictions and other encumbrances to which the underlying properties were subject at the time of acquisition by our predecessor or us, we believe that none of these burdens will materially interfere with their use in the operation of our business.

Item 3.    Legal Proceedings.

The information required by this item is included under the caption “Commitments and Contingencies” in Note 15 to our consolidated financial statements and is incorporated herein by reference thereto.

Item 4.    Mine Safety Disclosures.

Not applicable.

PART II. OTHER INFORMATION

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 under the symbol “BKEPP”.

On March 23, 2020, there were 41,034,763 common units outstanding, held by approximately 724 unitholders of record and 35,125,202 Preferred Units outstanding held by approximately 2 unitholders of record.  The actual number of unitholders is greater than the number of holders of record.  Ergon holds 6.8% of the 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 partnership agreement) to unitholders of record on the applicable record date.

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

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 credit agreement 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:

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 additional classes 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 incentive distribution 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 partner interest 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 be proportionately reduced if we issue additional units in the future (other than the issuance of partnership securities issued in connection with a reset of the incentive distribution target levels relating to our General Partner’s incentive distribution rights or the issuance of partnership securities upon conversion of outstanding partnership securities) and our General Partner does not contribute a proportionate amount of capital to us in order to maintain its then current general partner interest. 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 from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our General Partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.

If for any quarter:

then our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the unitholders and our General Partner in the following manner:

For equity compensation plan information, see “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters-Securities Authorized for Issuance under Equity Compensation Plans.”

Unregistered Sales of Securities

None.

Item 6.    Selected Financial Data.

We are a “smaller reporting company” as defined by Regulation S-K and as such, we are not required to provide the information required by Item 6.

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 for companies 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 Revenues

The crude oil market price and the corresponding forward market pricing curve may fluctuate significantly from period to period. In addition, volatility in the overall energy industry and specifically in publicly traded midstream energy partnerships may impact our partnership in the near term. Factors include the overall market 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 placed on 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 a premium is placed on delivering product to market and selling as soon as possible), changes in crude oil production volume and the demand for storage and transportation capacity in the areas in which we serve, geopolitical concerns and overall changes in our cost of capital. As of March 23, 2020, the forward price curve is in contango.  Potential impacts of these factors are discussed below.

Due to the global pandemic related to the coronavirus disease, COVID-19, and OPEC’s disagreements over production output, the energy market has seen historic drops in oil prices in March of 2020. Despite this volatility in prices, our business and cash flow are uniquely positioned and expected to be stable in 2020. Our asphalt and crude oil terminalling services segments represented 95% of our operating margin in 2019, and as of March 23, 2020, these segments are fully contracted with take-or-pay revenue that have a weighted average remaining term of 4.6 years. While our customers across all our segments could be impacted by the recent market volatility, they are primarily high-quality counterparties, with approximately 50% of our revenues earned from those that are investment grade, which minimizes our counterparty credit risk. Additionally, we have minimal direct commodity exposure, dependence on U.S. upstream drilling activity and single exploration and production counterparty risk. While we are unaware of any potential negative impact of COVID-19 on our business at this time, we are continuing to monitor the situation and have been preparing our employees to take precautions and planning for unexpected events, which may include disruptions to our customers, vendors, facilities and communities in which we operate. As of now, we do not expect any supply chain disruptions to our customers as a result of this disease, as the U.S. government has continued to indicate its support for infrastructure spending, which 80% of our operating margin supports through asphalt terminalling services.

Asphalt Terminalling Services - Historically, there have only been limited times in which asphalt prices and volumes have had a direct correlation with the price of crude oil. As a result, we do not expect that changes in the price of crude oil will necessarily have a significant impact on our asphalt terminalling services operating segment. Generally, asphalt volumes correlate more closely with the strength of state and local economies, the level of allocations of tax funding to transportation spending and an increase in infrastructure spending needs.

In 2019, the level of customer throughput volumes through our terminals have varied across the country, primarily impacted by weather patterns, refinery disruptions and the customers’ own supply chain needs. The Midwest was impacted by higher levels of rain earlier in the year that slowed customer throughput; however, activity increased later in the season to help make up for this. In addition, during the first half of 2019, several of our asphalt facilities in the Midwest were damaged by flooding. While the facilities were able to successfully execute flood plans to minimize damages, costs related to the floods are expected to include approximately $0.7 million of expenses for cleanup and the removal and reinstallation of equipment and $2.1 million of capital expenditures to restore land improvements and equipment. As of December 31, 2019, $2.1 million of these amounts have been spent. Impairment expense related to the assets was $0.3 million. As of December 31, 2019, we have recognized $0.7 million of insurance recoveries. While we are pursuing additional insurance claims for these events, there can be no assurance of the amount or timing of any proceeds we may receive under such claims.

On July 12, 2018, we sold certain asphalt facilities, storage tanks and related real property, contracts, permits, assets and other 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 store crude oil during the current month and sell into a future month.  From March of 2016 through February of 2020, the crude oil curve had generally been in a shallow contango or backwardation. In shallow contango or backwardated markets there is no clear incentive for marketers to store crude oil. Despite the shallow contango curve, we have seen increased activity and interests from customers that are regularly turning over their volumes by blending various crude grades and delivering it out of the terminal or customers utilizing the storage for more operational purposes for their downstream operations. As a result of this change in demand factors for Cushing storage, along with the forward price curve moving to a deeper contango in March of 2020, we anticipate a significant increase in demand, which has the potential to affect the volumes, rates and term lengths of our recontracting efforts.

Crude Oil Pipeline Services - Crude oil pipeline transportation, while potentially influenced by the shape of the crude oil market curve, is typically impacted more by overall drilling activity. From April 2016 to July 2018, a portion of our Oklahoma system was out of service, which reduced transportation capacity by approximately 20,000 Bpd. In July 2018, we were able to restore service to that portion of pipeline. The ability to fully utilize the capacity of the system may be impacted by the market price of crude oil and producers’ decisions to increase or decrease production in the areas we serve.

