10-K 1 vlpform10-kx12312017.htm 10-K Document
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
OR
o
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 1-36232
VALERO ENERGY PARTNERS LP
(Exact name of registrant as specified in its charter)
Delaware
90-1006559
(State or other jurisdiction of
(I.R.S. Employer
incorporation or organization)
Identification No.)
One Valero Way
 
San Antonio, Texas
78249
(Address of principal executive offices)
(Zip Code)
 
Registrant’s telephone number, including area code: (210) 345-2000
 
Securities registered pursuant to Section 12(b) of the Act: Common units representing limited partnership interests listed on the 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 þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes o No þ
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 þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ Accelerated filer o Non-accelerated filer o
Smaller reporting company o Emerging growth company o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
The aggregate market value of the voting and non-voting common units held by non-affiliates was approximately $1.0 billion based on the last sales price quoted as of June 30, 2017 on the New York Stock Exchange, the last business day of the registrant’s most recently completed second fiscal quarter.
The registrant had 69,262,070 common units and 1,413,511 general partner units outstanding at January 31, 2018.
DOCUMENTS INCORPORATED BY REFERENCE
None




CONTENTS
 
 
PAGE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 




i


References in this report to “Partnership,” “we,” “our,” “us,” or similar terms refer to Valero Energy Partners LP, one or more of its subsidiaries, or all of them taken as a whole. References to our “general partner” refer to Valero Energy Partners GP LLC, an indirect wholly owned subsidiary of Valero Energy Corporation. References in this report to “Valero” refer collectively to Valero Energy Corporation and its subsidiaries, other than Valero Energy Partners LP, any of its subsidiaries, or its general partner.
PART I
ITEMS 1 & 2. BUSINESS and PROPERTIES
BUSINESS
Overview
Valero Energy Partners LP is a Delaware limited partnership formed in July 2013 by Valero. On December 16, 2013, we completed our initial public offering (IPO) of common units representing limited partner interests. Our common units are listed on the New York Stock Exchange (NYSE) under the symbol “VLP.” Our offices are located at One Valero Way, San Antonio, Texas 78249.
Our website address is www.valeroenergypartners.com. Information on our website is not part of this report. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed with or furnished to the United States (U.S.) Securities and Exchange Commission (SEC) are available, free of charge, on our website (under Investor Relations > Financial Information > SEC Filings), soon after we file or furnish such information.
We are a master limited partnership formed to own, operate, develop, and acquire crude oil and refined petroleum products pipelines, terminals, and other logistics assets. We generate operating revenues by providing fee-based transportation and terminaling services to transport and store crude oil and refined petroleum products using our pipelines and terminals.
Our assets consist of certain crude oil and refined petroleum products pipelines, terminals, and other logistics assets. During 2017, we acquired the Red River crude system, the Parkway pipeline, and the Port Arthur terminal. See Note 2 of Notes to Consolidated Financial Statements for discussion of our acquisitions. As of December 31, 2017, our assets include crude oil and refined petroleum products pipeline and terminal systems in the U.S. Gulf Coast and U.S. Mid-Continent regions that are integral to the operations of ten of Valero’s refineries.
We expect Valero to serve as a critical source of our future growth by providing us opportunities to purchase additional logistics assets that it currently owns or may acquire or develop in the future. Our agreements with Valero are discussed more fully in other sections of this report.




1


Organizational Structure
The following simplified diagram depicts our organizational structure as of January 31, 2018.
vlporgchart201710k01312018.jpg
Segments
Our operations consist of one reportable segment and are conducted solely in the U.S. See Part II, Item 8., “Financial Statements and Supplementary Data” for financial information about our operations and assets.



2


Our Assets and Operations
The following sections describe our assets and the related services that we provide.
Ardmore Logistics System
Our Ardmore logistics system includes our 40 percent undivided interest in the Hewitt Segment of the Red River crude oil pipeline and our Wynnewood products system.
Hewitt Segment of Red River Pipeline (Red River crude system). We own a 40 percent undivided interest in the Hewitt segment of the Plains Red River pipeline. The Hewitt segment is an approximately 138-mile, 16-inch crude oil pipeline with a capacity of 150,000 barrels per day (of which 60,000 barrels per day of capacity are allocable to our 40 percent undivided interest). It originates at Plains Marketing, L.P.’s Cushing, Oklahoma terminal and ends at Hewitt Station in Hewitt, Oklahoma. The pipeline supports Valero’s Ardmore Refinery with a connection from Hewitt Station to Wasson Station. We also own a 40 percent undivided interest in two 150,000 shell barrel capacity tanks located at Hewitt Station, and we lease the remaining 60 percent capacity from the joint owner.
Wynnewood Products System. The Wynnewood products system is the primary distribution outlet for refined petroleum products from Valero’s Ardmore Refinery. The system consists of a 30-mile, 12-inch refined petroleum products pipeline with 90,000 barrels per day of capacity and two tanks with a total of 180,000 barrels of storage capacity. The system connects Valero’s Ardmore Refinery to the Magellan Central refined products pipeline system.
Corpus Christi Logistics System
Our Corpus Christi logistics system includes the operations of our Corpus Christi East and West terminals, which are crude oil, intermediates, and refined products terminals in Corpus Christi, Texas.
Corpus Christi East Terminal. Our Corpus Christi East terminal supports Valero’s Corpus Christi East Refinery. The Corpus Christi East terminal is located on the Corpus Christi ship channel and has storage tanks with 6.2 million barrels of storage capacity.
Corpus Christi West Terminal. Our Corpus Christi West terminal supports Valero’s Corpus Christi West Refinery. The Corpus Christi West terminal is located on the Corpus Christi ship channel and has storage tanks with 3.8 million barrels of storage capacity.
Our Corpus Christi terminals are connected via pipeline. The terminals can receive crude oil via the refineries’ docks, the Eagle Ford Pipeline LLC pipeline, the NuStar North Beach terminal, and NuStar’s Eagle Ford pipelines. The terminals can distribute products across their docks and through NuStar’s South Texas pipeline network.
Houston Logistics System
Our Houston logistics system includes the operations of our Houston terminal, which is a crude oil, intermediates, and refined petroleum products terminal that supports Valero’s Houston Refinery. The terminal is located on the Houston ship channel and has storage tanks with 3.6 million barrels of storage capacity. The terminal receives waterborne crude oil via the refinery’s docks and a connection to Houston Fuel Oil Terminal Company (HFOTCO), and the terminal receives pipeline crude oil through the Magellan and Seaway systems. The terminal can distribute refined petroleum products across the refinery’s docks and into the Magellan South pipeline system. Also, the terminal can access the Colonial, TEPPCO, and Explorer pipeline systems via the Kinder Morgan Pasadena terminal.



3


McKee Logistics System
Our McKee logistics system is a crude oil and refined petroleum products pipeline and terminal system supporting Valero’s McKee Refinery. Our McKee logistics system includes our McKee crude system, McKee products system, and the McKee terminal.
McKee Crude System. Our McKee crude system supplies crude oil to Valero’s McKee Refinery. The system has a throughput capacity of approximately 72,000 barrels per day and consists of 145 miles of pipelines located in the Texas panhandle, 20 crude oil truck unloading sites with lease automatic custody transfer units, and approximately 240,000 barrels of storage capacity.
McKee Products System. Our McKee products system transports refined petroleum products from Valero’s McKee Refinery to our refined petroleum products terminal in El Paso, Texas and on to Kinder Morgan’s SFPP system for marketing in the southwest U.S. We own a 33⅓ percent undivided interest in the system. Capacity on the McKee products system is allocated between the other interest owner and us according to our respective ownership interests. Our McKee products system comprises the following assets:
McKee to El Paso Pipeline. Our McKee to El Paso pipeline consists of 408 miles of 10-inch pipeline that delivers diesel and gasoline produced at Valero’s McKee Refinery to our El Paso terminal. The pipeline has a total capacity of 63,000 barrels per day (of which 21,000 barrels per day of capacity are allocable to our 33⅓ percent undivided interest).
SFPP Pipeline Connection. Our SFPP pipeline connection consists of 12 miles of 16- and 8-inch pipelines that deliver diesel and gasoline from our El Paso terminal to Kinder Morgan’s SFPP system. The SFPP pipeline connection has 98,400 barrels per day of capacity (of which 33,000 barrels per day of capacity are allocable to our 33⅓ percent undivided interest).
El Paso Terminal. Our El Paso terminal is located on 117 acres and consists of 10 storage tanks with 499,000 barrels of storage capacity (of which 166,000 barrels of capacity are allocable to our 33⅓ percent undivided interest). The El Paso terminal receives refined petroleum products delivered to the terminal through our McKee to El Paso pipeline and delivers refined petroleum products to our four-bay truck rack at our El Paso terminal and to Kinder Morgan’s SFPP system through our SFPP pipeline connection. Our El Paso terminal truck rack has 30,000 barrels per day of capacity (of which 10,000 barrels per day of capacity are allocable to our 33⅓ percent undivided interest).
McKee Terminal. Our McKee terminal is a crude oil, intermediates, and refined petroleum products terminal that supports Valero’s McKee Refinery in Sunray, Texas. Our McKee terminal has storage tanks with 4.4 million barrels of storage capacity. The terminal receives pipeline crude oil from the Wichita Falls, Dixon, and Hooker pipelines owned by NuStar Logistics, L.P. (NuStar) in addition to our McKee crude system. The terminal can distribute refined petroleum products through its truck racks, rail rack, and several pipelines including NuStar’s Southlake, Amarillo, and Colorado Springs pipelines, the Phillips/NuStar Denver pipeline, and our McKee to El Paso pipeline.
Memphis Logistics System
Our Memphis logistics system includes our Collierville crude system and our Memphis products system.
Collierville Crude System. Our Collierville crude system delivers crude oil from the Capline and Diamond pipelines to Valero’s Memphis Refinery. Our Collierville crude system comprises the following assets:
Collierville Pipeline System. Our Collierville pipeline system consists of 52 miles of 10- to 20-inch pipelines with 210,000 barrels per day of capacity that deliver crude oil to Valero’s Memphis Refinery. We lease an approximate 13 mile portion of this pipeline, which runs from the Mississippi



4


state line to Valero’s Memphis Refinery, from Memphis Light, Gas and Water (MLGW). The initial term of the lease, along with renewal periods available at our option, extend through 2046.
Collierville Terminal. Our Collierville terminal is located in Byhalia, Mississippi on 60 acres. The facility consists of three storage tanks with 975,000 barrels of storage capacity. The Collierville terminal receives crude oil delivered to the terminal through the Capline pipeline.
StJames Crude Tank. We own a 330,000 barrel crude oil storage tank in St. James, Louisiana located on land we lease from Marathon Pipe Line LLC. The tank can be used to aggregate crude oil volumes to batch deliveries through the Capline pipeline to our Collierville terminal.
Memphis Products System. Our Memphis products system is the primary outlet for refined petroleum products produced at Valero’s Memphis Refinery. Distribution of these products occurs through our Memphis truck rack and our terminal in West Memphis, Arkansas, for further distribution via truck and barge to marketing outlets along the central Mississippi River, to Exxon’s Memphis refined petroleum products terminal, and to the Memphis International Airport. Our Memphis products system comprises the following assets:
Memphis Airport Pipeline System. Our Memphis Airport pipeline system consists of a nine-mile, six-inch pipeline that delivers jet fuel produced at Valero’s Memphis Refinery to the Swissport Fueling, Inc. terminal located at the Memphis International Airport and a two-mile, six-inch pipeline that delivers jet fuel from Valero’s Memphis Refinery to the FedEx jet fuel terminal located at the Memphis International Airport. The Memphis Airport pipeline system has a total capacity of 20,000 barrels per day. Both six-inch pipelines are owned by MLGW and we have an agreement with MLGW under which we are the exclusive operator of both pipelines. Our agreement with MLGW automatically renews and MLGW does not have a right to terminate.
Shorthorn Pipeline System. Our Shorthorn pipeline system consists of seven miles of 14-inch pipeline that delivers diesel and gasoline produced at Valero’s Memphis Refinery to our West Memphis terminal and two miles of 12-inch pipeline that delivers diesel and gasoline from our West Memphis terminal and Valero’s Memphis Refinery to Exxon’s Memphis refined petroleum products terminal. We lease the 14-inch pipeline from MLGW. The initial term of the lease, along with renewal periods available at our option, extend through 2046. The Shorthorn pipeline system has a total capacity of 120,000 barrels per day.
Memphis Truck Rack. Our Memphis truck rack is located on five acres of land adjacent to Valero’s Memphis Refinery. The facility consists of a high-capacity seven-bay truck rack and five biodiesel storage tanks with 8,000 barrels of storage capacity. The truck rack has a capacity of 110,000 barrels per day.
West Memphis Terminal. Our West Memphis terminal is located in West Memphis, Arkansas on 75 acres. The facility consists of 18 storage tanks with over one million barrels of storage capacity, a truck rack, and a barge dock on the Mississippi River. Our West Memphis terminal receives refined petroleum products through our Shorthorn pipeline system and through a biodiesel truck unloading rack located at the terminal. The terminal delivers refined petroleum products to the five-bay, 50,000 barrels per day truck rack at the terminal, our two-berth, 4,000 barrels per hour barge dock on the Mississippi River, and our Shorthorn pipeline system for deliveries to Exxon’s Memphis terminal.
Meraux Logistics System
Our Meraux logistics system includes the operations of our Meraux terminal, which is a crude oil, intermediates, and refined petroleum products terminal that supports Valero’s Meraux Refinery located in



5


Meraux, Louisiana. The terminal is located southeast of New Orleans along the Mississippi River and has storage tanks with 3.9 million barrels of storage capacity. The terminal can receive crude oil via the refinery’s docks, from LOOP, and from the CAM pipeline system. The terminal can distribute refined petroleum products across the refinery’s truck rack, docks, and into the T&M Terminal Company pipeline, which connects to the Plantation and Colonial pipelines.
Port Arthur Logistics System
Our Port Arthur logistics system includes our Lucas crude system, Port Arthur products system, and the Port Arthur terminal.
Lucas Crude System. Our Lucas crude system supports diverse and flexible crude oil supply options for Valero’s Port Arthur Refinery. Our Lucas crude system comprises the following assets:
Lucas Pipeline. Our Lucas pipeline is a 12-mile, 30-inch pipeline with 400,000 barrels per day of capacity that delivers crude oil from our Lucas terminal to Valero’s Port Arthur Refinery.
Nederland Pipeline. Our Nederland pipeline is a five-mile, 32-inch pipeline with 600,000 barrels per day of capacity that delivers crude oil to our Lucas terminal from the Sunoco Logistics Nederland marine terminal.
Lucas Terminal. Our Lucas terminal is located 12 miles from Valero’s Port Arthur Refinery on 495 acres. The facility consists of seven storage tanks with an aggregate of 1.9 million barrels of storage capacity. The Lucas terminal receives crude oil through our Nederland pipeline, which connects to the Sunoco Logistics Partners L.P. marine terminal in Nederland, Texas, as well as through connections to the Cameron Highway crude oil pipeline and Enterprise’s Beaumont marine terminal. The terminal connects to TransCanada Cushing MarketLink pipeline via our TransCanada connection and to the Seaway crude oil pipeline via our Seaway connection. The Lucas terminal delivers crude oil to Valero’s Port Arthur Refinery through our Lucas pipeline.
Seaway Connection. Our Seaway connection has 750,000 barrels per day of capacity and connects our Lucas terminal to the Seaway crude oil pipeline.
TransCanada Connection. Our TransCanada connection has 400,000 barrels per day of capacity and connects our Lucas terminal to TransCanada’s Cushing MarketLink pipeline.
Port Arthur Products System. Our Port Arthur products system transports refined petroleum products from Valero’s Port Arthur Refinery to major third-party pipeline systems, including the Explorer, Colonial, Sunoco Logistics MagTex and Enterprise TE Products refined petroleum products pipeline systems, for delivery to various marketing outlets, and to Enterprise’s Beaumont marine terminal for exports. Our Port Arthur products system comprises the following assets:
12-10 Pipeline. Our 12-10 pipeline consists of 13 miles of 12-inch and 10-inch pipeline with 60,000 barrels per day of capacity that delivers refined petroleum products from Valero’s Port Arthur Refinery to the Enterprise TE Products pipeline connection, the Sunoco Logistics MagTex pipeline connection, and Enterprise’s Beaumont marine terminal.
Port Arthur Products Pipelines (PAPSEl Vista). Our Port Arthur products pipelines consist of a four-mile, 20-inch pipeline with 144,000 barrels per day of capacity that delivers gasoline from Valero’s Port Arthur Refinery to our El Vista terminal and a three-mile, 20-inch pipeline with 216,000 barrels per day of capacity that delivers diesel from Valero’s Port Arthur Refinery to our Port Arthur Products Station (PAPS) terminal.



