10-K 1 jpep-20161231x10k.htm 10-K jpep_Current folio_10K

 

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 


 

FORM 10-K

(Mark One)

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended December 31, 2016

 

or

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from   to

 

Commission file number 001-36647

 


 

JP ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)

 

Delaware

 

27-2504700

(State or other jurisdiction of
incorporation or organization)

 

(I.R.S. employer
identification number)

 

600 East Las Colinas Blvd
Suite 2000

Irving, Texas 75039
(Address of principal executive offices, including zip code)

(972) 444-0300

(Registrant’s telephone number, including area code)

 

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

 

 

 

 

Title of each class

 

Name of each exchange on which registered

Common Units Representing Limited Partner Interests

 

New York Stock Exchange

 

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes   No ☒

 

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.  Yes   No ☒

 

Indicate by check mark whether the Registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes ☒  No 

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes ☒  No 

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒

 

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer ☐

 

Accelerated filer ☒

 

 

 

Non-accelerated filer ☐
(Do not check if a smaller reporting company)

 

Smaller reporting company ☐

 

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes ☐  No ☒

 

The aggregate market value of common units held by non-affiliates of the registrant on June 30, 2016, was $122,192,092. The aggregate market value was computed by reference to the last sale price of the registrant's common units on the New York Stock Exchange on June 30, 2016.

 

As of February 27, 2017, the Registrant had 18,550,906 common units and 18,122,903 subordinated units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

 

 

 

 


 

TABLE OF CONTENTS

 

 

 

 

Page

 

 

PART I 

 

ITEMS 1. BUSINESS 

ITEM 1A. RISK FACTORS 

18 

ITEM 1B. UNRESOLVED STAFF COMMENTS 

38 

ITEM 2. PROPERTIES 

38 

ITEM 3. LEGAL PROCEEDINGS 

38 

ITEM 4. MINE SAFETY DISCLOSURES 

38 

PART II

 

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 

38 

ITEM 6. SELECTED FINANCIAL DATA 

40 

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 

43 

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 

67 

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 

68 

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 

68 

ITEM 9A. CONTROLS AND PROCEDURES 

68 

ITEM 9B. OTHER INFORMATION 

69 

PART III

 

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 

69 

ITEM 11. EXECUTIVE COMPENSATION 

75 

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS 

85 

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE 

86 

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES 

88 

PART IV

 

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 

89 

ITEM 16. FORM 10-K SUMMARY 

96 

 

 

i


 

PART I

 

Unless the context otherwise requires, references in this Annual Report on Form 10-K (this “report” or this “Form 10-K”) to “JP Energy Partners,” “the Partnership,” “we,” “our,” “us,” or like terms refer to JP Energy Partners LP and its subsidiaries, and references to “our general partner” refer to JP Energy GP II LLC, our general partner prior to March 8, 2017, and Argo Merger GP Sub, LLC, our general partner after March 8, 2017.  References to “our sponsor” or “Lonestar” refer to AL Lonestar, LLC, which owns and controls our general partner. References to “ArcLight Capital” refer to ArcLight Capital Partners, LLC and references to “ArcLight Fund V” refer to ArcLight Energy Partners Fund V, L.P. References to “ArcLight” refer collectively to ArcLight Capital and ArcLight Fund V. ArcLight Capital manages ArcLight Fund V, which controls our general partner through its ownership and control of Lonestar.

 

Cautionary Note Regarding Forward-Looking Statements

 

Certain statements and information in this Annual Report on Form 10-K may constitute “forward-looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “estimate,” “forecast,” “target,” “project,” “assume,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

 

the price of, demand for and production of, crude oil, refined products and natural gas liquids (“NGLs”) in the markets we serve;

the volumes of crude oil that we gather, transport and store, the throughput volumes at our refined products terminals and our NGL sales volumes;

the fees we receive for the crude oil, refined products and NGL volumes we handle;

pressures from our competitors, some of which may have significantly greater resources than us;

the cost of propane that we buy for resale, including due to disruptions in its supply, and whether we are able to pass along cost increases to our customers;

competitive pressures from other energy sources such as natural gas, which could reduce existing demand for propane;

the risk of contract cancellation, non-renewal or failure to perform by our customers, and our inability to replace such contracts and/or customers;

leaks or releases of hydrocarbons into the environment that result in significant costs and liabilities;

the level of our operating, maintenance and general and administrative expenses;

regulatory action affecting our existing contracts, our operating costs or our operating flexibility;

1


 

failure to secure or maintain contracts with our largest customers, or non-performance of any of those customers under the applicable contract;

competitive conditions in our industry;

changes in the long-term supply of and demand for oil, natural gas liquids, refined products and natural gas;

 

the availability and cost of capital and our ability to access certain capital sources;

a deterioration of the credit and capital markets;

volatility of fuel prices;

actions taken by our customers, competitors and third-party operators;

our ability to complete growth projects on time and on budget;

inclement or hazardous weather conditions, including flooding, and the physical impacts of climate change;

environmental hazards;

industrial accidents;

changes in laws and regulations (or the interpretation thereof) related to the transportation, storage or terminaling of crude oil and refined products or the distribution and sales of NGLs;

fires, explosions or other accidents;

the effects of future litigation;

 

the possibility that the expected synergies and value creation from the AMID Merger will not be realized or will not be realized within the expected time period;

 

the risk that the businesses of JPEP and AMID will not be integrated successfully;

disruption from the AMID Merger making it more difficult to maintain business and operational relationships; and

 

other factors discussed elsewhere in this Annual Report and in our other current and periodic reports filed with the Securities and Exchange Commission (the “SEC”).

 

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We disclaim any obligation to and do not intend to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

2


 

ITEM 1. BUSINESS

 

Overview

 

We are a growth-oriented limited partnership formed in May 2010 by members of management and further capitalized by ArcLight to own, operate, develop and acquire a diversified portfolio of midstream energy assets. Our operations consist of three business segments: (i) crude oil pipelines and storage, (ii) refined products terminals and storage and (iii) NGL distribution and sales.

 

For additional information relating to our disclosure of revenues, profits and total assets by operating segment, please read “Note 16—Reportable Segments” included in our audited consolidated financial statements incorporated by reference into this Form 10-K.

 

AMID Merger Agreement

 

On October 23, 2016, we and JP Energy GP II LLC entered into an Agreement and Plan of Merger (“LP Merger Agreement”) with American Midstream Partners, L.P. (“AMID”), American Midstream GP, LLC, the general partner of AMID (“AMID GP”), and an indirect and wholly owned subsidiary of AMID (“Merger Sub”).  On March 8, 2017, we were merged with and into Merger Sub (“AMID Merger”), with the Partnership surviving the merger as a wholly owned subsidiary of AMID.

   

At the effective time of the AMID Merger, (i) each common unit and each subordinated unit of the Partnership issued and outstanding, other than common units and subordinated units of the Partnership held by Lonestar, JP Energy Development LP, a Delaware limited partnership, or their respective affiliates (together, the “Affiliated Holders”) was converted into the right to receive 0.5775 of a common unit representing limited partner interests in AMID (“AMID Common Unit”) and (ii) each common unit and subordinated unit of the Partnership issued and outstanding held by the Affiliated Holders was converted into the right to receive 0.5225 of an AMID Common Unit.

   

In connection with the LP Merger Agreement, on October 23, 2016, AMID GP entered into an Agreement and Plan of Merger (the “GP Merger Agreement” and, together with the LP Merger Agreement, the “Merger Agreements”) with JP Energy GP II LLC and a wholly owned subsidiary of AMID GP (“GP Merger Sub”). On March 8, 2017, GP Merger Sub merged with and into JP Energy GP II LLC (the “GP Merger” together with the LP Merger, the “Mergers”), with JP Energy GP II LLC surviving the merger as a wholly owned subsidiary of AMID GP. 

 

In connection with the Merger Agreements, Lonestar, the Partnership and JP Energy GP II LLC entered into an Expense Reimbursement Agreement  providing that Lonestar will reimburse, or will pay directly on behalf of, the Partnership or our general partner the third party reasonable costs and expenses incurred by the Partnership or our general partner in connection with the Mergers, including all reasonable out-of-pocket legal and financial advisory fees, costs and expenses paid or payable to third parties and incurred in connection with the negotiation, execution and performance of the LP Merger Agreement and consummation of the Mergers.

 

How We Conduct Our Business

 

We conduct our business through fee-based and margin-based arrangements.

 

Fee-based.  We charge our customers a capacity, throughput or volume-based fee that is not contingent on commodity price changes. Our fee-based services include the operations in our crude oil pipelines and storage segment, our refined products terminals and storage segment, and the NGL transportation services we provide within our NGL distribution and sales segment. In our crude oil pipelines business, we purchase crude oil at an index price less a transportation fee, and simultaneously sell an identical volume of crude oil at a designated delivery point at the same index price. We consider this a fee-based business because we lock in the economic equivalent of a transportation fee. Our fee-based businesses are governed by tariffs or other negotiated fee agreements between us and our customers with terms ranging from one month to eight years.

 

3


 

Margin-based.  We purchase and sell crude oil in our crude oil pipelines and storage segment, and NGLs and refined products in our NGL distribution and sales segment. A portion of our margin related to the purchase and sale of crude oil in our crude oil pipelines and storage segment is derived from “fee equivalent” transactions in which we concurrently purchase and sell crude oil at prices that are based on an index, thereby generating revenue consisting of a margin plus our purchase, transportation, handling and storage costs. In our NGL distribution and sales segment, sales prices to our customers generally provide for a margin plus the cost of our products to our customers. We manage commodity price exposure through the structure of our sales and supply contracts and through a managed hedging program. Our risk management policy permits the use of financial instruments to reduce the exposure to changes in commodity prices that occur in the normal course of business, but prohibits the use of financial instruments for trading or to speculate on future changes in commodity prices.

 

Our Assets and Operations

 

Crude Oil Pipelines and Storage

 

Silver Dollar Pipeline System.  The Silver Dollar Pipeline System provides crude oil gathering services for producers targeting the Spraberry and Wolfcamp formations in the Midland Basin. The system currently consists of approximately 161 miles of high-pressure steel pipeline with throughput capacity of approximately 130,000 barrels per day and three interconnections to third-party, long-haul, transportation pipelines. Our operations are underpinned by long-term, fee-based contracts with leading producers in the Midland Basin. One significant contract has a remaining term of approximately six years and contains an acreage dedication related to crude oil production from approximately 125,000 acres in Crockett and Schleicher counties, Texas. Another significant contract has a remaining term of approximately 2.5 years and contains a minimum volume commitment that was amended in June 2016 to significantly increase the volumes committed thereunder. A third significant contract has a remaining term of approximately eight years and contains an acreage dedication related to crude oil production from approximately 57,000 acres in Reagan, Glasscock, Sterling and Irion Counties.

 

The Silver Dollar Pipeline System serves production from the Spraberry and Wolfcamp formations in the Midland Basin within Crockett, Reagan, Glasscock, Sterling, Irion and Schleicher Counties, Texas. As of December 2016, the Silver Dollar Pipeline System is connected to producers that control approximately 360,000 acres in Crockett, Reagan, Glasscock, Sterling, Irion and Schleicher Counties, Texas. The table below contains operational information related to the Silver Dollar Pipeline System.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Throughput For The Three

 

 

 

 

 

 

 

Months Ended

 

Length

    

Capacity

    

Storage Capacity

    

December 31, 2016

    

December 31, 2015

 

161 miles

 

130,000bpd

 

140,000 barrels

 

30,932bpd

 

26,888bpd

 

 

Construction of the Silver Dollar Pipeline System began in October 2012, and it was put into service in April 2013. The pipeline extends from the Midway Station in Crockett County, Texas to the Owens Station in Reagan County, Texas, a 4.3-acre site with an interconnection to Plains All American Pipeline, L.P.’s Spraberry pipeline expansion. In November 2014, a second connection was made to Oxy Centurion’s Cline Shale pipeline to give Silver Dollar a second delivery location. The Midway Station receives trucking volumes from multiple producers located to the south and has connections to neighboring producer facilities. The Midway Station currently has a 10,000 barrel tank and six truck injection stations.

 

In February 2015, we commissioned a new 70,000 barrel crude oil storage tank which increased our total crude oil storage capacity on the Silver Dollar Pipeline to 110,000 barrels at that time.

   

In April 2015, we announced that we had executed an interconnection agreement with an affiliate of Magellan Midstream Partners, L.P. (“Magellan”) to connect our Silver Dollar Pipeline System to Magellan’s Longhorn pipeline at the Barnhart Terminal in Crockett County, Texas. The interconnection provides producers with a third takeaway option from the Silver Dollar Pipeline System. The connection was completed and began service in September 2015. As part of the Magellan project, we also added 30,000 barrels of crude oil storage which further increased the total crude oil storage capacity on the Silver Dollar Pipeline to 140,000 barrels.

4


 

 

Picture 1

 

In our crude oil pipelines business, we purchase crude oil from a producer or supplier at a designated receipt point on our Silver Dollar Pipeline System at an index price less a transportation fee, and simultaneously sell an identical volume of crude oil at a designated delivery point at the same index price, allowing us to lock in a fixed margin that is in effect economically equivalent to a transportation fee. These transactions account for substantially all of the Adjusted EBITDA we generate on our Silver Dollar Pipeline System.

 

Crude Oil Storage. We own a crude oil storage facility in Cushing, Oklahoma with an aggregate shell capacity of approximately 3.0 million barrels, consisting of five 600,000-barrel storage tanks. These storage tanks were built in 2009 and are located on the western side of a terminal owned by Enterprise Products Partners L.P. (the “Enterprise Terminal”). The storage tanks are able to receive approximately 18,000 barrels of crude oil per hour or deliver approximately 8,000 barrels of crude oil per hour, and have inbound connections with multiple pipelines and two-way interconnections with all of the other major storage facilities in Cushing, including the delivery point specified in all crude oil futures contracts traded on the NYMEX. TEPPCO Partners LP (“TEPPCO”), a wholly owned subsidiary of Enterprise, serves as the operator of our facilities.

 

Our crude oil storage business provides stable and predictable fee-based cash flows. All of the shell capacity of our storage tanks is dedicated to one customer pursuant to a long-term contract, backed by an escrow account, with an expiration in August 2017. We generate crude oil storage revenues by charging this customer a fixed monthly fee per barrel of shell capacity that is not contingent on the customer’s actual usage of our storage tanks.

 

Our storage facility is on land that is subject to a 50-year lease with TEPPCO. We have the option to extend our lease by up to an additional 30 years. Our location in the Enterprise Terminal provides our customer with access to multiple pipelines outbound from Cushing, including a manifold connecting our tanks to the Enterprise Terminal. The Enterprise Terminal is connected to the Seaway Pipeline, which is owned and operated by Enterprise and Enbridge Inc. and transports crude oil from Cushing to the Gulf Coast.

 

We are party to an operating agreement pursuant to which an affiliate of TEPPCO operates and maintains the crude oil storage tanks located at our crude oil storage facility and provides us with certain services, including services related to product movements, data tracking, station operations (including documentation and inspection programs), and purchases of material. These services are provided to us at a monthly base rate and we are permitted to request additional

5


 

services from TEPPCO, which are provided to us at cost. TEPPCO is obligated to perform the services as a reasonably prudent operator and in accordance with all applicable laws and accepted industry practices. The operating agreement contains certain other customary terms, including provisions relating to restrictions on assignment, terms of payment, indemnification, confidentiality and dispute resolution. The operating agreement remains in place for the same term as the lease agreement described above.