During the past two years, we increased our internal crude oil marketing operations activities with the objective of increasing the overall utilization of our Oklahoma crude oil pipeline system. Typically, the volume of crude oil we purchase in a given month will be sold in the same month. However, we have market price exposure for inventory that is carried over month-to-month as well as pipeline linefill we maintain. Since our pipeline tariffs require shippers to carry their share of linefill, our crude oil marketing operations, as a shipper, also carries linefill. We may also be exposed to price risk with respect to the differing qualities of crude oil we transport and our ability to effectively blend them to market specifications.

Operating margin in our crude oil pipeline segment was negative for 2018, and in December 2018, we evaluated our pipeline system for impairment 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, See Note 12 to our consolidated financial statements for discussion on the cancellation of this project.

Crude Oil Trucking Services - Crude oil trucking, while potentially influenced by the shape of the crude oil forward price curve, is typically impacted more by overall drilling activity and the ability to have the appropriate level of assets located properly to efficiently move the barrels to delivery points for customers.

On April 24, 2018, we sold our producer field services business, which has been historically reported 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.

Our Revenues

Our revenues consist of (i) terminalling revenues, (ii) gathering and transportation revenues, (iii) product sales revenues and (iv) fuel surcharge revenues. During the year ended December 31, 2019, we derived approximately $36.5 million of our revenues from services we provided to related parties, with $36.2 million and $0.3 million 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 utilized by 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 our terminals. Terminal throughput service charges are recognized as the crude oil or asphalt product is delivered out of our terminal. Storage service revenues are recognized as the services are provided on a monthly basis. We earn terminalling revenues in two of our segments: (i) asphalt terminalling services and (ii) crude oil terminalling services.

As of March 23, 2020, we have leases and terminalling agreements for all of our 53 asphalt facilities, including 23 facilities under contract with Ergon.  These agreements have, based on a weighted average by remaining fixed revenue, approximately 4.7 years remaining under their terms. One agreement expires at the end of 2020, and the remaining agreements expire at varying times thereafter, through 2026. We operate the asphalt facilities pursuant to terminalling agreements while our contract counterparties operate the asphalt facilities that are subject to lease agreements.

As of March 23, 2020, we have approximately 5.5 million barrels of crude oil storage under service contracts, including 3.3 million barrels of crude oil storage contracts that expire in 2020. The remaining terms on the service contracts that extend beyond 2020 range from 15 months to 21 months. Storage contracts with Vitol represent 2.9 million barrels of crude oil storage capacity under contract.

Gathering and transportation services revenues consist of service fees recognized for the gathering of crude oil for our customers and the transportation of crude oil to refiners, to common carrier pipelines for ultimate delivery to refiners or to terminalling facilities owned by us and others. Revenue for the gathering and transportation of crude oil is recognized when the service is performed and is based upon regulated and non-regulated tariff rates and the related transport volumes.  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):

In July 2018, we restored service on an out-of-service portion of our Oklahoma system, increasing the transportation capacity of the pipeline system by approximately 20,000 Bpd. See Crude oil pipeline services segment within our results of operations discussion for additional detail. Vitol accounted for 36% and 33% of volumes transported in 2018 and 2019, respectively.

Product sales revenues are comprised of (i) revenues recognized for the sale of crude oil to our customers that we purchase at production leases and (ii) revenue recognized in buy/sell transactions with our customers. Product sales revenue is recognized for products upon delivery and when the customer assumes the risks and rewards of ownership. We earn product sales 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.  We recognize fuel surcharge revenues in the period in which the related fuel and power expenses are incurred.

Our Expenses

Operating expenses decreased by 9% in 2019 as compared to 2018. This decrease is primarily attributable to the sale of the field services business in April 2018 and three asphalt facilities to Ergon in July 2018, as well as a decrease in depreciation due to certain other asphalt assets reaching the end of their depreciable lives. These decreases were offset by increases related to the asphalt facility acquired in March 2018. General and administrative expenses decreased by 12% in 2019 as compared to 2018. The decrease is primarily due to activity related to a payment made in 2018 to a fraudulent bank account due to a compromise of the vendor’s email system as originally disclosed in the 2018 Form 10-K.  In 2018, we recognized expense for the $0.9 million payment, and in 2019 we received a $0.5 million settlement that decreased expense. Compensation expense also decreased due to changes in personnel. Our interest expense decreased by $0.9 million in 2019 as compared to 2018. See Interest expense within our results of operations discussion for additional detail regarding the factors that contributed to the increase in interest expense in 2019.

Income Taxes

As part of the process of preparing the consolidated financial statements, we are required to estimate the federal and state income taxes in each of the jurisdictions in which our subsidiary that is taxed as a corporation operates. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are included in our consolidated balance sheets. We must then assess, using all available positive and negative evidence, the likelihood that the deferred tax assets will be recovered from future taxable income. If we believe that recovery is not likely, we must establish a valuation allowance. To the extent we establish a valuation allowance or increase or decrease this allowance in a period, we must include an expense or reduction of expense within the tax provisions in the consolidated 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. The weight given to the potential effect of negative and positive evidence should be commensurate with the extent to which it can be objectively verified. The more negative evidence that exists (a) the more positive evidence is necessary and (b) the more difficult it is to support a conclusion that a valuation allowance is not needed for some portion, or all of the deferred tax asset. Among the more significant types of evidence that we consider are:

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 the benefits of the deferred tax assets, we have provided a full valuation allowance against our deferred tax asset as of December 31, 2019.

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 liquid asphalt 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 oil we terminal, gather, market or transport are affected by commodity prices. We generate revenues by charging a fee for services provided at each transportation stage as crude oil is shipped from its origin at the wellhead to destination points such as the Cushing Interchange, to refineries in Oklahoma, Kansas and Texas or to pipelines and by charging a fee for services provided for the terminalling of liquid asphalt and crude oil.

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) have limited 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 market expectations 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.  An increase or decrease in the production of crude oil from the oil fields served by our pipelines or an increase or decrease in the demand for crude oil in the areas served by our pipelines and terminal facilities will have a corresponding effect on the volumes we terminal, gather or transport. The production and demand for liquid 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 effect on 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 such acquisition 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 strategic locations.  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 the extent 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 working capital needs.

