Shell Midstream Partners, L.P. - Annual Report: 2018 (Form 10-K)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________________________________________________________
FORM 10-K
________________________________________________________________
(Mark One)
| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the fiscal year ended December 31, 2018
OR
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the transition period from to
Commission file number: 001-36710
______________________________________________________________
Shell Midstream Partners, L.P.
(Exact name of registrant as specified in its charter)
________________________________________________________________
| Delaware | 46-5223743 | |||||||
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |||||||
150 N. Dairy Ashford, Houston, Texas 77079
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (832) 337-2034
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Name of each exchange on which registered | |||||||
| Common Units, Representing Limited Partner Interests | New York Stock Exchange | |||||||
________________________________________________________________
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. x Yes ¨ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ¨ Yes x No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). x Yes ¨ No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a 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 | x | Accelerated filer | ¨ | |||||||||||
| Non-accelerated filer | ¨ | Smaller reporting company | ¨ | |||||||||||
| 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 Act). ¨ Yes x No
The aggregate market value of the registrant’s common units held by non-affiliates of the registrant as of June 29, 2018, was $2,744 million, based on the closing price of such units of $22.18 as reported on the New York Stock Exchange on such date. The registrant had 223,811,781 common units and no subordinated units outstanding as of February 21, 2019.
Documents incorporated by reference:
None
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
This report includes forward-looking statements. You can identify our forward-looking statements by the words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions.
We based the forward-looking statements on our current expectations, estimates and projections about us and the industries in which we operate in general. We caution you these statements are not guarantees of future performance as they involve assumptions that, while made in good faith, may prove to be incorrect, and involve risks and uncertainties we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual outcomes and results may differ materially from what we have expressed in the forward-looking statements. Any differences could result from a variety of factors, including the following:
•The continued ability of Royal Dutch Shell plc and our non-affiliate customers to satisfy their obligations under our commercial and other agreements and the impact of lower market prices for crude oil, refined petroleum products and refinery gas.
•The volume of crude oil, refined petroleum products and refinery gas we transport or store and the prices that we can charge our customers.
•The tariff rates with respect to volumes that we transport through our regulated assets, which rates are subject to review and possible adjustment imposed by federal and state regulators.
•Changes in revenue we realize under the loss allowance provisions of our fees and tariffs resulting from changes in underlying commodity prices.
•Our ability to renew or replace our third-party contract portfolio on comparable terms.
•Fluctuations in the prices for crude oil, refined petroleum products and refinery gas.
•The level of production of refinery gas by refineries and demand by chemical sites.
•The level of onshore and offshore (including deepwater) production and demand for crude oil by U.S. refiners.
•Changes in global economic conditions and the effects of a global economic downturn on the business of Shell and the business of its suppliers, customers, business partners and credit lenders.
•Availability of acquisitions and financing for acquisitions on our expected timing and acceptable terms.
•Changes in, and availability to us, of the equity and debt capital markets.
•Liabilities associated with the risks and operational hazards inherent in transporting and/or storing crude oil, refined petroleum products and refinery gas.
•Curtailment of operations or expansion projects due to unexpected leaks, spills, or severe weather disruption; riots, strikes, lockouts or other industrial disturbances; or failure of information technology systems due to various causes, including unauthorized access or attack.
•Costs or liabilities associated with federal, state and local laws and regulations relating to environmental protection and safety, including spills, releases and pipeline integrity.
•Costs associated with compliance with evolving environmental laws and regulations on climate change.
•Costs associated with compliance with safety regulations and system maintenance programs, including pipeline integrity management program testing and related repairs.
•Changes in tax status or applicable tax laws.
•Changes in the cost or availability of third-party vessels, pipelines, rail cars and other means of delivering and transporting crude oil, refined petroleum products and refinery gas.
•Direct or indirect effects on our business resulting from actual or threatened terrorist incidents or acts of war.
•The factors generally described in Part I, Item 1A. Risk Factors of this report.
GLOSSARY OF TERMS
Barrel or bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to crude oil or other liquid hydrocarbons.
BOEM: Bureau of Ocean Energy Management.
BSEE: Bureau of Safety and Environmental Enforcement.
Capacity: Nameplate capacity.
Common carrier pipeline: A pipeline engaged in the transportation of crude oil, refined products or natural gas liquids as a common carrier for hire.
Crude oil: A mixture of raw hydrocarbons that exists in liquid phase in underground reservoirs.
DOT: Department of Transportation.
EPAct: Energy Policy Act of 1992.
Expansion capital expenditures: Expansion capital expenditures is a defined term under our partnership agreement. Expansion capital expenditures are cash expenditures (including transaction expenses) for capital improvements. Expansion capital expenditures do not include maintenance capital expenditures or investment capital expenditures. Expansion capital expenditures do include interest payments (including periodic net payments under related interest rate swap agreements) and related fees paid during the construction period on construction debt. Where cash expenditures are made in part for expansion capital expenditures and in part for other purposes, the general partner determines the allocation between the amounts paid for each.
FERC: Federal Energy Regulatory Commission.
GAAP: United States generally accepted accounting principles.
HCAs: High Consequence Areas.
ICA: Interstate Commerce Act of 1887, as modified by the Elkins Act.
kbpd: Thousand barrels per day.
kbls: Thousand barrels.
klbs/d: Thousand pounds per day.
Life-of-lease transportation agreement: A contract in which the producer dedicates shipments of all current and future reserves pertaining to a specific lease or area to a specific carrier.
LNG: Liquefied natural gas.
LTIP: Shell Midstream Partners, L.P. 2014 Incentive Compensation Plan.
Maintenance capital expenditures: Maintenance capital expenditures is a defined term under our Partnership Agreement. Maintenance capital expenditures are cash expenditures (including expenditures for (a) the acquisition (through an asset acquisition, merger, stock acquisition, equity acquisition or other form of investment) by the Partnership or any of its subsidiaries of existing assets or assets under construction, (b) the construction or development of new capital assets by the Partnership or any of its subsidiaries, (c) the replacement, improvement or expansion of existing capital assets by the Partnership or any of its subsidiaries or (d) a capital contribution by the Partnership or any of its subsidiaries to a person that is not a subsidiary in which the Partnership or any of its subsidiaries has, or after such capital contribution will have, directly or indirectly, an equity interest, to fund the Partnership or such subsidiary’s share of the cost of the acquisition, construction or development of new, or the replacement, improvement or expansion of existing, capital assets by such person), in each case if and to the extent such acquisition, construction, development, replacement, improvement or expansion is made to maintain, over the long-term, the operating capacity or operating income of the Partnership and its subsidiaries, in the case of clauses (a), (b) and (c), or such person, in the case of clause (d), as the operating capacity or operating income of the Partnership and its subsidiaries or such person, as the case may be, existed immediately prior to such acquisition, construction, development,
replacement, improvement, expansion or capital contribution. For purposes of this definition, “long-term” generally refers to a period of not less than twelve months.
mscf/d: Million standard cubic feet per day.
Partnership Agreement: First Amended and Restated Agreement of Limited Partnership of Shell Midstream Partners, L.P., dated as of November 3, 2014, as amended by Amendment No. 1 thereto, dated February 26, 2018, and as amended by Amendment No. 2 thereto dated December 21, 2018.
PHMSA: Pipeline and Hazardous Materials Safety Administration.
Pipeline loss allowance or PLA: An allowance for volume losses due to measurement difference set forth in crude oil product transportation agreements, including long-term transportation agreements and tariffs for crude oil shipments.
Refined products: Hydrocarbon compounds, such as gasoline, diesel fuel, jet fuel and residual fuel that are produced by a refinery.
Refinery gas: Non-condensable gas obtained during distillation of crude oil or treatment of oil products in refineries.
Ship-or-pay contract: A contract requiring payment for the transportation of crude oil or refined products even if the crude oil or refined products are not transported.
Throughput: The volume of crude oil, refined products or natural gas transported or passing through a refinery, pipeline, terminal or other facility during a particular period.
SHELL MIDSTREAM PARTNERS, L.P.
TABLE OF CONTENTS
| Item | Page | ||||
PART I
Unless the context otherwise requires, references in this report to “Shell Midstream Partners,” “the Partnership,” “us,” “our,” “we,” or similar expressions refer to Shell Midstream Partners, L.P. and its subsidiaries. References to “our general partner” or “our sponsor” refer to Shell Midstream Partners GP LLC, a wholly owned subsidiary of Shell Pipeline Company LP (“SPLC”). References to “Shell” or “Parent” refer collectively to Royal Dutch Shell plc and its controlled affiliates, other than us, our subsidiaries and our general partner.
Part I should be read in conjunction with Part II, Item 7 and with the consolidated financial statements and notes thereto included in Part II, Item 8 of this report.
6
Items 1 and 2. BUSINESS AND PROPERTIES
Overview
Shell Midstream Partners, L.P. is a Delaware limited partnership formed by Shell on March 19, 2014 to own and operate pipeline and other midstream assets, including certain assets acquired from SPLC and its affiliates. We conduct our operations either through our wholly owned subsidiary Shell Midstream Operating, LLC (“Operating Company”) or through direct ownership. Our general partner is Shell Midstream Partners GP LLC (“general partner” or “sponsor”). Our common units trade on the New York Stock Exchange under the symbol “SHLX.”
We are a growth-oriented master limited partnership that owns, operates, develops and acquires pipelines and other midstream assets. As of December 31, 2018, our assets include interests in entities that own crude oil and refined products pipelines and terminals that serve as key infrastructure to (i) transport onshore and offshore crude oil production to Gulf Coast and Midwest refining markets and (ii) deliver refined products from those markets to major demand centers. Our assets also include interests in entities that own natural gas and refinery gas pipelines that transport offshore natural gas to market hubs and deliver refinery gas from refineries and plants to chemical sites along the Gulf Coast.
We generate revenue from the transportation, terminaling and storage of crude oil and refined products through our pipelines and storage tanks, and generate income from our equity and other investments. Our operations consist of one reportable segment. See Note 1 – Description of the Business and Basis of Presentation in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report.
The following table reflects our ownership, and Shell’s retained ownership, as of December 31, 2018:
| SHLX Ownership | Shell’s Retained Ownership | ||||||||||
| Pecten Midstream LLC (“Pecten”) | 100.0 | % | — | % | |||||||
| Sand Dollar Pipeline LLC (“Sand Dollar”) | 100.0 | % | — | % | |||||||
| Triton West LLC (“Triton”) | 100.0 | % | — | % | |||||||
| Zydeco Pipeline Company LLC (“Zydeco”) | 92.5 | % | 7.5 | % | |||||||
| Amberjack Pipeline Company LLC (“Amberjack”) – Series A/Series B | 75.0% / 50.0% | — | % | ||||||||
| Mars Oil Pipeline Company LLC (“Mars”) | 71.5 | % | — | % | |||||||
| Odyssey Pipeline L.L.C. (“Odyssey”) | 71.0 | % | — | % | |||||||
| Bengal Pipeline Company LLC (“Bengal”) | 50.0 | % | — | % | |||||||
| Crestwood Permian Basin LLC (“Permian Basin”) | 50.0 | % | — | % | |||||||
| LOCAP LLC (“LOCAP”) | 41.48 | % | — | % | |||||||
| Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”) | 36.0 | % | — | % | |||||||
| Explorer Pipeline Company (“Explorer”) | 12.62 | % | 25.97 | % | |||||||
| Proteus Oil Pipeline Company, LLC (“Proteus”) | 10.0 | % | — | % | |||||||
| Endymion Oil Pipeline Company, LLC (“Endymion”) | 10.0 | % | — | % | |||||||
| Colonial Pipeline Company (“Colonial”) | 6.0 | % | 10.12 | % | |||||||
| Cleopatra Gas Gathering Company, LLC (“Cleopatra”) | 1.0 | % | — | % | |||||||
2018 Acquisition
On May 11, 2018, we acquired SPLC’s ownership interests in Amberjack, which is comprised of 75% of the issued and outstanding Series A membership interests of Amberjack and 50% of the issued and outstanding Series B membership interests of Amberjack, for an aggregate purchase price of $1,220.0 million (the “May 2018 Acquisition”). We funded the May 2018 Acquisition with $494.0 million in borrowings under our Five Year Revolver due July 2023 (as defined below) and $726.0 million in borrowings under our Five Year Revolver due December 2022 (as defined below).
See Note 4 – Acquisitions and Divestiture in the Notes to Consolidated Financial Statements in Part II, Item 8 of this report for additional information.
7
Organizational Structure
The following simplified diagram depicts our organizational structure as of December 31, 2018:
8
Our Assets and Operations
Our assets consist of the following systems:
Crude Oil Pipelines
Onshore Crude Pipelines
Delta. Delta is wholly owned by Pecten, and we own a 100% interest in Pecten. SPLC is the operator of Delta.
Delta aggregates volumes from five offshore pipelines, including the Odyssey and Na Kika pipelines and connects offshore oil production in the eastern corridor of the Gulf of Mexico to key onshore markets. The system originates at Main Pass 69P and Main Pass 69A for the transportation of Heavy Louisiana Sweet (“HLS”) crude oil from the Gulf of Mexico to onshore demand centers and refineries.
Zydeco. We own a 92.5% interest in Zydeco, which owns the Zydeco pipeline system. SPLC owns the remaining 7.5% interest and is the operator of Zydeco.
Zydeco is a FERC-regulated pipeline system. Zydeco consists of four main pipeline segments that moves light, sweet crude from Houston, Texas to Houma, Louisiana and on to both Clovelly and St. James in Louisiana. Additionally, Zydeco has tankage in Port Neches, Texas and Houma, Louisiana, a dock in Houma, Louisiana and a pipeline that indirectly connects to the offshore Boxer pipeline system. Zydeco’s customers include traders, marketers, refiners, producers and affiliates of Shell.
Offshore Crude Pipelines
9
Auger. Auger is wholly owned by Pecten, and we own a 100% interest in Pecten. SPLC is the operator of Auger.
Auger is an offshore Gulf of Mexico corridor pipeline that transports medium sour crude and provides transportation for major oil producers and from multiple production fields in the Gulf of Mexico. Auger shares a complementary strategic connection to the Poseidon pipeline system, which provides certain connected producers the option to access either Poseidon or Auger delivery markets.
Na Kika. Na Kika is wholly owned by Pecten and we own a 100% interest in Pecten. SPLC is the operator of Na Kika.
Na Kika is anchored by the Na Kika platform which serves as a host to several subsea fields and connects to Delta at Main Pass 69 for the delivery of HLS crude oil to onshore demand centers and refineries.
Amberjack. We own 75.0% of the issued and outstanding Series A membership interests of Amberjack and 50.0% of the issued and outstanding Series B membership interests of Amberjack. Chevron Pipe Line Company (“Chevron”) owns the remaining membership interests in Amberjack. SPLC is the operator of Amberjack with the exception of the Jack St. Malo Pipeline which is operated by Chevron.
Amberjack transports crude received from several production platforms, including Jack St. Malo, Tahiti, Stampede and Bigfoot, and offers delivery options into multiple pipelines, including Mars and Poseidon, in which we own interests. Through the multiple pipeline connectivity options, Amberjack provides access to onshore destinations such as the entire Mississippi Refining Basin through Clovelly/LOOP and Zydeco’s Houma terminal.
Mars. We own a 71.5% interest in Mars, which owns the Mars pipeline system. BP Midstream Partners LP owns the remaining 28.5% interest in Mars. SPLC is the operator of Mars.
Transportation on certain segments of the Mars pipeline system are subject to the jurisdiction of FERC and the Louisiana Public Service Commission. Mars delivers production received from the Mississippi Canyon, Green Canyon and Walker Ridge areas to shore, terminating in salt dome caverns in Clovelly, Louisiana, which is a major trading hub. Mars leases its main storage cavern at Clovelly from LOOP LLC.
Odyssey. We own a 71.0% interest in Odyssey, which owns the Odyssey pipeline system. GEL Odyssey, LLC (“GEL”) owns a 29.0% interest in Odyssey. SPLC is the operator of Odyssey.
The Odyssey pipeline system transports crude oil in the offshore eastern Gulf of Mexico to markets in Louisiana. Odyssey provides transportation for major oil producers and from many different production fields in the eastern Gulf of Mexico. Crude oil transported via Odyssey is delivered to the Delta pipeline system for further delivery to onshore demand centers and refineries.
Poseidon. We own a 36.0% interest in Poseidon, which owns the Poseidon pipeline system. GEL Poseidon, LLC (“Genesis”) owns the remaining 64.0% interest and is the operator of Poseidon.
The Poseidon pipeline system is a key corridor pipeline, connecting to several Gulf of Mexico fields and delivers via connecting carriers into major crude trading hubs in Texas and Louisiana. Poseidon’s largest customers are major oil producers who ship from a variety of production fields in the Gulf of Mexico, many of whom have dedicated production to the pipeline.
Proteus. We own a 10.0% interest in Proteus, which owns the Proteus pipeline system. Mardi Gras Transportation System Inc. (“Mardi Gras”) and ExxonMobil Pipeline Company (“ExxonMobil”) collectively own the remaining 90.0% interest. SPLC is the operator of Proteus.
The Proteus pipeline system provides transportation for multiple oil producers in the eastern Gulf of Mexico. The pipeline provides access to the Mississippi Canyon area of the Gulf of Mexico. SPLC is currently building the Mattox pipeline which will connect to Proteus and transport all of the volumes from the Appomattox platform.
Endymion. We own a 10.0% interest in Endymion, which owns the Endymion pipeline system. Mardi Gras Endymion Oil Pipeline Company, LLC (“Mardi Gras Endymion”) and ExxonMobil collectively own the remaining 90.0% interest. SPLC is the operator of Endymion.
10
The Endymion pipeline system provides transportation for multiple oil producers in the eastern Gulf of Mexico. Endymion provides access to the Mississippi Canyon area of the Gulf of Mexico and is connected to the LOOP Clovelly storage terminal with access to multiple markets. Endymion leases a cavern from LOOP LLC.
Refined Products Pipelines
Bengal. We own a 50.0% interest in Bengal and Colonial owns the remaining 50.0% interest. Colonial is the system operator for regulatory reporting purposes and operates Bengal’s tankage. SPLC operates Bengal’s pipelines.
The Bengal pipeline system is a refined products pipeline system that connects four refineries in southern Louisiana to long-haul transportation pipelines. The pipeline system consists of two primary pipelines, one of which connects the Shell and Valero refineries in Norco, Louisiana and also connects the Marathon Petroleum Corporation refinery in Garyville, Louisiana to Bengal’s Baton Rouge, Louisiana tankage and the Plantation pipeline. The other primary line connects Shell’s Convent, Louisiana refinery to the Plantation pipeline and Bengal’s Baton Rouge, Louisiana tankage. The Bengal pipeline system provides transportation for a number of customers from connected refineries and terminals to the Plantation and Colonial pipelines, and from refineries to the Baton Rouge tankage.
Explorer. We own a 12.62% interest in Explorer, which owns the Explorer pipeline system. SPLC owns a 25.97% interest in Explorer, and MPL Investment LLC, Phillips 66 Partners Holdings LLC and Sunoco Pipeline L.P. collectively own the remaining 61.41% interest. The pipeline system is operated by Explorer.
The Explorer pipeline system is a FERC-regulated petroleum products pipeline system, which extends from the Gulf Coast to the Midwest. Explorer transports refined products with more than 70 different specifications for more than 60 different shippers.
Colonial. We own a 6.0% interest in Colonial, which owns the Colonial pipeline system. SPLC owns a 10.12% interest in Colonial, and CDPQ Colonial Partners, LP, Koch Capital Investments Company, LLC, KKR-Keats Pipeline Investors LP and IFM (US) Colonial Pipeline 2, LLC collectively own the remaining 83.88% interest. The pipeline system is operated by Colonial.
The Colonial pipeline system is the largest refined products pipeline in the United States based on barrel-miles transported. Colonial connects refineries along the Gulf Coast to numerous marketing terminals between Houston, Texas and Linden, New Jersey. Colonial transports gasoline, jet fuel, kerosene, home heating oil, diesel fuel and national defense fuels to shipper terminals, and is subject to FERC regulation. Colonial serves a diverse set of customers, including refiners, marketers, airports and airlines.
Terminals and Storage
Triton. We own a 100% interest in Triton which wholly owns the Anacortes (Washington), Colex (Texas), Des Plaines (Illinois), Portland (Oregon) and Seattle (Washington) refined products terminals. Our general partner is the operator of these five terminals.
These terminals receive products from pipelines and, in certain cases, barges, ships or railroads, and distribute them to third parties, who in turn deliver them to end-users and retail outlets. These terminals play a key role in moving products to the end-user market by providing efficient product receipt, storage and distribution capabilities, inventory management, ethanol and biodiesel blending, and other ancillary services that include the injection of various additives.
Lockport. Lockport is wholly owned by Pecten, and we own a 100% interest in Pecten. SPLC is the operator of Lockport.
Lockport is a crude terminal facility located southwest of Chicago that feeds regional refineries and offers strategic trading opportunities. Lockport provides storage services for a number of customers, receives primarily Canadian and Midwest crude and supplies Midwest refineries, and indirectly, a regional distribution hub.
Other Midstream Assets
Refinery Gas Pipeline. Refinery Gas Pipeline is wholly owned by Sand Dollar, and we own a 100% interest in Sand Dollar.
Refinery Gas Pipeline is a network of gas pipelines connecting multiple refineries and plants operated along the Gulf Coast to Shell Chemical sites, including Shell’s Norco refinery and Deer Park refinery. The pipelines transport refinery gas which is a mix of methane, natural gas liquids and olefins.
11
Permian Basin. We own a 50.0% interest in Permian Basin. CPB Member LLC (a jointly owned subsidiary of Crestwood Equity Partners LP and First Reserve) owns the remaining 50.0% interest. The Nautilus gas gathering system is owned by Permian Basin and operated by CPB Operator LLC.
The Nautilus gas gathering system includes receipt point meters, a pipeline, a high-pressure header system, compression capability and a high-pressure delivery point. Nautilus is designed to serve a dedication area of about 100,000 acres in West Texas. The Nautilus system gathers the majority of Shell’s operated Delaware Basin gas.
Permian Basin has undertaken a project to build the infrastructure to serve approximately 10,500 dedicated acres of development for Halcon Resources Company. The initial field development began in 2018 and will continue through 2019, with full field development taking place from 2020 to 2023. At completion, the expansion is expected to contain gathering lines, receipt points and a compressor station. This project provides an opportunity to secure third party business while we continue to build scale in the Permian.
LOCAP. We own a 41.48% interest in LOCAP. MPLX Operations LLC, an indirect subsidiary of MPLX LP, owns the remaining 58.52% interest. LOOP LLC is the operator of LOCAP.
The LOCAP pipeline connects the LOOP Clovelly Salt Dome storage facility to the active trading hub of St. James, Louisiana. Crude oil arriving at the St. James terminal can be dispatched to any one of four local refineries serving Louisiana and can also be dispatched to other pipeline systems transmitting more than 30% of the nation’s refining capacity to refineries throughout the Midwest. The LOCAP pipeline is FERC-regulated.
Cleopatra. We own a 1.0% interest in Cleopatra, which owns the Cleopatra pipeline system. Mardi Gras, BHP Billiton Petroleum (Deepwater) Inc., Enbridge Offshore (Gas Transmission) LLC, and Chevron Midstream Investments LLC collectively own the remaining 99.0% interest in Cleopatra. SPLC is the operator of Cleopatra.
The Cleopatra pipeline system is a gas gathering pipeline and provides gathering and transportation for multiple gas producers and third-party gas shippers.
Pipeline Systems and Terminal Systems
The following table sets forth certain information regarding our pipeline and terminal systems as of December 31, 2018:
| Pipeline System/Terminal System | Diameter (inches) | Approximate Length (miles) | Approximate Capacity (kbpd) (2) | Approximate Tank Storage Capacity (kbls) | ||||||||||||||||||||||
| Zydeco crude oil system - Mainlines | ||||||||||||||||||||||||||
| Houston to Port Neches | 20 | 85 | 250 | - | ||||||||||||||||||||||
| Port Neches to Houma | 22 | 215 | 375 | - | ||||||||||||||||||||||
| Houma to Clovelly | 24 | 35 | 500 | - | ||||||||||||||||||||||
| Houma to St James | 18 | 50 | 260 | - | ||||||||||||||||||||||
| Amberjack crude oil system | ||||||||||||||||||||||||||
| Jack St. Malo | 20/24 | 135 | 200 | - | ||||||||||||||||||||||
| Tahiti | 20/24 | 55 | 300 | - | ||||||||||||||||||||||
| ADP 24" | 24 | 100 | 300 | - | ||||||||||||||||||||||
| Jackalope | 20 | 35 | 200 | - | ||||||||||||||||||||||
| Genesis | 14 | 30 | 50 | - | ||||||||||||||||||||||
| Ewing Banks 910 | 8 | 5 | 20 | - | ||||||||||||||||||||||
| Auger crude oil system | ||||||||||||||||||||||||||
| Enchilada Platform to Eugene Island 315 | 12 | 35 | 35 | - | ||||||||||||||||||||||
| Enchilada Platform to Ship Shoal 28P | 20 | 100 | 200 | - | ||||||||||||||||||||||
| 14/16" Auger export line | 14/16 | 40 | 150 | - | ||||||||||||||||||||||
| Delta crude oil system | 16/20 | 130 | 420 | - | ||||||||||||||||||||||
| Na Kika crude oil system | 18 | 75 | 160 | - | ||||||||||||||||||||||
12
Mars crude oil system (1) | ||||||||||||||||||||||||||
| Mars TLP to West Delta 143 | 18 | 40 | 100 | - | ||||||||||||||||||||||
| Olympus TLP to West Delta 143 | 16/18 | 40 | 100 | - | ||||||||||||||||||||||
| West Delta 143 to Fourchon | 24 | 55 | 400 | - | ||||||||||||||||||||||
| Fourchon to Clovelly | 24 | 25 | 600 | - | ||||||||||||||||||||||
| Bengal product system | ||||||||||||||||||||||||||
| Norco to Baton Rouge tank farm | 24 | 95 | 305 | - | ||||||||||||||||||||||
| Convent to Baton Rouge tank farm | 16 | 65 | 210 | - | ||||||||||||||||||||||
| Poseidon crude oil system | Various | 365 | 350 | - | ||||||||||||||||||||||
| Odyssey crude oil system | Various | 105 | 220 | - | ||||||||||||||||||||||
| Proteus crude oil system | ||||||||||||||||||||||||||
| Thunder Horse TLP to South Pass 89E | 24/28 | 70 | 425 | - | ||||||||||||||||||||||
| Endymion crude oil system | ||||||||||||||||||||||||||
| South Pass 89E to Clovelly | 30 | 90 | 425 | - | ||||||||||||||||||||||
Cleopatra gas gathering system (2) | ||||||||||||||||||||||||||
| Atlantis TLP to Ship Shoal 332A | 16/20 | 115 | 500 | - | ||||||||||||||||||||||
| Colonial product system | Various | 5,500 | 2,500 | - | ||||||||||||||||||||||
| Explorer product system | Various | 1,830 | 660 | - | ||||||||||||||||||||||
Permian Basin gas gathering system (2) | Various | 135 | 220 | - | ||||||||||||||||||||||
| LOCAP pipeline system and storage facility | 48 | 55 | 1,700 | 2,600 | ||||||||||||||||||||||
| Lockport terminal system | n/a | n/a | - | 2,000 | ||||||||||||||||||||||
Refinery Gas Pipeline (2) | ||||||||||||||||||||||||||
| Houston Ship Channel | 8 | 10 | 3,960 | - | ||||||||||||||||||||||
| Texas City | 12 | 35 | 5,280 | - | ||||||||||||||||||||||
| Garyville - Norco | 12 | 20 | 3,720 | - | ||||||||||||||||||||||
| Convent to Garyville | 12 | 20 | 3,840 | - | ||||||||||||||||||||||
| Norco - Paraffinic | 8/12 | 20 | 3,720 | - | ||||||||||||||||||||||
| Triton refined products terminals | ||||||||||||||||||||||||||
Anacortes (3) | n/a | n/a | - | - | ||||||||||||||||||||||
| Colex | n/a | n/a | - | 2,585 | ||||||||||||||||||||||
| Des Plaines | n/a | n/a | - | 1,060 | ||||||||||||||||||||||
| Portland | n/a | n/a | - | 405 | ||||||||||||||||||||||
Seattle (3) | n/a | n/a | - | 490 | ||||||||||||||||||||||
(1) In addition to the pipeline capacity above, Mars also has storage capacity under its lease of a storage cavern with a related party.
(2) The approximate capacity information presented is in kbpd with the exception of the approximate capacity related to Cleopatra gas
gathering system and Permian Basin which are presented in mscf/d, and Refinery Gas Pipeline which is presented in klbs/d.
(3) The Anacortes and Seattle refined products terminals have truck racks which are not included in the above table. The Anacortes refined products terminal does not have tank storage.
Our Relationship with Shell
Shell is one of the world’s largest independent energy companies in terms of market capitalization and operating cash flow, and Shell and its joint ventures are a leading producer and transporter of onshore and offshore hydrocarbons as well as a major refiner in the United States. As one of the largest producers in the Gulf of Mexico, Shell is currently developing several deepwater prospects and associated infrastructure. In addition to its offshore production, Shell has significant onshore exploration and production interests and produces crude oil and natural gas throughout North America. Shell’s downstream portfolio includes interests in refineries and chemical processing plants throughout the United States. Shell’s portfolio of midstream assets provides key infrastructure required to transport and store crude oil and refined products for Shell and third parties. Shell’s ownership interests in transportation and midstream assets include crude oil and refined products pipelines,
13
crude oil and refined products terminals, chemicals pipelines, natural gas pipelines and processing plants, and LNG infrastructure assets. Shell or its affiliates are customers of most of our businesses.
SPLC is Shell’s principal midstream subsidiary in the United States. As of December 31, 2018, SPLC owns our general partner, a 43.8% limited partner interest in us and all of our incentive distribution rights.
Customers
See Note 13—Transactions with Major Customers and Concentration of Credit Risk in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report.
Competition
Our pipeline systems compete primarily with other interstate and intrastate pipelines and with marine and rail transportation. Some of our competitors may expand or construct transportation systems that would create additional competition for the services we provide to our customers. For example, newly constructed transportation systems in the onshore Gulf of Mexico region may increase competition in the markets where our pipelines operate. In addition, future pipeline transportation capacity could be constructed in excess of actual demand, which could reduce the demand for our services, in the market areas we serve, and could lead to the reduction of the rates that we receive for our services. While we do see some variation from quarter-to-quarter resulting from changes in our customers’ demand for transportation, this risk has historically been mitigated by the long-term, fixed rate basis upon which we contracted our capacity. However, two of our transportation services agreements on our Zydeco pipeline system expired in December 2018, and another will expire in mid-2019. These contracts represented approximately 30% of our revenues for both the years ended December 31, 2018 and 2017. Our business may be negatively affected if we are unable to renew or replace our contract portfolio on comparable terms. See “Management's Discussion and Analysis of Financial Condition and Results of Operations — Changes in Customer Contracting” for additional information.
Competition among onshore common carrier crude oil pipelines is based primarily on posted tariffs, quality of customer service and connectivity to sources of supply and demand. We believe that our position along the Gulf Coast provides a unique level of service to our customers. Our pipelines and terminals face competition from a variety of alternative transportation methods including rail, water borne movements including barging, shipping and imports and other pipelines that service the same origins or destinations as our pipelines.
Our offshore crude oil pipelines are primarily supported by life-of-lease transportation agreements or direct connected production. However, our offshore pipelines will compete for new production on the basis of geographic proximity to the production, cost of connection, available capacity, transportation rates and access to onshore markets. The principal competition for our offshore pipelines include other crude oil pipeline systems as well as producers who may elect to build or utilize their own production handling facilities. In addition, the ability of our offshore pipelines to access future oil and gas reserves will be subject to our ability, or the producers’ ability, to fund the capital expenditures required to connect to the new production. In general, our offshore pipelines are not subject to regulatory rate-making authority, and the rates our offshore pipeline charges for services are dependent on market conditions.
Competition for refined product transportation in any particular area is affected significantly by the end market demand for the volume of products produced by refineries in that area, the availability of products in that area and the cost of transportation to that area from distant refineries. In light of current market conditions, as well as the expiration of certain transportation agreements, we expect greater competition in the markets in which we provide refined product transportation. See “Management's Discussion and Analysis of Financial Condition and Results of Operations — Factors Affecting Our Business and Outlook” for additional information.
Our storage terminal competes with surrounding providers of storage tank services. Some of our competitors have expanded terminals and built new pipeline connections, and third parties may construct pipelines that bypass our location. These, or similar events, could have a material adverse impact on our operations.
Our refined products terminals generally compete with other terminals that serve the same markets. These terminals may be owned by major integrated oil and gas companies or by independent terminaling companies. While fees for terminal storage and throughput services are not regulated, they are subject to competition from other terminals serving the same markets. However, our contracts provide for stable, long-term revenue, which is not impacted by market competitive forces.
FERC and State Common Carrier Regulations
Our interstate common carrier and intrastate pipeline systems are subject to economic regulation by various federal, state and local agencies.
14
FERC regulates interstate transportation on our common carrier pipeline systems under the ICA, the EPAct and the rules and regulations promulgated under those laws. FERC regulations require that rates and terms and conditions of service for interstate service pipelines that transport crude oil and refined 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 proposed new or changed rates, services, or terms and conditions of service. FERC is authorized to investigate such charges and may suspend the effectiveness of a new rate for up to seven months. Under certain circumstances, FERC could limit a common carrier pipeline’s ability to charge rates until completion of an investigation during which FERC could find that the new or changed rate is unlawful. In contrast, FERC has clarified that initial rates and terms of service agreed upon with committed shippers in a transportation services agreement are not subject to protest or a cost-of-service analysis where the pipeline held an open season offering all potential shippers service on the same terms.
A successful rate challenge could result in a common carrier pipeline paying refunds of revenue collected in excess of the just and reasonable rate, together with interest for the period the rate was in effect, if any. FERC may also order a pipeline to reduce its rates prospectively, and may require a common carrier pipeline to pay shippers reparations retroactively for rate overages for a period of up to two years prior to the filing of a complaint. FERC also has the authority to change terms and conditions of service if it determines that they are unjust or unreasonable or unduly discriminatory or preferential.
We may at any time also be required to respond to governmental requests for information, including compliance audits and rate case reviews conducted by FERC, such as the audit of Explorer and rate complaints filed against Colonial. FERC’s Office of Enforcement concluded an audit of Explorer in Docket No. FA16-5-000 for the period January 1, 2013 to December 31, 2016, and issued a letter order on January 12, 2018 adopting the audit’s findings and recommendations and requiring Explorer to submit a compliance plan and quarterly compliance reports. Explorer accepted the audit’s findings and recommendations, which did not have a financial impact to us. Several shippers on Colonial filed separate complaints with FERC on November 22, 2017, February 2, 2018, March 1, 2018, and April 20, 2018 challenging all of Colonial’s tariff rates, as well as its practices and charges related to transmix and product volume loss. The complaints were docketed as Docket Nos. OR18-7-000, OR18-12-000, OR18-17-000, and OR-21-000. On September 20, 2018, FERC issued an order consolidating the complaints into one proceeding and setting the complaints for hearing and settlement judge procedures. Settlement procedures are ongoing, and FERC has not taken any final action on the complaints as of this time.
Additionally, EPAct deemed certain interstate petroleum pipeline rates then in effect to be just and reasonable under the ICA. These rates are commonly referred to as “grandfathered rates.” For example, Colonial’s rates in effect at the time of the passage of EPAct for interstate transportation service were deemed just and reasonable and therefore are grandfathered. New rates have since been established after EPAct for certain grandfathered pipeline systems such as Zydeco. FERC may change grandfathered rates upon complaint only after it is shown that:
•a substantial change has occurred since enactment in either the economic circumstances or the nature of the services that were a basis for the rate;
•the complainant was contractually barred from challenging the rate prior to enactment of EPAct and filed the complaint within 30 days of the expiration of the contractual bar; or
•a provision of the tariff is unduly discriminatory or preferential.
EPAct required FERC to establish a simplified and generally applicable methodology to adjust tariff rates for inflation for interstate petroleum pipelines. As a result, FERC adopted an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the U.S. Producer Price Index for Finished Goods (“PPI-FG”). The indexing methodology is applicable to existing rates, including grandfathered rates, with the exclusion of market-based rates. FERC’s indexing methodology is subject to review every five years. FERC recently completed its five-year review, revised its indexing methodology and determined that during the five-year period commencing July 1, 2016 and ending June 30, 2021, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by PPI-FG plus 1.23%. The ruling was appealed and the appeal was denied by the D.C. Circuit Court on November 28, 2017. No further appeal is expected at this time. In May 2018, Zydeco, Mars, LOCAP and Colonial filed with FERC to increase rates subject to FERC’s indexing adjustment methodology by approximately 4.4% starting on July 1, 2018.
We cannot predict whether or to what extent the index factor may change in the future. A pipeline is not required to raise its rates up to the index ceiling, but it is permitted to do so; however a pipeline must reduce its indexed rates to the extent they exceed the index ceiling when a negative index applies. Some indexed rates on our systems were reduced in 2016 in response to
15
the lower index ceiling, such as certain spot rates on Zydeco. Rate increases made under the index methodology are presumed to be just and reasonable and require a protesting party to demonstrate that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. Despite these procedural limits on challenging the indexing of rates, the overall rates are not entitled to any specific protection against rate challenges. Under the indexing rate methodology, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling.
While common carrier pipelines often use the indexing methodology to change their rates, common carrier pipelines may elect to support proposed rates by using other methodologies such as cost-of-service rate making, market-based rates, and settlement rates. A common carrier pipeline can propose a cost-of-service approach when seeking to increase its rates above the rate ceiling (or when seeking to avoid lowering rates to the reduced rate ceiling), but must establish that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology. A common carrier can charge market-based rates if it establishes that it lacks significant market power in the affected markets. A common carrier can establish rates under settlement if agreed upon by all current shippers. Rates for a new service on a common carrier pipeline can be established through a negotiated rate with an unaffiliated shipper.
The rates shown in our FERC tariffs have been established using the indexing methodology, by settlement or by negotiation. If we used cost-of-service rate making to establish or support our rates on our different pipeline systems, the issue of the proper allowance for federal and state income taxes could arise. In 2005, FERC issued a policy statement stating that it would permit common carrier pipelines, among others, to include an income tax allowance in cost-of-service rates to reflect actual or potential tax liability attributable to a regulated entity’s operating income, regardless of the form of ownership. Under FERC’s policy, a tax pass-through entity seeking such an income tax allowance must establish that its partners or members have an actual or potential income tax liability on the regulated entity’s income. Whether a pipeline’s owners have such actual or potential income tax liability is subject to review by FERC on a case-by-case basis. Although this policy is generally favorable for common carrier pipelines that are organized as pass-through entities, it still entails rate risk due to FERC’s case-by-case review approach and recent changes to FERC’s policy following litigation in the U.S. Court of Appeals for the D.C.Circuit. The application of this policy, as well as any decision by FERC regarding our cost of service, is also subject to review in the courts.
Under its current policy, FERC permits regulated interstate oil and gas pipelines to include an income tax allowance in their cost of service used to calculate cost-based transportation rates. The allowance is intended to reflect the actual or potential tax liability attributable to the regulated entity’s operating income, regardless of the form of ownership. On July 1, 2016, in United Airlines, Inc. v FERC, the United States Court of Appeals for the D.C. Circuit vacated a pair of FERC orders to the extent they permitted an interstate refined petroleum products pipeline owned by a Master Limited Partnership (“MLP”) to include an income tax allowance in its cost-of-service rates. The D.C. Circuit held that 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 FERC on remand to fashion a remedy to ensure that the pipeline’s rates do not allow it to over-recover its costs. Following the D.C. Circuit’s decision, FERC issued its Revised Policy Statement on Treatment of Income Taxes in Docket No. PL17-1-000 on March 15, 2018 which eliminates the recovery of an income tax allowance by MLP oil and gas pipelines in cost-of-service-based rates. FERC directed MLP oil pipelines to reflect the elimination of the income tax allowance in their Form No. 6, page 700 reporting and stated that it will incorporate the effects of this Revised Policy on industry-wide oil pipeline costs in the 2020 five-year review of the oil pipeline index level. The Commission also stated that it would address income tax allowances for other “pass-through” entities that are not MLPs in future proceedings. On July 18, 2018, FERC clarified in Order No. 849, which was directed at gas pipelines, that its general disallowance of MLP income tax allowance recovery by providing that an MLP will not be precluded in a future proceeding from making a claim that it is entitled to an income tax allowance based on a demonstration that its recovery of an income tax allowance does not result in a “double-recovery of investors’ income tax costs.” While FERC has not taken industry-wide action on oil pipeline rates apart from announcing that it would take the MLP income tax allowance elimination into account in the next five-year review of indexed rates in 2020, FERC could require oil pipelines to revise their rates in individual proceedings (including initial rate filing or complaint proceedings) or through other action. To the extent that we charge cost-of-service based rates, those rates could be affected by any changes in FERC’s income tax allowance policy to the extent our rates are subject to complaint or challenge by FERC acting on its own initiative, or to the extent that we propose new cost-of-service rates or changes to our existing rates.
On December 22, 2017, federal legislation known as the “Tax Cuts and Jobs Act” (the “TCJA”) was enacted, which made various changes to the United States tax laws, including reducing the highest marginal U.S. federal corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017, adjusting the individual income tax brackets, and establishing limited deductions for certain income from “pass-through” entities. In the Revised Policy Statement on Treatment of Income Taxes issued in Docket No. PL17-1-000, FERC stated that it would address the effect of these tax changes on industry-wide oil pipeline costs in the 2020 five-year review of the oil pipeline index level. FERC also could require oil pipelines to revise their rates in individual proceedings (including initial rate filing or complaint proceedings) or through other
16
action. If the FERC requires us to establish new tariff rates that reflect changes resulting from the TCJA, it is possible that certain tariff rates could be reduced, which could adversely affect our financial position, results of operations and ability to make cash dividends to our Class A shareholders.
On October 20, 2016, FERC issued an Advance Notice of Proposed Rulemaking in Docket No. RM17-1-000 regarding changes to the oil pipeline rate index methodology and data reporting on the Page 700 of the FERC Form No. 6. In an effort to improve the Commission’s ability to ensure that oil pipeline rates are just and reasonable under the ICA, the Commission is considering making the following changes to their current indexing methodologies for oil pipelines:
1) Deny index increases for any pipeline whose Form No. 6, Page 700 revenues exceed costs by 15% for both of the prior two years;
2) Deny index increases that exceed by 5% the cost changes reported on Page 700; and
3) Apply the new criteria to costs more closely associated with the pipeline’s proposed rates than with total company-wide costs and revenues now reported on Page 700.
Initial comments were filed on January 19, 2017, reply comments were filed on March 17, 2017 and no further action has been taken since. We will continue to monitor developments in this area.
Intrastate services provided by certain of our pipeline systems are subject to regulation by state regulatory authorities, such as the Texas Railroad Commission, which currently regulates Zydeco and Colonial pipeline rates; and the Louisiana Public Service Commission, which currently regulates the Zydeco, Mars, Delta and Colonial pipeline rates. State agencies typically require intrastate petroleum pipelines to file their rates with the agencies and permit shippers to challenge existing rates and proposed rate increases. State agencies may also investigate rates, services, and terms and conditions of service on their own initiative. State regulatory commissions could limit our ability to increase our rates or to set rates based on our costs, or could order us to reduce our rates and require the payment of refunds to shippers.
Further, rate investigations by FERC or a state commission could result in an investigation of our costs, including the:
•overall cost of service, including operating costs and overhead;
•allocation of overhead and other administrative and general expenses to the regulated entity;
•appropriate capital structure to be utilized in calculating rates;
•appropriate rate of return on equity and interest rates on debt;
•rate base, including the proper starting rate base;
•throughput underlying the rate; and
•proper allowance for federal and state income taxes.
Shippers can always file a complaint with FERC or a state agency challenging rates or conditions of services. If they were successful, FERC or a state agency could order reparations or service charge.
Certain pipelines, including Auger, Na Kika, Amberjack, Odyssey, Poseidon, Proteus, Endymion, Cleopatra and parts of Mars, are located offshore in the Outer Continental Shelf. As such, they are not subject to FERC or state rate regulation, but are subject to the Outer Continental Shelf Lands Act (“OCSLA”). Under the OCSLA, we must provide open and nondiscriminatory access to both pipeline owner and non-owner shippers, and comply with other requirements.
Pipeline and Terminal Safety
Our assets are subject to strict safety laws and regulations. Our transportation and storage of crude oil, refined products, and dry gas involves a risk that hazardous liquids or gas 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, liability and/or reparations to land owners and significant business interruption. The PHMSA of the DOT has adopted safety regulations with respect to the design, construction, operation, maintenance, inspection and management of most of our assets. In addition, some states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. The states in which most of our assets are located, Texas and Louisiana, are among the states that have developed regulatory programs that parallel the federal regulatory scheme and are applicable to intrastate pipelines transporting hazardous liquids and gases. The few assets not covered by PHMSA are regulated by the U.S. Environmental Protection Agency (“EPA”) and various state agencies and are designed and maintained to industry accepted codes and standards. The PHMSA regulations contain requirements for the
17
development and implementation of pipeline 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, are included in a drug and alcohol testing program, and that pipeline operators develop comprehensive spill response plans.
We are subject to regulation by PHMSA under the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) and the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”). The NGPSA delegated to PHMSA through DOT the authority to regulate gas pipelines. The HLPSA delegated to PHMSA through DOT the authority to develop, prescribe, and enforce federal safety standards for the transportation of hazardous liquids by pipeline. Congress also enacted the Pipeline Safety Act of 1992, which added the environment to the list of statutory factors that must be considered in establishing safety standards for hazardous liquid pipelines, required regulations be issued to define the term “gathering line” and establish safety standards for certain “regulated gathering lines,” and mandated that regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in HCAs. In 1996, Congress enacted the Accountable Pipeline Safety and Partnership Act, which limited the operator identification requirement mandate to pipelines that cross a waterway where a substantial likelihood of commercial navigation exists, required that certain areas where a pipeline rupture would likely cause permanent or long-term environmental damage be considered in determining whether an area is unusually sensitive to environmental damage, and mandated that regulations be issued for the qualification and testing of certain pipeline personnel. The Pipeline Safety Improvement Act of 2002 established mandatory inspections for all U.S. oil transportation pipelines, and some gathering lines in HCAs. In the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, Congress required mandatory inspections for certain U.S. crude oil and natural gas transmission pipelines in HCAs and mandated that regulations be issued for low-stress hazardous liquids pipelines and pipeline control room management. These assets are also subject to the Pipeline Safety Act of 2011, which reauthorized funding for federal pipeline safety programs through 2015, increased penalties for safety violations, established additional safety requirements for newly constructed pipelines, and required studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. In 2016, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the “Pipes Act”) was enacted. The Pipes Act reauthorized the PHMSA through 2019 and imposed a few new mandates on the agency. The law provided the Secretary of the DOT the power to issue pipeline industry wide emergency orders if an incident poses or exposes a particular widespread problem. It also required the PHMSA to develop regulations for the construction and operations of underground natural gas storage facilities and instructed the PHMSA to finish the tasks left over from the 2011 bill. PHMSA will have to be reauthorized by Congress in 2019 and this reauthorization may create new mandates on the agency.
PHMSA administers compliance with these statutes and has promulgated comprehensive safety standards and regulations for the transportation of hazardous liquids by pipeline, including regulations for the design and construction of new pipeline systems or those that have been relocated, replaced, or otherwise changed (Subparts C and D of 49 CFR § 195); pressure testing (Subpart E of 49 CFR § 195); operation and maintenance of pipeline systems, including inspecting and reburying pipelines in the Gulf of Mexico and its inlets, establishing programs for public awareness and damage prevention, managing the integrity of pipelines in HCAs, and managing the operation of pipeline control rooms (Subpart F of 49 CFR § 195); protecting steel pipelines from the adverse effects of internal and external corrosion (Subpart H of 49 CFR § 195); and integrity management requirements for pipelines in HCAs (49 CFR § 195.452). Gas pipelines have similar requirements in 49 CFR 192. On January 19, 2017, PHMSA announced the issuance of new operator qualification rules that clarify the current regulations. This rule was published just before the Trump Administration requirement to withdraw all pending regulations for further review. This rule did not change the operator qualification requirements but did enhance release reporting requirements, placed new training requirements on control room personnel and provided reimbursement provisions for PHMSA oversight of projects totaling $1 billion or more. In addition, on January 30, 2017, the Trump Administration issued an executive order directing agencies to identify two existing regulations to be repealed for every new regulation proposed for notice and comment, along with a zero sum incremental cost requirement for all regulations. This directive applies at the DOT level so it is unclear if 49 CFR 190-199 will be impacted at all as the DOT could pull regulations from other areas such as road transport or hazardous materials handling where there are more regulations that could be considered worthy of repeal in order to cover the repeal and cost cutting directives.
The safety enhancement requirements and other provisions of the Pipeline Safety Act of 2011, as well as any implementation of PHMSA rules thereunder, could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis; any or all of which tasks could result in our incurring increased operating costs that could be significant and have a material adverse effect on our operations or financial position. However, we do not anticipate we would be impacted by these regulatory initiatives to any greater degree than other similarly situated competitors. PHMSA has provided guidance on verification of records related to pipeline maximum allowable operating pressure for gas pipelines and has drafted regulations to formally incorporate this guidance. While this is currently targeted at gas pipelines it could eventually be rolled over to the liquid regulations and we continue to work with industry groups to
18
provide comment and recommendations to PHMSA on proposed regulations to help ensure regulations that will improve safety without providing undue burdens to operators.