 

Crude Oil Supply and Logistics.  Our crude oil pipelines and storage segment also manages the physical movement of crude oil from origination to final destination largely through our network of owned and leased assets. Our assets and operations are located in areas of substantial future crude oil production growth, including the Permian Basin, Eagle Ford shale, and the Texas Panhandle. We own and operate a fleet of approximately 63 crude oil gathering and transportation trucks and approximately four crude oil truck injection stations and terminals. Due to the limited pipeline infrastructure in some of the basins in which we operate, our crude oil gathering and transportation trucks provide immediate access for customers to transport their crude oil to the most advantageous outlets, including pipelines, rail terminals and local refining centers.

 

We primarily generate revenues in our crude oil supply and logistics business by purchasing crude oil from producers, aggregators and traders at an index price less a discount and selling crude oil to producers, traders and refiners at a price linked to the same index. The majority of activities that are carried out within our crude oil supply and logistics business are designed to produce a stable baseline of results in a variety of market conditions, while at the same time providing upside opportunities.

 

In general, sales prices referenced in the underlying contracts, most of which have a 30-day evergreen term, are market-based and may include pricing differentials for such factors as delivery location or crude oil quality. Our crude oil supply and logistics business generates substantial revenues and cost of products sold as a result of the significant volume of crude oil bought and sold. While the absolute price levels of crude oil significantly impact revenues and cost of products sold, such price levels normally do not bear a relationship to gross profit for crude oil sales generated under buy/sell contracts. As a result, period-to-period variations in revenues and cost of products sold are not generally meaningful in analyzing the variation in gross profit for our crude oil supply business.

 

We mitigate the commodity price exposure of our crude oil supply and logistics business by limiting our net open positions through the concurrent purchase and sale of like quantities of crude oil intended to lock in positive margins based on the timing, location or quality of the crude oil purchased and delivered. All of our supply activities are subject to our comprehensive risk management policy, which establishes limits in order to manage risk and mitigate our commodity price exposure.

 

We are focused on increasing the utilization of our crude oil gathering and transportation fleet. We typically assign crude oil gathering and transportation trucks to a specific area but can temporarily relocate them to meet demand as needed.

 

CAST.  We equip our drivers with advanced computer technology and dispatch them from central locations. Our drivers are provided with hand-held computers which allow them to utilize our CAST software after they have loaded product. Our CAST software is a centralized system for dispatch, electronic ticket management, reporting, operations data management and lease data management. The CAST software validates ticket data in the field to greatly improve accuracy relative to paper tickets and provides our customers with near real-time views of dispatch, truck tickets, vehicle location, load acceptances and rejections and drivers. The CAST software also offers our customers flexible reporting options by providing customized data to the customer in the format that works best for its accounting and marketing needs.

 

Refined Products Terminals and Storage

 

Our refined products terminals and storage segment is comprised of two refined products terminals located in North Little Rock, Arkansas and Caddo Mills, Texas. Our refined products terminals are facilities where refined products

6


 

are transferred to or from storage or transportation systems, such as pipelines, to other transportation systems, such as trucks. Our refined products terminals provide the following services:

 

·

receipt, storage, inventory management and distribution;

 

·

blending and injection of additives to achieve specified grades of gasoline; and

 

·

other ancillary services that include heating of bio-diesel, product transfer and railcar handling services.

 

Our refined products terminals consist of multiple storage tanks with a combined aggregate storage capacity of 1.3 million barrels and are equipped with automated truck loading equipment that is operational 24 hours per day. This automated system provides for control of security, allocations, and credit and carrier certification by remote input of data by the terminal and our customers. In addition, our refined products terminals are equipped with truck loading racks capable of providing automated computer blending to individual customer specifications.

 

We generate fee-based revenues in our refined products terminals and storage segment from:

 

·

throughput fees based on the receipt and redelivery of refined products, including fees based on the volume of product redelivered from the terminal;

 

·

storage fees based on a rate per barrel of storage capacity per month;

 

·

additive service fees based on ethanol and biodiesel used in blending services and for additive injection; and

 

·

ancillary fees for the heating of bio-diesel, product transfer and railcar handling services.

 

Our refined products terminals and storage segment generates its fee-based revenues pursuant to contracts that typically contain evergreen provisions consistent with industry practice so that, after an initial term of one to two years, they can be canceled upon 60 days’ notice. We also generate revenues from (i) blending activities, such as ethanol blending and butane blending, and (ii) our vapor recovery units.

 

The following table highlights the storage capacity, number of loading lanes, number of tanks, supply source, mode of distribution and average daily throughput of our refined products terminals:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Shell

 

 

 

 

 

 

 

 

 

 

 

 

    

Storage

    

 

    

 

    

 

    

 

    

Approximate Average Throughput

 

 

 

Capacity

 

Loading

 

Number

 

 

 

Mode of 

 

(barrels per day) for the Year Ended

Terminal Location

 

(bbls)

 

Lanes

 

of Tanks

 

Supply Source

 

Redelivery

 

December 31, 2016

    

December 31, 2015

 

Little Rock, AR

 

550,000

 

8

 

11

 

Pipeline, Rail and Truck

 

Truck

 

35,485

 

41,018

 

Caddo Mills, TX

 

770,000

 

5

 

10

 

Pipeline and Truck

 

Truck

 

21,256

 

21,057

 

 

North Little Rock terminal.  Our North Little Rock terminal consists of 11 storage tanks with an aggregate capacity of approximately 550,000 barrels and has eight loading lanes with automated truck loading equipment to minimize wait time for our customers. Our truck loading racks are capable of providing automated computer blending to customer specifications. The North Little Rock terminal handles products such as multi-octane conventional gasoline, ultra-low sulphur diesel with dye-at-rack capability, bio-diesel with ratio blending capability and ethanol. In the second quarter of 2016, we completed the connection of the North Little Rock terminal to Magellan’s Little Rock Pipeline. Following the connection, the North Little Rock terminal allows delivery from Enterprise TE Products Pipeline Company LLC and Magellan’s Little Rock Pipeline which provides access to both Gulf Coast and Mid-Continent refineries.  We also completed our ethanol unit train expansion project in the fourth quarter of 2016. With the ethanol

7


 

unit train expansion, our North Little Rock terminal’s ethanol offloading efficiency and capacity significantly improved, allowing for offloading of up to 108 car unit trains. Our North Little Rock terminal serves the Little Rock metropolitan area.

 

Caddo Mills terminal.  Our Caddo Mills terminal consists of 10 storage tanks with an aggregate capacity of approximately 770,000 barrels and has five loading lanes with automated truck loading equipment to minimize wait time for our customers. This terminal is served by the Explorer Pipeline and has truck loading racks capable of providing automated computer blending to customer specifications. Our Caddo Mills terminal handles products such as conventional blend stock for oxygenate blending (CBOB) gasoline, reformulated blend stock for oxygenate blending (RBOB), premium blend stock for oxygenate blending (PBOB), ethanol, ultra-low sulphur diesel with dye-at-rack capability and bio-diesel with ratio blending capability. We own approximately six additional acres of land at our Caddo Mills terminal that is available for future expansion. Management estimates that this acreage is capable of housing an additional 200,000 barrels of storage capacity. The Caddo Mills terminal serves Collin County, located in the northeast portion of the Dallas-Fort Worth metroplex (“DFW”).  In the first quarter of 2017, we began a capital project to connect to Explorer’s pipeline serving DFW, which will enable our customers to send gasoline and diesel volumes to DFW.

 

NGL Distribution and Sales

 

NGL Sales

 

Our NGL sales business involves the retail, commercial and wholesale sale of NGLs and other refined products (including sales of gasoline and diesel to our oilfield service and agricultural customers) in seven states in the Southwest and Midwest to approximately 102,000 customers through our distribution network of 43 customer service locations. We generate revenues by charging a price per gallon consisting of our product supply, transportation, handling, and storage costs plus a margin. Since July 2010, we have acquired 18 propane franchises to expand our market presence within our operating region in Texas, Oklahoma, New Mexico, Arizona, Arkansas, Kansas and Missouri.

 

Customers.  We sell propane, butane and refined fuels, including diesel, gasoline, lubricants and solvents, primarily to three customer markets: retail, commercial and wholesale, which include a mix of residential, commercial, agricultural, oilfield service and industrial customers. The customer service centers in our NGL sales business are located in suburban and rural areas where natural gas is not readily available. These customer service centers generally consist of an office, warehouse and service facilities, with one or more 2,500 to 45,000 gallon storage tanks on the premises. These tanks are used to supply our bobtail trucks, which in turn make deliveries to our retail customers. Customers can also bring their own NGL storage containers to our customer service centers to be filled.

 

Retail.  We primarily serve residential customers through the sale of propane for home heating and power generation. We deliver propane through our 133 active bobtail trucks, which have capacities ranging from 2,000 gallons to 5,000 gallons of propane into stationary storage tanks on our customers’ premises. Tank ownership and control at customer locations are important components of our operations and customer retention, and account for approximately half of our retail volumes. The capacity of these storage tanks ranges from approximately 100 gallons to approximately 12,000 gallons, with a typical tank having a capacity of 250 to 500 gallons. We also offer a propane supply commitment program to customers who own their own tanks. Under the program, customers receive progressively larger discounts off our posted prices each year that they remain as our customer. We also offer our customers a budget payment plan whereby the customer’s estimated annual propane purchases and service contracts are paid for in a series of estimated equal monthly payments over a twelve-month period.

 

In Arizona, our subsidiary, Alliant Arizona Propane, L.L.C., sells propane to residential and commercial customers through regulated central distribution systems in two communities, Payson and Page, which utilize pipelines to distribute propane through meters at the customer’s location. Alliant Arizona Propane, L.L.C. is a regulated utility that receives a fixed cost-plus fee for propane sold. Another subsidiary, Alliant Gas L.L.C., serves 28 communities in Texas through regulated central distribution systems pursuant to long-term contracts.

 

Commercial.  Our commercial customers include a mix of industrial customers, hotels, restaurants, churches, warehouses and retail stores. These customers generally use propane for the same purposes as our residential customers

8


 

as well as industrial, oilfield service and agricultural customers, who use propane and refined fuels, such as gasoline and diesel, for heating requirements and as fuel to power over-the-road vehicles, forklifts and stationary engines.

 

Wholesale.  Our wholesale customers are principally governmental agencies and other propane distributors. Our LPG transports, which are large trucks that have capacities ranging from 9,000 to 11,500 gallons, load propane at third-party supply points for delivery directly to tanks located on the property of our wholesale customers.

 

Product supply.  We utilize approximately 20 domestic sources of propane supply, including spot market purchases, with four suppliers providing a substantial portion of our propane. Our propane supply contracts are typically standard agreements with one-year terms and standard commercial provisions.

 

Our supply group manages and sources propane to ensure secure and reliable supply throughout the year. Our LPG transports pick up propane at our supply points, typically refineries, natural gas processing and fractionation plants or LPG storage terminals, for delivery to our customer service centers and our wholesale customers. Supplies of propane from our sources historically have been readily available. During the years ended December 31, 2016 and December 31, 2015, approximately 91% and 88%, respectively, of our propane supply was purchased under supply agreements, which typically have a term of one year, and the remainder was purchased on the spot market.

 

Our supply contracts typically provide for pricing based upon (i) index formulas using the current prices established at a major storage point such as Mont Belvieu, Texas, or Conway, Kansas or (ii) posted prices at the time of delivery. We use a variety of delivery methods, including our LPG transports and common carrier transports, to transport propane from suppliers to our customer service locations as well as various third-party storage facilities and terminals located in strategic areas across our area of operations. In order to manage our cost of propane, we enter into hedging arrangements on substantially all fixed-price contracts.

 

Cylinder Exchange

 

We currently operate the third-largest propane cylinder exchange business in the United States, which consists of the distribution of propane-filled cylinder tanks typically used in barbeque grilling and which covers 46 states in the continental United States through a network of approximately 20,000 distribution locations. We market our business under the brand name Pinnacle Propane Express or under the brand names of our customers. Our customers include grocery stores, pharmacies, convenience stores and hardware retailers which sell or exchange our propane-filled cylinders to consumers for end-use. For the year ended December 31, 2016, we sold or exchanged approximately 4.8 million propane cylinders containing approximately 17.0 million aggregate gallons of propane.

 

We generate revenues in our cylinder exchange business through the sale or exchange of propane-filled cylinders at an agreed upon contract price. For the years ended December 31, 2016 and December 31, 2015, we distributed 50% and 49%, respectively, of our propane volumes in our cylinder exchange business under long-term agreements and the remaining 50% and 51%, respectively, under one-month contracts or on a spot/demand basis. Our long-term cylinder exchange agreements typically permit us to adjust our prices at the time of contract renewal while our month-to-month cylinder exchange agreements allow us to pass our costs on to our customers and thereby minimize our commodity price exposure. In order to manage our cost of propane, we enter into hedging arrangements on a majority of fixed-price sales contracts.

 

Cylinder production cycle.  We own eight production facilities strategically located in Alabama, Illinois, Michigan, Missouri, Nevada, Oregon, South Carolina and Texas. Our production facilities receive inbound pallets of empty 20-pound propane cylinders, which are put through a processing cycle that includes cleaning, inspection, testing, painting, refilling and loading onto relay trucks for delivery to our 51 distribution depot locations. Drivers at our depots receive the full cylinders from our production facilities for delivery to our customer service locations and pick up empty cylinders, which are shipped to our production facilities for processing.

9


 

 

NGL Transportation

 

We own and operate a fleet of approximately 34 hard shell tank trucks that gather and transport NGLs and condensate for producers, gas processing plants, refiners and fractionators located in the Eagle Ford shale and Permian Basin. For the years ended December 31, 2016 and December 31, 2015, our NGL transportation trucks transported approximately 270,626 gallons per day and 344,763 gallons per day, respectively, of NGLs.

 

Competition

 

Crude oil pipelines and storage.  We are subject to competition from other crude oil pipelines, crude oil storage tank operators and crude oil marketing companies that may be able to transport or store crude oil at more favorable prices or transport crude oil greater distance or to more favorable markets. Additionally, we are subject to competition from other providers of crude oil supply and logistics services 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 crude oil pipeline, transportation, gathering and storage companies, including the major integrated oil companies, of widely varying sizes, financial resources and experience. Our competitors in our crude oil pipelines and storage segment include Blueknight Energy Partners, L.P., Enterprise Products Partners L.P., Medallion Midstream LLC, NGL Energy Partners L.P., Occidental Petroleum Corporation, Plains All American Pipeline, L.P., SemGroup Corporation, and Sunoco Logistics.

 

Refined products terminals and storage.  Our refined products terminals located in North Little Rock, Arkansas and Caddo Mills, Texas compete with other terminals on price, versatility and services provided. The competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading activities. In the North Little Rock, Arkansas market, these competitors include Magellan Midstream Partners LP, Delek Logistics Partners LP and HWRT Oil Company, LLC. In Dallas, Texas, the market served by our Caddo Mills, Texas terminal, these competitors include Valero Energy Corporation, Delek Logistics Partners, LP, Magellan Midstream Partners LP and Flint Hills Resources LP.