Ergon Agreements

Twenty-three of our asphalt facilities are contracted to Ergon under multiple agreements. Service revenues under these agreements are primarily based on contracted monthly fees under the applicable agreement at rates, which we believe are fair and reasonable to us and our unitholders and are comparable with the rates we charge third parties. Agreements for eight of the facilities expire on October 4, 2023, and agreements for the remaining 15 facilities expire on December 31, 2025. 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 Board’s conflicts committee reviewed and approved these agreements in accordance with our procedures for approval of related-party transactions and the provisions of the partnership agreement. For the years ended December 31, 2018 and 2019, we recognized revenues of $48.0 million and $36.1 million, respectively, for services provided to Ergon under these agreements.

Results of Operations

Non-GAAP Financial Measures

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

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

The table below summarizes our financial results for the years ended December 31, 2018 and 2019, and presents a reconciliation of our non-GAAP financial measure reconciled to the most directly comparable GAAP measure: 

Total operating margin excluding depreciation and amortization increased 7% from 2018 to 2019. Asphalt terminalling services operating margin decreased $6.0 million, or 9%, from 2018 to 2019 as a result of the sale of three asphalt facilities to Ergon in July 2018. This decrease was offset by increases in our other operating segments. The increase in our crude oil terminalling services operating margin is primarily due to an increase in rented storage capacity. Margins in our crude oil pipeline services segment reflect the recovery of throughput volumes since the restoration of a portion of our Oklahoma system in July 2018, on which we had suspended service in April 2016 due to the discovery of a pipeline exposure on a riverbed in southern Oklahoma.  In addition, an $0.8 million sale of crude oil product accumulated over time through customer loss allowance deductions for the year ended December 31, 2019, also contributed to the increased margin in our crude oil pipeline services segment; there were no such sales in the same period in 2018. Crude oil trucking services operating margin, excluding depreciation and amortization, improved for the year ended December 31, 2019, due to improved rates beginning in the fourth quarter of 2018 and longer length of hauls transported.

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

Analysis of Operating Segments

Asphalt terminalling services segment

Our asphalt terminalling services segment operations generally consist of fee-based activities associated with providing terminalling services, including storage, blending, processing and throughput services, for liquid asphalt. Revenue is generated through operating lease contracts and storage contracts, throughput and handling contracts.

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

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

Crude oil terminalling services segment

Our 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:

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

Crude oil pipeline services

Our crude oil pipeline services segment operations include both service and product sales revenue. Service revenue generally consists of tariffs and other fees associated with transporting crude oil products on pipelines. Product sales revenue is comprised of (i) revenues recognized for the sale of crude oil to our customers that we purchase at production leases and (ii) revenue recognized in buy/sell transactions with our customers. Product sales revenue is recognized for products upon delivery and when the customer assumes the risks and rewards of ownership.

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

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

Crude oil trucking services

On April 24, 2018, the Partnership 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 crude oil trucking and producer field services operating segment to crude oil trucking services during the second quarter of 2018. Our crude oil trucking services segment operations generally consist of fee-based activity associated with transporting crude oil products on trucks. Revenues are generated primarily through transportation fees.

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

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

Other Income and Expenses

Depreciation and amortization. Depreciation and amortization decreased to $25.5 million for 2019 compared to $29.4 million for 2018. 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, partially offset by the acquisition of the asphalt facility in March 2018.

General and administrative expense.  General and administrative expense was $14.1 million for the year ended December 31, 2019, compared to $16.0 million for 2018. The decrease from 2018 to 2019 is primarily due to activity related to a payment made in 2018 to a fraudulent bank account due to a compromise of the vendor’s email system as originally disclosed in the 2018 Form 10-K.  In 2018, we recognized expense for the $0.9 million payment, and in 2019 we received a $0.5 million settlement that decreased expense. Compensation expense also decreased due to changes in personnel.

Asset impairment expense. Asset impairment expense in 2018 and 2019 included $10.0 million and $2.2 million, respectively, related to Cimarron Express. See Note 12 to our consolidated financial statements for more information. The year ended December 31, 2019, also included flood-related impairment expense of $0.3 million. Asset impairment expense in 2018 also included $40.7 million related 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 recoverable value of the linefill as indicated by market rates dropping below our historical average cost per barrel. Other impairments in 2019 were comprised primarily of a write-down of an obsolete truck station.

Gain on sale of assets. Gain on sale of assets was $0.5 million in 2019 and $0.1 million in 2018.  For the year ending December 31, 2019, we sold various surplus assets, including three truck stations, a portion of pipeline linefill, and a 35-mile, standalone portion of the Mid-Continent pipeline system.  Proceeds received during the year for these sales were $5.7 million and resulted in a net gain on sale of assets of $0.5 million.  For the year ending December 31, 2018, a gain of $0.4 million related to the sale of our field services business in April was offset by losses on the sale of pipeline linefill and the sale and disposal of surplus, used property and equipment.

Other income. Other income for the year ended December 31, 2019, relates to insurance recoveries related to flood damages at certain asphalt facilities.

Gain on sale of unconsolidated affiliate. On April 3, 2017, we sold our investment in Advantage Pipeline, L.L.C. and received cash proceeds at closing from the sale of approximately $25.3 million, recognizing a gain on sale of unconsolidated affiliate 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, for which we recognized an additional gain on sale of unconsolidated affiliate during the three months ended September 30, 2017. We received approximately $2.2 million for the pro rata portion of the remaining net escrow proceeds in January 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 $16.0 million for 2019 compared to $16.9 million for 2018. Interest expense represents interest on borrowings under our credit agreement, as well as amortization of debt issuance costs and unrealized gains and losses related to the change in fair value of interest rate swaps. The following table presents the significant components of interest expense:

Lower weighted average debt outstanding during 2019 as compared to 2018 was partially offset by higher interest rates. 