We monitor the structural integrity of our pipelines through a program of periodic internal assessments using a variety of internal inspection tools, as well as hydrostatic testing that conforms to federal standards. We accompany these assessments with a comprehensive data integration effort and repair anomalies, as required, to ensure the integrity of the pipeline. We conduct a thorough review of risks to the pipelines and perform sophisticated calculations to establish an appropriate reassessment interval for each pipeline. We use external coatings and impressed current cathodic protection systems to protect against external corrosion. We conduct all cathodic protection work in accordance with National Association of Corrosion Engineers standards and continually monitor, test and record the effectiveness of these corrosion inhibiting systems. We have robust third party damage prevention and public awareness programs to help protect our lines from the risk of excavation and other outside force damage threats. Our tanks are inspected on a routine basis in compliance with PHMSA and EPA regulations. Every tank periodically receives a full out of service, internal inspection per American Petroleum Institute standard 653 and is repaired as necessary.
Product Quality Standards
Refined products that we transport are generally sold by our customers for consumption by the public. Various federal, state and local agencies have the authority to prescribe product quality specifications for refined 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 refined products in our system and could require the construction of additional storage. If we are unable to recover these costs through increased revenue, our cash flows and ability to pay cash distributions could be adversely affected. In addition, changes in the product quality of the refined products we receive on our refined product pipeline systems or at our tank farms could reduce or eliminate our ability to blend refined products.
Security
We are also subject to U.S. Department of Homeland Security Chemical Facility Anti-Terrorism Standards, which are designed to regulate the security of high-risk chemical facilities, and to Transportation Security Administration 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.
Information Technology and Cybersecurity
We use our Parent’s information technology systems, which are increasingly dependent on key contractors supporting the delivery of information technology (“IT”) services, and continue to expand in terms of number of systems. Shell, like many other multinational companies, is the target of attempts to gain unauthorized access to its IT systems and our data through various channels, including more sophisticated and coordinated attempts often referred to as advanced persistent threats. Shell continuously measures and, where required, further improves its cyber-security capabilities to reduce the likelihood of successful cyber-attacks. Shell’s cyber-security capabilities are embedded into its IT systems and its IT landscape is protected by various detective and protective technologies. The identification and assessment capabilities are built into Shell’s support processes and adhere to industry best practices. While cyber-security programs and protocols are in place, we cannot guarantee their effectiveness. A significant cyber-attack could have a material effect on our operations.
While we are not currently subject to U.S. 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 Department of Homeland Security, and we may become subject to such standards in the future. In addition, the European Union (“EU”) General Data Protection Regulation (“GDPR”) came into force in May 2018. The GDPR increases penalties up to a maximum of 4% of global turnover for breach of the regulation. The GDPR requires mandatory breach notification.
Environmental Matters
General. Our operations are subject to extensive and frequently changing federal, state and local laws, regulations and ordinances relating to the protection of the environment. Among other things, these laws and regulations govern the emission or discharge of pollutants into or onto the land, air and water, the handling and disposal of solid and hazardous wastes and the remediation of contamination. As with the industry in general, compliance with existing and anticipated environmental laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, operate and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we
19
believe they do not affect our competitive position, as the operations of our competitors are similarly affected. We believe our facilities are in substantial compliance with applicable environmental laws and regulations. However, these laws and regulations are subject to changes, or to changes in the interpretation of such laws and regulations, by regulatory authorities, and continued and future compliance with such laws and regulations may require us to incur significant expenditures. Additionally, violation of environmental laws, regulations, and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions limiting our operations, investigatory or remedial liabilities or construction bans or delays in the construction of additional facilities or equipment. Additionally, a release of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expenses, including costs to comply with applicable laws and regulations and to resolve claims by third parties for personal injury or property damage, or by the U.S. federal government or state governments for natural resources damages. These impacts could directly and indirectly affect our business and have an adverse impact on our financial position, results of operations and liquidity if we do not recover these expenditures through the rates and fees we receive for our services. We believe our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including, but not limited to, the type of competitor and location of its operating facilities.
We accrue for environmental remediation activities when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. As environmental remediation matters proceed toward ultimate resolution or as additional remediation obligations arise, charges in excess of those previously accrued may be required. New or expanded environmental requirements, which could increase our environmental costs, may arise in the future. We believe we comply with all legal requirements regarding the environment, but since not all of them are fixed or presently determinable (even under existing legislation) and may be affected by future legislation or regulations, it is not possible to predict all of the ultimate costs of compliance, including remediation costs that may be incurred and penalties that may be imposed.
Air Emissions and Climate Change. Our operations are subject to the Clean Air Act and its regulations and comparable state and local statutes and regulations in connection with air emissions from our operations. Under these laws, permits may be required before construction can commence on a new source of potentially significant air emissions, and operating permits may be required for sources that are already constructed. These permits may require controls on our air emission sources, and we may become subject to more stringent regulations requiring the installation of additional emission control technologies.
Future expenditures may be required to comply with the Clean Air Act and other federal, state and local requirements for our various sites, including our pipeline and storage facilities. The impact of future legislative and regulatory developments, if enacted or adopted, could result in increased compliance costs and additional operating restrictions on our business, all of which could have an adverse impact on our financial position, results of operations and liquidity.
In December 2007, Congress passed the Energy Independence and Security Act that created a second Renewable Fuels Standard. This standard requires the total volume of renewable transportation fuels (including ethanol and advanced biofuels) sold or introduced annually in the U.S. to rise to 36 billion gallons by 2022. The requirements could reduce future demand for refined products and thereby have an indirect effect on certain aspects of our business.
Currently, various legislative and regulatory measures to address greenhouse gas emissions (including carbon dioxide, methane and other gases) are in various phases of discussion or implementation in the U.S. These include requirements effective in 2010 to report emissions of greenhouse gases (“GHG”) to the EPA on an annual basis, and proposed federal legislation and regulation as well as state actions to develop statewide or regional programs, each of which require or could require reductions in our greenhouse gas emissions. Requiring reductions in greenhouse gas emissions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls at our facilities and (iii) administer and manage any greenhouse gas emissions programs, including acquiring emission credits or allotments. These requirements may also significantly affect domestic refinery operations and may have an indirect effect on our business, financial condition and results of operations. We do not believe the federal greenhouse gas reporting rule, as described above, or the greenhouse gas “tailoring” rule, which subjects certain facilities to the additional permitting obligations under the New Source Review/Prevention of Significant Deterioration and Title V programs of the Clean Air Act based on a facility’s greenhouse gas emissions, will have a material adverse effect on our operations.
In addition, the EPA has proposed and may adopt further regulations under the Clean Air Act addressing greenhouse gases, to which some of our facilities may become subject. For example, in May 2016, EPA finalized new rules for volatile organic compound and methane emissions from the oil and gas production, processing, transmission and storage industry. Congress continues to consider legislation on greenhouse gas emissions, which may include a delay in the implementation of greenhouse gas regulations by EPA or a limitation on EPA’s authority to regulate greenhouse gases, although the ultimate adoption and form of any federal legislation cannot presently be predicted. 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
20
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. In June 2017 the Trump Administration announced its intent to withdraw from the Paris Agreement. Pursuant to the terms of the Paris Agreement, the earliest date the U.S. can withdraw is November 2020. The impact of future regulatory and legislative developments, if adopted or enacted, could result in increased compliance costs, increased utility costs, additional operating restrictions on our business, and an increase in the cost of products generally. Although such costs may impact our business directly or indirectly by impacting our facilities or operations, the extent and magnitude of that impact cannot be reliably or accurately estimated due to the present uncertainty regarding the additional measures and how they will be implemented.
Waste Management and Related Liabilities. To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into soils, groundwater and surface water, and include measures to control pollution of the environment. These laws generally regulate the generation, storage, treatment, transportation, and disposal of solid and hazardous waste. They also require corrective action, including investigation and remediation, at a facility where such waste may have been released or disposed.
CERCLA. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), which is also known as Superfund, and comparable state laws impose liability, without regard to fault or to the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the former and present owner or operator of the site where the release occurred and the transporters and generators of the hazardous substances found at the site.
Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, we generate waste that falls within CERCLA’s definition of a “hazardous substance” and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites.
RCRA. We also generate solid wastes, including hazardous wastes, that are subject to the requirements of the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. From time to time, the EPA considers the adoption of stricter disposal standards for non-hazardous wastes. Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes. Any changes in the regulations could impact our maintenance capital expenditures and operating expenses. We continue to seek methods to minimize the generation of hazardous wastes in our operations.
Hydrocarbon Wastes. We currently own and lease, and SPLC has in the past owned and leased, properties where hydrocarbons are being or for many years have been handled. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or waste may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these hydrocarbons and wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or wastes was not under our control. These properties and hydrocarbons and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater), or to perform remedial operations to prevent further contamination.
Environmental Indemnity. The terms of each acquisition will vary, and in some cases we may receive contractual indemnification from the prior owner or operator for some or all of the liabilities relating to such matters, and in other cases we may agree to accept some or all of such liabilities. We do not believe that the portion of any such liabilities that the Partnership may bear with respect to any such properties previously acquired by the Partnership will have a material adverse impact on our financial condition or results of operations. For example, in connection with certain of our acquisitions from Shell, Shell agreed to indemnify us for certain environmental liabilities arising before the closing date, subject to customary deductibles and caps.
SPLC’s indemnification for breaches of representations or warranties relating to environmental matters in connection with the Initial Public Offering (“IPO”) terminated and expired on November 3, 2017.
Water. Our operations can result in the discharge of pollutants, including crude oil and refined products. Regulations under the Water Pollution Control Act of 1972 (“Clean Water Act”), Oil Pollution Act of 1990 (“OPA-90”) and state laws impose regulatory burdens on our operations. Spill prevention control and countermeasure requirements of federal laws and some state
21
laws require containment to mitigate or prevent contamination of navigable waters in the event of an oil overflow, rupture, or leak. For example, the Clean Water Act requires us to maintain Spill Prevention Control and Countermeasure (“SPCC”) plans at many of our facilities. We maintain numerous discharge permits as required under the National Pollutant Discharge Elimination System program of the Clean Water Act and have implemented tracking systems to oversee our compliance efforts. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. We believe we are in substantial compliance with applicable storm water permitting requirements.
In addition, the transportation and storage of crude oil and refined products over and adjacent to water involves risk and subjects us to the provisions of OPA-90 and related state requirements. Among other requirements, OPA-90 requires the owner or operator of a tank vessel or a facility to maintain an emergency plan to respond to releases of oil or hazardous substances. Also, in case of any such release, OPA-90 requires the responsible company to pay resulting removal costs and damages. OPA-90 also provides for civil penalties and imposes criminal sanctions for violations of its provisions. We operate facilities at which releases of oil and hazardous substances could occur. We have implemented emergency oil response plans for all of our components and facilities covered by OPA-90 and we have established SPCC plans for facilities subject to Clean Water Act SPCC requirements.
Construction or maintenance of our pipelines, tank farms and storage facilities may impact wetlands, which are also regulated under the Clean Water Act by the EPA and the U.S. Army Corps of Engineers. Regulatory requirements governing wetlands (including associated mitigation projects) may result in the delay of our pipeline projects while we obtain necessary permits and may increase the cost of new projects and maintenance activities.
Employee Safety. We are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.
Endangered Species Act. The Endangered Species Act restricts activities that may affect endangered species or their habitats. While some of our facilities are in areas that may be designated as habitat for endangered species, we believe that we are in substantial compliance with the Endangered Species Act. If endangered species are located in areas of the underlying properties where we wish to conduct development activities, such work could be prohibited or delayed or expensive mitigation may be required. In addition, the designation of new endangered species could cause us to incur additional costs or become subject to operating or development restrictions or bans in the affected area.
Inflation
Inflation did not have a material impact on our results of operations in 2018.
Seasonality
The volume of crude oil and refined products transported and stored utilizing our assets is directly affected by the level of supply and demand for crude oil and refined products in the markets served directly or indirectly by our assets. Additionally, producer turnarounds are often planned for certain periods during the year based on optimal, and in some cases, required, weather and working conditions.
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 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.
Future Financial Assurance
22
In July 2016, BOEM issued Notice to Lessees and Operators 2016 NOI (“NTL”) that augmented requirements above current levels for the posting of additional financial assurance by offshore lessees, among others, to assure that sufficient funds are available to perform decommissioning obligations with respect to platforms, pipelines and other facilities. In June 2017, BOEM announced that it would extend the NTL implementation timeline beyond the initial June 30, 2017 deadline, except in circumstances where there is a substantial risk of non-performance of decommissioning obligations, citing that more time was needed to work with the industry and other interested parties. There have been no further developments.
Insurance
All assets in which we have an interest are insured for certain property damage, business interruption and third party liabilities, inclusive of cyber event and pollution liabilities, in amounts which management believes are reasonable and appropriate. With the exception of Odyssey, our consolidated assets are insured at the entity level. For Odyssey, as well as our other non-consolidated interests in joint ventures, we carry commercial insurance for our pro rata interests.
Employees
We do not have any employees. We are managed and operated by the directors and officers of our general partner. See Part III, Item 10. Directors, Executive Officers and Corporate Governance — Management of Shell Midstream Partners, L.P. in this report.
Control Center Operations
Zydeco, Amberjack, Mars, Odyssey, Bengal’s pipeline, Auger, Lockport, Delta, Na Kika, Proteus, Endymion, Cleopatra, Refinery Gas Pipeline and our terminals are operated by SPLC or our general partner pursuant to operating and maintenance agreements. The pipeline, storage and terminal systems that are operated by SPLC are controlled from a central control room located in Houston, Texas. We took over control of central control room activities for Proteus, Endymion and Cleopatra on April 1, 2018. Colonial operates its pipeline system and Bengal’s tankage in a similar manner and has its own management team based in Alpharetta, Georgia. Explorer operates its pipeline system in a similar manner and has its own management team and control center operations in Tulsa, Oklahoma. Poseidon is operated by Manta Ray Gathering Company, LLC, LOCAP is operated by LOOP LLC and Permian Basin is operated by CPB Operator LLC.
Website
Our Internet website address is http://www.shellmidstreampartners.com. Information contained on our Internet website is not part of this report. Our Annual Reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments and exhibits to these reports, filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on our website, free of charge, as soon as reasonably practicable after such reports are filed with, or furnished to, the SEC. Alternatively, you may access these reports at the SEC’s website at http://www.sec.gov. We also post our beneficial ownership reports filed by officers, directors, and principal security holders under Section 16(a) of the Securities Exchange Act of 1934, corporate governance guidelines, audit committee charter, code of business ethics and conduct, code of ethics for senior financial officers, and information on how to communicate directly with our board of directors on our website.
23
Item 1A. RISK FACTORS
Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. If any of the following risks actually occur, they may materially harm our business and our financial condition and results of operations. In this event, we might not be able to pay distributions on our common units, and the trading price of our common units could decline.
Risks Related to Our Business
We may not have sufficient cash available for distribution 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 pay minimum quarterly distributions to our unitholders.
We may not generate sufficient cash flows each quarter to enable us to pay minimum quarterly 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 SPLC with respect to those expenses;
•the volume of crude oil, refined products and refinery gas that we transport and the ability of our customers to meet their obligations under our contracts;
•actions by FERC or other regulatory bodies that reduce our rates or increase expenses;
•the amount and timing of expansion capital expenditures and acquisitions we make;
•the amount of maintenance capital expenditures we make;
•our debt service requirements and other liabilities, and restrictions contained in our debt agreements;
•fluctuations in our working capital needs;
•the amount of cash distributed to us by the entities in which we own a noncontrolling interest;
•the amount of cash reserves established by our general partner; and
•changes in, and availability to us, of the equity and debt capital markets.
We do not control certain of the entities that own our assets.
We have no significant assets other than our ownership interests in entities that own crude oil, refined products and refinery gas pipelines and a crude tank storage and terminal system. As a result, our ability to make distributions to our unitholders depends on the performance of these entities and their ability to distribute funds to us. More specifically:
•many of the entities in which we own interests are managed by their respective governing board. Our ability to influence decisions with respect to the operation of such entities varies depending on the amount of control we exercise under the applicable governing agreement;
•we do not control the amount of cash distributed by several of the entities in which we own interests. We may influence the amount of cash distributed through our veto rights over the cash reserves made by certain of these entities;
•we may not have the ability to unilaterally require certain of the entities in which we own interests to make capital expenditures, and such entities may require us to make additional capital contributions to fund operating and maintenance expenditures, as well as to fund expansion capital expenditures, which would reduce the amount of cash otherwise available for distribution by us or require us to incur additional indebtedness;
•the entities in which we own interests may incur additional indebtedness without our consent, which debt payments would reduce the amount of cash that might otherwise be available for distribution;
•our assets are operated by entities that we do not control; and
24
•the operator of the assets held by each joint venture and the identity of our joint venture partners could change, in some cases without our consent.
For more information on the agreements governing the management and operation of the entities in which we own an interest, see Part III, Item 13. Certain Relationships and Related Party Transactions, and Director Independence — Agreements with Shell and Part I, Items 1 and 2. Business and Properties — Our Assets and Operations in this report.
Our ability to renew or replace our third-party contract portfolio on comparable terms could materially adversely affect our business, financial condition, results of operations and cash flows, including our ability to make distributions.
As portions of our third-party contract portfolio come up for replacement or renewal, and capacity becomes available, adverse market conditions may prevent us from replacing or renewing the contracts on comparable terms. For example, two of our transportation services agreements on our Zydeco pipeline system expired in December 2018, and another will expire in the second quarter of 2019. These contracts represented approximately 30% of our revenues for the year ended December 31, 2018. Our ability to achieve favorable terms under these expiring contracts could be affected by many factors, including:
•prolonged lower commodity prices;
•a decrease in demand for our services in the markets we serve;
•increased competition for our services in the markets we serve; and
•actions by FERC or other regulatory bodies that impact our rates or costs.
If we replace the expiring agreements with short-term or spot transportation or storage services, our revenues could be more volatile than they would be under long-term arrangements. If we are unable to replace the expiring agreements or renew the expiring agreements on comparable terms, it could materially adversely affect our business, financial condition, results of operations and cash flows, including our ability to make cash distributions to our unitholders.
If we are unable to obtain needed capital or financing on satisfactory terms to fund expansions of our asset base, our ability to make or increase quarterly cash distributions may be diminished or our financial leverage could increase. Other than our credit facilities, we do not have any contractual commitments with any of our affiliates to provide any direct or indirect financial assistance to us.
We will be required to do one of the following; use cash from our operations, incur borrowings or access the capital markets in order to fund our capital expenditures. If we do not make sufficient or effective capital expenditures, we may be unable to expand our business operations and may be unable to maintain or raise the level of our quarterly cash distributions. The entities in which we own an interest may also incur borrowings or access the capital markets to fund capital expenditures and may require that we fund our proportionate share of such expenditures. Our and their ability to obtain financing 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, or other uncertainties that are beyond our control. Furthermore, market demand for equity issued by MLP’s has been significantly lower in recent years than it has been historically, which may make it more challenging for us to finance our capital expenditures and to fund acquisitions with the issuance of equity in the capital markets. Any further decline in the debt and equity capital markets may increase the cost of financing and the risks of refinancing maturity debt. There can be no assurance that the capital markets will be available to us on acceptable terms or at all. The terms of any financing or the use of cash on hand could limit our ability to pay 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.
Our 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 operations and financial results could be materially and adversely affected.
Our operations are subject to all of the risks and operational hazards inherent in transporting and storing crude oil and refined products, including:
•damages to pipelines, facilities, offshore pipeline equipment and surrounding properties caused by third parties, severe weather, natural disasters, including hurricanes, and acts of terrorism;
25
•maintenance, repairs, mechanical or structural failures at our or SPLC’s facilities or at third-party facilities on which our customers’ or our operations are dependent, including electrical shortages, power disruptions, power grid failures and planned turnarounds;
•damages to, loss of availability of and delays in gaining access to interconnecting third-party pipelines, terminals and other means of delivering crude oil, refined products and refinery gas;
•costs and liabilities in responding to any soil and groundwater contamination that occurs on our terminal properties, even if the contamination was caused by prior owners and operators of our terminal system;
•disruption or failure of information technology systems and network infrastructure due to various causes, including unauthorized access or attack of the central control room from which some of our pipelines are remotely controlled;
•leaks of crude oil or refined products as a result of the malfunction or age of equipment or facilities;
•unexpected business interruptions;
•curtailments of operations due to severe seasonal weather; and
•riots, strikes, lockouts or 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 adverse effect on our business, financial condition and results of operations.
For example, beginning in the latter part of 2017 we ran an in-line inspection tool on our Zydeco pipeline system, hydro-tested the system and invested in additional equipment to mitigate the effects of pressure cycling in the future. The hydro-test resulted in the Zydeco pipeline from Houston, Texas and Houma, Louisiana being out of service for 49 days in the first quarter of 2018. The impact to net income and cash available for distribution was approximately $60.0 million in the first quarter of 2018. Final remediation activities were completed in the second quarter of 2018 with no material impact.
If third-party pipelines, production platforms, refineries, caverns and other facilities interconnected to our pipelines, Triton’s refined product terminal and Lockport’s terminal facilities become unavailable to transport, produce, refine or store crude oil, or produce or transport refined product, our revenue and available cash could be adversely affected.
We depend upon third-party pipelines, production platforms, refineries, caverns and other facilities that provide delivery options to and from our pipelines and terminal facilities. For example, Mars depends on a natural gas supply pipeline connecting to the West Delta 143 platform to power its equipment to deliver the volumes it transports to salt dome caverns in Clovelly, Louisiana. Similarly, shutdown or blockage of pipelines moving offshore gas can result in curtailment or shut-in of offshore crude production. Because we do not own these third-party pipelines, production platforms, refineries, caverns or facilities, their continuing operation is not within our control. For example, production platforms in the offshore Gulf of Mexico may be required to be shut in by BSEE or BOEM of the U.S. Department of the Interior following incidents such as loss of well control. If these or any other pipeline or terminal connection were to become unavailable for current or future volumes of crude oil or refined product due to repairs, damage to the facility, lack of capacity, shut in by regulators or any other reason, or if caverns to which we connect have cracks, leaks or leaching or require shut-in due to regulatory action or changes in law, our ability to operate efficiently and continue to store or ship crude oil and refined products to major demand centers could be restricted, thereby reducing revenue. Disruptions at refineries that use our pipelines, such as strikes or ship channel incidents, can also have an adverse impact on the volume of products we ship. Increases in the rates charged by the interconnected pipelines for transportation to and from our terminal facilities may reduce the utilization of our terminals. Our refined products terminals are limited to a 5% reduction in payments by the customer due to force majeure incidents. Any temporary or permanent interruption at any key pipeline or terminal interconnect, at any key production platform or refinery, at caverns to which we deliver, termination of any connection agreement, or adverse change in the terms and conditions of service, could have a material adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make cash distributions to our unitholders.
In the second quarter of 2018, Mars experienced lower volumes due to a planned producer turnaround. The impact to net income and cash available for distribution was approximately $7.0 million in 2018. Volumes returned to anticipated levels in the third quarter of 2018.
In November 2017, the Enchilada platform in Garden Banks Block 128 experienced a fire that resulted in the shut-in of all production flowing through Auger. The impact to net income and cash available for distribution in 2018 was approximately
26
$11.0 million. The platforms contributing a majority of Auger’s daily throughput have returned to service in the first quarter of 2018, and the remaining impacted platforms resumed production in the third quarter of 2018.
In the beginning of the fourth quarter of 2017, fields connecting to Odyssey went offline due to operational issues and came back online in the third quarter of 2018. The impact to net income and cash available for distribution for Odyssey and Delta was approximately $9.0 million in 2018.
If we are unable to make acquisitions on economically acceptable terms from Shell 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 cash available for distribution per unit. The consummation and timing of any future acquisitions will depend upon, among other things, whether we are able to:
•identify attractive acquisition candidates;
•negotiate acceptable purchase agreements;
•obtain financing for these acquisitions on economically acceptable terms, which may be more difficult at times when the capital markets are less accessible; and
•outbid any competing bidders.
We can offer no assurance that we will be able to successfully consummate any future acquisitions, whether from Shell 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 cash available for distribution per unit as a result of incorrect assumptions in our evaluation of such acquisitions or unforeseen consequences or other external events beyond our control. We may incur difficulties and additional costs in connection with integrating an acquired asset or entity. Acquisitions involve numerous risks, inefficiencies and unexpected costs and liabilities.
Any significant decrease in production of crude oil in areas in which we operate could reduce the volumes of crude oil we transport and store, which could adversely affect our revenue and available cash.
Our crude oil pipelines and terminal system depend on the continued availability of crude oil production and reserves, particularly in the Gulf of Mexico. Low prices for crude oil could adversely affect development of additional reserves and continued production from existing reserves that are accessible by our assets.
Crude oil prices have fluctuated significantly over the past few years, often with drastic moves in relatively short periods of time. During 2018, prices slowly increased from 2017 levels until the middle of the fourth quarter, at which point there was a steep decline. The current global geopolitical and economic uncertainty may contribute to continued volatility in financial and commodity markets in the near to medium term. High, low and average daily prices for West Texas Intermediate (“WTI”) crude oil at Cushing, Oklahoma during January 2019, 2018 and 2017 were as follows:
| WTI Crude Oil Prices | |||||||||||||||||
| High | Average | Low | |||||||||||||||
| January 2019 | $ | 54.18 | $ | 51.38 | $ | 46.31 | |||||||||||
| 2018 | 77.41 | 65.23 | 44.48 | ||||||||||||||
| 2017 | 60.46 | 50.80 | 42.48 | ||||||||||||||
In general terms, the prices of crude oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors impacting crude oil prices include worldwide economic conditions; weather conditions and seasonal trends; the levels of domestic production and consumer demand; the availability of imported crude oil; the availability of transportation systems with adequate capacity; the volatility and uncertainty of regional basis differentials and premiums; actions by the Organization of the Petroleum Exporting Countries and other oil producing nations; the price and availability of alternative energy, including alternative energy which may benefit from government subsidies; the effect of energy conservation measures; the strength of the U.S. dollar; the nature and extent of governmental regulation and taxation; and the anticipated future prices of crude oil and other commodities.
27
Lower crude oil prices, or expectations of declines in crude oil prices, have had and may continue to have a negative impact on exploration, development and production activity, particularly in the continental U.S. If lower prices are sustained, it could lead to a material decrease in such activity both onshore continental U.S. and in the Gulf of Mexico. Sustained reductions in exploration or production activity in our areas of operation could lead to reduced utilization of our pipeline and terminal systems or reduced rates under renegotiated transportation or storage agreements. Our customers may also face liquidity and credit issues that could impair their ability to meet their payment obligations under our contracts or cause them to renegotiate existing contracts at lower rates or for shorter terms. These conditions may lead some of our customers, particularly customers that are facing financial difficulties, to seek to renegotiate existing contracts on terms that are less attractive to us. Any such reduction in demand or less attractive terms could have a material adverse effect on our results of operations, financial position and ability to make or increase cash distributions to our unitholders.
In addition, production from existing areas with access to our pipeline and terminal systems will naturally decline over time. The amount of crude oil reserves underlying wells in these areas may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Accordingly, to maintain or increase the volume of crude oil transported, or throughput, on our pipelines, or stored in our terminal system, and cash flows associated with the transportation and storage of crude oil, our customers must continually obtain new supplies of crude oil. In addition, we will not generate revenue under our life-of-lease transportation agreements that do not include a guaranteed return to the extent that production in the area we serve declines or is shut in.
If new supplies of crude oil are not obtained, including supplies to replace any decline in volumes from our existing areas of operations, the overall volume of crude oil transported or stored on our systems would decline, which could have a material adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make cash distributions to our unitholders.
Any significant decrease in the demand for crude oil, refined products and refinery gas could reduce the volumes of crude oil, refined products and refinery gas that we transport, which could adversely affect our revenue and available cash.
The volumes of crude oil, refined products and refinery gas that we transport depend on the supply and demand for crude oil, gasoline, jet fuel, refinery gas and other refined products in our geographic areas. Demand for crude oil, refined products and refinery gas may decline in the areas we serve as a result of, decreased production by our customers, depressed commodity price environment, increased competition, and adverse economic factors, affecting the exploration, production and refining industries.
Further, crude oil, refined products and refinery gas compete with other forms of energy available to users, including electricity, coal, other fuels and alternative energy. Increased demand for such forms of energy at the expense of crude oil, refined products and refinery gas could lead to a reduction in demand for our services.
If the demand for crude oil, refined products or refinery gas decreases significantly, or if there were a material increase in the price of crude oil supplied to our customers’ refineries without an increase in the value of the products produced by those refineries, either temporary or permanent, it may cause our customers to reduce production of refined products at their refineries. If production of refined products declines, there would likely be a reduction in the volumes of crude oil and refined products that we transport. Any such reduction could have a material adverse effect on our results of operations, financial position and ability to make cash distributions to our unitholders.
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.
With the exception of Odyssey, our consolidated assets are insured at the entity level for certain property damage, business interruption and third-party liabilities, which includes pollution liabilities. For Odyssey, as well as our other non-consolidated interests in joint ventures, the current owners are required to carry insurance for their pro rata interest. We carry commercial insurance for our pro rata interests, which will increase our operations and maintenance expenses.
All of the insurance policies relating to our assets and operations are subject to policy limits. In addition, the waiting period under the business interruption insurance policies of the entities in which we own an interest is 60 days. We and the entities in which we own an interest 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. Changes in the insurance markets subsequent to the September 11, 2001 terrorist attacks and certain hurricanes and natural disasters have made it more difficult and more expensive to obtain certain types of coverage. The occurrence of an event that is not fully covered by insurance, or failure by our insurer to honor its coverage commitments for an insured event, could have a material adverse effect on our business, financial condition
28
and results of operations. Insurance companies may reduce the insurance capacity they are willing to offer or may demand significantly higher premiums or deductibles to cover our assets. 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. There is no assurance that the insurers of the entities in which we own an interest will renew their insurance coverage on acceptable terms, if at all, or that the entities in which we own an interest 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 the entities in which we own an interest suffer significant losses could have a material adverse effect on our business, financial condition and results of operations, including our ability to make cash 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 any of our most significant customers default on their 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. If any of our customers were to seek protection under the U.S. Bankruptcy Code or other insolvency laws, the court could void the customer’s contracts with us or allow our customer to reject such contracts. For certain of our pipelines, we may have a limited pool of potential customers and may be unable to replace any customers who default on their obligations to us. Therefore, any material deterioration in the creditworthiness of our customers or any material nonpayment or nonperformance by our customers could have a material adverse effect on our business, financial condition and results of operations, including our ability to make cash distributions to our unitholders.
In addition, we are subject to political and economic risks that impact our customers. For example, the U.S. has gradually expanded sanctions that have impacted Petroleos de Venezuela, S.A. (“PdVSA”) and its subsidiaries as well as the Government of Venezuela. On January 28, 2019, the Trump Administration designated PdVSA on the Specifically Designated Nationals and Blocked Persons List administered by the U.S. Treasury Department’s Office of Foreign Asset Control (“OFAC”). As a result, U.S. persons are generally prohibited from engaging in transactions with PdVSA and its majority-owned subsidiaries. Certain of our customers are subsidiaries of PdVSA and, as a result, we and certain of our customers may be impacted if the General Licenses allowing for the temporary continuation of operations or engagements with PdVSA and its majority-owned subsidiaries expire in 2019. Therefore, absent further action by the U.S. and OFAC, the loss of customers as a result of the sanctions could have a material adverse effect on our business, financial condition and results of operations, including our ability to make cash 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 expand our existing pipelines and terminals, such as by adding horsepower, pump stations, new connections or additional tank storage. We also intend to evaluate and capitalize on organic opportunities for expansion projects in order to increase revenue on our assets. If we undertake these projects, they may not be completed on schedule or at all or at the budgeted cost.
These expansion projects involve numerous regulatory, environmental, political and legal uncertainties, most of which are beyond our control.
Moreover, we may not receive sufficient long-term contractual commitments or spot shipments from customers to provide the revenue needed to support 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 spot shipments or make such interconnections, we may not realize an increase in revenue for an extended period of time. As a result, new or expanded facilities may not be able to attract enough throughput to achieve our expected investment return, which could have a material adverse effect on our business, financial condition and results of operations, including our ability to make cash 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 leases or 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 or similar rights, through our inability to renew leases, right-of-way contracts or otherwise, or inability to obtain
29
easements at reasonable costs could have a material adverse effect on our business, results of operations, financial condition and cash flows, including our ability to make cash distributions to our unitholders.
We are subject to pipeline safety laws and regulations, compliance with which may require significant capital expenditures, increase our cost of operations and affect or limit our business plans.
Our interstate and offshore pipeline operations are subject to pipeline safety regulations administered by the PHMSA of the DOT. These laws and regulations require us to comply with a significant set of requirements for the design, construction, operation, maintenance, inspection and management of our crude oil, refined products and refinery gas pipelines.
Certain aspects of our offshore pipeline operations, such as new construction and modification, are also regulated by BOEM, BSEE and the U.S. Coast Guard.
PHMSA has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines, with enhanced measures required for pipelines located where a leak or rupture could harm an HCA. The regulations require operators to:
•perform ongoing assessments of pipeline integrity;
•identify and characterize applicable threats to pipeline segments that could affect an HCA;
•improve data collection, integration and analysis;
•repair and remediate the pipeline as necessary; and
•implement preventive and mitigating actions.
In addition, states have adopted regulations similar to existing PHMSA regulations for intrastate pipelines. For example, our intrastate pipelines in Louisiana are subject to pipeline safety regulations, including integrity management regulations administered by the Office of Conservation of the Louisiana Department of Natural Resources.
At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing. We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines. In addition, our actual implementation costs may be affected by industry-wide demand for the associated contractors and service providers. Additionally, should any of our assets fail to comply with PHMSA regulations, they could be subject to shut-down, pressure reductions, penalties and fines. Changes to pipeline safety laws and regulations that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators. For example, PHMSA has announced that it anticipates the issuance of the Pipeline Safety: Safety of Hazardous Liquids Pipelines final rule in 2019. The requirements for regulatory reduction put in place by the Trump administration delayed this rule from the anticipated 2018 release; with reauthorization in 2019 it is expected that PHMSA will work diligently toward issuance of the final rule. The final rule addressed topics such as: reporting requirements for gravity and gathering lines, inspections of pipelines following extreme weather events, periodic assessment of pipelines not currently subject to integrity management, repair criteria, expanded use of leak detection systems, increased use of in-line inspection tools and other clarifications. PHMSA has drafted similar regulations for refinery gas pipelines. As drafted those rules are expected to have minimal impact to the assets we operate.
In this climate of increasingly stringent regulation, pipeline failures or failures to comply with applicable regulations could result in shut-downs, capacity constraints or operational limitations to our pipelines. Should any of these risks materialize, it could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
Compliance with and changes in environmental laws and regulations, including proposed climate change laws and regulations, could adversely affect our performance. Our customers are also subject to environmental laws and regulations, and any changes in these laws and regulations, including laws and regulations related to hydraulic fracturing, could result in significant added costs to comply with such requirements and delays or curtailment in pursuing production activities, which could reduce demand for our services.
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 regulations, including those relating to the discharge and remediation of materials in the environment, GHG emissions, waste management, species and habitat
30
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, or could impose strict liability on us for the conduct of third parties or for actions that complied with applicable requirements when taken, regardless of negligence or fault. Our offshore operations are also subject to laws and regulations protecting the marine environment administered by the U.S. Coast Guard and BOEM. Failure to comply with these laws and regulations could lead to administrative, civil or criminal penalties or liability and 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 EPA has, in recent years, adopted final rules making more stringent the National Ambient Air Quality Standards for ozone, sulfur dioxide and nitrogen dioxide. Emerging rules implementing these revised air quality standards may require us to obtain more stringent air permits and install more stringent controls at our operations, which may result in increased capital expenditures.
Climate change legislation and regulations to address GHG emissions are in various phases of discussion or implementation in the United States. The outcome of federal, state and regional actions to address climate change could result in a variety of regulatory programs including potential new regulations to control or restrict emissions, taxes or other charges to deter emissions of GHGs, energy efficiency requirements or alternative energy requirements to reduce demand, or other regulatory actions. These actions could result in increased compliance and operating costs or could adversely affect demand for the crude oil and refined products that we transport. Additionally, adoption of federal, state or regional requirements mandating a reduction in GHG emissions could have far-reaching impacts on the energy industry and the U.S. economy. We cannot predict the potential impact of such laws or regulations on our future consolidated financial condition, results of operations or cash flows. Finally, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, it is uncertain if they would have an adverse effect on our financial condition and operations.
Our customers are also subject to environmental laws and regulations that affect their businesses, and changes in these laws or regulations could materially adversely affect their businesses or prospects. Our crude oil pipelines serve customers who depend on production techniques, such as hydraulic fracturing, that are currently being scrutinized by federal, state and local authorities and that could be subjected to increased regulatory costs, delays or liabilities. Any changes in laws or regulations that impose significant costs or liabilities on our customers, or that result in delays, curtailments or cancellations of their projects, could reduce their demand for our services and materially adversely affect our business, results of operations, financial position or cash flows, including our ability to make cash distributions to our unitholders.
Subsidence and coastal erosion could damage our pipelines along the Gulf Coast and offshore and the facilities of our customers, which could adversely affect our operations and financial condition.
Our pipeline operations along the Gulf Coast and offshore could be impacted by subsidence and coastal erosion. Such processes could cause serious damage to our pipelines, which could affect our ability to provide transportation services. Additionally, such processes could impact our customers who operate along the Gulf Coast, and they may be unable to utilize our services. Subsidence and coastal erosion could also expose our operations to increased risks associated with severe weather conditions, such as hurricanes, flooding and rising sea levels. As a result, we may incur significant costs to repair and preserve our pipeline infrastructure. Such costs could adversely affect our business, financial condition, results of operation or cash flows, including our ability to make cash distributions to our unitholders.
We may be unable to obtain or renew permits necessary for our operations or for growth and expansion projects, 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. In addition, we implement maintenance, growth and expansion projects as necessary to pursue business opportunities, and these projects often require similar permits, licenses and approvals. These permits, licenses, approval limits and standards require a significant amount of
31
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 adverse effect on our ability to continue operations and on our business, financial condition, results of operations and cash flows, including our ability to make cash distributions to our unitholders.
Our assets were constructed over many decades which may cause our inspection, maintenance or repair costs to 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 adverse effect on our business and results of operations.
Our pipelines and storage terminals were constructed over many decades. Pipelines and storage terminals are generally long-lived assets, and construction and coating techniques have varied over time. Depending on the era of construction, some assets will require more frequent inspections, which could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our business, results of operations, financial condition or cash flows, including our ability to make cash distributions to our unitholders.
The tariff rates and rules and regulations for service of our regulated assets, as well as our business practices for our regulated assets, are subject to review, audit and possible adjustment by federal and state regulators, which could adversely affect our revenue and our ability to make distributions to our unitholders.
We provide both interstate and intrastate transportation services for refined products and crude oil. Our interstate and intrastate pipelines are common carriers and are required to provide service to any shipper similarly situated to an existing shipper that requests transportation services on our pipelines.
Zydeco, Bengal, Colonial, Explorer and portions of Mars 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, rules and regulations 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. Shippers may also file complaints that existing rates are unjust and unreasonable. 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. On November 3, 2015, Colonial made a rules and regulations tariff filing with FERC in Docket No. 16-61-000 to change, among other things, its capacity allocation and minimum tender procedures. Colonial made the filing to address chronic allocation issues on its system. FERC rejected the package of proposals in Colonial’s filing and a revised proposal filed on March 23, 2016, but accepted, in an order issued on January 13, 2017, certain aspects of Colonial’s November 3, 2015 filing related to the minimum tender requirement for the Woodbury-Linden Main Line and the rounding increment used to allocate capacity on Main Lines 1 & 2.
The TCJA reduced the highest marginal U.S. federal corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. In the Revised Policy Statement on Treatment of Income Taxes issued in Docket No. PL17-1-000, FERC states that it would address the effect of the tax changes on industry-wide oil pipeline costs in the 2020 five-year review of the oil pipeline index level. FERC also could require oil pipelines to revise their rates in individual proceedings (including initial rate filing or complaint proceedings) or through other action. Certain of our current tariff rates on file with FERC may reflect the federal income tax rates that were in effect at the time those tariff rates were established. As with any regulatory requirements promulgated by FERC, if FERC requires us to establish new tariff rates that reflect the current federal corporate income tax rate, it is possible the rates would be reduced, which could adversely affect our financial position, results of operation and ability to make cash distributions to our unitholders.
We may at any time also be required to respond to governmental requests for information, including compliance audits and rate case reviews conducted by FERC, such as the audit of Explorer and rate complaints filed against Colonial. FERC’s Office of Enforcement concluded an audit of Explorer in Docket No. FA16-5-000 for the period January 1, 2013 to December 31, 2016, and issued a letter order on January 12, 2018 adopting the audit’s findings and recommendations. Explorer accepted the audit’s findings and recommendations, which did not have a financial impact to us. Several shippers on Colonial filed separate complaints with FERC on November 22, 2017, February 2, 2018, March 1, 2018, and April 20, 2018 challenging all of Colonial’s tariff rates, as well as its practices and charges related to transmix and product volume loss. The complaints were docketed as Docket Nos. OR18-7-000, OR18-12-000, OR18-17-000, and OR-21-000. On September 20, 2018, FERC issued an order consolidating the complaints into one proceeding and setting the complaints for hearing and settlement judge procedures. Settlement procedures are ongoing, and FERC has not taken any final action on the complaints as of this time.
32
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 can also regulate whether a service may be provided or cancelled. The FERC and most state agencies support light-handed regulation of common carrier pipelines and have generally not investigated the rates, terms and conditions of service of pipelines in the absence of shipper complaints, and generally resolve complaints informally. Louisiana’s Public Service Commission has a more stringent review of rate increases and may prohibit or limit future rate increases for intrastate movements regulated by Louisiana.
Under our agreements with certain of our customers, we and the customer have agreed to base tariff rates for some of our pipelines, and our customers have agreed not to challenge the base tariff rates or changes to those rates during the term of the agreements, subject to certain exceptions. Some of these agreements and the underlying rates have been approved by FERC under a declaratory order. 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 on rates or services not covered by these agreements. Following the reversal of Zydeco, in December 2013, SPLC filed three related tariffs with FERC to establish rates for uncommitted service on Zydeco. The filed rates became effective on December 12, 2013 and were jointly protested in a FERC filing by Anadarko Petroleum Corporation, ConocoPhillips Company, Marathon Oil Company and Pioneer Natural Resources USA, Inc. (collectively, the “Liquid Shipper Group”). Zydeco later adopted those tariffs as part of its acquisition of the Ho-Ho pipeline, and Zydeco’s rates for uncommitted service were also protested by the Liquid Shipper Group under Docket Nos. IS14-607-000, IS14-608-000, IS14-609-000, and IS14-610-000, filed on July 31, 2014. After adoption of the SPLC tariffs by Zydeco, the protest against SPLC was dismissed. On August 15, 2015, all parties reached a settlement agreement establishing maximum uncommitted rates for uncommitted shippers, providing rate refunds plus interest, and establishing a two year rate moratorium during which neither Zydeco or the Liquid Shipper Group may file to change or challenge the settlement rates, among other terms. FERC accepted the settlement by a letter order, and the approved settlement, including the revised rates, went into effect December 1, 2016.
Further, rate investigations by FERC or a state commission could result in an investigation of our costs, including the:
•overall cost of service, including operating costs and overhead;
•allocation of overhead and other administrative and general expenses to the regulated entity;
•appropriate capital structure to be utilized in calculating rates;
•appropriate rate of return on equity and interest rates on debt;
•rate base, including the proper starting rate base;
•throughput underlying the rate; and
•proper allowance for federal and state income taxes.
Shippers can always file a complaint with the FERC or a state agency challenging rates or conditions of services. If they were successful, the FERC or state agency could order reparations. A successful challenge of any of our rates, or any changes to FERC’s approved rate or index methodologies, could adversely affect our revenue 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 adversely affect our revenues, including our ability to make cash distributions to our unitholders.
If we lose any of our key personnel, our ability to manage our business and continue our growth could be negatively impacted.
We depend on our senior management team and key technical personnel. If their services are unavailable to us for any reason, we may be required to hire other personnel to manage and operate our company and to develop our products and technology. We cannot assure you 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 adverse effect on our business, financial condition or results of operations.
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. Due to increased technology advances, we have become more reliant on technology to increase efficiency in our business. Instability in the financial markets as a result of
33
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 adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make cash distributions to our unitholders.
We rely heavily on information technology systems for our operations.
The operation of many of our business processes depends on reliable IT systems. We use our Parent’s IT systems, which are increasingly dependent on key contractors supporting the delivery of IT services, and continue to expand in terms of number of systems. Shell continuously measures and, where required, further improves its cyber-security capabilities to reduce the likelihood of successful cyber-attacks. Shell’s cyber-security capabilities are embedded into its IT systems and its IT landscape is protected by various detective and protective technologies. The identification and assessment capabilities are built into Shell’s support processes and adhere to industry best practices. While cyber-security programs and protocols are in place, we cannot guarantee their effectiveness. Disruption of critical IT services, or breaches of information security, could harm our reputation and have a material adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make cash distributions to our unitholders.
Violations of data protection laws carry fines and expose us to criminal sanctions and civil suits.
Data protection laws apply to us and our Parent. For example, the EU GDPR, which came into force in May 2018, increased penalties up to a maximum of 4% of global annual turnover for breach of the regulation. The GDPR requires mandatory breach notification, the standard for which is also followed outside the EU (particularly in Asia). Non-compliance with data protection laws could expose us or our Parent to regulatory investigations, which could result in fines and penalties. In addition to imposing fines, regulators may also issue orders to stop processing personal data, which could disrupt operations. We or our Parent could also be subject to litigation from persons or corporations allegedly affected by data protection violations. Violation of data protection laws is a criminal offense in some countries, and individuals can be imprisoned or fined. Any violation of these laws or harm to our reputation could have a material adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make cash distributions to our unitholders.
Restrictions in our credit facilities could adversely affect our business, financial condition, results of operations, ability to make cash distributions to our unitholders and the value of our units.
We will be 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 cash distributions to our unitholders. We have entered into two revolving credit facilities and two fixed rate facilities, and Zydeco has entered into a senior unsecured revolving credit facility with an affiliate of Shell with a total capacity of $2,990.0 million, under which a total of $2,094.0 million was drawn as of December 31, 2018. Borrowings under our credit facilities were used to fund in part our acquisitions in 2018, 2017 and 2016. Restrictions in our credit facilities and any future financing agreements 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 cash distributions to our unitholders.
The restrictions in our credit facilities 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 credit facilities 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 instruments, 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. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity — Credit Facilities in this report for additional information about our credit facilities.
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 cash distributions at our intended levels.
Interest rates on current and future credit facilities and debt offerings could increase above current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by our level of cash 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, 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 cash distributions at our intended levels.
Our pipeline loss allowance exposes us to commodity risk.
34
Our long-term transportation agreements and tariffs for crude oil shipments include a pipeline loss allowance. We collect pipeline loss allowance to reduce our exposure to differences in crude oil measurement between origin and destination meters, which can fluctuate widely. This arrangement exposes us to risk of financial loss in some circumstances, including when the crude oil is received from a ship or connecting carrier using different measurement techniques, or resulting from solids and water produced from the crude oil. It is not always possible for us to completely mitigate the measurement differential. If the measurement differential exceeds the loss allowance, the pipeline must make the customer whole for the difference in measured crude oil. Additionally, we take title to any excess product that we transport when product losses are within the allowed levels, and we sell that product several times per year at prevailing market prices. This allowance oil revenue is subject to more volatility than transportation revenue, as it is directly dependent on our measurement capability and prevailing commodity prices.
The lack of diversification of our assets and geographic locations could adversely affect our ability to make cash distributions to our unitholders.
A significant amount of our revenue is generated from assets located in Texas and the Louisiana Gulf Coast and offshore Louisiana. Due to our lack of diversification in assets and geographic location, an adverse development in our businesses or areas of operations, including adverse developments due to catastrophic events, weather, regulatory action and decreases in demand for crude oil and refined products, could have a significantly greater impact on our results of operations and cash available for distribution to our common unitholders than if we maintained more diverse assets and locations.
If we are deemed an “investment company” under the Investment Company Act of 1940, it could have a material adverse effect on our business and the price of our common units.
In some cases, our assets include partial ownership interests in joint ventures. If a sufficient amount of our assets, or other assets acquired in the future, are deemed to be “investment securities” within the meaning of the Investment Company Act of 1940, we may have to register as an investment company under the Investment Company Act, claim an exemption, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage, and require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events would adversely affect the price of our common units and could have a material adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make cash distributions to our unitholders.
Risks Inherent in an Investment in Us
Our general partner and its affiliates, including Shell, 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 Shell, and it is under no obligation to adopt a business strategy that favors us.
As of December 31, 2018, SPLC owned a 43.8% limited partner interest in us and owned and controlled 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, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is not adverse to the best interests of its owner, SPLC. Conflicts of interest may arise between SPLC 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 SPLC, over the interests of our common unitholders. These conflicts include, among others, the following situations:
•neither our partnership agreement nor any other agreement requires SPLC to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by SPLC to undertake acquisition opportunities for itself;
•SPLC’s directors and officers have a fiduciary duty to make these decisions in the best interests of the owners of SPLC, 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 SPLC and will owe fiduciary duties to SPLC and its owners;
•SPLC 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;
35
•except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;
•disputes may arise under agreements pursuant to which SPLC and its affiliates are our customers;
•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 cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions;
•our partnership agreement permits us to classify up to $90.0 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 75.0% of the common units;
•our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including under the Omnibus Agreements and our other agreements with SPLC and its affiliates;
•our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and
•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 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. This election 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.
We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon our cash reserves and external financing sources, including borrowings under our credit facilities and the issuance of debt and equity securities to fund future acquisitions and other expansion capital expenditures. To the extent we are unable to finance growth with external sources of capital, the requirement in our partnership agreement to distribute all of our available cash and our current cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as businesses that reinvest all of their available cash to expand ongoing operations.
Our credit facilities restrict our ability to incur additional debt including the issuance of debt securities, except for incurring bank loans or loans from affiliates up to other certain levels. To the extent we issue additional units, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our cash distributions per unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking
36
senior to our common units, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional units. If we incur additional debt (under our revolving credit facilities or otherwise) to finance our growth strategy, we will have increased interest expense, which in turn will reduce the available cash that we have to distribute to our unitholders.