 

NGL distribution and sales.  In addition to competing with suppliers of other energy sources such as natural gas, our NGL distribution and sales segment competes with other retail propane distributors. The retail propane industry is highly fragmented and competition generally occurs on a local basis with other large full-service multi-state propane marketers, thousands of smaller local independent marketers and farm cooperatives. The large, full-service multi-state marketers we compete with include Ferrellgas, L.P. and AmeriGas Partners, L.P. Each of our customer service centers operates in its own competitive environment because retail marketers tend to be located in close proximity to customers in order to lower the cost of providing service. Our typical customer service center has an effective marketing radius of approximately 50 miles, although in certain areas the marketing radius may be extended by one or more satellite offices. Most of our customer service centers compete with five or more marketers or distributors.

 

Customers

 

We rely on a limited number of customers for a substantial portion of our revenues. Occidental Energy Marketing, Inc., Plains Marketing LP., and BP Products North America each accounted for 10% or more of our total revenue for the year ended December 31, 2016, at approximately 25%, 15%, and 11%, respectively.

 

Seasonality

 

Weather conditions have a significant impact on the demand for our products, particularly propane and refined fuels for heating purposes. Many of our customers rely on propane primarily as a heating source. Accordingly, the volumes sold are directly affected by the severity of the winter weather in our service areas, which can vary substantially from year to year. In any given area, sustained warmer than normal temperatures, as was the case in the heating season over the last three years throughout our operating territories, will tend to result in reduced propane, fuel oil and natural gas consumption, while sustained colder than normal temperatures will tend to result in greater consumption. Meanwhile, our cylinder exchange operations experience higher volumes in the spring and summer, which includes the majority of the grilling season. Sustained periods of poor weather, particularly in the grilling season, can negatively

10


 

affect our cylinder exchange revenues. In addition, poor weather may reduce consumers’ propensity to purchase and use grills and other propane-fueled appliances, thereby reducing demand for cylinder exchange.

 

The volume of propane used by customers of our NGL sales business is higher during the first and fourth calendar quarters and lower during the second and third calendar quarters. Conversely, the volume of propane that we sell through our cylinder exchange business is higher during the second and third calendar quarters and lower in the first and fourth calendar quarters. We believe that our combination of our winter-weighted NGL sales business with our higher-margin, summer-weighted cylinder exchange business reduces overall seasonal fluctuations in volumes and financial results, as our cylinder exchange business is more active in summer months and our NGL sales business is more active in winter months. The impact of seasonality is also mitigated by non-heating related demand throughout the year for propane for oilfield services, fuel for automobiles and for industrial applications, such as forklifts, mowers and generators. For the year ended December 31, 2016, we sold approximately 58.8 million gallons of NGLs in our cylinder exchange and NGL sales businesses, selling approximately 41% in the second and third quarters of 2016 and 59% in the first and fourth quarters of 2016.

 

The volume of product that is handled, transported, throughput or stored in our refined products terminals is directly affected by the level of supply and demand in the wholesale markets served by our terminals. Overall supply of refined products in the wholesale markets is influenced by the absolute prices of the products, the availability of capacity on delivering pipelines and vessels, fluctuating refinery margins and the market’s perception of future product prices. Although demand for gasoline typically peaks during the summer driving season, which extends from April to September, and declines during the fall and winter months, most of the revenues generated at our refined products terminals do not experience any effects from such seasonality. However, the butane blending operations at our refined products terminals are affected by seasonality because of federal regulations governing seasonal gasoline vapor pressure specifications. Accordingly, we expect that the revenues we generate from butane blending will be highest in the winter months and lowest in the summer months.

 

Insurance

 

Our assets may experience physical damage as a result of an accident or natural disaster. These hazards can also 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 casualty, property, and environmental liability insurance policies at varying levels of deductibles and limits that we believe are reasonable and prudent under the circumstances to cover our operations and assets. As we continue to grow, we will continue to evaluate our policy limits and retentions as they relate to the overall cost and scope of our insurance program.

 

Regulation of the Industry and Our Operations

 

Crude Oil

 

We own and operate a fleet of trucks to transport crude oil. We are licensed to perform both intrastate and interstate motor carrier services and are subject to certain safety regulations issued by the Department of Transportation (“DOT”). DOT regulations cover, among other things, driver operations, maintaining log books, truck manifest preparations, the placement of safety placards on trucks and trailer vehicles, drug and alcohol testing, safety of operation and equipment and many other aspects of our trucking operations. Our trucking operations are also subject to regulations and oversight by the Occupational Safety and Health Administration. Additionally, our Silver Dollar Pipeline System is subject to the regulatory oversight of the Texas Railroad Commission and the DOT’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”), whose pipeline safety regulations are described in the section below.

 

Refined Products and NGLs

 

All states in which we operate have adopted fire safety codes that regulate the storage and distribution of propane. In some states, these laws are administered by state agencies, and in others they are administered on a municipal level. We maintain various permits necessary to ensure that our operations comply with applicable regulations. We conduct training programs to help ensure that our operations are in compliance with applicable governmental regulations. With respect to general operations, certain National Fire Protection Association (“NFPA”) Pamphlets, including Nos. 54 and 58 and/or one or more of various international codes (including international fire,

11


 

building and fuel gas codes) establish rules and procedures governing the safe handling of propane, or comparable regulations, which have been adopted by all states in which we operate. In addition, Alliant Arizona Propane, LLC is subject to regulation by the Arizona Corporation Commission and Alliant Gas, LLC is subject to regulation by the Texas Railroad Commission. We believe that the policies and procedures currently in effect at all of our facilities for the handling, storage and distribution of propane are consistent with industry standards and are in compliance in all material respects with applicable environmental, health and safety laws.

 

With respect to the transportation of NGLs, including propane, by truck, we are subject to regulation by PHMSA under the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002, among other statutes. Our propane gas pipeline systems are also subject to regulation by the PHMSA under the Natural Gas Pipeline Safety Act of 1968, which applies to, among other things, a propane gas system that supplies ten or more residential customers or two or more commercial customers from a single source and to a propane gas system any portion of which is located in a public place. The DOT’s pipeline safety regulations require operators of all gas systems to train employees and third-party contractors, establish written procedures to minimize the hazards resulting from gas pipeline emergencies and conduct and keep records of inspections and testing.

 

PHMSA requires pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in high-consequence areas (“HCAs”), defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density. The regulations require operators, including us, to (i) perform ongoing assessments of pipeline integrity, (ii) identify and characterize applicable threats to pipeline segments that could impact a HCA, (iii) improve data collection, integration and analysis, (iv) repair and remediate pipelines as necessary and (v) implement preventive and mitigating actions. In October 2015, PHMSA proposed changes to its pipeline safety regulations that would significantly extend the integrity management requirements to previously exempted pipelines and would impose additional obligations on pipeline operators that are already subject to the integrity management provisions. PHMSA’s proposed rule would also require annual reporting of safety-related conditions and incident reports for all gathering lines and gravity lines, including pipelines that are currently exempt from PHMSA regulations. PHMSA issued a separate regulatory proposal in July 2015 that would impose further pipeline incident prevention and response measures on pipeline operations. While we expect such regulatory changes to allow us time to become compliant with new requirements, once finalized, costs associated with compliance may have a material effect on our operations.

 

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, among other things, increases the maximum civil penalty for pipeline safety violations and directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas. Effective October 25, 2013, PHMSA adopted new rules increasing the maximum administrative civil penalties for violation of the pipeline safety laws and regulations after January 3, 2012 to $200,000 per violation per day, with a maximum of $2,000,000 for a related series of violations. PHMSA also has published an advisory bulletin providing guidance on verification of records related to pipeline maximum operating pressure. We have performed hydrotests of our facilities to confirm the maximum operating pressure and do not expect that any final rulemaking by PHMSA regarding verification of maximum operating pressure would materially affect our operations or revenue.

 

States are largely preempted by federal law from regulating pipeline safety for interstate lines but most states are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include requirements for facility design and management in addition to requirements for pipelines.

 

Management believes that the policies and procedures currently in effect at all of our propane gas systems are consistent with industry standards and are in compliance with applicable law. Due to our ownership and control of these gas utility companies, we are required to notify FERC of our status as a holding company. We filed such a notification of holding company status and we qualified for an exemption from FERC accounting regulations and access to our books and records because we are a holding company solely by reason of our interests in local gas distribution systems.

12


 

 

Environmental Matters

 

General

 

Our operations are subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of certain terminals, storage and transportation facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

 

·

requiring the installation of pollution-control equipment or otherwise restricting the way we operate;

 

·

limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;

 

·

delaying system modification or upgrades during permit reviews;

 

·

requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and

 

·

enjoining the operations of facilities deemed to be in non-compliance with permits issued pursuant to or permit requirements imposed by such environmental laws and regulations.

 

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

 

We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations or cash flows. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion of the material environmental laws and regulations that relate to our business.

 

Hazardous Substances and Waste

 

Our operations are subject to environmental laws and regulations relating to the management and release of solid and hazardous wastes and other substances, including hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. We may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

 

We also generate industrial wastes that are subject to the requirements of the Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. We

13


 

generate little hazardous waste. However, it is possible that wastes currently designated as non-hazardous, which could include wastes currently generated during our operations, will in the future be designated as “hazardous wastes” and, therefore, be subject to more rigorous and costly disposal requirements. Moreover, from time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for non-hazardous wastes, including natural gas wastes. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses or otherwise impose limits or restrictions on our operations or those of our customers.

 

We currently own or lease properties where hydrocarbons are being or have been handled for many years. Although previous operators have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.

 

Oil Pollution Act

 

The Oil Pollution Act (“OPA”) requires the preparation of a Spill Prevention Control and Countermeasure Plan (“SPCC”) for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the United States. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill prevention plan, which details how a facility’s operations comply with the requirements. To be in compliance, the facility’s SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intrafacility piping), inspections and records, security, and training.

 

Air Emissions

 

Our operations are subject to the Clean Air Act (“CAA”) and comparable state and local laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources and also impose various monitoring and reporting requirements. Such laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and criminal enforcement actions. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

 

On August 20, 2010, the EPA published regulations to control emissions of hazardous air pollutants from existing stationary reciprocating internal combustion engines, which was later amended in response to several petitions for reconsideration. The rule requires us to make certain expenditures and undertake certain activities, including the purchase and installation of emissions control equipment (e.g. oxidation catalysts, non-selective catalytic reduction equipment) on our engines following prescribed maintenance practices. In addition, on June 28, 2011, the EPA issued a final rule that establishes new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. This rule requires us to purchase, install, monitor and maintain emissions control equipment.

 

Water Discharges

 

The Clean Water Act (“CWA”) and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into regulated waters and impose requirements affecting our ability to conduct construction

14


 

activities in waters and wetlands. In addition, these laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

 

Endangered Species

 

The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. In addition, as a result of a settlement approved by the United States District Court for the District of Columbia on September 9, 2011, the United States Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the Endangered Species Act. Under the September 9, 2011 settlement, the United States Fish and Wildlife Service is required to review and address the needs of more than 250 species on the candidate list over a 6-year period. The designation of previously unprotected species as threatened or endangered in areas where we or our oil and propane exploration and production customers operate could cause us or our customers to incur increased costs arising from species protection measures and could result in delays or limitations in our customers’ performance of operations, which could reduce demand for our services.

 

Hydraulic Fracturing and Flaring

 

Increased regulation of hydraulic fracturing and flaring of natural gas could result in reductions or delays in crude oil, natural gas and NGL production by our customers, which could materially adversely impact our revenues. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into geographic formations to stimulate hydrocarbon production. Although we do not engage in hydraulic fracturing or flaring activities, an increasing percentage of hydrocarbon production by our customers and suppliers is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process and, due to the lack of natural gas transportation infrastructure in certain areas, sometimes also results in flaring of natural gas produced in association with crude oil production. Hydraulic fracturing and flaring are typically regulated by state oil and gas commissions. Some states, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. In addition, a number of federal agencies, including the EPA and the Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing, and have asserted federal regulatory authority over the process. In December 2016, the EPA released its final report regarding the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances such as water withdrawals for fracturing in times or areas of low water availability, surface spills during the management of fracturing fluids, chemicals or produced water, injection of fracturing fluids into wells with inadequate mechanical integrity, injection of fracturing fluids directly into groundwater resources, discharge of inadequately treated fracturing wastewater to surface waters, and disposal or storage of fracturing wastewater in unlined pits. The results of these studies could lead federal and state governments and agencies to develop and implement additional regulations. Moreover, Congress from time to time has proposed legislation to more closely and uniformly regulate hydraulic fracturing at the federal level. If new laws or regulations that significantly restrict hydraulic fracturing or flaring are adopted, such laws could make it more difficult or costly for our customers to perform fracturing to stimulate production from tight formations. Restrictions on hydraulic fracturing or flaring could also reduce the volume of hydrocarbons that our customers produce, and could thereby adversely affect our revenues and results of operations.

 

Climate Change

 

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases are contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that restrict emissions of GHGs under existing provisions of the Clean Air Act (“CAA”). Accordingly, the EPA adopted construction and operating permit requirements under the Prevention of Significant Deterioration and Title V programs for certain stationary sources. In addition, the EPA has adopted a

15


 

mandatory GHG emissions reporting program that imposes reporting and monitoring requirements on various types of facilities and industries. In November 2010, the EPA expanded its GHG reporting rule to include onshore and offshore oil and natural gas production, processing, transmission, storage, and distribution facilities, requiring reporting of GHG emissions from such facilities on an annual basis. In October 2015, the EPA finalized additional amendments to its greenhouse gas reporting rule, which added pre-reporting requirements for additional facilities. And in May 2016, the EPA finalized additional regulations to reduce emissions of methane and volatile organic compounds from the oil and gas sector.

 

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation in the United States, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. In addition, in December 2015, over 190 countries, including the United States, reached an international agreement to address GHG emissions (“Paris Accord”). The Paris Accord entered into force in November 2016 after over 70 countries, including the United States, ratified or otherwise indicated that it intends to comply with the agreement.

 

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would affect our business, any such future laws and regulations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, oil and gas, which could reduce the demand for crude oil or refined products produced or distributed by our customers, which could in turn reduce revenues we are able to generate by providing services to our customers. Accordingly, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Also increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

 

Anti-terrorism Measures

 

Certain of our bulk storage facilities are also subject to regulation by the Department of Homeland Security (“DHS”). The Department of Homeland Security Appropriation Act of 2007 requires the DHS to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to this act and, on November 20, 2007, further issued an Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. Covered facilities that are determined by DHS to pose a high level of security risk will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements, including those regarding inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information.

 

Trademarks and Tradenames

 

We utilize a variety of trademarks and tradenames which we own or have the right to use, including “JP Energy Partners,” “Pinnacle Propane,” “Pinnacle Propane Express” and “Alliant Arizona Propane.” We regard our trademarks, tradenames and other proprietary rights as valuable assets and believe that they have significant value in the marketing of our products and services.