Effects of Inflation

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

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements as defined by Item 303 of Regulation S-K.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

The following table summarizes our sources and uses of cash for the years ended December 31, 2018 and 2019 (in millions):

Operating Activities.  Net cash provided by operating activities was $49.8 million for the year ended December 31, 2019, as compared to $48.8 million for the year ended December 31, 2018. The increase in cash provided by operating activities is primarily the result of changes in net income as described in Results of Operations and in working capital.

Investing Activities.  Net cash used in investing activities was $4.3 million for the year ended December 31, 2019. Net cash used in investing activities included $8.4 million of proceeds from the sale of assets.  Of such proceeds, $2.6 million related to the December 2018 sale of linefill for which the cash consideration was not received until January 2019. Proceeds were offset by capital expenditures. Capital expenditures for the year ended December 31, 2019, included maintenance capital expenditures of $8.9 million, net of reimbursable expenditures of $0.2 million, and expansion capital expenditures of $3.5 million, net of reimbursable expenditures of $0.1 million. 

Net cash provided by investing activities was $39.5 million for the year ended December 31, 2018. Net cash provided by investing activities 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 $2.2 million related to the sale of our investment in Advantage Pipeline. Such proceeds were offset by capital expenditures and acquisitions.  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 crude oil marketing business’ activities. We also acquired an asphalt facility from a third party for $22.0 million in 2018.

Financing Activities.  Net cash used in financing activities was $46.4 million for the year ended December 31, 2019, and included net payments under our credit agreement of $10.0 million and distributions to unitholders of $34.0 million.

Net cash used in financing activities was $89.3 million for the year ended December 31, 2018. Financing activities for the year ended December 31, 2018, were primarily comprised of net payments under our credit agreement of $42.0 million and distributions to unitholders of $44.7 million.

Our Liquidity and Capital Resources

Cash flows from operations and borrowings under our credit agreement are our primary sources of liquidity. Our ability to borrow funds under our credit agreement may be limited by financial covenants. At December 31, 2019, we had a working capital deficit of $20.5 million. This is primarily a function of our approach to cash management. At December 31, 2019, we had approximately $143.4 million of availability under our revolving loan facility, subject to covenant restrictions, which limited our availability to $60.0 million.  On January 3, 2020, we paid Ergon $12.2 million related to our obligation to purchase Ergon’s interest in Cimarron Express (see Note 12 to our consolidated financial statements for more information).  After giving effect to this payment, we had approximately $267.6 million in borrowings outstanding under the credit facility and were not in violation of any of the covenants thereof.

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 maximum permitted consolidated total leverage ratio as of December 31, 2019, is 5.00 to 1.00, and decreases to 4.75 to 1.00 as of March 31, 2020 and thereafter. The Partnership’s consolidated total leverage ratio was 4.05 to 1.00 as of December 31, 2019. 

Management evaluates whether conditions and/or events raise substantial doubt about the Partnership’s ability to continue as a going concern within one year after the date that the consolidated financial statements are issued (the “assessment period”). In performing this assessment, management considered the risk associated 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 described below). However, there are certain inherent risks associated with our continued ability to comply with our consolidated total leverage ratio covenant.  These risks relate, among other things, to potential future (a) decreases in storage volumes and rates as well as throughput and transportation rates realized; (b) weather phenomenon that may potentially hinder the Partnership’s asphalt business activity; and (c) other items affecting forecasted levels of expenditures and uses of cash resources. Violation of the consolidated total leverage ratio covenant would be an event of default under the credit agreement, which would cause our $255.6 million in outstanding debt, as of December 31, 2019, to become immediately due and payable.  If this were to occur, the Partnership would not expect to have sufficient liquidity to repay these outstanding amounts then due, which could cause the lenders under the credit facility to pursue other remedies. Such remedies could include exercising their collateral rights to the Partnership’s assets. Based on our current forecasts, we believe we will be able to comply with the consolidated total leverage ratio during the assessment period.  However, we cannot make any assurances that we will be able to achieve our forecasts. If we are unable to achieve our forecasts, further actions may be necessary to remain in compliance with our consolidated total leverage ratio covenant including, but not limited to, cost reductions, common and preferred unitholder distribution curtailments, and/or asset sales.  We can make no assurances that we would be successful in undertaking these actions, or that we will remain in compliance with the consolidated total leverage ratio during the assessment period.

Capital Requirements. Our capital requirements consist of the following:

The following table breaks out capital expenditures for the years ended December 31, 2018 and 2019 (in thousands):

Expansion capital expenditures for the year ended December 31, 2018, included the purchase of $13.1 million of crude oil pipeline linefill to support our crude oil marketing business’ activities. We currently expect our expansion capital expenditures for organic growth projects to be approximately $2.0 million to $2.5 million and our maintenance capital expenditures to be approximately $7.5 million to $8.0 million, each net of reimbursable expenditures, in 2020. Our sources of liquidity for expansion and maintenance capital expenditures in 2019 were a combination of cash flows from operations and borrowings under our credit agreement, and we expect to use the same sources in 2020.

Our Ability to Grow Depends on Our Ability to Access External Expansion Capital. Our partnership agreement requires that we distribute all of our available cash to our unitholders. Available cash is reduced by cash reserves established by our General Partner to provide for the proper conduct of our business (including for future capital expenditures) and to comply with the provisions of our credit agreement.  We may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations because we distribute all of our available cash.

Description of Credit Agreement.  On May 11, 2017, we entered into an amended and restated credit agreement. 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 million and amend the maximum permitted consolidated total leverage 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 substantially all 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 currently committed revolving lender, subject to the consent of the new or increasing lenders and an aggregate maximum of $600.0 million for all revolving loan commitments 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.  The credit agreement requires mandatory prepayments of amounts outstanding thereunder with the net proceeds from certain asset sales, property or casualty insurance claims and condemnation proceedings, unless we reinvest such proceeds in accordance with the credit agreement, but these mandatory prepayments will not require any reduction of the lenders’ commitments under the credit agreement.