6


PAPS and El Vista Terminals. Our PAPS terminal consists of nine tanks with 1,144,000 barrels of diesel storage capacity, and our El Vista terminal consists of eight tanks with 1.2 million barrels of gasoline storage capacity. Our PAPS terminal also contains storage tanks owned by Colonial, which serves as the operator of our PAPS terminal. Each party owns its own tanks at the PAPS terminal and its own external pipelines connecting to the terminal, but certain equipment and improvements located at and serving the terminal are jointly owned. We own all of the El Vista terminal assets.
Port Arthur Terminal. Our Port Arthur terminal is a crude oil, intermediates, and refined petroleum products terminal that supports Valero’s Port Arthur Refinery. The Port Arthur terminal has 47 storage tanks with 8.5 million barrels of storage capacity. The terminal can receive domestic and foreign crude oil from pipelines and water. The terminal is directly connected to the Valero Pleasure Island crude offloading dock for waterborne crude oil. The Port Arthur terminal can also receive, via our Lucas terminal, domestic, Canadian, and other imported crude oil from the TransCanada Cushing MarketLink pipeline, the Seaway pipeline, and the Sunoco Logistics Nederland terminal. Refined petroleum products can be loaded onto ships at Valero’s Port Arthur Refinery docks or be delivered to the Explorer, Colonial, and Sunoco Logistics MagTex pipelines via our PAPS and El Vista terminals.
St. Charles Logistics System
Our St. Charles logistics system includes Parkway pipeline and our St. Charles terminal.
Parkway Pipeline. Our Parkway pipeline is an approximately 140-mile, 16-inch refined petroleum products pipeline with 110,000 barrels per day of capacity that transports refined petroleum products from Valero’s St. Charles Refinery to Collins, Mississippi for supply into the Plantation and Colonial pipeline systems.
St. Charles Terminal. Our St. Charles terminal is a crude oil, intermediates, and refined petroleum products terminal that supports Valero’s St. Charles Refinery in Norco, Louisiana. The terminal is located on the Mississippi River and has storage tanks with 10 million barrels of storage capacity. The terminal receives crude oil via the refinery’s docks, from Louisiana Offshore Oil Port (LOOP), and from the Clovelly-Alliance-Meraux (CAM) pipeline system, which connects to multiple domestic pipelines. The terminal can distribute refined petroleum products across the refinery’s docks and into the Plantation (via Parkway) and Colonial (via Bengal) pipeline systems. The terminal can also load renewable diesel onto railcars.
Three Rivers Logistics System
Our Three Rivers logistics system includes our Three Rivers crude system and our Three Rivers terminal.
Three Rivers Crude System. Our Three Rivers crude system supports Valero’s Three Rivers Refinery and is located in the Eagle Ford shale region in South Texas. The system consists of 11 crude oil truck unloading sites with lease automatic custody transfer units and three 1-mile, 12-inch pipelines with a capacity of 110,000 barrels per day. The system delivers crude oil received from the truck unloading sites and pipeline connections to tanks at Valero’s Three Rivers Refinery. The system also receives locally produced crude oil via connections to the Harvest Arrowhead pipeline system and the Plains Gardendale pipeline for processing at Valero’s Three Rivers Refinery or for shipment through third-party pipelines to Valero’s refineries in Corpus Christi, Texas. The system has a connection to the EOG Eagle Ford West Pipeline and supporting pipeline infrastructure, which segregate and connect Eagle Ford crude oil production to Valero’s Three Rivers Refinery.
Three Rivers Terminal. Our Three Rivers terminal is a crude oil, intermediates, and refined petroleum products terminal that supports Valero’s Three Rivers Refinery. The terminal is located in South Texas between Corpus Christi and San Antonio and has storage tanks with 2.3 million barrels of storage capacity. The terminal receives crude oil from our Three Rivers crude system and transports crude oil to Corpus Christi through an outbound connection to NuStar’s Three Rivers/Corpus Christi crude pipeline. The terminal can distribute



7


refined petroleum products through its truck rack and NuStar’s Pettus North, San Antonio South, and Laredo pipelines.



8


Pipelines
The following table summarizes information with respect to our pipelines described above:
Pipeline
 
Diameter
(inches)
 
Length
(miles)
 
Throughput
Capacity
(thousand barrels
per day)
 
Commodity
 
Associated
Valero
Refinery
 
Significant
Third-party
System Connections
Ardmore logistics system
 
 
 
 
 
 
 
 
 
 
Hewitt segment of Red River crude oil pipeline
 
16
 
138
 
60(a)
 
crude oil
 
Ardmore
 
Plains Red River, Plains Cushing
Wynnewood refined products pipeline
 
12
 
30
 
90
 
refined petroleum products
 
Ardmore
 
Magellan Central
McKee logistics system
 
 
 
 
 
 
 
 
 
 
 
 
McKee crude system
 
multiple segments
 
145
 
72
 
crude oil
 
McKee
 
McKee products system
 
 
 
 
 
 
 
 
 
 
 
 
McKee to El Paso pipeline
 
10
 
408
 
21(b)
 
refined petroleum products
 
McKee
 
SFPP pipeline connection
 
16, 8
 
12
 
33(c)
 
refined petroleum products
 
McKee
 
Kinder Morgan SFPP System
Memphis logistics system(d)
 
 
 
 
 
 
 
 
 
 
Collierville crude system
 
 
 
 
 
 
 
 
 
 
 
 
Collierville pipeline
 
10-20
 
52
 
210
 
crude oil
 
Memphis
 
Capline; Diamond (e)
Memphis products system
 
 
 
 
 
 
 
 
 
 
 
 
Memphis Airport pipeline system
 
6
 
11
 
20
 
jet fuel
 
Memphis
 
Memphis International Airport
Shorthorn pipeline system
 
14, 12
 
9
 
120
 
refined petroleum products
 
Memphis
 
Exxon Memphis
Port Arthur logistics system
 
 
 
 
 
 
 
 
 
 
Lucas crude system
 
 
 
 
 
 
 
 
 
 
 
 
Lucas pipeline
 
30
 
12
 
400
 
crude oil
 
Port Arthur
 
Sunoco Logistics Nederland; Enterprise Beaumont; Cameron Highway; TransCanada Cushing MarketLink; Seaway
Nederland pipeline
 
32
 
5
 
600
 
crude oil
 
Port Arthur
 
Sunoco Logistics Nederland
Port Arthur products system
 
 
 
 
 
 
 
 
 
 
 
 
12-10 pipeline
 
12, 10
 
13
 
60
 
refined petroleum products
 
Port Arthur
 
Sunoco Logistics MagTex; Enterprise TE Products, Enterprise Beaumont
20-inch diesel pipeline
 
20
 
3
 
216
 
diesel
 
Port Arthur
 
Explorer; Colonial
20-inch gasoline pipeline
 
20
 
4
 
144
 
gasoline
 
Port Arthur
 
Explorer; Colonial
St. Charles logistics system
 
 
 
 
 
 
 
 
 
 
Parkway pipeline
 
16
 
140
 
110
 
refined petroleum products
 
St. Charles
 
Plantation; Colonial
Three Rivers logistics system
 
 
 
 
 
 
 
 
 
 
Three Rivers crude system
 
12
 
3
 
110
 
crude oil
 
Three Rivers
 
Harvest Arrowhead; Plains Gardendale; EOG Eagle Ford West
_______________________
(a)
Capacity shown represents our 40 percent undivided interest in the pipeline segment. Total capacity for the pipeline segment is 150,000 barrels per day.
(b)
Capacity shown represents our 33⅓ percent undivided interest in the pipeline. Total capacity for the pipeline is 63,000 barrels per day.
(c)
Capacity shown represents our 33⅓ percent undivided interest in the pipeline connection. Total capacity for the pipeline connection is 98,400 barrels per day.
(d)
Portions of our Memphis logistics system pipelines are owned by MLGW, but they are operated and maintained exclusively by us under long-term arrangements with MLGW.
(e)
The Diamond pipeline is owned 50 percent by Valero and 50 percent by Plains All American Pipeline, L.P.



9


Terminals
The following table summarizes information with respect to our terminals described above:
Terminal
 
Tank Storage
Capacity
(thousands of
barrels)
 
Throughput
Capacity
(thousand
barrels
per day)
 
Commodity
 
Associated
Valero
Refinery
 
Significant
Third-party
System Connections
Ardmore logistics system
 
 
 
 
 
 
 
 
 
 
Hewitt Station tanks
 
300
 
 
crude oil
 
Ardmore
 
Plains Red River
Wynnewood terminal
 
180
 
 
refined petroleum products
 
Ardmore
 
Magellan Central
Corpus Christi logistics system
 
 
 
 
 
 
 
 
 
 
Corpus Christi East terminal
 
6,241
 
 
crude oil and refined petroleum products
 
Corpus Christi East
 
Eagle Ford Pipeline LLC; NuStar North Beach terminal, Eagle Ford pipelines & South Texas pipeline network
Corpus Christi West terminal
 
3,835
 
 
crude oil and refined petroleum products
 
Corpus Christi West
 
(same as Corpus Christi East terminal)
Houston logistics system
 
 
 
 
 
 
 
 
 
 
Houston terminal
 
3,642
 
 
crude oil and refined petroleum products
 
Houston
 
HFOTCO; Magellan crude; Seaway; Kinder Morgan Pasadena & Galena Park; Magellan East Houston & Galena Park
McKee logistics system
 
 
 
 
 
 
 
 
 
 
McKee crude system
 
 
 
 
 
 
 
 
 
 
Various terminals
 
240
 
 
crude oil
 
McKee
 
McKee products system
 
 
 
 
 
 
 
 
 
 
El Paso terminal
 
166 (a)
 
 
refined petroleum products
 
McKee
 
Kinder Morgan SFPP System
El Paso terminal truck rack
 
 
10 (b)
 
refined petroleum products
 
McKee
 
McKee terminal
 
4,400
 
 
crude oil and refined petroleum products
 
McKee
 
NuStar (several); NuStar/Phillips Denver
Memphis logistics system
 
 
 
 
 
 
 
 
 
 
Collierville crude system
 
 
 
 
 
 
 
 
 
 
Collierville terminal
 
975
 
 
crude oil
 
Memphis
 
Capline
St. James crude tank
 
330
 
 
crude oil
 
Memphis
 
Capline
Memphis products system
 
 
 
 
 
 
 
 
 
 
Memphis truck rack
 
8
 
110
 
refined petroleum products
 
Memphis
 
West Memphis terminal
 
1,080
 
 
refined petroleum products
 
Memphis
 
Exxon Memphis; Enterprise TE Products
West Memphis terminal dock
 
 
4 (c)
 
refined petroleum products
 
Memphis
 
West Memphis terminal truck rack
 
 
50
 
refined petroleum products
 
Memphis
 
Meraux logistics system
 
 
 
 
 
 
 
 
 
 
Meraux terminal
 
3,900
 
 
crude oil and refined petroleum products
 
Meraux
 
LOOP; CAM; Plantation; Colonial
____________________________
 
 
 
 
 
 
 
 
 
 
See footnotes on page 11.



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Terminal
 
Tank Storage
Capacity
(thousands of
barrels)
 
Throughput
Capacity
(thousand
barrels
per day)
 
Commodity
 
Associated
Valero
Refinery
 
Significant
Third-party
System Connections
Port Arthur logistics system
 
 
 
 
 
 
 
 
 
 
Lucas crude system
 
 
 
 
 
 
 
 
 
 
Lucas terminal
 
1,915
 
 
crude oil
 
Port Arthur
 
Sunoco Logistics Nederland; Enterprise Beaumont; Cameron Highway; TransCanada Cushing MarketLink; Seaway
Seaway connection
 
 
750
 
crude oil
 
Port Arthur
 
Seaway
TransCanada connection
 
 
400
 
crude oil
 
Port Arthur
 
TransCanada Cushing MarketLink
Port Arthur products system
 
 
 
 
 
 
 
 
 
 
El Vista terminal
 
1,210
 
 
gasoline
 
Port Arthur
 
Explorer; Colonial
PAPS terminal
 
1,144
 
 
diesel
 
Port Arthur
 
Explorer; Colonial
Port Arthur terminal
 
8,500
 
 
crude oil and refined petroleum products
 
Port Arthur
 
Sunoco Logistics Nederland; Explorer; Colonial; Sunoco Logistics MagTex; Cameron Highway; TransCanada Cushing MarketLink; Enterprise Beaumont
St. Charles logistics system
 
 
 
 
 
 
 
 
 
 
St. Charles terminal
 
10,004
 
 
crude oil and refined petroleum products
 
St. Charles
 
LOOP; CAM; Plantation; Colonial
Three Rivers logistics system
 
 
 
 
 
 
 
 
 
 
Three Rivers terminal
 
2,250
 
 
crude oil and refined petroleum products
 
Three Rivers
 
NuStar South Texas; Harvest Arrowhead; Plains Gardendale; EOG Eagle Ford West
____________________________
(a)
Capacity shown represents our 33⅓ percent undivided interest in the terminal. Total storage capacity is 499,000 barrels.
(b)
Capacity shown represents our 33⅓ percent undivided interest in the truck rack. Total capacity is 30,000 barrels per day.
(c)
Dock throughput is reflected in thousands of barrels per hour.
Our Commercial Agreements with Valero
General
Our commercial agreements with Valero prescribe rates, commitments, and other terms and conditions applicable to our pipelines and terminals. Under these commercial agreements, we provide transportation and terminaling services to Valero, and Valero pays us for minimum quarterly throughput volumes of crude oil and refined petroleum products, regardless of whether such volumes are physically delivered by Valero in any given quarter. These commercial agreements have initial 10-year terms from inception, and, with the exception of certain assets, Valero has the option to renew the agreements for one additional five-year term.
Minimum Quarterly Throughput Commitments and Tariff Rates—Pipelines
Our transportation agreements with Valero contain minimum volume commitments that require Valero to ship minimum volumes during each calendar quarter or pay us for the shortfall using a tariff rate with respect to such volumes. Tariff rates with respect to our pipeline systems may be adjusted annually at our discretion in accordance with the Federal Energy Regulatory Commission’s (FERC) indexing methodology. For any pipelines that may be subject to a jurisdictional tariff, we and Valero have agreed not to commence or support any tariff filing, application, protest, complaint, petition, motion, or other proceeding before FERC for the purpose of requesting that FERC accept or set tariff rates that would be inconsistent with the terms of our transportation services agreements, provided that Valero will continue to have the right under FERC regulations to challenge any proposed changes in our base tariff rates to the extent the changes are inconsistent with FERC’s indexing methodology or other rate changing methodologies, or to the extent the challenge is



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in response to any proceeding brought against us by a third party that could affect our ability to provide transportation services to Valero under our transportation services agreements or the applicable tariff.
Minimum Quarterly Throughput Commitments and Fees—Terminals
Under our terminal services agreement, Valero is obligated to throughput minimum volumes of crude oil and refined petroleum products and pay us throughput fees, as well as fees for providing related ancillary services such as ethanol, biodiesel and renewable diesel blending, and additive injection (except at the Wynnewood terminal, where Valero agrees to pay us a monthly fee as a base storage charge whether or not Valero actually uses any of the storage or other services made available by us at the terminal). Valero provides and pays for its own inventory of ethanol, biodiesel and renewable diesel blending, and additives to be blended or injected at the terminals, where applicable.
Throughput fees with respect to our terminals (or the base storage charge, with respect to our Wynnewood terminal) are increased on July 1 of each year during the term of the applicable terminal service schedule, and other fees with respect to our terminals may be increased annually at our discretion, in each case by a percentage not to exceed the corresponding percentage change in the applicable inflation index during the 12-month period ending on March 31 of such year. If such index decreases during any period, we are not required to reduce our fees, but any subsequent increases in fees based on an increase in the index will be limited to the amount by which such increase exceeds the aggregate amount of cumulative decreases during the intervening periods.
Quarterly Deficiency Payments
If Valero fails to meet its minimum quarterly throughput commitments under our commercial agreements in any given quarter, it is obligated to pay a deficiency payment equal to the volume deficiency multiplied by the applicable tariff and/or fee with respect to such asset. We refer to this payment as a “quarterly deficiency payment.” Quarterly deficiency payments may be applied as a credit for amounts owed on throughput volumes in excess of Valero’s minimum quarterly throughput commitment with respect to such asset during any of the following four quarters, after which time any unused credits will expire.
Minimum Capacity
Under each of our commercial agreements, we are obligated to provide Valero access to capacity of at least the minimum quarterly throughput commitment for our assets. If the minimum capacity of any of our assets falls below the level of Valero’s minimum quarterly throughput commitment at any time due to events affecting such assets (whether planned or unplanned) or if capacity on any of our assets is required to be allocated among users because volume nominations exceed available capacity, Valero’s minimum quarterly throughput commitments with respect to such assets may be proportionately reduced during the period for which capacity is less than Valero’s minimum quarterly throughput commitment.
Product Gains and Losses
Under each of our commercial agreements, other than those commercial agreements covering assets that may be subject to a jurisdictional tariff or are operated by a third party and such tariff or third-party operating agreement specifically provides otherwise, we have no liability for physical losses except to the extent such losses result from our gross negligence or willful misconduct. In the event a terminal or pipeline asset is equipped to measure volume gains and losses through the installation of custody transfer meters and we begin to accept third-party volumes for throughput, we are required to negotiate provisions regarding loss allowance and allocate gains and losses among us and our customers in accordance with standard industry practices.