 

Employees

 

We are managed and operated by the board of directors and executive officers of our general partner. Neither we nor our subsidiaries have any employees. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct our operations. As of February 27, 2017, our general partner and its affiliates

16


 

have approximately 664 employees performing services for our operations. None of these employees are covered by collective bargaining agreements and we believe that our general partner and its affiliates have a satisfactory relationship with their employees.

 

Financial Information about Geographical Areas

 

We have no international activities. For all periods included in this report, all of our revenue was derived from operations conducted in, and all of our assets were located in, the U.S. See Note 16 to our audited consolidated financial statements for additional information.

 

 

Available Information

 

We file or furnish annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any related amendments and supplements thereto with the Securities and Exchange Commission (“SEC”). You may read and copy any materials we file or furnish with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information regarding the public reference room by calling the SEC at 1-800-732-0330. In addition, the SEC maintains a website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

17


 

ITEM 1A. RISK FACTORS  

 

The occurrence of any of the events described in this Risk Factors section and elsewhere in this Annual Report on Form 10-K or in any other of our filings with the SEC could have a material adverse effect on our business, financial position, results of operations and cash flows. In evaluating an investment in any of our securities, you should consider carefully, among other things, the factors and the specific risks set forth below. This Annual Report on Form 10-K contains forward-looking statements that involve risks and uncertainties. See “Cautionary Note Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of the factors that could cause our actual results to differ materially from those projected.

 

Risks Related to Our Business

 

A sustained decrease in demand for, or production of, crude oil, refined products or NGLs in the areas we serve could reduce our revenues.

 

A sustained decrease in demand for crude oil, refined products or NGLs in the areas we serve could reduce our revenues, which could have a material adverse effect on our financial condition, results of operations and cash flows. Factors that could lead to a decrease in market demand for, or production of crude oil, refined products or NGLs include:

 

·

lower demand by consumers for refined products, NGLs or crude oil as a result of adverse economic conditions, an increase in the market price of crude oil, NGLs, gasoline or other refined products, use by consumers of alternative fuels or an increase in the fuel economy of vehicles;

 

·

lower drilling activity in the areas served by our crude oil gathering and transportation business as a result of a decrease in the market price of crude oil, NGLs or natural gas or for other reasons; and

 

·

fluctuations in the demand for crude oil, such as those caused by refinery downtime or shutdowns, lower crack spreads or lower consumer demand for petroleum products.

 

Benchmark crude oil prices declined significantly during 2015 and early 2016. As a result, many of the companies that produce oil and gas reduced capital expenditures for 2016. Such reduced expenditure levels, coupled with the high decline rates for many horizontal wells in shale resource plays, could lead to a substantial decrease in overall North American oil production. Other factors that could adversely impact production include reduced capital market access, increased capital raising costs for producers or adverse governmental or regulatory action. In turn, such developments could lead to reduced throughput on our pipelines, which, depending on the level of production declines, could have a material adverse effect on our business.

 

Certain of our operating costs and expenses are fixed and do not vary with the volumes we transport or redeliver. These costs and expenses may not decrease ratably or at all should we experience a reduction in the volumes we sell, transport or redeliver. As a result, we may experience declines in our margin and profitability if our volumes decrease.

 

We have several short-term contracts, one long-term contract and other contracts that can be canceled on as little as 30 days’ notice and will have to be renegotiated or replaced periodically. Our failure to replace contracts that are canceled or expire on acceptable terms, or at all, could cause our revenues to decline and reduce our ability to make distributions to our unitholders.

 

All of the shell capacity of our crude oil storage tanks in Cushing, Oklahoma is dedicated to one customer pursuant to a long-term contract with an initial expiration in August 2017.  In January 2017, such customer declined to exercise its option to extend the term of such contract by an additional two years.  We may not be able to renegotiate or replace this contract, and the terms of any renegotiated or replacement contract may not be as favorable as the contract it replaces. In addition, many of our contracts in our crude oil pipelines and storage segment either have terms as short as one month or have evergreen provisions and are cancellable on as little as 30 days’ notice. Many of our contracts in our NGL sales and distribution segment have terms as short as one month, and substantially all of our contracts with customers in our refined products terminals and storage segment have evergreen provisions after an initial term of one to

18


 

two years and are cancellable on as little as 60 days’ notice. As these NGL or crude oil contracts expire or if a refined products contract is canceled, we may not be able to extend, renegotiate or replace these contracts and the terms of any renegotiated contracts may not be as favorable as the contracts they replace. In addition, while the majority of the revenue in our crude oil pipelines and storage segment is generated pursuant to long-term contracts, our customers may negotiate for more favorable terms upon any renewal and could set contracts aside in the event of bankruptcy.

 

Our ability to extend or replace contracts could be impacted by a number of factors beyond our control, including competition, the level of supply and demand for crude oil and refined products in our areas of operations, general economic conditions and regulatory developments. To the extent we are unable to renew our contracts, including our crude oil storage contract, on terms that are favorable to us, our revenue and cash flows could decline and our ability to make cash distributions to our unitholders could be materially adversely affected.

 

We face competition in all of our business segments. Competitors that are able to supply our customers with similar services or products at a lower price could reduce our revenues.

 

We are subject to competition from other providers of crude oil transportation and storage services, refined products terminals and storage services and NGL distribution and sales services, including national, regional and local companies engaged in these activities. Some of these competitors are substantially larger than us and may have greater financial resources. Our ability to compete could be affected by many factors, including:

 

·

price competition;

 

·

the perception that another company can provide better service; and

 

·

the availability of alternative supply points, or supply points located closer to the operations of our customers.

 

In addition, our general partner and its affiliates, including JP Development, Lonestar and ArcLight, may engage in competition with us. If we are unable to compete with services offered by our competitors, including possibly our general partner or its affiliates, it could have a material adverse effect on our financial condition, results of operations and cash flows.

 

Because of the natural decline in production from our customers’ existing wells in our areas of operation, we depend, in part, on producers replacing declining production and also on our ability to secure new sources of crude oil. Any decrease in the volumes of crude oil that we transport could adversely affect our business and operating results.

 

The crude oil volumes that support our crude oil pipelines and storage segment depend on the level of oil production from wells on which we rely for throughput or sales and transportation volumes, which may be less than expected and will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput in this segment, we must obtain new sources of crude oil. In our crude oil pipelines and storage segment, the primary factors affecting our ability to obtain non-dedicated sources of crude oil include (i) the level of successful drilling activity and overall crude oil production in our areas of operation, (ii) our ability to compete for volumes from successful new wells and (iii) our ability to compete successfully for volumes from sources connected to other pipelines.

 

We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells on which we rely for throughput or the rate at which production from such wells declines. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things:

 

·

the availability and cost of capital;

 

·

prevailing and projected oil, natural gas and NGL prices;

 

·

basis differentials, transportation costs and other expenses impacting a producer’s net-back price;

 

19


 

·

demand for oil, natural gas and NGLs;

 

·

levels of reserves;

 

·

geological considerations;

 

·

environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and

 

·

the availability of drilling rigs and other costs of production and equipment.

 

Fluctuations in energy prices can also greatly affect the development of oil reserves. Drilling and production activity generally decreases as oil prices decrease. Declines in oil prices could have a negative impact on exploration, development and production activity, and if sustained, could lead to a material decrease in exploration and production activity. Any sustained decline of exploration or production activity in our areas of operation could lead to reduced utilization of our assets.

 

Because of these and other factors, even if oil reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain throughput and our sales and transportation volumes in our crude oil pipelines and storage segment, our revenue and cash flow could be reduced and our ability to make cash distributions to our unitholders could be adversely affected.

 

We do not intend to obtain independent evaluations of oil reserves connected to our Silver Dollar Pipeline System on a regular or ongoing basis; therefore, in the future, volumes of oil on our Silver Dollar Pipeline System could be less than we anticipate.

 

We do not intend to obtain independent evaluations of oil reserves connected to our Silver Dollar Pipeline System on a regular or ongoing basis. Accordingly, we may not have independent estimates of total reserves dedicated to our Silver Dollar Pipeline System or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our Silver Dollar Pipeline System are less than we anticipate and if our customers are unable to secure additional sources of crude oil production it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

 

Our success in our crude oil pipelines business depends, in part, on drilling activity and our ability to attract and maintain customers in a limited number of geographic areas.

 

Our Silver Dollar Pipeline System is located in the Midland Basin and we intend to focus future capital expenditures on developing our business in this area. Due to our focus on production from the Spraberry and Wolfcamp formations in the Midland Basin, an adverse development in oil production from this area would have a greater impact on our financial condition and results of operations than if we spread expenditures more evenly over a wider geographic area. For example, a change in the rules and regulations governing operations in or around the Midland Basin or a continued decline in oil prices could cause producers to reduce or cease drilling or to permanently or temporarily shut-in their production within the area, which could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

 

We may not be able to increase throughput and resulting revenue due to competition and other factors, which could limit our ability to grow our crude oil pipelines and storage segment.

 

Our ability to increase our throughput and resulting revenue is subject to numerous factors beyond our control, including competition from third parties, aggregate crude oil production from the area in close proximity to our pipeline and the extent to which our Silver Dollar Pipeline System has available takeaway capacity. To the extent that we lack available capacity on our Silver Dollar Pipeline System for additional volumes, we may not be able to compete effectively with third-party systems for additional oil production in our areas of operation. In addition, our efforts to attract new customers may be adversely affected by our desire to provide services pursuant to contracts that are

20


 

effectively fee-based. Our potential customers may prefer to obtain services pursuant to other forms of contractual arrangements under which we would be required to assume direct commodity exposure.

 

Our crude oil pipelines and storage operations involve market and regulatory risks.

 

As part of our crude oil pipelines and storage activities, we purchase crude oil at prices determined by prevailing market conditions. Following our purchase of crude oil, we generally resell crude oil at a higher price under a sales contract that is generally comparable in terms to our purchase contract, including any price escalation provisions. The profitability of our crude oil operations may be affected by the following factors:

 

·

our ability to negotiate crude oil purchase and sales agreements in changing markets on a timely basis;

 

·

reluctance of customers to enter into long-term purchase contracts;

 

·

consumers’ willingness to use other fuels instead of the end products in the crude oil supply chain;

 

·

the timing of imbalance or volume discrepancy corrections and their impact on our financial results;

 

·

the ability of our customers to make timely payment; and

 

·

any inability we may have to match purchase and sale of crude oil on comparable terms.

 

We depend on a relatively limited number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, any one or more of these customers could adversely affect our ability to make cash distributions to our unitholders.

 

We rely on a limited number of customers for a substantial portion of our revenues. Occidental Energy Marketing, Inc., Plains Marketing LP., and BP Products North America accounted for 10% or more of our total revenue for the year ended December 31, 2016, at approximately 25%, 15%, and 11%. We may be unable to negotiate extensions or replacements of contracts with our key customers on favorable terms or at all. In addition, these key customers may experience financial problems that 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. Furthermore, 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, results of operations, financial condition and ability to make cash distributions to our unitholders.

 

Midstream capacity constraints and interruptions could impact our operations.

 

We rely on various midstream facilities and systems in connection with our crude oil pipelines and storage operations. Such midstream systems include the systems we operate, as well as systems operated by third parties. When possible, we gain access to midstream systems that provide the most advantageous downstream market prices available to us. Regardless of who operates the midstream systems we rely upon, a portion of the supply in our crude oil pipelines and storage business may be interrupted or shut-in from time to time due to loss of access to plants, pipelines or gathering systems. Such access could be lost due to a number of factors, including, but not limited to, weather conditions, accidents, field labor issues or strikes. Additionally, we and third parties may be subject to constraints that limit our ability to construct, maintain or repair midstream facilities needed in connection with our crude oil pipelines and storage operations. Such interruptions or constraints could negatively impact our profitability.

 

21


 

The risk management policy governing our crude oil supply activities cannot eliminate all risks associated with our crude oil pipelines and storage business, and we cannot ensure that employees of our general partner will fully comply with the policy at all times, both of which could impact our financial and operational results and, in turn, our ability to make cash distributions to our unitholders.

 

We have in place a risk management policy that seeks to establish limits for the exposure in our crude oil pipelines and storage business by requiring that we restrict net open positions through the concurrent purchase and sale of like quantities of crude oil to create transactions intended to lock in positive margins based on the timing, location or quality of the crude oil purchased and delivered. Our risk management policy, however, cannot eliminate all risks. Any event that disrupts our anticipated physical supply of crude oil could create a net open position that would expose us to risk of loss resulting from price changes.

 

Moreover, we are exposed to price movements on products that are not hedged, such as our crude oil linefill, which must be maintained to operate our crude oil pipeline system. We are also exposed to certain price risks related to basis differentials. Basis differentials can be created to the extent that we hold or sell crude oil of a grade or quality at a location or at a time that differs from the specific delivery terms with respect to grade, quality, time or location of the applicable offsetting agreement. If this occurs, we may not be able to use the physical markets to fully hedge our price risk. Our exposure to price risks could impact our operational and financial results and our ability to make cash distributions to our unitholders.

 

We are also subject to the risk that employees of our general partner involved in our crude oil operations may not comply at all times with our risk management policy. We cannot ensure that all violations of our risk management policy, particularly if deception or other intentional misconduct is involved, will be detected prior to our businesses being materially affected.

 

A prolonged decline in index prices at Cushing, relative to other index prices, could reduce the demand for the services we provide in our crude oil storage business.

 

In recent years, a shortfall in takeaway pipeline capacity has at times led to an oversupply of crude oil at Cushing. This was cited as a principal reason for the decline in the West Texas Intermediate Index (“WTI Index”) price used at Cushing relative to other crude oil price indexes, including the Brent Crude Index over the same period. While the WTI Index price has recovered compared to the Brent Crude Index, a renewed decline in the WTI Index price relative to other index prices may reduce demand for transportation of crude oil to, and storage at our facility in, Cushing, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

 

The results of our crude oil storage business could be adversely affected during periods in which the overall forward market for crude oil is flat or backwardated.

 

The results of our crude oil storage business are influenced by the overall forward market for crude oil. A contango market (meaning that the price of crude oil for future delivery is higher than the current price) has a favorable impact on the demand for crude oil storage as it allows a party to simultaneously purchase crude oil at current prices for storage and sell at higher prices for future delivery. Conversely, a flat or backwardated market (meaning that the price of crude oil for future deliveries is lower than current prices) can negatively affect the demand for crude oil storage because there is little incentive to store crude oil when prices offered for future delivery are expected to be lower. Accordingly, a flat or backwardated market can negatively impact the demand for crude oil storage. If the mild contango in the forward market for crude oil does not become more pronounced or if the forward market becomes backwardated while we are attempting to renew our crude oil storage contract or enter into new crude oil storage contracts, it could adversely affect the results in our crude oil storage business.

 

22


 

All of our operations have indirect exposure to changes in commodity prices and some of our operations have direct exposure to commodity price changes.

 

Our operations have limited direct exposure to changes in commodity prices. However, the volumes of crude oil that we transport, store or supply, refined products that we handle and NGLs that we distribute and sell are indirectly affected by commodity prices because many of our customers have direct exposure to commodity prices. If our customers are negatively impacted by changes in commodity prices, they may, among other things, reduce the services they purchase from us. For example, lower crude oil prices could suppress drilling activity, which would reduce demand for our crude oil pipeline and storage services, while higher refined products prices could decrease consumer demand for refined products, which could reduce demand for services we provide at our refined products terminals.