The fees and reimbursements due to our general partner and its affiliates, including SPLC, for services provided to us or on our behalf will reduce our cash available for distribution. In certain cases, the amount and timing of such reimbursements will be determined by our general partner and its affiliates, including SPLC.
Pursuant to our partnership agreement, we reimburse our general partner and its affiliates, including SPLC, for costs and expenses they incur and payments they make on our behalf. Pursuant to the Omnibus Agreement and our Zydeco operating and management agreement, we pay an annual fee, currently $8.5 million and $8.5 million, respectively, to SPLC for general and administrative services. Effective February 1, 2019, the annual fee increased to $10.5 million pursuant to the new Omnibus Agreement. In addition, pursuant to the Omnibus Agreement, we reimburse our general partner for payments to SPLC for other expenses incurred by SPLC on our behalf to the extent the fees relating to such services are not included in the general and administrative services fee. We also reimburse our general partner and SPLC, as applicable, for certain services provided under our operating agreements related to Pecten, Sand Dollar and Triton West. For the year ended December 31, 2018, we reimbursed our general partner and SPLC $6.1 million and $3.7 million, respectively, under these operating agreements. Each of these payments will be made prior to making any distributions on our common units. The reimbursement of expenses and payment of fees to our general partner and its affiliates will reduce our cash available for distribution. There is no limit on the fee and expense reimbursements that we may be required to pay to our general partner and its affiliates.
Our partnership agreement replaces fiduciary duties applicable to a corporation with contractual duties and 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 replace fiduciary duties applicable to a corporation with contractual duties and 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 will not have any liability 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 will not be liable for monetary damages to us or our limited partners 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 will not be 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 the outstanding common units, excluding any common units owned by our general partner and its affiliates;
•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
37
•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.
Units held by ineligible holders may be subject to redemption.
We have adopted certain requirements regarding those investors who may own our common units. Eligible taxable holders are limited partners whose, or whose owners’, federal income tax status does not have or is not reasonably likely to have a material adverse effect on the rates that can be charged by us on assets that are subject to regulation by FERC or a similar regulatory body, as determined by our general partner with the advice of counsel. Ineligible holders are limited partners (a) who are not an eligible taxable holder or (b) whose nationality, citizenship or other related status would create a substantial risk of cancellation or forfeiture of any property in which we have an interest, as determined by our general partner with the advice of counsel. In certain circumstances set forth in our partnership agreement, units held by an ineligible holder may be redeemed by us at the then-current market price, which is the average of the daily closing prices for the 20 consecutive trading days immediately prior to the redemption date. 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 20.0% 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 20.0% 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 holders of stock in a public corporation, unitholders will 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 member of our general partner, which is a wholly owned subsidiary of SPLC. 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.
Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.
Unitholders will be unable initially 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 66 2/3% of all outstanding common units is required to remove our general partner.
Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20.0% 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 vote on any matter.
Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
38
Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.
Our partnership agreement does not restrict the ability of SPLC to transfer all or a portion of its general partner interest or its ownership interest in our general partner to a third party. Our general partner, or 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 cash flows and increase distributions. A transfer of incentive distribution rights by our general partner could reduce the likelihood of Shell or SPLC 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;
•the relative voting strength of each previously outstanding unit may be diminished; and
•the market price of our common units may decline.
SPLC 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 December 31, 2018, SPLC held 99,979,548 common units and no subordinated units. On February 17, 2017, all of the subordinated units converted into common units following the payment of the cash distribution for the fourth quarter of 2016. Additionally, we have agreed to provide SPLC 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, the 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 cash we have available to distribute to unitholders.
Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 75.0% 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
39
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, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. As of December 31, 2018, our general partner and its affiliates owned approximately 44.7% of our common units.
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.
The holder or holders of a majority of the incentive distribution rights, which is initially our general partner, have the right, at any time when the holders have received incentive distributions at the highest level to which they are entitled (48% in addition to distributions paid on its 2% general partner interest) for each of the prior four consecutive fiscal quarters (and the aggregate amounts distributed in respect of such four-quarter period did not exceed adjusted operating surplus for such four-quarter period), 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. 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 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 which 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 cash 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 cash 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 cash 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:
40
•how to allocate corporate opportunities among us and its other affiliates;
•whether to exercise its limited call right;
•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.
If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.
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. An effective system of internal controls is necessary for us to provide reliable and timely financial reports, prevent fraud and to operate successfully as a publicly traded partnership. We prepare our consolidated financial statements in accordance with GAAP, but our internal accounting controls may not meet all standards applicable to companies with publicly traded securities. Our efforts to develop and maintain our system of internal controls may not be successful, and 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, to annually review and report on the effectiveness of our system of internal controls over financial reporting. Any failure to develop, implement or maintain our effective internal controls or the failure to improve our system of internal controls could harm our operating results or cause us to fail to meet our reporting obligations.
We may incur significant costs in our efforts to comply with Section 404. Any failure to implement and maintain an effective system of internal controls over financial reporting will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.
Unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. We are 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.
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 you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received 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 us that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from our partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.
41
Because we are a publicly traded partnership, the NYSE does not require us to have, and we do not 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 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. See Part III, Item 10. Directors, Executive Officers and Corporate Governance in this report.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service, or 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 cash available for distribution 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 21%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. In addition, several states are evaluating changes to current law which could subject us to additional entity-level taxation and further reduce the cash available for distribution to unitholders.
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 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 partnerships or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, such a proposal could eliminate the qualifying income exception to the treatment of all publicly-traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted or will materially change interpretations of the current law, but it is possible that a change in law could affect us and may, if enacted, be applied retroactively. Any such changes would have a material adverse effect on our financial condition, cash flows, ability to make cash distributions to our unitholders and the value of an investment in our common units.
Our unitholders are required to pay income 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 unitholders’ 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 distribution at all.
A unitholders’ 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
42
than the adjusted issue price of the debt. A unitholders’ ratio of its share of taxable income to the cash received by it may also be affected by changes in law. For instance, our net interest rate deductions under the TCJA are limited to 30% of our “adjusted taxable income,” which is generally taxable income with certain modifications. If the limit applies, a unitholders’ 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.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution.
Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which our common units trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the TCJA, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If our unitholders sell common units, the unitholders will recognize a 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.
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 (“UBTI”) and will be taxable to them. Under the TCJA, an exempt organization is required to independently compute its UBTI from each separate unrelated trade or business which may prevent an exempt organization from utilizing losses we allocate to the organization against the organization’s UBTI from other sources and vice versa. 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 applicable state tax returns and pay tax on their share of our taxable income.
Under the TCJA, if a unitholder sells or otherwise disposes of a common unit, the transferee is required to withhold 10.0% 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 U.S. Department of the Treasury and the IRS have determined that this withholding requirement should not apply to any disposition of a publicly traded interest in a publicly traded partnership (such as us) until regulations or other guidance have been issued clarifying the application of this withholding requirement to dispositions of interests in publicly traded partnerships. Accordingly, while this new withholding requirement does not currently apply to interests in us, there can be no assurance that such requirement will not apply in the future.
43
We will 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 your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.
We prorate our items of income, gain, loss and deduction 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 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 U.S. Department of the Treasury adopted final Treasury Regulations allowing a similar monthly simplifying convention for taxable years beginning on or after August 3, 2015. However, such final regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration 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.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it (and some states) may collect any resulting taxes (including any applicable penalties and interest) directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
Pursuant to the Bipartisan Budget Act of 2015, 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. 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, our cash available for distribution to our unitholders might be substantially reduced. Additionally, we may be required to allocate an adjustment disproportionately among our unitholders, causing the publicly traded units to have different capital accounts, unless the IRS issues further guidance.
In the event the IRS makes an audit adjustment to our income tax returns and we do not or cannot shift the liability to our unitholders in accordance with their interests in us during the year under audit, we will generally have the ability to request that the IRS reduce the determined underpayment by reducing the suspended passive loss carryovers of our unitholders (without any compensation from us to such unitholders), to the extent such underpayment is attributable to a net decrease in passive activity losses allocable to certain partners. Such reduction, if approved by the IRS, will be binding on any affected 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 cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income.
We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies, which could adversely affect the value of the common units.
In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely 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. 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.
44
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.
If our assets were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.
If our assets are subjected to a material amount of additional entity-level taxation by individual states, our cash available for a distribution would be reduced. States are continually evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. We currently own assets and conduct business in certain states which impose an entity-level tax on partnerships, including Illinois, Texas, and Washington. Imposition of an entity-level tax on us in other jurisdictions in which we do business, or to which we expand our operations, could substantially reduce our cash available for distribution. Our partnership agreement provides that, if a law is enacted or an existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
As a result of investing in our common units, unitholders will likely be 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. Unitholders may be subject to such taxes, even if they do not live in the jurisdiction imposing the tax. 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. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own property and conduct business in a number of states, most of which currently impose a personal income tax on individuals, and most of which also impose an income or similar tax on corporations and certain other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose an income tax or similar tax. In certain states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent tax years. Some states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholders’ income tax liability to the state, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. It is each unitholder’s responsibility to file all federal, state and local tax returns required by applicable law to be filed by such unitholder. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units. Prospective unitholders should consult their own tax advisors regarding such matters.
Entity level taxes on income from C corporation subsidiaries will reduce cash available for distribution, and an individual unitholder’s share of dividend and interest income from such subsidiaries would constitute portfolio income that could not be offset by the unitholder’s share of our other losses or deductions.
A portion of our taxable income is earned through LOCAP, Explorer and Colonial, which are all C corporations. Such C corporations are subject to federal income tax on their taxable income at the corporate tax rate, which is currently 21.0%, and will likely pay state (and possibly local) income tax at varying rates, on their taxable income. Any such entity level taxes will reduce the cash available for distribution to our unitholders. Distributions from any such C corporation will generally be taxed again to unitholders as dividend income to the extent of current and accumulated earnings and profits of such C corporation. As of December 31, 2018, the maximum federal income tax rate applicable to such qualified dividend income that is allocable to individuals was 20.0%. An individual unitholders’ share of dividend and interest income from LOCAP, Explorer, Colonial or other C corporation subsidiaries would constitute portfolio income that could not be offset by the unitholders’ share of our other losses or deductions.
Item 1B. UNRESOLVED STAFF COMMENTS
None.
Item 3. LEGAL PROCEEDINGS
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the ordinary course of business, we are not a party to any litigation or governmental or other proceeding that we believe will have a material adverse
45
impact on our financial position, results of operations, or cash flows. In addition, pursuant to the terms of the various agreements under which we acquired assets from Shell affiliates since the IPO, those affiliates, as applicable, will indemnify us for certain liabilities relating to litigation and environmental matters attributable to the ownership or operation of the acquired assets prior to our acquisition of those assets.
Effective July 31, 2014, a rate case was filed against Zydeco with FERC. The rate case was resolved by a settlement approved by FERC which established maximum rates for uncommitted (or non-contract) shippers effective December 1, 2015. The settlement also provided for rate refunds for shippers of the difference between the higher pre-settlement uncommitted (or non-contract) rates and the lower settlement rates for the period from July 31, 2014 to November 30, 2015 (plus interest). In 2015, we recognized $2.3 million of general and administrative expenses related to the settlement of this rate case, and the shippers’ settlements were paid in January 2016. We filed claims for reimbursement of $1.4 million in 2015 from SPLC, and we received reimbursement in 2016. On a prospective basis, a successful challenge of any of our rates, or any changes to FERC’s approved rate or index methodologies, could adversely affect our revenue and cash flows, including our ability to make distributions to our unitholders.
46
Item 4. MINE SAFETY DISCLOSURES
Not applicable.
47
PART II
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Quarterly Common Unit Prices and Cash Distributions Per Unit
Our common units trade on the NYSE under the symbol “SHLX.”
As of February 21, 2019, SPLC owned 99,979,548 common units, representing an aggregate 43.8% limited partner interest in us, all of the incentive distribution rights, and 4,567,588 general partner units, representing a 2% general partner interest in us. On February 15, 2017, all of the subordinated units converted into common units following the payment of the cash distribution for the fourth quarter of 2016. As of February 1, 2019, we had four holders of record of our common units. In determining the number of unitholders, we consider clearing agencies and security position listings as one unitholder for each agency or listing.
Distributions of Available Cash
General
Our partnership agreement requires us to distribute all of our available cash to unitholders of record on the applicable record date, within 60 days after the end of each quarter.
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 maintenance and expansion capital expenditures, future acquisitions and anticipated future debt service 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 distributions if the effect of the establishment of such reserves will prevent us from making the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);
•plus, all cash on hand on the date of determination resulting from dividends or distributions received after the end of the quarter from equity interests in any person other than a subsidiary in respect of operations conducted by such person during the quarter;
•plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination resulting from working capital borrowings after the end of the quarter.
The purpose and 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 twelve 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 of $0.1625 per unit, or $0.6500 per unit on an annualized basis, to the holders of our units 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 or any amount 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. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity — Credit
48
Facilities in this report, for a discussion of the restrictions included in our credit facilities that may restrict our ability to make distributions.
General Partner Interest and Incentive Distribution Rights
Our general partner is currently entitled to 2% of all quarterly distributions. This general partner interest is represented by 4,567,588 general partner units as of February 21, 2019. 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 upon the issuance of additional units. The general partner’s initial 2% 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% general partner interest.
Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 48.0%, of the cash we distribute from operating surplus (as defined in our partnership agreement) in excess of $0.186875 per unit per quarter. The maximum distribution of 48.0% does not include any distributions that our general partner or its affiliates may receive on common or general partner units that they own.
On December 21, 2018, we and our general partner executed Amendment No. 2 (the “Second Amendment”) to the Partnership’s First Amended and Restated Agreement of Limited Partnership dated November 3, 2014. Under the Second Amendment, our sponsor agreed to waive $50.0 million of distributions in 2019 by agreeing to reduce distributions to holders of the incentive distribution rights by: (1) $17.0 million for the quarter ending March 31, 2019, (2) $17.0 million for the quarter ending June 30, 2019 and (3) $16.0 million for the quarter ending September 30, 2019.
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 Target 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% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2% general partner interest, our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.
| Marginal Percentage Interest in Distributions | |||||||||||||||||||||||
| Target Quarterly Distribution per Unit Target Amount | LP Unitholders | General Partner | |||||||||||||||||||||
| Minimum Quarterly Distribution | $ 0.162500 | 98% | 2% | ||||||||||||||||||||
| First Target Distribution | above $ 0.162500 | up to $ 0.186875 | 98% | 2% | |||||||||||||||||||
| Second Target Distribution | above $ 0.186875 | up to $ 0.203125 | 85% | 15% | |||||||||||||||||||
| Third Target Distribution | above $ 0.203125 | up to $ 0.243750 | 75% | 25% | |||||||||||||||||||
| Thereafter | above $ 0.243750 | 50% | 50% | ||||||||||||||||||||
Expiration of Subordination Period
On February 15, 2017, all of the subordinated units converted into common units following the payment of the cash distribution for the fourth quarter of 2016. Each of our 67,475,068 outstanding subordinated units converted into one common unit. As of March 31, 2017, and for any distribution of available cash in subsequent periods, the converted units participate pro rata with the other common units in distributions of available cash. The conversion of the subordinated units does not impact the amount of cash distributions paid by us or the total number of outstanding units. The allocation of net income and cash distributions during the period were effected in accordance with terms of the partnership agreement.
Equity Compensation Plan
The information relating to our equity compensation plan required by Item 5 is incorporated by reference to such information as set forth in Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters of this report.
49
Item 6. SELECTED FINANCIAL DATA
Please read the selected financial data presented below in conjunction with Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and the consolidated financial statements and accompanying notes included in Part II, Item 8 of this report.
| (in millions of dollars, except per unit data) | 2018 | 2017 | 2016 | 2015 | 2014 | ||||||||||||||||||||||||
| Statements of Income | |||||||||||||||||||||||||||||
Total revenue (1) | $ | 524.7 | $ | 470.1 | $ | 452.9 | $ | 485.5 | $ | 379.4 | |||||||||||||||||||
Total costs and expenses (1) | 312.5 | 270.0 | 229.4 | 232.9 | 204.8 | ||||||||||||||||||||||||
| Operating income | 212.2 | 200.1 | 223.5 | 252.6 | 174.6 | ||||||||||||||||||||||||
| Investment, dividend and other income (loss) | 333.1 | 224.0 | 166.3 | 125.6 | 40.9 | ||||||||||||||||||||||||
| Net income | 482.4 | 391.8 | 377.5 | 374.0 | 215.0 | ||||||||||||||||||||||||
| Net income attributable to the Partnership | 464.1 | 295.3 | 244.9 | 167.1 | 13.4 | ||||||||||||||||||||||||
| Net income per Limited Partner Unit - Basic and Diluted: | |||||||||||||||||||||||||||||
| Common | $ | 1.50 | $ | 1.28 | $ | 1.32 | $ | 1.16 | $ | 0.10 | |||||||||||||||||||
| Subordinated | $ | — | $ | — | $ | 1.27 | $ | 1.14 | $ | 0.10 | |||||||||||||||||||
Cash distributions declared per limited partner unit (2) | $ | 1.4950 | $ | 1.2461 | $ | 1.0258 | $ | 0.7900 | $ | 0.1042 | |||||||||||||||||||
| Balance Sheets | |||||||||||||||||||||||||||||
| Property, plant and equipment, net | $ | 742.4 | $ | 736.5 | $ | 733.7 | $ | 731.3 | $ | 616.3 | |||||||||||||||||||
| Total assets | $ | 1,913.5 | $ | 1,366.5 | $ | 1,303.9 | $ | 1,164.7 | $ | 1,071.8 | |||||||||||||||||||
| Debt payable – related party | $ | 2,090.7 | $ | 1,844.0 | $ | 686.0 | $ | 457.6 | $ | — | |||||||||||||||||||
Lease liability (3) | $ | 25.1 | $ | 24.3 | $ | 24.9 | $ | 22.8 | $ | — | |||||||||||||||||||
| Total (deficit) equity | $ | (257.0) | $ | (565.9) | $ | 534.2 | $ | 632.8 | $ | 989.4 | |||||||||||||||||||
(1) As a result of the adoption of the new revenue standard, prior period amounts have not been adjusted under the modified retrospective method and continue to be reported in accordance with our historic accounting under previous GAAP.
(2) The 2014 distribution per limited partner unit represents the pro-rated minimum quarterly distribution for the 59-day period from November 3, 2014 to December 31, 2014 in accordance with the Partnership Agreement.
(3) As part of the Motiva JV separation effective May 2017, Motiva is no longer a related party. As of both December 31, 2018 and 2017, this is a third-party balance.
50
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 are the analysis of our financial performance, financial condition, and significant trends that may affect future performance. It should be read in conjunction with the consolidated financial statements and notes thereto included in Part II, Item 8 of this report. It should also be read together with “Risk factors” and “Cautionary Statement Regarding Forward-Looking Statements” in this report.
On January 1, 2018, we adopted Topic 606, Revenue from Contracts with Customers, and all related ASU’s to this Topic (collectively, “the new revenue standard”) by applying the modified retrospective method to all contracts that were not completed on January 1, 2018. Results for reporting periods beginning after January 1, 2018 are presented in accordance with the new revenue standard, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting under previous GAAP. See Note 3 – Revenue Recognition in the Notes to Consolidated Financial Statements included in Part II, Item 8.
Partnership Overview
We are a growth-oriented master limited partnership that owns, operates, develops and acquires pipelines and other midstream assets. As of December 31, 2018, our assets include interests in entities that own crude oil and refined products pipelines and terminals that serve as key infrastructure to (i) transport onshore and offshore crude oil production to Gulf Coast and Midwest refining markets and (ii) deliver refined products from those markets to major demand centers. Our assets also include interests in entities that own natural gas and refinery gas pipelines which transport offshore natural gas to market hubs and deliver refinery gas from refineries and plants to chemical sites along the Gulf Coast.
For a description of our assets, please see Part I, Item 1 - Business and Properties of this report.
2018 developments include:
•IDR Waiver. On December 21, 2018, we and our general partner executed Amendment No. 2 (the “Second Amendment”) to our Partnership Agreement. Under the Second Amendment, our sponsor agreed to waive $50.0 million of distributions in 2019 by agreeing to reduce distributions to holders of the incentive distribution rights by: (1) $17.0 million for the quarter ending March 31, 2019, (2) $17.0 million for the quarter ending June 30, 2019 and (3) $16.0 million for the quarter ending September 30, 2019. We intend to use these funds for future investment.
•Borrowings. On July 31, 2018, we entered into a seven-year fixed rate credit facility with Shell Treasury Center (West) Inc. (“STCW”) with a borrowing capacity of $600.0 million (the “Seven Year Fixed Facility”). Additionally, on August 1, 2018, we amended and restated the Five Year Revolving Credit Facility due October 2019 such that the facility will now mature on July 31, 2023 (the “Five Year Credit Facility due July 2023”).
•May 2018 Acquisition. In May 2018, we entered into a purchase and sale agreement (the “Purchase Agreement”) with SPLC to acquire SPLC’s ownership interests in Amberjack Pipeline Company LLC, a Delaware limited liability company (“Amberjack”), which is comprised of 75% of the issued and outstanding Series A membership interests of Amberjack and 50% of the issued and outstanding Series B membership interests of Amberjack for $1,220.0 million (the “May 2018 Acquisition”). Amberjack is a joint venture with Chevron Pipe Line Company and owns an approximately 360-mile pipeline system in the Gulf of Mexico. We completed the May 2018 Acquisition in the second quarter of 2018 pursuant to the terms of the Purchase Agreement in exchange for payment to SPLC of $1,220.0 million in cash, which we funded with borrowings under existing credit facilities.
•Equity Offerings. In February 2018, we completed the sale of 25,000,000 common units in a registered public offering for $673.3 million net proceeds, and the sale of 11,029,412 common units in a private placement with Shell Midstream LP Holdings LLC, an indirect subsidiary of Shell, for an aggregate purchase price of $300.0 million.
•Debt Repayments. In February 2018, we used net proceeds from sales of common units and from our general partner’s proportionate capital contribution to repay $246.9 million of borrowings outstanding under the Five Year Revolver due July 2023 and $726.0 million of borrowings outstanding under the Five Year Revolver due December 2022. Refer to Note 9 – Related Party Debt in the Notes to Consolidated Financial Statements included in Part II, Item 8 for definitions.
We generate revenue from the transportation, terminaling and storage of crude oil and refined products through our pipelines and storage tanks, and we generate income from our equity and other investments. Our revenue is generated from customers in the same industry, our Parent’s affiliates, integrated oil companies, marketers, and independent exploration, production and
51
refining companies primarily within the Gulf Coast region of the U.S. We generally do not own any of the crude oil, refinery gas or refined petroleum products we handle, nor do we engage in the trading of these commodities. We therefore have limited direct exposure to risks associated with fluctuating commodity prices, although these risks indirectly influence our activities and results of operations over the long-term.
As a result of outages and repairs in 2017 related to Hurricane Harvey across several of our assets, as well as the declaration of a force majeure event for Zydeco, we incurred an impact of approximately $10.5 million in 2017 and $0.5 million in the first quarter of 2018 to net income and cash available for distribution. Because we declared a force majeure event for Zydeco, the expiration of unused credits on our committed transportation agreements for months prior to September 2017 has been extended one month. Refer to “Critical Accounting Policies and Estimates - Revenue Recognition” for additional information on these agreements.
As a result of Hurricane Michael in October 2018, we incurred an impact of approximately $2.5 million to net income and cash available for distribution in the fourth quarter of 2018. Although SPLC operated assets did not shut down, most platforms connected to assets in the eastern corridor of the Gulf of Mexico elected to shut in and evacuate as a safety precaution. There was no impact to people, assets or the environment in the corridor.
Executive Overview
Net income was $482.4 million and net income attributable to the Partnership was $464.1 million in 2018. We generated cash from operations of $508.4 million, raised $973.3 million in net proceeds from the sales of common units and increased our borrowing capacity by $600.0 million. Cash generated was primarily used to pay down debt with STCW. In addition, we completed the May 2018 Acquisition for $1,220.0 million. As of December 31, 2018, we had cash and cash equivalents of $208.0 million, total debt of $2,090.7 million, and unused capacity under our revolving credit facilities of $896.0 million.
Our 2018 operations and strategic initiatives demonstrated our continuing focus on our business strategies:
•Maintain operational excellence through prioritization of safety, reliability and efficiency;
•Growth through strategic acquisitions in key geographies to achieve integrated value;
•Focus on advantageous commercial agreements with creditworthy counterparties to enhance financial results and deliver reliable distribution growth over the long-term; and
•Optimize existing assets and pursue organic growth opportunities.
How We Evaluate Our Operations
Our management uses a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include: (i) revenue (including pipeline loss allowance (“PLA”) from contracted capacity and throughput; (ii) operations and maintenance expenses (including capital expenses); (iii) Adjusted EBITDA (defined below); and (iv) Cash Available for Distribution.
Contracted Capacity and Throughput
The amount of revenue our assets generate primarily depends on our transportation and storage services agreements with shippers and the volumes of crude oil, refinery gas and refined products that we handle through our pipelines, terminals and storage tanks.
The commitments under our transportation, terminaling and storage services agreements with shippers and the volumes which we handle in our pipelines and storage tanks are primarily affected by the supply of, and demand for, crude oil, refinery gas, natural gas and refined products in the markets served directly or indirectly by our assets. This supply and demand is impacted by the market prices for these products in the markets we serve. We utilize the commercial arrangements we believe are the most prudent under the market conditions to deliver on our business strategy. The results of our operations will be impacted by our ability to:
•maintain utilization of and rates charged for our pipelines and storage facilities;
•utilize the remaining uncommitted capacity on, or add additional capacity to, our pipeline systems;
52
•increase throughput volumes on our pipeline systems by making connections to existing or new third party pipelines or other facilities, primarily driven by the anticipated supply of, and demand for, crude oil and refined products; and
•identify and execute organic expansion projects.
Operations and Maintenance Expenses
Our management seeks to maximize our profitability by effectively managing operations and maintenance expenses. These expenses are comprised primarily of labor expenses (including contractor services), insurance costs (including coverage for our consolidated assets and operated joint ventures), utility costs (including electricity and fuel) and repairs and maintenance expenses. Utility costs fluctuate based on throughput volumes and the grades of crude oil and types of refined products we handle. Management performed a strategic evaluation of its insurance coverage and since renewal of the contracts at the end of 2017, all of our property and business interruption coverage is provided by a wholly owned subsidiary of Shell. This resulted in both overall cost savings and improved coverage. Our other operations and maintenance expenses generally remain stable across broad ranges of throughput and storage volumes, but can fluctuate from period to period depending on the mix of activities, particularly maintenance activities, performed during a period. At times, the fluctuation in operations and maintenance expenses may materially increase due to the performance of planned maintenance, such as turnaround work and asset integrity work, and unplanned maintenance, such as repair of damage caused by a natural disaster.
Adjusted EBITDA and Cash Available for Distribution
Adjusted EBITDA and cash available for distribution have important limitations as analytical tools because they exclude some, but not all, items that affect net income and net cash provided by operating activities. You should not consider Adjusted EBITDA or cash available for distribution in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because Adjusted EBITDA and cash available for distribution may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and cash available for distribution may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
The GAAP measures most directly comparable to Adjusted EBITDA and cash available for distribution are net income and net cash provided by operating activities. Adjusted EBITDA and cash available for distribution should not be considered as an alternative to GAAP net income or net cash provided by operating activities. Please refer to “Results of Operations - Reconciliation of Non-GAAP Measures” for the reconciliation of GAAP measures net income and cash provided by operating activities to non-GAAP measures Adjusted EBITDA and cash available for distribution.
We define Adjusted EBITDA as net income before income taxes, net interest expense, gain or loss from dispositions of fixed assets, allowance oil reduction to net realizable value, and depreciation, amortization and accretion, plus cash distributed to us from equity investments for the applicable period, less income from equity investments. We define Adjusted EBITDA attributable to the Partnership as Adjusted EBITDA less Adjusted EBITDA attributable to noncontrolling interests and Adjusted EBITDA attributable to Parent.
We define cash available for distribution as Adjusted EBITDA attributable to the Partnership less maintenance capital expenditures attributable to the Partnership, net interest paid, cash reserves and income taxes paid, plus net adjustments from volume deficiency payments attributable to the Partnership and certain one-time payments received. Cash available for distribution will not reflect changes in working capital balances.
We believe that the presentation of these non-GAAP supplemental financial measures provides useful information to management and investors in assessing our financial condition and results of operations. We present these financial measures because we believe replacing our proportionate share of our equity investments’ net income with the cash received from such equity investments more accurately reflects the cash flow from our business, which is meaningful to our investors.
Adjusted EBITDA and cash available for distribution are non-GAAP supplemental financial measures that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:
•our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis or, in the case of Adjusted EBITDA, financing methods;
•the ability of our business to generate sufficient cash to support our decision to make distributions to our unitholders;
•our ability to incur and service debt and fund capital expenditures; and
53
•the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.
Factors Affecting Our Business and Outlook
We believe key factors that impact our business are the supply of, and demand for, crude oil, natural gas, refinery gas and refined products in the markets in which our business operates. We also believe that our customers’ requirements, competition and government regulation of crude oil, refined products, natural gas and refinery gas play an important role in how we manage our operations and implement our long-term strategies. In addition, acquisition opportunities, whether from Shell or third parties, and financing options, will also impact our business. These factors are discussed in more detail below.
Changes in Crude Oil Sourcing and Refined Product Demand Dynamics
To effectively manage our business, we monitor our market areas for both short-term and long-term shifts in crude oil and refined products supply and demand. Changes in crude oil supply such as new discoveries of reserves, declining production in older fields, operational impacts at producer fields and the introduction of new sources of crude oil supply, affect the demand for our services from both producers and consumers. One of the strategic advantages of our crude oil pipeline systems is their ability to transport attractively priced crude oil from multiple supply markets to key refining centers along the Gulf Coast. Our crude oil shippers periodically change the relative mix of crude oil grades delivered to the refineries and markets served by our pipelines. They also occasionally choose to store crude longer term when the forward price is higher than the current price (a “contango market”). While these changes in the sourcing patterns of crude oil transported or stored are reflected in changes in the relative volumes of crude oil by type handled by our pipelines, our total crude oil transportation revenue is primarily affected by changes in overall crude oil supply and demand dynamics and U.S. exports.
Similarly, our refined products pipelines have the ability to serve multiple major demand centers. Our refined products shippers periodically change the relative mix of refined products shipped on our refined products pipelines, as well as the destination points, based on changes in pricing and demand dynamics. While these changes in shipping patterns are reflected in relative types of refined products handled by our various pipelines, our total product transportation revenue is primarily affected by changes in overall refined products supply and demand dynamics. Demand can also be greatly affected by refinery performance in the end market, as refined products pipeline demand will increase to fill the supply gap created by refinery issues.
We can also be constrained by asset integrity considerations in the volumes we ship. We may elect to reduce cycling on our systems to reduce asset integrity risk, which in turn would likely result in lower revenues.
As these supply and demand dynamics shift, we anticipate that we will continue to actively pursue projects that link new sources of supply to producers and consumers. Similarly, as demand dynamics change, we anticipate that we will create new services or capacity arrangements that meet customer requirements. We expect to continue extending our corridor pipelines to provide developing growth regions in the Gulf of Mexico with access via our existing corridors to onshore refining centers and market hubs. For example, Stampede achieved first oil in January 2018, and Big Foot and Claiborne came online at the end of 2018. We believe this strategy will allow our offshore business to grow profitably throughout demand cycles.
Changes in Customer Contracting
We generate a portion of our revenue under long-term transportation service agreements with shippers, including ship-or-pay agreements and life-of-lease transportation agreements, some of which provide a guaranteed return, and storage service agreements with marketers, pipelines and refiners. Historically, the commercial terms of these long-term transportation and storage service agreements have substantially mitigated volatility in our financial results by limiting our direct exposure to reductions in volumes due to supply or demand variability. Our business could be negatively affected if we are unable to renew or replace our contract portfolio on comparable terms, by sustained downturns or sluggishness in commodity prices or the economy in general, and is impacted by shifts in supply and demand dynamics, the mix of services requested by the customers of our pipelines, competition and changes in regulatory requirements affecting our operations. Our business can also be impacted by asset integrity or customer interruptions and natural disasters.
Two of our long-term transportation services agreements on the Zydeco system expired at the end of 2018, and another will expire in the second quarter of 2019. These contracts represented approximately 30% of our revenues for both the years ended December 31, 2018 and 2017. If we are not able to re-contract these volumes, or if the rates are substantially lower than those previously contracted, net income and cash available for distribution will be negatively impacted. Prolonged lower rates and the length of time without contracts could have a material impact on our financial results.
54
The market environment will dictate the rates, terms and lengths of any new agreements. Increases or decreases in available crude supply in the Houston market could affect demand for transportation to other markets, especially the Louisiana refining market. A number of factors could impact this, including increased production in fields with Houston connectivity and increased export capabilities at Texas Gulf Coast ports. Further, shippers may choose alternate routes on which to ship. Alternatively, Louisiana refineries’ availability and crude slates, as well as potential crude options at Louisiana Gulf Coast ports, could impact Louisiana demand for crude types available in the Houston market. Additionally, crude prices and basis differentials will directly impact the price our customers are willing to pay to transport.
As we continue discussions with new and existing shippers and monitor the market factors above, we will run the system with spot shipments at the posted tariff rates for our non-contracted capacity. Based on recent demand levels on the system, we believe that Zydeco continues to serve an important market and although the current market supports the use of spot shipments, we continue to strive for long-term agreements which provide more ratable financial results.
Additionally, revenue we generate from spot shipments will typically have a corresponding positive impact on cash available for distribution. However, in the first half of 2019, previously committed shippers will have the ability to ship on credits earned related to under-shipments prior to the expiration of their contracts. As such, we will recognize revenue for the usage of those credits, but we will not receive cash. We expect that the majority of these credits will be utilized in the first quarter.
The cumulative effect of the foregoing circumstances and challenges would have a material impact on our financial results. We expect the impact on our net income and cash available for distribution in the first quarter of 2019 to each be in the range of $15.0 million to $25.0 million. However, the aforementioned factors are constantly evolving and as such may not be a reliable predictor of actual financial results.
Changes in Commodity Prices and Customers’ Volumes
Crude oil prices have fluctuated significantly over the past few years, often with drastic moves in relatively short periods of time. During 2018, prices slowly increased from 2017 levels until the middle of the fourth quarter, at which point there was a steep decline. The current global geopolitical and economic uncertainty continues to contribute to volatility in financial and commodity markets. Our direct exposure to commodity price fluctuations is limited to the PLA provisions in our tariffs. We have indirect exposure to commodity price fluctuations to the extent such fluctuations affect the shipping patterns of our customers. Our assets benefit from long-term fee-based arrangements, and are strategically positioned to connect crude oil volumes originating from key onshore and offshore production basins to the Texas and Louisiana refining markets, where demand for throughput has remained strong. Historically, we have not experienced a material decline in throughput volumes on our crude oil pipeline systems as a result of lower crude oil prices. However, if crude oil prices remain at lower levels for a sustained period, we could see a reduction in our transportation volumes if production coming into our systems is deferred and our associated allowance oil sales decrease. Our customers may also experience liquidity and credit problems, which could cause them to defer development or repair projects, avoid our contracts in bankruptcy, or renegotiate our contracts on terms that are less attractive to us or impair their ability to perform under our contracts.
Our throughput volumes on our refined products pipeline systems depend primarily on the volume of refined products produced at connected refineries and the desirability of our end markets. These factors in turn are driven by refining margins, maintenance schedules and market differentials. Refining margins depend on the cost of crude oil or other feedstocks and the price of refined products. These margins are affected by numerous factors beyond our control, including the domestic and global supply of and demand for crude oil and refined products. We are currently experiencing relatively high demand for our pipeline systems that service refineries.
Other Changes in Customers’ Volumes
Total Zydeco volumes were lower in 2018 versus 2017 primarily due to a Force Majeure declared due to the hydro-test of the Zydeco pipeline from Houston, Texas to Houma, Louisiana resulting in 49 days of downtime in 2018. Additionally, there was a sale of an interplant line delivering to a connecting refinery during 2017, which resulted in lower volume in 2018. These decreases were partially offset by an increase in barrels originating from Houston and Nederland, as well as higher deliveries from Poseidon in 2018.
Transportation volumes on Auger were lower in 2018 versus 2017 primarily due to the shut-in of production throughout the first half of 2018 at certain connected producer facilities caused by the fire at the Enchilada platform in the fourth quarter of 2017.
55
Transportation volumes on Na Kika were slightly higher in 2018 versus 2017 driven by the new Coulomb redevelopment wells which achieved first oil in March 2018. Odyssey volumes were relatively flat in 2018 versus 2017. Despite higher volumes from select platforms in 2018 due to tie-backs, the new fields did not offset the impact of multiple legacy fields being shut-in for unplanned maintenance during the first half of 2018. These legacy fields returned to service early in the third quarter of 2018. Delta experienced increased transportation volumes in 2018 versus 2017 due to higher receipts from Na Kika, as well as higher volumes from a third party connecting carrier due to new tie-backs connected to such system which came online throughout 2018. We expect two additional tie-backs coming online in the first quarter of 2019 to provide incremental volume through the Odyssey and Delta systems.
Transportation volumes on Amberjack were higher in 2018 versus 2017 driven by increased production from two large fields in the central Gulf of Mexico.
Transportation volumes on Mars were higher in 2018 versus 2017 driven by increased production from three large fields in the central Gulf of Mexico, as well as from an increase in receipt volume from a connecting pipeline system. The increase in transportation volumes was partially offset by lower storage volumes in 2018 versus 2017. Additionally, there was a planned producer turnaround that impacted the second quarter of 2018.
Major Maintenance Projects
On the Zydeco pipeline system, we are in the execution stage of a directional drill project to address soil erosion over a two-mile section of our 22-inch diameter pipeline under the Atchafalaya River and Bayou Shaffer in Louisiana (the “directional drill project”). The project commenced in the latter half of 2017. Due to a change in service provider, as well as allowing for performance of the work during optimal weather and water conditions, construction timing has been delayed and we now expect the project to be completed in the first half of 2019. Zydeco expects to incur approximately $43.0 million in maintenance capital expenditures for the total project. Since inception, Zydeco has incurred $31.2 million, of which $12.2 million was in 2018. In connection with the acquisitions of additional interests in Zydeco, SPLC agreed to reimburse us against our proportionate share of certain costs and expenses with respect to this project. During 2018, we filed claims for reimbursement from SPLC of $11.4 million which were treated as capital contributions from our Parent.
In June 2017, a small release of approximately 23 gallons of crude oil occurred on the Zydeco pipeline near Erath, Louisiana. The portion of the pipeline impacted was repaired and returned to service. We ran an in-line inspection tool, hydro-tested the system and invested in additional equipment to mitigate the effects of pressure cycling in the future. The hydro-test resulted in the Zydeco pipeline from Houston, Texas to Houma, Louisiana being out of service for 49 days in the first quarter of 2018. Offshore volumes flowing into destination markets were not impacted. The impact to net income and cash available for distribution was approximately $60.0 million in the first quarter of 2018. Final remediation activities were completed in the second quarter of 2018 with no material impact.
In November 2017, the Enchilada platform in Garden Banks Block 128 experienced a fire that resulted in the shut-in of all production flowing through Auger. The platforms contributing a majority of Auger’s daily throughput returned to service in the first quarter of 2018, and the remaining impacted platforms resumed production in the third quarter of 2018. As such, the impact to net income and cash available for distribution was approximately $11.0 million in 2018. We filed a claim under our business continuity insurance and expect to partially recover losses occurring 60 days or more after the incident. Under this claim we received $6.5 million in 2018 and recorded it in Other income in our consolidated statements of income, and expect to receive approximately $3.0 million in the first half of 2019.
In the beginning of the fourth quarter of 2017, fields connecting to Odyssey went offline due to operational issues and came back online early in the third quarter of 2018. The impact to net income and cash available for distribution for Odyssey and Delta was approximately $9.0 million in the first half of 2018.
In the second quarter of 2018, Mars experienced lower volumes due to a planned producer turnaround. The impact to net income and cash available for distribution was approximately $7.0 million. Volumes returned to anticipated levels in the third quarter of 2018.
On the Refinery Gas Pipeline system, a project to convert a section of pipe from the Convent refinery to Sorrento from refinery gas service to butane service was put on hold due to the refinery’s decision to continue the operation of its catalytic converter. In connection with the acquisition of the Refinery Gas Pipeline asset, Shell Chemical agreed to reimburse us for our share of certain costs and expenses with respect to the conversion project. During 2017, we incurred costs and expenses related to the project, and filed claims for reimbursement from Shell Chemical, of $1.7 million, which were treated as capital contributions
56
from our Parent. With the project suspended, we incurred immaterial maintenance capital expenditures to close out this project in 2018.
Certain connected producers have turnarounds planned for 2019. The expected impact to net income and cash available for distribution is approximately $10.0 million in each of the second and third quarters of 2019.
For expected capital expenditures in 2019, refer to Capital Resources and Liquidity - Capital Expenditures.
Major Expansion Projects
In June 2017, Zydeco began construction on a tank expansion project in Houma to address future capacity shortfalls during tank maintenance which will allow us to service additional capacity, as well as allow for existing tanks to come out of service for regularly scheduled inspection and maintenance. We are building two 250,000 barrel working tanks at the existing Houma facility for a total of $44.1 million in growth capital expenditures. Since inception, Zydeco has incurred $39.7 million, of which $22.4 million was incurred in 2018. Beginning in January 2019, one of the tanks is in service, and the second tank is expected to be in service later in the first quarter of 2019. The project is expected to be completed during the first quarter of 2019. The scope includes interconnecting piping, dike expansion and associated facility work.
On Amberjack, we expect an increase in volume going forward due to multiple production expansion projects. We anticipate this will result in an increase in equity investment income and distributions received from Amberjack. See “Factors Affecting Our Business and Outlook” for additional information.
Customers
We transport and store crude oil, refined products, natural gas, and refinery gas for a broad mix of customers, including producers, refiners, marketers and traders, and are connected to other crude oil and refined products pipelines. In addition to serving directly-connected U.S. Gulf Coast markets, our crude oil and refined products pipelines have access to customers in various regions of the United States through interconnections with other major pipelines. Our customers use our transportation and storage services for a variety of reasons. Refiners typically require a secure and reliable supply of crude oil over a prolonged period of time to meet the needs of their specified refining diet and frequently enter into long-term firm transportation agreements to ensure a ready supply of crude oil, rate surety and sometimes sufficient transportation capacity over the life of the contract. Similarly, chemical sites require a secure and reliable supply of refinery gas to crackers and enter into long-term firm transportation agreements to ensure steady supply. Producers of crude oil and natural gas require the ability to deliver their product to market and frequently enter into firm transportation contracts to ensure that they will have sufficient capacity available to deliver their product to delivery points with greater market liquidity. Marketers and traders generate income from buying and selling crude oil and refined products to capitalize on price differentials over time or between markets. Our customer mix can vary over time and largely depends on the crude oil and refined products supply and demand dynamics in our markets. Refer to Note 13 - Transactions with Major Customers and Concentration of Credit Risk in the Notes to the Consolidated Financial Statements included in Part II, Item 8 for additional information.
Competition
Our pipeline systems compete primarily with other interstate and intrastate pipelines and with marine and rail transportation. Some of our competitors may expand or construct transportation systems that would create additional competition for the services we provide to our customers. For example, newly constructed transportation systems in the onshore Gulf of Mexico region may increase competition in the markets where our pipelines operate. In addition, future pipeline transportation capacity could be constructed in excess of actual demand, which could reduce the demand for our services, in the market areas we serve, and could lead to the reduction of the rates that we receive for our services. While we do see some variation from quarter-to-quarter resulting from changes in our customers’ demand for transportation, this risk has historically been mitigated by the long-term, fixed rate basis upon which we have contracted a substantial portion of our capacity. However, contracts that represented approximately 30% of our revenues for both the years ended December 31, 2018 and 2017 expired in December 2018 or will expire in 2019. Our business may be negatively affected if we are unable to renew or replace our contract portfolio on comparable terms. See “Changes in Customer Contracting” for additional information.
Our storage terminal competes with surrounding providers of storage tank services. Some of our competitors have expanded terminals and built new pipeline connections, and third parties may construct pipelines that bypass our location. These, or similar events, could have a material adverse impact on our operations.
Our refined products terminals generally compete with other terminals that serve the same markets. These terminals may be owned by major integrated oil and gas companies or by independent terminaling companies. While fees for terminal storage and
57
throughput services are not regulated, they are subject to competition from other terminals serving the same markets. However, our contracts provide for stable, long-term revenue, which is not impacted by market competitive forces.
Regulation
Our assets are subject to regulation by various federal, state and local agencies.
In May 2018, Zydeco, Mars, LOCAP and Colonial filed with FERC to increase rates subject to FERC’s indexing adjustment methodology by approximately 4.4% starting on July 1, 2018.
In March 15, 2018, FERC issued its Revised Policy Statement on Treatment of Income Taxes in Docket No. PL17-1-000 and on July 18, 2018, FERC issued Order No. 849, which adopts procedures to address the impact of the TCJA for natural gas pipelines. In the Revised Policy Statement on Treatment of Income Taxes, FERC eliminated the recovery of an income tax allowance by an MLP oil and gas pipelines in cost-of-service-based rates. In Order No. 849, however, FERC has clarified its general disallowance of MLP income tax allowance recovery by providing that an MLP will not be precluded in a future proceeding from making a claim that it is entitled to an income tax allowance. FERC will permit an MLP to demonstrate that its recovery of an income tax allowance does not result in a “double-recovery of investors’ income tax costs.” FERC originally issued the March 2018 Revised Policy Statement following remand of a proceeding from the United States Court of Appeals for the D.C. Circuit. In United Airlines, Inc. v. FERC, the D.C. Circuit vacated a pair of FERC orders to the extent they permitted an interstate refined petroleum products pipeline owned by an MLP to include an income tax allowance in its cost-of-service rates. The D.C. Circuit held that FERC had failed to demonstrate that the inclusion of an income tax allowance in the pipeline’s rates would not lead to a double recovery of income tax costs attributable to regulated service and instructed FERC on remand to fashion a remedy to ensure that the pipeline’s rates do not allow it to over-recover its costs.
At this time, FERC has not taken any industry-wide action regarding review of rates for crude oil and liquids pipelines. However, under the Revised Policy Statement on Treatment of Income Taxes, MLP owned crude oil and liquids pipelines are now required to report Page 700 information in their FERC Form 6 annual reports for the year ending December 31, 2017 that reflects elimination of the income tax allowance for both 2016 and 2017 reporting years. FERC also states in the policy statement that it will address the impact of the elimination of the income tax allowance as part of its five-year review of the oil pipeline rate index level in 2020. FERC can also implement the elimination of the income tax allowance in proceedings involving review of initial cost-of-service rates, rate changes, and rate complaints. For crude oil and liquids pipelines owned by non-MLP partnerships and other pass-through businesses, FERC will address such issues as they arise in subsequent proceedings.
We believe that FERC’s decisions on income tax allowances in 2018 will not have a material impact on our operations and financial performance. Since FERC only maintains jurisdiction over interstate crude oil and liquids pipelines, the recent decisions are not expected to have an impact on rates charged through our offshore operations. FERC also does not maintain jurisdiction over certain of the onshore assets in which we have interests. Rates related to these assets should not be impacted by the FERC decision. For our FERC-regulated rates charged through our interstate crude oil and liquids pipelines, the rates are based on either a negotiated or market-based rate, which are below the cost-of-service rates established by FERC. As such, neither our negotiated nor market-based rate revenue for our FERC-regulated assets would be subject to the income tax recovery disallowance. Additionally, we have evaluated the impact of FERC’s recent policy changes on our non-operated joint ventures. Due to the nature of their assets, operations and/or their entity form, we do not believe there will be any material impact to their operations and earnings.
On October 20, 2016, the Federal Energy Regulatory Commission issued an Advance Notice of Proposed Rulemaking in Docket No. RM17-1-000 regarding changes to the oil pipeline rate index methodology and data reporting on the Page 700 of the FERC Form No. 6. In an effort to improve the Commission’s ability to ensure that oil pipeline rates are just and reasonable under the ICA, the Commission is considering making the following changes to their current indexing methodologies for oil pipelines:
1) Deny index increases for any pipeline whose Form No. 6, Page 700 revenues exceed costs by 15% for both of the prior two years;
2) Deny index increases that exceed by 5% the cost changes reported on Page 700; and
3) Apply the new criteria to costs more closely associated with the pipeline’s proposed rates than with total company-wide costs and revenues now reported on Page 700.
Initial comments were filed on January 19, 2017, and reply comments were filed on March 17, 2017. We will continue to monitor developments in this area.
58
Acquisition Opportunities
We plan to continue to pursue acquisitions of complementary assets from SPLC and other subsidiaries of Shell, as well as from third parties. Since our initial public offering, we have acquired approximately $4,900.0 million of assets from Shell and its affiliates. We also may pursue acquisitions jointly with SPLC. Given the size and scope of SPLC’s footprint and its significant ownership interest in us, we expect acquisitions from SPLC will be an important growth mechanism for the foreseeable future. Neither SPLC nor any of its affiliates is under any obligation, however, to sell or offer to sell us additional assets or to pursue acquisitions jointly with us, and we are under no obligation to buy any additional assets from them or to pursue any joint acquisitions with them. We will continue to focus our acquisition strategy on transportation and midstream assets. We believe that we will be well positioned to acquire midstream assets from SPLC, other subsidiaries of Shell, and third parties should such opportunities arise. Identifying and executing acquisitions is a key part of our strategy. However, if we do not make acquisitions on economically acceptable terms or if we incur a substantial amount of debt in connection with the acquisitions, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our available cash. Our ability to obtain financing or access capital markets may also directly impact our ability to continue to pursue strategic acquisitions. Current market demand for equity issued by MLP’s may make it more challenging for us to fund our acquisitions with the issuance of equity in capital markets. As such, we maintain a conservative balance sheet, providing us other financing options such as hybrid securities, sponsor take-backs and debt.