Borrowings under our credit agreement bear interest, at our option, at either the reserve-adjusted eurodollar rate (as defined in the credit agreement) plus an applicable margin 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 on the eurodollar rate, and we pay a commitment fee on the unused commitments under the credit agreement.  The applicable margins for the interest rate, the letters of credit fee and the commitment fee vary quarterly based on our consolidated total leverage ratio (as defined in the credit agreement, being generally computed as the ratio of consolidated total debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges).

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

Prior to the date on which we issue qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notes previously or concurrently issued) that equals or exceeds $200.0 million, the maximum permitted consolidated total leverage ratio is 5.00 to 1.00 for the fiscal quarter ending 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 permitted consolidated 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 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 we issue qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notes previously or concurrently issued) that equals or exceeds $200.0 million, the maximum permitted consolidated total leverage ratio is 5.00 to 1.00; provided that 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 the second 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 consolidated total secured debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) is 3.50 to 1.00, but this covenant is only tested from and after the date on which we issue qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notes previously or concurrently issued) that equals or exceeds $200.0 million.

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

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

At December 31, 2019, our consolidated total leverage ratio was 4.05 to 1.00 and our consolidated interest coverage ratio was 4.24 to 1.00.  We were in compliance with all covenants of our credit agreement as of December 31, 2019.

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

In addition to other customary events of default, the credit agreement includes an event of default if:

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

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

Critical Accounting Policies and Estimates

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

Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts and disclosure of contingencies. Management makes significant estimates including: (1) allowance for doubtful accounts receivable; (2) estimated useful lives of assets, which impacts depreciation; (3) estimated cash flows and fair values inherent in impairment tests; (4) accruals related to revenues and expenses; (5) the estimated fair value of financial instruments; and (6) liability and contingency 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 or extend the useful life of an asset are expensed as incurred. The carrying value of the assets is based on estimates, assumptions and judgments relative to useful lives and salvage values.  As assets are disposed of or sold, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is included in 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, including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives and salvage values that we believe to be reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. The estimated useful lives of our asset groups are as follows: 

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 obligations include varying levels of activity, including completely removing the assets and returning the land to its original state. We have determined that the settlement dates related to the retirement obligations are indeterminate. The assets with indeterminate settlement dates have been in existence for many years and with regular maintenance will continue to be in service for many years to come. In addition, it is not possible to predict when demands for our services will cease, and we do not believe that such demand will cease for the foreseeable future.  Accordingly, we believe the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, we cannot reasonably estimate the fair value of the associated asset retirement obligations.  We believe that if our asset retirement obligations were settled in the foreseeable future the potential cash flows that would be required to settle the obligations based on current costs are not material.  We will record asset retirement obligations for these assets in the period in which sufficient information becomes available for us to reasonably determine the settlement dates.

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

Goodwill. Goodwill represents the excess of the cost of acquisitions over the amounts assigned to assets acquired and liabilities assumed. Goodwill is not amortized, but is tested annually for impairment and when events and circumstances warrant an interim evaluation. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit. If the fair value of a reporting unit exceeds its carrying amount, 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 of the respective reporting unit, utilizing discount rates and other factors in determining the fair value of the reporting unit.  Inputs in the Partnership’s estimated discounted future net cash flows include existing and estimated future asset utilization, estimated growth rates in future cash flows and estimated terminal values. No impairment expense was recorded in 2018 or 2019.

Recent Accounting Pronouncements

For information regarding recent accounting developments that may affect our future financial statements, see Note 21 to our consolidated financial statements.

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

As a smaller reporting company, we are not required to provide the information required by Item 7A.

Item 8.    Financial Statements and Supplementary Data.

Our consolidated financial statements, together with the report of our independent registered public accounting firm PricewaterhouseCoopers LLP, are set forth on pages F-1 through F-28 of this report and are incorporated herein by reference.

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

None.

Item 9A.    Controls and Procedures.

Evaluation of disclosure controls and procedures. Our General Partner’s management, including the Chief Executive Officer and Chief Financial Officer, the principal executive officer and principal financial officer, respectively, of our General Partner, evaluated as of the end of the period covered by this report, the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of December 31, 2019.

Management’s Report on Internal Control Over Financial Reporting. Our General Partner’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Our General Partner’s management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal Control - Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2019. 

Changes in internal control over financial reporting.  There were no changes to our internal control over financial reporting that occurred during the three months ended December 31, 2019, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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 a regular basis in the future. The directors of our General Partner oversee our operations. Unitholders are not entitled to elect the directors of our General Partner or directly or indirectly participate in our management or operations. Our General Partner owes a limited fiduciary duty to our unitholders. Our General Partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Our General Partner, therefore, may cause us to incur indebtedness or other obligations that are nonrecourse to it. Borrowings under our existing credit 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 with Ergon), 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 and a member of the compensation committee and the conflicts committee of the Board.  Mr. Bradshaw serves as the chairman of the conflicts committee and a member of the compensation committee and the audit committee of the Board.  Mr. Shapiro serves as the chairman of the compensation committee and a member of 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 23, 2020. 

Our directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified.  Officers serve at the discretion of the Board. Robert H. Lampton and William W. Lampton are brothers. There are no other family relationships between officers and 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 Oil and 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 career at Shell, where he served from 1981 to 2009, lastly as President of Shell Pipeline Co., LP. Mr. Hurley received his Bachelor of Science in chemical engineering from North Carolina State University.

D. Andrew Woodward became the Chief Financial Officer of our General Partner in April 2019. Mr. Woodward has substantial financial experience across investment banking, corporate development, and corporate finance within the energy and midstream industry. Mr. Woodward previously served as Vice President, Finance and Treasurer of Andeavor Logistics (NYSE: ANDX), where he was appointed by its board of directors to be the principal financial officer. Prior to this appointment, he led investor relations for ANDX and started his career with Andeavor, now Marathon Petroleum, in corporate development leading valuation, structuring and economic analysis on corporate and asset transactions. Before joining Andeavor, Mr. Woodward served as Vice President at RBC Capital Markets within its energy investment banking group where he advised on numerous large scale mergers and acquisitions and capital markets transactions. Mr. Woodward received his Bachelor of Arts in economics and philosophy from Colorado College and his Master of Business Administration from the University of Texas at Austin. 