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Termination and Suspension
Valero is permitted under our commercial agreements (except for the Parkway pipeline transportation agreement) to suspend, reduce, or terminate its obligations under certain circumstances. If Valero determines to totally or partially suspend refining operations at a refinery that is supported by our assets for a period of at least 12 consecutive months, we and Valero are required to negotiate in good faith to agree upon a reduction of Valero’s minimum quarterly throughput commitments under the applicable commercial agreement(s), and if we are unable to agree to an appropriate reduction, then after Valero has made a public announcement of such suspension, Valero may terminate the applicable agreement(s) upon 12 months’ notice to us (unless in the interim Valero publicly announces its intent to resume operations at the refinery, in which case its termination notice is deemed revoked). If a force majeure event with respect to our assets prevents us from performing any of our obligations under a commercial agreement, Valero’s obligations with respect to the affected assets under the applicable commercial agreement, including its minimum quarterly throughput commitments, will be suspended to the extent we cannot perform our obligations. In addition, if a force majeure event prevents Valero from fulfilling any of its obligations under our commercial agreements for more than 60 days, Valero’s applicable obligations with respect to the affected assets, including its minimum quarterly throughput commitments, under our commercial agreements will be suspended for the remainder of the force majeure event.
Turnarounds or other planned outages at a refinery are not force majeure events. If a force majeure event prevents any party from performing its obligations under a commercial agreement for a period of more than 12 consecutive months, then either party may terminate the agreement with respect to the affected assets. If Valero elects to terminate or suspend any of our commercial agreements, our financial condition, results of operations, cash flows, and ability to make distributions to our unitholders may be materially and adversely affected. We cannot assure you that Valero will continue to use our assets or that we will be able to generate additional revenues from third parties.
Our Relationship with Valero
Valero is an independent petroleum refiner and ethanol producer. Valero’s assets include 15 petroleum refineries located in the U.S., Canada, and the United Kingdom, with a combined total throughput capacity of approximately 3.1 million barrels per day and 11 ethanol plants located in the U.S. Mid-Continent region with a combined production capacity of approximately 1.45 billion gallons per year. Valero also has a substantial portfolio of transportation and logistics assets.
The loss of Valero as a customer would have a material and adverse effect on us. For the years ended December 31, 2017, 2016, and 2015, Valero accounted for all of our revenues. We expect to continue to derive a substantial amount of our revenues from Valero for the foreseeable future.
Valero owns 100 percent of our general partner, a 66.2 percent limited partner interest in us, and all of our incentive distribution rights. We believe Valero will promote and support the successful execution of our business strategies given its significant ownership in us, the importance of our assets to Valero’s refining and marketing operations, and its stated intention to use us as its primary vehicle to expand the transportation and logistics assets supporting its business.
In addition to our commercial agreements with Valero, we entered into several agreements with Valero in connection with the IPO, many of which we have amended in connection with subsequent acquisitions. These agreements include an amended and restated omnibus agreement, an amended and restated services and secondment agreement, a tax sharing agreement, and several lease and access agreements. These agreements are described in Note 3 of Notes to Consolidated Financial Statements, and the descriptions of these agreements in Note 3 are incorporated herein by reference.



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Employees
We do not have any employees and our general partner does not have any employees. We are managed by the executive officers of our general partner under the oversight of our board of directors. All of the personnel that conduct our business are employed by Valero, and their services are provided to us pursuant to our omnibus agreement and services and secondment agreement with Valero.
Pipeline Control Operations
Our pipeline systems, other than the El Paso pipeline and the Hewitt Segment (which are operated by third- parties), are operated from a central control room located in San Antonio, Texas. The control center operates with a supervisory control and data acquisition system equipped with computer systems designed to monitor operational data continuously. Monitored data includes pressures, temperatures, gravities, flow rates, and alarm conditions. The control center operates remote pumps, motors, and valves associated with the receipt and delivery of crude oil and refined petroleum products, and provides for the remote-controlled shutdown of pump stations on the pipeline system. A fully functional back-up operations center is also maintained and routinely operated throughout the year to ensure safe and reliable operations.
Seasonality
The volumes of crude oil and refined petroleum products transported in our pipelines and stored in our terminals are directly affected by the levels of supply and demand for crude oil and refined petroleum products in the markets served directly or indirectly by our assets. Demand for gasoline is generally higher during the summer months than during the winter months due to seasonal increases in motor vehicle traffic. As a result, Valero’s operating results are generally lower for the first and fourth quarters of each year. Unfavorable weather conditions during the spring and summer months and a resulting lack of the expected seasonal upswings in traffic and sales could adversely affect Valero’s business, financial condition, and results of operations, which may adversely affect our business, financial condition, and results of operations. However, many effects of seasonality on our revenues will be substantially mitigated through the use of our fee-based commercial agreements with Valero that include minimum quarterly throughput commitments.
Competition
As a result of our contractual relationship with Valero under our commercial agreements and our direct connections to ten of Valero’s refineries, we believe that our pipelines and terminals will not face significant competition from other pipelines and terminals for Valero’s crude oil or refined petroleum products transportation requirements to and from the refineries we support.
If Valero’s customers reduce their purchases of refined petroleum products from Valero due to the increased availability of less expensive products from other suppliers or for other reasons, Valero may ship only the minimum volumes through our pipelines (or pay the shortfall payment if it does not ship the minimum volumes), which would cause a decrease in our revenues. Valero competes with integrated petroleum companies, which have their own crude oil supplies and distribution and marketing systems, as well as with independent refiners, many of which also have their own distribution and marketing systems. Valero also competes with other suppliers that purchase refined petroleum products for resale. Competition in any particular geographic area is affected significantly by the volume of products produced by refineries in that area and by the availability of products and the cost of transportation to that area from distant refineries.
Environmental Matters
Our operations are subject to extensive environmental regulations by governmental authorities relating to the discharge and remediation of materials in the environment, greenhouse gas emissions, waste management, pollution prevention, species and habitat preservation, pipeline integrity, and other safety-related regulations, and characteristics and composition of fuels. Because environmental laws and regulations are becoming more complex and stringent and new environmental laws and regulations are continuously being enacted or



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proposed, the level of future expenditures required for environmental matters could increase in the future. In addition, any major upgrades in any of our operating facilities could require material additional expenditures to comply with environmental laws and regulations.
Rate and Other Regulations
FERC and Common Carrier Regulations
We own pipeline assets in Texas, New Mexico, Tennessee, Louisiana, Mississippi, Arkansas, and Oklahoma, and we provide both interstate and intrastate transportation services. Our common carrier pipeline systems are subject to regulation by various federal, state, and local agencies.
FERC regulates interstate transportation on our common carrier pipeline systems under the Interstate Commerce Act (ICA), the Energy Policy Act of 1992 (EPAct), and the rules and regulations promulgated under those laws. FERC regulations require that rates for interstate service pipelines that transport crude oil and refined petroleum products (collectively referred to as petroleum pipelines) and certain other liquids, be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. FERC’s regulations also require interstate common carrier petroleum pipelines to file with FERC and publicly post tariffs stating their interstate transportation rates and terms and conditions of service. Under the ICA, FERC or interested persons may challenge existing or changed rates or services. FERC is authorized to investigate such charges and may suspend the effectiveness of a new rate for up to seven months. A successful rate challenge could result in a common carrier paying refunds together with interest for the period that the rate was in effect. FERC may also order a pipeline to change its rates, and may require a common carrier to pay shippers reparations for damages sustained for a period up to two years prior to the filing of a complaint.
Intrastate services provided by certain of our pipeline systems are subject to regulation by state regulatory authorities, such as the Texas Railroad Commission (TRRC), which currently regulates our portion of the McKee to El Paso pipeline. The TRRC uses a complaint-based system of regulation, both as to matters involving rates and priority of access. FERC and state regulatory commissions generally have not investigated rates, unless the rates are the subject of a protest or a complaint. However, FERC or a state commission could investigate our rates on its own initiative or at the urging of a third party.
If our rate levels were investigated by FERC or a state commission, the inquiry could result in a comparison of our rates to those charged by others or to an investigation of our costs. We do not anticipate any complaints against our rates or any investigation by FERC or a state regulatory commission related to our rates or terms of service. Valero has agreed not to contest our tariff rates or terms of service for the term of our transportation services agreements, provided that our tariff changes and rate increases are consistent with the terms of the transportation services agreements. Even so, FERC or a state commission could order us to change our rates or terms of service or require us to pay shippers reparations, together with interest and subject to the applicable statute of limitations, if it were determined that an established rate or terms of service were unjust or unreasonable.
Pipeline Safety
Our assets are subject to increasingly strict safety laws and regulations. The transportation and storage of crude oil and refined petroleum products involve a risk that hazardous liquids may be released into the environment, potentially causing harm to the public or the environment. In turn, such incidents may result in substantial expenditures for response actions, significant government penalties, liability to government agencies for natural resources damages, and significant business interruption. The Department of Transportation (DOT) and Pipeline and Hazardous Materials Safety Administration have adopted safety regulations with respect to the design, construction, operation, maintenance, inspection, and management of our assets. These regulations contain requirements for the development and implementation of pipeline



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integrity management programs, which include the inspection and testing of pipelines and necessary maintenance or repairs. These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans.
Product Quality Standards
Refined petroleum products that we transport are generally sold by Valero for consumption by the public. Various federal, state, and local agencies have the authority to prescribe product quality specifications for products. Changes in product quality specifications or blending requirements could reduce our throughput volumes, require us to incur additional handling costs, or require capital expenditures. For example, different product specifications for different markets affect the fungibility of the products in our system and could require the construction of additional storage. If we are unable to recover these costs through increased revenues, our cash flows and ability to make distributions could be adversely affected. In addition, changes in the product quality of the products we receive on our product pipeline systems or at our terminals could reduce or eliminate our ability to blend products.
Security
We are also subject to Department of Homeland Security (DHS) Chemical Facility Anti-Terrorism Standards, which are designed to regulate the security of high-risk chemical facilities, and to the Transportation Security Administration’s Pipeline Security Guidelines. We have an internal program of inspection designed to monitor and enforce compliance with all of these requirements. We believe that we are in material compliance with all applicable laws and regulations regarding the security of our facilities.
While we are not currently subject to governmental standards for the protection of computer-based systems and technology from cyber threats and attacks, proposals to establish such standards are being considered by the U.S. Congress and by U.S. Executive Branch departments and agencies, including the DHS, and we may become subject to such standards in the future. We are currently implementing our own cybersecurity programs and protocols; however, we cannot guarantee their effectiveness. A significant cyber-attack could have a material effect on our operations and those of our customer.
PROPERTIES
General
The location and general character of our principal properties are described above under “—Our Assets and Operations,” and those descriptions are incorporated herein by reference. We believe that our properties and facilities are generally adequate for our operations and that our facilities are maintained in a good state of repair. As of December 31, 2017, we were the lessee under a number of cancelable and noncancelable leases for certain properties. Our leases are discussed more fully in Notes 3 and 7 of Notes to Consolidated Financial Statements.
Utilization of Our Facilities
Operating highlights for our pipelines and terminals—including pipeline transportation revenues, pipeline transportation throughput volumes, terminaling revenues, terminaling throughput volumes, and storage revenues—are described in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—2017 Compared to 2016” and “—2016 Compared to 2015,” and are incorporated herein by reference.
Title to Properties and Permits
Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property and in some instances these rights-of-way are revocable at the election of the grantor. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained permits from public authorities to cross over or



16


under, or to lay facilities in or along, watercourses, county roads, municipal streets, and state highways and, in some instances, these permits are revocable at the election of the grantor. We have also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election. In some states and under some circumstances, we have the right of eminent domain to acquire rights-of-way and lands necessary for our common carrier pipelines.
Under our omnibus agreement, Valero will indemnify us for certain title defects and for failures to obtain certain consents and permits necessary to conduct our business. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with 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, 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.



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Item 1A. RISK FACTORS
You should carefully consider each of the following risks and all of the other information contained in this Annual Report on Form 10-K in evaluating us and our common units. Some of these risks relate principally to our business and the industry in which we operate, while others relate principally to the business and operations of Valero, tax matters, ownership of our common units, and securities markets generally.
Our financial condition, results of operations, and cash flows and our ability to make distributions to our unitholders could be materially and adversely affected by these risks, and, as a result, the trading price of our common units could decline.
Risks Related to Our Business
Valero accounts for all of our revenues. Therefore, we are subject to the business risks associated with Valero’s business. Furthermore, if Valero changes its business strategy, is unable for any reason, including financial or other limitations, to satisfy its obligations under our commercial agreements or significantly reduces the volumes transported through our pipelines or terminals, our revenues would decline and our financial condition, results of operations, cash flows, and ability to make distributions to our unitholders would be materially and adversely affected.
Valero accounts for all of our revenues. We expect to continue to derive a substantial amount of our revenues from Valero for the foreseeable future, and as a result, any event, whether in our areas of operation or elsewhere, that materially and adversely affects Valero’s business may adversely affect our financial condition, results of operations, and cash flows and our ability to make distributions to our unitholders. Accordingly, we are indirectly subject to the operational and business risks of Valero, the most significant of which include the following:
disruption of Valero’s ability to obtain crude oil;
interruptions at Valero’s refineries and other facilities;
any decision by Valero to temporarily or permanently curtail or shut down operations at one or more of its refineries or other facilities and reduce or terminate its obligations under our commercial agreements;
competitors that produce their own supply of feedstocks, have more extensive retail outlets, or have greater financial resources may have a competitive advantage over Valero;
the ability to obtain credit and financing on acceptable terms, which could also adversely affect the financial strength of business partners;
the costs to comply with environmental laws and regulations;
significant losses resulting from the hazards and risks of operations may not be fully covered by insurance, and could adversely affect Valero’s operations and financial results;
large capital projects can take many years to complete, and market conditions could deteriorate significantly between the project approval date and the project startup date, negatively impacting project returns;
interruptions of supply and increased costs as a result of Valero’s reliance on third-party transportation of crude oil and refined petroleum products;
potential losses from Valero’s derivative transactions; and



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the effects of changing commodity and refined product prices.
The volumes of crude oil and refined petroleum products that we transport and terminal depend substantially on Valero’s refining margins. Refining margins are dependent both upon the price of crude oil or other refinery feedstocks and refined petroleum products. These prices are affected by numerous factors beyond our or Valero’s control, including the global supply and demand for crude oil, gasoline and other refined petroleum products, competition from alternative energy sources, and the impact of new and more stringent regulations affecting the energy industry. A material decrease in the refining margins at Valero’s refineries supported by our assets could cause Valero to reduce the volumes we transport and terminal for Valero, which could materially and adversely affect our financial condition, results of operations, and ability to make distributions to our unitholders.
We may not have sufficient distributable cash flow following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to maintain or increase our quarterly distributions to our unitholders.
We may not generate sufficient cash flows each quarter to enable us to maintain or increase distributions. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things, our throughput volumes, tariff rates and fees, and prevailing economic conditions. In addition, the actual amount of cash flows we generate will also depend on other factors, some of which are beyond our control, including:
the amount of our operating expenses and general and administrative expenses, including reimbursements to Valero, which are not subject to any caps or other limits, in respect of those expenses;
the amount and timing of capital expenditures and acquisitions we make;
our debt service requirements and other liabilities, and restrictions contained in our revolving credit facility and other debt agreements;
fluctuations in our working capital needs; and
the amount of cash reserves established by our general partner.
If we are unable to obtain needed capital or financing on satisfactory terms to fund expansions of our asset base, our ability to make quarterly distributions may be diminished or our financial leverage could increase. We do not have any commitment with any of our affiliates to provide any direct or indirect financial assistance to us.
If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and may be unable to maintain or raise the level of our quarterly distributions. We will be required to use cash from our operations, incur borrowings or access the capital markets in order to fund our expansion capital expenditures. Our ability to incur indebtedness or access the capital markets may be limited by our financial condition at such time as well as the covenants in our debt agreements, general economic conditions and contingencies, and uncertainties that are beyond our control. The terms of any such financing could also limit our ability to make distributions to our common unitholders. Incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.