Results of Operations
| 2018 | 2017 | 2016 | |||||||||||||||
Revenue (1) | $ | 524.7 | $ | 470.1 | $ | 452.9 | |||||||||||
| Costs and expenses | |||||||||||||||||
Operations and maintenance (1) | 161.9 | 149.7 | 116.9 | ||||||||||||||
Cost of product sold (1) | 32.7 | — | — | ||||||||||||||
| (Gain) loss from revision of ARO and disposition of fixed assets | (3.4) | 0.1 | 0.2 | ||||||||||||||
| General and administrative | 59.5 | 57.8 | 53.4 | ||||||||||||||
| Depreciation, amortization and accretion | 45.9 | 45.0 | 43.1 | ||||||||||||||
| Property and other taxes | 15.9 | 17.4 | 15.8 | ||||||||||||||
Total costs and expenses (1) | 312.5 | 270.0 | 229.4 | ||||||||||||||
| Operating income | 212.2 | 200.1 | 223.5 | ||||||||||||||
| Income from equity method investments | 234.9 | 186.6 | 138.1 | ||||||||||||||
| Dividend income from other investments | 66.8 | 37.4 | 28.3 | ||||||||||||||
| Other income (loss) | 31.4 | — | (0.1) | ||||||||||||||
| Investment, dividend and other income (loss) | 333.1 | 224.0 | 166.3 | ||||||||||||||
| Interest expense, net | 62.5 | 32.2 | 12.3 | ||||||||||||||
| Income before income taxes | 482.8 | 391.9 | 377.5 | ||||||||||||||
| Income tax expense | 0.4 | 0.1 | — | ||||||||||||||
| Net income | 482.4 | 391.8 | 377.5 | ||||||||||||||
| Less: Net income attributable to the Parent | — | 77.3 | 102.3 | ||||||||||||||
| Less: Net income attributable to noncontrolling interests | 18.3 | 19.2 | 30.3 | ||||||||||||||
| Net income attributable to the Partnership | $ | 464.1 | $ | 295.3 | $ | 244.9 | |||||||||||
| General partner’s interest in net income attributable to the Partnership | $ | 134.4 | $ | 64.6 | $ | 25.0 | |||||||||||
| Limited Partners’ interest in net income attributable to the Partnership | $ | 329.7 | $ | 230.7 | $ | 219.9 | |||||||||||
Adjusted EBITDA attributable to the Partnership (2) | $ | 616.7 | $ | 380.1 | $ | 294.9 | |||||||||||
Cash available for distribution attributable to the Partnership (2) | $ | 536.3 | $ | 360.0 | $ | 273.2 | |||||||||||
(1) As a result of the adoption of the new revenue standard, prior period amounts have not been adjusted under the modified retrospective method and continue to be reported in accordance with our historic accounting under previous GAAP.
(2) For a reconciliation of Adjusted EBITDA and Cash available for distribution attributable to the Partnership to their most comparable GAAP measures, please read “—Reconciliation of Non-GAAP Measures.”
59
Pipeline throughput (thousands of barrels per day) (1) | 2018 | 2017 | 2016 | ||||||||||||||
| Zydeco - Mainlines | 623 | 611 | 568 | ||||||||||||||
| Zydeco - Other segments | 249 | 359 | 478 | ||||||||||||||
| Zydeco total system | 872 | 970 | 1,046 | ||||||||||||||
| Amberjack total system | 324 | 256 | 196 | ||||||||||||||
| Mars total system | 516 | 469 | 388 | ||||||||||||||
| Bengal total system | 539 | 581 | 547 | ||||||||||||||
| Poseidon total system | 235 | 254 | 265 | ||||||||||||||
| Auger total system | 58 | 60 | 114 | ||||||||||||||
| Delta total system | 228 | 219 | 253 | ||||||||||||||
| Na Kika total system | 42 | 39 | 46 | ||||||||||||||
| Odyssey total system | 115 | 116 | 107 | ||||||||||||||
| LOCAP total system | 1,228 | 1,228 | 1,100 | ||||||||||||||
| Other systems | 344 | 322 | 257 | ||||||||||||||
Terminals (2) (3) | |||||||||||||||||
| Lockport terminaling throughput and storage volumes | 226 | 181 | 188 | ||||||||||||||
| Revenue per barrel ($ per barrel) | |||||||||||||||||
Zydeco total system (4) | $ | 0.74 | $ | 0.66 | $ | 0.57 | |||||||||||
Amberjack total system (4) | 2.50 | 2.43 | 2.21 | ||||||||||||||
Mars total system (4) | 1.19 | 1.41 | 1.41 | ||||||||||||||
Bengal total system (4) | 0.34 | 0.34 | 0.34 | ||||||||||||||
Auger total system (4) | 1.34 | 1.12 | 1.13 | ||||||||||||||
Delta total system (4) | 0.57 | 0.54 | 0.52 | ||||||||||||||
Na Kika total system (4) | 0.79 | 0.72 | 0.71 | ||||||||||||||
Odyssey total system (4) | 0.88 | 0.90 | 0.95 | ||||||||||||||
Lockport total system (5) | 0.21 | 0.25 | 0.27 | ||||||||||||||
(1) Pipeline throughput is defined as the volume of delivered barrels. For additional information regarding our pipeline and terminal systems, refer to Part I, Item I - Business and Properties - Our Assets and Operations.
(2) Terminaling throughput is defined as the volume of delivered barrels and storage is defined as the volume of stored barrels.
(3) Refinery Gas Pipeline and our refined products terminals are not included above as they generate revenue under transportation and terminaling service agreements, respectively, that provide for guaranteed minimum throughput.
(4) Based on reported revenues from transportation and allowance oil divided by delivered barrels over the same time period. Actual tariffs charged are based on shipping points along the pipeline system, volume and length of contract.
(5) Based on reported revenues from transportation and storage divided by delivered and stored barrels over the same time period. Actual rates are based on contract volume and length.
60
Reconciliation of Non-GAAP Measures
The following tables present a reconciliation of Adjusted EBITDA and cash available for distribution to net income and net cash provided by operating activities, the most directly comparable GAAP financial measures, for each of the periods indicated.
Please read “—Adjusted EBITDA and Cash Available for Distribution” for more information.
| 2018 | 2017 | 2016 | |||||||||||||||
| Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income | |||||||||||||||||
| Net income | $ | 482.4 | $ | 391.8 | $ | 377.5 | |||||||||||
| Add: | |||||||||||||||||
| (Gain) loss from revision of ARO and disposition of fixed assets | (3.4) | 0.1 | 0.2 | ||||||||||||||
| Allowance oil reduction to net realizable value | 5.5 | 0.3 | — | ||||||||||||||
| Depreciation, amortization and accretion | 45.9 | 45.0 | 43.1 | ||||||||||||||
| Interest expense, net | 62.5 | 32.2 | 12.3 | ||||||||||||||
| Income tax expense | 0.4 | 0.1 | — | ||||||||||||||
| Cash distribution received from equity method investments | 301.7 | 198.3 | 158.0 | ||||||||||||||
| Less: | |||||||||||||||||
| Equity method distributions included in other income | 24.4 | — | — | ||||||||||||||
| Income from equity method investments | 234.9 | 186.6 | 138.1 | ||||||||||||||
| Adjusted EBITDA | 635.7 | 481.2 | 453.0 | ||||||||||||||
| Less: | |||||||||||||||||
| Adjusted EBITDA attributable to Parent | — | 80.3 | 124.9 | ||||||||||||||
| Adjusted EBITDA attributable to noncontrolling interests | 19.0 | 20.8 | 33.2 | ||||||||||||||
| Adjusted EBITDA attributable to the Partnership | 616.7 | 380.1 | 294.9 | ||||||||||||||
| Less: | |||||||||||||||||
Net interest paid attributable to the Partnership (1) | 62.3 | 32.2 | 9.4 | ||||||||||||||
| Income taxes paid attributable to the Partnership | 0.3 | 0.1 | — | ||||||||||||||
Maintenance capex attributable to the Partnership (2) | 25.3 | 28.3 | 22.6 | ||||||||||||||
| Add: | |||||||||||||||||
| Net adjustments from volume deficiency payments attributable to the Partnership | (3.9) | 5.0 | 7.5 | ||||||||||||||
| Reimbursements from Parent included in partners’ capital | 11.4 | 16.1 | 2.8 | ||||||||||||||
| April 2017 divestiture attributable to the Partnership | — | 19.4 | — | ||||||||||||||
| Cash available for distribution attributable to the Partnership | $ | 536.3 | $ | 360.0 | $ | 273.2 | |||||||||||
(1) Amount represents both paid and accrued interest attributable to the period.
(2) Effective April 1, 2017, the amount is inclusive of cash paid during the period, as well as accruals incurred for work performed during the period. Prior period amounts have not been changed and represent cash paid during the period.
61
| 2018 | 2017 | 2016 | |||||||||||||||
| Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Cash Provided by Operating Activities | |||||||||||||||||
| Net cash provided by operating activities | $ | 508.4 | $ | 432.4 | $ | 429.2 | |||||||||||
| Add: | |||||||||||||||||
| Interest expense, net | 62.5 | 32.2 | 12.3 | ||||||||||||||
| Income tax expense | 0.4 | 0.1 | — | ||||||||||||||
| Return of investment | 48.2 | 18.2 | 15.8 | ||||||||||||||
| Less: | |||||||||||||||||
| Change in deferred revenue and other unearned income | (4.3) | 6.0 | 7.9 | ||||||||||||||
| Non-cash interest expense | 0.9 | 0.4 | 2.7 | ||||||||||||||
| Allowance oil reduction to net realizable value | 5.5 | 0.3 | — | ||||||||||||||
| Change in other assets and liabilities | (18.3) | (5.0) | (6.3) | ||||||||||||||
| Adjusted EBITDA | 635.7 | 481.2 | 453.0 | ||||||||||||||
| Less: | |||||||||||||||||
| Adjusted EBITDA attributable to Parent | — | 80.3 | 124.9 | ||||||||||||||
| Adjusted EBITDA attributable to noncontrolling interests | 19.0 | 20.8 | 33.2 | ||||||||||||||
| Adjusted EBITDA attributable to the Partnership | 616.7 | 380.1 | 294.9 | ||||||||||||||
| Less: | |||||||||||||||||
Net interest paid attributable to the Partnership (1) | 62.3 | 32.2 | 9.4 | ||||||||||||||
| Income taxes paid attributable to the Partnership | 0.3 | 0.1 | — | ||||||||||||||
Maintenance capex attributable to the Partnership (2) | 25.3 | 28.3 | 22.6 | ||||||||||||||
| Add: | |||||||||||||||||
| Net adjustments from volume deficiency payments attributable to the Partnership | (3.9) | 5.0 | 7.5 | ||||||||||||||
| Reimbursements from Parent included in partners’ capital | 11.4 | 16.1 | 2.8 | ||||||||||||||
| April 2017 divestiture attributable to the Partnership | — | 19.4 | — | ||||||||||||||
| Cash available for distribution attributable to the Partnership | $ | 536.3 | $ | 360.0 | $ | 273.2 | |||||||||||
(1) Amount represents both paid and accrued interest attributable to the period.
(2) Effective April 1, 2017, the amount is inclusive of cash paid during the period, as well as accruals incurred for work performed during the period. Prior period amounts have not been changed and represent cash paid during the period.
62
2018 compared to 2017
Revenues
Total revenue increased by $54.6 million in 2018 as compared to 2017, comprised of an increase of $30.7 million attributable to product revenue, $23.6 million attributable to transportation and terminaling services revenue and $0.4 million attributable to storage revenue, partially offset by a $0.1 million decrease attributable to lease revenue.
Product revenue increased by $30.7 million due to the impact of the new revenue standard in 2018. Product revenue results from allowance oil sales for Zydeco and Pecten. In 2017, product revenue was recorded net of cost of product sold in operations and maintenance expenses.
Transportation services revenue increased $2.3 million for Zydeco primarily due to a shift in the composition of volumes and associated tariffs between mainline and non-mainline, as well as an increase in expiring credits on our committed transportation agreements and the impact of Hurricane Harvey in 2017. This increase was partially offset by being out of service for 49 days as a result of the hydro-test in early 2018 and a decrease in non-mainline shipments due to the sale of an interplant line in April 2017. Transportation services revenue increased by $9.2 million for Pecten primarily due to new wells coming online in 2018 and higher volumes from a connecting carrier due to new tie-backs that also came online in 2018. This increase was partially offset by the downtime of the Auger and Enchilada platforms in 2018 following the fire in November 2017, coupled with declining production volumes from certain wells and lower receipt volumes on Delta from certain connecting carriers. Additionally, Sand Dollar had an increase of $4.7 million due to the impact of the new revenue standard, partially offset by a $1.1 million decrease on Odyssey primarily due to connecting fields being shut-in for unplanned maintenance.
Terminaling services revenue increased by $8.5 million for Triton due to the impact of the new revenue standard related to the non-lease service component of the terminaling services agreements. This increase was partially offset by the termination of the terminaling services revenue upon commencement of the terminaling services agreements in December 2017, which are treated as operating leases and impact lease revenue.
Lease revenue increased by $10.6 million for Sand Dollar and decreased $10.7 million for Triton. The increase for Sand Dollar resulted from transportation services agreements entered into in May 2017 that are considered operating leases. For Triton, 2018 lease revenue resulted from terminaling services agreements entered into in December 2017 that are considered operating leases, whereas lease revenue in 2017 resulted from a Colex operating lease that existed in 2017 and terminated upon entering into the terminaling services agreements. The decrease for Triton is due to the non-lease service component of the terminaling services agreements being included in transportation and terminaling services revenue under the new revenue standard.
Storage revenue increased $0.4 million primarily related to higher storage volume for Lockport, partially offset by a reduction in storage volume for Zydeco.
Costs and Expenses
Total costs and expenses increased $42.5 million in 2018 due to $32.7 million higher cost of product sold, $12.2 million in higher operations and maintenance expenses, $1.7 million higher general and administrative expenses and $0.9 million in higher depreciation expense, partially offset by a $3.5 million gain on revision of ARO and disposition of fixed assets and $1.5 million of lower property taxes due to changes in property tax appraisal estimates.
Cost of product sold in 2018 represents the cost of sales of allowance oil and is a result of the adoption of the new revenue standard, as well a net realizable value adjustment of allowance oil due to declining crude oil prices in the latter part of 2018. In 2017, cost of product sold was recorded net with product revenue in operations and maintenance expenses.
Operations and maintenance expenses increased primarily due to costs associated with the hydro-test of Zydeco in 2018 and higher insurance costs. These increases were partially offset by lower project development and utility costs on Zydeco resulting from lower volumes due to being out of service for 49 days in the first quarter of 2018, as well as lower usage fees for Triton due to the commencement of the terminaling services agreements entered into in December 2017. Additionally, there was a gain on pipeline operations in 2018 as compared to a loss in 2017, partially offset by a gain on sale of allowance oil in 2017 as a result of the accounting prior to the adoption of the new revenue standard on January 1, 2018.
General and administrative expense increased primarily due to higher allocations of salaries in 2018 under our operating agreements, as well as the allocation of severance expense. This increase was partially offset by an overall reduction in professional service fees.
63
Investment, Dividend and Other Income (Loss)
Investment, dividend and other income (loss) increased $109.1 million in 2018 as compared to 2017. Income from equity method investments increased by $48.3 million. The increase was primarily a result of equity earnings associated with the May 2018 Acquisition, income from Permian Basin which was acquired in October 2017 and an increase in LOCAP net income primarily due to a lower tax provision in 2018. These increases were partially offset by lower storage revenue on Mars, the impact of suspending equity method accounting for Poseidon and lower revenue on Bengal. Other income increased by $31.4 million primarily related to distributions from Poseidon and business continuity insurance proceeds received in connection with the fire at the Enchilada platform impacting Auger. Additionally, dividend income from other investments increased by $29.4 million in 2018 primarily related to increased distributions from Explorer and Colonial, including a one-time dividend due to a remeasurement of Colonial’s deferred tax liability as a result of tax reform rate change.
Interest Expense
Interest expense increased by $30.3 million due to additional borrowings outstanding under our credit facilities during 2018 as compared to 2017.
2017 compared to 2016
Revenues
Total revenue increased by $17.2 million in 2017 as compared to 2016, comprised of $43.2 million attributable to lease revenue, partially offset by decreases of $23.5 million in transportation and terminaling services revenue and $2.5 million in storage revenue.
Lease revenue increased by $31.0 million and $12.2 million for Sand Dollar and Triton, respectively. These increases primarily resulted from certain transportation and terminaling services agreements entered into in May 2017 and December 2017, respectively, that are considered operating leases. Additionally, on Triton there was a Colex operating lease that commenced in June 2016 and terminated upon entering into the terminaling services agreements.
Transportation services revenue decreased by $28.9 million for Pecten primarily driven by the expiration of the surcharge on Auger rates related to the recovery of earlier improvements on the line, Auger extended planned maintenance activities and emergency shut-down situations at connected producer facilities and declining production volumes from certain wells, as well as shipper response to local market pricing changes on Auger, Delta and Na Kika. Additionally, terminaling services revenue decreased by $14.2 million for Triton primarily due to the commencement of the terminaling services agreements in December 2017 which have taken the place of the transportation services revenue, as well as the Colex operating lease which existed for the majority of 2017 but only commenced in June 2016. These agreements are treated as operating leases and impact lease revenue.
These decreases were partially offset by an increase of $18.5 million for Zydeco primarily attributable to an increase in delivered volumes on the mainline, despite the impact of Hurricane Harvey. The increase in volumes was attributable to a new joint tariff agreement entered into in September 2016 with a connecting carrier and changes in certain customers’ sourcing strategies, as well as a net increase, excluding the sale of the interplant line discussed below, in shipments on non-mainlines in 2017 due to a variety of maintenance events at refineries in our destination markets in 2016. These increases on Zydeco were partially offset by a decrease in non-mainline shipments due to the sale of an interplant line in the April 2017 Divestiture. Additionally, there was an increase of $1.1 million for Odyssey.
Storage revenue decreased $2.5 million primarily related to a reduction in storage volume for Lockport.
Costs and Expenses
Total costs and expenses increased $40.6 million in 2017 due to $32.8 million in higher operations and maintenance expense, $4.4 million higher general and administrative expenses and $1.9 million of additional depreciation expense due to the completion of certain projects in 2017, and $1.6 million in property taxes due to changes in property tax appraisal estimates, partially offset by $0.1 million loss from disposition of fixed assets.
Operations and maintenance expenses increased due to higher project development and maintenance costs, as well as increased insurance costs for both consolidated and investment interests acquired in the fourth quarter of 2016, as well as in connection with the May 2017 Acquisition and the December 2017 Acquisition. Additionally, there is a larger net gain on pipeline operations related to allowance oil in 2016 than in 2017.
64
General and administrative expense increased primarily due to higher allocations of salaries in the 2017, partially offset by decreased professional fees in 2017 and costs associated with equity issuances in 2016.
Investment, Dividend and Other Income (Loss)
Investment, dividend and other income (loss) is primarily comprised of earnings from our equity investments and the dividend income from our cost investments. The earnings from our equity investments increased by $48.5 million in 2017 primarily related to Mars. Mars had higher net income in 2017, coupled with the impact of retrospectively adjusting for the incremental ownership acquired. The incremental adjustment on Mars results in a higher overall ownership interest for 2017 as compared to 2016 due to the timing of the October 2016 Acquisition which was treated prospectively. Additionally, we have income in 2017 from Proteus and Endymion which were acquired in the fourth quarter 2016, and Permian Basin which was acquired in the fourth quarter 2017.
The increase of $9.1 million in dividend income is due to higher overall distributions from Colonial in 2017, partially due to the acquisition of an additional interest in the second quarter of 2016. Additionally, the impact of retrospectively adjusting for the incremental ownership acquired in Explorer resulted in a higher overall ownership interest for 2017 as compared to 2016 due to the timing of the August 2016 Acquisition which was treated prospectively.
Interest Expense
Interest expense increased by $19.9 million due to additional borrowings outstanding under our credit facilities during 2017 versus 2016.
Capital Resources and Liquidity
We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under our credit facilities and our ability to access the capital markets. We believe this access to credit along with cash generated from operations will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions. Our liquidity as of December 31, 2018 was $1,104.0 million consisting of $208.0 million cash on hand and $896.0 million available capacity under our revolving credit facilities.
On December 21, 2018, we and our general partner executed Amendment No. 2 (the “Second Amendment”) to the Partnership’s First Amended and Restated Agreement of Limited Partnership dated November 3, 2014. Under the Second Amendment, our sponsor agreed to waive $50.0 million of distributions in 2019 by agreeing to reduce distributions to holders of the incentive distribution rights by: (1) $17.0 million for the quarter ending March 31, 2019, (2) $17.0 million for the quarter ending June 30, 2019 and (3) $16.0 million for the quarter ending September 30, 2019.
During 2018, we negotiated with STCW to increase our borrowing capacity by $600.0 million through the addition of the Seven Year Fixed Facility effective July 31, 2018. The Seven Year Fixed Facility was fully drawn on August 1, 2018 and the borrowings were used to partially repay borrowings under the Five Year Revolver due December 2022.
Additionally, on August 1, 2018, we amended and restated the Five Year Revolver due October 2019 such that the facility will now mature on July 31, 2023 and is now referred to as the Five Year Revolver due July 2023.
65
Credit Facilities
As of December 31, 2018, we have entered into the following credit facilities:
| Total Capacity | Maturity Date | |||||||||||||
| Seven Year Fixed Facility | $ | 600.0 | July 31, 2025 | |||||||||||
Five Year Revolver due July 2023 (1) | 760.0 | July 31, 2023 | ||||||||||||
| Five Year Revolver due December 2022 | 1,000.0 | December 1, 2022 | ||||||||||||
| Five Year Fixed Facility | 600.0 | March 1, 2022 | ||||||||||||
| Zydeco Revolver | 30.0 | August 6, 2019 | ||||||||||||
(1) On August 1, 2018, the Partnership extended the maturity date. This was previously referred to as the Five Year Revolver due October 2019.
Borrowings under the Five Year Revolver due July 2023, the Five Year Revolver due December 2022 and the Zydeco Revolver bear interest at the three-month LIBOR rate plus a margin. Our weighted average interest rate for 2018 and 2017 was 3.5% and 2.7%, respectively. The weighted average interest rate includes drawn and undrawn interest fees, but does not consider the amortization of debt issuance costs or capitalized interest. A 1/8 percentage point (12.5 basis points) increase in the interest rate on the total variable rate debt of $894.0 million as of December 31, 2018 would increase our consolidated annual interest expense by approximately $1.1 million. Our current interest rates for outstanding borrowings are 3.5% under our Five Year Revolver due July 2023, 3.5% under our Five Year Revolver due December 2022 and 3.9% under the Zydeco Revolver. Borrowings under the Seven Year Fixed Facility and the Five Year Fixed Facility bear interest at 4.06% and 3.23% per annum, respectively.
We will need to rely on the willingness and ability of our related party lender to secure additional debt, our ability to use cash from operations and/or obtain new debt from other sources to repay/refinance such loans when they come due and/or to secure additional debt as needed.
The 364-Day Revolver matured on March 1, 2017. There was no balance outstanding during the period.
As of December 31, 2018, we were in compliance with the covenants contained in our credit facilities, and Zydeco was in compliance with the covenants contained in the Zydeco Revolver.
For definitions and additional information on our credit facilities, refer to Note 9 - Related Party Debt in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report.
Equity Issuances
On February 6, 2018, we completed the sale of 25,000,000 common units in a registered public offering for approximately $673.3 million net proceeds. Additionally, we completed the sale of 11,029,412 common units in a private placement with Shell Midstream LP Holdings LLC, an indirect subsidiary of Shell, for an aggregate purchase price of $300.0 million. See Note 11 — (Deficit) Equity in the Notes to Consolidated Financial Statements included in Part II, Item 8 for additional information.
Cash Flows from Our Operations
Operating Activities. We generated $508.4 million in cash flows from operating activities in 2018 compared to $432.4 million in 2017. The $76.0 million increase in cash flows was primarily driven by an increase in operating income, equity investment income, dividends from other investments, and other income related to the suspension of equity accounting on Poseidon and business continuity insurance proceeds. These increases were partially offset by the timing of receipt of receivables and payment of accruals in 2018.
We generated $432.4 million in cash flows from operating activities in 2017 compared to $429.2 million in 2016. The $3.2 million increase in cash flows was primarily driven by an increase in equity method investment distributions and other investment dividends, partially offset by a decrease in operating income, an increase in interest paid and a decrease in working capital.
Investing Activities. Our cash flows used in investing activities was $510.3 million in 2018 compared to $509.1 million in 2017. The increase in cash flow used in investing activities was primarily due to higher net acquisitions from Parent and contributions to Permian Basin in 2018. These increases in cash flow used in investing activities were partially offset by acquisitions from
66
third parties in 2017, an increase in the return of investment of equity investees and lower capital expenditures. See Note 4 – Acquisitions and Divestiture in the Notes to Consolidated Financial Statements included in Part II, Item 8 for additional information.
Our cash flows used in investing activities was $509.1 million in 2017 compared to $244.8 million in 2016. The increase in cash flow used in investing activities was primarily due to our acquisitions in 2017 and an increase in expansion capital expenditures on Zydeco. See Note 4 – Acquisitions and Divestiture in the Notes to Consolidated Financial Statements included in Part II, Item 8 for additional information.
Financing Activities. Our cash flows provided by financing activities was $72.2 million in 2018 compared to $92.3 million in 2017. The decrease in cash flow provided by financing activities was primarily due to higher repayments of debt, increased distributions paid to unitholders and our general partner in 2018, lower proceeds from divestitures and lower contributions from our Parent. These decreases were partially offset by higher borrowings under our credit facilities, higher net proceeds from equity offerings, a net distribution to Parent in 2017, higher contribution from our general partner, lower credit facility issuance costs and lower distributions to Parent and noncontrolling interests in 2018.
Our cash flows provided by financing activities was $92.3 million in 2017 compared to $156.1 million used in financing activities in 2016. The increase in cash flow provided by financing activities was primarily due to an increase in borrowings under our credit facilities, partially offset by a decrease in net proceeds from equity issuances, an increase in the repayments of borrowings under our revolving credit facilities, an increase in capital distributions to the general partner and an increase in distributions paid to the unitholders and the general partner.
Capital Expenditures
Our operations can be capital intensive, requiring investments to maintain, 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. 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, expansion capital expenditures are those made to acquire additional assets to grow our business, to expand and upgrade our systems and facilities and to construct or acquire new systems or facilities. We regularly explore opportunities to improve service to our customers and maintain or increase our assets’ capacity and revenue. We may incur substantial amounts of capital expenditures in certain periods in connection with large maintenance projects that are intended to only maintain our assets’ capacity or revenue.
We incurred capital expenditures of $51.6 million, $57.9 million and $44.7 million for 2018, 2017 and 2016, respectively. The decrease in capital expenditures from 2017 to 2018 is primarily due to lower spend on the direction drill project for Zydeco, partially offset by increased spend on the Houma tank expansion project. The increase in capital expenditures from 2016 to 2017 is primarily due to the Houma tank expansion project and directional drill project for Zydeco.
A summary of our capital expenditures is shown in the table below:
| 2018 | 2017 | 2016 | |||||||||||||||
| Expansion capital expenditures | $ | 24.7 | $ | 18.0 | $ | 9.4 | |||||||||||
| Maintenance capital expenditures | 24.5 | 40.0 | 36.4 | ||||||||||||||
| Total capital expenditures paid | 49.2 | 58.0 | 45.8 | ||||||||||||||
| Increase (decrease) in accrued capital expenditures | 2.4 | (0.1) | (1.1) | ||||||||||||||
| Total capital expenditures incurred | $ | 51.6 | $ | 57.9 | $ | 44.7 | |||||||||||
We expect total capital expenditures to be approximately $45.0 million for 2019, a summary of which is shown in table below:
67
| Actual Capital Expenditures | Expected Capital Expenditures | ||||||||||
| 2018 | 2019 | ||||||||||
| (in millions of dollars) | |||||||||||
| Expansion capital expenditures | |||||||||||
| Zydeco | $ | 24.3 | $ | 7.0 | |||||||
| Triton | 0.5 | — | |||||||||
| Total expansion capital expenditures | 24.8 | 7.0 | |||||||||
| Maintenance capital expenditures | |||||||||||
| Zydeco | 19.3 | 27.0 | |||||||||
| Pecten | 1.4 | 4.5 | |||||||||
| Triton | 6.1 | 6.5 | |||||||||
| Total maintenance capital expenditures | 26.8 | 38.0 | |||||||||
| Total capital expenditures | $ | 51.6 | $ | 45.0 | |||||||
Total expansion capital expenditures in both 2018 and as expected for 2019 are primarily related to the Houma tank expansion project on Zydeco.
Zydeco’s maintenance capital expenditures for 2018 were $19.3 million, primarily related to $12.2 million for the directional drill project, as well as improvements at Houma, Port Neches and Calliou Island. In connection with the acquisition of additional interests in Zydeco, SPLC agreed to reimburse us for our proportionate share of certain costs and expenses incurred by Zydeco with respect to the directional drill project. During 2018, we filed claims for reimbursement from SPLC of $11.4 million. We expect Zydeco’s maintenance capital expenditures to be approximately $27.0 million for 2019, of which approximately $12.0 million is for the directional drill project and $6.0 million is related to a pipeline exposure requiring replacement. The majority of the remaining spend is related an upgrade of the motor control center at Houma, pressure cycling mitigation and other routine maintenance.
Pecten’s maintenance capital expenditures for 2018 were $1.4 million, primarily related to electrical improvements and tank maintenance for Lockport. We expect Pecten’s maintenance capital expenditures to be approximately $4.5 million in 2019 for electrical improvements at Lockport, and various improvements on Delta.
Triton’s maintenance capital expenditures for 2018 were $6.1 million. This includes vapor recovery assessment, tank work at Colex and Des Plaines and occupied building blast assessment. We expect Triton’s maintenance capital expenditures to be approximately $6.5 million in 2019 for vapor recovery improvements at Des Plaines, and tank and facility work at Colex and Des Plaines.
With the exception of the Zydeco directional drill project for which we are indemnified for our proportionate share, we anticipate that both maintenance and expansion capital expenditures for 2019 will be funded primarily with cash from operations.
Capital Contribution
In accordance with the Member Interest Purchase Agreement entered into in conjunction with the October 2017 Acquisition, we will make capital contributions for our pro rata interest in Permian Basin to fund capital and other expenditures, as approved by supermajority (75%) vote of the members. We have made capital contributions of $28.0 million in 2018, and expect to make capital contributions of approximately $14.5 million in 2019.
Tax Cuts and Jobs Act
On December 22, 2017, the TCJA was signed into law by President Trump. The TCJA makes broad and complex changes to the Internal Revenue Code of 1986, including, but not limited to, (1) creating a new deduction on certain pass-through income to individual partners; (2) repealing the partnership technical termination rule; (3) creating new limitations on certain deductions and credits, including interest expense deductions; and (4) reducing the highest marginal U.S. federal corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. With the exception of the operations of Colonial, Explorer and LOCAP, which are treated as corporations for federal income tax purposes, the operations of the Partnership are not subject to federal income tax, and therefore, the legislation did not have a material impact to the Partnership for 2018.
68
Contractual Obligations
A summary of our contractual obligations, as of December 31, 2018, is shown in the table below (in millions):
| Total | Less than 1 year | Years 2 to 3 | Years 4 to 5 | More than 5 years | |||||||||||||||||||||||||
| Operating leases for land | $ | 3.4 | $ | 0.2 | $ | 0.4 | $ | 0.4 | $ | 2.4 | |||||||||||||||||||
| Operating lease of platform space | 1.9 | 0.1 | 0.2 | 0.2 | 1.4 | ||||||||||||||||||||||||
Capital leases (1) | 66.2 | 5.0 | 10.1 | 10.1 | 41.0 | ||||||||||||||||||||||||
Other agreements (2) | 46.7 | 5.6 | 11.2 | 11.2 | 18.7 | ||||||||||||||||||||||||
Debt obligation (3) | 2,094.0 | — | — | 1,494.0 | 600.0 | ||||||||||||||||||||||||
| $ | 2,212.2 | $ | 10.9 | $ | 21.9 | $ | 1,515.9 | $ | 663.5 | ||||||||||||||||||||
(1) Capital leases include Port Neches storage tanks and Garden Banks 128 "A" platform. Port Neches storage tanks includes $30.1 million in interest, $24.3 million in principal and $9.6 million in executory costs.
(2) Includes a joint tariff agreement and Odyssey tie-in agreement.
(3) See Note 9 – Related Party Debt in the Notes to Consolidated Financial Statements included in Part II, Item 8 for additional information.
Odyssey entered into an operating lease dated May 12, 1999 with a third party for usage of offshore platform space at Main Pass 289C. Additionally, Odyssey entered into a tie-in agreement effective January 2012 with a third party, which allowed producers to install the tie-in connection facilities and tying into the system. The agreements will continue to be in effect until the continued operation of the platform is uneconomic.
On December 1, 2014, we entered into a terminal services agreement with a related party in which we were to take possession of certain storage tanks located in Port Neches, Texas, effective December 1, 2015. On October 26, 2015, the terminal services agreement was amended to provide for an interim in-service period for the purposes of commissioning the tanks in which we paid a nominal monthly fee. Our capitalized costs and related capital lease obligation commenced effective December 1, 2015. Upon the in-service date of September 1, 2016, our monthly lease payment was increased to $0.4 million. Under this agreement, in the eighteenth month after the in-service date, actual fixed and variable costs could be compared to premised costs. If the actual and premised operating costs differ by more than 5.0%, the lease would be adjusted accordingly and this adjustment will be effective for the remainder of the lease. No adjustment as been made to date. The imputed interest rate on the capital portion of the lease is 15.0%.
On September 1, 2016, which is the in-service date of the capital lease for the Port Neches storage tanks, a joint tariff agreement with a third party became effective and requires monthly payments of approximately $0.4 million. The tariff will be reviewed annually and the rate updated based on the FERC indexing adjustment to rates effective July 1 of each year. Effective July 1, 2018 there was an approximately 4.4% increase to this rate based on FERC indexing adjustment. The initial term of the agreement is ten years with automatic one year renewal terms with the option to cancel prior to each renewal period.
Off-Balance Sheet Arrangements
We have not entered into any transactions, agreements or other contractual arrangements that would result in off-balance sheet liabilities.
Critical Accounting Policies and Estimates
Critical accounting policies are those that are important to our financial condition and require management’s most difficult, subjective or complex judgments. Different amounts would be reported under different operating conditions or under alternative assumptions.
We apply those accounting policies that we believe best reflect the underlying business and economic events, consistent with GAAP. Our more critical accounting policies include those related to long-lived assets, equity method investments and revenue recognition. Inherent in such policies are certain key assumptions and estimates. We periodically update the estimates used in the preparation of the financial statements based on our latest assessment of the current and projected business and general economic environment. Our significant accounting policies are summarized in Note 2 - Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report. We believe the following to be our most critical accounting policies applied in the preparation of our financial statements.
Long-Lived Assets
69
Key estimates related to long-lived assets include useful lives, recoverability of carrying values and existence of any retirement obligations. Such estimates could be significantly modified. The carrying values of long-lived assets could be impaired by significant changes or projected changes in supply and demand fundamentals of oil, natural gas, refinery gas or refined products (which could have a negative impact on operating rates or margins), new technological developments, new competitors, adverse changes associated with the United States and global economies and with governmental actions. We evaluate long-lived assets for potential impairment indicators whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, including when negative conditions such as significant current or projected operating losses exist. Our judgments regarding the existence of impairment indicators are based on legal factors, market conditions and the operational performance of our businesses. Actual impairment losses incurred could vary significantly from amounts estimated. Long-lived assets assessed for impairment are grouped at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. Additionally, future events could cause us to conclude that impairment indicators exist and that associated long-lived assets of our businesses are impaired. Any resulting impairment loss could have a material adverse impact on our financial condition and results of operations.
The estimated useful lives of long-lived assets range from five to 40 years. Depreciation of these assets under the straight-line method over their estimated useful lives totaled $45.9 million, $45.0 million and $43.1 million for 2018, 2017 and 2016, respectively. If the useful lives of the assets were found to be shorter than originally estimated, depreciation charges would be accelerated. Additional information concerning long-lived assets and related depreciation and amortization appears in Note 7 — Property, Plant and Equipment in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report.
Equity Method Investments
We account for investments where we have the ability to exercise significant influence, but not control, under the equity method of accounting. Income from equity method investments represents our proportionate share of net income generated by the equity method investees. Differences in the basis of the investments and the separate net asset value of the investees, if any, are amortized into net income over the remaining useful lives of the underlying assets. Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value.
Revenue Recognition
We adopted the new revenue standard on January 1, 2018. See Note 3 — Revenue Recognition in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report for additional information.
We recognize revenue when we transfer promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. We recognize revenue through the application of a five-step model, which includes: identification of the contract; identification of the performance obligations; determination of the transaction price; allocation of the transaction price to the performance obligations; and recognition of revenue as the entity satisfies the performance obligations. We generate a portion of our revenue under long-term agreements by charging fees for the transportation, terminaling and storage of crude oil and refined products, and for the transportation of refinery gas through our assets. Contract obligations are billed monthly. Transportation revenue is billed as services are rendered, and we accrue revenue based on nominations for that accounting month. We estimate this revenue based on contract data, regulatory information, and preliminary throughput and allocation measurements, among other items. Additionally, we refer to our transportation services agreements and throughput and deficiency agreements as “ship-or-pay” contracts.
As a result of FERC regulations, revenues we collect may be subject to refund. We establish reserves for these potential refunds based on actual expected refund amounts on the specific facts and circumstances. We had no reserves for potential refunds as of December 31, 2018 and 2017.
The majority of our long-term transportation agreements and tariffs for crude oil transportation include PLA. PLA is an allowance for volume losses due to measurement differences set forth in crude oil transportation agreements. PLA is intended to assure proper measurement of the crude oil despite solids, water, evaporation and variable crude types that can cause mismeasurement. PLA provides additional revenue for us if product losses on our pipelines are within the allowed levels, and we are required to compensate our customers for any product losses that exceed the allowed levels. We take title to any excess loss allowance when product losses are within the allowed levels, and we sell that product several times per year at prevailing market prices.
Certain transportation and terminaling services agreements with related parties are considered operating leases under GAAP. Revenues from these agreements are recorded within “Lease revenue-related parties” in the accompanying consolidated
70
statement of income. See Note 3 — Revenue Recognition in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report.
Onshore Crude Pipelines
Our onshore crude pipelines transport volumes on a spot basis. Additionally, our Zydeco pipeline system has historically generated a substantial portion of its revenue from transportation services agreements. In compliance with FERC indexing adjustments, our rates may be indexed annually. Certain rates on our assets were not affected either due to the fact that the index did not apply to contracted rates or they were already below the index ceiling level.
Our FERC-approved transportation services agreements on Zydeco entitle the customer to a specified amount of guaranteed capacity on the pipeline. This capacity cannot be pro-rated even if the pipeline is oversubscribed. In exchange, the customer makes a specified monthly payment regardless of the volume transported. If the customer does not ship its full guaranteed volume in a given month, it makes the full monthly cash payment and it may ship the unused volume in a later month for no additional cash payment for up to 12 months, subject to availability on the pipeline. The cash payment received is recognized as deferred revenue, and thereby not included in revenue or net income until the earlier of the actual or estimated shipment of the unused volumes or the expiration of the 12-month period, as provided for in the applicable contract. If there is insufficient capacity on the pipeline to allow the unused volume to be shipped, the customer forfeits its right to ship such unused volume. We do not refund any cash payments relating to unused volumes.
Please see “— Factors Affecting our Business and Outlook — Changes in Customer Contracting” for additional information on Zydeco’s transportation services agreements.
Offshore Crude Pipelines
Our offshore crude pipelines generate revenue under several types of long-term transportation agreements: life-of-lease transportation agreements, life-of-lease transportation agreements with a guaranteed return, transportation and dedication agreements (“T&D agreements”), debottleneck surcharge agreements and buy/sell agreements. Some crude oil also moves on our offshore pipelines under posted tariffs, which may be indexed annually. In addition, Mars has the ability to charge inventory management fees.
Our life-of-lease transportation agreements have a term equal to the life of the applicable mineral lease. Our life-of-lease transportation agreements require producers to transport all production from the specified fields connected to the pipeline for the entire life of the lease. This means that the dedicated production cannot be transported by any other means, such as barges or another pipeline. Some of these agreements can also include provisions to guarantee a return to the pipeline to enable the pipeline to recover its investment in the initial years despite the uncertainty in production volumes by providing for an annual transportation rate adjustment over a fixed period of time to achieve a fixed rate of return. The calculation for the fixed rate of return is usually based on actual project costs and operating costs. At the end of the fixed period, some rates will be locked in at the last calculated rate and adjusted thereafter based on the FERC index.
In addition to posted tariffs, Amberjack generates revenue under T&D agreements which require shippers to dedicate production from specific fields for a fixed term, generally for life of the facility or lease. In addition, some T&D agreements require a minimum volume to be delivered for a fixed term. If the producer falls below the minimum volume for the specified term, they are required to make a payment for the volume deficiency at the agreed transportation rate. T&D agreements may, but typically do not, offer firm space on the pipeline in question. If a segment of the pipeline system is oversubscribed, space is prorated in accordance with the then published rules and regulations of the pipeline. Additionally, Amberjack has debottleneck surcharge agreements related to recovering certain costs associated with the debottleneck work performed on the system which do provide firm capacity to some delivery locations.
Odyssey and Poseidon provide for the transportation of crude oil through the use of buy/sell arrangements where crude is purchased at the receipt location into the pipeline and sold back to the counterparty at the destination at that price plus a transportation differential. Proteus and Endymion provide for the transportation of crude oil via private Oil Transportation Agreements (“OTAs”). These OTAs are a mix of term and life-of-lease transportation agreements. For Endymion, these OTA contracts also allow for storage at the Clovelly storage terminal.
Refined Products Pipelines
Bengal’s revenue is primarily dependent on ship-or-pay contracts, which are renewable at the election of the shipper. In compliance with FERC indexing adjustments, the rates may be indexed annually. Bengal also has a joint tariff division agreement with Colonial covering certain transportation of refined products. Colonial and Explorer generate revenue under both
71
FERC approved rates that are subject to annual indexing. Colonial also provides for transportation under market-based rates. Additionally, Explorer has an auction program for certain excess capacity when the pipeline is fully subscribed, as well as ship-or-pay contracts for certain products.
Terminals and Storage
Our Seattle, Portland, Anacortes, Des Plaines and Colex products terminals provide storage and terminaling services, which are 100% utilized. For each terminal, revenue, based on throughput, is generated via a single, long-term, terminaling services agreement with a related party which are treated as operating leases. Each agreement provides for a guaranteed minimum throughput. The contracts initially expire on November 30, 2027 with an option to extend the agreement for ten additional one year terms.
At Lockport, our storage tanks are utilized at approximately 95% capacity primarily via four terminal services agreements. Two of the agreements expired in 2018 and have been extended under revised terms through May 2019 and December 2019, respectively. The other two agreements will also expire in 2019. We continue to actively develop new business for the facility.
Other Midstream Assets
Our Refinery Gas Pipeline system generates revenue under transportation services agreements that include minimum revenue commitments and are treated as operating leases. The contracts require a specified monthly payment regardless of volume shipped, and do not receive a credit for unused volume in a given month to use in future months.
Recent Accounting Pronouncements
Please read Note 2 — Summary of Significant Accounting Policies — Recent Accounting Pronouncements included in Part II, Item 8 of this report.
72
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. With the exception of buy/sell arrangements on some of our offshore pipelines and our allowance oil retained, we do not take ownership of the crude oil or refined products that we transport and store for our customers, and we do not engage in the trading of any commodities. We therefore have limited direct exposure to risks associated with fluctuating commodity prices.
Our long-term transportation agreements and tariffs for crude oil shipments include PLA. The PLA provides additional revenue for us at a stated factor per barrel. If product losses on our pipelines are within the allowed levels we retain the benefit, otherwise we are required to compensate our customers for any product losses that exceed the allowed levels. We take title to any excess product that we transport when product losses are within allowed level, and we sell that product several times per year at prevailing market prices. This allowance oil revenue, which accounted for 5.9%, 6.2% and 5.4% of our total revenue in 2018, 2017 and 2016, respectively, is subject to more volatility than transportation revenue, as it is directly dependent on our measurement capability and commodity prices. As a result, the income we realize under our loss allowance provisions will increase or decrease as a result of changes in the mix of product transported, measurement accuracy and underlying commodity prices. We do not intend to enter into any hedging agreements to mitigate our exposure to decreases in commodity prices through our loss allowances.
We may also have risk associated with changes in policy or other actions taken by FERC. Please see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Factors Affecting our Business and Outlook — Regulation” for additional information.
Interest Rate Risk
We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under our revolving credit facilities. To the extent that interest rates increase, interest expense for these revolvers will also increase. As of December 31, 2018 and December 31, 2017, the Partnership had $894.0 million and $1,246.9 million, respectively, in outstanding variable rate borrowings under these revolving credit facilities. A hypothetical change of 12.5 basis points in the interest rate of our variable rate debt would impact the Partnership’s annual interest expense by approximately $1.1 million and $1.6 million for the years ended 2018 and 2017, respectively. We do not currently intend to enter into any interest rate hedging agreements, but will continue to monitor interest rate exposure.
Our fixed rate debt does not expose us to fluctuations in our results of operations or liquidity from changes in market interest rates. Changes in interest rates do affect the fair value of our fixed rate debt. See Note 9 — Related Party Debt in the accompanying Notes to Consolidated Financial Statements included in Part II, Item 8 of this report for further discussion of our borrowings and fair value measurements.
73
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
SHELL MIDSTREAM PARTNERS, L.P.
INDEX TO FINANCIAL STATEMENTS
| Page | |||||
74
Report of Independent Registered Public Accounting Firm
The Board of Directors of Shell Midstream Partners GP LLC and Unitholders of Shell Midstream Partners, L.P.
Opinion on Internal Control over Financial Reporting
We have audited Shell Midstream Partners, L.P.’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Shell Midstream Partners, L.P. (the Partnership) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the accompanying consolidated balance sheets of Shell Midstream Partners, L.P. as of December 31, 2018 and 2017, and the related consolidated statements of income, cash flows and changes in (deficit) equity for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “financial statements”) of the Partnership and our report dated February 21, 2019 expressed an unqualified opinion thereon.
Basis for Opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Houston, Texas
February 21, 2019
75
Report of Independent Registered Public Accounting Firm
The Board of Directors of Shell Midstream Partners GP LLC and Unitholders of Shell Midstream Partners, L.P.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Shell Midstream Partners, L.P. (the Partnership) as of December 31, 2018 and 2017, and the related consolidated statements of income, cash flows and changes in (deficit) equity for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “financial statements”). In our opinion, based on our audits and the report of other auditors, the financial statements present fairly, in all material respects, the consolidated financial position of the Partnership at December 31, 2018 and 2017, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.
We did not audit the financial statements of Poseidon Oil Pipeline Company, L.L.C., a limited liability company in which the Partnership has a 36% interest, for the year ended December 31, 2016. In the consolidated financial statements, the Partnership’s equity in the net income of Poseidon Oil Pipeline Company, L.L.C. is stated at $29.7 million for the year ended December 31, 2016. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Poseidon Oil Pipeline Company, L.L.C., is based solely on the report of other auditors.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 21, 2019 expressed an unqualified opinion thereon.
Adoption of ASU No. 2014-09
As discussed in Note 3 to the consolidated financial statements, the Partnership and Mars Oil Pipeline Company LLC, an investment accounted for by the equity method, changed their method for accounting for revenue in 2018 due to the adoption of Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers (Topic 606), and the amendments in ASUs 2015-14, 2016-08, 2016-10 and 2016-12.
Basis for Opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.
/s/ Ernst & Young LLP
We have served as the Partnership’s auditor since 2016.
Houston, Texas
February 21, 2019
76
Report of Independent Registered Public Accounting Firm
To the Management Committee of
Poseidon Oil Pipeline Company, L.L.C.
Houston, Texas
We have audited the statements of operations, cash flows, and members’ equity of Poseidon Oil Pipeline Company L.L.C. (the “Company”) for the year ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the results of operations and cash flows of Poseidon Oil Pipeline Company L.L.C. for the year ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Houston, Texas
February 17, 2017
77
SHELL MIDSTREAM PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
December 31, | |||||||||||
| 2018 | 2017 | ||||||||||
(in millions of dollars) | |||||||||||
| ASSETS | |||||||||||
| Current assets | |||||||||||
| Cash and cash equivalents | $ | 208.0 | $ | 137.7 | |||||||
| Accounts receivable – third parties, net | 18.8 | 17.2 | |||||||||
| Accounts receivable – related parties | 28.7 | 23.8 | |||||||||
| Allowance oil | 12.7 | 12.4 | |||||||||
| Prepaid expenses | 15.4 | 12.5 | |||||||||
| Total current assets | 283.6 | 203.6 | |||||||||
| Equity method investments | 822.9 | 362.6 | |||||||||
| Property, plant and equipment, net | 742.4 | 736.5 | |||||||||
| Other investments | 62.1 | 62.1 | |||||||||
| Other assets – related parties | 2.5 | 1.7 | |||||||||
| Total assets | $ | 1,913.5 | $ | 1,366.5 | |||||||
| LIABILITIES | |||||||||||
| Current liabilities | |||||||||||
| Accounts payable – third parties | $ | 4.0 | $ | 4.0 | |||||||
| Accounts payable – related parties | 8.9 | 11.6 | |||||||||
| Deferred revenue – third parties | 8.0 | 5.5 | |||||||||
| Deferred revenue – related party | 2.6 | 13.9 | |||||||||
| Accrued liabilities – third parties | 13.0 | 12.7 | |||||||||
| Accrued liabilities – related parties | 15.7 | 7.2 | |||||||||
| Total current liabilities | 52.2 | 54.9 | |||||||||
| Noncurrent liabilities | |||||||||||
| Debt payable – related party | 2,090.7 | 1,844.0 | |||||||||
| Lease liability | 25.1 | 24.3 | |||||||||
| Asset retirement obligations | — | 6.6 | |||||||||
| Other unearned income | 2.5 | 2.6 | |||||||||
| Total noncurrent liabilities | 2,118.3 | 1,877.5 | |||||||||
| Total liabilities | 2,170.5 | 1,932.4 | |||||||||
| Commitments and Contingencies (Note 14) | |||||||||||
| (DEFICIT) EQUITY | |||||||||||
| Common unitholders – public (123,832,233 and 98,832,233 units issued and outstanding as of December 31, 2018 and December 31, 2017) | 3,459.3 | 2,773.5 | |||||||||
| Common unitholder – SPLC (99,979,548 and 88,950,136 units issued and outstanding as of December 31, 2018 and December 31, 2017) | (198.0) | (507.2) | |||||||||
| General partner – SPLC (4,567,588 and 3,832,293 units issued and outstanding as of December 31, 2018 and December 31, 2017) | (3,543.7) | (2,855.5) | |||||||||
| Total partners’ deficit | (282.4) | (589.2) | |||||||||
| Noncontrolling interests | 25.4 | 23.3 | |||||||||
| Total deficit | (257.0) | (565.9) | |||||||||
| Total liabilities and deficit | $ | 1,913.5 | $ | 1,366.5 | |||||||
The accompanying notes are an integral part of the consolidated financial statements.