 

In addition, in our refined products terminals and storage segment, we also generate revenue from (i) blending activities, such as ethanol blending and butane blending, and (ii) our vapor recovery units. Our blending activities are subject to direct commodity price exposure. Any significant reduction in the amount of services we provide to our customers because of direct or indirect commodity price exposure and any significant reduction in the refined products that we sell could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

 

We do not operate our crude oil storage facility.

 

TEPPCO Partners L.P., a wholly owned subsidiary of Enterprise Products Partners L.P., serves as the operator of our crude oil storage facility. Under the operating agreement governing TEPPCO’s operation of our facility, we are liable for any losses or claims arising from damage to our property or personal injury claims of our personnel that may result from the actions of the operator, even if such losses or claims result from the operator’s gross negligence or willful misconduct. If disputes arise over operation of our crude oil storage facility, or if our operator fails to provide the services contracted under the agreement, our business, results of operation, financial condition and ability to make cash distributions to our unitholders could be adversely affected.

 

Our refined products terminals are dependent upon their interconnections with terminals and pipelines owned and operated by others.

 

Our refined products terminals are dependent upon their interconnections with other terminals and pipelines owned and operated by third parties to reach end markets and as a significant source of supply. Our North Little Rock terminal is currently supplied by the TEPPCO Pipeline and Magellan’s Little Rock Pipeline, while our Caddo Mills terminal is supplied by the Explorer Pipeline. Reduced or interrupted throughput on these pipelines or outages at terminals with which our refined products terminals share interconnects because of weather or other natural events, testing, line repair, damage, reduced operating pressures or other causes could result in our being unable to deliver refined products to our customers from our terminals or receive products for storage at our terminals, which could adversely affect our cash flows and revenues. In addition, in the event that one of the pipelines depended upon by either of our refined products terminals modifies its tariff to discontinue service for one or more of the products throughput at our terminals, we will have to discontinue selling or secure an alternate supply of such product. This could have a material adverse impact on the throughput volumes and revenues of our refined products terminals and storage segment.

 

The assets in our refined products terminals and storage segment have been in service for several decades.

 

Our refined products terminals and storage assets are generally long-lived assets. Our North Little Rock terminal has been in service for approximately 35 years, and our Caddo Mills terminal has been in service for approximately 30 years. The age and condition of these assets could result in increased maintenance or remediation expenditures. Any significant increase in these expenditures could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

 

23


 

Warm weather in the winter heating season or inclement weather in the summer grilling season could lower demand for propane.

 

Weather conditions have a significant impact on the demand for propane for both heating and agricultural purposes. Many of our customers rely on propane primarily as a heating source during the winter. For the year ended December 31, 2016, we sold approximately 65% of our retail, commercial and wholesale propane volumes during the first and fourth quarters of the year.

 

Actual weather conditions can vary substantially from year to year, significantly affecting our financial performance. For example, in 2016 the average temperature in the seven states in which we operate was 7% warmer than the average temperature of the prior year, as measured by the number of heating degree days reported by the National Oceanic and Atmospheric Administration (“NOAA”).

 

Conversely, our cylinder exchange business experiences higher volumes in the spring and summer, which includes the majority of the grilling season. For the year ended December 31, 2016, we sold approximately 55% of the propane volumes in our cylinder exchange business during the second and third quarters of the year. Sustained periods of poor weather, particularly in the grilling season, can reduce consumers’ propensity to purchase and use grills and other propane-fueled appliances, thereby reducing demand for cylinder exchange and our outdoor products.

 

Sudden and sharp propane cost increases cannot be passed on to customers with contracted pricing arrangements and these contracted pricing arrangements will adversely affect our profit margins if they are not immediately hedged with an offsetting propane purchase commitment.

 

Results of operations related to the retail distribution of propane is primarily based on the cents-per-gallon difference between the sales price we charge our customers and our costs to purchase and deliver propane to our propane distribution locations. We enter into propane sales commitments with a portion of our customers that provide for a contracted price agreement for a specified period of time. The propane cost per gallon is subject to various market conditions and may fluctuate based on changes in demand, supply and other energy commodity prices, such as crude oil and natural gas prices. We employ risk management techniques that attempt to mitigate risks related to the purchasing, storing, transporting and selling of propane. However, sudden and sharp propane cost increases cannot be passed on to customers with contracted pricing arrangements. In addition, even upon the expiration of short-term contracts, we may face competitive or relationship pressure to minimize any price increases. Therefore, these commitments expose us to product price risk and reduced profit margins if those transactions are not immediately hedged with an offsetting propane purchase commitment.

 

High prices for propane can lead to customer conservation and attrition, resulting in reduced demand for our products.

 

Propane prices are subject to fluctuations in response to changes in wholesale prices and other market conditions beyond our control. Therefore, our average retail sales prices can vary significantly within a heating season or from year to year as wholesale prices fluctuate with propane commodity market conditions. During periods of high propane costs our selling prices generally increase. High prices can lead to customer conservation and attrition, resulting in reduced demand for our products.

 

We are dependent on certain principal propane suppliers, which increases the risks from an interruption in supply and transportation.

 

During the year ended December 31, 2016, we purchased 75% of our propane needs from four suppliers. If supplies from these sources were interrupted, the cost of procuring replacement supplies and transporting those supplies from alternative locations might be materially higher and our earnings could be affected. Additionally, in certain areas, based on favorable pricing or the strategic location of certain supply points, a single supplier may provide more than 75% of our propane requirements for that area. Although we have relationships with other suppliers in these areas and have the ability to acquire product elsewhere, in the event of a supply disruption with our primary suppliers in certain regions, we could be forced to purchase propane at a less favorable price and with a higher transportation cost. Accordingly, disruptions in supply in certain areas could also have an adverse impact on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

24


 

 

Energy efficiency, advances in technology and competition from other energy sources may affect demand for propane and increases in propane prices may cause our residential customers to increase their conservation efforts.

 

The national trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, has generally reduced the demand for propane. Propane also competes with other sources of energy such as electricity, natural gas and fuel oil, some of which can be less costly for equivalent energy value. In particular, the gradual expansion of the nation’s natural gas distribution systems has increased the availability of affordable natural gas in rural areas, which historically found propane to be the more cost-effective choice. We cannot predict the effect that future conservation measures, technological advances in heating, conservation, energy generation or other devices or the development of alternative energy sources might have on our operations. As the price of propane increases, some of our customers tend to increase their conservation efforts and thereby decrease their consumption of propane.

 

If the independently owned third-party haulers that we rely upon for the delivery of propane cylinders from our production facilities to certain of our distribution depots do not perform as expected, or if we or these third-party haulers are not able to manage growth effectively, our relationships with our customers may be adversely impacted and our delivery of propane by cylinder exchange may decline.

 

We rely in part on independently owned third-party haulers to deliver cylinders from our production facilities to certain of our distribution depots. Accordingly, our success depends on our ability to maintain and manage relationships with these third-party haulers. We exercise only limited influence over the resources that the third-party haulers devote to the delivery of cylinders. We could experience a loss of consumer or retailer goodwill if our third-party haulers do not adhere to our quality control and service guidelines or fail to ensure the timely delivery of an adequate supply of propane cylinders to certain of our production depots. In addition, the number of retail locations accepting delivery of our propane by cylinder exchange and, subsequently, the retailer’s corresponding sales have historically grown significantly along with the creation of our third-party hauler network. Accordingly, our haulers must be able to adequately service an increasing number of propane cylinder deliveries to our distribution depots so that we can service our retail accounts. If we or our third-party haulers fail to manage the growth of our cylinder exchange operations effectively, our financial results from our delivery of propane by cylinder exchange may be adversely affected.

 

A significant increase in motor fuel costs or other commodity prices may adversely affect our profits.

 

Motor fuel is a significant operating expense for us in connection with the operation of both our crude oil pipelines and storage and NGL distribution and sales segments. Because we do not attempt to hedge motor fuel price risk, a significant increase in motor fuel prices will result in increased transportation costs to us. The price and supply of motor fuel is unpredictable and fluctuates based on events we cannot control, such as geopolitical developments, supply and demand for oil and gas, actions by oil and gas producers, war and unrest in oil-producing countries and regions, regional production patterns and weather concerns. Additionally, we may be affected by increases in the cost of materials used to produce portable propane cylinders. As a result, any increases in these prices may adversely affect our profitability and competitiveness.

 

Our failure or our counterparties’ failure to perform on obligations under commodity derivative and financial derivative contracts could have a material adverse effect on our financial condition, results of operations and cash flows.

 

We enter into hedging arrangements to manage the cost of propane in our cylinder exchange business. We also may from time to time enter into derivative instruments to hedge our exposure to variable interest rates. Volatility in the oil and gas commodities sector for an extended period of time or intense volatility in the near-term could impair our or our counterparties’ ability to meet margin calls, which could cause us or our counterparties to default on commodity and financial derivative contracts. This could have a material adverse effect on our liquidity or our ability to procure product supply at prices reasonable to us or at all.

 

25


 

We are exposed to the credit risks, and certain other risks, of our key customers and other counterparties.

 

In connection with the acquisition of certain of our assets, we have entered into agreements pursuant to which various counterparties have agreed to indemnify us, subject to certain limitations, for (i) certain pre-closing environmental liabilities discovered within specified time periods after the date of the applicable acquisition, (ii) certain matters arising from the pre-closing ownership and operation of assets and (iii) ongoing remediation related to the assets. Our business, results of operations, financial condition and our ability to make cash distributions to our unitholders could be adversely affected in the future if these third parties fail to satisfy an indemnification obligation owed to us.

 

Risks of nonpayment and nonperformance by customers, including producers, are significant considerations in our business.  Although we have credit risk management policies and procedures that are designed to mitigate and limit our exposure in this area, there can be no assurance that we have adequately assessed and managed the creditworthiness of our existing or future counterparties, that there will not be an unanticipated deterioration in their creditworthiness or unexpected instances of nonpayment or nonperformance or that they will try to renegotiate contractual terms, all of which could have an adverse impact on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

 

We may be asked by third parties to provide additional credit support for certain of our crude oil purchases.

 

We rely on letters of credit under our revolving credit facility to purchase crude oil for our supply and logistics business.  Any changes in our credit profile could affect the way crude oil suppliers view our ability to make payments and induce them to require additional support for our obligations, such as letters of credit or other forms of security, which would increase our operating costs and impact our ability to purchase crude oil or capitalize on market opportunities.    Our business, results of operations, financial condition and our ability to make cash distributions to our unitholders could be adversely affected in the future if third parties require additional credit support from us.

 

Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.

 

One of the ways we intend to grow our business is through organic growth projects. The construction of additions or modifications to our existing assets and the construction of new midstream assets involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control. Such expansion projects may also require the expenditure of significant amounts of capital, and financing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Moreover, our revenue may not increase immediately upon the expenditure of funds on a particular project.

 

Our growth strategy requires access to new capital. Tightened capital markets or increased competition for investment opportunities could impair our ability to grow.

 

We continuously consider potential acquisitions and opportunities for organic growth projects. Our ability to fund our capital projects and make acquisitions depends on whether we can access the necessary financing to fund these activities. Any limitations on our access to capital or increase in the cost of that capital could significantly impair our growth strategy. In addition, a variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, changes in key benchmark interest rates, the adoption of new or amended banking or capital market laws or regulations, the re-pricing of market risks and volatility in capital and financial markets. Due to these factors, we cannot be certain that funding for our capital needs will be available from bank credit arrangements or the capital markets on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to implement our growth strategy, enhance our existing business, complete acquisitions and organic growth projects, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.

 

26


 

Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the crude oil and refined products that we gather, store, transport and handle.

 

The crude oil and refined products that we gather, store, transport and handle are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality specifications could reduce our throughput volume, require us to incur additional handling costs or require the expenditure of significant capital. In addition, different product specifications for different markets impact the fungibility of products transported and stored in our refined products terminals and could require the construction of additional facilities to segregate products with different specifications. We may be unable to recover these costs through increased revenues.

 

We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.

 

Our operations are subject to stringent and complex federal, state and local environmental laws and regulations that govern the discharge of materials into the environment or otherwise relate to environmental protection. These laws include federal and state laws that impose obligations related to air emissions, regulate the cleanup of hazardous substances that may be or have been released at properties currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal, regulate discharges from our facilities into state and federal waters, including wetlands, establish strict liability for releases of oil into waters of the United States, impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities, relate to the protection of endangered flora and fauna and impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.

 

These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations or at locations currently or previously owned or operated by us. Joint and several strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of hydrocarbon wastes on, under or from our properties and facilities, some of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the facilities where any wastes we generate are taken for reclamation or disposal, may also 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. Numerous governmental authorities, such as the Environmental Protection Agency (the “EPA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions or costly pollution control measures. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits or regulatory authorizations, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue. More stringent laws and regulations may be adopted in the future. We may not be able to recover all or any of these costs from insurance.

 

Climate change legislation or regulatory initiatives could result in increased operating costs and reduced demand for the services we provide.

 

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases are contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that restrict emissions of GHGs under existing provisions of the Clean Air Act (“CAA”). Accordingly, the EPA adopted pre-construction and operating permit requirements under the Prevention of Significant Deterioration and Title V programs for certain stationary sources. In addition, the EPA has adopted a mandatory GHG emissions reporting program that imposes reporting and monitoring requirements on various types of facilities and industries. In November 2010, the EPA expanded its GHG reporting rule to include onshore and offshore oil and natural gas production, processing, transmission, storage, and distribution facilities, requiring reporting of GHG

27


 

emissions from such facilities on an annual basis. In October 2015, the EPA finalized additional amendments to its greenhouse gas reporting rule, which added reporting requirements for additional facilities. And in May 2016, the EPA finalized additional regulations to reduce emissions of methane and volatile organic compounds from the oil and gas sector.

 

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation in the United States, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. In additions, in December 2015, over 190 countries, including the United States, reached an international agreement to address GHG emissions (“Paris Accord”). The Paris Accord entered into force in November 2016 after over 70 countries, including the United States, ratified or otherwise indicated that it intends to comply with the agreement.

 

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would affect our business, any such future laws and regulations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, oil and gas, which could reduce the demand for crude oil or refined products produced or distributed by our customers, which could in turn reduce revenues we are able to generate by providing services to our customers. Accordingly, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Also, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

 

Our operations are subject to regulation by state and local regulatory authorities. Changes to or additional regulatory measures adopted by such authorities could adversely affect our results of operations and our ability to make cash distributions to unitholders.

 

Services provided by our gathering systems are subject to ratable-take and common purchaser statutes and complaint-based regulation by state regulatory authorities, such as the Texas Railroad Commission.  Ratable-take statutes generally require gatherers to take without undue discrimination crude oil production that may be tendered to the gatherer for handling.  Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer.  Complaint-based regulation allows oil producers to file complaints with state regulators in an effort to resolve grievances relating to access to oil gathering pipelines and rate discrimination.  These statutes could restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or transport oil.