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If Valero satisfies only its minimum quarterly throughput commitments under, or if Valero terminates or we are unable to renew or extend, our commercial agreements with Valero, our ability to make distributions to our unitholders will be reduced.
Valero is not obligated to use our services with respect to volumes of crude oil or refined petroleum products in excess of the minimum quarterly throughput commitments under our commercial agreements. During refinery turnarounds, which typically last 30 to 60 days and are performed every four to five years, we expect that Valero will satisfy only its minimum quarterly throughput commitments under our commercial agreements. Our commercial agreements with Valero generally have initial terms of 10 years from the date of acquisition of the related asset (the earliest of which begin to expire in 2023), and with the exception of certain assets, Valero has the option to renew the agreements for one additional five-year term. If Valero fails to use our facilities and services after expiration of those agreements and we are unable to generate additional revenues from third parties, our ability to make distributions to our unitholders will be reduced.
Further, Valero may suspend, reduce or terminate its obligations under our commercial agreements if certain events occur, such as Valero’s determination to totally or partially suspend refining operations at one of its refineries that our assets support for a period that will continue for at least 12 months, or a force majeure event that impacts one of Valero’s refineries for more than 60 days. Any such reduction, suspension, or termination of Valero’s obligations would have a material and adverse effect on our financial condition, results of operations, and cash flows and our ability to make distributions to our unitholders.
We may not be able to obtain third-party revenues due to competition and other factors outside our control, which could limit our ability to grow and may extend our dependence on Valero.
Our ability to obtain third-party revenues is subject to numerous factors beyond our control, including competition from third parties, availability of potential acquisition opportunities, and the extent to which we have available capacity when third-party shippers require it. We can provide no assurance that we will be able to materially increase third-party revenues. Our efforts to establish our reputation and attract new unaffiliated customers may be adversely affected by our relationship with Valero and our desire to provide services pursuant to fee-based contracts. Our potential customers may prefer to obtain services under contracts through which we could be required to assume direct commodity exposure.
Our ability to acquire transportation and logistics assets from Valero is subject to risks and uncertainty, and ultimately we may not further acquire any assets from Valero.
Our present growth strategy depends significantly on acquiring assets from Valero. The consummation and timing of any future acquisitions will depend upon, among other things, Valero’s willingness to offer assets for sale, our ability to negotiate acceptable purchase agreements and commercial agreements with respect to such assets, and our ability to obtain financing on acceptable terms. We have no control over Valero’s decision to offer us the ability to acquire any of its assets. We can provide no assurance that we will be able to successfully consummate any future acquisitions from Valero, and Valero is under no obligation to accept any offer that we may choose to make. In addition, we may decide not to acquire additional assets from Valero, and any such decision will not be subject to unitholder approval. In addition, our right of first offer with respect to certain of Valero’s assets under our omnibus agreement may be terminated by Valero at any time in the event that it no longer controls our general partner.



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If we are unable to make acquisitions on economically acceptable terms from Valero or third parties, our future growth would be limited, and any acquisitions we may make may reduce, rather than increase, our cash flows and ability to make distributions to unitholders.
Our strategy to grow our business and increase distributions to unitholders is dependent in part on our ability to make acquisitions that result in an increase in distributable cash flow per unit. Our growth strategy is based in part on our expectation of ongoing divestitures by industry participants, including our right of first offer from Valero. The consummation and timing of any future acquisitions will depend upon, among other things, whether:
we are able to identify attractive acquisition candidates;
we are able to negotiate acceptable purchase agreements;
we are able to obtain financing for these acquisitions on economically acceptable terms; and
we are outbid by competitors.
We can provide no assurance that we will be able to consummate any future acquisitions, whether from Valero or any third parties. If we are unable to make future acquisitions, our future growth and ability to increase distributions will be limited. Furthermore, even if we do consummate acquisitions that we believe will be accretive, they may in fact result in a decrease in distributable cash flow per unit as a result of incorrect assumptions in our evaluation of such acquisitions, unforeseen consequences, or other external events beyond our control. Acquisitions involve numerous risks, including difficulties in integrating acquired businesses or assets, inefficiencies, and unexpected costs and liabilities.
Our ability to expand may be limited if Valero does not grow its business.
Our growth strategy depends in part on the growth of Valero’s business. We believe our growth will be driven in part by identifying and executing organic expansion projects that will result in increased throughput volumes from Valero and third parties. If Valero focuses on other growth areas or does not make capital expenditures to fund the growth of its business, we may not be able to fully execute our growth strategy.
Our and Valero’s operations are subject to many risks and operational hazards. If a significant accident or event occurs that results in a business interruption or shutdown for which we are not adequately insured, our financial condition, results of operations, and cash flows and our ability to sustain or increase distributions to our unitholders could be materially and adversely affected.
Our operations are subject to all of the risks and operational hazards inherent in transporting, terminaling, and storing crude oil and refined petroleum products, including:
damages to facilities, equipment, and surrounding properties caused by third parties, severe weather, natural disasters, and acts of terrorism;
maintenance, repairs, mechanical or structural failures at our or Valero’s facilities or at third-party facilities on which our or Valero’s operations are dependent, including electrical shortages, power disruptions, and power grid failures;
damages to and loss of availability of interconnecting third-party pipelines, terminals, and other means of delivering crude oil, feedstocks, and refined petroleum products;
disruption or failure of information technology systems and network infrastructure due to various causes, including unauthorized access or attack;



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curtailments of operations due to severe seasonal weather; and
riots, work stoppages, slowdowns or strikes, as well as other industrial disturbances.
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, as well as business interruptions or shutdowns of our facilities. Any such event or unplanned shutdown could have a material and adverse effect on our financial condition, results of operations, and cash flows and our ability to make distributions to our unitholders. In addition, Valero’s refining operations supported by our assets, on which our operations are substantially dependent and over which we have no control, are subject to similar operational hazards and risks inherent in refining crude oil.
Our insurance policies do not cover all losses, costs, or liabilities that we may experience, and insurance companies that currently insure companies in the energy industry may cease to do so or substantially increase premiums.
We do not maintain insurance coverage against all potential losses and could suffer losses for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. We maintain insurance policies for certain property damage, business interruption, and third-party liabilities, which includes pollution liabilities, and are subject to policy limits under these policies. The occurrence of an event that is not fully covered by insurance or failure by one or more insurers to honor its coverage commitments for an insured event could have a material and adverse effect on our financial condition, results of operations, and cash flows and our ability to make distributions to our unitholders. Insurance companies may reduce the insurance capacity they are willing to offer or may demand significantly higher premiums or deductibles to cover these facilities. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, we may be unable to obtain and maintain adequate insurance at a reasonable cost. We cannot provide assurance that our insurers will renew our insurance coverage on acceptable terms, if at all, or that we will be able to arrange for adequate alternative coverage in the event of non-renewal. The unavailability of full insurance coverage to cover events in which we suffer significant losses could have a material and adverse effect on our financial condition, results of operations, and cash flows and our ability to make distributions to our unitholders.
We are exposed to the credit risks, and certain other risks, of our customers, and any material nonpayment or nonperformance by our customers could reduce our ability to make distributions to our unitholders.
We are subject to the risks of loss resulting from nonpayment or nonperformance by our customers. If Valero or any other significant customer defaults on its obligations to us, our financial results could be adversely affected. Our customers may be highly leveraged and subject to their own operating and regulatory risks. Any material nonpayment or nonperformance by our customers could reduce our financial condition, results of operations, and cash flows and our ability to make distributions to our unitholders.
Our expansion of existing assets and 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 operations and financial condition.
In order to optimize our existing asset base, we intend to evaluate and capitalize on organic opportunities for expansion projects in order to increase revenues on our pipelines and terminals. The expansion of existing pipelines or terminals, such as by adding horsepower, pump stations, or loading racks, or the construction or expansion of new transportation and logistics assets, involves numerous regulatory, environmental, political, and legal uncertainties, most of which are beyond our control. If we undertake these projects, they may not be completed on schedule or at all or at the budgeted cost. Moreover, we may not receive sufficient



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long-term contractual commitments from customers to provide the revenues needed to support such projects and we may be unable to negotiate acceptable interconnection agreements with third-party pipelines to provide destinations for increased throughput. Even if we receive such commitments or make such interconnections, we may not realize an increase in revenues for an extended period of time. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could materially and adversely affect our financial condition, results of operations, and cash flows and our ability in the future to make distributions to our unitholders.
We do not own all of the land on which our assets are located, which could result in disruptions to our operations.
We do not own all of the land on which our assets are located, and we are, therefore, subject to the possibility of more onerous terms and increased costs to retain necessary land use if we do not have valid leases or rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our assets on land owned by third parties and governmental agencies, and some of our agreements may grant us those rights for only a specific period of time. Our loss of these rights, through our inability to renew leases, right-of-way contracts or otherwise, could have a material and adverse effect on our financial condition, results of operations, and cash flows and our ability to make distributions to our unitholders.
We are dependent upon third parties to operate some of our assets.
Certain of our assets are operated by third parties. Success in jointly owned assets depends in large part on whether our partners, over whom we may have little or no control, satisfy their contractual obligations. If such third parties fail to operate such assets in accordance with the terms of any applicable operating agreement with them or otherwise fail to meet their contractual obligations, such failures could result in our inability to meet our commitments to our customers, which in turn could result in a reduction in our revenues, or in us becoming liable to our customers for any losses they may sustain by reason of our failure to comply, which losses may not be recoverable by us. Differences in opinions or views between us and our partners can result in delayed decision-making or failure to agree on material issues that could adversely affect the business and operations of such assets. Additionally, the failure by a partner to comply with applicable laws, regulations, or client requirements could negatively impact our business.
Our substantial indebtedness and the restrictions in our revolving credit facility, senior notes, and subordinated credit agreements with Valero could adversely affect our business, financial condition, results of operations, ability to make distributions to our unitholders, and the value of our units.
As of December 31, 2017, our total debt, which includes notes payable – related party, was $1.275 billion. Our substantial indebtedness and the additional debt we may incur in the future for potential acquisitions may adversely affect our liquidity and therefore our ability to make interest payments on our notes.
We are dependent upon the earnings and cash flows generated by our operations in order to meet any debt service obligations and to allow us to make distributions to our unitholders. Our substantial indebtedness and the restrictions in the agreements governing our indebtedness could restrict our ability to finance our future operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make distributions to our unitholders. For example, our revolving credit facility and subordinated credit agreements contain covenants that require us to maintain a ratio of total debt to earnings before interest, taxes, depreciation, and amortization (EBITDA) for the prior four fiscal quarters of not greater than 5.0 to 1.0 as of the last day of each fiscal quarter (or 5.5 to 1.0 during specified periods following certain acquisitions).



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Our substantial indebtedness and the restrictions in our revolving credit facility, senior notes, and subordinated credit agreements could affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our debt agreements could result in an event of default, which would enable our lenders to declare the outstanding principal of that debt, together with accrued interest, to be immediately due and payable. If the payment of our debt is accelerated, defaults under our other debt agreements, if any, may be triggered, and our assets may be insufficient to repay such debt in full, and the holders of our units could experience a partial or total loss of their investment. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity” for additional information about the agreements governing our indebtedness.
A downgrade of our credit ratings, which are determined by independent third parties, could impact our financial position, results of operations, and liquidity.
Our access to credit and capital markets depends on the credit ratings assigned to our debt by independent credit rating agencies. We currently maintain investment-grade ratings by Standard & Poor’s Ratings Services (S&P), Moody’s Investors Service (Moody’s), and Fitch Ratings (Fitch) on our notes. Ratings from credit agencies are not recommendations to buy, sell, or hold our securities. Each rating should be evaluated independently of any other rating. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Specifically, if ratings agencies were to downgrade our long-term rating, particularly below investment grade, our borrowing costs would increase, which could adversely affect our ability to attract potential investors and our funding sources could decrease. In addition, we may not be able to obtain favorable credit terms from our suppliers or they may require us to provide collateral, letters of credit, or other forms of security, which would increase our operating costs. As a result, a downgrade below investment grade in our credit ratings could have a material adverse impact on our financial position, results of operations, and liquidity.
Increases in interest rates could adversely impact the price of our common units, our ability to issue equity, or incur debt for acquisitions or other purposes and our ability to make distributions at our intended levels.
In the future, the interest rates on our indebtedness could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by our level of distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units. Interest rates are highly sensitive to many factors that are beyond our control, including general economic conditions and policies of various governmental and regulatory agencies and, in particular, the Federal Reserve Board, which increased its targeted federal funds rate several times in 2017 and may continue to do so. As the Federal Reserve Board increases its target federal funds rate, overall interest rates will likely rise and a rising interest rate environment could have an adverse impact on the price of our common units, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make distributions at our intended levels.
Compliance with and changes in environmental and pipeline integrity and safety laws could adversely affect our performance.
The principal environmental risks associated with our operations are emissions into the air and releases into the soil, surface water, or groundwater. Our operations are subject to extensive environmental laws and



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regulations, including those relating to the discharge and remediation of materials in the environment, greenhouse gas emissions, waste management, species and habitat preservation, pollution prevention, pipeline integrity and other safety-related regulations, and characteristics and composition of fuels. Certain of these laws and regulations could impose obligations to conduct assessment or remediation efforts at our facilities or third-party sites where we take wastes for disposal or where our wastes migrated. Environmental laws and regulations also may impose liability on us for the conduct of third parties or for actions that complied with applicable requirements when taken, regardless of negligence or fault. If we violate or fail to comply with these laws and regulations, it could lead to administrative, civil, or criminal penalties or liability and the imposition of injunctions, operating restrictions, or the loss of permits.
Because environmental laws and regulations are becoming more stringent and new environmental laws and regulations are continuously being enacted or proposed, the level of expenditures required for environmental matters could increase in the future. Current and future legislative action and regulatory initiatives could result in changes to operating permits, material changes in operations, increased capital expenditures and operating costs, increased costs of the goods we transport, and decreased demand for products we handle that cannot be assessed with certainty at this time. We may be required to make expenditures to modify operations or install pollution control equipment or release prevention and containment systems that could materially and adversely affect our business, financial condition, results of operations, and liquidity if these expenditures, as with all costs, are not ultimately reflected in the tariffs and other fees we receive for our services.
For example, the U.S. Environmental Protection Agency (EPA) has, in recent years, adopted final rules making more stringent the National Ambient Air Quality Standards (NAAQS) for ozone, sulfur dioxide, and nitrogen dioxide. Emerging rules and permitting requirements implementing these revised standards may require us to install more stringent controls at our facilities, which may result in increased capital expenditures. Governmental restrictions on greenhouse gas emissions, including those that have been or may be imposed in various states or at the federal level, could also result in material increased compliance costs, additional operating restrictions or permitting delays for our business, and an increase in the cost of, and reduction in demand for, the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity. For example, in May 2016, the EPA finalized new rules for volatile organic compound and methane emissions from the oil and gas production, processing, transmission and storage industry. In June 2017, the EPA proposed to stay those requirements for 90 days. The 90-day stay was vacated in July 2017. The EPA also proposed a two-year stay to those requirements in June 2017, and that two-year stay has not yet been finalized. Prior to the inauguration of President Trump, the EPA announced that it intends to develop methane emission standards for existing sources and issued information collection requests to companies with production, gathering and boosting, gas processing, storage, and transmission facilities. In addition, in 2015, the U.S. participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the U.S. in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions, which set greenhouse gas emission reduction goals, every five years beginning in 2020. While the Trump Administration announced its intent to withdraw from the Paris Agreement in June 2017, there are no guarantees that it will not be implemented.
Further, certain of our pipeline facilities may be subject to the pipeline integrity and safety regulations of various federal and state regulatory agencies. In recent years, increased regulatory focus on pipeline integrity and safety has resulted in various proposed or adopted regulations. For example, in June 2016, President Obama signed the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (2016 Pipeline Safety Act) that extends statutory mandate of the Department of Transportation’s Pipeline and Hazardous Materials Administration (PHMSA) under prior legislation through 2019 and, among other things, requires PHMSA to complete certain of its outstanding mandates and develop new safety standards for natural gas