78
SHELL MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF INCOME
2018 | 2017 | 2016 | |||||||||||||||
(in millions of dollars, except per unit data) | |||||||||||||||||
| Revenue | |||||||||||||||||
| Transportation, terminaling and storage services – third parties | $ | 209.4 | $ | 235.6 | $ | 251.5 | |||||||||||
| Transportation, terminaling and storage services – related parties | 228.5 | 178.2 | 188.3 | ||||||||||||||
| Product revenue – third parties | 2.2 | — | — | ||||||||||||||
| Product revenue – related parties | 28.5 | — | — | ||||||||||||||
| Lease revenue – related parties | 56.1 | 56.3 | 13.1 | ||||||||||||||
| Total revenue | 524.7 | 470.1 | 452.9 | ||||||||||||||
| Costs and expenses | |||||||||||||||||
| Operations and maintenance – third parties | 107.5 | 104.1 | 76.9 | ||||||||||||||
| Operations and maintenance – related parties | 54.4 | 45.6 | 40.0 | ||||||||||||||
| Cost of product sold – third parties | 7.4 | — | — | ||||||||||||||
| Cost of product sold – related parties | 25.3 | — | — | ||||||||||||||
| (Gain) loss from revision of ARO and disposition of fixed assets | (3.4) | 0.1 | 0.2 | ||||||||||||||
| General and administrative – third parties | 7.8 | 10.1 | 9.7 | ||||||||||||||
| General and administrative – related parties | 51.7 | 47.7 | 43.7 | ||||||||||||||
| Depreciation, amortization and accretion | 45.9 | 45.0 | 43.1 | ||||||||||||||
| Property and other taxes | 15.9 | 17.4 | 15.8 | ||||||||||||||
| Total costs and expenses | 312.5 | 270.0 | 229.4 | ||||||||||||||
| Operating income | 212.2 | 200.1 | 223.5 | ||||||||||||||
| Income from equity method investments | 234.9 | 186.6 | 138.1 | ||||||||||||||
| Dividend income from other investments | 66.8 | 37.4 | 28.3 | ||||||||||||||
| Other income (loss) | 31.4 | — | (0.1) | ||||||||||||||
| Investment, dividend and other income (loss) | 333.1 | 224.0 | 166.3 | ||||||||||||||
| Interest expense, net | 62.5 | 32.2 | 12.3 | ||||||||||||||
| Income before income taxes | 482.8 | 391.9 | 377.5 | ||||||||||||||
| Income tax expense | 0.4 | 0.1 | — | ||||||||||||||
| Net income | 482.4 | 391.8 | 377.5 | ||||||||||||||
| Less: Net income attributable to the Parent | — | 77.3 | 102.3 | ||||||||||||||
| Less: Net income attributable to noncontrolling interests | 18.3 | 19.2 | 30.3 | ||||||||||||||
| Net income attributable to the Partnership | $ | 464.1 | $ | 295.3 | $ | 244.9 | |||||||||||
| General partner’s interest in net income attributable to the Partnership | $ | 134.4 | $ | 64.6 | $ | 25.0 | |||||||||||
| Limited Partners’ interest in net income attributable to the Partnership | $ | 329.7 | $ | 230.7 | $ | 219.9 | |||||||||||
| Net income per Limited Partner Unit - Basic and Diluted: | |||||||||||||||||
| Common | $ | 1.50 | $ | 1.28 | $ | 1.32 | |||||||||||
| Subordinated | $ | — | $ | — | $ | 1.27 | |||||||||||
| Distributions per Limited Partner unit: | $ | 1.4950 | $ | 1.2461 | $ | 1.0258 | |||||||||||
| Weighted average Limited Partner Units outstanding - Basic and Diluted: | |||||||||||||||||
| Common units - public | 121.3 | 91.4 | 80.4 | ||||||||||||||
| Common units - SPLC | 99.0 | 89.0 | 21.5 | ||||||||||||||
| Subordinated units - SPLC | — | — | 67.5 | ||||||||||||||
The accompanying notes are an integral part of the consolidated financial statements.
79
SHELL MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
| 2018 | 2017 | 2016 | |||||||||||||||
| (in millions of dollars) | |||||||||||||||||
| Cash flows from operating activities | |||||||||||||||||
| Net income | $ | 482.4 | $ | 391.8 | $ | 377.5 | |||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities | |||||||||||||||||
| Depreciation, amortization and accretion | 45.9 | 45.0 | 43.1 | ||||||||||||||
| (Gain) loss from revision of ARO and disposition of fixed assets | (3.4) | 0.1 | 0.2 | ||||||||||||||
| Non-cash interest expense | 0.9 | 0.4 | 2.7 | ||||||||||||||
| Allowance oil reduction to net realizable value | 5.5 | 0.3 | — | ||||||||||||||
| Undistributed equity earnings | (5.8) | (6.5) | 4.1 | ||||||||||||||
| Changes in operating assets and liabilities | |||||||||||||||||
| Accounts receivable | (6.8) | (7.4) | 0.3 | ||||||||||||||
| Allowance oil | (5.8) | (3.4) | (4.0) | ||||||||||||||
| Prepaid expenses and other assets | (3.7) | (6.8) | (0.1) | ||||||||||||||
| Accounts payable | (6.9) | 8.3 | 0.3 | ||||||||||||||
| Deferred revenue and other unearned income | (4.3) | 6.0 | 7.9 | ||||||||||||||
| Accrued liabilities | 10.4 | 4.6 | (2.8) | ||||||||||||||
| Net cash provided by operating activities | 508.4 | 432.4 | 429.2 | ||||||||||||||
| Cash flows from investing activities | |||||||||||||||||
| Capital expenditures | (49.2) | (58.0) | (45.8) | ||||||||||||||
| Acquisitions from Parent | (481.6) | (420.5) | (172.8) | ||||||||||||||
| Third party acquisitions | — | (37.9) | (42.0) | ||||||||||||||
| Contributions to investment | (28.0) | (12.0) | — | ||||||||||||||
| Purchase price adjustment | — | 0.3 | — | ||||||||||||||
| Return of investment | 48.2 | 18.2 | 15.8 | ||||||||||||||
| Other | 0.3 | — | — | ||||||||||||||
| April 2017 Divestiture | — | 0.8 | — | ||||||||||||||
| Net cash used in investing activities | (510.3) | (509.1) | (244.8) | ||||||||||||||
| Cash flows from financing activities | |||||||||||||||||
| Net proceeds from equity offerings | 973.3 | 277.9 | 818.1 | ||||||||||||||
| Borrowings under credit facilities | 1,820.0 | 1,693.1 | 638.7 | ||||||||||||||
| Repayments of credit facilities | (1,572.9) | (533.1) | (410.0) | ||||||||||||||
| Contributions from general partner | 20.0 | 5.8 | 9.8 | ||||||||||||||
| Proceeds from April 2017 Divestiture | — | 20.2 | — | ||||||||||||||
| Capital distributions to general partner | (738.4) | (1,034.5) | (896.3) | ||||||||||||||
| Distributions to noncontrolling interests | (16.4) | (18.9) | (30.2) | ||||||||||||||
| Distributions to unitholders and general partner | (423.1) | (267.8) | (179.9) | ||||||||||||||
| Net distributions to Parent | — | (65.6) | (120.0) | ||||||||||||||
| Other contributions from Parent | 11.6 | 18.2 | 14.4 | ||||||||||||||
| Credit facility issuance costs | (1.3) | (2.4) | (0.6) | ||||||||||||||
| Other | (0.6) | (0.6) | (0.1) | ||||||||||||||
| Net cash provided by (used in) financing activities | 72.2 | 92.3 | (156.1) | ||||||||||||||
| Net increase in cash and cash equivalents | 70.3 | 15.6 | 28.3 | ||||||||||||||
| Cash and cash equivalents at beginning of the period | 137.7 | 122.1 | 93.8 | ||||||||||||||
| Cash and cash equivalents at end of the period | $ | 208.0 | $ | 137.7 | $ | 122.1 | |||||||||||
80
| Supplemental Cash Flow Information | |||||||||||||||||
| Non-cash investing and financing transactions: | |||||||||||||||||
| Change in asset retirement obligation | $ | 1.7 | $ | — | $ | (1.0) | |||||||||||
| Change in accrued capital expenditures | 2.4 | (0.1) | (1.1) | ||||||||||||||
| Other non-cash contributions from Parent | 1.9 | — | 0.2 | ||||||||||||||
| Net assets not contributed to the Partnership | — | (5.1) | — | ||||||||||||||
| Other non-cash capital distributions to general partner | — | — | (7.1) | ||||||||||||||
| Other non-cash contribution from general partner | — | — | 7.1 | ||||||||||||||
The accompanying notes are an integral part of the consolidated financial statements.
81
SHELL MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CHANGES IN (DEFICIT) EQUITY
Partnership | |||||||||||||||||||||||||||||||||||||||||
(in millions of dollars) | Common Unitholders Public | Common Unitholder SPLC | Subordinated Unitholder SPLC | General Partner SPLC | Noncontrolling Interests | Net Parent Investment | Total | ||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2015 | $ | 1,637.5 | $ | (130.4) | $ | (409.8) | $ | (998.6) | $ | 108.4 | $ | 425.4 | $ | 632.5 | |||||||||||||||||||||||||||
| Net income | 107.2 | 27.2 | 85.5 | 25.0 | 30.3 | 102.3 | 377.5 | ||||||||||||||||||||||||||||||||||
| Net proceeds from public offerings | 818.1 | — | — | — | — | — | 818.1 | ||||||||||||||||||||||||||||||||||
| Contributions from general partner | — | — | — | 16.9 | — | — | 16.9 | ||||||||||||||||||||||||||||||||||
| Other contributions from Parent | — | — | — | 3.0 | — | 6.7 | 9.7 | ||||||||||||||||||||||||||||||||||
| Distributions to unitholders and general partner | (77.1) | (20.9) | (65.3) | (16.6) | — | — | (179.9) | ||||||||||||||||||||||||||||||||||
| Net distributions to Parent | — | — | — | — | — | (120.0) | (120.0) | ||||||||||||||||||||||||||||||||||
| Distribution to noncontrolling interests | — | — | — | — | (30.2) | — | (30.2) | ||||||||||||||||||||||||||||||||||
| Capital distributions to general partner | — | — | — | (903.4) | — | — | (903.4) | ||||||||||||||||||||||||||||||||||
| Acquisition of noncontrolling interest | — | — | — | — | (87.0) | — | (87.0) | ||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2016 | $ | 2,485.7 | $ | (124.1) | $ | (389.6) | $ | (1,873.7) | $ | 21.5 | $ | 414.4 | $ | 534.2 | |||||||||||||||||||||||||||
| Net income | 118.4 | 112.3 | — | 64.6 | 19.2 | 77.3 | 391.8 | ||||||||||||||||||||||||||||||||||
| Net proceeds from public offerings | 277.9 | — | — | — | — | — | 277.9 | ||||||||||||||||||||||||||||||||||
| Contributions from general partner | — | — | — | 5.8 | — | — | 5.8 | ||||||||||||||||||||||||||||||||||
| Other contributions from Parent | — | — | — | 17.1 | — | — | 17.1 | ||||||||||||||||||||||||||||||||||
| Distributions to unitholders and general partner | (108.5) | (87.1) | (18.7) | (53.5) | — | — | (267.8) | ||||||||||||||||||||||||||||||||||
| Net distributions to Parent | — | — | — | — | — | (65.6) | (65.6) | ||||||||||||||||||||||||||||||||||
| Distribution to noncontrolling interests | — | — | — | — | (18.9) | — | (18.9) | ||||||||||||||||||||||||||||||||||
| Proceeds from April 2017 divestiture | — | — | — | 18.7 | 1.5 | — | 20.2 | ||||||||||||||||||||||||||||||||||
| Expiration of subordinated period | — | (408.3) | 408.3 | — | — | — | — | ||||||||||||||||||||||||||||||||||
| Acquisitions from Parent | — | — | — | (1,034.5) | — | (420.5) | (1,455.0) | ||||||||||||||||||||||||||||||||||
| Net assets not contributed to the partnership | — | — | — | — | — | (5.6) | (5.6) | ||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2017 | $ | 2,773.5 | $ | (507.2) | $ | — | $ | (2,855.5) | $ | 23.3 | $ | — | $ | (565.9) | |||||||||||||||||||||||||||
| Impact of change in accounting policy (Note 3) | (1.4) | 1.0 | — | (2.2) | 0.3 | — | (2.3) | ||||||||||||||||||||||||||||||||||
| Net income | 182.4 | 147.3 | — | 134.4 | 18.3 | — | 482.4 | ||||||||||||||||||||||||||||||||||
| Net proceeds from equity offerings | 673.3 | 300.0 | — | — | — | — | 973.3 | ||||||||||||||||||||||||||||||||||
| Contributions from general partner | — | — | — | 20.0 | — | — | 20.0 | ||||||||||||||||||||||||||||||||||
| Other contributions from Parent | — | — | — | 13.5 | (0.1) | — | 13.4 | ||||||||||||||||||||||||||||||||||
| Distributions to unitholders and general partner | (168.5) | (139.1) | — | (115.5) | — | — | (423.1) | ||||||||||||||||||||||||||||||||||
| Distribution to noncontrolling interests | — | — | — | — | (16.4) | — | (16.4) | ||||||||||||||||||||||||||||||||||
| May 2018 Acquisition | — | — | — | (738.4) | — | — | (738.4) | ||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2018 | $ | 3,459.3 | $ | (198.0) | $ | — | $ | (3,543.7) | $ | 25.4 | $ | — | $ | (257.0) | |||||||||||||||||||||||||||
The accompanying notes are an integral part of the consolidated financial statements.
82
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Except as noted within the context of each note disclosure, the dollar amounts presented in the tabular data within these note disclosures are stated in millions of dollars.
1. Description of Business and Basis of Presentation
Shell Midstream Partners, L.P. (“we,” “us,” “our” or “the Partnership”) is a Delaware limited partnership formed by Royal Dutch Shell plc on March 19, 2014 to own and operate pipeline and other midstream assets, including certain assets received from Shell Pipeline Company LP (“SPLC”) and its affiliates. We conduct our operations either through our wholly owned subsidiary Shell Midstream Operating, LLC (“Operating Company”) or through direct ownership. Our general partner is Shell Midstream Partners GP LLC (“general partner” or “sponsor”). References to “RDS”, “Shell” or “Parent” refer collectively to Royal Dutch Shell plc and its controlled affiliates, other than us, our subsidiaries and our general partner. Our common units trade on the New York Stock Exchange under the symbol “SHLX.”
Description of Business
We are a growth-oriented master limited partnership that owns, operates, develops and acquires pipelines and other midstream assets. As of December 31, 2018, our assets include interests in entities that own crude oil and refined products pipelines and terminals that serve as key infrastructure to (i) transport onshore and offshore crude oil production to Gulf Coast and Midwest refining markets and (ii) deliver refined products from those markets to major demand centers. Our assets also include interests in entities that own natural gas and refinery gas pipelines which transport offshore natural gas to market hubs and deliver refinery gas from refineries and plants to chemical sites along the Gulf Coast.
We generate revenue from the transportation, terminaling and storage of crude oil and refined products through our pipelines and storage tanks, and generate income from our equity and cost method investments. Our operations consist of one reportable segment.
The following table reflects our ownership, and Shell’s retained ownership as of December 31, 2018:
| SHLX Ownership | Shell’s Retained Ownership | ||||||||||
| Pecten Midstream LLC (“Pecten”) | 100.0 | % | — | % | |||||||
| Sand Dollar Pipeline LLC (“Sand Dollar”) | 100.0 | % | — | % | |||||||
| Triton West LLC (“Triton”) | 100.0 | % | — | % | |||||||
| Zydeco Pipeline Company LLC (“Zydeco”) | 92.5 | % | 7.5 | % | |||||||
| Amberjack Pipeline Company LLC (“Amberjack”) – Series A/Series B | 75.0% / 50.0% | — | % | ||||||||
| Mars Oil Pipeline Company LLC (“Mars”) | 71.5 | % | — | % | |||||||
| Odyssey Pipeline L.L.C. (“Odyssey”) | 71.0 | % | — | % | |||||||
| Bengal Pipeline Company LLC (“Bengal”) | 50.0 | % | — | % | |||||||
| Crestwood Permian Basin LLC (“Permian Basin”) | 50.0 | % | — | % | |||||||
| LOCAP LLC (“LOCAP”) | 41.48 | % | — | % | |||||||
| Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”) | 36.0 | % | — | % | |||||||
| Explorer Pipeline Company (“Explorer”) | 12.62 | % | 25.97 | % | |||||||
| Proteus Oil Pipeline Company, LLC (“Proteus”) | 10.0 | % | — | % | |||||||
| Endymion Oil Pipeline Company, LLC (“Endymion”) | 10.0 | % | — | % | |||||||
| Colonial Pipeline Company (“Colonial”) | 6.0 | % | 10.12 | % | |||||||
| Cleopatra Gas Gathering Company, LLC (“Cleopatra”) | 1.0 | % | — | % | |||||||
Basis of Presentation
Our consolidated financial statements include all subsidiaries required to be consolidated under generally accepted accounting principles in the United States (“GAAP”). Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars. The accompanying consolidated financial statements and related notes have been prepared under the rules and regulations of the Securities and Exchange Commission (the “SEC”). These rules and regulations conform to the accounting principles contained in the Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification, the single source of GAAP.
83
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Our consolidated subsidiaries include Pecten, Sand Dollar, Triton, Zydeco, Odyssey and the Operating Company. Asset acquisitions of additional interests in previously consolidated subsidiaries and interests in equity method and other investments are included in the financial statements prospectively from the effective date of each acquisition. In cases where these types of acquisitions are considered acquisitions of businesses under common control, the financial statements are retrospectively adjusted. The following businesses were acquired from our Parent and accounted for as acquisitions of businesses under common control. As such, our consolidated financial statements include the financial results of these businesses, which were derived from the financial statements and accounting records of SPLC and Shell for the periods prior to acquisition. Specifically, such businesses are reflected for the following periods prior to the effective date of such acquisitions by us:
•May 2017 Acquisition for periods prior to May 10, 2017; and
•December 2017 Acquisition for periods prior to December 1, 2017, including the effect of fully consolidating Odyssey.
Our consolidated statements of income, cash flows and changes in equity for 2017 and 2016 consist of the combined results of the May 2017 Acquisition and the December 2017 Acquisition prior to the respective acquisition dates, and the consolidated activity of the Partnership. Our consolidated statements of income exclude the results of these businesses from net income attributable to the Partnership for the periods indicated above by allocating these results to our Parent. See Note 4 - Acquisitions and Divestiture for definitions and additional information.
Expense Allocations. Our consolidated statements of income also include expense allocations for certain functions performed by SPLC and Shell on behalf of the above businesses prior to their respective dates of acquisition by us. Such costs are included in either general and administrative expenses or operations and maintenance expenses in the accompanying consolidated statements of income, depending on the nature of the employee’s role in our operations. The expense allocations have been determined on a basis that we, SPLC and Shell consider to be a reasonable reflection of the utilization of the services provided or the benefit received during the periods presented.
Beginning July 1, 2014, Zydeco entered into an operating and management agreement with SPLC (the “Management Agreement”) under which SPLC provides general management and administrative services to us. Therefore, we do not receive allocated corporate expenses from SPLC or Shell under this agreement. We receive direct and allocated field and regional expenses including payroll expenses not covered under the Management Agreement. In addition, beginning from October 1, 2015, Pecten entered into an operating and management agreement under which we receive direct and allocated field and regional expenses from SPLC. Beginning May 10, 2017, Sand Dollar entered into an operating and administrative management agreement under which we receive allocated expenses from SPLC. On December 1, 2017, our general partner, SPLC and Triton West entered into an operating and administrative management agreement. Our general partner provides certain operational and support services pursuant to the agreement. The necessary personnel are employed by SPLC and are assigned to our general partner. Triton West is allocated costs in connection with the services. On December 1, 2017, our general partner, SPLC and Odyssey entered into an operating and administrative management agreement pursuant to which we receive direct and allocated expenses from our general partner. The expenses under these agreements are primarily allocated to us on the basis of headcount, labor or other measure. These expense allocations have been determined on a basis that both SPLC and we consider to be a reasonable reflection of the utilization of services provided or the benefit received by us during the periods presented. See details of related party transactions in Note 5 — Related Party Transactions.
Cash. For all consolidated subsidiaries, we establish our own cash accounts for the funding of our operating and investing activities, with the exception of the capital expenditures incurred by SPLC on our behalf and then contributed to us. Funds are not commingled with the cash of other entities. Prior to the acquisition of each of these interests, the cash generated and used by our operations was deposited to Shell Treasury Center (West) Inc. (“STCW”) which was commingled with the cash of other entities controlled by Shell. STCW funded our operating activities and STCW or an affiliate funded investing activities as needed. Accordingly, we did not record any cash and cash equivalents held by SPLC on our behalf for any period prior to the effective date of each acquisition from Shell.
2. Summary of Significant Accounting Policies
Principles of Consolidation
Our consolidated financial statements include all subsidiaries where we have control. The assets and liabilities in the accompanying consolidated financial statements have been reflected on a historical basis. All significant intercompany accounts and transactions are eliminated upon consolidation. See Note 1 — Description of the Business and Basis of Presentation for additional details.
84
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Regulation
Certain businesses are subject to regulation by various authorities including, but not limited to the FERC. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers.
Net Parent Investment
Net Parent Investment represents Shell’s historical investment in us, our accumulated net earnings through the date which we completed the acquisition, and the net effect of transactions with, and allocations from, SPLC and Shell.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported of assets, liabilities, revenues and expenses in the accompanying consolidated financial statements and notes. Actual results could differ from those estimates.
Common Control Transactions
Assets and businesses acquired from our Parent and its subsidiaries are accounted for as common control transactions whereby the net assets acquired are combined with ours at our Parent’s historical carrying value. If any recognized consideration transferred in such a transaction exceeds the carrying value of the net assets acquired, the excess is treated as a capital distribution to our General Partner, similar to a dividend. If the carrying value of the net assets acquired exceeds any recognized consideration transferred including, if applicable, the fair value of any limited partner units issued, then our Parent would record an impairment and our net assets acquired would be recorded at fair value. To the extent that such transactions require prior periods to be retrospectively adjusted, historical net equity amounts prior to the transaction date are reflected in “Net Parent Investment.” Cash consideration up to the carrying value of net assets acquired is presented as an investing activity in our consolidated statement of cash flows. Cash consideration in excess of the carrying value of net assets acquired is presented as a financing activity in our consolidated statement of cash flows. Assets and businesses sold to our Parent are also common control transactions accounted for using historical carrying value with any resulting gain treated as a contribution from Parent.
Revenue Recognition
Our revenues are primarily generated from the transportation, terminaling and storage of crude oil, refined gas and refined petroleum products through our pipelines, terminals and storage tanks. We recognize revenue when we transfer promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. We recognize revenue through the application of a five-step model, which includes: identification of the contract; identification of the performance obligations; determination of the transaction price; allocation of the transaction price to the performance obligations; and recognition of revenue as the entity satisfies the performance obligations.
See Note 3 — Revenue Recognition for information and disclosures related to revenue from contracts with customers.
Cash and Cash Equivalents
Our cash and cash equivalents includes cash and short-term highly liquid overnight deposits.
Accounts Receivable and Allowance for Doubtful Accounts
Accounts receivable represent valid claims against customers for products sold or services rendered, net of allowances for
doubtful accounts. We assess the creditworthiness of our counterparties on an ongoing basis and require security, including
prepayments and other forms of collateral, when appropriate. We establish provisions for losses on accounts receivable due
from shippers and operators if we determine that we will not collect all or part of the outstanding balance. Outstanding
customer receivables are regularly reviewed for possible nonpayment indicators, and allowances for doubtful accounts are
recorded based upon management’s estimate of collectability at each balance sheet date. As of December 31, 2018 and 2017, we did not have any allowance for doubtful accounts.
Equity Method Investments
We account for investments where we have the ability to exercise significant influence, but not control, under the equity method of accounting. Income from equity method investments represents our proportionate share of net income generated by the equity method investees. Differences in the basis of the investments and the underlying net asset value of the investees, if any, are amortized into net income over the remaining useful lives of the underlying assets. Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to
85
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value.
Property, Plant and Equipment
Our property, plant and equipment is recorded at its historical cost of construction or, upon acquisition, at either the fair value of the assets acquired or the historical carrying value to the entity that placed the asset in service. Expenditures for major renewals and betterments are capitalized while those minor replacement, maintenance, and repairs which do not improve or extend asset life are expensed when incurred. For constructed assets, we capitalize all construction-related direct labor and material costs, as well as indirect construction costs. We capitalize interest on certain projects. For 2018, 2017 and 2016, the total amount of interest capitalized was immaterial.
We use the straight-line method to depreciate property, plant and equipment based on the estimated useful life of the asset. We report gains or losses on dispositions of fixed assets as (Gain) loss from revision of ARO and disposition of fixed assets in the accompanying consolidated statements of income.
Impairment of Long-lived Assets
We evaluate long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. These events include a significant decrease in the market value of the asset, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, which is a determination that involves judgment, we perform an impairment assessment by comparing estimated undiscounted future cash flows associated with the asset to the asset’s net book value. If the net book value exceeds our estimate of undiscounted future cash flows, an impairment is calculated as the amount the net book value exceeds the estimated fair value associated with the asset. We determined that there were no asset impairments in 2018, 2017 or 2016.
Income Taxes
We are not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income are generally borne by our partners through the allocation of taxable income. Our income tax expense results from partnership activity in the state of Texas, as conducted by Zydeco, Sand Dollar and Triton. Income tax expense for 2018, 2017 and 2016 was immaterial.
On December 22, 2017, the Tax Cuts and Jobs Act (the “TCJA”) was signed into law by President Trump. The TCJA makes broad and complex changes to the Internal Revenue Code of 1986, including, but not limited to, (1) creating a new deduction on certain pass-through income to individual partners; (2) repealing the partnership technical termination rule; (3) creating new limitations on certain deductions and credits, including interest expense deductions; and (4) reducing the highest marginal U.S. federal corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. With the exception of the operations of Colonial, Explorer and LOCAP, which are treated as corporations for federal income tax purposes, the operations of the Partnership are not subject to federal income tax, and therefore, the legislation did not have a material impact to the Partnership for 2018.
Other Investments
We account for equity investments in entities where we do not have control or significant influence at fair value with changes in fair value recognized in net income when the fair value is readily determinable. For investments without readily determinable fair values, we carry such investments at cost less impairments, if any. These investments are remeasured at fair value either upon the occurrence of an observable price change or upon identification of impairment. These investments are reported as Other investments in our consolidated balance sheets and dividends received are reported in Dividend income from other investments in our consolidated income statements. We have the following three equity investments which are accounted for at cost as they do not have readily determinable fair values:
86
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| December 31, 2018 | December 31, 2017 | ||||||||||||||||||||||
| Ownership | Amount | Ownership | Amount | ||||||||||||||||||||
| Colonial | 6.00 | % | $ | 11.4 | 6.00 | % | $ | 11.4 | |||||||||||||||
Explorer (1) | 12.62 | % | 48.6 | 12.62 | % | 48.6 | |||||||||||||||||
| Cleopatra | 1.00 | % | 2.1 | 1.00 | % | 2.1 | |||||||||||||||||
| $ | 62.1 | $ | 62.1 | ||||||||||||||||||||
(1) As part of the December 2017 Acquisition, our ownership in Explorer increased from 2.62% to 12.62% and we continued to account for this investment as a cost method investment as of December 31, 2018 and December 31, 2017. Our voting interest is in line with our percentage ownership and key governance issues pertaining to Explorer require a majority vote. Consequently, we do not control or exercise significant influence over Explorer.
During the year ended December 31, 2018 we did not identify the occurrence of an observable price change or an identification of impairment for these three equity investments.
Asset Retirement Obligations
Asset retirement obligations (“AROs”) represent contractual or regulatory obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. Our AROs were zero and $6.6 million, respectively, as of December 31, 2018 and 2017. The decrease in the ARO balance resulted from revisions to an ARO on the Odyssey pipeline.
Our assets include pipelines and terminals that have contractual or regulatory obligations that will need to be settled at retirement. The settlement date of these obligations will depend mostly on the various supply sources that connect to our systems and the ongoing demand for usage in the markets we serve. We expect these supply sources and market demands to continue for the foreseeable future. As the settlement dates of obligations are indeterminate, there is not sufficient information to make a reasonable estimate of the ARO of our remaining assets as of December 31, 2018 and 2017.
We continue to evaluate our AROs and future developments could impact the amounts we record.
Pensions and Other Postretirement Benefits
We do not have our own employees. Employees that work on our pipelines or terminal are employees of SPLC and we share employees with other SPLC-controlled and non-controlled entities. For presentation of these accompanying consolidated financial statements, our portion of payroll costs and employee benefit plan costs have been allocated as a charge to us by SPLC and Shell Oil Company. Shell Oil Company sponsors various employee pension and postretirement health and life insurance plans. For purposes of these accompanying consolidated financial statements, we are considered to be participating in the benefit plans of Shell Oil Company. We participate in the following defined benefits plans: Shell Oil Pension Plan, Shell Oil Retiree Health Care Plan, and Pennzoil-Quaker State Retiree Medical & Life Insurance. As a participant in these benefit plans, we recognize as expense in each period an allocation from Shell Oil Company, and we do not recognize any employee benefit plan assets or liabilities. See Note 5 — Related Party Transactions for total pension and benefit expenses under these plans.
Legal
We are subject to litigation and regulatory proceedings as the result of our business operations and transactions. We use both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. In general, we expense legal costs as incurred. When we identify specific litigation that is expected to continue for a significant period of time, is probable to occur and may require substantial expenditures, we identify a range of possible costs expected to be required to litigate the matter to a conclusion or reach an acceptable settlement, and we accrue for the most probable outcome. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected.
Environmental Matters
We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their economic benefit. We expense costs such as permits, compliance with existing environmental regulations, remedial investigations, soil sampling, testing and monitoring costs to meet applicable environmental laws and regulations where prudently incurred or determined to be reasonably possible in the ordinary course of business. We are permitted to recover such expenditures through tariff rates charged to customers. We also expense costs that relate to an existing
87
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
condition caused by past environmental incidents, which do not contribute to current or future revenue generation. We record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable.
For 2018, 2017 and 2016, we incurred $0.1 million, $0.4 million, and $0.1 million, respectively, of environmental cleanup costs. At both December 31, 2018 and 2017, we had accruals for $0.3 million for environmental clean-up costs pursuant to a Consent Decree issued in 1998 by the State of Washington Department of Ecology with respect to our products terminal located in Seattle, Washington. The costs relate to ongoing groundwater compliance monitoring and other remedial activities. Refer to Note 5 — Related Party Transactions under the Omnibus Agreement for additional details.
We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income statement in the period in which they are probable and reasonably estimable.
Other Contingencies
We recognize liabilities for other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the lower end of the range is accrued.
Fair Value Estimates
We measure assets and liabilities requiring fair value presentation or disclosure using an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability) and disclose such amounts according to the quality of valuation inputs under the following hierarchy:
Level 1: Quoted prices in an active market for identical assets or liabilities.
Level 2: Inputs other than quoted prices that are directly or indirectly observable.
Level 3: Unobservable inputs that are significant to the fair value of assets or liabilities.
We classify the fair value of an asset or liability based on the lowest level of input significant to its measurement. A fair value initially reported as Level 3 will be subsequently reported as Level 2 if the unobservable inputs become inconsequential to its measurement, or corroborating market data becomes available. Asset and liability fair values initially reported as Level 2 will be subsequently reported as Level 3 if corroborating market data becomes unavailable.
The carrying amounts of our accounts receivable, accounts payable, and accrued liabilities approximate their fair values due to their short-term nature.
Net income per limited partner unit
Net income per unit applicable to common limited partner units, and to subordinated limited partner units in periods prior to the expiration of the subordination period, is computed by dividing the respective limited partners’ interest in net income attributable to the partnership for the period by the weighted average number of common units and subordinated units, respectively, outstanding for the period. Because we have more than one class of participating securities, we use the two-class method when calculating the net income per unit applicable to limited partners. The classes of participating securities include common units, subordinated units, general partner units, and incentive distribution rights (“IDR’s”). Basic and diluted net income per unit are the same because we do not have any potentially dilutive units outstanding for the period presented.
Our net income includes earnings related to businesses acquired through transactions between entities under common control for periods prior to their acquisition by us. We have allocated these pre-acquisition earnings to our General Partner.
On February 15, 2017, all of the subordinated units converted into common units following the payment of the cash distribution for the fourth quarter of 2016. See Note 11 — (Deficit) Equity for additional information.
88
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Recent Accounting Pronouncements
Standards Adopted as of January 1, 2018
In May 2014, the FASB issued Accounting Standards Update (“ASU”) 2014-09 to Topic 606, Revenue from Contracts with Customers, which superseded revenue recognition guidance in Topic 605, Revenue Recognition, under GAAP. We adopted the new standard utilizing the modified retrospective transition approach, effective January 1, 2018, by recognizing the cumulative effect of initially applying the standard for periods prior to January 1, 2018 to the opening balance of (deficit) equity. See Note 3 — Revenue Recognition for additional information and disclosures required by the new standard.
Under the new standard, the adoption date for the majority of our equity method investments will follow the non-public business entity adoption date of January 1, 2019 for their stand-alone financial statements, with the exception of Mars and Permian Basin, which adopted on January 1, 2018. Accordingly, Amberjack will recognize a cumulative effect transition adjustment to equity of $18.9 million under the modified retrospective transition method as of January 1, 2019. The adjustment is related to its dedication and transportation agreements which contain tiered pricing arrangements resulting in a deferral of revenue. We will recognize our proportionate share of this Amberjack non-cash cumulative effect transition adjustment to decrease opening equity by $9.4 million at the transition date. The adoption of the new standard by our other equity method investments is not expected to be material.
In January 2017, the FASB issued ASU 2017-01 to Topic 805, Business Combinations, to clarify the definition of a business and to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This update was effective for us as of January 1, 2018. There was no impact on our financial statements as a result of this adoption in relation to our acquisition during the second quarter of 2018.
In August 2016, the FASB issued ASU 2016-15 to Topic 230, Statement of Cash Flows, making changes to the classification of certain cash receipts and cash payments in order to reduce diversity in presentation. The update addresses eight specific cash flow issues, of which only one is applicable to our financial statements. The applicable update relates to distributions received from equity method investees and prescribes two options for presenting these cash flows: cumulative earnings approach or nature of the distribution approach. We will continue to apply the cumulative earnings approach, where distributions received are considered either returns on investment and classified as operating cash flows or returns of investment and classified as investing cash flows. The adoption of this update on January 1, 2018 did not have a material impact on our financial statements.
In January 2016, the FASB issued ASU 2016-01 to Topic 825, Financial Instruments — Overall: Recognition and Measurement of Financial Assets and Financial Liabilities, requiring equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. Additionally, the update allows equity investments that do not have readily determinable fair values to be re-measured at fair value either upon the occurrence of an observable price change or upon identification of impairment, and requires additional disclosure around those investments. As these equity investments do not have readily determinable fair values, the adoption of this update on January 1, 2018 did not have a material impact on our financial statements.
Standards Not Adopted as of December 31, 2018
In February 2016, the FASB issued ASU 2016-02 to Topic 842, Leases, which requires lessees to recognize right-of-use assets and lease liabilities on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either a financing lease or operating lease with classification affecting the pattern of expense recognition in the consolidated statements of income and presentation of cash flows in the consolidated statements of cash flows. This update also requires improved disclosures to help users of financial statements better understand the amount, timing and uncertainty of cash flows arising from leases. For lessors, this update modifies the classification criteria and the accounting for sales-type and direct financing leases. This update is effective on a modified retrospective basis for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. We are adopting the new standard using the modified retrospective transition approach, effective January 1, 2019. We do not expect to recognize any cumulative effect of initially applying the standard for periods prior to January 1, 2019. We have completed the identification and aggregation of our lease contract population. We have also completed our review of these lease contracts to determine the transition approach as well as any necessary changes to existing processes and controls. The adoption will impact our consolidated financial statements and related disclosures as we will recognize right-of-use assets of approximately $4.7 million and corresponding lease liabilities for operating lease liabilities (where we are the lessee) of approximately $4.7 million. We do not expect an impact from adoption on our consolidated financial statements where we are the lessor.
89
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We will elect the practical expedients upon transition that will retain the lease classification and initial direct costs for any leases that exist prior to adoption. As such, we are not required to reassess whether any contracts entered into prior to adoption are leases. In January 2018, the FASB issued ASU 2018-01 to provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under existing guidance. We will elect this practical expedient. In July 2018, the FASB issued ASU 2018-11 which provides entities an optional transitional relief method that allows entities to not apply the new guidance in the comparative periods they present in their financial statements in the year of adoption. This update also provides an optional practical expedient for lessors to avoid separating lease and associated non-lease components within a contract if certain criteria are met. We will elect all these most recent practical expedients with the exception of the practical expedient to avoid separating lease and non-lease components within a contract and will continue to evaluate all other available transition practical expedients offered in connection with the new standard.
Under the new standard, the adoption date for our equity method investments will follow the non-public business entity adoption date of January 1, 2020 for their stand-alone financial statements.
In June 2016, the FASB issued ASU 2016-13 to Topic 326, Financial Instruments — Credit Losses: Measurement of Credit Losses on Financial Instruments, which replaces the current incurred loss impairment method with a method that reflects expected credit losses on financial instruments. The update is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted for fiscal years beginning after December 15, 2018. While we are still evaluating the impact of ASU 2016-13, we do not expect the adoption of this standard to have a material impact on our consolidated financial statements.
90
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. Revenue Recognition
Adoption of ASC Topic 606 “Revenue from Contracts with Customers”
On January 1, 2018, we adopted Topic 606 and all related ASU’s to this Topic (collectively, “the new revenue standard”) by applying the modified retrospective method to all contracts that were not completed on January 1, 2018. Results for reporting periods beginning after January 1, 2018 are presented in accordance with the new revenue standard, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting under previous GAAP.
We recorded a non-cash cumulative effect transition adjustment to increase opening equity by $4.6 million, with the impact primarily due to the earlier recognition of revenue related to deficiency payments under minimum volume commitment contracts. Additionally, we recorded a non-cash cumulative effect transition adjustment for $6.9 million related to our equity method investment for Mars. The Mars adjustment related to its transportation and dedication agreement and method of recognition as a stand-ready obligation which results in a deferral of the recognition of revenue over the life of the contract, whereas under previous GAAP, revenue was recognized upon physical delivery. See Note 6 - Equity Method Investments for additional information. These adjustments resulted in a total net decrease to our total opening equity of $2.3 million.
Revenue Recognition
The new revenue standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The new revenue standard requires entities to recognize revenue through the application of a five-step model, which includes: identification of the contract; identification of the performance obligations; determination of the transaction price; allocation of the transaction price to the performance obligations; and recognition of revenue as the entity satisfies the performance obligations.
Our revenues are primarily generated from the transportation, terminaling and storage of crude oil, refinery gas and refined petroleum products through our pipelines, terminals and storage tanks. To identify the performance obligations, we considered all the products or services promised in the contracts with customers, whether explicitly stated or implied based on customary business practices. Revenue is recognized when each performance obligation is satisfied under the terms of the contract.
Each barrel of product transported or day of services provided is considered a distinct service that represents a performance obligation that would be satisfied over time if it were accounted for separately. The services provided over the contract period are a series of distinct services that are substantially the same, have the same pattern of transfer to the customer, and therefore, qualify as a single performance obligation. Since the customer simultaneously receives and consumes the benefits of services, we recognize revenue over time based on a measure of progress of volumes transported for transportation services contracts or number of days elapsed for storage and terminaling services contracts.
Product revenue related to allowance oil sales is recognized at the point in time when the control of the oil transfers to the customer.
For all performance obligations, payment is typically due in full within 30 days of the invoice date.
Disaggregation of Revenue
The following table provides information about disaggregated revenue by service type and customer type:
91
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| 2018 | 2017 (1) | 2016 (1) | ||||||||||||||||||
| Transportation services revenue – third parties | $ | 200.9 | $ | 226.9 | $ | 242.9 | ||||||||||||||
Transportation services revenue – related parties (2) | 176.1 | 172.2 | 179.7 | |||||||||||||||||
| Total transportation services revenue | 377.0 | 399.1 | 422.6 | |||||||||||||||||
| Storage services revenue – third parties | 8.5 | 8.7 | 8.6 | |||||||||||||||||
| Storage services revenue – related parties | 6.7 | 6.0 | 8.6 | |||||||||||||||||
| Total storage services revenue | 15.2 | 14.7 | 17.2 | |||||||||||||||||
| Terminaling services revenue – third parties | — | — | — | |||||||||||||||||
| Terminaling services revenue – related parties | 45.7 | — | — | |||||||||||||||||
Total terminaling services revenue (3) | 45.7 | — | — | |||||||||||||||||
| Product revenue – third parties | 2.2 | — | — | |||||||||||||||||
| Product revenue – related parties | 28.5 | — | — | |||||||||||||||||
Total product revenue (4) | 30.7 | — | — | |||||||||||||||||
| Total Topic 606 revenue | 468.6 | N/A | N/A | |||||||||||||||||
| Lease revenue – related parties | 56.1 | 56.3 | 13.1 | |||||||||||||||||
| Total revenue | $ | 524.7 | $ | 470.1 | $ | 452.9 | ||||||||||||||
(1) As noted above, prior period amounts have not been adjusted under the modified retrospective method.
(2) Transportation services revenue — related parties for 2018 includes $4.7 million of non-lease component in our transportation services contract.
(3) Terminaling services revenue for 2018 is entirely comprised of the non-lease service component in our terminaling services contracts.
(4) Product revenue for 2018 is comprised of allowance oil sales.
Transportation services revenue
We have both long-term transportation contracts and month-to-month contracts for spot shippers that make nominations on our pipelines. Some of the long-term contracts entitle the customer to a specified amount of guaranteed capacity on the pipeline. Transportation services are charged at a per barrel rate or other applicable unit of measure. We apply the allocation exception guidance for variable consideration related to market indexing for long-term transportation contracts because (a) the variable payment relates specifically to our efforts to transfer the distinct service and (b) we allocate the variable amount of consideration entirely to the distinct service which is consistent with the allocation objective. Except for guaranteed capacity payments as discussed below, transportation services are billed monthly as services are rendered.
Our contracts and tariffs contain terms for the customer to reimburse us for losses from evaporation or other loss in transit in the form of allowance oil. Allowance oil represents the net difference between the tariff PLA volumes and the actual volumetric losses. We obtain control of the excess oil not lost during transportation, if any. Under the new revenue standard, we include the excess oil retained during the period, if any, as non-cash consideration and include this amount in the transaction price for transportation services on a net basis. Our allowance oil is valued at the lower of cost or net realizable value using the average market price of the relevant type of crude oil during the month product was transported. Gains from pipeline operations that relate to allowance oil are recorded in Operations and maintenance expenses in the accompanying consolidated statements of income.
As a result of FERC regulations, revenues we collect may be subject to refund. We establish reserves for these potential refunds based on actual expected refund amounts on the specific facts and circumstances. We had no reserves for potential refunds as of December 31, 2018 and 2017.
Deferred revenue
Our FERC-approved transportation services agreements on Zydeco entitle the customer to a specified amount of guaranteed capacity on the pipeline. This capacity cannot be pro-rated even if the pipeline is oversubscribed. In exchange, the customer
92
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
makes a specified monthly payment regardless of the volume transported. If the customer does not ship its full guaranteed volume in a given month, it makes the full monthly cash payment (i.e., deficiency payments) and it may ship the unused volume in a later month for no additional cash payment for up to 12 months, subject to availability on the pipeline. The cash payment received is recognized as deferred revenue, a contract liability under the new revenue standard. If there is insufficient capacity on the pipeline to allow the unused volume to be shipped, the customer forfeits its right to ship such unused volume. We do not refund any cash payments relating to unused volumes.
Prior to January 1, 2018, deferred revenue under these arrangements was previously recognized into revenue once all contingencies or potential performance obligations associated with the related volumes had been satisfied or expired. Under the new revenue standard, we are required to estimate the likelihood that unused volumes will be shipped or forfeited at each reporting period based on additional data that becomes available and only to the extent that it is probable that a significant reversal of revenue will not occur. In some cases, this estimate could result in the earlier recognition of revenue.
Storage and terminaling services revenue
Storage and terminaling services are provided under short-term and long-term contracts, with a fixed price per month for committed storage and terminaling capacity, or under a monthly spot-rate for uncommitted storage or terminaling. Since the customer simultaneously receives and consumes the benefits of services, we recognize revenue over time based on the number of days elapsed. We apply the allocation exception guidance for variable consideration related to market indexing for long-term contracts because (a) the variable payment relates specifically to our efforts to transfer the distinct service and (b) we allocate the variable amount of consideration entirely to the distinct service which is consistent with the allocation objective. Storage and terminaling services are billed monthly as services are rendered.
Reimbursements from customers
Under certain transportation, terminaling and storage service contracts, we receive reimbursements from customers to recover costs of construction, maintenance or operating costs either under a tariff surcharge per volume shipped or under separate reimbursement payments. Because we consider these amounts as consideration from customers associated with ongoing services to be provided to customers, we defer these payments in deferred revenue and recognize amounts in revenue over the life of the associated revenue contract as performance obligations are satisfied under the contract. We consider these payments to be revenue because control of the long-lived assets does not transfer to our customer upon completion. Our financial statements were not materially impacted by adoption of the new revenue standard related to reimbursements from customers.
Lease revenue
Certain of our long-term transportation and terminaling services contracts with related parties are accounted for as operating leases under Topic 840, Leases. These agreements have both a lease component and an implied operation and maintenance service component (“non-lease service component”). We allocate the arrangement consideration between the lease components that fall within the scope of Topic 840 and any non-lease service components within the scope of the new revenue standard based on the relative stand-alone selling price of each component. We estimate the stand-alone selling price of the lease and non-lease service components based on an analysis of service-related and lease-related costs for each contract, adjusted for a representative profit margin. The contracts have a minimum fixed monthly payment for both the lease and non-lease service components. We present the non-lease service components under the new revenue standard within Transportation, terminaling and storage services – related parties in the consolidated statement of income.
Revenues from the lease components of these agreements are recorded within Lease revenue – related parties in the consolidated statement of income. Certain of these agreements were each entered into for terms of ten years, with the option to extend for two additional five year terms and we have additional agreements with an initial term of ten years with the option to extend for up to ten additional one-year terms. As of December 31, 2018, future minimum payments to be received under the ten-year contract term of these operating leases were estimated to be:
| Total | Less than 1 year | Years 2 to 3 | Years 4 to 5 | More than 5 years | ||||||||||||||||||||||||||||
| Operating leases | $ | 933.4 | $ | 107.7 | $ | 215.5 | $ | 215.5 | $ | 394.7 | ||||||||||||||||||||||
Product revenue
We generate revenue by selling accumulated allowance oil inventory to customers. Sale of allowance oil is recorded as product revenue, with specific cost based on a weighted average price per barrel recorded as cost of product sold.
93
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Prior to the adoption of the new revenue standard, allowance oil received was recorded as revenue on a gross basis with the resulting actual gain or loss recorded in operations and maintenance expenses. The subsequent sale of allowance oil, net of the product cost, was recorded as operations and maintenance expenses.
Joint tariff
Under a certain joint tariff, revenues were historically recorded on a net basis as an agent prior to the adoption of the new revenue standard. However, subsequent to the adoption of the new revenue standard, because we control the transportation service before it is transferred to the customer, we are the principal and, therefore, record revenues from these agreements on a gross basis within Transportation, terminaling and storage services – third parties or related parties.