 

Our pipelines do not provide interstate transportation services that are subject to regulation by FERC; however, a change in the jurisdictional characterization of our assets, or a change in policy, could result in increased regulation of our assets, which could materially affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

 

Our crude oil pipeline facilities are not subject to regulation by FERC under the Interstate Commerce Act (the “ICA”) because we do not provide interstate transportation service or have been exempted from FERC regulation.  However, if circumstances change as to the use of our pipelines or FERC’s policies, services provided by our facilities could become subject to regulation by FERC under the ICA.  Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows.  In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the ICA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by the FERC.

 

28


 

We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any related pipeline repair or preventative or remedial measures.

 

The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in “high consequence areas.”  The regulations require operators to:

 

·

Perform ongoing assessments of pipeline integrity;

 

·

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

 

·

Improve data collection, integration, and analysis;

 

·

Repair and remediate the pipeline, as necessary; and

 

·

Implement preventive and mitigation actions.

 

The 2011 Pipeline Safety Act, among other things, increased the maximum civil penalty for pipeline safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas.  Effective October 25, 2013, the PHMSA adopted new rules increasing the maximum administrative civil penalties for violations of the pipeline safety laws and regulations that occur after January 3, 2012 to $200,000 per violation per day, with a maximum of $2,000,000 for a related series of violations. Should our operations fail to comply with DOT or comparable state regulations, we could be subject to substantial penalties and fines.

 

PHMSA has also proposed changes to its pipeline safety regulations that would significantly extend the integrity management requirements to previously exempt pipelines and would impose additional obligations on pipeline operators that are already subject to the integrity management requirements. PHMSA’s proposed rule would also require annual reporting of safety-related conditions and incident reports for all gathering lines and gravity lines, including pipelines that are currently exempt from PHMSA regulations. PHMSA has also issued a separate regulatory proposal that would impose pipeline incident prevention and response measures on pipeline operators.  The adoption of these and other laws or regulations that apply more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operational costs that could be significant. While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our cash flow.

 

Increased regulation of hydraulic fracturing could result in reductions or delays in crude oil, natural gas and NGL production in our areas of operation, which could adversely impact our business and results of operations.

 

Increased regulation of hydraulic fracturing could result in reductions or delays in crude oil, natural gas and NGL production by our customers, which could materially adversely impact our revenues. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into geographic formations to stimulate hydrocarbon production. Although we do not engage in hydraulic fracturing activities, an increasing percentage of hydrocarbon production by our customers and suppliers is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing is typically regulated by state oil and gas commissions. Some states, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. In addition, a number of federal agencies, including the EPA and the Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing, and have asserted federal regulatory authority over the process. In December 2016, the EPA released its final report regarding the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances such as water withdrawals for

29


 

fracturing in times or areas of low water availability, surface spills during the management of fracturing fluids, chemicals or produced water, injection of fracturing fluids into wells with inadequate mechanical integrity, injection of fracturing fluids directly into groundwater resources, discharge of inadequately treated fracturing wastewater to surface waters, and disposal or storage of fracturing wastewater in unlined pits.  The results of these studies could lead federal and state governments and agencies to develop and implement additional regulations. Moreover, Congress from time to time has proposed legislation to more closely and uniformly regulate hydraulic fracturing at the federal level. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for our customers to perform fracturing to stimulate production from tight formations. Restrictions on hydraulic fracturing could also reduce the volume of hydrocarbons that our customers produce, and could thereby adversely affect our revenues and results of operations.

 

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not adequately insured or if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, our operations and financial results could be adversely affected.

 

Our operations are subject to all of the risks and hazards inherent in the crude oil transportation and storage, refined products terminals and storage and NGL distribution and sales industries, including:

 

·

damage to our facilities, vehicles and equipment caused by hurricanes, tornadoes, floods, fires and other natural disasters, acts of terrorism and actions by third parties;

 

·

inadvertent damage from construction, vehicles, farm and utility equipment;

 

·

leaks of crude oil, NGLs and other hydrocarbons or losses of crude oil or NGLs as a result of the malfunction of equipment or facilities;

 

·

ruptures, fires and explosions; and

 

·

other hazards that could also result in personal injury, loss of life, pollution or suspension of operations.

 

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent in our business. For example our business interruption/loss of income insurance provides limited coverage in the event of damage to any of our underground storage tanks. In addition, although we are insured for environmental pollution resulting from certain environmental incidents, we may not be insured against all environmental incidents that might occur, some of which may result in toxic tort claims. If a significant incident occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates.

 

We are subject to litigation risks that could adversely affect our operating results to the extent not covered by insurance.

 

Our operations are subject to all operating hazards and risks normally associated with handling, storing and delivering combustible liquids such as NGLs, refined products and crude oil. We have been, and are likely to continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business, both as a result of these operating hazards and risks and as a result of other aspects of our business. We are self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined amounts above which third-party insurance applies. We cannot guarantee that our insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that these levels of insurance will be available at economical prices, or that all legal matters that arise will be covered by our insurance programs.

 

30


 

Cyber-attacks and threats could have a material adverse effect on our operations.

 

Cyber-attacks 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 liability resulting from a cyber-attack on our assets that may shut down all or part of our business. We currently are implementing our own cyber security programs and protocols; however, we cannot guarantee their effectiveness. A significant cyber-attack could have a material adverse effect on our operations or those of our customers.

 

The risk of terrorism, political unrest and hostilities in the Middle East or other energy producing regions may adversely affect the economy and our business.

 

Terrorist attacks, political unrest and hostilities in the Middle East or other energy producing regions may adversely impact the price and availability of crude oil, refined products and NGLs, as well as our results of operations, our ability to raise capital and our future growth. The impact that the foregoing may have on our industry in general, and on us in particular, is not known at this time. An act of terror could result in disruptions of crude oil and NGL supplies and markets, and our infrastructure or facilities could be direct or indirect targets. Terrorist activity may also hinder our ability to gather and transport crude oil, refined products and NGLs if our means of transportation become damaged as a result of an attack.

 

Derivatives legislation adopted by Congress and rules and regulations promulgated thereunder by the CFTC could have an adverse impact on our ability to hedge risks associated with our business.

 

The Dodd-Frank Act was signed into law in 2010 and regulates derivative and commodity transactions, which include certain instruments used in our risk management activities. The Dodd-Frank Act requires the Commodity Futures Trading Commission (the “CFTC”), the SEC and other regulators to promulgate rules and regulations implementing the legislation. Although the CFTC has finalized most of its regulations under the Dodd-Frank Act, it continues to review and refine its initial rulemakings through additional interpretations and supplemental rulemakings. As a result, it is not possible at this time to predict the ultimate effect of the rules and regulations on our business and while most of the regulations have been adopted, any new regulations or modifications to existing regulations may increase the cost of derivative contracts, limit the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and the regulations thereunder, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. 

 

In December 2016, the CFTC re-proposed new rules that would place federal limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions and finalized a companion rule on aggregation of positions among entities under common ownership or control. If finalized, the position limits rule may have an impact on our ability to hedge our exposure to certain enumerated commodities.

 

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and mandatory trading on designated contract markets or swap execution facilities. The CFTC may designate additional classes of swaps as subject to the mandatory clearing requirement in the future, but has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. The CFTC and prudential banking regulators also adopted mandatory margin requirements on uncleared swaps between swap dealers and certain other counterparties. The margin requirements are currently effective with respect to certain market participants and will be phased in over time with respect to other market participants, based on the level of an entity’s swaps activity. We expect to qualify for and rely upon an end-user exception from the mandatory clearing and trade execution requirements for swaps entered to hedge our commercial risks. We will also qualify for an exception from the uncleared swaps margin requirements. However, the application of the mandatory clearing and trade execution requirements and the uncleared swaps margin requirement to other market participants, such as swap dealers, may adversely affect the cost and availability of the swaps that we use for hedging.

31


 

 

Finally, under the Dodd-Frank Act, the CFTC is also directed generally to prevent price manipulation and fraud in physical commodities markets traded in interstate commerce, including physical energy and other commodities, as well as financial instruments, such as futures, options and swaps. The CFTC has adopted additional anti-market manipulation, anti-fraud and disruptive trading practices regulations that prohibit, among other things, fraud and price manipulation in the physical commodities, futures, options and swaps markets. Should we violate the laws regulating our hedging activities, we could be subject to CFTC enforcement action and material penalties and sanctions.

 

Our ability to operate our business effectively could be impaired if we fail to attract and retain key management personnel and employees.

 

Our ability to operate our business and implement our strategies will depend on our continued ability to attract and retain highly skilled management personnel with energy industry experience. Competition for these persons in the energy industry is intense. Additionally, given our size, we may be at a disadvantage, relative to our larger competitors, in the competition to attract and retain such personnel. We may not be able to continue to employ our senior executives and key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract senior executives and key personnel could have a material adverse effect on our ability to effectively operate our business.

 

The amount of cash we have available for distribution to holders of our common and subordinated units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.

 

The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on our profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net income for financial accounting purposes.

 

Risks Inherent in an Investment in Us

 

Affiliates of our general partner, including Lonestar and ArcLight, may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

 

Neither our partnership agreement nor any other agreement will prohibit affiliates of our general partner, including Lonestar and ArcLight, from owning assets or engaging in businesses that compete directly or indirectly with us. For example, ArcLight Fund V is the majority owner of the general partners of other publicly traded master limited partnerships in the midstream segment of the energy industry, which may compete with us in the future. In addition, Lonestar, ArcLight and other affiliates of our general partner may acquire, construct or dispose of midstream assets in the future without any obligation to offer us the opportunity to purchase any of those assets. As a result, competition from affiliates of our general partner, including Lonestar and ArcLight, could materially adversely impact our results of operations and distributable cash flow.

 

We have no legal obligation to make quarterly cash distributions, and our general partner has considerable discretion to establish cash reserves that would reduce the amount of available cash we distribute to unitholders.

 

Generally, our available cash is comprised of cash on hand at the end of a quarter plus cash on hand resulting from any working capital borrowings made after the end of the quarter less cash reserves established by our general partner. Our general partner has considerable discretion to establish cash reserves, which would result in a reduction in the amount of available cash we distribute to unitholders. Accordingly, there is no guarantee that we will make quarterly cash distributions to our unitholders, and we have no legal obligation to do so.

 

 

 

32


 

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

 

Under certain circumstances, unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution to you 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 an impermissible 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. Transferees of common units are liable for the obligations of the transferor to make contributions to the partnership that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from our partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

 

Tax Risks

 

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for U.S. federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of additional entity-level taxation, then our distributable cash flow to our unitholders would be substantially reduced.

 

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. We have not requested a ruling from the IRS on this matter.  Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for U.S. federal income tax purposes. A change in our business, a change in current law or our failure to satisfy the requirements for partnership treatment under the Internal Revenue Code of 1986, as amended (the “Code”) could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

 

If we were treated as a corporation for U.S. federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35.0%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to you. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Several states have subjected, or are evaluating ways to subject, partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to you. Therefore, if we were treated as a corporation for U.S. federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

 

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 U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of Congress have periodically considered substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships, including the elimination of the qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. In addition, recent regulatory developments surrounding the qualifying income exception may impact our treatment as a partnership for U.S. federal income tax purposes.  The U.S. Department of Treasury and the IRS have published final regulations regarding "qualifying income" under Section 7704(d)(1)(E) of the Code (the “Final Regulations”). The Final Regulations provide a list of industry-specific activities and certain limited support activities that generate qualifying income, which includes the retail sale of propane.  The impact on the Final Regulations of a regulatory freeze imposed by the incoming administration in a January 20, 2017 White House memorandum (the “Regulatory Freeze Memorandum”) is not immediately clear.  Should the Final Regulations be withdrawn or otherwise deemed inapplicable, we may have to rely on other guidance to

33


 

determine if we satisfy the qualifying income exception.  The U.S. Department of Treasury and the IRS have previously issued proposed regulations regarding qualifying income (the “Proposed Regulations”).  Although the Proposed Regulations adopt a narrow interpretation of the activities that generate qualifying income and do not specifically address retail sales of propane, we believe the income that we treat as qualifying income also satisfies the qualifying income requirements under the Proposed Regulations.  Because the Proposed Regulations are not binding on the IRS and the impact of the Regulatory Freeze Memorandum remains unclear, it is possible that future guidance could take a position that is contrary to our interpretation of Section 7704 of the Code.  If such future guidance were to treat any portion of our income we treat as qualifying income as non-qualifying income, we anticipate being able to treat that income as qualifying income for ten years under special transition rules provided in the Proposed Regulations.

 

Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible for us to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units.

 

Our unitholders’ share of our income is taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us.

 

Because a unitholder is treated as a partner to whom we allocate taxable income that could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income is taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

 

If the IRS contests the U.S. federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS 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 U.S. federal income tax purposes. The IRS may adopt positions that differ from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs connected to any contest with the IRS will be borne indirectly by our unitholders (including holders of our subordinated units), because the costs will reduce our distributable cash flow.

 

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.

 

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Generally, we expect to elect to have our general partner and our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, but there can be no assurance that such election will be effective in all circumstances. If we are unable to have our general partner and our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced. These rules are not applicable to us for tax years beginning on or prior to December 31, 2017. 

 

34


 

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

 

If our unitholders sell common units, they will recognize a gain or loss for U.S. federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale of common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.

 

Tax-exempt entities and non-United States persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

 

An investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-United States persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, is unrelated business taxable income and is taxable to them. Distributions to non-United States persons are reduced by withholding taxes at the highest applicable effective tax rate, and non-United States persons are required to file federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-United States person, you should consult a tax advisor before investing in our common units.

 

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

 

Because, among other reasons, we cannot match transferors and transferees of common units, we adopt depreciation and amortization positions that may not conform to all aspects of existing regulations promulgated under the Code by the U.S. Department of Treasury and the IRS (“Treasury Regulations”). A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

 

We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge aspects of our proration method, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

 

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The U.S. Department of Treasury and the IRS have issued Treasury Regulations that permit publicly traded partnerships to use a similar monthly simplifying convention, but these Treasury Regulations do not specifically authorize all aspects of our proration method. If the IRS were to successfully challenge this method, we could be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

 

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

 

Because a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for U.S. federal income

35


 

tax purposes as a partner with respect to those common 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 common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common 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 loaning their common units.

 

We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.

 

In determining the items of income, gain, loss and deduction allocable to our unitholders, in certain circumstances, including when we issue additional units, we must determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

 

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

 

The sale or exchange of 50.0% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for U.S. federal income tax purposes.

 

We will be considered to have technically terminated our partnership for U.S. federal income tax purposes if there is a sale or exchange of 50.0% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether this 50.0% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for U.S. federal income tax purposes, but instead we would be treated as a new partnership for U.S. federal income tax purposes. If treated as a new partnership, we must make new tax elections, including a new election under Section 754 of the Code, and we could be subject to penalties if we are unable to determine that a termination occurred. The IRS administers a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

 

As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

 

In addition to U.S. federal income taxes, our unitholders are likely subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders are likely required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We conduct business in every state in the continental United States. Many of these states currently impose a personal income tax on individuals. As we make acquisitions or expand our business, we may

36


 

control assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all federal, state and local tax returns.

 

Risks Related to the AMID Merger

 

The failure to integrate successfully our business and AMID’s business in the expected timeframe would adversely affect the combined company’s future.