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storage facilities by June 22, 2018. The 2016 Pipeline Safety Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. Additionally, on January 13, 2017, PHMSA announced the issuance of the Pipeline Safety: Safety of Hazardous Liquids Pipelines final rule. However, this was withdrawn following the Trump Administration’s January 20, 2017, announcement that all regulations that had been sent to the Office of the Federal Register, but not yet published, be immediately withdrawn for further review. Compliance with pipeline safety laws and regulations could have a material adverse effect on our results of operations. Further, should we fail to comply with pipeline safety regulations, we could be subject to penalties and fines. PHMSA has the authority to impose civil penalties for pipeline safety violations up to a maximum of approximately $200,000 per day for each violation and approximately $2,000,000 for a related series of violations. This maximum penalty authority established by statute has been and will continue to be adjusted periodically to account for inflation. The implementation of these regulations, and the adoption of future regulations, could require us to make additional capital expenditures, including to install new or modified safety measures, or to conduct new or more extensive maintenance programs at our pipeline facilities.
Severe weather events may have an adverse effect on our assets and operations.
Some members within the scientific community believe that the increasing concentrations of greenhouse gas emissions in the Earth’s atmosphere, among other reasons, may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such climatic events were to occur, they could have an adverse effect on our assets and operations.
We may be unable to obtain or renew permits necessary for our operations, which could inhibit our ability to do business.
Our facilities operate under a number of federal and state permits, licenses, and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. These permits, licenses, approval limits, and standards require a significant amount of monitoring, record keeping, and reporting in order to demonstrate compliance with the underlying permit, license, approval limit, or standard. Noncompliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties, and injunctive relief. A decision by a government agency to deny or delay issuing a new or renewed permit or approval, or to revoke or substantially modify an existing permit or approval, could have a material and adverse effect on our ability to continue operations and on our financial condition, results of operations, and cash flows and our ability to make distributions to our unitholders.
Many of our assets have been in service for many years and, as a result, our maintenance or repair costs may increase in the future. In addition, there could be service interruptions due to unknown events or conditions or increased downtime associated with our pipelines that could have a material and adverse effect on our financial condition, results of operations, and cash flows and our ability to make distributions to our unitholders.
Our pipelines and terminals are generally long-lived assets, and many of them have been in service for many years. The age and condition of our assets could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our results of operations, financial position, or cash flows, as well as our ability to make distributions to our unitholders.



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The tariff rates of our regulated assets are subject to review and possible adjustment by federal and state regulators, which could adversely affect our revenues and our ability to make distributions to our unitholders.
We own pipeline assets in Texas, New Mexico, Tennessee, Louisiana, Mississippi, Arkansas, and Oklahoma, and we provide both interstate and intrastate transportation services for refined petroleum products and crude oil. Many of our pipelines are common carriers and may be required to provide service to any shipper that requests transportation services on our pipelines.
Many of our pipelines provide interstate transportation services that are subject to regulation by FERC under the ICA. FERC uses prescribed rate methodologies for developing and changing regulated rates for interstate pipelines. Shippers may protest (and FERC may investigate) the lawfulness of existing, new, or changed tariff rates. FERC can suspend new or changed tariff rates for up to seven months and can allow new rates to be implemented subject to refund of amounts collected in excess of the rate ultimately found to be just and reasonable. If FERC finds a rate to be unjust and unreasonable, it may order payment of reparations for up to two years prior to the filing of a complaint or investigation, and FERC may prescribe new rates prospectively. We may also be required to respond to requests for information from government agencies, including compliance audits conducted by the FERC.
State agencies may regulate the rates, terms, and conditions of service for our pipelines offering intrastate transportation services, and such agencies could limit our ability to increase our rates or order us to reduce our rates and pay refunds to shippers. State agencies have generally not been aggressive in regulating common carrier pipelines, have generally not investigated the rates, terms, and conditions of service of intrastate pipelines in the absence of shipper complaints, and generally resolve complaints informally.
Under our commercial agreements, we and Valero have agreed to the base tariff rates for all of our pipelines and a mechanism to modify those rates during the term of the agreements. Valero has also agreed not to challenge the base tariff rates or changes to those rates during the term of the agreements, except to the extent such changes are inconsistent with the agreements. These agreements do not, however, prevent any other new or prospective shipper, FERC, or a state agency from challenging our tariff rates or our terms and conditions of service, and due to the complexity of rate making, the lawfulness of any rate is never assured. A successful challenge of any of our rates, or any changes to FERC’s approved rate or index methodologies, could adversely affect our revenues and our ability to make distributions to our unitholders. Similarly, if state agencies in the states in which we offer intrastate transportation services change their policies or aggressively regulate our rates or terms and conditions of service, it could also materially and adversely affect our financial condition, results of operations, and cash flows and our ability to make distributions to our unitholders.
The FERC’s ratemaking policies are subject to change and may impact the rates charged and revenues received on our interstate oil pipelines. In July 2016, in United Airlines, Inc. v. FERC, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated a pair of FERC orders to the extent they permitted an interstate petroleum products pipeline owned by a master limited partnership to include an income tax allowance in its cost-of-service-based rates. The D.C. Circuit held that the FERC had failed to demonstrate that the inclusion of an income tax allowance in the pipeline’s rates would not lead to an over-recovery of costs attributable to regulated service. The D.C. Circuit instructed the FERC on remand to fashion a remedy to ensure that the pipeline’s rates do not allow it to over-recover its costs. In response to the D.C. Circuit’s remand, in December 2016, the FERC issued a Notice of Inquiry seeking comments regarding how to address any potential double recovery resulting from the FERC’s current income tax allowance and rate of return policies. Initial comments were filed in March 2017 with reply comments filed in April 2017. We cannot currently predict when the FERC will issue an order in the Notice of Inquiry proceeding or what



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action the FERC may take in any such order. Depending upon the resolution of these issues, the cost of service rates of any interstate liquids pipeline could be affected to the extent it proposes new rates or changes its existing rates or if its rates are subject to complaint or are challenged by the FERC.
In addition, there is not always a clear boundary between interstate and intrastate pipeline transportation services, and such determinations are fact-dependent and made on a case-by-case basis. Our undivided interest in the McKee to El Paso pipeline currently provides transportation services pursuant to an intrastate tariff that is subject to regulation by the TRRC. Because a portion of this pipeline crosses New Mexico and our transportation services may be interstate in nature, we applied for a waiver of the tariff filing and reporting requirements of the ICA for our portion of the pipeline, which the FERC conditionally granted. The FERC’s conditions for granting the waiver include that we maintain all books and records in a manner consistent with the Uniform System of Accounts and that we immediately report any change in the circumstances on which the waiver was granted.
If Valero fails to provide the personnel necessary to conduct our operations, our ability to manage our business and continue our growth could be negatively impacted.
Valero is responsible for providing the personnel necessary to conduct our operations, including the executive officers of our general partner. We depend on the services of these individuals. If their services are unavailable to us for any reason, we may be required to hire other personnel to manage and operate our company. We cannot assure our unitholders that we would be able to locate or employ such qualified personnel on acceptable terms or at all.
Terrorist or cyber-attacks and threats, or escalation of military activity in response to these attacks, could have a material and adverse effect on our financial condition, results of operations, and cash flows and our ability to make distributions to our unitholders.
Terrorist attacks and threats, cyber-attacks, or escalation of military activity in response to these attacks, may have significant effects on general economic conditions, fluctuations in consumer confidence and spending, and market liquidity, each of which could materially and adversely affect our business. Strategic targets, such as energy-related assets and transportation assets, may be at greater risk of future terrorist or cyber-attacks than other targets in the U.S. We do not maintain specialized insurance for possible liability or loss resulting from a cyber-attack on our assets that may shut down all or part of our business. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital including our ability to repay or refinance debt. It is possible that any of these occurrences, or a combination of them, could have a material and adverse effect on our financial condition, results of operations, and cash flows and our ability to make distributions to our unitholders.
A significant interruption related to our information technology systems could adversely affect our business.
Our information technology systems and network infrastructure may be subject to unauthorized access or attack, which could result in a loss of intellectual property, proprietary information or employee, customer or vendor data; public disclosure of sensitive information; increased costs to prevent, respond to or mitigate cybersecurity events; systems interruption; or the disruption of our business operations. A breach could also originate from, or compromise, our customers’ and vendors’ or other third-party networks outside of our control. A breach may also result in legal claims or proceedings against us by our unitholders, employees, customers and vendors. There can be no assurance that our infrastructure protection technologies and disaster recovery plans can prevent a technology systems breach or systems failure, which could have a material adverse effect on our financial position or results of operations. Furthermore, the continuing and evolving threat of cyber-attacks has resulted in increased regulatory focus on prevention. To the extent we face



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increased regulatory requirements, we may be required to expend significant additional resources to meet such requirements.
Our customers’ operating results are seasonal and generally lower in the first and fourth quarters of the year. Our customers depend on favorable weather conditions in the spring and summer months.
Demand for gasoline is generally higher during the summer months than during the winter months due to seasonal increases in motor vehicle traffic. As a result, our customers’ operating results are generally lower for the first and fourth quarters of each year. Unfavorable weather conditions during the spring and summer months and a resulting lack of the expected seasonal upswings in traffic and sales could adversely affect our customers’ business, financial condition, and results of operations, which may adversely affect our business, financial conditions, and results of operations.
The level and terms of Valero’s indebtedness and its credit ratings could adversely affect our ability to grow our business and our ability to make distributions to our unitholders and our credit ratings and profile.
If the level of Valero’s indebtedness increases significantly in the future, it would increase the risk that Valero may default on its obligations to us under our commercial agreements. The terms of Valero’s indebtedness may limit its ability to borrow additional funds and may impact our operations in a similar manner. If Valero were to default under its debt obligations, Valero’s creditors could attempt to assert claims against our assets during the litigation of their claims against Valero. The defense of any such claims could be costly and could materially impact our financial condition, even absent any adverse determination. If these claims were successful, our ability to meet our obligations to our creditors, make distributions, and finance our operations could be materially and adversely affected. If one or more credit rating agencies were to downgrade Valero’s credit rating, we could experience an increase in our borrowing costs or difficulty accessing the capital markets. Such a development could adversely affect our ability to grow our business and to make distributions to our unitholders.
Risks Inherent in an Investment in Us
Our general partner and its affiliates, including Valero, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our unitholders. Additionally, we have no control over the business decisions and operations of Valero, and Valero is under no obligation to adopt a business strategy that favors us.
As of January 31, 2018, Valero owned a 66.2 percent limited partner interest in us and owns and controls our general partner. Although our general partner has a duty to manage us in a manner that is not adverse to the best interests of us and our unitholders, because it is a wholly owned subsidiary of Valero, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is beneficial to Valero. Conflicts of interest may arise between Valero and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, the general partner may favor its own interests and the interests of its affiliates, including Valero, over the interests of our common unitholders. These conflicts include, among others, the following situations:
neither our partnership agreement nor any other agreement requires Valero to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by Valero to increase or decrease refinery production, shut down or reconfigure a refinery, shift the focus of its investment and growth to areas not served by our assets, or undertake acquisition opportunities for itself;



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Valero has an economic incentive to cause us to not seek higher rates and fees, even if such higher rates and fees would reflect those that could be obtained in arm’s-length, third-party transactions;
Valero’s directors and officers have a fiduciary duty to make decisions beneficial to the stockholders of Valero, which may be contrary to our interests; in addition, many of the officers and directors of our general partner are also officers and/or directors of Valero and will owe fiduciary duties to Valero and its stockholders;
Valero may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;
our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limiting our general partner’s liabilities, and restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;
except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;
disputes may arise under our commercial agreements with Valero;
our general partner will determine the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;
our general partner will determine the amount and timing of many of our capital expenditures and whether a capital expenditure is classified as an expansion capital expenditure, which would not reduce operating surplus, or a maintenance capital expenditure, which would reduce our operating surplus. This determination can affect the amount of cash that is distributed to our unitholders;
our general partner will determine which costs incurred by it are reimbursable by us;
our general partner may cause us to borrow funds in order to permit the payment of distributions, even if the purpose or effect of the borrowing is to make incentive distributions;
our partnership agreement permits us to classify up to $50 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings, or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions to our general partner in respect of the general partner units or the incentive distribution rights;
our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
our general partner intends to limit its liability regarding our contractual and other obligations;
our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if it and its affiliates own more than 80 percent of the common units. As of January 31, 2018, Valero owned 67.5 percent of our common units, and, as a result, Valero did not have the ability to exercise the limited call right;
our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including under the omnibus agreement and our commercial agreements with Valero;
our general partner decides whether to retain separate counsel, accountants, or others to perform services for us; and



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our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights or the elimination of our incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner, which we refer to as our conflicts committee, or our unitholders. Any such action may result in lower distributions to our common unitholders in certain situations.
Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors, and owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement, or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity, or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
Our partnership agreement requires that we distribute all of our available cash to our unitholders and we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
In addition, because we intend to distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our debt agreements on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.
Our general partner has certain incentive distribution rights that reduce the amount of our cash available for distribution to our common unitholders.
Our general partner currently holds a general partner interest in us that entitles it to receive two percent of all distributions paid to our common unitholders and incentive distribution rights that entitle it to receive an increasing percentage (13 percent, 23 percent and 48 percent) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and certain target distribution levels have been achieved. Throughout 2017, our general partner was at the top tier of the incentive distribution rights scale. Because a higher percentage of our cash is allocated to our general partner due to our incentive distribution rights, it is more difficult for us to increase the amount of distributions to our unitholders and our cost of capital is higher, making investments, capital expenditures and acquisitions, and therefore, future growth, more costly.
The fees and reimbursements due to our general partner and its affiliates, including Valero, for services provided to us or on our behalf will reduce our distributable cash flow. In certain cases, the amount and



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timing of such reimbursements will be determined by our general partner and its affiliates, including Valero.
Pursuant to our partnership agreement, we reimburse our general partner and its affiliates, including Valero, for expenses they incur and payments they make on our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. Pursuant to the amended and restated omnibus agreement, as amended, we pay an annual fee of $13.2 million to Valero for general and administrative services and reimburse Valero for any out-of-pocket costs and expenses incurred by Valero in providing these services to us. In the event we acquire additional assets from Valero in the future, we may agree to increase such annual fee. In addition, we are required to reimburse our general partner for its payments to Valero pursuant to the services and secondment agreement for the wages, benefits, and other costs of Valero employees seconded to our general partner to perform operational and maintenance services at certain of our pipeline and terminal systems. Each of these payments will be made prior to making any distributions on our common units. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates reduces our cash flows, and, as a result, reduces our ability to make distributions to our unitholders. There is no limit on the fees and expense reimbursements that we may be required to pay to our general partner and its affiliates.
Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:    
whenever our general partner (acting in its capacity as our general partner), the board of directors of our general partner, or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner, and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was not adverse to our best interests, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
our general partner is not liable to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;
our general partner and its officers and directors are not liable to us or our limited partners for monetary damages resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
our general partner is not in breach of its obligations under the partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:
approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;
approved by the vote of a majority of our outstanding common units, excluding any common units owned by our general partner and its affiliates;



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determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
determined by the board of directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth subbullet points above, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
If a unitholder is not an “Eligible Holder,” the unitholder’s common units may be subject to redemption.
Our partnership agreement includes certain requirements regarding those investors who may own our common units. “Eligible Holders” are limited partners whose (a) federal income tax status is not reasonably likely to have a material and adverse effect on the rates that can be charged by us on assets that are subject to regulation by FERC or an analogous regulatory body and (b) nationality, citizenship, or other related status would not create a substantial risk of cancellation or forfeiture of any property in which we have an interest, in each case as determined by our general partner with the advice of counsel. If the unitholder is not an Eligible Holder, in certain circumstances as set forth in our partnership agreement, the unitholder’s units may be redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.
Our partnership agreement restricts the voting rights of unitholders owning 20 percent or more of our common units.
Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20 percent or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot be used to vote on any matter.
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. For example, unlike a holder of stock in a public corporation, our unitholders do not have “say on pay” advisory voting rights. Unitholders did not elect our general partner or the board of directors of our general partner and will have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis. The board of directors of our general partner is chosen by the sole member of our general partner, which is a wholly owned subsidiary of Valero. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.