Impact of adoption
In accordance with the new revenue standard, the following tables summarize the impact of adoption on our consolidated financial statements as of and for the year ended December 31, 2018:
| 2018 | ||||||||||||||||||||
| Consolidated Statement of Income | As Reported Under Topic 606 | Amounts Without Adoption of Topic 606 | Effect of Change Increase/(Decrease) | |||||||||||||||||
| Revenue | ||||||||||||||||||||
| Transportation, terminaling and storage services – third parties | $ | 209.4 | $ | 209.2 | $ | 0.2 | ||||||||||||||
| Transportation, terminaling and storage services – related parties | 228.5 | 183.4 | 45.1 | |||||||||||||||||
| Product revenue – third parties | 2.2 | — | 2.2 | |||||||||||||||||
| Product revenue – related parties | 28.5 | — | 28.5 | |||||||||||||||||
| Lease revenue – related parties | 56.1 | 106.5 | (50.4) | |||||||||||||||||
| Costs and expenses | ||||||||||||||||||||
| Operations and maintenance – third parties | 107.5 | 112.1 | (4.6) | |||||||||||||||||
| Operations and maintenance – related parties | 54.4 | 46.8 | 7.6 | |||||||||||||||||
| Cost of product sold – third parties | 7.4 | 5.5 | 1.9 | |||||||||||||||||
| Cost of product sold – related parties | 25.3 | — | 25.3 | |||||||||||||||||
| Net income | $ | 482.4 | $ | 487.0 | $ | (4.6) | ||||||||||||||
| December 31, 2018 | ||||||||||||||||||||
| Consolidated Balance Sheet | As Reported Under Topic 606 | Amounts Without Adoption of Topic 606 | Effect of Change Increase/(Decrease) | |||||||||||||||||
| Deferred revenue – related party | $ | 2.6 | $ | 2.5 | $ | 0.1 | ||||||||||||||
Contract Balances
We perform our obligations under a contract with a customer by providing services in exchange for consideration from the customer. The timing of our performance may differ from the timing of the customer’s payment, which results in the recognition of a contract asset or a contract liability. Although we did not have any contract assets as of December 31, 2018, we recognize a contract asset when we transfer goods or services to a customer and contractually bill an amount which is less than the revenue allocated to the related performance obligation. We recognize deferred revenue (contract liability) when the customer’s payment of consideration precedes our performance. The following table provides information about receivables and contract liabilities from contracts with customers:
| January 1, 2018 | December 31, 2018 | |||||||||||||
| Receivables from contracts with customers – third parties | $ | 17.2 | $ | 18.8 | ||||||||||
| Receivables from contracts with customers – related parties | 18.8 | 21.4 | ||||||||||||
| Deferred revenue – third parties | 5.5 | 8.0 | ||||||||||||
| Deferred revenue – related party | 9.4 | 2.6 | ||||||||||||
94
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Significant changes in the deferred revenue balances with customers during the period are as follows:
| December 31, 2017 | Transition Adjustment | Additions (1) | Reductions (2) | December 31, 2018 | ||||||||||||||||||||||||||||
| Deferred revenue – third parties | $ | 5.5 | $ | — | $ | 10.0 | $ | (7.5) | $ | 8.0 | ||||||||||||||||||||||
| Deferred revenue – related party | 13.9 | (4.5) | 3.1 | (9.9) | 2.6 | |||||||||||||||||||||||||||
(1) Contract liability additions resulted from deficiency payments from minimum volume commitment contracts.
(2) Contract liability reductions resulted from revenue earned through the actual or estimated use and expiration of deficiency credits.
We currently have no assets recognized from the costs to obtain or fulfill a contract as of December 31, 2018.
Remaining Performance Obligations
As of December 31, 2018, contracts with remaining performance obligations primarily include minimum volume commitment contracts, long-term storage contracts and the service component of transportation and terminaling services contracts accounted for as operating leases.
The following table includes revenue expected to be recognized in the future related to performance obligations exceeding one year of their initial terms that are unsatisfied or partially unsatisfied as of December 31, 2018:
| Total | 2019 | 2020 | 2021 | 2022 | 2023 and beyond | |||||||||||||||||||||||||||||||||
Revenue expected to be recognized on multi-year committed shipper transportation contracts (1) | $ | 539.9 | $ | 64.3 | $ | 50.1 | $ | 49.8 | $ | 49.8 | $ | 325.9 | ||||||||||||||||||||||||||
Revenue expected to be recognized on other multi-year transportation service contracts (2) | 45.0 | 5.4 | 5.4 | 5.4 | 5.4 | 23.4 | ||||||||||||||||||||||||||||||||
| Revenue expected to be recognized on multi-year storage service contracts | 4.0 | 4.0 | — | — | — | — | ||||||||||||||||||||||||||||||||
Revenue expected to be recognized on multi-year terminaling service contracts (2) | 416.3 | 46.7 | 46.7 | 46.7 | 46.7 | 229.5 | ||||||||||||||||||||||||||||||||
| Total | $ | 1,005.2 | $ | 120.4 | $ | 102.2 | $ | 101.9 | $ | 101.9 | $ | 578.8 | ||||||||||||||||||||||||||
(1) Excludes revenue deferred for deficiency payments.
(2) Relates to the non-lease service components of certain of our long-term transportation and terminaling service contracts which are accounted for as operating leases.
As an exemption, we do not disclose the amount of remaining performance obligations for contracts with an original expected duration of one year or less or for variable consideration that is allocated entirely to a wholly unsatisfied promise to transfer a distinct service that forms part of a single performance obligation.
95
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. Acquisitions and Divestiture
2018 Acquisition
On May 11, 2018, we acquired SPLC’s ownership interests in Amberjack Pipeline Company LLC, a Delaware limited liability company (“Amberjack”), which is comprised of 75% of the issued and outstanding Series A membership interests of Amberjack and 50% of the issued and outstanding Series B membership interests of Amberjack for $1,220.0 million (the “May 2018 Acquisition”). The May 2018 Acquisition closed pursuant to a Purchase and Sale Agreement dated May 9, 2018 (the “May 2018 Purchase and Sale Agreement”) between us and SPLC, and is accounted for as a transaction between entities under common control on a prospective basis as an asset acquisition. We acquired historical carrying value of net assets under common control of $481.6 million which is included in Equity method investments in our consolidated balance sheet. We recognized $738.4 million of consideration in excess of the historical carrying value of net assets acquired as a capital distribution to our general partner in accordance with our policy for common control transactions. We funded the May 2018 Acquisition with $494.0 million in borrowings under our Five Year Revolver due July 2023 (as defined in Note 9—Related Party Debt) and $726.0 million in borrowings under our Five Year Revolver due December 2022 (as defined in Note 9—Related Party Debt).
2017 Acquisitions
During 2017, we completed three acquisitions, each as described below. Of these, the December 2017 Acquisition and the May 2017 Acquisition were considered transfers of businesses between entities under common control, and therefore the related acquired assets and liabilities were transferred at historical carrying value. Because these acquisitions were common control transactions in which we acquired businesses, our historical financial statements were recast for the periods of our Parent’s ownership prior to the transactions.
December 2017 Acquisition
On December 1, 2017, we acquired a 100% interest in Triton, 41.48% of the issued and outstanding membership interest in LOCAP, an additional 22.9% interest in Mars, an additional 22.0% interest in Odyssey, and an additional 10.0% interest in Explorer from SPLC and SOPUS for $825.0 million in cash (the “December 2017 Acquisition”). As part of the December 2017 Acquisition, SOPUS contributed all but the working capital and certain environmental liabilities of Triton. The December 2017 Acquisition closed pursuant to a Purchase and Sale Agreement (the “December 2017 Purchase and Sale Agreement”) among the Operating Company, us, SPLC and SOPUS. SPLC and SOPUS are each wholly owned subsidiaries of Shell. We funded the cash consideration for the December 2017 Acquisition from $825.0 million in borrowings under the Five Year Revolver due December 2022 (as defined in Note 9—Related Party Debt) and the Five Year Fixed Facility (as defined in Note 9—Related Party Debt). Total transaction costs of $0.6 million were expensed as incurred. The terms of the December 2017 Acquisition were approved by the Board of Directors of our general partner (the “Board”) and by the conflicts committee of the Board, which consists entirely of independent directors. The conflicts committee engaged an independent financial advisor and legal counsel.
In connection with the December 2017 Acquisition we acquired the following:
Cost investment (1) | $ | 22.3 | |||
Equity method investments (2) | 76.1 | ||||
Property, plant and equipment, net (3) | 118.2 | ||||
Partners’ capital (4) | 3.2 | ||||
| December 2017 Acquisition | $ | 219.8 | |||
(1) Book Value of an additional 10.0% interest in Explorer contributed by SPLC.
(2) Book Value of an additional 22.9% interest in Mars and a 41.48% interest in LOCAP contributed by SPLC.
(3) Book Value of a 100.0% interest in the historical carrying value of property, plant and equipment, net contributed by SOPUS.
(4) Book Value of an additional 22.0% interest in Odyssey contributed by SOPUS.
We recognized $605.2 million of consideration in excess of the book value of net assets acquired as a capital distribution to our general partner in accordance with our policy for common control transactions. For the period from closing through December 31, 2017, we recognized $7.7 million in revenues and $18.8 million of net earnings related to this acquisition.
October 2017 Acquisition
96
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On October 17, 2017, we acquired a 50.0% interest in Crestwood Permian Basin LLC (“Permian Basin”), which owns the Nautilus gathering system in the Permian Basin, for $49.9 million consideration and initial capital contributions (the “October 2017 Acquisition”). The October 2017 Acquisition closed pursuant to a Member Interest Purchase Agreement dated October 16, 2017 (the “October 2017 Purchase Agreement”), among the Operating Company and CPB Member LLC (a jointly owned subsidiary of Crestwood Equity Partners LP and First Reserve). We have determined we have significant influence over the financial and operating policies of Permian Basin and we therefore account for this investment under the equity method. We funded the October 2017 Acquisition with cash on hand. The terms of the October 2017 Acquisition were approved by the Board.
May 2017 Acquisition
On May 10, 2017, we acquired a 100% interest in Delta, Na Kika and Refinery Gas Pipeline for $630.0 million in consideration (the “May 2017 Acquisition”). As part of the May 2017 Acquisition, SPLC and Shell GOM Pipeline Company LP (“Shell GOM”) contributed all but the working capital of Delta and Na Kika to Pecten, and Shell Chemical LP (“Shell Chemical”) contributed all but the working capital of Refinery Gas Pipeline to Sand Dollar. The May 2017 Acquisition closed pursuant to a Purchase and Sale Agreement dated May 4, 2017 (the “May 2017 Purchase and Sale Agreement”), among the Operating Company, us, Shell Chemical, Shell GOM and SPLC. Shell Chemical, Shell GOM and SPLC are each wholly owned subsidiaries of Shell. We funded the May 2017 Acquisition with $50.0 million of cash on hand, $73.1 million in borrowings under our Year Revolver due July 2023 (as defined in Note 9 — Related Party Debt), and $506.9 million in borrowings under our Year Fixed Facility (as defined in Note 9 — Related Party Debt). Total transaction costs of $0.8 million were expensed as incurred. The terms of the May 2017 Acquisition were approved by the Board and by the conflicts committee of the Board, which consists entirely of independent directors. The conflicts committee engaged an independent financial advisor and legal counsel. In accordance with the May 2017 Purchase and Sale Agreement, Shell Chemical has agreed to reimburse us for costs and expenses incurred in connection with the conversion of a section of pipe from the Convent refinery to Sorrento from refinery gas service to butane service. The May 2017 Purchase and Sale Agreement contains other customary representations, warranties and covenants.
In connection with the May 2017 Purchase and Sale Agreement, we granted Shell Chemical a purchase option and right of first refusal with respect to Refinery Gas Pipeline and certain other related assets and the ownership interests in Sand Dollar. The purchase option may be triggered by, among other things, (i) a third party obtaining the right to use any or all of Refinery Gas Pipeline; (ii) the loss of all volume on Refinery Gas Pipeline that would result in it being permanently shutdown for years or more; (iii) the termination of a transportation services agreement between Shell Chemical and Sand Dollar (“Refinery Gas Pipeline Agreement”); (iv) the expiration of the term of the Refinery Gas Pipeline Agreement; or (v) a change of control of our general partner; provided, however, that in the case of (i) through (iv), the purchase option would only be applicable to the Refinery Gas Pipeline impacted by such event. In addition, in the event that Sand Dollar receives an offer to sell all or a portion of Refinery Gas Pipeline or the ownership interests in Sand Dollar from a third party, Shell Chemical has a right of first refusal with respect to such Refinery Gas Pipeline or ownership interests, as applicable, for so long as the Refinery Gas Pipeline Agreement between Shell Chemical and Sand Dollar is in effect.
In connection with the May 2017 Acquisition we acquired historical carrying value of property, plant and equipment, net and other assets under common control as follows:
| Delta | $ | 40.1 | |||
| Na Kika | 26.0 | ||||
| Refinery Gas Pipeline | 134.6 | ||||
| May 2017 Acquisition | $ | 200.7 | |||
We recognized $429.3 million of consideration in excess of the book value of net assets acquired as a capital distribution to our general partner in accordance with our policy for common control transactions. For the period from closing through December 31, 2017, we recognized $63.8 million in revenues and $29.3 million of net earnings related to this acquisition.
2017 Divestiture
On April 28, 2017, Zydeco divested a small segment of its pipeline system (the “April 2017 Divestiture”) to SOPUS as part of the Motiva JV separation. The April 2017 Divestiture closed pursuant to a Pipeline Sale and Purchase Agreement (the “April 2017 Pipeline Sale and Purchase Agreement”) dated April 28, 2017 among Zydeco and SOPUS. We received $21.0 million in cash consideration for this sale, of which $19.4 million is attributable to the Partnership. The cash consideration represents $0.8
97
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
million for the book value of net assets divested, and $20.2 million in excess proceeds received from our Parent. The April 2017 Pipeline Sale and Purchase Agreement contained customary representations and warranties and indemnification by SOPUS.
2016 Acquisitions
On December 27, 2016, we acquired the following: (a) a 10.0% interest in Endymion from Mardi Gras Endymion Oil Pipeline Company, LLC, (b) a 10.0% interest in Proteus from Mardi Gras Transportation System Inc. (“Mardi Gras”) and (c) a 1.0% interest in Cleopatra from Mardi Gras. Each acquisition closed pursuant to their respective purchase agreements for an aggregate purchase price of $42.0 million (the “December 2016 Acquisition”). We have determined we have significant influence over the financial and operating policies of Proteus and Endymion and we therefore account for these investments under the equity method. We do not have control or significant influence over Cleopatra and therefore account for this investment under the cost method. We funded the December 2016 Acquisition with borrowings under the Year Revolver due July 2023 (as defined in Note 9 — Related Party Debt). The terms of the December 2016 Acquisition were approved by the Board.
In connection with the December 2016 Acquisition we acquired the following:
Cost investments (1) | $ | 2.1 | |||
Equity method investments (2) | 39.9 | ||||
December 2016 Acquisition | $ | 42.0 | |||
(1) $2.1 million purchase price of 1.0% in Cleopatra.
(2) $20.8 million purchase price of 10.0% in Endymion and $19.1 million purchase price of 10.0% interest in Proteus.
On October 3, 2016, we acquired a 49.0% interest in Odyssey from Shell Oil Products US (“SOPUS”) and an additional 20.0% interest in Mars from SPLC for $350.0 million (the “October 2016 Acquisition”). The October 2016 Acquisition closed pursuant to a purchase and sale agreement dated September 27, 2016 (“Odyssey and Mars Purchase and Sale Agreement”) among us, the Operating Company, SPLC and SOPUS, and is accounted for as a transaction between entities under common control on a prospective basis as an asset acquisition. We funded the October 2016 Acquisition with $50.0 million of cash on hand and $300.0 million in borrowings under the Year Revolver due July 2023 (as defined in Note 9—Related Party Debt) with STCW, an affiliate of Shell. The terms of the October 2016 Acquisition were approved by the Board and by the conflicts committee of the Board, which consists entirely of independent directors. The conflicts committee engaged an independent financial advisor and legal counsel. In accordance with the Odyssey and Mars Purchase and Sale Agreement, SPLC has agreed to pay us up to $10.0 million if Mars inventory management fees do not meet certain levels in aggregate for the calendar years ending 2017 through 2021. At this time there is no estimate of the amount, if any, to be received.
In connection with the October 2016 Acquisition, we acquired net assets under common control and recorded at their historical carrying value as follows:
Equity method investments (1) (2) | $ | 54.3 | |||
| October 2016 Acquisition | $ | 54.3 | |||
(1) $51.3 million historical carrying value of 20.0% additional interest in Mars contributed by SPLC.
(2) $3.0 million historical carrying value of 49.0% interest in Odyssey contributed by SOPUS.
On August 9, 2016, we acquired a 2.62% equity interest in Explorer from SPLC (the “August 2016 Acquisition”) for $26.2 million. The August 2016 Acquisition was made in connection with SPLC’s right, as a current shareholder of Explorer, to acquire a portion of the equity interest being divested by another shareholder of Explorer. At that time SPLC separately owned a 35.97% equity interest in Explorer. The August 2016 Acquisition closed on August 9, 2016 pursuant to a Share Purchase and Sale Agreement among us, the Operating Company and SPLC, and is accounted for as a transaction between entities under common control on a prospective basis as an asset acquisition. We funded the August 2016 Acquisition with $26.3 million of cash on hand. Total transaction costs of $0.1 million were incurred. The terms of the August 2016 Acquisition were approved by the Board.
On May 23, 2016, we acquired an additional 30.0% interest in Zydeco, an additional 1.0% interest in Bengal and an additional 3.0% interest in Colonial for $700.0 million in consideration (the “May 2016 Acquisition”). The May 2016 Acquisition closed pursuant to a Contribution Agreement (the “May 2016 Contribution Agreement”) dated May 17, 2016 among us, the Operating Company and SPLC and became effective on April 1, 2016, and is accounted for as a transaction between entities under common control on a prospective basis as an asset acquisition. We funded the May 2016 Acquisition with $345.8 million from
98
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the net proceeds of a registered public offering of 10,500,000 common units representing limited partner interests in us (the “May 2016 Offering”), $50.4 million of cash on hand and $296.7 million in borrowings under the Year Revolver due July 2023 (as defined in Note 9—Related Party Debt) with STCW, an affiliate of Shell. The remaining $7.1 million in consideration consisted of an issuance of 214,285 general partner units to our general partner in order to maintain its 2% general partner interest in us. Total transaction costs of $0.4 million were incurred in association with the May 2016 Acquisition. The terms of the May 2016 Acquisition were approved by the Board and by the conflicts committee of the Board, which consists entirely of independent directors. The conflicts committee engaged an independent financial advisor and legal counsel. In accordance with the May 2016 Contribution Agreement, SPLC has agreed to reimburse us for our proportionate share of certain costs and expenses incurred by Zydeco after April 1, 2016 with respect to a directional drill project to address soil erosion over a two-mile section of our 22-inch diameter pipeline under the Atchafalaya River and Bayou Shaffer in Louisiana. Such reimbursements will be treated as an additional capital contribution from the general partner at the time of counter party payment. The May 2016 Contribution Agreement contained customary representations and warranties and indemnification by SPLC.
In connection with the May 2016 Acquisition, we acquired historical carrying value of net assets under common control as follows:
Cost investments (1) | $ | 5.2 | |||
Equity method investments (2) | 1.5 | ||||
Partners’ capital (3) | 87.0 | ||||
| May 2016 Acquisition | $ | 93.7 | |||
(1) Book value of 3.0% additional interest in Colonial contributed by SPLC.
(2) Book value of 1.0% additional interest in Bengal contributed by SPLC.
(3) Book value of 30.0% additional interest in Zydeco from SPLC’s noncontrolling interest.
We recognized $606.3 million of consideration in excess of the historical carrying value of net assets acquired as a capital distribution to our general partner in accordance with our policy for common control transactions. This capital distribution is comprised of $599.2 million in cash and $7.1 million in general partner units issued.
5. Related Party Transactions
Related party transactions include transactions with SPLC and Shell, including those entities in which Shell has an ownership interest but does not have control.
Acquisition Agreements
Refer to Note 4 — Acquisitions and Divestiture for a description of applicable agreements.
Omnibus Agreement
On November 3, 2014, we entered into an Omnibus Agreement with SPLC and our general partner concerning our payment of an annual general and administrative services fee to SPLC as well as our reimbursement of certain costs incurred by SPLC on our behalf. This agreement addresses the following matters:
•our payment of an annual general and administrative fee of $8.5 million for the provision of certain services by SPLC;
•our obligation to reimburse SPLC for certain direct or allocated costs and expenses incurred by SPLC on our behalf;
•our obligation to reimburse SPLC for all expenses incurred by SPLC as a result of us becoming and continuing as a publicly traded entity; we will reimburse our general partner for these expenses to the extent the fees relating to such services are not included in the general and administrative fee; and
•the granting of a license from Shell to us with respect to the use of certain Shell trademarks and trade names.
Under the Omnibus Agreement, SPLC indemnified us against certain enumerated risks. Of those two indemnity obligations, one expired in 2017 and one remains. Under the remaining indemnification, SPLC agreed to indemnify us against tax liabilities relating to our initial assets that are identified prior to the date that is 60 days after the expiration of the statute of limitations applicable to such liabilities. This obligation has no threshold or cap. We in turn agreed to indemnify SPLC against events and conditions associated with the ownership or operation of our initial assets (other than any liabilities against which SPLC is specifically required to indemnify us as described above).
99
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
During 2018 and 2017, neither we nor SPLC made any claims for indemnification under the Omnibus Agreement. On February 19, 2019, we, our general partner, SPLC, Shell Midstream Operating LLC and Shell Oil Company terminated the Omnibus Agreement effective as of February 1, 2019, and we, our general partner, SPLC and Shell Midstream Operating LLC entered into a new Omnibus Agreement effective February 1, 2019. In addition, we, our general partner and SPLC entered into a Trade Marks License Agreement with Shell Trademark Management Inc. effective as of February 1, 2019. Refer to Note 15 — Subsequent Events for additional information.
Tax Sharing Agreement
We have entered into a tax sharing agreement with Shell. Pursuant to this agreement, we have agreed to reimburse Shell for state and local income and franchise taxes attributable to any activity of our operating subsidiaries, and reported on Shell’s state or local income or franchise tax returns filed on a combined or unitary basis. Reimbursements under this agreement equal the amount of tax our applicable operating subsidiaries would be required to pay with respect to such activity, if such subsidiaries were to file a combined or unitary tax return separate from Shell. Shell will compute and invoice us for the tax reimbursement amount within 15 days of Shell filing its combined or unitary tax return on which such activity is included. We may be required to make prepayments toward the tax reimbursement amount to the extent that Shell is required to make estimated tax payments during the relevant tax year. The tax sharing agreement currently in place is effective for all taxable periods ending on or after December 31, 2017. The current agreement replaced a similar tax sharing agreement between Zydeco and Shell, which was effective for all tax periods ending before December 31, 2017. Reimbursements for tax years ended December 31, 2018, 2017 and 2016 were not material to our consolidated statements of income.
Other Agreements
In connection with the Initial Public Offering (“IPO”) and our acquisitions from Shell, we have entered into several customary agreements with SPLC and Shell. These agreements include pipeline operating agreements, reimbursement agreements and services agreements.
Pecten Contribution Agreement
Maintenance expense and capital expenditures for certain projects associated with the Lockport Terminal have been incurred. Under the Pecten Contribution Agreement entered into in connection with the acquisition in November 2015, SPLC has agreed to reimburse us for the maintenance expense and capital expenditures related to these projects. During 2018 and 2017, we recognized no reimbursement as other contributions from Parent, and in 2016 we recognized $1.6 million for these reimbursements as other contributions from Parent.
Operating Agreements
In connection with the formation of Pecten on October 1, 2015, Pecten entered into an operating and administrative management agreement with SPLC. Pursuant to this agreement, SPLC performs physical operations and maintenance services for Lockport and Auger and provides general and administrative services for Pecten. Pecten is required to reimburse SPLC for costs and expenses incurred in connection with such services. Also pursuant to the agreement, SPLC and Pecten agree to standard indemnifications as operator and asset owner, respectively.
In connection with the May 2017 Acquisition, on May 10, 2017, SPLC entered into an operating and administrative management agreement with Sand Dollar. Sand Dollar is allocated and required to reimburse SPLC for certain costs in connection with the services provided pursuant to the agreement. Also pursuant to the agreement, SPLC and Sand Dollar agree to standard indemnifications as operator and asset owner, respectively.
On December 1, 2017, our general partner, SPLC and Triton entered into an operating and administrative management agreement. Our general partner provides certain operational and support services pursuant to the agreement. The necessary personnel are employed by SPLC and are assigned to our general partner. Triton West is allocated certain costs by the general partner in connection with the services provided pursuant to the agreement. Our general partner reimburses SPLC for certain costs related to the assigned personnel. Our general partner, SPLC and Triton West each provide standard indemnifications as operator, employer and asset owner, respectively.
In connection with the December 2017 Acquisition, we were assigned an operating agreement for Odyssey, whereby SPLC performs physical operations and maintenance services and provides general and administrative services for Odyssey. Odyssey is required to reimburse SPLC for costs and expenses incurred in connection with such services. Also pursuant to the agreement, SPLC and Odyssey agree to standard indemnifications as operator and asset owner, respectively.
100
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Partnership Agreement
On December 21, 2018, we executed Amendment No. 2 (the “Second Amendment”) to the Partnership’s First Amended and Restated Agreement of Limited Partnership dated November 3, 2014. Under the Second Amendment, our sponsor agreed to waive $50.0 million of distributions in 2019 by agreeing to reduce distributions to holders of the incentive distribution rights by: (1) $17.0 million for the three months ending March 31, 2019, (2) $17.0 million for the three months ending June 30, 2019 and (3) $16.0 million for the three months ending September 30, 2019.
Noncontrolling Interests
For Zydeco, noncontrolling interest consists of SPLC’s 7.5% retained ownership interest as of December 31, 2018, 2017 and 2016. For Odyssey, noncontrolling interest consists of GEL Offshore Pipeline LLC’s (“GEL”) 29.0% retained ownership interest as of December 31, 2018, 2017 and 2016.
Other Related Party Balances
Other related party balances consist of the following:
| December 31, | |||||||||||
| 2018 | 2017 | ||||||||||
| Accounts receivable | $ | 28.7 | $ | 23.8 | |||||||
| Prepaid expenses | 14.9 | 11.9 | |||||||||
| Other assets | 2.5 | 1.7 | |||||||||
Accounts payable (1) | 8.9 | 11.6 | |||||||||
| Deferred revenue | 2.6 | 13.9 | |||||||||
Accrued liabilities (2) | 15.7 | 7.2 | |||||||||
Debt payable (3) | 2,090.7 | 1,844.0 | |||||||||
(1) Accounts payable reflects amounts owed to SPLC for reimbursement of third-party expenses incurred by SPLC for our benefit.
(2) As of December 31, 2018, Accrued liabilities reflects $14.3 million accrued interest and $1.4 million other accrued liabilities. As of December 31, 2017, Accrued liabilities reflects $6.6 million accrued interest and $0.6 million other accrued liabilities.
(3) Debt payable reflects borrowings outstanding net of unamortized debt issuance costs of $3.3 million and $2.9 million as of December 31, 2018 and 2017, respectively.
Related Party Credit Facilities
We have entered into four credit facilities with STCW: the Year Fixed Facility, the Year Revolver due July 2023, the Year Revolver due December 2022 and the Year Fixed Facility. Zydeco has also entered into the Zydeco Revolver with STCW. See Note 9 – Related Party Debt for definitions and additional information regarding these credit facilities.
Related Party Revenues and Expenses
We provide crude oil transportation, terminaling and storage services to related parties under long-term contracts. We entered into these contracts in the normal course of our business. Our transportation, terminaling and storage services revenue and lease revenue from related parties for 2018, 2017 and 2016 is disclosed in Note 3 – Revenue Recognition.
In 2018, 2017 and 2016, we converted excess allowance oil to cash through sales to affiliates of Shell of $3.2 million, $1.3 million and $1.3 million, respectively. In 2018, upon the adoption of the new revenue standard, we include the revenue in Product revenue – related parties and the cost in Cost of product sold – related parties. In 2017 and 2016, we included net gains/(losses) from such sales in Operations and maintenance – related parties.
The majority of our insurance coverage is provided by a wholly owned subsidiary of Shell with the remaining coverage provided by third-party insurers. The related party portion of insurance expense, which is included within Operations and maintenance – related parties, for 2018, 2017 and 2016 was $15.2 million, $8.0 million and $5.9 million, respectively.
The following table shows related party expenses, including personnel costs described above, incurred by Shell and SPLC on our behalf that are reflected in the accompanying consolidated statements of income for the indicated periods:
101
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| 2018 | 2017 | 2016 | |||||||||||||||
| Operations and maintenance – related parties | $ | 54.4 | $ | 45.6 | $ | 40.0 | |||||||||||
| General and administrative – related parties | 51.7 | 47.7 | 43.7 | ||||||||||||||
For a discussion of services performed by Shell on our behalf, see Note 1 – Description of the Business and Basis of Presentation – Basis of Presentation. Pursuant to various operating and administrative management agreements, we are allocated indirect operating and general corporate expenses from Shell. Our allocated share of operating expenses, which are included within Operations and maintenance – related parties for 2018, 2017 and 2016, were $15.1 million, $17.1 million and $15.9 million, respectively. Additionally, our allocated share of general corporate expenses, which are included within General and administrative – related parties for 2018, 2017 and 2016, were $32.9 million, $26.3 million and $24.0 million, respectively. Included in General and administrative – related parties are $8.5 million, $8.1 million and $7.7 million, respectively, under the Management Agreement and $8.5 million, $8.5 million and $8.5 million, respectively, under the Omnibus Agreement.
In November 2017, the Enchilada platform in Garden Banks Block 128 experienced a fire that resulted in the shut-in of all production flowing through Auger. As a result, we filed a claim under our related party business continuity insurance and expect to partially recover losses occurring 60 days or more after the incident. Under this claim we received $6.5 million in 2018 and recorded it in Other income in our consolidated statements of income.
Pension and Retirement Savings Plans
Employees who directly or indirectly support our operations participate in the pension, postretirement health and life insurance, and defined contribution benefit plans sponsored by Shell, which include other Shell subsidiaries. Our share of pension and postretirement health and life insurance costs for 2018, 2017 and 2016 was $6.3 million, $4.3 million and $5.1 million, respectively. Our share of defined contribution benefit plan costs for 2018, 2017 and 2016 was $2.5 million, $1.7 million and $2.0 million, respectively. Pension and defined contribution benefit plan expenses are included in either General and administrative – related parties or Operations and maintenance – related parties in the accompanying consolidated statements of income, depending on the nature of the employee’s role in our operations.
Share-based Compensation
Certain SPLC and Shell employees supporting our operations as well as other Shell operations were historically granted awards under the Performance Share Plan (“PSP”), Shell’s incentive compensation program. Share-based compensation expense is included in General and administrative – related parties in the accompanying consolidated statements of income. These costs for 2018, 2017 and 2016 were immaterial.
Equity and Other Investments
We have equity and other investments in entities, including Colonial and Explorer, in which SPLC also owns interests. In some cases we may be required to make capital contributions or other payments to these entities. See Note 6 – Equity Method Investments for additional details.
Reimbursements from Our General Partner
The following table reflects reimbursements from our Parent in 2018, 2017 and 2016:
| 2018 | 2017 | 2016 | |||||||||||||||
Cash received (1) | $ | 11.7 | $ | 15.8 | $ | 2.8 | |||||||||||
Changes in receivable from Parent (2) | (0.3) | 0.3 | 0.2 | ||||||||||||||
Total reimbursements (3) | $ | 11.4 | $ | 16.1 | $ | 3.0 | |||||||||||
(1) These reimbursements are included in Other contributions from Parent in the accompanying consolidated statements of cash flows.
(2) These reimbursements are included in Other non-cash contributions from Parent in the accompanying supplemental cash flow information.
(3) These reimbursements are included in Other contributions from Parent in the accompanying consolidated statements of (deficit) equity and are exclusive of the $2.0 million for 2018 related to contributions from Parent.
In 2018, 2017 and 2016, we filed claims for reimbursement from our Parent of $11.4 million, $16.1 million and $3.0 million, respectively. This reflects our proportionate share of Zydeco directional drill project costs and expenses of $11.4 million, $14.4 million and $1.4 million, respectively. Additionally, in 2017 this included reimbursement for the Refinery Gas Pipeline gas to
102
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
butane service connection project of $1.7 million and in 2016 this included $1.6 million of reimbursement of costs and expenses incurred by Lockport for the storm water improvement and tank repair projects.
6. Equity Method Investments
For each of the following investments, we have the ability to exercise significant influence over these investments based on certain governance provisions and our participation in the significant activities and decisions that impact the management and economic performance of the investments.
Equity method investments comprise the following as of the dates indicated:
| December 31, | |||||||||||||||||||||||
| 2018 | 2017 | ||||||||||||||||||||||
| Ownership | Amount | Ownership | Amount | ||||||||||||||||||||
Amberjack – Series A / Series B (1) | 75.0% / 50.0% | $ | 457.5 | —% | $ | — | |||||||||||||||||
| Mars | 71.5% | 168.9 | 71.5% | 187.4 | |||||||||||||||||||
| Bengal | 50.0% | 81.5 | 50.0% | 79.7 | |||||||||||||||||||
| Permian Basin | 50.0% | 72.2 | 50.0% | 49.4 | |||||||||||||||||||
| LOCAP | 41.48% | 8.2 | 41.48% | 6.9 | |||||||||||||||||||
| Poseidon | 36.0% | — | 36.0% | 2.3 | |||||||||||||||||||
| Proteus | 10.0% | 16.3 | 10.0% | 17.4 | |||||||||||||||||||
| Endymion | 10.0% | 18.3 | 10.0% | 19.5 | |||||||||||||||||||
| $ | 822.9 | $ | 362.6 | ||||||||||||||||||||
(1) We acquired an interest in Amberjack in the May 2018 Acquisition. The acquisition of this interest has been accounted for prospectively.
Unamortized differences in the basis of the initial investments and our interest in the separate net assets within the financial statements of the investees are amortized into net income over the remaining useful lives of the underlying assets. As of December 31, 2018, 2017 and 2016, the unamortized basis differences included in our equity investments are $40.4 million, $41.4 million and $42.7 million, respectively. For the years ended 2018, 2017 and 2016, the net amortization expense was $3.7 million, $3.8 million and $2.8 million, respectively, which is included in Income from equity method investments.
During the first quarter of 2018, the investment amount for Poseidon was reduced to zero due to distributions received that were in excess of our investment balance and we, therefore, suspended the equity method of accounting. As we have no commitments to provide further financial support to Poseidon, we have recorded excess distributions of $24.4 million in Other income for the year ended December 31, 2018. Once our cumulative share of equity earnings becomes greater than the amount of distributions received, we will resume the equity method of accounting as long as the equity method investment balance remains greater than zero.
Our equity investments in affiliates balance was affected by the following during the periods indicated:
| For the Year Ended December 31, | |||||||||||||||||||||||||||||||||||||||||||||||
| 2018 | 2017 | 2016 | |||||||||||||||||||||||||||||||||||||||||||||
| Distributions Received | Income from Equity Method Investments | Impact of Change in Accounting Policy | Distributions Received | Income from Equity Method Investments | Purchase Price Adjustment | Distributions Received | Income from Equity Method Investments | ||||||||||||||||||||||||||||||||||||||||
Amberjack (1) | $ | 104.4 | $ | 80.3 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||||||||||||||
Mars (2) | 119.3 | 107.7 | (6.9) | 125.9 | 121.8 | — | 88.3 | 79.8 | |||||||||||||||||||||||||||||||||||||||
| Bengal | 19.0 | 20.8 | — | 19.0 | 22.6 | — | 19.6 | 20.2 | |||||||||||||||||||||||||||||||||||||||
Poseidon (3) | 33.1 | 6.4 | — | 38.4 | 27.4 | — | 41.9 | 29.7 | |||||||||||||||||||||||||||||||||||||||
Other (4) | 25.9 | 19.7 | — | 15.0 | 14.8 | 0.3 | 8.2 | 8.4 | |||||||||||||||||||||||||||||||||||||||
| $ | 301.7 | $ | 234.9 | $ | (6.9) | $ | 198.3 | $ | 186.6 | $ | 0.3 | $ | 158.0 | $ | 138.1 | ||||||||||||||||||||||||||||||||
(1) We acquired an interest in Amberjack in the May 2018 Acquisition. The acquisition of this interest has been accounted for prospectively.
(2) We acquired an additional 22.9% interest in Mars in the December 2017 Acquisition.
103
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(3) As stated above, the equity method of accounting has been suspended for Poseidon and excess distributions are recorded in Other income.
(4) Included in Other is the activity associated with our investments in Permian Basin, LOCAP, Proteus and Endymion. We acquired a 41.48% interest in LOCAP in the December 2017 Acquisition. The acquisition of our ownership interests in Proteus and Endymion was effective in the December 2016 Acquisition, for which we were not entitled to a distribution and the related equity investment income was less than $0.1 million.
See Note 4 – Acquisitions and Divestiture for additional information regarding the acquisitions of our equity investments. We acquired an additional 22.0% interest in Odyssey on December 1, 2017, which is now being consolidated in our financial statements on a retrospective basis.
The adoption date of the new revenue standard for the majority of our equity method investments will follow the non-public business entity adoption date of January 1, 2019 for their stand-alone financial statements, with the exception of Mars and Permian Basin which adopted on January 1, 2018. As a result of adoption, we recognized our proportionate share of the Mars cumulative effect transition adjustment as a decrease to opening equity in the amount of $6.9 million under the modified retrospective transition method, related to its transportation and dedication agreements which resulted in a deferral of revenue. The cumulative effect transition adjustment for Permian Basin was not material.
Summarized Financial Information
The following presents aggregated selected balance sheet and income statement data for our equity method investments (on a 100% basis):
| For the Year Ended December 31, 2018 | ||||||||||||||||||||||||||
| Total revenues | Total operating expenses | Operating income | Net income | |||||||||||||||||||||||
| Statements of Income | ||||||||||||||||||||||||||
Amberjack (1) | $ | 204.0 | $ | 47.3 | $ | 156.7 | $ | 156.8 | ||||||||||||||||||
| Mars | 241.3 | 87.4 | 153.9 | 153.9 | ||||||||||||||||||||||
| Bengal | 69.2 | 28.1 | 41.1 | 41.1 | ||||||||||||||||||||||
| Poseidon | 115.5 | 34.6 | 80.9 | 73.0 | ||||||||||||||||||||||
Other (2) | 152.2 | 67.0 | 85.2 | 75.8 | ||||||||||||||||||||||
| As of December 31, 2018 | ||||||||||||||||||||||||||||||||||||||||||||
| Current assets | Non-current assets | Total assets | Current liabilities | Non-current liabilities | Equity (deficit) | Total liabilities and equity (deficit) | ||||||||||||||||||||||||||||||||||||||
| Balance Sheets | ||||||||||||||||||||||||||||||||||||||||||||
Amberjack (1) | $ | 45.8 | $ | 846.2 | $ | 892.0 | $ | 4.3 | $ | 4.2 | $ | 883.5 | $ | 892.0 | ||||||||||||||||||||||||||||||
| Mars | 53.1 | 178.2 | 231.3 | 5.4 | 18.4 | 207.5 | 231.3 | |||||||||||||||||||||||||||||||||||||
| Bengal | 27.1 | 155.4 | 182.5 | 8.7 | — | 173.8 | 182.5 | |||||||||||||||||||||||||||||||||||||
| Poseidon | 18.9 | 203.0 | 221.9 | 15.9 | 242.9 | (36.9) | 221.9 | |||||||||||||||||||||||||||||||||||||
Other (2) | 49.7 | 875.7 | 925.4 | 64.5 | 455.5 | 405.4 | 925.4 | |||||||||||||||||||||||||||||||||||||
(1) Our interest in Amberjack was acquired on May 11, 2018. Amberjack total revenues, total operating expenses and operating income (on a 100% basis) was $294.9 million, $73.5 million and $221.4 million, respectively.
(2) Included in Other is the activity associated with our investments in Permian Basin, LOCAP, Proteus and Endymion.
| For the Year Ended December 31, 2017 | ||||||||||||||||||||||||||
| Total revenues | Total operating expenses | Operating income | Net income | |||||||||||||||||||||||
| Statements of Income | ||||||||||||||||||||||||||
| Mars | $ | 255.5 | $ | 81.9 | $ | 173.6 | $ | 173.6 | ||||||||||||||||||
| Bengal | 72.8 | 28.1 | 44.7 | 44.8 | ||||||||||||||||||||||
| Poseidon | 117.1 | 32.6 | 84.5 | 78.5 | ||||||||||||||||||||||
Other (1) | 123.7 | 46.2 | 77.5 | 66.0 | ||||||||||||||||||||||
104
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| As of December 31, 2017 | ||||||||||||||||||||||||||||||||||||||||||||
| Current assets | Non-current assets | Total assets | Current liabilities | Non-current liabilities | Equity (deficit) | Total liabilities and equity (deficit) | ||||||||||||||||||||||||||||||||||||||
| Balance Sheets | ||||||||||||||||||||||||||||||||||||||||||||
| Mars | $ | 47.6 | $ | 187.5 | $ | 235.1 | $ | 5.1 | $ | — | $ | 230.0 | $ | 235.1 | ||||||||||||||||||||||||||||||
| Bengal | 25.0 | 156.6 | 181.6 | 10.5 | 0.3 | 170.8 | 181.6 | |||||||||||||||||||||||||||||||||||||
| Poseidon | 18.7 | 218.6 | 237.3 | 17.6 | 237.4 | (17.7) | 237.3 | |||||||||||||||||||||||||||||||||||||
Other (1) | 91.6 | 625.3 | 716.9 | 98.9 | 244.7 | 373.3 | 716.9 | |||||||||||||||||||||||||||||||||||||
(1) Included in Other is the activity associated with our investments in Permian Basin, LOCAP, Proteus and Endymion. Interest in Permian Basin was acquired by us on October 17, 2017 and is pro-rated in above table. For the year ended December 31, 2017, Permian Basin total revenue, total operating expenses and operating income (on a 100% basis) was $8.3 million, $5.0 million and $3.3 million, respectively.
| For the Year Ended December 31, 2016 | ||||||||||||||||||||||||||
| Total revenues | Total operating expenses | Operating income | Net income | |||||||||||||||||||||||
| Statements of Income | ||||||||||||||||||||||||||
| Mars | $ | 229.8 | $ | 83.0 | $ | 146.8 | $ | 146.8 | ||||||||||||||||||
| Bengal | 69.5 | 28.7 | 40.8 | 40.2 | ||||||||||||||||||||||
| Poseidon | 120.3 | 30.7 | 89.6 | 84.9 | ||||||||||||||||||||||
Other (1) | 52.0 | 17.4 | 34.6 | 20.9 | ||||||||||||||||||||||
| As of December 31, 2016 | ||||||||||||||||||||||||||||||||||||||||||||
| Current assets | Non-current assets | Total assets | Current liabilities | Non-current liabilities | Equity | Total liabilities and equity | ||||||||||||||||||||||||||||||||||||||
| Balance Sheets | ||||||||||||||||||||||||||||||||||||||||||||
| Mars | $ | 40.0 | $ | 197.5 | $ | 237.5 | $ | 5.1 | $ | — | $ | 232.4 | $ | 237.5 | ||||||||||||||||||||||||||||||
| Bengal | 34.0 | 147.5 | 181.5 | 16.8 | 0.7 | 164.0 | 181.5 | |||||||||||||||||||||||||||||||||||||
| Poseidon | 17.1 | 233.6 | 250.7 | 20.7 | 219.7 | 10.3 | 250.7 | |||||||||||||||||||||||||||||||||||||
Other (1) | 42.5 | 395.4 | 437.9 | 43.9 | 100.8 | 293.2 | 437.9 | |||||||||||||||||||||||||||||||||||||
(1) Interests in Proteus and Endymion were acquired by us on December 27, 2016, and is pro-rated in above table. For 2016, Proteus total revenue, total operating expenses and operating income (on a 100% basis) was $24.7 million, $11.7 million and $13.0 million, respectively. For 2016, Endymion total revenue, total operating expenses and operating income (on a 100% basis) was $28.1 million, $12.3 million and $15.8 million, respectively.
Capital Contributions
In accordance with the Member Interest Purchase Agreement entered into in conjunction with the acquisition of Permian Basin in October 2017, we will make capital contributions for our pro rata interest in Permian Basin to fund capital and other expenditures, as approved by supermajority (75%) vote of the members. We made capital contributions of $28.0 million in 2018.
7. Property, Plant and Equipment
Property, plant and equipment consist of the following as of the dates indicated:
105
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| December 31, | |||||||||||||||||
Depreciable Life | 2018 | 2017 | |||||||||||||||
| Land | — | $ | 11.5 | $ | 8.2 | ||||||||||||
| Building and improvements | 10 - 40 years | 39.0 | 38.9 | ||||||||||||||
Pipeline and equipment (1) | 10 - 30 years | 1,162.1 | 1,153.6 | ||||||||||||||
| Other | 5 - 25 years | 17.9 | 17.8 | ||||||||||||||
| 1,230.5 | 1,218.5 | ||||||||||||||||
Accumulated depreciation and amortization (2) | (567.3) | (526.1) | |||||||||||||||
| 663.2 | 692.4 | ||||||||||||||||
| Construction in progress | 79.2 | 44.1 | |||||||||||||||
| Property, plant and equipment, net | $ | 742.4 | $ | 736.5 | |||||||||||||
(1) As of December 31, 2018 and 2017, includes cost of $365.8 million and $353.7 million, respectively, related to assets under operating leases (as lessor), which commenced in May 2017 and December 2017. As of both December 31, 2018 and 2017, includes cost of $22.8 million related to assets under capital lease (as lessee).
(2) As of December 31, 2018 and 2017, includes accumulated depreciation of $120.7 million and $104.7 million, respectively, related to assets under operating leases (as lessor), which commenced in May 2017 and December 2017. As of December 31, 2018 and 2017, includes accumulated depreciation of $4.5 million and $3.0 million, respectively, related to assets under capital lease (as lessee).
For 2018, 2017 and 2016, depreciation and amortization expense on property, plant and equipment of $45.9 million, $45.0 million and $43.1 million, respectively, is included in cost and expenses in the accompanying consolidated statements of income. Depreciation and amortization expense on property, plant and equipment includes amounts pertaining to assets under operating (as lessor) and capital leases (as lessee).
8. Accrued Liabilities – Third Parties
Accrued liabilities – third parties consist of the following as of the dates indicated:
| December 31, | |||||||||||
| 2018 | 2017 | ||||||||||
| Project accruals | $ | 6.7 | $ | 6.0 | |||||||
| Property taxes | 3.9 | 4.2 | |||||||||
| Other accrued liabilities | 2.4 | 2.5 | |||||||||
| Total current accrued liabilities – third parties | $ | 13.0 | $ | 12.7 | |||||||
See Note 5 – Related Party Transactions for a discussion of Accrued liabilities – related parties.
106
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. Related Party Debt
Consolidated related party debt obligations comprise the following as of the dates indicated:
| December 31, | ||||||||||||||||||||||||||||||||||||||
| 2018 | 2017 | |||||||||||||||||||||||||||||||||||||
| Outstanding Balance | Total Capacity | Available Capacity | Outstanding Balance | Total Capacity | Available Capacity | |||||||||||||||||||||||||||||||||
| Seven Year Fixed Facility | $ | 600.0 | $ | 600.0 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||
Five Year Revolver due July 2023 (1) | 494.0 | 760.0 | 266.0 | 246.9 | 760.0 | 513.1 | ||||||||||||||||||||||||||||||||
| Five Year Revolver due December 2022 | 400.0 | 1,000.0 | 600.0 | 1,000.0 | 1,000.0 | — | ||||||||||||||||||||||||||||||||
| Five Year Fixed Facility | 600.0 | 600.0 | — | 600.0 | 600.0 | — | ||||||||||||||||||||||||||||||||
| Zydeco Revolver | — | 30.0 | 30.0 | — | 30.0 | 30.0 | ||||||||||||||||||||||||||||||||
| Unamortized debt issuance costs | (3.3) | n/a | n/a | (2.9) | n/a | n/a | ||||||||||||||||||||||||||||||||
| Debt payable – related party | $ | 2,090.7 | $ | 2,990.0 | $ | 896.0 | $ | 1,844.0 | $ | 2,390.0 | $ | 543.1 | ||||||||||||||||||||||||||
(1) On August 1, 2018, the Partnership extended the maturity date. This was previously referred to as the Five Year Revolver due October 2019.
Interest and fee expenses associated with our borrowings, net of capitalized interest, were $61.0 million, $29.4 million and $8.6 million for 2018, 2017 and 2016, respectively, of which we paid $53.2 million, $25.0 million and $7.0 million, respectively.
Borrowings under our revolving credit facilities approximate fair value as the interest rates are variable and reflective of market rates, which results in a Level 2 instrument. The fair value of our Year Fixed Facility and our Year Fixed Facility is estimated based on the published market prices for issuances of similar risk and tenor and is categorized as a Level 2 instrument. As of December 31, 2018, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $2,094.0 million and $2,099.1 million, respectively. As of December 31, 2017, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $1,846.9 million and $1,858.4 million, respectively.
The Year Fixed Facility was fully drawn on August 1, 2018 and the borrowings were used to partially repay borrowings under the Year Revolver due December 2022.
On May 11, 2018, we funded the May 2018 Acquisition with $494.0 million in borrowings under the Year Revolver due July 2023 and $726.0 million in borrowings under the Year Revolver due December 2022.
On February 6, 2018, we used net proceeds from sales of common units and from our general partner’s proportionate capital
contribution to repay $246.9 million of borrowings outstanding under our Year Revolver due July 2023 and $726.0 million
of borrowings outstanding under our Year Revolver due December 2022.
On December 1, 2017, we borrowed $1,000.0 million under the Year Revolver due December 2022 and $93.1 million under our Year Fixed Facility. We used $825.0 million of these proceeds to fund the December 2017 Acquisition and the remaining $268.1 million to repay borrowings outstanding under our Year Revolver due July 2023. Additionally, we paid $0.7 million of accrued interest on the repaid borrowings with cash on hand.
On September 15, 2017, we used net proceeds from sales of common units to third parties to repay $265.0 million of borrowings outstanding under our Year Revolver due July 2023.
On May 10, 2017, we funded the May 2017 Acquisition with $50.0 million of cash on hand, $73.1 million in borrowings under our Year Revolver due July 2023 and $506.9 million in borrowings under our Year Fixed Facility (as defined below).
On May 23, 2016, we partially funded the cash portion of the May 2016 Acquisition with $296.7 million in borrowings under our Year Revolver due July 2023.