 

The AMID merger involved the integration of two companies that currently operate independently. The success of the AMID merger will depend—in large part—on the ability of the combined company to realize the anticipated benefits, including cost savings, innovation and operational efficiencies, from combining our business with AMID’s business. To realize these anticipated benefits, our business and AMID’s business must be successfully integrated. This integration will be complex and time-consuming. The failure to integrate successfully and to manage successfully the challenges presented by the integration process may result in the combined company not achieving the anticipated benefits of the AMID merger.

 

Potential difficulties that may be encountered in the integration process include the following: 

·

integrating our business and AMID’s business in a manner that permits the combined company to achieve the full benefit of synergies, cost savings and operational efficiencies that are anticipated to result from the AMID merger; 

·

our funds available for operations, future business opportunities and cash distributions to our unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;

·

complexities associated with managing the larger, more complex combined business;

·

complexities associated with integrating the workforces of the two companies;

·

potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the AMID merger, including one-time cash costs to integrate the two companies that may exceed the anticipated range of such one-time cash costs that we and AMID estimated as of the date of execution of the merger agreement; difficulty or inability to refinance the debt of the combined company or comply with the covenants thereof;

·

performance shortfalls at one or both of the companies as a result of the diversion of management’s attention caused by completing the AMID merger and integrating the companies’ operations; and

·

the disruption of, or the loss of momentum in, each company’s ongoing business or inconsistencies in standards, controls, systems, procedures and policies.

 

Any of these difficulties in successfully integrating our business and AMID’s business, or any delays in the integration process, could adversely affect the combined company’s ability to achieve the anticipated benefits of the AMID merger and could adversely affect the combined company’s business, financial results, financial condition and unit price. Even if the combined company is able to integrate our business operations and AMID’s business operations successfully, there can be no assurance that this integration will result in the realization of the full benefits of synergies, cost savings, innovation and operational efficiencies that we and AMID currently expect from this integration or that these benefits will be achieved within the anticipated time frame.

 

The future results of the combined company will suffer if the combined company does not effectively manage its expanded operations.

The size of the business of the combined company has increased significantly beyond the pre-merger size of either our business or AMID’s business. The combined company’s future success depends, in part, upon its ability to manage this expanded business, which will pose substantial challenges for management, including challenges related to the management and monitoring of new operations and associated increased costs and complexity. There can be no assurances that the combined company will be successful or that it will realize the expected operating efficiencies, cost savings, revenue enhancements and other benefits currently anticipated from the AMID merger.

 

 

37


 

ITEM 1B. UNRESOLVED STAFF COMMENTS.

 

None.

 

ITEM 2. PROPERTIES.

 

We believe that we have satisfactory title to all of the assets that we own. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, liens that can be imposed in some jurisdictions for government-initiated action to clean up environmental contamination, liens for current taxes and other burdens and easements, restrictions and other encumbrances to which the underlying properties were subject at the time of acquisition by us, we believe that none of these burdens should materially detract from the value of these properties or from our interest in these properties or should materially interfere with their use in the operation of our business.

 

Our general partner maintains its headquarters in Irving, Texas. We also have regional offices located in Houston, Texas, Tulsa, Oklahoma and Gurnee, Illinois. The current lease of our general partner’s headquarters expires in 2020. We believe that our existing facilities are adequate to meet our needs for the immediate future and that additional facilities will be available on commercially reasonable terms as needed.

 

ITEM 3. LEGAL PROCEEDINGS.

 

The information required for this item is provided in “Note 15 — Commitments and Contingencies” included in our audited consolidated financial statements in Part IV, Item 15 of this report, which is incorporated herein by reference.

 

ITEM 4. MINE SAFETY DISCLOSURES.

 

None.

 

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND

ISSUER PURCHASES OF EQUITY SECURITIES.

 

Market Information

 

Our common limited partner units are traded on the New York Stock Exchange (“NYSE”) under the symbol “JPEP.” Initial trading of our common units commenced on October 2, 2014. The AMID Merger closed on March 8, 2017, and our units will be delisted from the NYSE.

 

38


 

The following table sets forth the quarterly high and low sales prices per common unit, as reported by the NYSE, and the quarterly cash distributions for the indicated period:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Price Range

 

Distribution per

 

Quarterly Period

    

High

    

Low

    

common unit

 

 

 

 

 

 

 

 

 

 

 

 

2016

 

 

 

 

 

 

 

 

 

 

Fourth Quarter

 

$

10.19

 

$

7.16

 

$

0.3250

 

Third Quarter

 

 

10.08

 

 

6.49

 

 

0.3250

 

Second Quarter

 

 

8.96

 

 

4.88

 

 

0.3250

 

First Quarter

 

 

6.17

 

 

1.89

 

 

0.3250

 

2015

 

 

 

 

 

 

 

 

 

 

Fourth Quarter

 

$

8.95

 

$

3.91

 

$

0.3250

 

Third Quarter

 

 

13.94

 

 

5.25

 

 

0.3250

 

Second Quarter

 

 

15.00

 

 

10.75

 

 

0.3250

 

First Quarter

 

 

15.52

 

 

10.75

 

 

0.3250

 

 

 

Holders

 

As of February 27, 2017, the market price for our common units was $8.93 per unit and there were approximately 61 unitholders of record of our common units. There are 76 unitholders of record of our subordinated units. There is no established public trading market for our subordinated units.  The AMID Merger closed on March 8, 2017, at which time all of our common and subordinated units converted into AMID Common Units. See Item 1—Business—AMID Merger Agreement for more details.

 

Securities Authorized for Issuance under Equity Compensation Plans

 

For information regarding our Equity Compensation Plan, please read “Item 12—Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters,” which is incorporated by reference into this Item 5.

 

Recent Sales of Unregistered Securities

 

The information required for this item is provided in “Note 5 – Acquisitions and Dispositions”, included in our audited consolidated financial statements in Part IV, Item 15 of this report.

 

Issuer Purchases of Equity Securities

 

The following table summarizes our repurchases of equity securities during the three months ended December 31, 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Period

 

Total number of units withheld (1)

 

Average price per unit

 

Total number of units purchased as part of publicly announced plans

 

Maximum number of units that may yet be purchased under the plan

 

October 1, 2016 - October 31, 2016

 

 

 —

 

$

 —

 

 

 —

 

 

 —

 

November 1, 2016 - November 30, 2016

 

 

92

 

 

7.63

 

 

 —

 

 

 —

 

December 1, 2016 - December 31, 2016

 

 

609

 

 

8.72

 

 

 —

 

 

 —

 


(1)

Represents units withheld to satisfy employees’ tax withholding obligations in connection with vesting of phantom units during the period.

 

39


 

Unitholder Return Performance Graph

 

The following performance graph and related information shall not be deemed “soliciting material” or “filed” with the SEC, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933, as amended (the “Securities Act”) or the Securities Exchange Act of 1934, as amended (the “Exchange Act”), except to the extent we specifically incorporate it by reference into such filing.

 

The following performance graph compares the cumulative total unitholder return on our common units as traded on the NYSE with the Standard & Poor’s 500 Stock Index (the “S&P 500”), and the Alerian MLP Index (“MLP Index”). It is assumed that (i) $100 was invested in our common units at $19.11 per unit (the closing price at the end of our first trading day), the S&P 500, and the MLP Index on October 2, 2014 (our first day of trading) and (ii) distributions were reinvested on the relevant payment dates. The following performance graph is historical and not necessarily indicative of future price performance.

 

Picture 3

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    

10/2/2014

    

12/31/2014

    

6/30/2015

    

12/31/2015

 

6/30/2016

 

12/31/2016

JP Energy Partners

 

$

100.00

 

$

64.00

 

$

71.29

 

$

28.91

 

$

57.14

 

$

73.24

S&P 500

 

 

100.00

 

 

105.79

 

 

106.01

 

 

105.02

 

 

107.85

 

 

115.04

Alerian MLP Index

 

 

100.00

 

 

87.43

 

 

75.54

 

 

55.15

 

 

60.53

 

 

60.16

 

 

 

ITEM 6. SELECTED FINANCIAL DATA.

 

The table set forth below presents, as of the dates and for the periods indicated, our selected historical consolidated financial and operating data. The historical financial data presented as of December 31, 2016, 2015, 2014, 2013 and 2012 and for the years ended December 31, 2016, 2015, 2014, 2013 and 2012 have been derived from our audited historical consolidated financial statements.

 

The following table should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our audited consolidated financial statements included elsewhere in this document.

 

40


 

The following table presents Adjusted EBITDA and adjusted gross margin, financial measures that are not presented in accordance with generally accepted accounting principles in the United States (“GAAP”). For a discussion of how we derive these measures and a reconciliation of Adjusted EBITDA and adjusted gross margin to their most directly comparable financial measures calculated in accordance with GAAP and a discussion of how we use Adjusted EBITDA and adjusted gross margin to evaluate our operating performance, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Operations — Adjusted EBITDA and adjusted gross margin.”

41


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

 

    

2016

    

2015

    

2014

    

2013

    

2012

 

 

 

($ in thousands, except unit data)

 

Statement of Operations Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total revenue

 

$

493,960

 

$

680,585

 

$

726,154

 

$

390,869

 

$

204,391

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cost of sales, excluding depreciation and amortization

 

 

350,187

 

 

527,476

 

 

605,682

 

$

276,804

 

 

151,478

 

Operating expense

 

 

64,137

 

 

69,377

 

 

65,584

 

 

57,728

 

 

26,292

 

General and administrative

 

 

42,581

 

 

45,383

 

 

46,362

 

 

44,488

 

 

20,785

 

Depreciation and amortization

 

 

47,151

 

 

46,852

 

 

40,230

 

 

30,987

 

 

12,941

 

Goodwill impairment

 

 

15,456

 

 

29,896

 

 

 —

 

 

 —

 

 

 —

 

Loss on disposal of assets, net

 

 

2,569

 

 

909

 

 

1,137

 

 

1,492

 

 

1,142

 

Operating loss

 

 

(28,121)

 

 

(39,308)

 

 

(32,841)

 

 

(20,630)

 

 

(8,247)

 

Other income (expense):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

 

(5,970)

 

 

(5,375)

 

 

(8,981)

 

 

(8,245)

 

 

(3,249)

 

Loss on extinguishment of debt

 

 

 —

 

 

 —

 

 

(1,634)

 

 

 —

 

 

(497)

 

Other income, net

 

 

628

 

 

1,732

 

 

8

 

 

887

 

 

320

 

Loss from continuing operations before income taxes

 

 

(33,463)

 

 

(42,951)

 

 

(43,448)

 

 

(27,988)

 

 

(11,673)

 

Income tax expense

 

 

(521)

 

 

(754)

 

 

(300)

 

 

(208)

 

 

(222)

 

Net loss from continuing operations

 

 

(33,984)

 

 

(43,705)

 

 

(43,748)

 

 

(28,196)

 

 

(11,895)

 

Net income (loss) from discontinued operations (1)

 

 

(539)

 

 

(14,951)

 

 

(9,275)

 

 

13,975

 

 

3,507

 

Net loss

 

$

(34,523)

 

$

(58,656)

 

$

(53,023)

 

$

(14,221)

 

$

(8,388)

 

Net loss attributable to the period from January 1, 2014 to October 1, 2014

 

 

 —

 

 

 —

 

 

34,407

 

 

 

 

 

 

 

Net loss attributable to limited partners

 

$

(34,523)

 

$

(58,656)

 

$

(18,616)

 

 

 

 

 

 

 

Basic and diluted net loss from continuing operations per common unit

 

$

(0.92)

 

$

(1.19)

 

 

(0.52)

 

 

 

 

 

 

 

Basic and diluted net loss per common unit

 

 

(0.93)

 

 

(1.60)

 

 

(0.51)

 

 

 

 

 

 

 

Basic and diluted net loss from continuing operations per subordinated unit

 

 

(0.94)

 

 

(1.20)

 

 

(0.52)

 

 

 

 

 

 

 

Basic and diluted net loss per subordinated unit

 

 

(0.95)

 

 

(1.61)

 

 

(0.51)

 

 

 

 

 

 

 

Distributions declared per common and subordinated unit

 

 

1.300

 

 

1.279

 

 

 —

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Statement of Cash Flows Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash provided by (used in):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating activities

 

$

45,277

 

$

46,041

 

$

30,157

 

$

13,882

 

$

(6,990)

 

Investing activities

 

 

(13,063)

 

 

(79,077)

 

 

(46,153)

 

 

(27,735)

 

 

(292,334)

 

Financing activities

 

 

(31,474)

 

 

31,698

 

 

16,087

 

 

6,988

 

 

304,991

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other Financial Data(2):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Adjusted gross margin

 

$

142,749

 

$

150,291

 

$

133,832

 

$

112,954

 

$

51,326

 

Adjusted EBITDA

 

 

52,325

 

 

46,865

 

 

31,651

 

 

34,284

 

 

14,560

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance Sheet Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

2,727

 

$

1,987

 

$

3,325

 

$

3,234

 

$

10,099

 

Property, plant and equipment, net

 

 

278,150

 

 

291,454

 

 

251,690

 

 

227,068

 

 

181,142

 

Total assets

 

 

674,430

 

 

735,259

 

 

813,173

 

 

843,402

 

 

562,124

 

Total long-term debt (including current maturities)

 

 

177,950

 

 

163,194

 

 

84,508

 

 

184,846

 

 

167,739

 

Total partners’ capital

 

 

434,086

 

 

504,920

 

 

600,680

 

 

533,393

 

 

314,153

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Data(3):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil pipeline throughput (Bbl/d)

 

 

26,662

 

 

28,246

 

 

20,868

 

 

13,738

 

 

 

Crude oil sales (Bbl/d)

 

 

24,425

 

 

40,255

 

 

15,612

 

 

5,107

 

 

7,516

 

Refined products terminals throughput (Bbl/d)

 

 

56,741

 

 

62,075

 

 

63,859

 

 

69,071

 

 

57,143

 

NGL and refined product sales (Mgal/d)

 

 

181

 

 

211

 

 

200

 

 

181

 

 

129

 


(1)

In February 2016, we completed the sale of our crude oil supply and logistics operations in the Midcontinent region of Oklahoma and Kansas. In June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.

 

(2)

Adjusted gross margin and Adjusted EBITDA are financial measures that are not presented in accordance with GAAP. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Operations — Adjusted EBITDA and adjusted gross margin.”

 

42


 

(3)

Represents the average daily throughput volume and the average daily sales volume in our crude oil pipelines and storage segment, the average daily throughput volume in our refined products terminals and storage segment and the average daily sales volume in our NGL distribution and sales segment.

 

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

 

The following discussion and analysis of our financial condition and results of operations is provided as a supplement to, and should be read in conjunction with, our historical consolidated financial statements and the notes thereto included elsewhere in this document.

 

Overview

 

We are a growth-oriented limited partnership formed in May 2010 by members of management and further capitalized by ArcLight to own, operate, develop and acquire a diversified portfolio of midstream energy assets. Our operations consist of three business segments: (i) crude oil pipelines and storage, (ii) refined products terminals and storage and (iii) NGL distribution and sales. Together our businesses provide midstream infrastructure solutions for the growing supply of crude oil, refined products and NGLs in the United States. Our primary business strategy is to focus on:

 

·

owning, operating and developing midstream assets serving two of the most prolific shale plays in the United States, as well as serving key crude oil, refined product and NGL distribution hubs;

 

·

providing midstream infrastructure solutions to users of liquid petroleum products in order to capitalize on changing product flows between producing and consuming markets resulting from the significant growth in hydrocarbon production across the United States; and

 

·

operating one of the largest propane cylinder exchange businesses in the United States and capitalizing on the increase in demand and extended applications for portable propane cylinders.