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Even if holders of our common units are dissatisfied, they cannot remove our general partner without its consent.
Our unitholders are not able to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66⅔ percent of all outstanding common units is required to remove our general partner. As of January 31, 2018, Valero owned 67.5 percent of our common units (excluding common units held by officers and directors of our general partner and Valero).
Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. Furthermore, our partnership agreement does not restrict the ability of Valero to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.
The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party, it will have less incentive to grow our partnership and increase distributions. A transfer of incentive distribution rights by our general partner could reduce the likelihood of Valero selling or contributing additional assets to us, which in turn would impact our ability to grow our asset base.
We may issue additional units without unitholder approval, which would dilute unitholder interests.
At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such limited partner interests. Further, there are no limitations in our partnership agreement on our ability to issue equity securities that rank equal or senior to our common units as to distributions or in liquidation or that have special voting rights and other rights. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
our existing unitholders’ proportionate ownership interest in us will decrease;
the amount of cash we have available to distribute on each unit may decrease;
because the amount payable to holders of incentive distribution rights is based on a percentage of total available cash, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same;
the ratio of taxable income to distributions may increase;



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the relative voting strength of each previously outstanding unit may be diminished; and
the market price of our common units may decline.
Valero may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.
As of January 31, 2018, Valero held 46,768,586 of our common units. Additionally, we have agreed to provide Valero with certain registration rights under applicable securities laws. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.
Our general partner’s discretion in establishing cash reserves may reduce the amount of cash we have available to distribute to unitholders.
Our partnership agreement requires our general partner to deduct from operating surplus the cash reserves that it determines are necessary to fund our future operating expenditures. In addition, our partnership agreement permits the general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of our distribution to unitholders.
Our general partner has a limited call right that may require the unitholders to sell common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80 percent of our then-outstanding common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. As of January 31, 2018, our general partner and its affiliates owned less than 80 percent of our outstanding common units, but in the future, we may engage in transactions with Valero pursuant to which we may issue additional common units to Valero.
Our general partner, or any transferee holding a majority of the incentive distribution rights, may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to the incentive distribution rights, without the approval of the conflicts committee of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
Our general partner has the right, at any time when the holders have received incentive distributions at the highest level to which they are entitled (48 percent) for each of the prior four consecutive fiscal quarters (and the amount of each such distribution did not exceed adjusted operating surplus for each such quarter), to reset the minimum quarterly distribution and the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Given our distribution history, our general partner is currently able to exercise this right. Following a reset election, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution. Our general partner has the right to



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transfer the incentive distribution rights at any time, in whole or in part, and any transferee holding a majority of the incentive distribution rights shall have the same rights as our general partner with respect to resetting target distributions.
In the event of a reset of the minimum quarterly distribution and the target distribution levels, the holders of the incentive distribution rights will be entitled to receive, in the aggregate, the number of common units equal to that number of common units that would have entitled the holders to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions on the incentive distribution rights in the prior two quarters. Our general partner will also be issued the number of general partner units necessary to maintain the same percentage general partner interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal expansion projects that would not otherwise be sufficiently accretive to distributions per common unit. It is possible, however, that our general partner or a transferee could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units rather than retain the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then-current business environment. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience dilution in the amount of distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels.
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement permits our general partner to limit its liability, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.
Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replace those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:
how to allocate corporate opportunities among us and its other affiliates;
whether to exercise its limited call right;



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whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner;
how to exercise its voting rights with respect to the units it owns;
whether to exercise its registration rights;
whether to elect to reset target distribution levels;
whether to transfer the incentive distribution rights to a third party; and
whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.
By purchasing a common unit, a common unitholder agrees to become bound by the provisions in our partnership agreement, including the provisions discussed above.
If we fail to maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which could have a material and adverse impact on our financial condition, results of operations, and cash flows and our ability to make distributions to our unitholders.
We are required to disclose material changes made in our internal control over financial reporting on a quarterly basis and we are required to assess the effectiveness of our controls annually. Effective internal controls are necessary for us to provide reliable and timely financial reports, to prevent fraud, and to operate successfully as a publicly traded limited partnership. We may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. For example, Section 404 requires us, among other things, annually to review and report on the effectiveness of our internal control over financial reporting. Any failure to develop, implement, or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations.
Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm’s, future conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Any failure to maintain effective internal controls over financial reporting will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have a material and adverse effect on our financial condition, results of operations, and cash flows and our ability to make distributions to our unitholders.
A unitholder’s liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for any and all of our obligations as if a unitholder were a general partner if a court or government agency were to determine that (i) we were conducting business in a state but had not complied with that particular state’s partnership statute; or (ii) a unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other actions under our partnership agreement constitute “control” of our business.



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Our 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, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable both 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 nonrecourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
Because we are a publicly traded limited partnership, the NYSE does not require us to have, and we do not have or intend to have, a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to our affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to a corporation. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.
Tax Risks
Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service (IRS) were to treat us as a corporation for 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 would be substantially reduced.
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes.
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 federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for 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 21 percent for taxable years beginning on or after January 1, 2018, and 35 percent to the extent we were treated as a corporation in any taxable years ending prior to January 1, 2018, and would likely pay state and local income tax at varying rates. Distributions generally would be taxed again to our unitholders 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 our unitholders. Because a tax would be imposed upon us as a corporation, our distributable cash flow would be substantially reduced. In addition, changes in current state law may subject us to additional entity-level taxation by individual states.
Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for



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federal, state, or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels may be adjusted to reflect the impact of that law on us.
The present federal income tax treatment of publicly traded limited partnerships, including us, or an investment in our common units may be modified by administrative or judicial interpretation, or legislative change, at any time, and potentially retroactively. We are unable to predict whether any such modifications will ultimately occur.
Unitholders may be required to pay taxes on their share of our taxable income even if they do not receive any cash distributions from us. A unitholder’s share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, transactions in which we engage or changes in law, and may be substantially different from any estimate we make in connection with a unit offering.
A unitholder’s allocable share of our taxable income will be taxable to it, which may require the unitholder to pay federal income taxes and, in some cases, state and local income taxes, even if the unitholder receives cash distributions from us that are less than the actual tax liability that results from that income or no cash distributions at all.
A unitholder’s share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, which may be affected by numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control, and certain transactions in which we might engage. For example, we may engage in transactions that produce substantial taxable income allocations to some or all of our unitholders without a corresponding increase in cash distributions to our unitholders, such as a sale or exchange of assets, the proceeds of which are reinvested in our business or used to reduce our debt, or an actual or deemed satisfaction of our indebtedness for an amount less than the adjusted issue price of the debt. A unitholder’s ratio of its share of taxable income to the cash received by it may also be affected by changes in law. For instance, under the recently enacted tax reform law known as the Tax Cuts and Jobs Act of 2017, the net interest expense deductions of certain business entities, including us, are limited to 30 percent of such entity’s “adjusted taxable income,” which is generally taxable income with certain modifications. If the limit applies, a unitholder’s taxable income allocations will be more (or its net loss allocations will be less) than would have been the case absent the limitation.
From time to time, in connection with an offering of our units, we may state an estimate of the ratio of federal taxable income to cash distributions that a purchaser of units in that offering may receive in a given period. These estimates depend in part on factors that are unique to the offering with respect to which the estimate is stated, so the expected ratio applicable to other units will be different, and in many cases less favorable, than these estimates. Moreover, even in the case of units purchased in the offering to which the estimate relates, the estimate may be incorrect due to the uncertainties described above, challenges by the IRS to tax reporting positions which we adopt, or other factors. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units.



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If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us, in which case we may require our unitholders and former unitholders to reimburse us for such taxes (including any applicable penalties or interest) or, if we are required to bear such payment, our cash available for distribution to our unitholders might be substantially reduced.
If the IRS makes audit adjustments to income tax returns for tax years beginning after 2017, it may assess and collect taxes (including any applicable penalties and interest) directly from us. We will generally have the ability to shift any such tax liability to our general partner and our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so (and will choose to do so) under all circumstances, or that we will be able to (or choose to) effect corresponding shifts in state income or similar tax liability resulting from the IRS adjustment in states in which we do business in the year under audit or in the adjustment year. If we make payments of taxes, penalties and interest resulting from audit adjustments, we may require our unitholders and former unitholders to reimburse us for such taxes (including any applicable penalties or interest) or, if we are required to bear such payment, our cash available for distribution to our unitholders might be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during that taxable year.
Tax gain or loss on the disposition of our common units could be more or less than expected.
Unitholders who sell common units will recognize gain or loss for 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 a unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in its 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. 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. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income to the unitholder due to potential recapture items, including depreciation recapture.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. 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, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and pay tax on their share of our taxable income. Any tax-exempt entity or non-U.S. person should consult a tax advisor before investing in our common units.
Under the recently enacted tax reform law, if a unitholder sells or otherwise disposes of a common unit, the transferee is required to withhold 10 percent of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferee but were not withheld. However, the Department of the Treasury and the IRS have determined that this withholding requirement should not apply to any disposition of a publicly traded interest in a publicly traded partnership (such as us) until regulations or other guidance



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have been issued clarifying the application of this withholding requirement to dispositions of interests in publicly traded partnerships. Accordingly, while this new withholding requirement does not currently apply to interests in us, there can be no assurance that such requirement will not apply in the future.
We treat each purchaser of 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 the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the 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.
We prorate our items of income, gain, loss, and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, 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 for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this proration method may not be permitted under existing or proposed Treasury Regulations. The U.S. Department of the Treasury recently adopted final Treasury Regulations allowing a similar monthly simplifying convention for taxable years beginning on or after August 3, 2015. However, such regulations do not specifically authorize the use of the proration method we have currently adopted. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.
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, the unitholder would no longer be treated for 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, the unitholder may no longer be treated for federal income 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 distributions received by the unitholder as to those common units could be fully taxable as ordinary income.



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We have adopted certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss, and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss, and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. The IRS may challenge our valuation methods and allocations of taxable income, gain, loss, and deduction between our general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
As a result of investing in our common units, a unitholder 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 federal income taxes, our unitholders will likely be 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 the unitholders do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. We conduct business and/or control assets in Arkansas, Louisiana, Mississippi, New Mexico, Oklahoma, Tennessee, and Texas. Except for Texas, all of these states currently impose a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is each unitholder’s responsibility to file all federal, state, and local tax returns. Unitholders should consult their own tax advisors regarding such matters. Under the tax laws of some states where we conduct business, we may be required to withhold a percentage from amounts to be distributed to a unitholder who is not a resident of that state.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial, or administrative changes and differing interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative, or judicial interpretation at any time. For example, from time to time, the President and members of the U.S. Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships, including elimination of partnership tax treatment for publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Moreover, any such modification could make it more difficult or impossible for us to meet the exception that allows publicly traded partnerships that generate qualifying income to be treated as partnerships (rather than corporations) for U.S. federal income tax purposes, affect or cause us to change our business activities, or affect the tax consequences of an investment in our common units. We are unable to predict whether any such changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.



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Compliance with and changes in tax law could adversely affect our performance.
We are subject to extensive tax laws and regulations, including federal and state income tax laws and transactional taxes such as excise, sales/use, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
We incorporate by reference into this Item our disclosures made in Part II, Item 8 of this report included in Note 7 of Notes to Consolidated Financial Statements under the caption “Litigation Matters.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.



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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Unit Price and Cash Distributions
Our common units are listed on the NYSE under the symbol “VLP.” As of January 31, 2018, there were 7 holders of record of our common units and Valero owned all of our general partner units. There is no established trading market for our general partner units. Our common units represent limited partner interests in us that entitle the holders to the rights and privileges specified in our partnership agreement.
The following table sets forth the range of the daily high and low sales prices per common unit and cash distributions to common unitholders for each quarter of 2017 and 2016.
Quarter Ended
 
High
Sale
Price
 
Low
Sale
Price
 
Quarterly Cash
Distribution
per Unit
 
Record
Date
 
Distribution
Date
2017:
 
 
 
 
 
 
 
 
 
 
December 31
 
$
45.06

 
$
39.52

 
$
0.5075

 
February 5, 2018
 
February 13, 2018
September 30
 
47.50

 
40.00

 
0.4800

 
November 1, 2017
 
November 9, 2017
June 30
 
48.90

 
41.15

 
0.4550

 
August 1, 2017
 
August 10, 2017
March 31
 
51.00

 
44.21

 
0.4275

 
May 2, 2017
 
May 11, 2017
2016:
 
 
 
 
 
 
 
 
 
 
December 31
 
44.86

 
38.90

 
0.4065

 
February 2, 2017
 
February 10, 2017
September 30
 
47.33

 
40.14

 
0.3850

 
November 3, 2016
 
November 10, 2016
June 30
 
49.55

 
42.31

 
0.3650

 
August 1, 2016
 
August 9, 2016
March 31
 
52.20

 
39.02

 
0.3400

 
May 2, 2016
 
May 10, 2016

Distributions of Available Cash
Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date.
Definition of Available Cash
Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:
less, the amount of cash reserves established by our general partner to:
provide for the proper conduct of our business (including reserves for our future capital expenditures and anticipated future credit needs requirements and refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceedings or rate proceedings under applicable law subsequent to that quarter);
comply with applicable law, any of our or our subsidiaries’ debt instruments or other agreements; or
provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for



44


distributions if the effect of the establishment of such reserves will prevent us from paying the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);
plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.
The effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our partnership agreement, working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners, and with the intent of the borrower to repay such borrowings within 12 months with funds other than from additional working capital borrowings.
Intent to Distribute the Minimum Quarterly Distribution
We intend to make at least the minimum quarterly distribution to holders of our common units of $0.2125 per unit, or $0.85 per unit on an annualized basis, to the extent we have sufficient available cash after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.
General Partner Interest and Incentive Distribution Rights
Our general partner is currently entitled to 2.0 percent of all quarterly distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute up to a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s initial 2.0 percent interest in these distributions will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0 percent general partner interest.
Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 48 percent, of the cash we distribute from operating surplus (as defined in our partnership agreement) in excess of $0.244375 per unit per quarter. The maximum distribution of 48 percent does not include any distributions that our general partner or its affiliates may receive on common or general partner units that they own.
Percentage Allocations of Available Cash from Operating Surplus
The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit Target Amount.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0 percent general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2.0 percent general partner interest, our general partner has not transferred its incentive distribution rights, and that there are no arrearages on common units.



45


 
 
Total Quarterly
Distribution per Unit
Target Amount
 
Marginal Percentage
Interest in Distributions
 
 
 
Unitholders
 
General Partner
Minimum Quarterly Distribution
 
$0.2125
 
98%
 
2%
First Target Distribution
 
above $0.2125 up to $0.244375
 
98%
 
2%
Second Target Distribution
 
above $0.244375 up to $0.265625
 
85%
 
15%
Third Target Distribution
 
above $0.265625 up to $0.31875
 
75%
 
25%
Thereafter
 
$0.31875
 
50%
 
50%
Securities Authorized for Issuance Under Equity Compensation Plans
The information appearing in Part III, Item 12., “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters—Securities Authorized for Issuance Under Equity Compensation Plans,” is incorporated herein by reference.