On March 29, 2016, we used cash on hand and net proceeds from sales of common units to third parties to repay $272.6 million of borrowings outstanding under the Year Revolver due July 2023 and all $137.4 million of borrowings outstanding under the 364-Day Revolver.
Credit Facility Agreements
107
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Year Fixed Facility
On July 31, 2018, we entered into a seven-year fixed rate credit facility with STCW with a borrowing capacity of $600.0 million (the “ Year Fixed Facility”). We incurred an issuance fee of $1.3 million, which was paid on August 7, 2018. The Year Fixed Facility contains customary representations, warranties, covenants and events of default, the occurrence of which would permit the lender to accelerate the maturity date of amounts borrowed under the Year Fixed Facility.
The Year Fixed Facility bears an interest rate of 4.06% per annum and matures on July 31, 2025.
Year Revolver due July 2023
On August 1, 2018, we amended and restated the five year revolving credit facility originally due October 2019 such that the facility will now mature on July 31, 2023 (the “ Year Revolver due July 2023”). The Year Revolver due July 2023 will continue to bear interest at LIBOR plus a margin and we continue to pay interest of 0.19% on any unused capacity. Commitment fees began to accrue beginning on the date we entered into the agreement.
As of December 31, 2018, the annualized weighted average interest rate for the Year Revolver due July 2023 was 3.6%. There is no issuance fee associated with this amendment. All other material terms and conditions of the Year Revolver due July 2023 remain unchanged.
The Five Year Revolver due July 2023 was originally entered into on November 3, 2014. On September 27, 2016, we amended and restated the Year Revolver due July 2023 to increase the amount of the facility to $760.0 million, and paid an additional issuance fee of $0.6 million.
The Year Revolver due July 2023 provides that loans advanced under the facility can have a term ending on or before its maturity date.
Year Revolver due December 2022
On December 1, 2017, we entered into a five year revolving credit facility with STCW (the “ Year Revolver due December 2022”) with a borrowing capacity of $1,000.0 million and paid an issuance fee of $1.7 million. Borrowings under the Year Revolver due December 2022 bear interest at the three-month LIBOR rate plus a margin. Additionally, we pay interest of 0.19% on any unused capacity. As of December 31, 2018, the weighted average interest rate for the Year Revolver due December 2022 was 3.3%. Commitment fees began to accrue beginning on the date we entered into the agreement. The Year Revolver due December 2022 matures on December 1, 2022.
Year Fixed Facility
On March 1, 2017, we entered into a Loan Facility Agreement with STCW with a borrowing capacity of $600.0 million (the “ Year Fixed Facility”) and paid an issuance fee of $0.7 million. The Year Fixed Facility provides that we may not repay or prepay amounts borrowed without the consent of the lender and amounts repaid or prepaid may not be re-borrowed.
The Year Fixed Facility bears a fixed interest rate of 3.23% per annum. The Year Fixed Facility matures on March 1, 2022.
364-Day Revolver
On June 29, 2015, we entered into a revolving credit facility (the “364-Day Revolver”) with STCW which expired as of March 1, 2017.
Zydeco Revolving Credit Facility Agreement
On August 6, 2014, Zydeco entered into a senior unsecured revolving credit facility agreement with STCW (the “Zydeco Revolver”). The facility has a borrowing capacity of $30.0 million. Loans advanced under the agreement have up to a -month term.
Borrowings under the credit facility bear interest at the three-month LIBOR rate plus a margin. Additionally, we pay interest of 0.23% on any unused capacity. As of December 31, 2018, the interest rate for the Zydeco Revolver was 3.9%. The Zydeco Revolver matures on August 6, 2019.
Covenants
108
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Under the Year Fixed Facility, the Year Revolver due July 2023, the Year Revolver due December 2022, the Year Fixed Facility, and the Zydeco Revolver, we (and Zydeco in the case of the Zydeco Revolver) have, among other things:
•agreed to restrict additional indebtedness not loaned by STCW;
•to give the applicable facility pari passu ranking with any new indebtedness; and
•to refrain from securing our assets except as agreed with STCW.
The facilities also contain customary events of default, such as nonpayment of principal, interest and fees when due and violation of covenants, as well as cross-default provisions under which a default under one credit facility may trigger an event of default in another facility with the same borrower. Any breach of covenants included in our debt agreements which could result in our related party lender demanding payment of the unpaid principal and interest balances will have a material adverse effect upon us and would likely require us to seek to renegotiate these debt arrangements with our related party lender and/or obtain new financing from other sources. As of December 31, 2018, we were in compliance with the covenants contained in the Year Fixed Facility, the Year Revolver due July 2023, the Year Revolver due December 2022, the Year Fixed Facility, and Zydeco was in compliance with the covenants contained in the Zydeco Revolver.
Borrowings and repayments under our credit facilities for 2018, 2017 and 2016 are disclosed in our consolidated statements of cash flows. See Note 4 – Acquisitions and Divestiture for additional information regarding our use of borrowings. See Note 11 – (Deficit) Equity for additional information regarding the source of our repayments.
109
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. Leases
On December 1, 2014, we entered into a terminaling services agreement with a related party in which we were to take possession of certain storage tanks located in Port Neches, Texas, effective December 1, 2015. On October 26, 2015, the terminal services agreement was amended to provide for an interim in-service period for the purposes of commissioning the tanks in which we pay a nominal monthly fee. Our capitalized costs and related capital lease obligation commenced on December 1, 2015. Upon the in-service date of September 1, 2016, our monthly lease payment was increased to $0.4 million. Under this agreement, in the eighteenth month after the in-service date, actual fixed and variable costs could be compared to premised costs. If the actual and premised operating costs differ by more than 5.0%, the lease would be adjusted accordingly and this adjustment will be effective for the remainder of the lease. No adjustment has been made to date. The imputed interest rate on the capital portion of the lease is 15.0%.
Odyssey entered into an operating lease dated May 12, 1999 with a third party for usage of offshore platform space at Main Pass 289C. The agreement will continue to be in effect until the continued operation of the platform is uneconomic.
We are also obligated under various long-term and short-term noncancelable operating leases, primarily related to tank farm land leases. Several of the leases provide for renewal terms. Rental expense included in Operations and maintenance on the consolidated statements of income for 2018, 2017 and 2016 was $0.2 million, $0.3 million and $0.5 million, respectively.
The future minimum lease payments as of December 31, 2018, for the above lease obligations were:
Total | 2019 | 2020 | 2021 | 2022 | 2023 | Remainder | |||||||||||||||||||||||||||||||||||
| Operating leases for land | $ | 3.4 | $ | 0.2 | $ | 0.2 | $ | 0.2 | $ | 0.2 | $ | 0.2 | $ | 2.4 | |||||||||||||||||||||||||||
| Operating lease of platform space | 1.9 | 0.1 | 0.1 | 0.1 | 0.1 | 0.1 | 1.4 | ||||||||||||||||||||||||||||||||||
Capital leases (1) | 56.6 | 4.3 | 4.3 | 4.3 | 4.3 | 4.3 | 35.1 | ||||||||||||||||||||||||||||||||||
| $ | 61.9 | $ | 4.6 | $ | 4.6 | $ | 4.6 | $ | 4.6 | $ | 4.6 | $ | 38.9 | ||||||||||||||||||||||||||||
(1) Capital leases include Port Neches storage tanks and Garden Banks 128 "A" platform. Port Neches storage tanks includes $30.1 million in interest, $24.3 million in principal and excludes $9.6 million in executory costs.
As of December 31, 2018 and 2017, we had short-term payment obligations relating to capital expenditures totaling $8.3 million and $5.8 million, respectively. These represent unconditional payment obligations to vendors for products and services delivered in connection with capital projects.
110
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. (Deficit) Equity
Our capital accounts are comprised of a 2% general partner interests and 98% limited partner interests. The common units represent limited partner interests in us. The holders of common units, both public and SPLC, are entitled to participate in partnership distributions and have limited rights of ownership as provided for under our partnership agreement. Our general partner participates in our distributions and also currently holds Incentive Distribution Rights ("IDR’s) that entitle it to receive increasing percentages of the cash we distribute from operating surplus.
In November 2018, we filed an update to our universal shelf registration statement on Form S-3 with the SEC relating to an indeterminate number of common units and partnership securities representing limited partner units. We also filed a shelf registration statement on Form S-3 with the SEC in November 2018 relating to $1,000,000,000 of common units and partnership securities representing limited partner units to be used in connection with the at-the-market equity distribution program, direct sales, or other sales consistent with the plan of distribution set forth in the registration statement.
Public Offerings and Private Placement
On February 6, 2018, we completed the sale of 25,000,000 common units in a registered public offering for $673.3 million net proceeds ($680.0 million gross proceeds, or $27.20 per common unit, less $6.0 million of underwriter’s fees and $0.7 million of transaction fees). In connection with the issuance of common units, we issued 510,204 general partner units to our general partner for $13.9 million in order to maintain its 2% general partner interest in us. On February 6, 2018, we also completed the sale of 11,029,412 common units in a private placement with Shell Midstream LP Holdings LLC, an indirect subsidiary of Shell, for an aggregate purchase price of $300.0 million, or $27.20 per common unit. In connection with the issuance of the common units, we issued 225,091 general partner units to the general partner for $6.1 million in order to maintain its 2% general partner interest in us.
We used net proceeds from sales of common units and from our general partner’s proportionate capital contribution to repay $246.9 million of borrowings outstanding under the Year Revolver due July 2023 and $726.0 million of borrowings outstanding under the Year Revolver due December 2022, as well as for general partnership purposes.
On September 15, 2017, we completed the sale of 5,170,000 common units in a registered public offering for $135.1 million net proceeds. In connection with the issuance of common units, we issued 105,510 general partner units to our general partner for $2.8 million in order to maintain its 2% general partner interest in us. We used the net proceeds from these sales of common units and from our general partner’s proportionate capital contribution to repay borrowings outstanding under the Five Year Revolver due July 2023 and for general partnership purposes.
On May 23, 2016, in conjunction with the May 2016 Acquisition, we completed the sale of 10,500,000 common units in a registered public offering for $345.8 million net proceeds ($349.1 million gross proceeds, or $33.25 per common unit, less $2.9 million of underwriter’s fees and $0.4 million of transaction fees). In connection with the issuance of common units, we issued 214,285 general partner units to our general partner as non-cash consideration of $7.1 million in order to maintain its 2% general partner interest in us. We used the net proceeds from the May 2016 Offering and from our general partner’s proportionate capital contribution to partially fund the May 2016 Acquisition.
As part of the registered public offering on May 23, 2016, the underwriters received an option to purchase an additional 1,575,000 common units, which they exercised in full on June 9, 2016 for $51.8 million net proceeds ($52.4 million gross proceeds, or $33.25 per common unit, less $0.5 million in underwriter’s fees and $0.1 million of transaction fees). In connection with the issuance of common units, we issued 32,143 general partner units to our general partner for $1.1 million in order to maintain its 2% general partner interest in us.
On March 29, 2016, we completed the sale of 12,650,000 common units in a registered public offering (the “March 2016 Offering”) for $395.1 million net proceeds ($401.6 million gross proceeds, or $31.75 per common unit, less $6.3 million of underwriter’s fees and $0.2 million of transaction fees). In connection with the issuance of the common units, we issued 258,163 general partner units to our general partner for $8.2 million in order to maintain its 2% general partner interest in us. We used the net proceeds from the March 2016 Offering and from our general partner’s proportionate capital contribution to repay borrowings outstanding under the Year Revolver due July 2023 and the 364-Day Revolver and for general partnership purposes.
At-the-Market Program
111
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On March 2, 2016, we commenced an “at-the-market” equity distribution program pursuant to which we may issue and sell common units for up to $300.0 million in gross proceeds.
During the quarter ended September 30, 2017, we completed the sale of 5,200,000 common units under this program for $139.8 million net proceeds ($140.2 million gross proceeds, or an average price of $26.96 per common unit, less $0.4 million of transaction fees). In connection with the issuance of the common units, we issued 106,122 general partner units to our general partner for $2.9 million in order to maintain its 2% general partner interest in us. We used the net proceeds from these sales of common units and from our general partner’s proportionate capital contribution to repay borrowings outstanding under the Year Revolver due July 2023 and for general partnership purposes.
During the quarter ended June 30, 2017, we completed the sale of 94,925 common units under this program for $2.9 million net proceeds ($3.0 million gross proceeds, or an average price of $31.51 per common unit, less $0.1 million of transaction fees). In connection with the issuance of the common units, we issued 1,938 general partner units to our general partner for $0.1 million in order to maintain its 2% general partner interest in us. We used proceeds from these sales of common units and from our general partner’s proportionate capital contribution for general partnership purposes.
During the quarter ended March 31, 2016, we completed the sale of 750,000 common units under this program for $25.4 million net proceeds ($25.5 million gross proceeds, or an average price of $34.00 per common unit, less $0.1 million of transaction fees). In connection with the issuance of the common units, we issued 15,307 general partner units to our general partner for $0.5 million in order to maintain its 2% general partner interest in us. We used the net proceeds from these sales of common units and from our general partner’s proportionate capital contribution to repay borrowings outstanding under the Year Revolver due July 2023 and the 364-Day Revolver and for general partnership purposes.
Other than as described above, we did not have any sales under this program.
Units Outstanding
As of December 31, 2018, we had 223,811,781 common units outstanding, of which 123,832,233 were publicly owned. SPLC owned 99,979,548 common units representing an aggregate 43.8% limited partner interest in us, all of the IDR’s, and 4,567,588 general partner units, representing a 2% general partner interest in us.
The changes in the number of units outstanding from December 31, 2016 through December 31, 2018 are as follows:
| Public Common | SPLC Common | SPLC Subordinated | General Partner | Total | |||||||||||||||||||||||||
| Balance as of December 31, 2016 | 88,367,308 | 21,475,068 | 67,475,068 | 3,618,723 | 180,936,167 | ||||||||||||||||||||||||
| Expiration of subordination period | — | 67,475,068 | (67,475,068) | — | — | ||||||||||||||||||||||||
| Units issued in connection with ATM program | 5,294,925 | — | — | 108,060 | 5,402,985 | ||||||||||||||||||||||||
| Units issued in connection with public offerings | 5,170,000 | — | — | 105,510 | 5,275,510 | ||||||||||||||||||||||||
| Balance as of December 31, 2017 | 98,832,233 | 88,950,136 | — | 3,832,293 | 191,614,662 | ||||||||||||||||||||||||
| Units issued in connection with equity offerings | 25,000,000 | 11,029,412 | — | 735,295 | 36,764,707 | ||||||||||||||||||||||||
| Balance as of December 31, 2018 | 123,832,233 | 99,979,548 | — | 4,567,588 | 228,379,369 | ||||||||||||||||||||||||
Expiration of Subordination Period
On February 15, 2017, all of the subordinated units converted into common units following the payment of the cash distribution for the fourth quarter of 2016. Each of our 67,475,068 outstanding subordinated units converted into one common unit. The converted units will participate pro rata with the other common units in distributions of available cash. The conversion of the subordinated units does not impact the amount of cash distributions paid by us or the total number of outstanding units.
Distributions to our Unitholders
Our sponsor has elected to waive $50.0 million of IDR’s in 2019 to be used for future investment by the Partnership. Under the terms of the Second Amendment, distributions to holders of the incentive distribution rights shall be reduced by: (1) $17.0 million for the three months ending March 31, 2019, (2) $17.0 million for the three months ending June 30, 2019 and (3) $16.0 million for the three months ending September 30, 2019.
The following table details the distributions declared and/or paid for the periods presented:
112
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Date Paid or to be Paid | Three Months Ended | Public Common | SPLC Common | SPLC Subordinated | General Partner | Distributions per Limited Partner Unit | ||||||||||||||||||||||||||||||||||||||||||||
IDR’s | 2% | Total | ||||||||||||||||||||||||||||||||||||||||||||||||
(in millions, except per unit amounts) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| February 11, 2016 | December 31, 2015 | $ | 13.9 | $ | 4.7 | $ | 14.8 | $ | 1.2 | $ | 0.7 | $ | 35.3 | $ | 0.22000 | |||||||||||||||||||||||||||||||||||
| May 12, 2016 | March 21, 2016 | 17.9 | 5.1 | 15.8 | 2.0 | 0.9 | 41.7 | 0.23500 | ||||||||||||||||||||||||||||||||||||||||||
| August 12, 2016 | June 30, 2016 | 22.0 | 5.4 | 16.9 | 3.7 | 1.0 | 49.0 | 0.25000 | ||||||||||||||||||||||||||||||||||||||||||
| November 14, 2016 | September 30, 2016 | 23.3 | 5.7 | 17.8 | 6.0 | 1.1 | 53.9 | 0.26375 | ||||||||||||||||||||||||||||||||||||||||||
| February 14, 2017 | December 31, 2016 | 24.5 | 5.9 | 18.7 | 8.3 | 1.2 | 58.6 | 0.27700 | ||||||||||||||||||||||||||||||||||||||||||
| May 12, 2017 | March 31, 2017 | 25.7 | 25.9 | — | 10.7 | 1.3 | 63.6 | 0.29100 | ||||||||||||||||||||||||||||||||||||||||||
| August 14, 2017 | June 30, 2017 | 26.9 | 27.0 | — | 12.9 | 1.4 | 68.2 | 0.30410 | ||||||||||||||||||||||||||||||||||||||||||
| November 14, 2017 | September 30, 2017 | 31.4 | 28.3 | — | 16.2 | 1.5 | 77.4 | 0.31800 | ||||||||||||||||||||||||||||||||||||||||||
| February 14, 2018 | December 31, 2017 | 32.9 | 29.6 | — | 18.9 | 1.7 | 83.1 | 0.33300 | ||||||||||||||||||||||||||||||||||||||||||
| May 15, 2018 | March 31, 2018 | 43.1 | 34.8 | — | 25.7 | 2.1 | 105.7 | 0.34800 | ||||||||||||||||||||||||||||||||||||||||||
| August 14, 2018 | June 30, 2018 | 45.2 | 36.5 | — | 29.4 | 2.3 | 113.4 | 0.36500 | ||||||||||||||||||||||||||||||||||||||||||
| November 14, 2018 | September 30, 2018 | 47.3 | 38.2 | — | 33.1 | 2.4 | 121.0 | 0.38200 | ||||||||||||||||||||||||||||||||||||||||||
| February 14, 2019 | December 31, 2018 (1) | 49.5 | 40.0 | — | 36.9 | 2.6 | 129.0 | 0.40000 | ||||||||||||||||||||||||||||||||||||||||||
(1) For more information see Note 15 - Subsequent Events.
Distributions to Noncontrolling Interests
Distributions to SPLC for its noncontrolling interest in Zydeco were $7.3 million, $8.9 million and $20.3 million in 2018, 2017 and 2016, respectively. Distributions to GEL for its noncontrolling interest in Odyssey were $9.1 million, $10.0 million and $9.9 million in 2018, 2017 and 2016, respectively. See Note 5—Related Party Transactions for additional details.
113
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
12. Net Income Per Limited Partner Unit
Net income per unit applicable to common limited partner units, and to subordinated limited partner units in periods prior to the expiration of the subordination period, is computed by dividing the respective limited partners’ interest in net income attributable to the partnership for the period by the weighted average number of common units and subordinated units, respectively, outstanding for the period. Because we have more than one class of participating securities, we use the two-class method when calculating the net income per unit applicable to limited partners. The classes of participating securities include common units, subordinated units, general partner units, and IDR’s. Basic and diluted net income per unit are the same because we do not have any potentially dilutive units outstanding for the period presented.
Our net income includes earnings related to businesses acquired through transactions between entities under common control for periods prior to their acquisition by us. We have allocated these pre-acquisition earnings to our General Partner.
The following tables show the allocation of net income attributable to the Partnership to arrive at net income per limited partner unit:
| 2018 | 2017 | 2016 | |||||||||||||||
| Net income | $ | 482.4 | $ | 391.8 | $ | 377.5 | |||||||||||
| Less: | |||||||||||||||||
| Net income attributable to the Parent | — | 77.3 | 102.3 | ||||||||||||||
| Net income attributable to noncontrolling interests | 18.3 | 19.2 | 30.3 | ||||||||||||||
| Net income attributable to the Partnership | 464.1 | 295.3 | 244.9 | ||||||||||||||
| Less: | |||||||||||||||||
| General partner’s distribution declared | 134.5 | 64.6 | 24.2 | ||||||||||||||
| Limited partners’ distribution declared on common units | 334.6 | 227.7 | 109.8 | ||||||||||||||
| Limited partner’s distribution declared on subordinated units | — | — | 69.2 | ||||||||||||||
| Income (less than)/in excess of distributions | $ | (5.0) | $ | 3.0 | $ | 41.7 | |||||||||||
| 2018 | |||||||||||||||||
| General Partner | Limited Partners’ Common Units | Total | |||||||||||||||
| (in millions of dollars, except per unit data) | |||||||||||||||||
| Distributions declared | $ | 134.5 | $ | 334.6 | $ | 469.1 | |||||||||||
| Income less than distributions | (0.1) | (4.9) | (5.0) | ||||||||||||||
| Net income attributable to the Partnership | $ | 134.4 | $ | 329.7 | $ | 464.1 | |||||||||||
| Weighted average units outstanding: | |||||||||||||||||
| Basic and diluted | 220.3 | ||||||||||||||||
| Net income per limited partner unit: | |||||||||||||||||
| Basic and diluted | $ | 1.50 | |||||||||||||||
114
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| 2017 | |||||||||||||||||
| General Partner | Limited Partners’ Common Units | Total | |||||||||||||||
| (in millions of dollars, except per unit data) | |||||||||||||||||
| Distributions declared | $ | 64.6 | $ | 227.7 | $ | 292.3 | |||||||||||
| Income in excess of distributions | — | 3.0 | 3.0 | ||||||||||||||
| Net income attributable to the Partnership | $ | 64.6 | $ | 230.7 | $ | 295.3 | |||||||||||
| Weighted average units outstanding: | |||||||||||||||||
| Basic and diluted | 180.4 | ||||||||||||||||
| Net income per limited partner unit: | |||||||||||||||||
| Basic and diluted | $ | 1.28 | |||||||||||||||
| 2016 | |||||||||||||||||||||||
| General Partner | Limited Partners’ Common Units | Limited Partner’s Subordinated Units | Total | ||||||||||||||||||||
| (in millions of dollars, except per unit data) | |||||||||||||||||||||||
| Distributions declared | $ | 24.2 | $ | 109.8 | $ | 69.2 | $ | 203.2 | |||||||||||||||
| Income in excess of distributions | 0.8 | 24.6 | 16.3 | 41.7 | |||||||||||||||||||
| Net income attributable to the Partnership | $ | 25.0 | $ | 134.4 | $ | 85.5 | $ | 244.9 | |||||||||||||||
| Weighted average units outstanding: | |||||||||||||||||||||||
| Basic and diluted | 101.9 | 67.5 | |||||||||||||||||||||
| Net income per limited partner unit: | |||||||||||||||||||||||
| Basic and diluted | $ | 1.32 | $ | 1.27 | |||||||||||||||||||
13. Transactions with Major Customers and Concentration of Credit Risk
Our Parent and its affiliates accounted for 59.7%, 49.9% and 44.5% of our total revenues for 2018, 2017 and 2016, respectively. The following table shows revenues from third party customers that accounted for a 10% or greater share of consolidated revenues for the indicated years:
| 2018 | 2017 | 2016 | |||||||||||||||
| Customer C | $ | 64.5 | $ | 70.3 | $ | 72.9 | |||||||||||
The following table shows accounts receivable from third party customers that accounted for a 10% or greater share of consolidated net accounts receivable for the indicated years:
December 31, | |||||||||||||||||
| 2018 | 2017 | 2016 | |||||||||||||||
| Customer C | $ | 5.2 | $ | 5.8 | $ | 6.3 | |||||||||||
We have a concentration of revenues and trade receivables due from customers in the same industry, our Parent’s affiliates, integrated oil companies, marketers, and independent exploration, production and refining companies primarily within the Gulf Coast region of the U.S. These concentrations of customers may impact our overall exposure to credit risk as they may be similarly affected by changes in economic, regulatory, regional and other factors. We are potentially exposed to concentration of credit risk primarily through our accounts receivable with our Parent. These receivables have payment terms of 30 days or less, and there has been no history of collectability issues. We monitor the creditworthiness of third-party major customers. We manage our exposure to credit risk through credit analysis, credit limit approvals and monitoring procedures, and for certain
115
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
transactions, we may request letters of credit, prepayments or guarantees. As of December 31, 2018 and 2017, there were no such arrangements.
We have concentrated credit risk for cash by maintaining deposits in a major bank, which may at times exceed amounts covered by insurance provided by the United States Federal Deposit Insurance Corporation (“FDIC”). We monitor the financial health of the bank and have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk. As of December 31, 2018, we had approximately $207.3 million in cash and cash equivalents in excess of FDIC limits.
14. Commitments and Contingencies
Environmental Matters
We are subject to federal, state, and local environmental laws and regulations. We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are probable and reasonably estimable. For both December 31, 2018 and 2017, we had $0.3 million accrued liabilities associated with environmental clean-up costs. The accrued liability as of December 31, 2018 and 2017 relates to a Consent Decree issued in 1998 by the State of Washington Department of Ecology with respect to our products terminal located in Seattle, Washington. The costs relate to ongoing groundwater compliance monitoring and other remedial activities.
Legal Proceedings
We are named defendants in lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of our outstanding legal matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we do not expect that the ultimate resolution of these matters will have a material adverse effect on our financial position, operating results or cash flows.
Indemnification
Under our Omnibus Agreement, certain environmental liabilities, tax liabilities, litigation and other matters attributable to the ownership or operation of our assets prior to the IPO are indemnified by SPLC. Other than tax liabilities for which the statute of limitations has not expired, the obligations of SPLC under the Omnibus Agreement have expired. See Note 5–Related Party Transactions for additional information.
Minimum Throughput
On September 1, 2016, the in-service date of the capital lease for the Port Neches storage tanks, a joint tariff agreement with a third party became effective and requires monthly payments of approximately $0.4 million. The tariff will be analyzed annually and the rate updated based on the FERC indexing adjustment effective July 1 of each year. Effective July 1, 2018, there was an approximately 4.4% increase to this rate based on FERC indexing adjustment. The initial term of the agreement is years with automatic year renewal terms with the option to cancel prior to each renewal period.
Other Commitments
Odyssey entered into a tie-in agreement effective January 2012 with a third party, which allowed producers to install the tie-in connection facilities and tying into the system. The agreement will continue to be in effect until the continued operation of the platform is uneconomic.
We hold cancelable easements or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline systems. Obligations under these easements are not material to the results of our operations.
Leases
We have operating leases for land, a lease of platform space and capital leases for storage tanks and platform space. See Note 10 – Leases for additional information relating to our lease obligations.
116
SHELL MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
15. Subsequent Event(s)
We have evaluated events that occurred after December 31, 2018 through the issuance of these consolidated financial statements. Any material subsequent events that occurred during this time have been properly recognized or disclosed in the consolidated financial statements and accompanying notes.
Distribution
On January 24, 2019, the Board declared a cash distribution of $0.4000 per limited partner unit for the three months ended December 31, 2018. The distribution was paid on February 14, 2019 to unitholders of record as of February 4, 2019.
Omnibus
On February 19, 2019, we, our general partner, SPLC, Shell Midstream Operating LLC and Shell Oil Company terminated the Omnibus Agreement effective as of February 1, 2019, and we, our general partner, SPLC and Shell Midstream Operating LLC entered into a new Omnibus Agreement effective February 1, 2019. The new Omnibus Agreement (i) removes indemnities that have expired; (ii) includes updates for additional assets acquired; and (iii) increases the administrative fee payable to SPLC to $10.5 million. On February 19, 2019, we, our general partner and Shell Trademark Management Inc. entered into a Trade Marks License Agreement granting us the use of certain Shell trademarks and trade names. The Trade Marks License Agreement is effective as of February 1, 2019 and will expire on January 1, 2024 unless earlier terminated by either party upon 360 days’ notice. The foregoing description of the Omnibus Agreement Termination Agreement, the new Omnibus Agreement and the Trade Marks License Agreement is not complete and is qualified in its entirety by reference to the full text of the Omnibus Agreement Termination Agreement, the new Omnibus Agreement and the Trade Marks License Agreement, filed as Exhibits 10.17, 10.18 and 10.19, respectively, and are each incorporated herein by reference.
16. Selected Quarterly Financial Data (Unaudited)
(in millions of dollars, except per unit data) | Total Revenues (1) | Income Before Income Taxes | Net Income | Net Income Attributable to the Partnership | Limited Partners’ Interest in Net Income Attributable to the Partnership | Net Income per Common Unit - Basic and Diluted (2) | ||||||||||||||||||||||||||||||||
| 2018 | ||||||||||||||||||||||||||||||||||||||
| First | $ | 99.6 | $ | 64.8 | $ | 64.8 | $ | 64.0 | $ | 37.0 | $ | 0.18 | ||||||||||||||||||||||||||
| Second | 129.3 | 115.5 | 115.4 | 110.7 | 79.1 | 0.35 | ||||||||||||||||||||||||||||||||
| Third | 153.5 | 154.3 | 154.2 | 148.3 | 112.3 | 0.50 | ||||||||||||||||||||||||||||||||
| Fourth | 142.3 | 148.2 | 148.0 | 141.1 | 101.3 | 0.45 | ||||||||||||||||||||||||||||||||
| 2017 | ||||||||||||||||||||||||||||||||||||||
| First | $ | 109.1 | $ | 98.1 | $ | 98.1 | $ | 70.8 | $ | 58.7 | $ | 0.33 | ||||||||||||||||||||||||||
| Second | 112.4 | 91.7 | 91.7 | 65.5 | 51.2 | 0.29 | ||||||||||||||||||||||||||||||||
| Third | 121.8 | 99.5 | 99.5 | 72.6 | 55.0 | 0.31 | ||||||||||||||||||||||||||||||||
| Fourth | 126.8 | 102.6 | 102.5 | 86.4 | 65.8 | 0.35 | ||||||||||||||||||||||||||||||||
(1) As a result of the adoption of the new revenue standard, prior period amounts have not been adjusted under the modified retrospective method and continue to be reported in accordance with our historic accounting under previous GAAP.
(2) The net income per common unit for each of the quarterly periods in the applicable year may not equal the year-to-date net income per common unit as the calculations of each are performed independently.
117
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
Item 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Management of the Partnership, with the participation of its Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Partnership’s disclosure controls and procedures as of the end of the annual period. Our disclosure controls and procedures have been designed to provide reasonable assurance that the information required to be disclosed in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures. Based on their evaluation, the Partnership’s Chief Executive Officer and Chief Financial Officer have concluded that the Partnership’s disclosure controls and procedures (as defined in Rules 13(a)-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934, as amended), were effective at the reasonable assurance level as of the end of the annual period covered by this report.
Management’s Report on Internal Control over Financial Reporting
Management of the Partnership is responsible for establishing and maintaining adequate internal control over financial reporting. The Partnership’s internal control system is designed to provide reasonable assurance to the Partnership’s management and board of directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Accordingly, even effective controls can provide only reasonable assurance with respect to financial statement preparation and presentation.
Management of the Partnership assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2018. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (2013). Based on this assessment, management concluded that the Partnership maintained effective internal control over financial reporting as of December 31, 2018.
The effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2018 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which is included in Part II, Item 8. Financial Statements and Supplementary Data of this report.
Changes in Internal Control over Financial Reporting
There has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended December 31, 2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. OTHER INFORMATION
Disclosures Required Pursuant to Section 13(r) of the Securities Exchange Act of 1934
In accordance with our General Business Principles and Code of Conduct, Shell Midstream Partners seeks to comply with all applicable international trade laws including applicable sanctions and embargoes.
Under the Iran Threat Reduction and Syria Human Rights Act of 2012, and Section 13(r) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we are required to include certain disclosures in our periodic reports if we or any of our “affiliates” (as defined in Rule 12b-2 under the Exchange Act) knowingly engaged in certain specified activities during the period covered by the report. Because the Securities and Exchange Commission (the “SEC”) defines the term “affiliate” broadly, it includes any entity controlled by us as well as any person or entity that controls us or is under common control with us.
The activities listed below have been conducted outside the U.S. by non-U.S. affiliates of Royal Dutch Shell plc that may be deemed to be under common control with us. The disclosure does not relate to any activities conducted directly by us, our subsidiaries or our general partner, Shell Midstream Partners GP LLC (the “General Partner”), and does not involve our or the General Partner’s management.
118
For purposes of this disclosure, we refer to Royal Dutch Shell plc and its subsidiaries other than us, our subsidiaries, the General Partner and Shell Midstream LP Holdings LLC as the “RDS Group”. When not specifically identified, references to actions taken by the RDS Group mean actions taken by the applicable RDS Group company. None of the payments disclosed below was made in U.S. dollars, nor are any of the balances disclosed below held in U.S. dollars; however, for disclosure purposes, all have been converted into U.S. dollars at the appropriate exchange rate. We do not believe that any of the transactions or activities listed below violated U.S. sanctions.
In 2018, the RDS Group settled a receivable of $10.5 million with the National Iranian Oil Company (NIOC) associated with the RDS Group’s previous upstream activities conducted prior to the imposition of European Union sanctions against a payable for freight and ancillary services in relation to oil cargoes purchased in 2016. The net payable of $1.0 million was paid to NIOC in March 2018.
In 2017, the RDS Group entered into a technology licence agreement with Petrochemical Industries Design and Engineering Company (PIDEC) to provide licence and engineering services to Abadan Oil Refinery Company (AORC) in relation to Cansolv sulphur dioxide (SO2) scrubbing technology, as well as a separate end-user licence agreement with AORC for a continuing licence for the Cansolv SO2 technology once PIDEC’s work at Abadan has been completed. In addition, a separate agreement was signed at the same time between the RDS Group, the RDS Group’s Iran branch of Shell Development B.V. (SDI) and PIDEC, for the arrangement of payments due under the licence and engineering agreement to be made to SDI in Iran. In 2018 these agreements generated gross revenue of $691,768 and an estimated net profit of $438,131. At December 31, 2018, the RDS Group had a receivable outstanding of $691,768. In October 2018, the RDS Group sent notices of termination with respect to these two agreements.
In addition, at December 31, 2018, the RDS Group had a receivable of $1.2 million outstanding with Hamedan Ibn Sina Petrochemical Company associated with a technology licence agreement signed in 2016. In October 2018, the RDS Group sent notice of suspension with respect to this agreement.
In May 2018, the RDS Group agreed to extend the term of a memorandum of understanding (MOU) originally signed in 2016, with the NIOC to cover a joint review of a number of oil and gas opportunities. This amendment extended the term of the MOU to August 6th, 2018. There was no gross revenue or net profit associated with this transaction.
In 2018, the RDS Group received gross revenue of $228,441 into its account at Karafarin Bank from Bank Mellat in relation to advisory services provided to Marun Petrochemical Company, pursuant to an advisory agreement entered into in June 2017. No net profit was associated with these services in 2018.
In October 2018, the RDS Group paid $2.1 million to National Iranian Tankers Company pursuant to a charter party agreement entered into in May 2017. This payment constituted full settlement of all obligations under the charter party agreement.
In 2018, the RDS Group paid $18,812 for the clearance of overflight permits for RDS Group aircraft over Iranian airspace and $6,352 for handling cost to the Iranian Civil Aviation Authority. There was no gross revenue or net profit associated with these transactions. On occasion, RDS Group aircraft may be routed over Iran and therefore these payments may continue in the future.
In 2018, RDS Group employees met with Iranian officials in Iran. In relation to these travelling RDS Group employees, $6,336 was paid to Iranian authorities for visas and $688 for exit fees; $190 was paid to Bimeh Insurance Company for travel insurance; $853 was paid to Iranian airlines for flight tickets. Additionally, $246 visa cost was incurred by RDS Group non US affiliates. The RDS Group also discovered $294 in visa costs for RDS Group employees and $142 visa cost incurred by RDS Group non US affiliates in relation to 2017 that were not previously disclosed. Using an agent, CIBT Visumdienst B.V, the RDS Group also paid $62 consular fee to an Iranian embassy. There was no gross revenue or net profit associated with these transactions. The RDS Group has ceased these discussions and don’t expect similar payments in the future.
In 2018, the RDS Group provided downstream retail services to the Iranian Embassy in Switzerland and to the International Islamic Liquidity Management Corporation in Malaysia. These transactions generated gross revenue of $4,064 and an estimated net profit of $236 in Switzerland and $979 gross revenue and an estimated net profit of $57 in Malaysia. The RDS Group has no contractual agreement with these parties.
The RDS Group maintains accounts with Karafarin Bank where its cash deposits (balance of $5.0 million at December 31, 2018) generated non-taxable interest income of $0.3 million in 2018, and the RDS Group paid $351 in bank charges. The RDS Group has made payments amounting to $1.4 million through its account in Karafarin Bank to a variety of non-sanctioned parties.
119
PART III
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Management of Shell Midstream Partners, L.P.
We are managed by the board of directors and executive officers of Shell Midstream Partners GP LLC, our general partner. Our general partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. SPLC owns all of the membership interests in our general partner. Our general partner has a board of directors, and our common unitholders are not entitled to elect the directors or to participate directly or indirectly in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.
SPLC appointed all nine directors on our general partner’s board of directors. We have three directors who have been determined by our board of directors to be independent under the independence standards of the New York Stock Exchange (“NYSE”).
We do not have any employees. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct operations, whether through directly hiring employees or by obtaining services of personnel employed by Shell, SPLC or third parties, but we sometimes refer to these individuals as our employees because they provide services directly to us.
Directors and Executive Officers of Shell Midstream Partners GP LLC
Directors are elected by the sole member of our general partner and hold office until their successors have been elected or qualified or until their earlier death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion of, the board of directors. The following table shows information for the directors and executive officers of our general partner as of February 21, 2019.
| Name | Age | Position with Shell Midstream Partners GP LLC | ||||||||||||
| Curtis R. Frasier | 63 | Director, Chairman of the Board of Directors | ||||||||||||
Kevin M. Nichols (1) | 51 | Director, Chief Executive Officer and President | ||||||||||||
| Shawn J. Carsten | 52 | Director, Vice President and Chief Financial Officer | ||||||||||||
| Lori M. Muratta | 53 | Vice President, General Counsel and Secretary | ||||||||||||
| Alton G. Smith | 58 | Vice President, Operations | ||||||||||||
Steven Ledbetter (2) | 43 | Vice President, Commercial | ||||||||||||
| James J. Bender | 62 | Director | ||||||||||||
| Carlos A. Fierro | 57 | Director | ||||||||||||
| Paul R. A. Goodfellow | 53 | Director | ||||||||||||
| Rob L. Jones | 60 | Director | ||||||||||||
| Margaret C. Montana | 63 | Director | ||||||||||||
Marcel Teunissen (3) | 45 | Director | ||||||||||||
(1) Kevin M. Nichols was elected as Director, Chief Executive Officer and President effective April 1, 2018.
(2) Steven Ledbetter became Vice President, Commercial effective April 1, 2018.
(3) Marcel Teunissen was elected as a Director effective February 1, 2018.
Curtis R. Frasier. Curtis Frasier became a member of the board of directors of our general partner on October 29, 2014 and is the Chairman of the Board of Directors. Employed at Shell from 1982 until 2013, Mr. Frasier provided legal advice and services in areas of commercial, corporate and international law based in the US, London and The Netherlands. Retired from Shell since September 2013, Mr. Frasier most recently served as Executive Vice President, Chief Legal Officer and General Counsel of Shell Upstream Americas as well as Head of Legal for Shell in the United States from 2009 to 2013. From 2006 to 2009, Mr. Frasier served as Executive Vice President, Shell Gas & Power—Americas, where he led Shell’s Gas & Power businesses in the Americas, including natural gas pipelines, power plants and LNG re-gasification terminals. From 2002 to 2006, Mr. Frasier served as General Counsel of the global exploration and production business of Shell International Petroleum Company in The Hague. From 1997 to 2002, Mr. Frasier served as Executive Vice President, Shell US Gas & Power where he held executive leadership positions in Tejas Gas Corporation, Coral Energy (now Shell Gas Trading) and Shell US Gas &
120
Power. Following the sale of Shell’s natural gas processing assets to Enterprise Products Partners, L.P., Mr. Frasier served as a member of the board of directors of Enterprise Products GP, LLC, the general partner of Enterprise from 1999 to 2002. From 1995 to 1997, Mr. Frasier served as President of Shell Midstream Enterprises, a producer services company providing third-party oil and natural gas processing, transportation and marketing. From 1994 to 1995, Mr. Frasier also served as Manager, Supply Operations, Shell Oil Company managing Shell’s crude oil and refined product logistics throughout the United States. Mr. Frasier is an Executive Board Member of the Institute for Energy Law; Member of the Board of Trustees, the Center for American and International Law; Member of the Board of Directors, the Julie Ann Wrigley Global Institute of Sustainability; and Member of the Board of Visitors, the University of Tulsa College of Law’s Sustainable Energy and Resource Law. Mr. Frasier earned a Bachelor of Arts from Arizona State University and a Juris Doctorate from the University of Tulsa. We believe that Mr. Frasier’s extensive experience in commercial and legal roles in the midstream industry and his prior experience as a director of the general partner of a master limited partnership makes him well qualified to serve as the Chairman of the board of directors of our general partner.
Kevin M. Nichols. Kevin Nichols was named President and Chief Executive Officer of our general partner and elected as a member of our Board effective April 1, 2018. He became Vice President, Commercial of our general partner on October 29, 2014, and resigned from that role effective March 31, 2018. Since June 2012, Mr. Nichols has served as Vice President and General Manager, Business Development for SPLC. Mr. Nichols devotes the majority of his time to his roles at SPLC and spends time, as needed, devoted to our business and affairs. Mr. Nichols is currently responsible for commercial activities that include business development, oil movements, tariffs, joint venture governance, and portfolio activity. Since joining Shell in 1992, Mr. Nichols has held numerous roles of increasing responsibility in Shell, managing regions of Shell’s Retail business and from 2008 to 2012 worked in Shell’s Downstream Strategy group in London where he set strategy for market entries and growth in Asia. Mr. Nichols earned a Bachelor of Science in Management from San Diego State University and an MBA from Rice University. We believe that Mr. Nichols’ extensive experience in the energy industry, particularly his experience in the pipeline sector, makes him well qualified to serve as an executive officer and a member of the Board.
Shawn J. Carsten. Shawn Carsten became Chief Financial Officer and Vice President of our General Partner on March 1, 2017. He is a 30-year Shell executive with deep financial and operational management experience, as well as significant experience in Shell’s Upstream, Downstream and Retail businesses. Prior to his current role, Mr. Carsten served as the Downstream Controller - Americas of Equilon Enterprises LLC d/b/a Shell Oil Products US, where he was responsible for the financial results and control framework for Shell’s Downstream companies in North and South America, as well as finance operations personnel in the Americas and in Asia. Prior to his role as Controller, Mr. Carsten spent 2013 serving as the Finance Shareholding Representative for Motiva, a multi-billion dollar joint venture, where he was responsible for assessing value proposals and investment opportunities. From 2011 through 2012, Mr. Carsten served as the Finance Manager for Supply and Distribution, supporting North and South America with operational management and functional leadership for capital project development, commercial development and business performance; having served in various related capacities since 2008. Mr. Carsten holds a bachelor’s degree in Finance from the University of Colorado and a MBA from the Kellogg School of Management at Northwestern University. We believe that Mr. Carsten’s extensive experience across a wide range of energy segments, particularly his experience in financial management of domestic supply and distribution, makes him well qualified to serve as a director.
Lori M. Muratta. Lori Muratta became Vice President, General Counsel and Secretary of our general partner in 2014. In 2017, she was named Managing Counsel, Midstream & Commercial for Shell, a role she fills in addition to her role with our general partner. Ms. Muratta devotes the majority of her time to our business and affairs and also spends time devoted to the business and affairs of Shell. Prior to her current roles, from 2000 Ms. Muratta served as Senior Counsel for Shell Oil Company, where she advised the company in mergers, acquisitions, divestments, joint ventures and financings in the upstream, midstream and downstream businesses. She also provided corporate law support to the Shell’s U.S. subsidiaries and affiliates. Before her time at Shell, Ms. Muratta was Attorney and Manager of Communications at Solvay America, Inc. and worked as an associate at Mayor, Day, Caldwell & Keeton LLP and O’Melveny & Myers LLP. Ms. Muratta received a Bachelor of Science in Foreign Service, cum laude, from Georgetown University and a Juris Doctor, cum laude, from Harvard Law School.
Alton (Greg) G. Smith. Mr. Smith became Vice President, Operations of our general partner on October 29, 2014. Mr. Smith devotes the majority of his time to his roles at SPLC and also spends time, as needed, devoted to our business and affairs. Mr. Smith was appointed President, SPLC in November 2010. In January 2011, Mr. Smith also assumed the role of General Manager, Gulf of Mexico Operations. Prior to this appointment he served as the Gulf of Mexico Regional Operations Manager for SPLC, a role in which he had day-to-day operations accountability for Shell’s then 3,500 miles of crude oil, chemical and product pipelines located offshore Gulf of Mexico and along the Texas/Louisiana Gulf Coast. Mr. Smith started his career with SPLC in 1983 and has held a number of assignments of increasing responsibility within Shell, primarily in engineering and operations. These roles include Manager of GOM Business Development, Control Center Manager, and Manager of
121
Distribution Operations Support and Engineering. He has served as the Chairman of the API Pipeline Committee and on the API Cybernetics Committee and the Performance Excellence Committee. Mr. Smith earned a Bachelor of Science in Electrical Engineering from The Ohio State University.
Steven Ledbetter. Mr. Ledbetter became Vice President, Commercial of our general partner on April 1, 2018. Mr. Ledbetter is a 19-year Shell executive with deep financial and operational management experience. Mr. Ledbetter served as the President of Jiffy Lube International ("Jiffy Lube"), a wholly owned subsidiary of Shell. Prior to his role as President of Jiffy Lube, Mr. Ledbetter served as Director of Key Accounts for Shell’s Consumer Lubricants business ("Lubricants") for North America from 2010 to 2013, where he was responsible for large platform multi-site business development throughout North America. From 2009 to 2010, he worked as Deal Manager setting strategy and negotiating large platform deals for the route to market for the Lubricants business in North America. In 2007, Mr. Ledbetter was North American Consumer Finance Manager for Lubricants, responsible for financial support and economic assurance of the business. In 2004, he became a member of the leadership team for Shell’s Puget Sound Refinery in Anacortes, Washington, accountable for finance and procurement activities of the site. From 1999 to 2004, Mr. Ledbetter held various roles in SPLC, including financial support to the business, Treasurer of several joint ventures, business planning and accounting. Prior to joining Shell, Mr. Ledbetter was a facility cost analyst with United States Gypsum Company based in Texas. Mr. Ledbetter holds a bachelor’s degree in Finance from Texas A&M University. The Partnership believes that Mr. Ledbetter’s extensive experience across a wide range of strategy, finance, commercial deal structuring, business transformation and business leadership makes him well qualified to serve as an executive officer.
James (Jim) J. Bender. Jim Bender became a member of the board of directors of our general partner on October 29, 2014. Since April 2016, Mr. Bender has been employed with the Hall Estill Law Firm in Denver as Of Counsel. Since December 2015, he has served as an Advisory Board Member of Orion Energy Partners. From May 2014 to July 2014, Mr. Bender served as Senior Vice President of Special Projects of WPX Energy, Inc. (WPX), and from December 2013 to May 2014 as interim President and Chief Executive Officer of WPX. Mr. Bender served as a member of the board of directors of WPX from December 2013 to May 2014. He also served as Chairman of the board of directors of APCO Oil and Gas International Inc., (a publicly-traded affiliate of WPX) from December 2013 to August 2014. From April 2011 to December 2013, Mr. Bender served as Senior Vice President and General Counsel of WPX. Mr. Bender has served as a member of the board of directors of Two Harbors Investment Corp. since May 2013. Mr. Bender served as Senior Vice President and General Counsel of The Williams Companies, Inc. (Williams) from December 2002 to December 2011 and General Counsel of Williams Partners GP LLC, the general partner of Williams Partners L.P., from September 2005 until December 2011. Mr. Bender served as the General Counsel of the general partner of Williams Pipeline Partners L.P., from 2007 until its merger with Williams Partners L.P. in August 2010. From June 1997 to June 2002, he was Senior Vice President and General Counsel of NRG Energy, Inc. Mr. Bender earned a bachelor’s degree in mathematics, summa cum laude, from St. Olaf College and a Juris Doctor, magna cum laude, from the University of Minnesota Law School. We believe that Mr. Bender’s extensive experience in the energy industry, and more specifically with sponsored master limited partnerships, makes him well qualified to serve as a member of the board of directors of our general partner.
Carlos A. Fierro. Carlos A. Fierro became a member of the board of directors of our general partner on January 1, 2015. Mr. Fierro is a private investor and consultant based in Washington, D.C. In addition to this board of directors, Mr. Fierro serves on the board of directors, audit committee and governance and compensation committee of Athabasca Oil Corporation, a Canadian energy company with a focused strategy on the development of thermal and light oil assets. From May 2016 to the present, Mr. Fierro has served as a Senior Advisor to Guggenheim Securities, the investment banking arm of Guggenheim Partners. From September 2008 through June 2013, Mr. Fierro was a Managing Director and Global Head of the Natural Resources Group of Barclays, which encompasses Barclays’ oil and gas, chemicals and metals and mining businesses. Mr. Fierro joined Barclays Capital in 2008 from Lehman Brothers, where he was the Global Head of the Natural Resources Group from January 2007 through September 2008. From September 2004 through January 2007, Mr. Fierro served as Co-Head of Mergers & Acquisitions in Europe for Lehman Brothers from a base in London. Prior to that, Mr. Fierro led Lehman Brothers’ mergers and acquisitions effort in the natural resources sector for seven years, based in New York. Throughout his banking career, Mr. Fierro participated in the development, structuring, negotiation and execution of numerous merger, acquisition, divestiture, restructuring and joint venture transactions. In the natural resources sector, these included transactions for companies involved in exploration and production, refining and marketing, oil field services, mining, pipelines, petrochemicals and coal. Prior to his banking career, Mr. Fierro practiced corporate, M&A and securities law for eleven years with Baker & Botts, L.L.P., where he was a partner. In his practice, Mr. Fierro devoted his time principally to oil and gas transactions, including hostile takeovers, acquisitions, divestitures, public and private debt and equity financing transactions, corporate restructurings and proxy fights. Mr. Fierro holds a B.A. from the University of Notre Dame and a J.D. from Harvard University. We believe that Mr. Fierro’s extensive experience in the energy banking industry, and his work in mergers and acquisitions, makes him well qualified to serve as a member of the board of directors of our general partner.