 

We are focused on growing our business through organic development, acquiring and constructing additional midstream infrastructure assets and by increasing the utilization of our existing assets to gather, transport, store and distribute crude oil, refined products and NGLs.

 

Recent Developments

 

AMID Merger Agreement

 

On October 23, 2016, we and JP Energy GP II LLC entered into LP Merger Agreement with AMID, AMID GP, and Merger Sub.  On March 8, 2017, we were merged with and into Merger Sub, with the Partnership surviving the merger as a wholly owned subsidiary of AMID.

   

At the effective time of the AMID Merger, (i) each of our common and subordinated units issued and outstanding, other than our common and subordinated units held by Affiliated Holders was converted into 0.5775 of an AMID Common Unit and (ii) each of our common and subordinated units issued and outstanding held by the Affiliated Holders was converted into 0.5225 of an AMID Common Unit.

   

In connection with the LP Merger Agreement, on October 23, 2016, AMID GP entered into the GP Merger Agreement with JP Energy GP II LLC and GP Merger Sub. On March 8, 2017, GP Merger Sub merged with and into JP Energy GP II LLC (the “GP Merger” together with the LP Merger, the “Mergers”), with JP Energy GP II LLC surviving the merger as a wholly owned subsidiary of AMID GP. 

 

In connection with the Merger Agreements, Lonestar, the Partnership and JP Energy GP II LLC entered into an Expense Reimbursement Agreement providing that Lonestar will reimburse, or will pay directly on behalf of, the

43


 

Partnership or our general partner the third party reasonable costs and expenses incurred by the Partnership or our general partner in connection with the Mergers, including all reasonable out-of-pocket legal and financial advisory fees, costs and expenses paid or payable to third parties and incurred in connection with the negotiation, execution and performance of the LP Merger Agreement and consummation of the Mergers.

 

Current Year Highlights

 

Disposition of Mid-Continent Crude Oil Supply and Logistics Assets

 

On February 1, 2016, we sold certain trucking and marketing assets in the Mid-Continent area (the “Mid-Continent Business”), in connection with JP Development’s sale of its GSPP pipeline assets to a third party buyer. The sales price related to the Mid-Continent Business was $9.7 million; which included certain adjustments related to inventory and other working capital items. We continue to retain our crude oil storage operations in the Mid-Continent area of Oklahoma.

 

General Trends and Outlook

 

Our business is subject to the key trends discussed below. We have based our expectations on assumptions made by us and on the basis of information currently available to us. To the extent our underlying assumptions about our interpretation of available information prove to be incorrect, our actual results may vary from our expected results.

 

Production

 

Over the past several years, there has been a fundamental shift in crude oil production in the United States towards unconventional resources. According to the EIA, this includes crude oil produced from shale formations, tight gas and coal beds. The emergence of unconventional crude oil plays, such as in the Permian Basin, and advances in technology have been crucial factors that have allowed producers to efficiently extract significant volumes of crude oil from these plays. According to the EIA, the dual application of horizontal drilling and hydraulic fracturing has been the primary driver of increases in shale production. The development of these unconventional sources has offset declines in other, more traditional hydrocarbon supply sources, which has helped meet growing demand and lowered the need for imported crude oil. While crude oil production in the United States has been strong in recent years, the steep decline in crude oil prices has reduced the incentive for producers to expand production. Several major producers have reported that they plan to reduce their capital expansion budgets, and several oilfield services companies have announced reductions in staffing. Various media outlets have reported that, with prices at current levels, it may become uneconomical to drill new crude oil wells in certain basins. If crude oil prices remain low, declines in crude oil production may adversely impact volumes in our crude oil pipelines and storage segment.

 

Production of Refined Products

 

Access to lower cost crude oil supplies has enabled inland refineries to produce refined petroleum products at a cost that allows them to compete over a much broader geographic area with supply from refineries located on the Gulf Coast. This dynamic has significantly diminished the flow of crude oil from the Gulf Coast to the Midwest and increased the flow of refined petroleum products from the Midwest to the Gulf Coast.

 

Supply of Crude Oil Storage Capacity

 

An important factor in determining the value of our crude oil storage capacity and the rates we are able to charge for new contracts or contract renewals is whether a surplus or shortfall of crude oil storage capacity exists relative to the overall demand for crude oil storage services in a given market area. We currently have a long-term contract with the user of our crude oil storage capacity in Cushing, Oklahoma that expires in August 2017.

 

44


 

Seasonality

 

The financial and operational results in our NGL distribution and sales segment are impacted by the seasonal nature of propane demand. The retail propane business is seasonal because of increased demand during the months of November through March primarily for the purpose of providing heating in residential and commercial buildings. As a result, the volume of propane we sell is at its highest during our first and fourth quarters and is directly affected by the severity of the winter. However, our cylinder exchange business sales volumes provide us increased operating profits during our second and third quarters, which reduces overall seasonal fluctuations in the financial and operational results in our cylinder exchange business and our NGL sales business. For the year ended December 31, 2016, we sold approximately 59% of the propane volumes in our cylinder exchange and NGL sales businesses during the first and fourth quarters of the year.

 

The butane blending operations at our refined products terminals are affected by seasonality because of federal regulations governing seasonal gasoline vapor pressure specifications. Accordingly, we expect that the revenues we generate from butane blending will be highest in the winter months and lowest in the summer months.

 

Weather

 

Weather conditions have a significant impact on the demand for propane for both heating and agricultural purposes. Accordingly, the volume of propane used by our customers for this purpose is affected by the severity of winter weather in the regions we serve and can vary substantially from year to year while general economic conditions in the United States and the wholesale price of propane can have a significant impact on the correlation between weather and customer demand. For the year ended December 31, 2016, the weather in Texas, Oklahoma, New Mexico, Arizona, Arkansas, Kansas and Missouri, the seven states in which our NGL sales business operates, was 7% warmer than the average temperature of the prior year as measured by the number of heating degree days reported by the NOAA. If these seven states were to experience a cooling trend, we could expect demand for propane to increase, which could lead to greater sales and income.

 

Commodity Prices

 

We are exposed to volatility in crude oil, refined products and NGL commodity prices. We manage such exposure through the structure of our sales and supply contracts and through a managed hedging program. Our risk management policy permits the use of financial instruments to reduce the exposure to changes in commodity prices that occur in the normal course of business but prohibits the use of financial instruments for trading or to speculate on future changes in commodity prices.

 

In our crude oil pipelines and storage segment, we purchase and take title to a portion of the crude oil that we sell, which exposes us to changes in the price of crude oil in our sales markets. We manage this commodity price risk by limiting our net open positions and through the concurrent purchase and sale of like quantities of crude oil that are intended to lock in positive margins based on the timing, location or quality of the crude oil purchased and delivered. In our refined products terminals and storage segment, we sell excess volumes of refined products and our gross margin is impacted by changes in the market prices for these sales. We may execute forward sales contracts or financial swaps to reduce the risk of commodity price changes in this segment. In our NGL distribution and sales business, we are generally able to pass through the cost of products through sales prices to our customers. To the extent we enter into fixed price product sales contracts in this business, we generally hedge our supply costs using financial swaps. In our cylinder-exchange business, we sell approximately half of our volumes pursuant to contracts of generally two to three years in duration, which allow us to re-negotiate prices at the time of contract renewal, and we sell the remaining volumes on demand or under month-to-month contracts and generally adjust prices on these contracts on an annual basis. We hedge a majority of the forecasted volumes under our fixed-price contracts using financial swaps, and we may also use financial swaps to manage commodity price risk on our month-to-month contracts. In our NGL transportation business, we do not take title to the products we transport and, therefore, have no direct commodity price exposure to the price of volumes transported.

 

45


 

Average daily prices for NYMEX West Texas Intermediate crude oil ranged from a high of $54.01 per barrel to a low of $26.19 per barrel from January 1, 2016 through December 31, 2016. Fluctuations in energy prices, like the recent declines in commodity prices of crude oil, can also greatly affect the development of new crude oil reserves. Further declines in commodity prices of crude oil could have a negative impact on exploration, development and production activity, and, if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our assets. We are unable to predict future potential movements in the market price for crude oil and, thus, cannot predict the ultimate impact of commodity prices on our operations. If commodity prices revert to the lower trend experienced in 2015 and early 2016, this could lead to reduced profitability and may result in future potential impairments of long-lived assets, goodwill or intangible assets. We performed our annual impairment assessment of goodwill in the fourth quarter of 2016, which resulted in an impairment charge of $15.5 million. Due to the market conditions discussed above, there is an increased likelihood of incurring additional future goodwill impairments, which may be material.

 

Interest Rates

 

The credit markets experienced near-record low interest rates in recent years. As the overall economy strengthens, it is likely that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. If this occurs, interest rates on floating rate credit facilities and future offerings in the debt capital markets could be higher than current levels, causing our current or prospective financing costs to increase accordingly. We mitigate some of our exposure to variable interest rate risk by entering into interest rate swap agreements related to a portion of our variable-rate debt. These agreements change a portion of our variable-rate cash flow exposure on the debt obligations to fixed cash flows.

 

How We Evaluate Our Operations

 

Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements for consistency and trend analysis. These metrics include volumes, revenues, cost of sales, excluding depreciation and amortization, operating expenses, Adjusted EBITDA and distributable cash flow.

 

·

Volumes and revenues.

 

·

Crude oil pipelines and storage.  The amount of revenue we generate from our crude oil pipelines business depends primarily on throughput volumes. We generate a substantial majority of our crude oil pipeline revenues through long-term contracts containing acreage dedications or minimum volume commitments. Throughput volumes on our pipeline system are affected primarily by the supply of crude oil in the market served by our assets. The revenue generated from our crude oil supply and logistics business depends on the volume of crude oil we purchase from producers, aggregators and traders and then sell to producers, traders and refiners as well as the volumes of crude oil that we gather and transport. The volume of our crude oil supply and logistics activities and the volumes transported by our crude oil gathering and transportation trucks are affected by the supply of crude oil in the markets served directly or indirectly by our assets. Accordingly, we actively monitor producer activity in the areas served by our crude oil supply and logistics business and other producing areas in the United States to compete for volumes from crude oil producers. Revenues in this business are also impacted by changes in the market price of commodities that we pass through to our customers. The volume of crude oil stored at our crude oil storage facility in Cushing, Oklahoma has no impact on the revenue generated by our crude oil storage business because we receive a fixed monthly fee per barrel of shell capacity that is not contingent on the usage of our storage tanks.

·

Refined products terminals and storage.  The amount of revenue we generate from our refined products terminals depends primarily on the volume of refined products that we handle. These volumes are affected primarily by the supply of and demand for refined products in the markets served directly or indirectly by our refined products terminals.

 

·

NGL distribution and sales.  The amount of revenue we generate from our NGL distribution and sales segment depends on the gallons of NGLs we sell through our cylinder exchange and NGL sales

46


 

businesses. In addition, our NGL transportation operations generate revenue based on the number of gallons of NGLs we gather and the distance we transport those gallons for our customers. Revenues in this segment are also impacted by changes in the market price of commodities that we pass through to our customers.

 

·

Cost of sales, excluding depreciation and amortization.  Our management attempts to minimize cost of sales, excluding depreciation and amortization, in order to enhance the profitability of our operations. Cost of sales, excluding depreciation and amortization, includes the costs to purchase the product and any costs incurred to transport the product to the point of sale and to store the product until it is sold. We seek to minimize cost of sales, excluding depreciation and amortization, by attempting to acquire the products which we use in each of our segments at times and prices which are most optimal based on our knowledge of the industry and the regions in which we operate.

 

·

Operating expenses.  Our management seeks to maximize the profitability of our operations in part by minimizing operating expenses. These expenses are comprised of payroll, wages and benefits, utility costs, fleet costs, repair and maintenance costs, rent, fuel, insurance premiums, taxes and other operating costs, some of which are independent of the volumes we handle.

 

·

Adjusted EBITDA and adjusted gross margin.  Our management uses Adjusted EBITDA and adjusted gross margin to analyze our performance. We define Adjusted EBITDA as net income (loss) plus (minus) interest expense (income), income tax expense (benefit), depreciation and amortization expense, asset impairments, (gains) losses on asset sales, certain non-cash charges such as non-cash equity compensation, non-cash vacation expense, non-cash (gains) losses on commodity derivative contracts (total (gain) loss on commodity derivatives less net cash flow associated with commodity derivatives settled during the period), corporate overhead support from our general partner (expenses incurred by us but absorbed by our general partner and not passed through to us) and selected (gains) charges and transaction costs that are unusual or non-recurring. We define adjusted gross margin as total revenues minus cost of sales, excluding depreciation and amortization, and certain non-cash charges such as non-cash vacation expense and non-cash gains (losses) on derivative contracts (total gain (losses) on commodity derivatives less net cash flow associated with commodity derivatives settled during the period).

 

Adjusted EBITDA and adjusted gross margin are supplemental, non-GAAP financial measures used by management and by external users of our financial statements, such as investors and commercial banks, to assess:

 

·

our operating performance as compared to those of other companies in the midstream sector, without regard to financing methods, historical cost basis or capital structure;

 

·

the ability of our assets to generate sufficient cash flow to make distributions to our unitholders; and

 

·

the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

 

Adjusted EBITDA and adjusted gross margin are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and adjusted gross margin are net income (loss) and operating income (loss), respectively. Adjusted EBITDA and adjusted gross margin should not be considered as an alternative to net income (loss), operating income (loss) or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and adjusted gross margin exclude some, but not all, items that affect net income (loss) and operating income (loss) and these measures may vary among other companies. As a result, Adjusted EBITDA and adjusted gross margin may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

 

47


 

Set forth below are reconciliations of Adjusted EBITDA and adjusted gross margin to their most directly comparable financial measure calculated in accordance with GAAP.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

 

 

    

2016

    

2015

    

2014

    

2013

    

2012

 

 

 

 

(in thousands)

 

 

Reconciliation of Adjusted EBITDA to net loss

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net loss

 

$

(34,523)

 

$

(58,656)

 

$

(53,023)

 

$

(14,221)

 

$

(8,388)

 

 

Depreciation and amortization

 

 

47,151

 

 

46,852

 

 

40,230

 

 

30,987

 

 

12,941

 

 

Goodwill impairment

 

 

15,456

 

 

29,896

 

 

 —

 

 

 —

 

 

 —

 

 

Interest expense

 

 

5,970

 

 

5,375

 

 

8,981

 

 

8,245

 

 

3,249

 

 

Loss on extinguishment of debt

 

 

 —

 

 

 —

 

 

1,634

 

 

 

 

497

 

 

Income tax expense

 

 

521

 

 

754

 

 

300

 

 

208

 

 

222

 

 

Loss on disposal of assets, net

 

 

2,569

 

 

909

 

 

1,137

 

 

1,492

 

 

1,142

 

 

Unit-based compensation

 

 

2,024

 

 

1,217