46


ITEM 6. SELECTED FINANCIAL DATA
The selected financial data shown in the table below was derived from the consolidated financial statements of the Partnership and from the combined financial statements of our Predecessor (defined below). We completed our IPO of common units representing limited partner interests on December 16, 2013. Since the IPO, we have acquired businesses and assets from Valero. Each business acquisition was accounted for as the transfer of a business between entities under the common control of Valero. Accordingly, this financial data has been retrospectively adjusted to include the historical results of those business acquisitions for all periods presented prior to the effective dates of each acquisition. We refer to the historical results prior to the IPO and the effective dates of each acquisition from Valero as those of our “Predecessor.” During 2017, we acquired assets from Valero that were accounted for as transfers of assets between entities under the common control of Valero. Our prior period financial statements and financial information were not retrospectively adjusted for these asset acquisitions. See Note 2 in Notes to Consolidated Financial Statements for further discussion of our acquisitions from Valero.
The following table should be read together with Item 7., “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and accompanying notes in Item 8., “Financial Statements and Supplementary Data.” The amounts below are presented in thousands, except per unit amounts. Net income per unit is only calculated after the IPO, as no units were outstanding prior to December 16, 2013.
 
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
 
2014
 
2013
Operating revenues – related party
 
$
452,005

 
$
362,619

 
$
243,624

 
$
129,180

 
$
124,985

Net income (loss)
 
238,433

 
188,831

 
71,312

 
(33,361
)
 
(25,403
)
Net income attributable to partners
 
238,433

 
204,253

 
131,878

 
59,281

 
2,041

Limited partners’ interest in net income
 
189,320

 
180,700

 
125,809

 
57,902

 
2,000

Net income per limited partner unit –
basic and diluted:
 
 
 
 
 
 
 
 
 
 
Common units
 
2.77

 
2.85

 
2.12

 
1.01

 
0.03

Subordinated units
 

 
2.38

 
2.07

 
1.01

 
0.03

Cash distribution declared per unit
 
1.8700

 
1.4965

 
1.1975

 
0.9410

 
0.0370

Cash and cash equivalents
 
42,052

 
71,491

 
80,783

 
236,579

 
375,118

Total assets (a)
 
1,517,352

 
979,257

 
962,121

 
1,082,464

 
1,127,124

Debt and capital lease obligations, net of current portion
 
905,283

 
525,355

 
175,246

 
1,519

 
3,079

Notes payable – related party
 
370,000

 
370,000

 
370,000

 

 

 
 
 
 
 
 
 
 
 
 
 
 
(a) Amounts reported as of December 31, 2016, 2015, and 2014 have been reclassified to conform to the 2017 presentation, which reflects the gross presentation of receivables – related party and accounts payable – related party.




47


ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with Items 1 and 2., “Business and Properties,” Item 1A., “Risk Factors,” and Item 8., “Financial Statements and Supplementary Data,” included in this report.
CAUTIONARY STATEMENT FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report, including without limitation our disclosures below under the heading “OUTLOOK,” includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words “anticipate,” “believe,” “expect,” “plan,” “intend,” “estimate,” “project,” “projection,” “predict,” “budget,” “forecast,” “goal,” “guidance,” “target,” “could,” “should,” “may,” and similar expressions.
Although we believe the assumptions upon which these forward-looking statements are based are reasonable, any of these assumptions could prove to be inaccurate and the forward-looking statements based on these assumptions could be incorrect. The matters discussed in these forward-looking statements are subject to risks, uncertainties, and other factors that could cause actual results and trends to differ materially from those made, projected, or implied in or by the forward-looking statements depending on a variety of uncertainties or other factors including, but not limited to:
the suspension, reduction, or termination of Valero’s obligation under our commercial agreements and our services and secondment agreement;
changes in global economic conditions on Valero’s business and the business of its suppliers, customers, business partners, and credit lenders;
a material decrease in Valero’s profitability;
disruptions due to equipment interruption or failure at our facilities, Valero’s facilities, or third-party facilities on which our business or Valero’s business is dependent;
the risk of contract cancellation, non-renewal, or failure to perform by Valero’s customers, and Valero’s inability to replace such contracts and/or customers;
Valero’s and our ability to remain in compliance with the terms of its and our outstanding indebtedness;
the timing and extent of changes in commodity prices and demand for Valero’s refined petroleum products;
our ability to obtain credit and financing on acceptable terms in light of uncertainty and illiquidity in credit and capital markets;
actions of customers and competitors;
changes in our cash flows from operations;
state and federal environmental, economic, health and safety, energy, and other policies and regulations, including those related to climate change and any changes therein, and any legal or regulatory investigations, delays, or other factors beyond our control;
operational hazards inherent in refining operations and in transporting and storing crude oil and refined petroleum products;
earthquakes or other natural disasters affecting operations;
changes in capital requirements or in execution of planned capital projects;



48


the availability and costs of crude oil, other refinery feedstocks, and refined petroleum products;
changes in the cost or availability of third-party vessels, pipelines, and other means of delivering and transporting crude oil, feedstocks, and refined petroleum products;
direct or indirect effects on our business resulting from actual or threatened terrorist incidents or acts of war;
weather conditions affecting our or Valero’s operations or the areas in which Valero markets its refined petroleum products;
seasonal variations in demand for refined petroleum products;
adverse rulings, judgments, or settlements in litigation or other legal or tax matters, including unexpected environmental remediation costs in excess of any accruals, which affect us or Valero;
risks related to labor relations and workplace safety;
changes in insurance markets impacting costs and the level and types of coverage available; and
political developments.
Any one of these factors, or a combination of these factors, could materially affect our future results of operations and affect whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.
All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.
OVERVIEW
We are a master limited partnership formed by Valero to own, operate, develop, and acquire crude oil and refined petroleum products pipelines, terminals, and other logistics assets. We generate operating revenues by providing fee-based transportation and terminaling services. During 2017, we acquired businesses and assets and began receiving fees for services provided by these businesses and assets commencing on the effective date of each acquisition. See Note 2 of Notes to Consolidated Financial Statements for further discussion of our acquisitions. Our assets consist of crude oil and refined petroleum products pipeline and terminal systems in the U.S. Gulf Coast and U.S. Mid-Continent regions that are integral to the operations of ten of Valero’s refineries.
We reported net income and net income attributable to partners of $238.4 million for the year ended December 31, 2017. This compares to net income of $188.8 million and net income attributable to partners of $204.3 million for the year ended December 31, 2016.
The increase in net income of $49.6 million was due primarily to a $70.5 million increase in operating income driven by contributions from our McKee, Meraux, Three Rivers, and Port Arthur terminals, which we acquired from Valero in April 2016, September 2016, and November 2017, as further described in Note 2 of Notes to Consolidated Financial Statements. The increase in operating income was offset by a $21.1 million increase in “interest and debt expense, net of capitalized interest” as a result of incremental borrowings and a higher effective interest rate in 2017.
Net income attributable to partners represents our results of operations only and excludes the results of our Predecessor. Our Predecessor’s results are those that are associated with the McKee, Meraux, and Three



49


Rivers terminals for the periods prior to the dates we acquired these businesses from Valero and represent only the costs of operating the terminals. See Note 1 of Notes to Consolidated Financial Statements for the reason that results of businesses acquired from Valero are included with our results for periods prior to their dates of acquisition. The increase in net income attributable to partners of $34.2 million in 2017 compared to 2016 is due primarily to the operating results generated by our McKee, Meraux, Three Rivers, and Port Arthur terminals and our Red River crude system and Parkway pipeline in 2017. See Note 2 of Notes to Consolidated Financial Statements for discussion of our acquisitions.
Additional analysis of the changes in the components of net income is provided below under “RESULTS OF OPERATIONS.”
OUTLOOK
All of our operating revenues are generated from fee-based arrangements with Valero, and the amount of operating revenues we generate depends on the volumes of crude oil and refined petroleum products owned by Valero that we transport through our pipelines and handle at our terminals. These volumes are primarily affected by the reliability of Valero’s refineries served by our pipelines and terminals as well as the supply of, and demand for, crude oil and refined petroleum products in the markets served by our assets. However, our arrangements with Valero contain minimum volume commitments that require Valero to ship minimum volumes during each calendar quarter or pay us a deficiency payment. Deficiency payments are applied as a credit for volumes transported on the applicable pipeline or terminal system in excess of its minimum volume commitment during the following four quarters. If it is remote that Valero will utilize these payments, the amount of the expected unused credits will be recognized as operating revenues in the period when that determination is made. Valero has historically met or exceeded most of its minimum volume commitments, and we expect that Valero will transport volumes through our pipelines and throughput volumes at our terminals in 2018 generally consistent with historical levels.
Effective March 31, 2017, we entered into an agreement with Diamond Green Diesel Holdings, LLC (DGD), a joint venture consolidated by Valero, to construct and operate a rail loading facility located at Valero’s St. Charles Refinery for the purpose of loading DGD’s renewable diesel onto railcars. The construction of the rail loading facility was completed in April 2017, and we began providing services to DGD in May 2017. In addition, we agreed to construct a new 180,000 barrel storage tank and provide storage services to DGD. The construction of the new tank is expected to be completed in the first quarter of 2018. This agreement contains minimum commitments for DGD’s use of the assets.
On November 1, 2017, we acquired our Parkway pipeline and Port Arthur terminal from Valero for total consideration of $200.0 million and $308.0 million, respectively. See Note 2 of Notes to Consolidated Financial Statements for further discussion of these acquisitions. We expect our throughput volumes and revenues to increase in 2018 from the full year of operations of these assets.




50


RESULTS OF OPERATIONS
The following tables highlight our results of operations and our operating performance for the years ended December 31, 2017, 2016, and 2015. The narrative following these tables provides an analysis of our results of operations.
2017 Compared to 2016
Results of Operations
(in thousands, except per unit amounts)
 
 
Year Ended December 31,
 
 
2017
 
2016
 
Change
Operating revenues – related party
 
$
452,005

 
$
362,619

 
$
89,386

Costs and expenses:
 
 
 
 
 
 
Cost of revenues (excluding depreciation expense reflected below)
 
108,374

 
96,115

 
12,259

Depreciation expense
 
52,475

 
45,965

 
6,510

Other operating expenses
 
577

 

 
577

General and administrative expenses
 
15,549

 
15,965

 
(416
)
Total costs and expenses
 
176,975

 
158,045

 
18,930

Operating income
 
275,030

 
204,574

 
70,456

Other income, net
 
753

 
284

 
469

Interest and debt expense, net of capitalized interest
 
(36,015
)
 
(14,915
)
 
(21,100
)
Income before income tax expense
 
239,768

 
189,943

 
49,825

Income tax expense
 
1,335

 
1,112

 
223

Net income
 
238,433

 
188,831

 
49,602

Less: Net loss attributable to Predecessor
 

 
(15,422
)
 
15,422

Net income attributable to partners
 
238,433

 
204,253

 
34,180

Less: General partner’s interest in net income
 
49,113

 
23,553

 
25,560

Limited partners’ interest in net income
 
$
189,320

 
$
180,700

 
$
8,620

 
 
 
 
 
 
 
Net income per limited partner unit – basic and diluted:
 
 
 
 
Common units
 
$
2.77

 
$
2.85

 
 
Subordinated units
 
$

 
$
2.38

 
 
 
 
 
 
 
 
 
Weighted average limited partner units outstanding – basic and diluted:
 
 
 
 
Common units
 
68,220

 
48,817

 
 
Subordinated units
 

 
17,463

 
 



51


Operating Highlights and Other Financial Information
(in thousands, except throughput, per barrel, and per unit amounts)

 
 
Year Ended December 31,
 
 
2017
 
2016
 
Change
Operating highlights:
 
 
 
 
 
 
Pipeline transportation:
 
 
 
 
 
 
Pipeline transportation revenues
 
$
100,631

 
$
78,451

 
$
22,180

Pipeline transportation throughput (BPD) (a)
 
964,198

 
829,269

 
134,929

Average pipeline transportation revenue per barrel (b)
 
$
0.29

 
$
0.26

 
$
0.03

 
 
 
 
 
 
 
Terminaling:
 
 
 
 
 
 
Terminaling revenues
 
$
347,996

 
$
283,628

 
$
64,368

Terminaling throughput (BPD)
 
2,889,361

 
2,265,150

 
624,211

Average terminaling revenue per barrel (b)
 
$
0.33

 
$
0.34

 
$
(0.01
)
 
 
 
 
 
 
 
Storage and other revenues
 
$
3,378

 
$
540

 
$
2,838

 
 
 
 
 
 
 
Total operating revenues – related party
 
$
452,005

 
$
362,619

 
$
89,386

 
 
 
 
 
 
 
Capital expenditures:
 
 
 
 
 
 
Maintenance
 
$
8,954

 
$
13,027

 
$
(4,073
)
Expansion
 
29,562

 
10,129

 
19,433

Total capital expenditures
 
38,516

 
23,156

 
15,360

Less: Capital expenditures attributable to Predecessor
 

 
3,394

 
(3,394
)
Capital expenditures attributable to Partnership
 
$
38,516

 
$
19,762

 
$
18,754

 
 
 
 
 
 
 
Other financial information:
 
 
 
 
 
 
Distribution declared per unit
 
$
1.8700

 
$
1.4965

 


 
 
 
 
 
 
 
Distribution declared:
 
 
 
 
 
 
Limited partner units – public
 
$
42,051

 
$
32,382

 
 
Limited partner units – Valero
 
86,503

 
67,560

 
 
General partner units – Valero
 
47,897

 
21,648

 
 
Total distribution declared
 
$
176,451

 
$
121,590

 
 
______________
(a)
Represents the sum of volumes transported through each separately tariffed pipeline segment divided by the number of days in the period.
(b)
Average revenue per barrel is calculated as revenue divided by throughput for the period. Throughput is derived by multiplying the throughput barrels per day (BPD) by the number of days in the period.



52


Operating revenues increased $89.4 million, or 25 percent, in 2017 compared to 2016. The increase was due primarily to the following:
Incremental throughput from acquired businesses and assets. We generated incremental terminaling revenues of $56.2 million in 2017 from our McKee, Meraux, Three Rivers, and Port Arthur terminals. The McKee terminal was acquired in April 2016, the Meraux and Three Rivers terminals were acquired in September 2016, and the Port Arthur terminal was acquired in November 2017. In addition, we generated incremental pipeline revenues of $14.6 million in 2017 from our Red River crude system and our Parkway pipeline, which were acquired in January 2017 and November 2017, respectively.
Higher throughput volumes. We experienced an 8 percent and 10 percent increase in volumes handled at our other terminals and pipeline systems, respectively, in 2017 compared to 2016. The increase in volumes had a favorable impact to our operating revenues of $15.8 million.
Operating revenues from our DGD rail loading facility. Our DGD rail loading facility, which was placed in service in May 2017, generated operating revenues of $2.8 million in 2017.
Cost of revenues (excluding depreciation expense reflected below) increased $12.3 million, or 13 percent, in 2017 compared to 2016. The increase was due primarily to operating expenses of $3.9 million related to our Parkway pipeline and Port Arthur terminal, which were acquired in November 2017; $2.2 million related to our Red River crude system, which was acquired in January 2017; and $2.0 million related to our DGD rail loading facility, which began operations in May 2017. We also incurred higher maintenance expense of $4.1 million at our Houston and Corpus Christi terminals and our Lucas and Collierville crude systems due primarily to inspection activity.
Depreciation expense increased $6.5 million, or 14 percent, in 2017 compared to 2016 due primarily to depreciation expense recognized on the assets that compose our Red River crude system, Parkway pipeline, and Port Arthur terminal, which were acquired in 2017.
Other operating expenses reflects the uninsured portion of our property damage losses and repair costs incurred in 2017 as a result of damages caused by Hurricane Harvey primarily at our Houston terminal and Port Arthur products system.
General and administrative expenses decreased $416,000, or 3 percent, in 2017 compared to 2016 due primarily to acquisition costs (legal and investment advisor fees) of $832,000 incurred in 2016 in connection with our acquisitions of the McKee, Meraux, and Three Rivers terminals. The decrease in acquisition costs in 2017 was partially offset by incremental costs of $319,000 related to the management fee charged to us by Valero in connection with acquired businesses and assets.
“Interest and debt expense, net of capitalized interest” increased $21.1 million in 2017 compared to 2016 due primarily to the following:
Incremental interest expense incurred on the Senior Notes. In December 2016, we issued $500.0 million of 4.375 percent senior notes due December 2026 (Senior Notes). We used the proceeds of the Senior Notes to repay $494.0 million of outstanding borrowings under our revolving credit facility. The interest rate on the Senior Notes is higher than our revolving credit facility, thereby increasing the effective interest rate in 2017. Incremental interest expense resulting from the Senior Notes was approximately $8.9 million in 2017.