Joel W. Kanvik has served as Chief Legal Officer of our General Partner since November 2016 and 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. He provided legal and business counsel to a family of corporations/limited partnerships, including the development and execution for large-scale construction/acquisition projects, mergers and acquisitions, contracts and licenses, intellectual property, litigation management and corporate governance. Mr. Kanvik received his Bachelor of Arts in political science from Northwestern University and his Juris Doctor from the University of Wisconsin. 

Michael McLanahan has served as the Chief Accounting Officer of our General Partner since April 2019.  Mr. McLanahan previously served the Partnership in various accounting roles, including the Corporate Controller, and prior to joining the Partnership, he served as an audit manager for the public accounting firm of Ernst & Young LLP. Mr. McLanahan received his Bachelor of Arts in accounting from Ouachita Baptist 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 our General Partner from February 2010 to July 2013.  Previously, Mr. Speer served as the Vice President of Operations of our asphalt and emulsion subsidiary since June 2009.  Prior to joining our team, Mr. Speer served as Vice President of Operations for Koch Industries, Inc. and had operational responsibility for Koch’s crude 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 years of experience in the energy industry and received his Bachelor of Science in mechanical engineering from Kansas 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 Oil Company, LLC. He served as Senior Vice President and General Counsel of Devon Energy Corporation from January 1997 until he retired in February 2007. From February 2007 to February 2010, Mr. Ligon served in the capacity of Strategic Advisor to Love’s Travel Stops & Country Stores, Inc., based in Oklahoma City, Oklahoma, and previously acted as Executive Director of the Love’s Entrepreneurship Center at Oklahoma City University. He is also a member of the board of directors of Heritage Trust Company, Security State Bank (in which he has 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 Gas Inc., Vantage Drilling Company and TEPPCO Partners, L.P. Mr. Ligon received his undergraduate degree in chemistry from Westminster College and his law degree from the University of Texas School of Law. Mr. Ligon was selected to serve as a director on the Board due to his extensive business and leadership experience derived from his background as a director of various companies in the energy industry, as well 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 and transportation 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 at Kirby Corporation, including as President-Refined Products Division from 1992 to 1996. Mr. Bradshaw also served as an officer in the United States Navy. He received his Master of Business Administration from Harvard University and a bachelor’s degree in mathematics from the University of Missouri. Mr. Bradshaw was selected to serve as a director on the Board due to his business judgment and extensive industry knowledge and experience.

John A. Shapiro has served as a director of our General Partner since November 2009.  Mr. Shapiro retired as an officer at Morgan Stanley & Co., where he had served for more than 24 years in various capacities, most recently as Global Head of Commodities. While an officer at Morgan Stanley, Mr. Shapiro participated in the successful acquisitions of TransMontaigne Inc. and Heidmar Inc., and served as a member of the board of directors of both companies. Prior to joining Morgan Stanley & Co., Mr. Shapiro worked for Conoco, Inc. and New England Merchants National Bank. Mr. Shapiro has been a lecturer at Princeton University, Harvard University School of Government, HEC Business School (Paris, France) and Oxford University Energy Program (Oxford, UK). In addition, he serves 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 focused on upstream E&P investments. Mr. Shapiro has served on the board of directors of Blue Wolf Mongolia Holdings. He received his Master of Business Administration from Harvard University and his bachelor’s degree in economics from Princeton University. Mr. Shapiro was selected to serve as a director on the Board due to his financial expertise and extensive industry experience developed through his work at Morgan Stanley & Co., and by serving as a director of other energy 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 Audit in 2011 and currently serves as Senior Vice President - Finance. He also serves as Chairman of Ergon’s Senior Management Team. He is a certified public accountant in the state of Mississippi and previously worked at Arthur Anderson and Haddox Reid Burkes & Calhoun, PLLC, where he specialized in assurance and advisory services in the areas of oil and gas, manufacturing, investments and employee benefit plans. Mr. Adams received his Bachelor of Accountancy from Mississippi State University, and holds the designations of Chartered Global Management Accountant, Certified Fraud Examiner and Certified Internal Auditor. Mr. Adams currently serves as a member of the advisory council for Mississippi State’s Adkerson School of Accountancy and is the Chairman of the Board of Hartfield Academy. He has previously served as Chairman/President of the Petroleum Accounting Society of Mississippi and of the Mississippi Society of 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 on the 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 for Ergon 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 in Business Administration in accounting and his Master of Business Administration from Mississippi College and is a certified public accountant in the state of Mississippi. He also holds a Chartered Global Management Accountant designation. Mr. Brooks was selected to serve as a director on the Board due to his affiliation 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 in 2005. Prior to taking the role of Executive Vice President, Mr. Pastorek held various positions within Ergon including Senior Project Manager, Manager of Corporate Maintenance, General Manager - Ergon Terminaling, Inc., Vice President - Ergon Terminaling, Inc., and President - Ergon Terminaling, Inc. Mr. Pastorek received his Bachelor of Science in mechanical engineering from Mississippi State University and is a licensed professional engineer in the state of Mississippi. Mr. Pastorek was selected to serve as a director on the Board due to his affiliation with Ergon and his financial and business expertise.

Robert H. Lampton has served as a director of our General Partner since October 2016. Mr. Lampton has been with Ergon since 1983, and currently serves as President of the Supply and Distribution Division. He previously served as President of Ergon Terminalling, Inc., Ergon Trucking, Inc., Ergon Marine and Industrial 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 Company from 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 a member 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 Jackson Chamber Partnership (of which he is a past chairman), and Mississippi Baptist Health Foundation. He is a member of the Dean’s Advisory Council of Mississippi State University’s Bagley College of Engineering, and served as co-chair of the Mississippi Works initiative under Governor Phil Bryant. Mr. Lampton was selected 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 independence standards established by Nasdaq.  Nasdaq’s independence definition includes a series of objective tests, including that the director is not an employee of the company and has not engaged in various types of business dealings with the company. In addition, the Board has made a subjective determination as to each independent director that no relationships exist which, in the opinion of the Board, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director. In making these determinations, the directors reviewed and discussed information provided by the directors and us with regard to each director’s business and personal activities as they may relate to us and our management.  Nasdaq does not require a listed limited partnership like us to have a majority of independent directors on the Board or to establish a nominating committee.