122
Paul R. A. Goodfellow. Paul Goodfellow became a member of the board of directors of our general partner on October 29, 2014. Since April 2017, Dr. Goodfellow has served as Executive Vice President, Wells for Shell International. Prior to this, Dr. Goodfellow has served as Vice President, United Kingdom and Ireland for Upstream International since February 2015, and as the Vice President Unconventionals US and Canada for Shell Upstream Americas from January 2013. Prior to this role, Dr. Goodfellow moved into the role of Vice President Development, Onshore in September 2009 for Shell Upstream Americas responsible for field development planning, technical and technology functions. In July 2008, Dr. Goodfellow was named Venture Manager for North America Onshore. Since 2007, he has also served on the board of directors of Shell’s Bully deepwater drillship joint venture. In August 2003, he took up the role of Wells Manager for the Americas Region and in 2000, Dr. Goodfellow was assigned to Shell Exploration & Production Company as the Operations Manager for Deepwater Drilling and Completions. He has worked in a variety of wells related roles throughout the Shell Group. Dr. Goodfellow worked in the mining industry in South Africa and Finland prior to joining Shell in Holland in 1991. Dr. Goodfellow is a Chartered Engineer and a member of the Institute of Mining and Metallurgy and SPE. Dr. Goodfellow earned a Bachelor of Engineering in Mining Engineering and a Ph.D. in Rock Mechanics from The Camborne School of Mines in the United Kingdom. We believe that Dr. Goodfellow’s extensive experience in the energy industry makes him well qualified to serve as a member of the board of directors of our general partner.
Rob L. Jones. Rob Jones became a member of the board of directors of our general partner on October 29, 2014. Mr. Jones is a private investor and consultant based in Houston, Texas. Mr. Jones also currently serves as a director on the board of Spire Inc., a public utility holding company based in St. Louis, Missouri. Mr. Jones also serves as a director on the board of BancAfflicated Inc., a privately held bank based in Arlington, Texas. From September 2012 until June 2014, Mr. Jones served as an Executive in Residence at the McCombs School of Business at the University of Texas at Austin (McCombs). Mr. Jones continues as a guest lecturer and speaker at McCombs. Mr. Jones also served as Lead Independent Director for Susser Petroleum Partners, L.P. (SUSP), a publicly traded partnership. From 2007 through June 2012, Mr. Jones was the Co-Head of Bank of America Merrill Lynch Commodities (MLC). MLC is a global commodities trading business and a wholly owned subsidiary of Bank of America Merrill Lynch. Prior to taking leadership of MLC in 2007, he served as Head of Merrill Lynch’s Global Energy and Power Investment Banking Group and founder of Merrill Lynch Commodities Partners, a private equity vehicle for the firm. An investment banker with Merrill Lynch and The First Boston Corporation for over 20 years, Mr. Jones worked extensively with a variety of energy and power clients, with a particular focus on the natural gas and utility sectors. From 1980 until 1985, Mr. Jones was a Financial Associate with the oil and gas exploration and production division of Sun Company, primarily based in Dallas, Texas. He is a graduate of the University of Texas, where he received a Bachelor of Business Administration in Finance with Honors and an MBA with High Honors and was a Sord Scholar. Mr. Jones is a Life Member of the Dean’s Advisory Council of McCombs and an Emeritus Member of the Children’s Fund of Houston Texas. We believe that Mr. Jones’ extensive experience in financial and mergers and acquisitions roles in the energy banking industry and his experience as a lead independent director makes him well qualified to serve as a member of the board of directors of our general partner.
Margaret (Peggy) C. Montana. Peggy Montana retired as Chief Executive Officer and President in June 2015 and remains a member of the board of directors of our general partner. Employed at Shell from 1977 until 2015, Ms. Montana served in various capacities in the downstream and midstream sector during her career. Ms. Montana became Executive Vice President, US Pipelines & Special Projects - Americas in Shell Downstream Inc. in January 2014. Ms. Montana served as Executive Vice President, Supply & Distribution, from 2009 to 2014, where she was responsible for hydrocarbon supply to Shell’s downstream worldwide fuels manufacturing and marketing businesses. Prior to 2009, Ms. Montana served in the U.S. from 2004 as Vice President, Supply, and then Vice President, Global Distribution, where she led Shell’s fuels global terminal and distribution operations. In these various roles, Ms. Montana has led Shell’s U.S. pipeline business since 2006. Ms. Montana currently is a member of the board of directors of Contanda, a private terminal company; the board of trustees of Missouri University of Science & Technology and the Houston YMCA. Past affiliations include API Downstream Committee and the National Petroleum Council. Ms. Montana holds a bachelor of science in Chemical Engineering from the University of Missouri, Rolla. We believe that Ms. Montana’s extensive experience in the energy industry, particularly her experience in supply and distribution and in the pipeline sector, makes her well qualified to serve as a member of the board of directors of our general partner.
Marcel Teunissen. Marcel Teunissen became a member of the board of directors of our general partner on February 1, 2018. Mr. Teunissen has been with Shell for 21 years in senior finance and commercial positions, in Shell’s Upstream and Downstream businesses and in its corporate head office. Currently, Mr. Teunissen is Vice President Finance, Integrated Gas Ventures, based in Houston, Texas. In this role he is responsible for finance management of a global portfolio of Upstream gas and LNG assets. Prior to this role, Mr. Teunissen was Vice President Finance, Heavy Oil, based in Calgary, Canada, responsible for the financial results of the 250kbd oil sands joint venture, which Shell divested in 2017. From 2012 to 2015, Mr.Teunissen was Vice President Financial Planning & Appraisal at Shell’s head office in The Hague, Netherlands, supporting the Group’s
123
executive committee and Board of Directors on business planning. In the 10 years before that, Mr. Teunissen was based in Singapore and involved in mergers and acquisitions as regional supply & trading finance manager and refinery finance manager. In the early part of his career, he had the opportunity to gain experience as country Finance Manager for some of Shell’s smaller businesses in the Caribbean and South America. Mr. Teunissen holds a Master’s degree in Business Economics from Erasmus University in Rotterdam, The Netherlands. We believe Mr. Teunissen’s extensive global experience in financial and commercial management makes him will qualified to serve as a member of the board of directors of our general partner.
Board Leadership Structure
Although the chief executive officer of our general partner currently does not also serve as the chairman of the board, the board of directors of our general partner has no policy with respect to the separation of the offices of chairman of the board of directors and chief executive officer. Instead, that relationship is defined and governed by the amended and restated limited liability company agreement of our general partner, which permits the same person to hold both offices. Directors of the board of directors of our general partner are designated or elected by SPLC. Accordingly, unlike holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.
Board Role in Risk Oversight
Our corporate governance guidelines provide that the board of directors of our general partner is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility is satisfied by our audit committee, which is responsible for reviewing and discussing with management and our independent registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies.
Director Independence
Although most companies listed on the NYSE are required to have a majority of independent directors serving on the board of directors of the listed company, the NYSE does not require a publicly traded partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation or a nominating and corporate governance committee. We are, however, required to have an audit committee of at least three members within one year of the date our common units are first listed on the NYSE, and all of our audit committee members are required to meet the independence and financial literacy tests established by the NYSE and the Exchange Act.
Committees of the Board of Directors
The board of directors of our general partner has an audit committee and a conflicts committee. The board of directors may also have such other committees as the board determines from time to time. Each of the standing committees of the board of directors has the composition and responsibilities described below.
Audit Committee
Our general partner has an audit committee composed of at least three directors, each of whom meets the independence and experience standards established by the NYSE and the Exchange Act. Our audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. Our audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. Our audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to our audit committee. Messrs. Jones, Bender and Fierro currently serve as members of our audit committee; Mr. Jones is the committee chair. Each of Messrs. Jones, Bender and Fierro is deemed to be “financially literate” as defined by the listing standards of NYSE, and each of Messrs. Jones and Fierro is deemed an “audit committee financial expert,” as defined in SEC regulations. Our audit committee charter is posted on the “Corporate Governance” section of our website. We have a separately-designated standing audit committee in accordance with section 3(a)(58)(A) of the Securities Exchange Act of 1934.
Our audit committee has reviewed and discussed the audited financial statements with management. It has also discussed with the independent auditors the matters required by Public Company Accounting Oversight Board (“PCAOB”) Auditing Standard No. 16, Communications with Audit Committees. Our audit committee has received written disclosures and the letter from the independent accountants required by applicable requirements of the PCAOB regarding the independent accountant’s communications with the audit committee concerning independence, and has discussed with the independent accountant the
124
independent accountant’s independence. The audit committee recommended to the board of directors that the audited financial statements as of and for the year ended December 31, 2018 be included in this report.
Conflicts Committee
In accordance with the terms of our partnership agreement, at least two members of the board of directors of our general partner will serve on our conflicts committee to review specific matters that may involve conflicts of interest. The members of our conflicts committee cannot be officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. In addition, the members of our conflicts committee cannot own any interest in our general partner or its affiliates or any interest in us or our subsidiaries other than common units or awards, if any, under our incentive compensation plan. Messrs. Bender, Jones and Fierro currently serve as members of our conflicts committee; Mr. Bender is the committee chair.
Governance Guidelines
We have adopted governance guidelines to assist the board of directors of our general partner in the exercise of its responsibilities. Our corporate governance guidelines provide that the non-management directors will meet periodically in executive sessions without management participation. At least annually, all of the independent directors of our general partner meet in executive sessions without management participation or participation by non-independent directors. Currently, Mr. Frasier, the chairman of the board of directors, presides at the executive sessions of the non-management directors and Mr. Jones, the chairman of the audit committee, presides at the executive sessions of the independent directors.
Compensation Committee Interlocks and Insider Participation
The listing rules of the NYSE do not require us to maintain, and we do not maintain, a compensation committee.
Code of Conduct and Code of Ethics
We have adopted a Code of Conduct applicable to all employees, directors and officers, as well as a Code of Ethics applicable to our general partner’s chief financial officer. Our Code of Conduct covers topics including, but not limited to, conflicts of interest, insider dealing, competition, discrimination and harassment, confidentiality, bribery and corruption, sanctions and compliance procedures. Our Code of Ethics covers topics including, but not limited to, conflicts of interest, gifts and disclosure controls. Our Code of Conduct and Code of Ethics are posted on the “Corporate Governance” section of our website.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 (the Act) requires directors and executive officers of our general partner, and persons who own more than 10% of a registered class of our equity securities, to file reports of ownership and changes in ownership of our common units with the SEC and the NYSE, and to furnish us with copies of the forms they file. To our knowledge, based solely upon a review of the copies of such reports furnished to us and written representations of our officers and directors, during 2018, all Section 16(a) reports applicable to our officers and directors were filed on a timely basis, except that one Form 4 relating to an open market purchase by Curtis R. Frasier was filed one day late.
Item 11. EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
Neither we nor our general partner employ any of the individuals who serve as executive officers of our general partner and are responsible for managing our business. Our general partner does not have a compensation committee. We are managed by our general partner, the executive officers of which are employees of Shell. We and our general partner have entered into the Omnibus Agreement with SPLC pursuant to which, among other matters:
•SPLC makes available to our general partner the services of Shell employees who will serve as the executive officers of our general partner; and
•We pay SPLC an annual administrative fee, currently $8.5 million, to cover, among other things, the services provided to us by the executive officers of our general partner.
These officers and all other personnel necessary for our business to function are employed and compensated by Shell, subject to the administrative services fee in accordance with the terms of the Omnibus Agreement. Under the Omnibus Agreement, none
125
of Shell’s long-term incentive compensation expense is allocated directly to us. We are responsible for paying the long-term incentive compensation expense, if any, associated with our long-term incentive plan described below. The executive officers of our general partner continue to participate in employee benefit plans and arrangements sponsored by Shell, including plans that may be established in the future. Our general partner has not entered into any employment agreements with any of its executive officers. We did not grant any awards under our long-term incentive plan to our officers or directors, nor do we have a current intent to do so. Our long-term incentive plan is described below under “—Long-Term Incentive Plan.”
Responsibility and authority for compensation-related decisions for executive officers of our general partner reside with Shell’s human resources function and the RDS Management Development Committee, as applicable. Other than compensation under our long-term incentive plan, which requires action by the board of directors of our general partner, any such compensation decisions are not subject to any approvals by the board of directors of our general partner or any committees thereof. Our Named Executive Officers (“NEOs”) consist of our general partner’s principal executive officer, former principal executive officer, principal financial officer and the three most highly compensated executive officers other than its principal executive officer and principal financial officer as of December 31, 2018, being:
•Kevin M. Nichols, Chief Executive Officer and President
•John H. Hollowell, former Chief Executive Officer and President
•Shawn J. Carsten, Vice President and Chief Financial Officer
•Lori M. Muratta, Vice President, General Counsel and Secretary
•Alton G. Smith, Vice President, Operations
•Steven Ledbetter, Vice President, Commercial
Each of Mr. Nichols, Mr. Hollowell, Mr. Carsten, Ms. Muratta, Mr. Smith and Mr. Ledbetter devotes (or devoted) a significant portion of his or her time to his or her roles in Shell and spends time, as needed, directly managing our business and affairs. Pursuant to the terms of the Omnibus Agreement, we pay a fixed administrative fee to SPLC, which covers, among other things, the services provided to us by our NEOs. None of Mr. Nichols, Mr. Hollowell, Mr. Carsten, Ms. Muratta, Mr. Smith or Mr. Ledbetter receive any separate amounts of compensation for their services to our business or as executive officers of our general partner and, except for the fixed administrative fee we paid SPLC, we did not otherwise pay or reimburse any compensation amounts to or for them.
Summary Compensation Table
The following summarizes the total compensation paid to our NEOs for their services in relation to our business in 2018, 2017 and 2016:
126
Name and Principal Position (1) | Year | Salary | Bonus | Unit Awards | Option Awards | Non-Equity Incentive Compensation Plan | Change in Pension Value and Nonqualified Deferred Compensation Earnings | All Other Compensation | Total | |||||||||||||||||||||||||||||||||||||||||||||||
Kevin M. Nichols, President and Chief Executive Officer (2) | 2018 2017 2016 | — — — | — — — | — — — | — — — | — — — | — — — | — — — | — — — | |||||||||||||||||||||||||||||||||||||||||||||||
John H. Hollowell, President and Chief Executive Officer (2) | 2018 2017 2016 | — — — | — — — | — — — | — — — | — — — | — — — | — — — | — — — | |||||||||||||||||||||||||||||||||||||||||||||||
| Shawn J. Carsten, Vice President and Chief Financial Officer | 2018 2017 2016 | — — — | — — — | — — — | — — — | — — — | — — — | — — — | — — — | |||||||||||||||||||||||||||||||||||||||||||||||
| Lori M. Muratta, Vice President, General Counsel and Secretary | 2018 2017 2016 | — — — | — — — | — — — | — — — | — — — | — — — | — — — | — — — | |||||||||||||||||||||||||||||||||||||||||||||||
| Alton G. Smith, Vice President, Operations | 2018 2017 2016 | — — — | — — — | — — — | — — — | — — — | — — — | — — — | — — — | |||||||||||||||||||||||||||||||||||||||||||||||
Steven Ledbetter, Vice President, Commercial (3) | 2018 2017 2016 | — — — | — — — | — — — | — — — | — — — | — — — | — — — | — — — | |||||||||||||||||||||||||||||||||||||||||||||||
(1) Mr. Nichols, Mr. Hollowell, Mr. Carsten, Ms. Muratta, Mr. Smith, and Mr. Ledbetter devoted a significant portion of their overall working time to our business. Except for the fixed management fee we paid to SPLC under the Omnibus Agreement, we did not pay or reimburse any compensation amounts to or for our named executive officers in 2018, 2017 or 2016.
(2) John H. Hollowell retired as President and Chief Executive Officer effective April 1, 2018 and was replaced by Kevin M. Nichols effective April 1, 2018.
(3) Steven Ledbetter was not an NEO in 2017 or 2016.
Narrative Disclosure to Summary Compensation Table and Additional Narrative Disclosure
Compensation by Shell
Shell provides compensation to its executives in the form of base salaries, annual cash incentive awards, long-term equity incentive awards and participation in various employee benefit plans and arrangements, including broad based and supplemental defined contribution and defined benefit retirement plans. In addition, although our NEOs have not entered into employment agreements with Shell, Mr. Nichols has, and Mr. Hollowell had, an end of employment arrangement with Shell under which each respectively receives, or received, separation payments and benefits from Shell based on termination at the employer’s initiative or on mutually agreed terms. In the future, Shell may provide different or additional compensation components, benefits, or perquisites to our NEOs.
The following sets forth a more detailed explanation of the elements of Shell’s executive compensation program.
Base Compensation
Our named executive officers earn a base salary for their services to Shell and its affiliates, which amounts are paid by Shell or its affiliates other than us. We incur only a fixed expense per month under the Omnibus Agreement with respect to the compensation paid by Shell to each of our NEOs.
Annual Cash Bonus Payments
Our NEOs are eligible to earn cash payments from Shell under Shell’s annual incentive bonus program and other discretionary bonuses that may be awarded by Shell. Any bonus payments earned by the NEOs will be paid by Shell and will be determined solely by Shell without input from us or our general partner or its board of directors. The amount of any bonus payment made by Shell will not result in changes to the contractually fixed fee for executive management services that we pay to Shell under the Omnibus Agreement.
Share-Based Compensation
127
Shell’s incentive compensation programs primarily consist of share awards, restricted share awards or cash awards (any of which may be a performance award). Conditional awards of RDS shares are made under the terms of the Performance Share Plan (“PSP”) on a selective basis to senior personnel each year. The extent to which the awards vest is determined over a three-year performance period. Half of the award is linked to the key performance indicators, averaged over the period. The other half of the award is linked to a comparison with four main competitors of RDS over the period on the basis of four relative performance measures. All shares that vest are increased by an amount equal to the notional dividends accrued on those shares during the period from the award date to the vesting date. None of the awards result in beneficial ownership until the shares are delivered. Shares are awarded subject to a three-year vesting period.
Certain SPLC and Shell employees supporting our operations as well as other Shell operations were historically granted awards under the PSP. Share-based compensation expense is included in general and administrative expenses in the accompanying consolidated statements of income. These costs for 2018, 2017 and 2016 were immaterial.
Long-Term Equity-Based Incentive Compensation
Shell maintains a long-term incentive program pursuant to which it grants equity based awards in Royal Dutch Shell plc to certain of its executives and employees. Our NEOs may receive awards under Shell’s equity incentive plan from time to time as may be determined by the RDS Management Development Committee. The amount of any long-term incentive compensation made by Shell will not result in changes to the contractually fixed fee for executive management services that we will pay to Shell under the Omnibus Agreement.
Retirement, Health, Welfare and Additional Benefits
Our NEOs are eligible to participate in the employee benefit plans and programs that Shell offers to its employees, subject to the terms and eligibility requirements of those plans. Our NEOs are also eligible to participate in Shell’s tax-qualified defined contribution and defined benefit retirement plans to the same extent as all other Shell employees. Shell also has certain supplemental retirement plans in which its executives and key employees participate.
Director Compensation
Officers or employees of Shell or its affiliates who also serve as directors of our general partner do not receive additional compensation for such service. Our general partner’s directors who are not also officers or employees of Shell receive compensation for service on the board of directors and its committees. We currently pay each of such directors $150,000 annually. We currently pay the audit committee chairman an additional $15,000 annually and the conflicts committee chairman an additional $15,000 annually. In addition, each such director will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board and committee meetings. We currently pay meeting fees to each of such directors in the amount of $2,000 for each in-person board meeting, $2,000 for each in-person committee meeting, $1,000 for each telephonic board meeting and $1,000 for each telephonic committee meeting. Each director will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law pursuant to our partnership agreement.
Non-Employee Director Compensation Table
The following summarizes the compensation for our non-employee directors for 2018.
| Name | Fees Earned or Paid in Cash | Unit Awards | Option Awards | Non-Equity Incentive Plan Compensation | Non-Qualified Compensation | Deferred Earnings | All Other Compensation | Total | ||||||||||||||||||||||||||||||||||||||||||
| James J. Bender | 198,000 | — | — | — | — | — | — | 198,000 | ||||||||||||||||||||||||||||||||||||||||||
| Carlos A. Fierro | 184,000 | — | — | — | — | — | — | 184,000 | ||||||||||||||||||||||||||||||||||||||||||
| Curtis R. Frasier | 162,000 | — | — | — | — | — | — | 162,000 | ||||||||||||||||||||||||||||||||||||||||||
| Rob L. Jones | 200,000 | — | — | — | — | — | — | 200,000 | ||||||||||||||||||||||||||||||||||||||||||
| Margaret C. Montana | 163,000 | — | — | — | — | — | — | 163,000 | ||||||||||||||||||||||||||||||||||||||||||
Pay Ratio Disclosure
We do not have any employees. The officers and all other personnel necessary for our business are employed and compensated by Shell, subject to the administrative services fee in accordance with the terms of the Omnibus Agreement and our operating
128
agreements. Therefore we are unable to provide an estimate of the relationship of the median of the annual total compensation of our employees and the annual total compensation of our chief executive officer.
Long-Term Incentive Plan
Our general partner has adopted the Shell Midstream Partners, L.P. 2014 Incentive Compensation Plan (“LTIP”) for officers, directors and employees of our general partner or its affiliates, and any consultants, affiliates of our general partner or other individuals who perform services for us. Our general partner may issue our executive officers and other service providers long-term equity based awards under the plan, which awards would compensate the recipients thereof based on the performance of our common units and their continued employment during the vesting period, as well as align their long-term interests with those of our unit holders. Our general partner has not issued, and does not currently intend to issue any awards under the plan.
We are responsible for the cost of awards granted under our LTIP and all determinations with respect to awards, if any, to be made under our LTIP will be made by the board of directors of our general partner or any committee thereof that may be established for such purpose or by any delegate of the board of directors or such committee, subject to applicable law, which we refer to as the plan administrator. We currently expect that the board of directors of our general partner or a committee thereof will be designated as the plan administrator. The following description reflects the principal terms that are currently expected to be included in the LTIP.
General
The LTIP permits the board of directors of our general partner or any applicable committee or delegate thereof, in its discretion, subject to applicable law, from time to time to grant unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. The purpose of awards, if any, under the LTIP is to provide additional incentive compensation to individuals providing services to us, and to align the economic interests of such individuals with the interests of our unitholders. The LTIP limits the number of units that may be delivered pursuant to vested awards to 6,000,000 common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units subject to awards that are canceled, forfeited, or otherwise terminated without delivery of the common units are generally available for delivery pursuant to other awards, as provided in the LTIP.
Restricted Units and Phantom Units
A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, on a deferred basis, upon specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. The administrator of the LTIP may make grants of restricted and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the administrator may determine are appropriate, including the period over which restricted or phantom units will vest. The administrator of the LTIP may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement.
Distributions made by us with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units.
Distribution Equivalent Rights
The administrator of the LTIP, in its discretion, may also grant distribution equivalent rights, either as standalone awards or in tandem with other awards. Distribution equivalent rights are rights to receive an amount in cash, restricted units or phantom units equal to all or a portion of the cash distributions made on units during the period an award remains outstanding.
Unit Options and Unit Appreciation Rights
The LTIP may also permit the grant of options covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the administrator of the LTIP may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price equal to at least the fair market value of a common unit on the date of grant.
Unit Awards
129
Awards covering common units may be granted under the LTIP with such terms and conditions, including restrictions on transferability, as the administrator of the LTIP may establish.
Profits Interest Units
Awards may consist of profits interest units to the extent contemplated by our partnership agreement. The administrator will determine the applicable vesting dates, conditions to vesting and restrictions on transferability and any other restrictions for profits interest awards.
Other Unit-based Awards
The LTIP may also permit the grant of “other unit-based awards,” which are awards that, in whole or in part, are valued or based on or related to the value of a common unit. The vesting of any other unit-based award may be based on a grantee’s continued service, the achievement of performance criteria or other measures. On vesting or on a deferred basis upon specified future dates or events, any other unit-based award may be paid in cash and/or in units (including restricted units), or any combination thereof as the administrator of the LTIP may determine.
Source of Common Units
Common units to be delivered with respect to awards may be newly issued units, common units acquired by us or our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner directly from us, or any other person or any combination of the foregoing.
Anti-Dilution Adjustments and Change in Control
If an “equity restructuring” event occurs that could result in an additional compensation expense under applicable accounting standards if adjustments to awards under the LTIP with respect to such event were discretionary, the administrator of the LTIP will equitably adjust the number and type of units covered by each outstanding award and the terms and conditions of such award to equitably reflect the restructuring event, and the administrator will adjust the number and type of units with respect to which future awards may be granted under the LTIP. With respect to other similar events, including, for example, a combination or exchange of units, a merger or consolidation or an extraordinary distribution of our assets to unitholders, that would not result in an accounting charge if adjustment to awards were discretionary, the administrator of the LTIP has the discretion to adjust awards in the manner it deems appropriate and to make equitable adjustments, if any, with respect to the number and kind of units subject to outstanding awards, the terms and conditions of any outstanding awards and the grant or exercise price per unit for outstanding awards under the LTIP. Furthermore, in connection with a change in control of us or our general partner, or a change in any law or regulation affecting the LTIP or outstanding awards or any relevant change in accounting principles, the administrator of the LTIP will generally have discretion to (i) accelerate the time of exercisability or vesting or payment of an award, (ii) permit awards to be surrendered in exchange for a cash payment, (iii) cause awards then outstanding to be assumed or substituted for other rights by the surviving entity in the change in control, (iv) provide for either (A) the termination of any award in exchange for a payment of the amount that would have been received upon the exercise of such award or realization of the grantee’s rights under such award or (B) the replacement of an award with other rights or property selected by the administrator having an aggregate value not exceeding the amount that could have been received upon the exercise of such award or realization of the grantee’s rights had such award been currently exercisable or payable or fully vested, (v) provide that an award be assumed by the successor or survivor entity, or be exchanged for similar options, rights or awards covering the equity of the successor or survivor, with appropriate adjustments thereto, (vi) make adjustments in the number and type of units subject to outstanding awards, the number and kind of outstanding awards, the terms and conditions of, and/or the vesting and performance criteria included in, outstanding awards, (vii) provide that an award will vest or become exercisable or payable and/or (viii) provide that an award cannot be exercised or become payable after such event and will terminate upon such event.
Termination of Employment
The LTIP provides the administrator with the discretion to determine in each award agreement the effect of a termination of a grantee’s employment, membership on our general partner’s board of directors or other service arrangement on the grantee’s outstanding awards.
Amendment or Termination of LTIP
The administrator of the LTIP, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The LTIP automatically terminates on the tenth anniversary of the date it was initially adopted by our general partner. The administrator of the LTIP also has the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may
130
be made that would materially impair the vested rights of the participant without the consent of the affected participant or result in taxation to the participant under Section 409A of the Internal Revenue Code.
Compensation Committee Report
We do not have a Compensation Committee. Accordingly, the Compensation Committee Report required by Item 407(e)(5) of Regulation S-K is given by the board of directors of our general partner. The board of directors of our general partner has reviewed and discussed the Compensation Discussion and Analysis presented above with management and, based on such review and discussions, the board has approved the inclusion of the Compensation Discussion and Analysis in this Annual Report on Form 10-K.
Members of the board of directors of Shell Midstream Partners GP LLC:
Curtis R. Frasier
James J. Bender
Shawn J. Carsten
Carlos A. Fierro
Paul R. A. Goodfellow
Kevin M. Nichols
Rob L. Jones
Margaret C. Montana
Marcel Teunissen
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The following table sets forth the beneficial ownership of common units of Shell Midstream Partners, L.P. held by beneficial owners of 5% or more of the common units, by each director, director nominee and named executive officer of our general partner and by the directors, director nominee and executive officers of our general partner as a group. The percentage of units beneficially owned is based on 223,811,781 common units outstanding as of February 21, 2019.
Name of Beneficial Owner (1) | Common Units Beneficially Owned | Percentage of Common Units Beneficially Owned | ||||||||||||
Shell Pipeline Company LP (2) | 99,979,548 | 44.7 | % | |||||||||||
Tortoise Capital Advisors, L.L.C. 11550 Ash Street, Suite 300, Leawood, Kansas 66211 (3) | 23,553,456 | 10.5 | % | |||||||||||
ALPS Advisors, Inc. 1290 Broadway, Suite 1100, Denver CO 80203 (4) | 12,317,939 | 5.5 | % | |||||||||||
Alerian MLP ETF 1290 Broadway, Suite 1100, Denver, CO 80203 (5) | 12,270,035 | 5.5 | % | |||||||||||
| James J. Bender | 25,000 | — | % | |||||||||||
| Rob L. Jones | 15,000 | — | % | |||||||||||
| Margaret C. Montana | 13,335 | — | % | |||||||||||
| Kevin M. Nichols | 8,500 | — | % | |||||||||||
| Curtis R. Frasier | 5,000 | — | % | |||||||||||
| Alton G. Smith | 5,000 | — | % | |||||||||||
| Carlos A. Fierro | 3,000 | — | % | |||||||||||
| Lori M. Muratta | 2,960 | — | % | |||||||||||
| Shawn J. Carsten | 2,500 | — | % | |||||||||||
| John H. Hollowell | — | — | % | |||||||||||
| Paul R. A. Goodfellow | — | — | % | |||||||||||
| Marcel Teunissen | — | — | % | |||||||||||
| Steven Ledbetter | — | — | % | |||||||||||
| Directors and executive officers as a group (13 persons) | 80,295 | — | % | |||||||||||
(1) The address for all beneficial owners in this table, except as noted in the table, is 150 N. Dairy Ashford, Houston, Texas 77079.
131
(2) Shell Pipeline Company LP owns Shell Midstream LP Holdings LLC, which owns the common units presented above, and Shell Midstream Partners GP LLC, which owns all of our general partner units. Shell Pipeline Company LP may be deemed to beneficially own the units held by Shell Midstream Holdings LLC and Shell Midstream Partners GP LLC.
(3) Based solely on a Schedule 13G/A filed by Tortoise Capital Advisors, L.L.C. on February 6, 2019. Tortoise Capital Advisors, L.L.C. has sole voting power over 1,462,828 common units, shared voting power over 20,667,269 common units, sole dispositive power over 1,462,828 common units and shared dispositive power over 22,090,628 common units.
(4) Based solely on a Schedule 13G/A filed by ALPS Advisors, Inc. (“ALPS”) on February 4, 2019. ALPS has shared voting power and dispositive power over 12,317,939 common units. ALPS disclaims beneficial ownership of these units. ALPS reported that it is an investment advisor registered under the Investment Advisors Act of 1940 and provides investment advice to investment companies registered under the Investment Company Act of 1940 and that Alerian MLP ETF (“Alerian”) is one of the investment companies to which ALPS provides investment advice (see note 5 below). ALPS also reported that, in its role as investment advisor, it has voting and/or investment power over our securities owned by Alerian, it may be deemed to be the beneficial owner of such securities, all such securities are owned by Alerian and ALPS disclaims beneficial ownership of such securities.
(5) Based solely on a Schedule 13G/A filed by Alerian on February 4, 2019. Alerian has shared voting power and shared dispositive power over 12,270,035 common units. Alerian reported that it is an investment company registered under the Investment Company of 1940 to which ALPS provides investment advice (see note 4 above).
Securities Authorized for Issuance under Equity Compensation Plans
The following table sets forth information about all existing equity compensation plans as of December 31, 2018.
| Plan Category | Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights | Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (1) ) | |||||||||||||||||
Equity compensation plans approved by security holders (1) | — | — | 6,000,000 | |||||||||||||||||
| Equity compensation plans not approved by security holders | — | — | — | |||||||||||||||||
| Total | — | — | 6,000,000 | |||||||||||||||||
(1) The amounts shown represents common units available under the LTIP as of December 31, 2018. No awards have been made under the LTIP.
Item 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS, AND DIRECTOR INDEPENDENCE
As of February 21, 2019, the general partner and its affiliates owned 99,979,548 common units, representing a 43.8% limited partner interest in us, and all of our incentive distribution rights. In addition, our general partner owned 4,567,588 general partner units representing a 2% general partner interest in us. See Part III, Item 10. Directors, Executive Officers and Corporate Governance – Management of Shell Midstream Partners, L.P. in this report for additional information regarding director independence.
Distributions and Payments to Our General Partner and Its Affiliates
The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our ongoing operation and upon liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
132
Operational Stage
| Distributions of available cash to our general partner and its affiliates | We generally make cash distributions of 98% to the common unitholders pro rata, including SPLC, as holder of an aggregate of 99,979,548 common units (43.8% of all units outstanding) and 2% to our general partner, assuming it makes all capital contributions necessary to maintain its 2% general partner interest in us. In addition, if cash distributions exceed the minimum quarterly distribution and target distribution levels, the incentive distribution rights held by our general partner entitle our general partner to increasing percentages of the cash distributions, up to 48.0% of the cash distributions above the highest target distribution level. | |||||||
| Payments to our general partner and its affiliates | Pursuant to our partnership agreement, we reimburse our general partner and its affiliates, including SPLC, for costs and expenses they incur and payments they make on our behalf. Pursuant to the Omnibus Agreement, we pay an annual fee, currently $8.5 million, to SPLC for general and administrative services. In addition, we reimburse our general partner and SPLC, as applicable, pursuant to our management agreement and operational and administrative management agreements for each of Pecten, Sand Dollar and Triton West. | |||||||
| Withdrawal or removal of our general partner | If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. | |||||||
| Liquidation Stage | ||||||||
| Liquidation | Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances. | |||||||
Agreements with Shell
We have entered into various agreements with Shell, as described in detail below. These agreements were negotiated in connection with, among other things, the formation of the Partnership, the IPO and our acquisitions from Shell. These agreements address, among other things, the acquisition of assets and the assumption of liabilities by us. These agreements were not the result of arm’s length negotiations and, as such, they or underlying transactions may not be based on terms as favorable as those that could have been obtained from unaffiliated third parties.
Omnibus Agreement
In connection with the IPO we entered into an Omnibus Agreement with SPLC and our general partner that addressed the following matters:
•our payment of an annual administrative fee, currently $8.5 million, for the provision of certain services by SPLC;
•our obligation to reimburse SPLC for certain direct or allocated costs and expenses incurred by SPLC on our behalf;
•SPLC’s obligation to indemnify us for certain environmental and other liabilities, and our obligation to indemnify SPLC for certain environmental and other liabilities related to our assets to the extent SPLC is not required to indemnify us; and
•the granting of a license from Shell to us with respect to use of certain Shell trademarks and trade names.
The environmental indemnification obligation expired on November 3, 2017.
So long as SPLC controls our general partner, the Omnibus Agreement will remain in full force and effect. If SPLC ceases to control our general partner, either party may terminate the Omnibus Agreement, provided that the indemnification obligations will remain in full force and effect in accordance with their terms. Payment in the amount of $8.5 million was made in each of the following years, 2018, 2017 and 2016 under the Omnibus Agreement. On February 19, 2019, we, our general partner, SPLC, Shell Midstream Operating LLC and Shell Oil Company terminated the Omnibus Agreement effective as of February 1, 2019, and we, our general partner, SPLC and Shell Midstream Operating LLC entered into a new Omnibus Agreement effective February 1, 2019. In addition, we, our general partner and SPLC entered into a Trade Marks License Agreement with Shell
133
Trademark Management Inc. effective as of February 1, 2019. Refer to Note 15 - Subsequent Events in the Notes to the Consolidated Financial Statements included in Part II, Item 8 for additional information.
Operating Agreements
In connection with the formation of Pecten on October 1, 2015, Pecten entered into an Operating and Administrative Management Agreement with SPLC. Pursuant to this agreement, SPLC performs physical operations and maintenance services for Lockport and Auger and provides general and administrative services for Pecten. Pecten is required to reimburse SPLC for costs and expenses incurred in connection with such services. Also pursuant to the agreement, SPLC and Pecten agree to standard indemnifications as operator and asset owner, respectively.
In connection with the May 2017 Acquisition, on May 10, 2017, SPLC entered into an Operating and Administrative Management Agreement with Sand Dollar. Sand Dollar is allocated and required to reimburse SPLC for certain costs in connection with the services provided pursuant to the agreement. Also pursuant to the agreement, SPLC and Sand Dollar agree to standard indemnifications as operator and asset owner, respectively.
On December 1, 2017, our general partner, SPLC and Triton West entered into an Operating and Administrative Management Agreement. Our general partner provides certain operational and support services pursuant to the agreement. The necessary personnel are employed by SPLC and are assigned to our general partner. Triton West is allocated certain costs by the general partner in connection with the services provided pursuant to the agreement. Our general partner reimburses SPLC for certain costs related to the assigned personnel. Our general partner, SPLC and Triton West each provide standard indemnifications as operator, employer and asset owner, respectively.
In connection with the December 2017 Acquisition, we were assigned an operating agreement for Odyssey, whereby SPLC performs physical operations and maintenance services and provides general and administrative services for Odyssey. Odyssey is required to reimburse SPLC for costs and expenses incurred in connection with such services. Also pursuant to the agreement, SPLC and Odyssey agree to standard indemnifications as operator and asset owner, respectively.
For amounts paid under these agreements, see Note 5 - Related Party Transactions in the Notes to the Consolidated Financial Statements in Part II, Item 8 of this report.
Joint Venture and Subsidiary Governing Agreements
We are a party to the governing agreements of the entities in which we own equity interests. The governing agreements of such entities govern the ownership and management of the applicable entity. Our ability to influence decisions with respect to the operation of certain of the entities in which we own interests varies depending on the amount of control we exercise under the applicable governing agreement.
The governing agreements generally include provisions related to cash distributions, capital calls, transfer restrictions and termination of the applicable entity. For example, we do not control the amount of cash distributed by several of the entities in which we own interests. We may influence the amount of cash distributed through our veto rights provided for in the applicable governing agreement over the cash reserves made by certain of these entities. Additionally, we may not have the ability to unilaterally require certain of the entities in which we own interests to make capital expenditures, and such entities may require us to make additional capital contributions to fund operating and maintenance expenditures, as well as to fund expansion capital expenditures, which would reduce the amount of cash otherwise available for distribution by us or require us to incur additional indebtedness.
Voting Agreements
Pursuant to a voting agreement between SPLC and us, we have voting power over the ownership interests retained by SPLC in Zydeco. Pursuant to the voting agreement, SPLC is prohibited from transferring its ownership interest in Zydeco unless the transferee agrees to be bound by the applicable voting agreement.
Tax Sharing Agreement
We have entered into a tax sharing agreement with Shell. Pursuant to this agreement, we have agreed to reimburse Shell for state and local income and franchise taxes attributable to any activity of our operating subsidiaries, and reported on Shell’s state or local income or franchise tax returns filed on a combined or unitary basis. Reimbursements under this agreement equal the amount of tax our applicable operating subsidiaries would be required to pay with respect to such activity, if such subsidiaries were to file a combined or unitary tax return separate from Shell. Shell will compute and invoice us for the tax reimbursement amount within 15 days of Shell filing its combined or unitary tax return on which such activity is included. We may be required
134
to make prepayments toward the tax reimbursement amount to the extent that Shell is required to make estimated tax payments during the relevant tax year. The tax sharing agreement currently in place is effective for all taxable periods ending on or after December 31, 2017. The current agreement replaced a similar tax sharing agreement between Zydeco and Shell, which was effective for all tax periods ending before December 31, 2017. Reimbursements for tax years ended December 31, 2018, 2017 and 2016 were not material to our consolidated statements of income.
Other Agreements
Under the pipeline operating agreements, SPLC or Shell provides operational and management services for which we, our subsidiaries or investments reimburse SPLC or Shell, as applicable, for certain direct expenses incurred in connection with providing services under such agreements. In addition, Zydeco entered into a management agreement with SPLC under which Zydeco pays SPLC an annual management fee for general and administrative services. Payment in the amounts of $8.5 million, $8.1 million and $7.7 million, respectively, were made in 2018, 2017 and 2016 under this agreement.
Procedures for Review, Approval or Ratification of Transactions with Related Parties
The board of directors of our general partner has adopted policies for the review, approval and ratification of transactions with related persons. For the purposes of the policy, a “related person” is expected to be any director or executive officer of our general partner, any unitholder known to us to be the beneficial owner of more than 5.0% of the our common units, and any immediate family member of any such person, and a “related person transaction” is expected to be generally a transaction in which we are, or our general partner or any of our subsidiaries is, a participant, the amount involved exceeds $0.1 million, and a related person has a direct or indirect material interest. Transactions resolved under the conflicts provision of the partnership agreement are not required to be reviewed or approved under the policy.
The policy sets forth certain categories of transactions that are deemed to be pre-approved by the audit committee of the board of directors of our general partner under the policy. After applying these categorical standards and weighing all of the facts and circumstances, the audit committee of the board of directors of our general partner must then either approve or reject the transaction in accordance with the terms of the policy.
The board of directors of our general partner has adopted a written policy, under which a director would be expected to bring to the attention of the board of directors of our general partner any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board of directors of our general partner, be determined by a majority of the disinterested directors.
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The following table presents fees for professional services performed by our independent registered public accounting firm, Ernst & Young LLP, for 2018 and 2017.
(in millions of dollars) | 2018 | 2017 | |||||||||
| Fees | |||||||||||
Audit fees (1) | $ | 2.2 | $ | 2.4 | |||||||
| Audit-related fees | — | — | |||||||||
| Tax fees | — | — | |||||||||
| All other fees | — | — | |||||||||
| Total | $ | 2.2 | $ | 2.4 | |||||||
(1) Fees for audit services related to the fiscal year consolidated audit, quarterly reviews, and services that were provided in connection with registration statements, statutory and regulatory filings.
The Audit Committee has adopted a pre-approval policy that provides guidelines for the audit, audit-related, tax and other non-audit services that may be provided by the independent registered public accounting firm to the Partnership. All of the fees in the table above were approved in accordance with this policy. The policy (a) identifies the guiding principles that must be considered by the Audit Committee in approving services to ensure that the independent registered public accounting firm’s independence is not impaired; (b) describes the audit, audit-related, tax and other services that may be provided and the non-audit services that are prohibited; and (c) sets forth pre-approval requirements for all permitted services. Under the policy, all services to be provided by the independent registered public accounting firm must be pre-approved by the Audit Committee.
135
The Audit Committee has delegated authority to approve permitted services to the Audit Committee’s Chair. Such approval must be reported to the entire Audit Committee at the next scheduled Audit Committee meeting.
136
PART IV
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
1. Financial Statements and Supplementary Data
The financial statements and supplementary information listed in the Index to Financial Statements, which appears in Part II, Item 8, are filed as part of this Annual Report.
2. Financial Statement Schedules
The following financial statement schedules are included pursuant to Rule 3-09 of Regulation S-X (17 CFR 210.3-09):
| Mars Oil Pipeline Company LLC | |||||
| Amberjack Pipeline Company LLC | |||||
All other financial statement schedules are omitted because they are not required, not significant, not applicable or the information is shown in another schedule, the financial statements or the notes to consolidated financial statements.
3. Exhibits
The exhibits listed in the Index to Exhibits are filed as part of this Annual Report.
137
SHELL MIDSTREAM PARTNERS, L.P.
INDEX TO EXHIBITS
Incorporated by Reference | ||||||||||||||||||||||||||||||||
Exhibit Number | Exhibit Description | Form | Exhibit Number | Filing Date | SEC File No. | |||||||||||||||||||||||||||
| 3.1 | S-1 | 3.1 | 06/18/2014 | 333-196850 | ||||||||||||||||||||||||||||
| 3.2 | 8-K | 3.1 | 11/03/2014 | 001-36710 | ||||||||||||||||||||||||||||
| 3.3 | 8-K | 3.1 | 2/28/2018 | 001-36710 | ||||||||||||||||||||||||||||
| 3.4 | 8-K | 3.1 | 12/21/2018 | 001-36710 | ||||||||||||||||||||||||||||
| 3.5 | S-1 | 3.3 | 06/18/2014 | 333-196850 | ||||||||||||||||||||||||||||
| 3.6 | 8-K | 3.2 | 11/03/2014 | 001-36710 | ||||||||||||||||||||||||||||
| 10.1 | 8-K | 10.2 | 11/03/2014 | 001-36710 | ||||||||||||||||||||||||||||
| 10.2 | 8-K | 10.1 | 02/05/2018 | 001-36710 | ||||||||||||||||||||||||||||
| 10.3# | 8-K | 10.4 | 11/03/2014 | 001-36710 | ||||||||||||||||||||||||||||
| 10.4 | 8-K | 10.5 | 11/03/2014 | 001-36710 | ||||||||||||||||||||||||||||
| 10.5 | 8-K | 10.1 | 02/26/2016 | 001-36710 | ||||||||||||||||||||||||||||
| 10.6 | 8-K | 10.1 | 05/17/2016 | 001-36710 | ||||||||||||||||||||||||||||
| 10.7 | 8-K | 10.1 | 07/29/2016 | 001-36710 | ||||||||||||||||||||||||||||
| 10.8 | 8-K | 10.1 | 09/28/2016 | 001-36710 | ||||||||||||||||||||||||||||
| 10.9 | 8-K | 10.1 | 02/27/2017 | 001-36710 | ||||||||||||||||||||||||||||
| 10.10 | 8-K | 10.1 | 05/05/2017 | 001-36710 | ||||||||||||||||||||||||||||
| 10.11 | 8-K | 10.1 | 10/20/2017 | 001-36710 | ||||||||||||||||||||||||||||
| 10.12 | 8-K | 10.1 | 11/28/2017 | 001-36710 | ||||||||||||||||||||||||||||
| 10.13 | 8-K | 10.1 | 12/05/2017 | 001-36710 | ||||||||||||||||||||||||||||
| 10.14 | 8-K | 10.1 | 05/14/2018 | 001-36710 | ||||||||||||||||||||||||||||
| 10.15 | 8-K | 10.1 | 08/02/2018 | 001-36710 | ||||||||||||||||||||||||||||
| 10.16 | 8-K | 10.2 | 08/02/2018 | 001-36710 | ||||||||||||||||||||||||||||
138
| 10.17* | ||||||||||||||||||||||||||||||||
| 10.18* | ||||||||||||||||||||||||||||||||
| 10.19* | ||||||||||||||||||||||||||||||||
| 21* | ||||||||||||||||||||||||||||||||
| 23.1* | ||||||||||||||||||||||||||||||||
| 23.2* | ||||||||||||||||||||||||||||||||
| 23.3* | ||||||||||||||||||||||||||||||||
| 23.4* | ||||||||||||||||||||||||||||||||
| 31.1* | ||||||||||||||||||||||||||||||||
| 31.2* | ||||||||||||||||||||||||||||||||
| 32.1** | ||||||||||||||||||||||||||||||||
| 32.2** | ||||||||||||||||||||||||||||||||
| 99.1* | ||||||||||||||||||||||||||||||||
| 99.2* | ||||||||||||||||||||||||||||||||
| 101.INS* | XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | |||||||||||||||||||||||||||||||
| 101.SCH* | XBRL Taxonomy Extension Schema | |||||||||||||||||||||||||||||||
| 101.PRE* | XBRL Taxonomy Extension Presentation Linkbase | |||||||||||||||||||||||||||||||
| 101.CAL* | XBRL Taxonomy Extension Calculation Linkbase | |||||||||||||||||||||||||||||||
| 101.DEF* | XBRL Taxonomy Extension Definition Linkbase | |||||||||||||||||||||||||||||||
| 101.LAB* | XBRL Taxonomy Extension Label Linkbase | |||||||||||||||||||||||||||||||
* Filed herewith.
** Furnished herewith.
# Management contract or compensatory plan or arrangement required to be filed as an exhibit to this Form 10-K pursuant to Item 15(b).
139
Item 16. FORM 10-K SUMMARY
Not applicable.
140
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| SHELL MIDSTREAM PARTNERS, L.P. | |||||
| By: Shell Midstream Partners GP LLC, its general partner | |||||
| February 21, 2019 | /s/ Shawn J. Carsten | ||||
Shawn J. Carsten Vice President and Chief Financial Officer | |||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed, as of February 21, 2019, by the following persons on behalf of the registrant and in the capacities indicated.
| Signature | Title | |||||||
| /s/ Kevin M. Nichols | Director, President and Chief Executive Officer Shell Midstream Partners GP LLC (principal executive officer) | |||||||
| Kevin M. Nichols | ||||||||
| /s Shawn J. Carsten | Director, Vice President and Chief Financial Officer Shell Midstream Partners GP LLC (principal accounting officer and principal financial officer) | |||||||
| Shawn J. Carsten | ||||||||
| /s/ Curtis R. Frasier | Chairman of the Board of Directors Shell Midstream Partners GP LLC | |||||||
| Curtis R. Frasier | ||||||||
| /s/ Paul R.A. Goodfellow | Director Shell Midstream Partners GP LLC | |||||||
| Paul R.A. Goodfellow | ||||||||
| /s/ Rob L. Jones | Director Shell Midstream Partners GP LLC | |||||||
| Rob L. Jones | ||||||||
| /s/ James J. Bender | Director Shell Midstream Partners GP LLC | |||||||
| James J. Bender | ||||||||
| /s/ Carlos A. Fierro | Director Shell Midstream Partners GP LLC | |||||||
| Carlos A. Fierro | ||||||||
| /s/ Margaret C. Montana | Director Shell Midstream Partners GP LLC | |||||||
| Margaret C. Montana | ||||||||
| /s/ Marcel Teunissen | Director Shell Midstream Partners GP LLC | |||||||
| Marcel Teunissen | ||||||||
141