53


Incremental borrowings in connection with acquisitions. In connection with the acquisition of the McKee, Meraux, Three Rivers, and Port Arthur terminals and the Parkway pipeline, we borrowed $729.0 million under our revolving credit facility. Interest expense on the incremental borrowings was approximately $6.1 million in 2017.
Higher interest rates in 2017. Borrowings on our revolving credit facility and subordinated credit agreements with Valero bear interest at variable rates. We incurred additional interest of $5.1 million in 2017 on these borrowings due to higher interest rates in 2017 compared to 2016.



54


2016 Compared to 2015

Results of Operations
(in thousands, except per unit amounts)
 
 
Year Ended December 31,
 
 
2016
 
2015
 
Change
Operating revenues – related party
 
$
362,619

 
$
243,624

 
$
118,995

Costs and expenses:
 
 
 
 
 
 
Cost of revenues (excluding depreciation expense reflected below)
 
96,115

 
105,973

 
(9,858
)
Depreciation expense
 
45,965

 
45,678

 
287

General and administrative expenses
 
15,965

 
14,520

 
1,445

Total costs and expenses
 
158,045

 
166,171

 
(8,126
)
Operating income
 
204,574

 
77,453

 
127,121

Other income, net
 
284

 
223

 
61

Interest and debt expense, net of capitalized interest
 
(14,915
)
 
(6,113
)
 
(8,802
)
Income before income tax expense
 
189,943

 
71,563

 
118,380

Income tax expense
 
1,112

 
251

 
861

Net income
 
188,831

 
71,312

 
117,519

Less: Net loss attributable to Predecessor
 
(15,422
)
 
(60,566
)
 
45,144

Net income attributable to partners
 
204,253

 
131,878

 
72,375

Less: General partner’s interest in net income
 
23,553

 
6,069

 
17,484

Limited partners’ interest in net income
 
$
180,700

 
$
125,809

 
$
54,891

 
 
 
 
 
 
 
Net income per limited partner unit – basic and diluted:
 
 
 
 
Common units
 
$
2.85

 
$
2.12

 
 
Subordinated units
 
$
2.38

 
$
2.07

 
 
 
 
 
 
 
 
 
Weighted average limited partner units outstanding –
     basic and diluted:
 
 
 
 
Common units
 
48,817

 
31,222

 
 
Subordinated units
 
17,463

 
28,790

 
 



55


Operating Highlights and Other Financial Information
(in thousands, except throughput, per barrel, and per unit amounts)

 
 
Year Ended December 31,
 
 
2016
 
2015
 
Change
Operating highlights:
 
 
 
 
 
 
Pipeline transportation:
 
 
 
 
 
 
Pipeline transportation revenues
 
$
78,451

 
$
81,435

 
$
(2,984
)
Pipeline transportation throughput (BPD) (a)
 
829,269

 
949,884

 
(120,615
)
Average pipeline transportation revenue per barrel (b)
 
$
0.26

 
$
0.23

 
$
0.03

 
 
 
 
 
 
 
Terminaling:
 
 
 
 
 
 
Terminaling revenues
 
$
283,628

 
$
161,649

 
$
121,979

Terminaling throughput (BPD)
 
2,265,150

 
1,340,407

 
924,743

Average terminaling revenue per barrel (b)
 
$
0.34

 
$
0.33

 
$
0.01

 
 
 
 
 
 
 
Storage and other revenues
 
$
540

 
$
540

 
$

 
 
 
 
 
 
 
Total operating revenues – related party
 
$
362,619

 
$
243,624

 
$
118,995

 
 
 
 
 
 
 
Capital expenditures:
 
 
 
 
 
 
Maintenance
 
$
13,027

 
$
10,828

 
$
2,199

Expansion
 
10,129

 
27,281

 
(17,152
)
Total capital expenditures
 
23,156

 
38,109

 
(14,953
)
Less: Capital expenditures attributable to Predecessor
 
3,394

 
29,632

 
(26,238
)
Capital expenditures attributable to Partnership
 
$
19,762

 
$
8,477

 
$
11,285

 
 
 
 
 
 
 
Other financial information:
 
 
 
 
 
 
Distribution declared per unit
 
$
1.4965

 
$
1.1975

 
 
 
 
 
 
 
 
 
Distribution declared:
 
 
 
 
 
 
Limited partner units – public
 
$
32,382

 
$
22,028

 
 
Limited partner units – Valero
 
67,560

 
51,566

 
 
General partner units – Valero
 
21,648

 
5,003

 
 
Total distribution declared
 
$
121,590

 
$
78,597

 
 
______________
(a)
Represents the sum of volumes transported through each separately tariffed pipeline segment.
(b)
Average revenue per barrel is calculated as revenue divided by throughput for the period. Throughput is derived by multiplying the throughput barrels per day by the number of days in the period.




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Operating revenues increased $119.0 million, or 49 percent, in 2016 compared to 2015. The increase was due primarily to the following:
Incremental terminaling throughput from businesses acquired from Valero. We experienced a 111 percent increase in terminaling revenues in 2016 compared to 2015 as a result of revenues generated from the operations of the McKee, Meraux, and Three Rivers terminals, which were acquired from Valero in 2016. The incremental throughput volumes at these terminals had a favorable impact to our operating revenues of $124.1 million in 2016.
Lower operating revenues at systems owned or acquired prior to 2015. We estimate that a decrease in throughput volumes at our other pipelines and terminals had an unfavorable impact to our operating revenues of approximately $5.1 million. The decrease is due primarily to a decrease of 25 percent in pipeline transportation throughput volumes and 21 percent in terminaling throughput volumes at our Port Arthur logistics system in 2016 compared to 2015. The decrease in volumes was primarily a result of planned turnaround activity at Valero’s Port Arthur refinery in September and October 2016, during which time the refinery was largely shut down. In addition, we experienced a decrease of 26 percent in pipeline transportation throughput volumes at our McKee crude system in 2016 compared to 2015 due to decreased crude oil production in the region. Average pipeline transportation revenue per barrel was higher in 2016 compared to 2015 due primarily to the recognition of $2.2 million of deferred revenue associated with unused minimum volume credits by Valero.
Cost of revenues (excluding depreciation expense reflected below) decreased $9.9 million, or 9 percent, in 2016 compared to 2015. The decrease was due primarily to lower maintenance expense of $4.7 million at our Corpus Christi terminals related to inspection activity in 2015. Additionally, waste handling costs at our Corpus Christi and St. Charles terminals decreased $2.3 million in 2016.
Depreciation expense increased $287,000, or 1 percent, in 2016 compared to 2015 due primarily to additional depreciation expense related to assets placed into service in the latter part of 2015 and 2016, including expansion and improvement projects at our Corpus Christi, Houston, Meraux, and St. Charles terminals, partially offset by $2.8 million in accelerated depreciation related to the retirement of certain assets of our McKee crude system in 2015.
General and administrative expenses increased $1.4 million, or 10 percent, in 2016 compared to 2015 due primarily to incremental costs of $843,000 related to the management fee charged to us by Valero as a result of additional administrative services provided to us in connection with our acquisitions from Valero in 2015 and 2016 and an increase of $470,000 in public company costs.
“Interest and debt expense, net of capitalized interest” increased $8.8 million in 2016 compared to 2015 due primarily to interest expense incurred on borrowings under our revolving credit facility and subordinated credit agreements with Valero entered into in connection with the acquisitions. Additionally, we issued the Senior Notes in December 2016 and used the proceeds to repay $494.0 million of outstanding borrowings under our revolving credit facility. The interest on the Senior Notes is higher than our revolving credit facility, thereby increasing the effective interest rate for 2016. See Notes 2 and 6 of Notes to Consolidated Financial Statements for further discussion. Interest expense on the incremental borrowings was $8.2 million in 2016.
Our income tax expense is associated with the Texas margin tax. During 2016, the relative amount of operating revenues we generated in Texas increased in connection with the acquisitions of the Corpus Christi, McKee, Meraux, and Three Rivers terminals. As a result, our income tax expense has increased.



57


LIQUIDITY AND CAPITAL RESOURCES
Liquidity
We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under our revolving credit facility, and issuances of additional debt and equity securities. We may also enter into financing transactions with Valero in connection with acquisitions. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions.
ATM Program
On September 16, 2016, we entered into an equity distribution agreement pursuant to which we may offer and sell from time to time our common units having an aggregate offering price of up to $350.0 million based on amounts, at prices, and on terms to be determined by market conditions and other factors at the time of our offerings (such continuous offering program, or at-the-market program, referred to as our “ATM Program”). We have sold common units having an aggregate value of $45.5 million under our ATM Program, resulting in $304.5 million remaining available as of December 31, 2017. See Note 10 of Notes to Consolidated Financial Statements for a description of the ATM Program.

Revolving Credit Facility
We have a $750.0 million senior unsecured revolving credit facility (the Revolver) that matures in November 2020. We have the option to increase the aggregate commitments under the Revolver to $1.0 billion, subject to certain restrictions. The Revolver also provides for the issuance of letters of credit of up to $100.0 million. As of December 31, 2017, we had $410.0 million of borrowings and no letters of credit outstanding under the Revolver. As a result, we had $340.0 million of available capacity. See Note 5 of Notes to Consolidated Financial Statements for a description of the Revolver.
Cash Flows Summary
Components of our cash flows are set forth below (in thousands):

 
 
 
Year Ended December 31,
 
 
 
2017
 
2016
 
2015
Cash flows provided by (used in):
 
 
 
 
 
Operating activities
 
$
288,931

 
$
229,894

 
$
108,376

Investing activities
 
(517,851
)
 
(126,732
)
 
(428,171
)
Financing activities
 
199,481

 
(112,454
)
 
163,999

Net decrease in cash and cash equivalents
$
(29,439
)
 
$
(9,292
)
 
$
(155,796
)
Cash Flows for the Year Ended December 31, 2017
Our operations generated $288.9 million of cash in 2017, driven primarily by net income of $238.4 million and noncash adjustments (primarily for depreciation expense) of $54.2 million, partially offset by unfavorable changes in working capital of $3.7 million. See “RESULTS OF OPERATIONS” for further discussion of our operations. The change in our working capital is further described in Note 13 of Notes to Consolidated Financial Statements and mainly resulted from:

an increase in receivables – related party of $9.6 million attributable primarily to billings related to our Red River crude system, Parkway pipeline, and the Port Arthur terminal, which were acquired in 2017; and



58


a decrease in accounts payable – related party of $3.4 million due primarily to the timing of invoices from Valero for services provided to our general partner under our amended and restated services and secondment agreement; partially offset by
an increase in accounts payable of $7.4 million attributable primarily to payables related to our Parkway pipeline, which was acquired in 2017; and
an increase in accrued interest payable of $1.3 million due primarily to interest expense incurred on the $380.0 million borrowed under the Revolver in connection with the acquisitions of the Parkway pipeline and the Port Arthur terminal.

The $288.9 million of cash generated by our operations, along with (i) $380.0 million of borrowings under the Revolver and (ii) $36.5 million in proceeds received in connection with unit issuances under our ATM Program, were used mainly to:

fund $462.5 million in acquisitions from Valero consisting of the Parkway pipeline and the Port Arthur terminal;
pay $161.3 million in cash distributions to limited partners and our general partner;
fund the $71.8 million acquisition of the Red River crude system; and
fund $38.5 million in capital expenditures.

Cash Flows for the Year Ended December 31, 2016
Our operations generated $229.9 million of cash in 2016, driven primarily by net income of $188.8 million and noncash adjustments (primarily for depreciation expense) of $47.0 million, partially offset by unfavorable changes in working capital of $6.0 million. See “RESULTS OF OPERATIONS” for further discussion of our operations. The change in our working capital is further described in Note 13 of Notes to Consolidated Financial Statements and mainly resulted from:

an increase in receivables – related party of $10.8 million attributable primarily to billings related to our newly acquired McKee, Meraux, and Three Rivers terminals; partially offset by
an increase in deferred revenue – related party of $3.4 million due to deficiency payments associated with minimum volume commitments.

The $229.9 million of cash generated by our operations, along with (i) $848.8 million in proceeds from the issuance of debt (including gross proceeds of $499.8 million from the issuance of our Senior Notes and $349.0 million of borrowings under the Revolver of as discussed in Note 5 of Notes to Consolidated Financial Statements), (ii) $14.9 million of net cash transferred from Valero related to the cash flows associated with our Predecessor, and (iii) $9.9 million in proceeds received in connection with our ATM Program, were used mainly to:

fund $480.0 million in acquisitions from Valero consisting of the McKee Terminal Services Business and the Meraux and Three Rivers Terminal Services Business;
make debt repayments of $494.9 million, of which $494.0 million related to the Revolver;
pay $109.4 million in cash distributions to limited partners and our general partner;
fund $23.2 million in capital expenditures; and
pay $5.3 million in debt issuance and offering costs.

Cash Flows for the Year Ended December 31, 2015
Our operations generated $108.4 million of cash in 2015, driven primarily by net income of $71.3 million and noncash adjustments (primarily for depreciation expense) of $46.0 million, partially offset by unfavorable changes in working capital of $9.0 million. See “RESULTS OF OPERATIONS” for further



59


discussion of our operations. The change in our working capital is further described in Note 13 of Notes to Consolidated Financial Statements and mainly resulted from:

an increase in receivables – related party of $15.6 million due primarily to activity related to our newly acquired Houston, St. Charles, and Corpus Christi terminals; partially offset by
an increase in accounts payable – related party of $6.0 million, also attributable primarily to activity related to our newly acquired terminals.

The $108.4 million of cash generated by our operations, along with (i) $755.0 million in proceeds from the issuance of debt ($555.0 million from the two subordinated credit agreements with Valero (Loan Agreements) in connection with businesses acquired in 2015 and borrowings under the Revolver of $200.0 million as discussed in Note 5 of Notes to Consolidated Financial Statements), (ii) $189.7 million in proceeds from the 2015 Offering (net of the underwriting discount), (iii) $77.3 million of net cash transferred from Valero related to the cash flows associated with our Predecessor, and (iv) $4.0 million from the issuance of general partner units, were used mainly to:

fund $966.2 million in acquisitions from Valero consisting of the Houston and St. Charles Terminal Services Business and the Corpus Christi Terminal Services Business;
make debt repayments of $211.2 million, of which $185.0 million related to the Loan Agreements and $25.0 million related to the Revolver;
pay $71.7 million in cash distributions to limited partners and our general partner;
fund $38.1 million in capital expenditures; and
pay $3.0 million in debt issuance and offering costs.

Capital Resources
Capital Expenditures
Our operations can be capital intensive, requiring investments to expand, upgrade, or enhance existing operations and to meet environmental and operational regulations. Our capital requirements consist of maintenance capital expenditures and expansion capital expenditures as those terms are defined in our partnership agreement. Examples of maintenance capital expenditures are those made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. In contrast, examples of expansion capital expenditures include those made to expand and upgrade our systems and facilities and to construct or acquire new systems or facilities to grow our business.
Our capital expenditures were as follows (in thousands):
 
 
 
Years Ended December 31,
 
 
 
2017
 
2016
 
2015
Maintenance
 
$
8,954

 
$
13,027

 
$
10,828

Expansion (a)
 
29,562

 
10,129

 
27,281

Total capital expenditures
 
$
38,516

 
$
23,156

 
$
38,109

 
 
 
 
 
 
 
 
(a) This table excludes amounts paid for our acquisitions. See Note 2 in Notes to Consolidated Financial Statements for further discussion of our acquisitions.



60


Our capital expenditures in 2017 were primarily for:
the construction of a new tank and improvement of assets at our Port Arthur products system;
the construction of the DGD rail loading facility and new tank at the St. Charles terminal; and