In addition, the members of the audit committee also each qualify as “independent” under special standards established by the SEC for members of audit committees, and the audit committee includes at least one member who is determined by the Board to meet the qualifications of an “audit committee financial expert” in accordance with SEC rules, including that the person meets the relevant definition of an “independent” director.  John A. Shapiro is the independent director who has been determined to be an audit committee financial expert. Unitholders should understand that this designation is a disclosure requirement of the SEC related to experience and understanding with respect to certain accounting and auditing matters. The designation does not impose any duties, obligations or liability that are greater than are generally imposed on a member of the audit committee and the Board, and the designation of a director as an audit committee financial expert pursuant to this SEC requirement does not affect the duties, obligations or liability of any other member of the audit committee or 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 differences between the two roles.  We have taken this position to achieve an appropriate balance with regard to our strategic direction, oversight of management, unitholder interests and director independence.  Our General Partner’s Chief Executive Officer is responsible for setting our strategic direction and overseeing our day-to-day performance.  Our General Partner’s chairman of the Board is an independent director who provides guidance to the Chief Executive Officer and sets the agenda for 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 and strategies necessary to mitigate those risks and the status and effectiveness of those actions and strategies.  These regular updates are provided at meetings of the Board 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’s management team.  

Board Committees

We have standing conflicts, audit and compensation committees of the Board.  Each member of the audit, compensation and conflicts committees is an independent director in accordance with Nasdaq and applicable securities laws.  Each of the audit, compensation and conflicts committees has a written charter approved by the Board.  The written charter for each of these committees is available on our web site at www.bkep.com under the “Investors - Corporate Governance” section.  We will also provide a copy of any of our committee charters to any of our unitholders without charge upon written request to the attention of Investor Relations at 6060 American Plaza, Suite 600, Tulsa, Oklahoma 74135.  The current members of the audit, compensation and conflicts committees of the 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 the conflicts committee is to review matters that the directors believe may involve conflicts of interest.  The conflicts committee determines if the resolution of the conflict of interest is fair and reasonable to us.  The conflicts committee may retain independent legal and financial advisors to assist in its evaluation of a transaction.  The members of the conflicts committee may not be officers or employees of our General Partner or directors, officers or employees of its affiliates and must meet the independence standards to serve on an audit committee of a board of directors established by any national securities exchange upon which our common units are traded and the SEC.  Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our General Partner of any duties it may owe us or our unitholders.

Audit Committee.  The members of the audit committee are Messrs. Bradshaw, Ligon (chairman) and Shapiro.  The primary responsibilities of the audit committee are to assist the Board in its general oversight of our financial reporting, internal controls and audit functions, and it is directly responsible for the appointment, retention, compensation and oversight of the work of our independent auditors.  

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 responsibility of the compensation committee is to oversee compensation decisions for the outside directors of our General Partner and executive officers of our General Partner, as well as 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, and including our General Partner’s independent directors, who are not employees of our General Partner, with regard to their activities relating to us.  The Code of Business Conduct and Ethics incorporates guidelines designed to deter wrongdoing and to promote honest and ethical conduct and compliance with applicable laws and regulations.  It also incorporates our expectations of our General Partner’s employees that enable us to provide accurate and timely disclosure in our filings with the Securities and Exchange Commission and other public communications.  The Code of Business Conduct and Ethics is publicly available under the “Investors - Corporate Governance - Code of Business Conduct and Ethics” section of our website at www.bkep.com.  The information contained on, or connected to, our website 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 to the attention of Investor Relations at 6060 American Plaza, Suite 600, Tulsa, Oklahoma 74135.  If any substantive amendments are made to the Code of Business Conduct and Ethics, or if we or our General Partner grant any waiver, including any implicit waiver, from a provision of the code to any of our General Partner’s executive officers and directors, we will disclose the nature of such amendment or waiver on that web site or in a current report on Form 8-K.

Section 16(a) Beneficial Ownership Reporting Compliance

Based solely upon a review of Forms 3, 4 and 5 (and any amendments thereto) furnished to us, we believe that all directors, officers, beneficial owners of more 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 of them during the year ended December 31, 2019, except for one Form 4 filed late on behalf of one of our officers in June 2019 with respect to one transaction.

Reimbursement of Expenses of our General Partner

Pursuant to our partnership agreement, our General Partner and its affiliates are entitled to receive reimbursement for the payment of expenses related to our operations 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 2019 and the two most highly compensated executive officers other than the PEO serving at December 31, 2019, and up to two additional 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, 2019, are referred to as the Named Executive Officers (“NEOs”).  The NEOs during 2019 were:

As is the case with many publicly traded partnerships, we have not historically directly employed any persons responsible for managing or operating us or for providing services relating to day-to-day business affairs.  Our General Partner manages our operations and activities, and its Board and officers make decisions on our behalf. The compensation for the NEOs for services rendered to us is determined by the compensation committee of our General Partner.  

Employment Agreements.  Messers. Hurley and Woodward have each entered into an employment agreement with our General Partner or one of its subsidiaries.

Employment Agreement of Mr. Hurley. Mr. Hurley’s employment agreement had an initial term of five years that now automatically renews for subsequent one-year periods unless either party gives 90 days advance notice of termination. Pursuant to Mr. Hurley’s employment agreement, Mr. Hurley was paid an initial annual base salary of $425,000. Our General Partner’s compensation committee has increased the base salary of Mr. Hurley to $450,000 since the initial employment agreement. Mr. Hurley also received 500,000 non-participating phantom units in September 2012 under the General Partner’s Long-Term Incentive Plan, which vested ratably over five years pursuant to the Phantom Unit Agreement he entered into with the General Partner. The units were fully vested as of December 31, 2017.  The employment agreement also provides that Mr. Hurley is eligible to participate in any employee benefit plans maintained by the General Partner and is entitled to reimbursement for certain out-of-pocket expenses.  Mr. Hurley has agreed 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 the expiration of the term of Mr. Hurley’s employment agreement or termination due to death or disability, Mr. Hurley’s employment agreement provides for payment of 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 be entitled to continued participation in our General Partner’s welfare benefit programs for a period of 18 months following termination. Based upon Mr. Hurley’s current base salary, the maximum amount of the lump sum severance payment would be approximately $0.5 million, in addition to continued participation in the General 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 defined therein) occurs, Mr. Hurley is terminated by our General Partner without Cause (as defined therein) or Mr. Hurley terminates the agreement for Good Reason (as defined 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 of base salary and Mr. Hurley’s most recent annual bonus and continued participation in our General Partner’s welfare benefit programs for the longer of the remainder of the term of the employment agreement or one year after termination. Based upon Mr. Hurley’s current base salary and most recent annual bonus, the maximum amount of the lump sum severance payment would be approximately $0.6 million, in addition to continued participation in the General Partner’s welfare benefit programs and the amounts of earned but unpaid base salary and benefits under any incentive plans.

Employment Agreement of Mr. Woodward. Mr. Woodward’s employment agreement had an initial term of three years that will automatically renew for subsequent one-year periods unless either party gives 90 days advance notice of termination. Pursuant to Mr. Woodward’s employment agreement, Mr. Woodward’s initial annual base salary is $350,000. Pursuant to his offer of employment referenced in his employment agreement, Mr. Woodward also received a $50,000 initial bonus that was paid following 90 days of employment and a $50,000 grant of long-term incentive units that was awarded following 30 days of employment, which will vest June 1, 2022.  The offer of employment also provided for an incentive compensation bonus of $160,000 and a grant of $160,000 of long-term incentive units, both to be awarded as part of the Partnership’s regular March 2020 compensation actions.  Per the offer of employment, the long-term incentive units can be paid in units or cash equivalent, and in March 2020, it was determined to pay $85,000 in units and $75,000 in cash.  The offer of employment also provided for make-whole payments to replace certain lost compensation opportunities with Mr. Woodward’s prior employer totaling $550,000, with $150,000 paid on December 31, 2019, and two installments of $200,000 to be paid on December 31 of 2020 and 2021.  The employment agreement also provides that Mr. Woodward is eligible to participate in any employee benefit plans maintained by the General Partner and is entitled to reimbursement for certain out-of-pocket expenses.  Mr. Woodward has agreed 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. Woodward other than for Good Reason as defined therein, termination after the expiration of the term of Mr. Woodward’s employment agreement or termination due to death or disability, Mr. Woodward’s employment agreement provides for payment of any unpaid base salary and vested or unvested benefits under any incentive plans, a lump sum payment equal to 12 months of base salary, any unpaid make-whole payments and Mr. Woodward will also be entitled to continued participation in our General Partner’s welfare benefit programs for a period of 12 months following termination. Based upon Mr. Woodward’s current base salary and unpaid make-whole payments, the maximum amount of the lump sum severance payment would be approximately $0.8 million, in addition to continued participation in the General Partner’s welfare benefit programs and the amounts of earned but unpaid base salary and benefits under any incentive plans. 

Long-Term Incentive Plan. General.  Our General Partner has adopted the Long-Term Incentive Plan (“LTIP”) for employees, consultants and directors of our 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 its entirety by reference to the LTIP. The LTIP provides for the grant of unit awards, restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. There are currently 4,100,000 common units reserved for issuance under the LTIP, subject to adjustment for certain events.  Units that are canceled, forfeited or withheld to satisfy our General Partner’s tax withholding obligations are available for delivery pursuant to other awards. 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 are fully 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 the recipient 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 vesting of 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 may make grants of restricted units and phantom units under the LTIP to eligible individuals containing such terms, consistent with the LTIP, as the compensation committee may determine, including the period over which restricted units and phantom units granted will vest. The compensation committee may, at its discretion, 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 vesting requirements as the restricted units. The compensation committee, at its discretion, may also grant tandem distribution equivalent rights with respect to phantom units.

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

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

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

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

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

Amendment or Termination of LTIP.  The Board, at its discretion, may terminate the LTIP at any time with respect to the units for which a grant has not theretofore 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 when units 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 from time to time and the compensation committee may amend any award; provided, however, that no change in any outstanding award may be made that would materially impair the rights of the participant without the consent of the affected participant.

Unit Purchase Plan. On June 23, 2014, the Partnership’s unitholders approved the Blueknight Energy Partners, L.P. Employee Unit Purchase Plan (the “Unit Purchase Plan”). The Unit Purchase Plan provides employees of the General Partner and its affiliates who perform services for the Partnership the opportunity to acquire 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 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. The purpose of the Unit Purchase Plan is to promote our interests by providing employees of the General Partner and its affiliates a cost-effective program to enable them to acquire or increase their ownership of common units and to provide a means whereby such individuals may develop a sense of proprietorship and personal involvement in our development and financial success, and to encourage them to devote their best efforts to our business, thereby advancing our interests. As of December 31, 2019, 372,795 common units have been delivered under the Unit Purchase Plan.

Summary Compensation Table

The following table summarizes the compensation of our NEOs for the years ended 2019 and 2018. 

Outstanding Equity Awards at Fiscal Year-End 2019

The following table provides information concerning all outstanding equity awards made to a NEO as of December 31, 2019, including, but not limited to, awards made under our General Partner’s LTIP. 

Director Compensation for Fiscal Year 2019

Directors who are not officers or employees of any controlling entity or their affiliates receive compensation for attending meetings of the Board and committees thereof.  Such directors receive the following:

In addition, each director is fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law.

Item 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 23, 2020, held by:

Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.  Percentage of total common and Preferred Units beneficially owned is based on 41,034,763 common units and 35,125,202 Preferred Units outstanding as of March 23, 2020.

Securities Authorized for Issuance under Equity Compensation Plans (as of March 23, 2020)